Powering
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TransAlta Corporation
2018 Annual Integrated Report
Letter to Shareholders
Message from the Chair
Management’s Discussion and Analysis
Consolidated Financial Statements
Notes to Consolidated Financial Statements
Eleven-Year Financial and Statistical Summary
Plant Summary
Sustainability Performance Indicators
Independent Sustainability Assurance Statement
Shareholder Information
Shareholder Highlights
Corporate Information
Glossary of Key Terms
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Letter to Shareholders
Letter to Shareholders
As I sit down to write this letter, we are halfway through our transformation to become a leading clean energy
company. For the past 65 years, TransAlta has focused primarily on the development, construction and operation
of coal-fired generating plants, fueling the growth of the communities where we operate. Almost 20 years ago,
the Alberta electricity market was de-regulated and long-term power purchase arrangements (PPAs) were
established. Today, we stand three years into our transformation that includes converting our Alberta coal units
to gas generation in response to a competitive environment in Alberta that is defined by the PPAs coming to an
end, the cost of carbon becoming a reality and the anticipated capacity market being implemented in Alberta.
Our coal-to-gas conversions will be completed in another three to four years, at which time we will be a largely
transformed business. Our strategy is based on both the need to respond to these external changes and our focus
on realizing significant long-term value for our shareholders.
Our strategy is simple: i) convert to gas; ii) realize the full value of our hydro assets; and iii) grow TransAlta
Renewables. The execution steps to make this strategy a reality are known, in place and tracking.
1. The first priority of our strategy involves shifting our Alberta fleet to compete in the capacity market, primarily
by transitioning the coal fleet to gas in the 2020 to 2023 time frame. Once completed, we will see our Alberta
thermal fleet contribute strong cash flow to the company for many years to come.
2. Our second priority is to maintain our Alberta hydro assets as we approach the expiry of its PPA. When this
arrangement expires at the end of 2020, we expect to receive the full benefit of the attributes inherent in
these hydro assets, including capacity, energy and ancillary services.
3. Our third strategic priority is to support growth in TransAlta Renewables. We receive a reliable dividend
from our investment in TransAlta Renewables and this investment also extends our average contract life and
reduces the business risk and cost of capital for TransAlta Corporation.
With the benefit of understanding our strategic priorities, let me now outline our performance in 2018 and what
is to come in 2019 and beyond.
2018 Performance Highlights
In 2018, we realized some of our best performance for safety, availability and free cash flow:
▪ We delivered free cash flow of $367 million, $56 million higher than 2017, after adjusting for the one-time
payment for the termination of the Sundance B and C power purchase arrangements in 2018 and the payment
from the Ontario Electricity Financial Corporation in 2017 (net of our partner's share).
▪ Our total injuries declined 44% relative to 2017. While this is a great result, we are still striving to see further
improvement.
▪ We increased our co-firing at the Canadian coal unit, resulting in savings of approximately $12 million in
greenhouse gas costs.
Availability was strong and we achieved our best availability at Sundance since 1990 and at Keephills since
2011.
▪
▪ We increased cash flow from Australia from $127 million to $136 million.
▪
The hydro segment increased cash flow by $35 million, despite lower production, representing stronger
energy pricing and the higher demand for ancillary services.
▪ We continued to pay down debt in 2018 with a reduction of net recourse debt of approximately $515 million.
We expect to continue our deleveraging strategy over the next three years as part of our balanced capital
allocation plan.
The successes of 2018 were hard-won given the headwinds of 2018:
▪
▪
The net loss realized in 2018 was a result of, in part, the acceleration of the depreciation and amortization of
the mine and coal assets provided by of the Off-Coal Agreement with the Government of Alberta.
Carbon compliance costs increased due to regulated increase in the carbon price and the fact that carbon
costs are no longer passed-through to the buyer under the power purchase arrangements.
▪ We retired Sundance Units 1 and 2 and mothballed Sundance Units 3 and 5, resulting in production at
Canadian coal decreasing by over 8,000 gigawatts/hour compared to 2017.
▪ We realized higher coal costs on a dollar per MWh basis due to lower coal tonnage and the allocation of fixed
costs across lower production - we are focused on providing the lowest cost fuel for the remaining life of the
facilities.
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TransAlta Corporation | 2018 Annual Integrated Report
Letter to Shareholders
TransAlta’s performance in 2018 is particularly noteworthy given the work being undertaken to shift our cost
structure and operating models to adapt to the new market and regulatory realities. This has been largely driven
through our company-wide initiative known as Project Greenlight, which has produced meaningful change within
the company. This includes adopting cost reduction measures, implementing operational improvements and
enhancing employee engagement. Examples of this transformation include the headcount reduction of over 15%
in 2018, the co-firing of gas at Sundance and Keephills, and improving equipment utilization at our mining
operations. We are also focused on improving organizational effectiveness, which includes being operationally
disciplined, encouraging bottom-up innovation and facilitating performance transparency. For a company that
is over 100 years old, these changes do not come easily, but the success of this program to date is an indication of
the company’s commitment to drive value for decades to come.
Executing on Growth
When I think of our overall growth plans, I think about them in two categories. The growth in TransAlta
Renewables and the growth represented by the coal-to-gas conversions in TransAlta.
Supporting Growth in TransAlta Renewables
In 2018, we entered into agreements providing for the development and construction of two new wind facilities:
i) a 90 MW project located in Pennsylvania, US with a 15-year purchase agreement with Microsoft; and ii) a 29
MW project located in New Hampshire, US with two 20-year purchase agreements with investment grade
counterparties. In addition, we entered into a 20-year agreement with the Alberta Electric System Operator
(AESO) for the 207 MW Windrise wind project in Alberta, Canada. We expect this growth to create approximately
$40 to $45 million of new EBITDA in the consolidated company, with an average contract tenure of more than
18 years.
TransAlta Renewables acquired the economic interest in the Pennsylvania and New Hampshire wind projects.
TransAlta Renewables is fully responsible for the capital costs associated with their construction. Further, the
Windrise project is a drop down candidate for TransAlta Renewables. Growth projects that are dropped down
to TransAlta Renewables are not funded from capital out of TransAlta. TransAlta Renewables has its own credit
line, has the ability to raise project debt or tax equity on a project-by-project basis and also has its own source of
free cash flow to fund these projects. TransAlta’s 61% ownership of TransAlta Renewables also has the effect of
lowering the cost of capital at TransAlta.
Coal-to-Gas Conversions: Growing TransAlta
The coal-to-gas conversions, including the pipeline, are very much growth-oriented as they will result in the
cumulative life extension of our fleet by approximately 75 years, assuming all units are converted. The conversions
will provide competitive, reliable, low cost power to the Alberta market and are expected to position us well in
the anticipated Alberta capacity market. In 2018, we exercised our option to acquire 50 percent ownership in
the Pioneer Pipeline, which will allow us to increase the amount of natural gas we co-fire at Sundance and Keephills
and also facilitates the acceleration of the coal-to-gas conversions. The capital that we have committed to the
Pioneer Pipeline is a significant milestone as it represents our first official capital investment in our coal-to-gas
conversion strategy. The expected return on the coal-to-gas conversions far exceeds our cost of capital and makes
it a clear winner for value creation. At the beginning of 2019, we received regulatory approval for our coal-to-
gas conversions.
2019 and Beyond
As we look forward, we expect to see the cash flow from the Alberta hydro assets to naturally grow once its PPA
expires. This is due to the fact we will fully benefit from the value tied to the capacity, energy and ancillary services
associated with these long-term assets. Our Alberta hydro assets are essential to the Alberta market as they
provide significant benefits in their unique ability to both provide reserves and respond quickly to changes in
electricity demand. Our reinvestment in these hydro assets is unwavering as it provides shareholders with an
interest in a set of assets that are scarce (in Alberta) and provide service into perpetuity.
Regardless of the political environment in Alberta that may emerge, we are positioned to respond effectively. The
two policies in particular that warrant attention are: i) policies pertaining to market design, and ii) policies
pertaining to greenhouse gases. The AESO has announced an intention to implement a capacity market in Alberta
to be effective in 2021. We support the implementation of the capacity market because it provides for an effective
replacement of the current capacity commitment under the legislated power purchase arrangements. A capacity
market is an efficient way to ensure capacity is available in Alberta when consumers need power, regardless of
whether the wind blows or the weather is cold. We also know that even more stable capacity is needed as the
development of renewables increase over time, due to the intermittent nature of the renewable generation. We
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TransAlta Corporation | 2018 Annual Integrated Report
Letter to Shareholders
also expect that as renewable generation continues to get cheaper and more desirable by customers, there can
be a shortfall of capacity if the price isn’t transparent and there isn’t a concerted effort to call for enough new
capacity. We also see an unrelenting demand by the public to reduce greenhouse gases in the production of
electricity. We expect that large emitters will always pay something for their emissions.
This annual report marks our 7th year of reporting our own sustainability goals. I personally helped develop our
sustainability goals in 1989 and bought our first carbon offsets in 1991. TransAlta has always been ahead of the
market on how sustainability - both environmental sustainability AND economic sustainability - sets the context
for how we do our work. By 2030, we will have reduced greenhouse gases by 60%, reduced SO2 by 95% and
reduced NOx by 50% compared to 2015 levels. Our sustainability goals now touch on every aspect of our strategy,
whether it’s the coal-to-gas conversions, continuing to support our hydro assets in Alberta or growing TransAlta
Renewables.
Owning TransAlta
One of the darkest days in my life as a CEO was January 18, 2016. On that day, the stock traded at $3.76. This
was the result of a number of factors, not least of which was the Government of Alberta’s stated intention to cease
coal-fired emissions by 2030. TransAlta responded quickly and decisively to that reality. We initiated and engaged
in negotiations with the Government of Alberta, which ultimately resulted in the recovery of approximately $37
million in annual Off-Coal payments. We also reduced our corporate recourse debt from $3.4 billion to $1.6 billion
since 2015. Our success in stepping up to this challenge is reflected in our share performance since January 2,
2016, as compared to our peers on the TSX and the TSX utility capped index. Our return since that day has been
approximately 35% annualized, including the dividend. This return has been achieved even though we are only
half-way through our transformation.
This is not to suggest that you need to wait until 2022 to realize value. We know that shareholders expect more
and expect more sooner. As detailed above, the company remains focused on i) the conversions to gas (including
their ability to compete in the capacity market), ii) pursuing incremental growth at TransAlta Renewables; and iii)
competitively positioning the Alberta hydro assets in Alberta. These priorities, taken together, are expected to
generate sufficient free cash flow in order to allow us to allocate capital to new growth projects, pay shareholder
dividends, complete share buy-backs or fund additional debt reduction. By remaining focused and dedicated to
this strategy, we are confident in our ability to create sustainable shareholder value.
As always, we appreciate your input as we move through this transition. I will leave with you one final thought.
As we go beyond 2020, we are focused on implementing our capital allocation strategy that balances the demand
associated with reinvestment, growth, debt repayments and, not least of which, providing shareholders a return
on their capital.
Dawn L. Farrell
President and Chief Executive Officer
February 26, 2019
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TransAlta Corporation | 2018 Annual Integrated Report Message from the Chair
Message from the Chair
2018 marked a strong year of financial and operating performance for TransAlta. Our improving performance
Dear Fellow Shareholders,
is just one indicator of progress. The bigger indicator that TransAlta is on the right track, is the enhanced clarity
and confidence we have related to our future of clean power generation and our ability to unlock and create
value from our diverse portfolio of assets.
Resilience, Strength and Focus
TransAlta has come a long way from the regulatory uncertainty and balance sheet complexity of just four years
ago. The extent of our transformation speaks to the resilience of our business, strength of our team and
relentless focus on execution. While these are significant accomplishments, our job as your Board is to keep
looking ahead, and to ensure the actions we are taking today will continue the momentum towards future
success.
In 2018, TransAlta maintained focus on this future by accelerating debt repayment, advancing the transition
from coal to gas, while making strategic investments to drive incremental growth and future cash flows. With
one of the strongest balance sheets in the sector, TransAlta invested in its clean power future by acquiring wind
farm developments with long-term contracted revenue streams and made a critical investment in the gas
pipeline for the conversion of our coal plants to gas. We also bought back shares under our share buy-back
program, something we will continue to act on when the right opportunity arises. These steps along with
continued work on the new market design and confidence in the long-term value of existing hydro and wind
assets provide a firm foundation for delivery of shareholder value.
Furthermore, to ensure we have the talent and expertise to lead TransAlta into the future, we added talent to
our executive team in 2018 with the addition of Christophe Dehout as Chief Financial Officer, Kerry O’Reilly
as Chief Legal Officer, and Jane Fedoretz, as Chief Talent & Transformation Officer. All three executives bring
enthusiasm, experience and intellect to support the company’s evolution to a leaner, more efficient, more
profitable customer-focused culture.
We continue to bring fresh insight and broad experience to our Board which offers diversity of experience,
tenure and perspective. Over the past eighteen months, we have been able to attract two very talented
Directors in the Honourable Rona H. Ambrose and Bryan D. Pinney. Our Directors, with an average tenure of
six years, bring expertise in all aspects of TransAlta’s business and their insight and judgement have guided the
development and advancement of the long-term strategy.
We have also strategically timed retirements to ensure continuity and stability on the Board. Our long-standing
director Timothy Faithfull will retire following our 2019 Annual Shareholder Meeting. On behalf of the Board,
I would like to thank Tim for the wealth of knowledge and expertise he has brought to the board during his
tenure. For my part, I expect to retire as a director and Chair next year and the Board will be working to identify
a new chair through the course of 2019.
As I complete my tenure as Chair, the Board’s priority will be to oversee the final stages of TransAlta’s
transformation plan. We continue to be like the tortoise I referred to last year - consistently moving forward
to deliver on our stated goals. The finish line is in sight. With our expert team and diverse portfolio of assets,
TransAlta is in a strong position to respond to future clean energy demands and create long-term value for
shareholders.
Ambassador Gordon D. Giffin
Chair of the Board of Directors
February 26, 2019
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TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
Management’s Discussion and Analysis
Table of Contents
Forward-Looking Statements
Additional IFRS Measures and Non-IFRS Measures
Business Model
Highlights
Discussion of Consolidated Financial Results
Significant and Subsequent Events
Financial Position
Cash Flows
Financial Instruments
2019 Financial Outlook
Other Consolidated Analysis
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Critical Accounting Policies and Estimates
Accounting Changes
Competitive Forces
TransAlta's Capital
2018 Sustainability Performance
2019 Sustainability Performance Targets
Governance and Risk Management
Fourth Quarter
Discussion of Consolidated Financial Results
Selected Quarterly Information
Disclosure Controls and Procedures
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This Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with our audited annual 2018 consolidated
financial statements and our Annual Information Form for the year ended Dec. 31, 2018. 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, 2018. 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 February 26, 2019. 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 | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
This MD&A includes "forward-looking information" within the meaning of applicable Canadian securities laws, and
Forward-Looking Statements
"forward-looking statements" within the meaning of applicable United States securities laws, including the United States
Private Securities Litigation Reform Act of 1995 (collectively referred to herein as "forward-looking statements"). All forward-
looking statements are based on our beliefs as well as assumptions based on information available at the time the
assumption was made and on management's experience and perception of historical trends, current conditions and
expected future developments, as well as other factors deemed appropriate in the circumstances. Forward-looking
statements are not facts, but only predictions and generally can be identified by the use of statements that include phrases
such as "may", "will", "can"; "could", "would", "shall", "believe", "expect", "estimate", "anticipate", "intend", "plan", "forecast"
"foresee", "potential", "enable", "continue" or other comparable terminology. These statements are not guarantees of our
future performance, events or results and are subject to risks, uncertainties and other important factors that could cause
our actual performance, events or results to be materially different from that set out in or implied by the forward-looking
statements.
In particular, this MD&A contains forward-looking statements including, but not limited to: our transformation, growth,
capital allocation and debt reduction strategies; growth opportunities from 2018 to 2031 and beyond; potential for growth
in renewables and greenfield development acquisitions; the amount of capital allocated to new growth or development
projects; our business, anticipated future financial performance and anticipated results, including our outlook and
performance targets; our expected success in executing on our growth projects; the timing and the completion of growth
and development projects, and their attendant costs; our estimated spend on growth and sustaining capital and
productivity projects; expectations in terms of the cost of operations, capital spend and maintenance, and the variability
of those costs; the conversion of our coal-fired units to natural gas, and the timing and costs thereof; the form and terms
of any definitive agreement with Tidewater, as defined below, regarding the construction of a pipeline; the terms of the
current or any further proposed normal course issuer bid, including timing and number of shares to be repurchased
pursuant to the normal course issuer bid and the acceptance thereof by the Toronto Stock Exchange; the mothballing of
certain units; the impact of certain hedges on future earnings, results and cash flows; estimates of fuel supply and demand
conditions and the costs of procuring fuel; expectations for demand for electricity, including for clean energy, in both the
short term and long term, and the resulting impact on electricity prices; the impact of load growth, increased capacity, and
natural gas and other fuel costs on power prices; expectations in respect of generation availability, capacity and production;
expectations regarding the role different energy sources will play in meeting future energy needs; expected financing of
our capital expenditures; expected governmental regulatory regimes and legislation, including the change to a capacity
market in Alberta and the expected impact on us and the timing of the implementation of such regimes and regulations, as
well as the cost of complying with resulting regulations and laws; our marketing and trading strategy and the risks involved
in these strategies; estimates of future tax rates, future tax expense and the adequacy of tax provisions; changes in
accounting estimates and accounting policies; anticipated growth rates and competition in our markets; our expectations
and obligations and anticipated liabilities relating to 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 and other currencies in locations where we do business; the
monitoring of our exposure to liquidity risk; expectations in respect to the global economic environment and growing
scrutiny by investors relating to sustainability performance; and our credit practices.
The forward-looking statements contained in this MD&A are based on many assumptions including, but not limited to, the
following: no significant changes to applicable laws and regulations, including any tax and regulatory changes in the markets
in which we operate; no material adverse impacts to the investment and credit markets; assumptions related to 2019
guidance include: Alberta spot power price equal to $50 to $60 per megawatt hours ("MWh"); Alberta contracted power
price equal to $50 to $55 per MWh; Mid-C spot power prices equal to US$20 to US$25 per MWh; Mid-C contracted power
price of US$47 to US$53 per MWh; sustaining capital between $160 million and $190 million; productivity capital of $10
million to $15 million; Sundance coal capacity factor of 30% and hydro and wind resource being approximately in line with
long-term averages; our proportionate ownership of TransAlta Renewables not changing materially; no decline in the
dividends to be received from TransAlta Renewables; the expected life extension of the coal fleet and anticipated financial
results generated on conversion; assumptions regarding the ability of the converted units to successfully compete in the
Alberta capacity market; and assumptions regarding the our current strategy and priorities, including as it pertains to our
current priorities relating to the coal-to-gas conversions, growing TransAlta Renewables and being able to realize the full
economic benefit from the capacity, energy and ancillary services from our Alberta hydro assets once the applicable power
purchase arrangement has expired.
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TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
Forward-looking statements are subject to a number of significant risks, uncertainties and assumptions that could cause
actual plans, performance, results or outcomes to differ materially from current expectations. Factors that may adversely
impact what is expressed or implied by forward-looking statements contained in this MD&A include, but are not limited
to, risks relating to: fluctuations in market prices; changes in demand for electricity and capacity and our ability to contract
our generation for prices that will provide expected returns and replace contracts as they expire; the legislative, regulatory
and political environments in the jurisdictions in which we operate; environmental requirements and changes in, or
liabilities under, these requirements; changes in general economic or market 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 and other climate-change related risks; unexpected increases in cost
structure and disruptions in the source of fuels, water or wind required to operate our facilities; failure to meet financial
expectations; natural and man-made disasters, including those resulting in dam or dyke failures; the threat of domestic
terrorism and cyberattacks; equipment failure and our ability to carry out or have completed the repairs in a cost-effective
manner or timely manner; commodity risk management and energy trading risks; industry risk and competition; the need
to engage or rely on certain stakeholder groups and third parties; fluctuations in the value of foreign currencies and foreign
political risks; the need for and availability of additional financing; structural subordination of securities; counterparty
credit risk; changes in credit and market conditions; changes to our relationship with, or ownership of, TransAlta
Renewables; risks associated with development projects and acquisitions, including capital costs, permitting, labour and
engineering risks, and delays in the construction or commissioning of projects or delays in the closing of acquisitions;
increased costs or delays in the construction or commissioning of pipelines to converted units; changes in expectations in
the payment of future dividends, including from TransAlta Renewables Inc.; inadequacy or unavailability of insurance
coverage; downgrades in credit ratings; our provision for income taxes; legal, regulatory and contractual disputes and
proceedings involving the Corporation, including as it pertains to establishing commercial operations at the South Hedland
Power Station; reliance on key personnel; and labour relations matters. The foregoing risk factors, among others, are
described in further detail in the Governance and Risk Management section of this MD&A and the Risk Factors section in
our Annual Information Form for the year ended Dec. 31, 2018.
Readers are urged to consider these factors carefully in evaluating the forward-looking statements and are cautioned not
to place undue reliance on them, which reflect the Corporation's expectations only as of the date hereof. 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 statements might occur to a
different extent or at a different time than we have described, or might not occur at all. We cannot assure that projected
results or events will be achieved.
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TransAlta Corporation | 2018 Annual Integrated Report Management’s Discussion and Analysis
Management’s Discussion and Analysis
An additional IFRS measure is a line item, heading or subtotal that is relevant to an understanding of the consolidated
financial statements but is not a minimum line item mandated under IFRS, or the presentation of a financial measure that
Additional IFRS Measures and Non-IFRS Measures
is relevant to an understanding of the consolidated financial statements but is not presented elsewhere in the consolidated
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, 2018, 2017 and 2016. Presenting these line items provides
management and investors with a measurement of ongoing operating performance that is readily comparable from period
to period.
We evaluate our performance and the performance of our business segments using a variety of measures. Certain of the
financial measures discussed in this MD&A are not defined under IFRS, are not standard measures 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. Comparable EBITDA, FFO, FCF, total consolidated net debt, adjusted net debt and segmented cash flow generated
by the business, all as defined below, are non-IFRS measures that are presented in this MD&A. See the Discussion of
Consolidated Financial Results, Segmented Comparable Results, Key Financial Ratios and TransAlta’s Capital sections of
this MD&A for additional information, including a reconciliation of such non-IFRS measures to the most comparable IFRS
measure.
Our Business
Business Model
We are one of Canada’s largest publicly traded power generators with over 108 years of operating experience. We own,
operate and manage a highly contracted and geographically diversified portfolio of assets representing 8,273 MW(1) of
capacity and use a broad range of generation fuels comprised of coal, natural gas, water, solar and wind. Our energy
marketing operations maximize margins by securing and optimizing high-value products and markets for ourselves and
our customers in dynamic market conditions.
Vision and Values
Our vision is to be a leader in clean energy using our expertise, scale and diversified fuel mix to capitalize on opportunities
in our core markets and grow 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 shareholder value by delivering solid returns through a combination of dividend yield and
disciplined growth in cash flow per share, while striving for a low to moderate risk profile over the long term, balancing
capital allocation and maintaining financial strength to allow for financial flexibility. Our comparable cash flow growth is
driven by optimizing and diversifying our existing assets and further expanding our overall portfolio and operations in
Canada, the US and Australia. We are focusing on these geographic areas as our expertise, scale and diversified fuel mix
allow us to create expansion opportunities in our core markets.
Material Sustainability Impacts
Sustainability means ensuring that our financial returns consider short- and long-term economics, environmental impacts
and societal and community needs. We track the performance of 74 sustainability-related Key Performance Indicators
(“KPIs”). We obtained a limited assurance report from Ernst & Young LLP over material KPIs. This MD&A integrates our
financial and sustainability reporting.
(1) We measure capacity as maximum capacity (see the Glossary of Key Terms for definition of this and other key terms), which is consistent with industry standards.
Capacity figures represent capacity owned and in operation unless otherwise stated, and reflect the basis of consolidation of underlying assets.
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TransAlta Corporation | 2018 Annual Integrated Report
Highlights
Year ended Dec. 31
Consolidated Financial Highlights
Revenues
Net earnings (loss) attributable to common shareholders
Cash flow from operating activities
Comparable EBITDA(1)
FFO(1)
FCF(1)
Net earnings (loss) per share attributable to common shareholders, basic and
diluted
FFO per share(1)
FCF per share(1)
Dividends declared per common share
Dividends declared per preferred share(2)
As at Dec. 31
Total assets
Total consolidated net debt(1)(3)
Total long-term liabilities
Management’s Discussion and Analysis
Management’s Discussion and Analysis
2018
2,249
(248)
820
1,123
927
524
2017
2,307
(190)
626
1,062
804
328
(0.86)
(0.66)
3.23
1.83
0.20
1.29
2018
9,428
3,141
4,421
2.79
1.14
0.12
0.77
2017
10,304
3,363
4,311
2016
2,397
117
744
1,144
734
257
0.41
2.55
0.89
0.20
1.36
2016
10,996
3,893
5,116
(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 Discussion of Consolidated Financial Results section of this MD&A for further discussion of these
items, including, where applicable, reconciliations to measures calculated in accordance with IFRS.
(2) Weighted average of the Series A, B, C, E, and G preferred share dividends declared. Dividends declared vary year over year due to timing of dividend declarations.
(3) Total consolidated net debt includes long-term debt, including current portion, amounts due under credit facilities, tax equity and finance lease obligations, net of
available cash and the fair value of economic hedging instruments on debt. See the table in the Capital Structure section of this MD&A for more details on the composition
of total consolidated net debt.
FCF, one of the Corporation's key financial metrics, totalled $524 million, up $196 million compared to last year. After
adjusting for the one-time receipt for the termination of the Sundance B and C power purchase arrangements ("PPAs") in
2018 and the Ontario Electricity Financial Corporation ("OEFC") payment in 2017 (net of our partners share), FCF was
$367 million or $56 million higher than 2017. FFO was $927 million for 2018, compared to $804 million for 2017, an
increase of $123 million.
▪
▪
All generation segments had cash flows equal to or better than the same period last year.
In Alberta, Canadian Coal, Hydro and our wind assets benefited from higher power prices. Average prices during the
year in Alberta increased to $50 per MWh from $22 per MWh in 2017, mainly reflecting the impact of higher carbon
pricing costs paid by certain generators and stronger market conditions.
Canadian Coal cash flows were significantly higher in 2018 compared to 2017 as the cash flows in the first quarter
included the one-time receipt for the termination of the Sundance B and C PPAs, which reflects the receipt of the
capacity payments that would have been received over the 2018 to 2020 period had these PPAs not been terminated.
Sustaining capital was lower in 2018 relative to 2017, primarily because of lower capital requirements in Canadian
Coal as a result of the retirement of Sundance Units 1 and 2 and the mothballing of Sundance Units 3 and 5, and lower
capital requirements in Canadian Gas and US Coal, mainly due to the timing of outages.
▪
▪
Revenues in 2018 were $2,249 million, down $58 million compared to 2017, mainly as a result of lower production within
the Canadian Coal segment due to the retirement of Sundance Units 1 and 2 and the mothballing of Sundance Units 3 and
5 resulting from the termination of the Sundance B and C PPAs. This was partially offset by increased prices in the Alberta
market.
Comparable EBITDA for the year ended Dec. 31, 2018, was $1,123 million, up $61 million compared to 2017, mainly due
to the one-time receipt of $157 million for the termination of the Sundance B and C PPAs, partially offset by higher carbon
compliance costs and reduced revenue relating to the termination of the Sundance B and C PPAs. Excluding unrealized
mark-to-market losses, comparable EBITDA was $1,145 million. Beginning in the first quarter of 2019, unrealized mark-
to-market gains or losses will be excluded from comparable EBITDA to be more comparable with other companies in the
industry.
Net loss attributable to common shareholders in 2018 was $248 million ($0.86 net loss per share) compared to a net loss
M5
TRANSALTA CORPORATION M5
TransAlta Corporation | 2018 Annual Integrated Report Management’s Discussion and Analysis
Management’s Discussion and Analysis
of $190 million ($0.66 net earnings per share) in 2017. Earnings in 2018 were negatively impacted by higher mine
depreciation and carbon compliance costs included in fuel and purchased power, higher impairments, lower finance lease
income due to the sale of the Solomon facility, and higher preferred share dividends due to the timing of declarations,
partially offset by the one-time receipt of $157 million for the termination of the Sundance B and C PPAs and lower income
tax expense. Net loss attributable to common shareholders in 2017 was negatively impacted by lower comparable EBITDA
of $82 million as well as the reduction of the US tax rate announced in December ($105 million). The US tax rate reduction
was offset by an increase in other comprehensive income.
During 2018, our strategic focus continued to be on reducing our corporate debt, improving our operating performance
and transitioning to clean power generation. The Corporation made the following progress in executing upon its strategy
Significant Events
throughout the period:
▪
On Dec. 17, 2018, we exercised our option to acquire a 50 per cent ownership in the gas pipeline ("Pioneer Pipeline")
connecting Tidewater Midstream and Infrastructure Ltd.'s ("Tidewater") Brazeau River Complex to TransAlta's
generating units at Sundance and Keephills. Our investment is subject to regulatory approval.
On Dec. 17, 2018, the Corporation announced that we will invest $270 million in our 207 MW Windrise wind project,
which was selected by the Alberta Electric System Operator ("AESO") as one of the two successful projects in the
Renewable Electricity Program Round 3.
On Nov. 13, 2018, we appointed Christophe Dehout as our Chief Financial Officer, replacing Brett Gellner (our then
interim Chief Financial Officer), who continues to serve as our Chief Strategy and Investment Officer. Mr. Dehout
brings broad experience in power generation and extensive knowledge of capital markets, mergers and acquisitions,
corporate finance and corporate transformations.
On Oct. 19, 2018, TransAlta Renewables announced that the 17.25 MW expansion of the wind facility at Kent Hills,
New Brunswick, is fully operational, bringing total generating capacity at the site to 167 MW.
On Aug. 2, 2018, the Corporation redeemed all of our then outstanding 6.40 per cent debentures, due Nov. 18, 2019,
for approximately $425 million, including the principal amount of $400 million, a prepayment premium and accrued
and unpaid interest.
On July 20, 2018, the Corporation monetized the payments under the Off-Coal Agreement ("OCA") with the
Government of Alberta and closed an approximate $345 million bond offering bearing interest at a rate of 4.509 per
cent per annum, payable semi-annually and maturing on Aug. 5, 2030.
On June 22, 2018, TransAlta Renewables closed a bought deal offering of 11,860,000 common shares through a
syndicate of underwriters. The shares were issued at a price of $12.65 per share for gross proceeds of approximately
$150 million.
On May 31, 2018, TransAlta Renewables acquired an economic interest in the 50 MW Lakeswind Wind Farm and 21
MW of solar projects located in the US ("Mass Solar") from TransAlta and acquired ownership of the 20 MW Kent
Breeze Wind Farm located in Ontario. The total purchase price for the three assets was approximately $166 million,
including the assumption of $62 million of tax equity obligations and project debt. On June 28, 2018, TransAlta
Renewables subscribed for an additional $33 million (US$25 million) of tracking preferred shares of a subsidiary of
the Corporation related to Mass Solar in order to fund the repayment of Mass Solar's project debt.
On March 15, 2018, the Corporation redeemed the then outstanding 6.650 per cent US $500 million senior notes due
May 15, 2018. The redemption price for the notes was approximately $617 million (US$516 million). Repayment of
the US senior notes was funded by cash on hand and our credit facility.
On Feb. 20, 2018, TransAlta Renewables entered into an arrangement to acquire two construction-ready wind projects
in the Northeastern United States. The wind development projects consist of: i) a 90 MW project located in
Pennsylvania that has a 15-year PPA with Microsoft Corp. ("Big Level") and ii) a 29 MW project located in New
Hampshire with two 20-year PPAs ("Antrim") (collectively, the "US Wind Projects"). On April 20, 2018, TransAlta
Renewables acquired an economic interest in the Big Level project. The Corporation expects the Antrim acquisition
to close in early 2019.
During the year, the Corporation purchased and cancelled 3,264,500 common shares at an average price of $7.02 per
common share through our normal course issuer bid ("NCIB") program, for a total cost of $23 million.
On March 31, 2018, the Corporation received approximately $157 million in compensation for the termination of the
Sundance B and C PPAs from the Balancing Pool.
On Jan. 1, 2018, the Corporation permanently shutdown Sundance Unit 1 and mothballed Sundance Unit 2. On April
1, 2018, we mothballed Sundance Unit 3 and Sundance Unit 5. On July 31, 2018, we decided to permanently shut
down Sundance Unit 2.
▪
▪
▪
▪
▪
▪
▪
▪
▪
▪
▪
▪
See the Significant and Subsequent Events section of this MD&A for further details.
M6
TRANSALTA CORPORATION M6
TransAlta Corporation | 2018 Annual Integrated Report Management’s Discussion and Analysis
Management’s Discussion and Analysis
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, including the comparable figures below, are not defined under IFRS. Those
Discussion of Consolidated Financial Results
discussed below, and elsewhere in this MD&A, are not defined under IFRS and, therefore, should not be considered in
isolation or as an alternative to or to be more meaningful than net earnings attributable to common shareholders or cash
flow from operating activities, as determined in accordance with IFRS, when assessing our financial performance or
liquidity. These measures are not necessarily comparable to a similarly titled measure of another company. Each business
segment assumes responsibility for its operating results measured to comparable EBITDA and cash flows generated by
the business. Gross margin is also a useful measure as it provides management and investors with a measurement of
operating performance that is readily comparable from period to period.
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
Comparable EBITDA
may distort our core business results. In addition, we reclassify certain transactions to facilitate the discussion of the
performance of our business:
▪
Certain assets we own in Canada (and in 2016 and 2017 in Australia) are fully contracted and recorded as finance
leases under IFRS. We believe it is more appropriate to reflect the payments we receive under the contracts as a
capacity payment in our revenues instead of as finance lease income and a decrease in finance lease receivables. We
depreciate these assets over their expected lives;
We also reclassify the depreciation on our mining equipment from fuel and purchased power to reflect the actual
cash cost of our business in our comparable EBITDA;
In December 2016, we agreed to terminate our existing arrangement with the Independent Electricity System
Operator (“IESO”) relating to our Mississauga cogeneration facility in Ontario and entered into a new Non-Utility
Generator (“NUG”) Enhanced Dispatch Contract (the “NUG Contract”) effective Jan. 1, 2017. Under the new NUG
Contract, we received fixed monthly payments until December 31, 2018 with no delivery obligations. Under IFRS,
for our reported results in 2016, as a result of the NUG Contract, we recognized a receivable of $207 million
(discounted), a pre-tax gain of approximately $191 million net of costs to mothball the units, and accelerated
depreciation of $46 million. In 2017 and 2018, on a comparable basis, we recorded the payments we received as
revenues as a proxy for operating income, and continued to depreciate the facility until Dec. 31, 2018; and
On the commissioning of the South Hedland Power Station in July 2017, we prepaid approximately $74 million of
electricity transmission and distribution costs. Interest income is recorded on the prepaid funds. We reclassify this
interest income as a reduction in the transmission and distribution costs expensed each period to reflect the net cost
to the business.
▪
▪
▪
M7
TRANSALTA CORPORATION M7
TransAlta Corporation | 2018 Annual Integrated Report Management’s Discussion and Analysis
Management’s Discussion and Analysis
A reconciliation of net earnings (loss) attributable to common shareholders to comparable EBITDA results is set out below:
Year ended Dec. 31
Net earnings (loss) attributable to common shareholders
Net earnings attributable to non-controlling interests
Preferred share dividends
Net earnings (loss)
Adjustments to reconcile net income to comparable EBITDA
Income tax expense (recovery)
Gain on sale of assets and other
Foreign exchange (gain) loss
Net interest expense
Depreciation and amortization
Comparable reclassifications
Decrease in finance lease receivables
Mine depreciation included in fuel cost
Australian interest income
Adjustments to earnings to arrive at comparable EBITDA
Impacts to revenue associated with certain de-designated and economic
hedges
Impacts associated with Mississauga recontracting(1)
Asset impairment charge(2)
2018
(248)
108
50
(90)
(6)
(1)
15
250
574
59
140
4
—
105
73
2017
(190)
42
30
(118)
64
(2)
1
247
635
59
75
2
2
77
20
Comparable EBITDA
1,123
1,062
2016
117
107
52
276
38
(4)
5
229
601
57
65
—
26
(177)
28
1,144
(1) Impacts associated with Mississauga recontracting for the year ended Dec. 31, 2018, are as follows: revenue ($108 million), and fuel and purchased power and de-
designated hedges ($3 million). Impacts associated with Mississauga recontracting for the year ended Dec. 31, 2017, are as follows: revenue ($101 million), fuel and
purchased power and de-designated hedges ($12 million), operations, maintenance and administration ($3 million), and recovery related to a renegotiated land lease
($9 million). Impacts associated with Mississauga recontracting for the year ended Dec. 31, 2016, are as follows: net other operating income ($191 million) and fuel and
purchased power and de-designated hedges ($14 million).
(2) Asset impairment charges for 2018 include a $38 million charge related to the retirement of Sundance Unit 2, Lakeswind and Kent Breeze impairment of $12 million
and a write-off of project development costs of $23 million (2017 - $20 million retirement of Sundance Unit 1, 2016 - $28 million for the Wintering Hills impairment).
Comparable EBITDA increased by $61 million for the year ended Dec. 31, 2018, compared to 2017. This was mainly due
to:
▪
Our Canadian Coal and Hydro segments were up year over year, and together accounted for an increase of $110
million of comparable EBITDA.
◦
◦
At Canadian Coal, the one-time receipt of $157 million for the termination of the Sundance B and C PPAs
was partially offset by higher carbon compliance costs and reduced revenue relating to the termination of
the Sundance B and C PPAs.
Our Hydro operations benefited from higher market prices for Ancillary Services.
▪
▪
▪
▪
Our US Coal, Canadian Gas and Australian Gas segments were down compared to 2017 for a combined decrease of
$44 million.
◦
◦
US Coal was down primarily due to non-cash mark-to-market losses.
Our Canadian Gas segment was lower mainly because 2017 comparable EBITDA benefited from the
settlement of the contract indexation dispute with the OEFC relating to the Ottawa and Windsor generating
facilities, totalling $34 million, which was mostly offset by the positive impact of the Mississauga
recontracting and cost reduction initiatives.
Our Australian Gas segment was lower mainly due to lower finance income as a result of Fortescue Metals
Group Ltd.'s ("FMG") repurchase of the Solomon Power Station partially offset by a full year of operations
for the South Hedland Power Station.
◦
Our Wind and Solar segment benefited from higher merchant prices and insurance proceeds from a tower fire at
Wyoming Wind Farm, which were offset by the unfavourable impact of the US non-cash mark-to-market losses relating
to the fair value of the Big Level PPA contract, resulting in flat comparable EBITDA.
Energy Marketing was down $2 million in 2018 compared to 2017, but overall, largely consistent year over year.
Corporate costs remained consistent with 2017 results.
Our overall results in 2018 included costs of approximately $16 million (2017 - $29 million) in operations, maintenance
and administration (“OM&A”) and $21 million (2017 - $25 million) in productivity capital relating to Project Greenlight,
our transformation initiative. We estimate that the Project Greenlight initiatives generated net $70 million in gross margin,
M8
TRANSALTA CORPORATION M8
TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
OM&A expenses and capital savings. See the Power Generating Portfolio Capital and Strategic Growth and Corporate
Transformation sections of this MD&A for further details regarding Project Greenlight.
FFO is an important metric as it provides a proxy for cash generated from operating activities before changes in working
Funds from Operations and Free Cash Flow
capital, and provides the ability to evaluate cash flow trends in comparison with results from prior periods. FCF is an
important metric as it represents the amount of cash 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 FFO and FCF are not distorted by changes that we consider temporary in nature,
reflecting, among other things, the impact of seasonal factors and timing of receipts and payments. FFO per share and FCF
per share are calculated using the weighted average number of common shares outstanding during the period.
The table below reconciles our cash flow from operating activities to our FFO and FCF:. (
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
Decrease in finance lease receivable
Other
FFO
Deduct:
Sustaining capital
Productivity capital
Dividends paid on preferred shares
Distributions paid to subsidiaries’ non-controlling interests
Other
FCF
Weighted average number of common shares outstanding in the year
FFO per share
FCF per share
2018
2017
820
44
864
59
4
927
(168)
(21)
(40)
(169)
(5)
524
287
3.23
1.83
626
114
740
59
5
804
(235)
(24)
(40)
(172)
(5)
328
288
2.79
1.14
2016
744
(73)
671
57
6
734
(272)
(8)
(42)
(151)
(4)
257
288
2.55
0.89
The increase in FCF was driven by year-over-year stronger cash flow from operating activities of $194 million partially due
to the payment for the termination of the Sundance B and C PPAs and lower sustaining and productivity capital
expenditures. Higher FCF in 2017 compared to 2016 was also driven by strong cash flow from operations before changes
in working capital and reduced sustaining and productivity capital expenditures. FCF in 2016 was lower due to payments
made to the Market Surveillance Administrator of $25 million.
M9
TRANSALTA CORPORATION M9
TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
The table below bridges our comparable EBITDA to our FFO and FCF:
Year ended Dec. 31
Comparable EBITDA
Provisions
Unrealized (gains) losses from risk management activities
Interest expense
Current income tax expense
Realized foreign exchange gain (loss)
Decommissioning and restoration costs settled
Other cash and non-cash items
FFO
Deduct:
Sustaining capital
Productivity capital
Dividends paid on preferred shares
Distributions paid to subsidiaries’ non-controlling interests
Other
FCF
Management’s Discussion and Analysis
2018
1,123
2017
1,062
7
22
(187)
(28)
5
(31)
16
927
(168)
(21)
(40)
(169)
(5)
524
(7)
(28)
(218)
(23)
15
(19)
22
804
(235)
(24)
(40)
(172)
(5)
328
2016
1,144
(114)
4
(229)
(23)
(5)
(23)
(20)
734
(272)
(8)
(42)
(151)
(4)
257
Segmented cash flows generated by the business measures the net cash generated by each of our segments after sustaining
and productivity capital expenditures, reclamation costs, provisions, and non-cash mark-to-market gains or losses. This is
Segmented Comparable Results
the cash flow available to: pay our interest and cash taxes, make distributions to our non-controlling partners and pay
dividends to our preferred shareholders, grow the business, pay down debt and return capital to our shareholders.
Year ended Dec. 31
Segmented cash flow(1)
Canadian Coal(2)
US Coal
Canadian Gas(3)
Australian Gas
Wind and Solar
Hydro
Generation segmented cash flow
Energy Marketing
Corporate
Total segmented cash flow
2018
2017
2016
279
63
228
136
211
96
1,013
33
(107)
939
175
33
221
127
201
61
818
39
(108)
749
198
21
235
99
180
53
786
25
(95)
716
(1) Segmented cash flow is a non-IFRS measure.
(2) 2018 includes $157 million received from the Balancing Pool for the early termination of the Sundance B and C PPAs in the first quarter of 2018.
(3) 2017 includes $34 million from the OEFC relating to the 2017 indexation dispute.
Cash flow generated by the business totalled $939 million in 2018, up $190 million over 2017, mainly due to the one-time
receipt of $157 million for the termination of the Sundance B and C PPAs, lower sustaining capital expenditures and higher
Ancillary Services revenue from our hydro facilities. Cash flow in 2017 was $33 million higher than 2016 due to disciplined
cost control and sustaining capital expenditure allocation.
M10
TRANSALTA CORPORATION M10
TransAlta Corporation | 2018 Annual Integrated Report
Year ended Dec. 31
Canadian Coal
Availability (%)
Contract production (GWh)
Merchant production (GWh)
Total production (GWh)
Gross installed capacity (MW)(1)
Revenues
Fuel and purchased power
Comparable gross margin
Operations, maintenance and administration
Taxes, other than income taxes
Net other operating expense (income)(2)
Comparable EBITDA
Deduct:
Sustaining capital:
Routine capital
Mine capital
Finance leases
Planned major maintenance
Total sustaining capital expenditures
Productivity capital
Total sustaining and productivity capital
Provisions
Unrealized gains (losses) on risk management activities
Decommissioning and restoration costs settled
Other
Canadian Coal cash flow
Management’s Discussion and Analysis
Management’s Discussion and Analysis
2018
91.6
8,936
5,304
14,240
3,231
912
526
386
171
13
(198)
400
17
42
14
15
88
12
100
(10)
11
19
1
279
2017
82.0
18,683
3,786
22,469
3,791
999
510
489
192
13
(40)
324
22
28
14
54
118
12
130
5
3
11
—
175
2016
85.3
19,823
3,787
23,610
3,791
1,048
386
662
178
13
(2)
473
33
23
13
100
169
1
170
85
7
13
—
198
(1) On Jan. 1, 2018, 560 MW Sundance Units 1 and 2 were shut down and mothballed, respectively. On April 1, 2018, 774 MW Sundance Units 3 and 5 were mothballed.
On July 31, 2018 Sundance Unit 2 was shut down permanently.
(2) In 2018, this includes the $157 million payment for the termination of the Sundance B and C PPAs. In both 2018 and 2017, this includes the $40 million OCA
payment.
2018
Availability for the year improved compared to 2017, mainly due to lower planned outages and unplanned outages and
derates in 2018.
Production for the year ended Dec. 31, 2018, decreased 8,229 gigawatt hours (“GWh”) compared to 2017, primarily due
to the retirement and mothballing of certain Sundance units and less dispatching, partially offset by lower planned and
unplanned outages.
Revenue for the year ended Dec. 31, 2018, decreased by $87 million compared to 2017, mainly due to lower production
offset by higher prices. Revenue per MWh of production rose to approximately $64 per MWh in 2018 from $44 per MWh
in 2017, which more than offset the increase in carbon compliance costs and resulted in higher gross margin per MWh in
2018.
Fuel, carbon compliance costs and purchased power costs per MWh were higher in 2018 compared to 2017. Coal costs on
a dollar per MWh were higher due to fixed costs and lower tonnage. Pit development work commenced in 2018 at the
Highvale mine and is expected to provide the lowest cost fuel for the remaining life of the facilities. Carbon compliance
costs were higher in 2018, reflecting the regulated increase in the carbon price and due to the fact that carbon compliance
costs are no longer recoverable on the Sundance units as the PPAs have been terminated. Both the fuel and carbon pricing
cost increases were as expected.
During the year we commenced co-firing with natural gas. Natural gas combustion produces fewer greenhouse gas ("GHG")
emissions than coal combustion, which lowers our GHG compliance costs. The combined impact of relatively low Alberta
M11
TRANSALTA CORPORATION M11
TransAlta Corporation | 2018 Annual Integrated Report Management’s Discussion and Analysis
Management’s Discussion and Analysis
gas prices and lower GHG compliance costs made this economically viable on the merchant plants for a substantial part of
the year.
OM&A costs were lower in 2018 compared to 2017. There are certain fixed and common costs that are required to maintain
the remaining operational Sundance units and some one-time OM&A costs were incurred in association with the
mothballing and retirement of Sundance Units 1 and 2. We continue to optimize the operations of the facility in response
to the merchant market.
Comparable EBITDA for the year ended Dec. 31, 2018, increased $76 million compared to 2017, as a result of the one-
time receipt of $157 million for the termination of the Sundance B and C PPAs, partially offset by higher carbon compliance
costs and reduced revenue relating to the termination of the Sundance B and C PPAs.
For the year ended Dec. 31, 2018, sustaining capital expenditures decreased by $30 million compared to 2017, mainly due
to lower planned outages and mothballing of units, partially offset by increased mine pit development work. Establishing
a new pit provides the lowest cost fuel for the remaining life of the facilities. In 2017, four planned outages were performed
throughout the year, while during 2018 there was only one planned major outage at one of our non-operated plants. Overall,
for 2018, there are four fewer units in the fleet to maintain, which significantly reduced our sustaining capital costs.
2017
Availability in 2017 was down compared to 2016 due to higher unplanned outages and derates due to coal supply
disruptions at our mine during the last half of the year, which also resulted in lower production of 1,141 GWh year over
year.
Comparable EBITDA for the year ended Dec. 31, 2017, decreased $149 million compared to 2016, due to the $80 million
reversal of the Keephills 1 provision in the fourth quarter of 2016. As expected, fuel and purchased power were impacted
by higher coal costs related to the expected higher strip ratio and higher environmental compliance costs in 2017. In
addition, we incurred additional costs in the third quarter to mitigate the impact of lower productivity at our mine.
OM&A increased $14 million year over year due mostly to contractor spend on Project Greenlight improvement initiatives
($20 million) and higher material and operating expenses ($5 million), and was partially offset by lower compensation ($11
million). See the Strategic Growth and Corporate Transformation section of this MD&A for further details.
The 2017 results also included $40 million related to OCA payments included in net other operating income. We received
our OCA payment in the third quarter.
Sustaining and productivity capital expenditures for the year ended Dec. 31, 2017, were lower by $40 million compared
to 2016, mainly due to the timing of major outages in 2017 and pit stops executed in 2016 on our Sundance 1 and 2 units.
M12
TRANSALTA CORPORATION M12
TransAlta Corporation | 2018 Annual Integrated Report
Year ended Dec. 31
US Coal
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
Operations, maintenance and administration
Taxes, other than income taxes
Comparable EBITDA
Deduct:
Sustaining capital:
Routine capital
Finance leases
Planned major maintenance
Total sustaining capital expenditures
Productivity capital
Total sustaining and productivity capital
Provisions
Unrealized gains (losses) on risk management activities
Decommissioning and restoration costs settled
US Coal cash flow
(1) Adjusted for dispatch optimization.
Management’s Discussion and Analysis
Management’s Discussion and Analysis
2018
60.2
84.6
3,329
5,704
(3,665)
5,368
1,340
442
314
128
61
5
62
2
4
11
17
—
17
—
(29)
11
63
2017
66.3
86.2
3,609
5,488
(3,625)
5,472
1,340
437
293
144
51
4
89
3
3
29
35
3
38
—
10
8
33
2016
88.1
88.9
3,535
4,896
(3,854)
4,577
1,340
380
281
99
54
4
41
3
3
11
17
—
17
7
(13)
9
21
2018
Availability for the year was down compared to 2017 due to the timing of dispatch optimization and unplanned outages
and derates in the last half of 2018, slightly offset by forced outages at Centralia Unit 1 in January 2017. In 2017 and 2018,
both Centralia Units were taken out of service in February as a result of seasonally lower prices in the Pacific Northwest.
In both years, we performed major maintenance during that time.
Production was down 104 GWh in 2018 compared to 2017, due mainly to dispatch optimization and increased unplanned
outages in the last half of the year.
OM&A costs were $10 million higher in 2018 compared to 2017, due to employee gainshare, annual incentive
compensation and retention bonuses, as well as increased disbursements paid to the community fund.
Comparable EBITDA decreased by $27 million compared to 2017 primarily due to unfavourable changes on unrealized
mark-to-market positions recorded within fuel and purchased power offset by reduced coal costs and favourable market
prices.
Sustaining and productivity capital expenditures for 2018 were $21 million lower than 2017, due to lower planned outages.
US Coal's 2018 cash flow improved by $30 million compared to the prior year, mainly due to stronger operating results
excluding unrealized mark-to-market impacts and lower sustaining and productivity capital spend.
2017
Availability was down compared to 2016 due to a forced outage on Centralia Unit 1 in January. Both Centralia Units were
taken out of service in February due to low prices in the Pacific Northwest market. We performed major maintenance on
both units during that time. The lower availability was not material to our results as our contractual obligations were
supplied with less expensive power purchased in the market during the first half of the year.
M13
TRANSALTA CORPORATION M13
TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
Production was up 895 GWh in 2017 compared to 2016 due mainly to lower dispatch optimization caused by higher prices
in the fourth quarter of 2017. The increased generation was partially offset by higher unplanned and planned maintenance.
Comparable EBITDA increased by $48 million compared to 2016 due to increased sales volumes that led to increased
margins from higher market prices and higher contract rates. Lower coal transportation costs and the favourable impact
of mark-to-market (year-over-year gain of $13 million) on certain forward financial contracts that do not qualify for hedge
accounting also positively impacted comparable EBITDA.
Sustaining and productivity capital expenditures for the year ended Dec. 31, 2017, increased by $21 million compared to
2016 due to planned outages executed during the second quarter of 2017. Productivity capital was invested in the
installation of inspection equipment to optimize heat rates on coal and improve air distribution systems.
Year ended Dec. 31
Canadian Gas
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
Deduct:
Sustaining capital:
Routine capital
Planned major maintenance
Total sustaining capital expenditures
Productivity capital
Total sustaining and productivity capital
Provisions
Unrealized gains (losses) on risk management activities
Decommissioning and restoration costs settled
2018
93.3
1,620
93
1,713
945
407
99
308
48
1
259
4
16
20
2
22
—
9
—
2017
91.6
1,504
244
1,748
952
430
113
317
53
1
263
8
22
30
2
32
3
7
—
Canadian Gas cash flow
228
221
2016
95.7
2,784
288
3,072
1,057
470
171
299
54
1
244
7
5
12
—
12
(2)
(2)
1
235
(1) 2018 and 2017 excludes capacity of Mississauga, which was mothballed in early 2017. All years include 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.
2018
Availability for the year ended Dec. 31, 2018, increased 1.7 per cent compared to 2017, mainly due to the 2017 base cycling
conversion project at Windsor and lower planned and unplanned outages at Sarnia and Windsor in 2018.
Production for the year decreased 35 GWh compared to 2017, as lower market demand at Sarnia was partially offset by
higher production at the Fort Saskatchewan, Ottawa and Windsor facilities.
Comparable EBITDA for 2018 decreased by $4 million compared to 2017, mainly due to the retroactive contract indexation
dispute settlement with the OEFC in 2017 ($34 million) offset by the positive impact from the Mississauga recontracting,
higher realized pricing at Sarnia and cost reduction initiatives. The Mississauga, Ottawa, Windsor, and our 60 per cent share
of Fort Saskatchewan, generating facilities are owned through our 50.01 per cent interest in TransAlta Cogeneration L.P.
("TA Cogen"). The Mississauga recontracting ended in December 2018 and was not renewed.
M14
TRANSALTA CORPORATION M14
TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
Sustaining capital totalled $20 million in 2018, a decrease of $10 million mainly due to higher capital spend in 2017, when
we completed the scheduled maintenance at Sarnia and the base cycling conversion project at Windsor to increase its
flexibility to respond to market prices.
Cash flow at Canadian Gas improved by $7 million for the year ended Dec. 31, 2018, compared to the prior year mainly
due to lower sustaining capital spend in 2018, partially offset by lower EBITDA. In 2017, one-time sustaining capital
expenditures were incurred for the Windsor base cycling conversion project.
2017
Availability decreased approximately four per cent compared to 2016, primarily due to a planned major inspection at our
Sarnia plant, the conversion to the peaking plant at Windsor and an unplanned steam turbine outage at Windsor.
Production in 2017 decreased 1,324 GWh compared to 2016, primarily due to changes in contracts at Mississauga and
Windsor at the end of 2016.
Comparable EBITDA for 2017 increased by $19 million compared to 2016, primarily due to the settlement with the OEFC
of the retroactive adjustment to price indices at Ottawa and Windsor and the positive impact from the temporary shutdown
at our Mississauga gas facility, partially offset by unfavourable changes on unrealized mark-to-market positions in gas
contracts that do not qualify for hedge accounting and the reduction in earnings from the change to a peaking contract at
our Windsor facility.
Sustaining capital for the year ended Dec. 31, 2017, increased $18 million compared to the same period in 2016, primarily
due to the planned major inspection at Sarnia and the base to cycling conversion project at Windsor, which was undertaken
to increase its flexibility to respond to market prices.
In December 2018, TransAlta exercised its option to terminate its agreement with Boeing Canada Inc. in Mississauga
effective Dec. 31, 2021. TransAlta is required to remove the Mississauga plant and restore the site within the three-year
time frame.
Year ended Dec. 31
Australian Gas
Availability (%)
Contract 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
Deduct:
Sustaining capital:
Routine capital
Planned major maintenance
Total sustaining and productivity capital
Other
Australian Gas cash flow
2018
94.0
1,814
450
165
4
161
37
—
124
2
—
2
(14)
136
2017
93.4
1,803
450
180
12
168
31
—
137
9
1
10
—
127
2016
93.1
1,529
425
174
20
154
25
1
128
3
11
14
15
99
(1) The 2016 figures include production capacity for the Solomon Power Station, which was accounted for as a finance lease. In 2017, FMG repurchased the Solomon
Power Station and therefore was removed from 2017 capacity, which was offset by adding capacity for the South Hedland Power Station, which achieved commercial
operations on July 28, 2017.
M15
TRANSALTA CORPORATION M15
TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
2018
Availability for the year ended Dec. 31, 2018, increased compared to 2017, mainly due to a full year of operation from the
South Hedland Power Station, which was offset by FMG's repurchase of the Solomon Power Station.
Production for 2018 was comparable to 2017, due to the addition of the South Hedland Power Station, which was offset
by FMG’s repurchase of the Solomon Power Station. Due to the nature of our contracts, changes in production do 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 decreased by $13 million compared to 2017 mainly due to FMG's repurchase of Solomon
Power Station, higher OM&A costs due to the addition of the South Hedland Power Station and ongoing legal costs
associated with our dispute with FMG, which were partially offset by higher EBITDA from the South Hedland Power Station.
Sustaining and productivity capital for 2018 decreased by $8 million compared to 2017, due to major maintenance incurred
at our Southern Cross facility in August 2017 that was not required in 2018.
Cash flow at Australian Gas increased by $9 million in 2018 mainly due to lower sustaining capital requirements and an
increase in cash flow from the collection of a long-term receivable, largely offset by lower EBITDA.
2017
Production for 2017 increased by 274 GWh compared to 2016 due to the commissioning of our South Hedland Power
Station in July 2017, and an increase in customer load, partially offset by the early termination of our lease for our Solomon
Power Station in November 2017. As a result of the early termination, we received US$325 million ($417 million) in the
fourth quarter of 2017. Due to the nature of our contracts, the increase in customer load did not have a significant financial
impact on our results as our contracts are structured as capacity payments with a pass-through of fuel costs.
Comparable EBITDA was up $9 million for 2017 compared to 2016 due to the commissioning of our South Hedland Power
Station in July 2017, which was partially offset by the early termination of our lease for our Solomon Power Station in
November 2017.
M16
TRANSALTA CORPORATION M16
TransAlta Corporation | 2018 Annual Integrated Report
Year ended Dec. 31
Wind and Solar
Availability (%)
Contract production (GWh)
Merchant production (GWh)
Total production (GWh)
Gross installed capacity (MW)(1)
Revenues
Fuel and purchased power
Comparable gross margin
Operations, maintenance and administration
Taxes, other than income taxes
Net other operating income
Comparable EBITDA
Deduct:
Sustaining capital:
Routine capital
Planned major maintenance
Total sustaining capital expenditures
Productivity capital
Total sustaining and productivity capital
Provisions
Unrealized gains (losses) on risk management activities
Decommissioning and restoration costs settled
Other (insurance proceeds)
Wind and Solar cash flow
Management’s Discussion and Analysis
Management’s Discussion and Analysis
2018
95.4
2,363
1,005
3,368
1,382
282
17
265
50
8
(6)
213
5
8
13
2
15
—
(20)
1
6
211
2017
95.8
2,362
1,098
3,460
1,363
287
17
270
48
8
—
214
1
10
11
2
13
—
—
—
—
2016
94.9
2,301
1,212
3,513
1,408
272
18
254
52
8
(1)
195
2
11
13
3
16
(1)
—
—
—
201
180
(1) The 2017 figure excludes capacity for the Wintering Hills wind facility, which was sold on March 1, 2017.
2018
Availability for the year ended Dec. 31, 2018, was comparable to 2017, which was expected.
Production for 2018 decreased by 92 GWh compared to 2017, mainly due to lower wind resources across Alberta and the
United States combined with the sale of the Wintering Hills merchant facility on March 1, 2017. This lower production was
partially offset by higher wind resources in Eastern Canada.
Comparable EBITDA for 2018 was comparable with 2017, as higher merchant prices in Alberta and insurance proceeds
from the tower fire at Wyoming Wind Farm were offset by the unfavourable impact of the US non-cash mark-to-market
losses relating to the fair value of the Big Level PPA contract and the unfavourable impact of lower wind resources.
Wind and Solar's cash flow improved by $10 million for the year ended Dec. 31, 2018, compared to the prior year, due
mainly to the addback of the US non-cash mark-to-market losses relating to the fair value of the Big Level PPA contract.
2017
Production for 2017 decreased by 53 GWh compared to 2016 as we sold the Wintering Hills wind facility in the first quarter
of 2017. Generation from our other facilities was slightly higher than in 2016.
Comparable EBITDA for 2017 increased $19 million compared to 2016, primarily driven by higher volumes at contracted
facilities, price increases on our contracted assets, higher prices in Alberta on our uncontracted assets and lower costs in
our long-term service agreements.
M17
TRANSALTA CORPORATION M17
TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Year ended Dec. 31
Hydro
Production
Energy contracted
Alberta hydro PPA assets (GWh)(1)
Other hydro energy (GWh)(1)
Energy merchant
Other hydro energy (GWh)
Total energy production (GWh)
Ancillary service volumes (GWh)(2)
Gross installed capacity (MW)
Revenues
Alberta hydro PPA assets energy
Alberta hydro PPA assets ancillary
Capacity payments received under Alberta hydro PPA(3)
Other revenue(4)
Total gross revenues
Net payment relating to Alberta hydro PPA
Revenues
Fuel and purchased power
Comparable gross margin
Operations, maintenance and administration
Taxes, other than income taxes
Net other operating income
Comparable EBITDA
Deduct:
Sustaining capital:
Routine capital, excluding hydro life extension
Hydro life extension
Planned major maintenance
Total before flood-recovery capital
Flood-recovery capital
Total sustaining capital expenditures
Productivity capital
Total sustaining and productivity capital
Hydro cash flow
Management’s Discussion and Analysis
2018
2017
2016
1,519
306
81
1,906
3,265
926
90
104
56
41
291
(135)
156
6
150
38
3
—
109
4
—
8
12
—
12
1
13
96
1,530
336
82
1,948
3,044
926
36
36
54
43
169
(48)
121
6
115
37
3
—
75
8
—
5
13
—
13
1
14
61
1,410
358
88
1,856
2,623
926
28
30
55
50
163
(37)
126
8
118
33
3
—
82
8
9
10
27
2
29
—
29
53
(1) Alberta hydro PPA assets include 12 hydro facilities on the Bow and North Saskatchewan river systems included under the PPA legislation. Other hydro facilities
include our hydro facilities in BC, Ontario and the hydro facilities in Alberta not included in the legislated PPAs.
(2) Ancillary services as described in the AESO Consolidated Authoritative Document Glossary.
(3) Capacity payments include the annual capacity charge as described in the Power Purchase Arrangements Determination Regulation AR 175/2000, available from
Alberta Queen's Printer.
(4) Other revenue includes revenues from our non-PPA hydro facilities, our transmission business and other contractual arrangements including the flood mitigation
agreement with the Alberta government and black start services.
2018
Production for 2018 decreased by 42 GWh over 2017, primarily due to lower water resources.
Comparable EBITDA for 2018 increased $34 million compared to 2017. Alberta Hydro benefited from stronger energy
prices and a higher demand for Ancillary Services.
Hydro's cash flow improved by $35 million for 2018, compared to 2017, due mainly to higher comparable EBITDA.
M18
TRANSALTA CORPORATION M18
TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
2017
Production for 2017 increased by 92 GWh compared to 2016, primarily due to stronger water resources from spring run-
off during the first nine months of 2017 in Alberta.
However, comparable EBITDA for the year ended Dec. 31, 2017, decreased by $7 million compared to 2016, due to higher
OM&A costs and a $3 million positive adjustment relating to a prior year metering issue at one of our facilities recorded
in 2016.
Sustaining capital expenditures for 2017 decreased $16 million compared to 2016 due to lower expenditures on major
overhauls. Life extension projects at Bighorn and Brazeau and flood recovery capital spend occurred in 2016.
Year ended Dec. 31
Energy Marketing
Revenues and comparable gross margin
Operations, maintenance and administration
Comparable EBITDA
Deduct:
Provisions
Unrealized gains (losses) on risk management activities
Energy Marketing cash flow
2018
2017
2016
67
24
43
3
7
33
69
24
45
(2)
8
39
76
24
52
24
3
25
2018
Comparable EBITDA for 2018 remained fairly consistent with 2017 results, which was expected.
Energy Marketing's cash flows for 2018 decreased by $6 million compared to 2017, mainly due to the settlement of trading
positions adversely affected by cold weather in the first quarter and the removal of non-cash mark-to-market gains driven
by a number of long-term trades that are expected to settle in 2019.
2017
Comparable EBITDA results were lower by $7 million compared to 2016, due to unfavourable first quarter of 2017 results
impacted by warm winter weather in the Northeast, significant precipitation in the Pacific Northwest and reduced margins
from our customer business.
2018
Corporate
Our Corporate overhead costs of $87 million were consistent in 2018 compared to 2017 as we realized benefits from cost-
efficiency initiatives that were offset by the addition of the Supply Chain Management team, which will provide future cost
savings by leveraging our buying power. Corporate cash flow also includes $20 million (2017 - $22 million) in sustaining
and productivity capital spend.
2017
Our Corporate overhead costs of $85 million were $14 million higher for the year ended Dec. 31, 2017, compared to 2016
mostly due to higher annual incentive compensation and Project Greenlight initiative fees. See the Strategic Growth and
Corporate Transformation section of this MD&A for further details. The first quarter of 2017 also includes the
reclassification of incentives for 2016 between our operational segments and our Corporate segment.
M19
TRANSALTA CORPORATION M19
TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
The methodologies and ratios used by rating agencies to assess our credit rating are not publicly disclosed. We have
Key Financial Ratios
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
strengthened our financial position and flexibility and met most of our target ranges in 2018.
Funds from Operations before Interest to Adjusted Interest Coverage
As at Dec. 31
FFO
Less: Early termination of the Sundance PPAs received during the first quarter of 2018
Add: Interest on debt and finance leases, net of interest income and capitalized interest
FFO before interest
Interest on debt and finance leases, net of interest income
Add: 50 per cent of dividends paid on preferred shares
Adjusted interest
FFO before interest to adjusted interest coverage (times)
2018
927
(157)
174
944
176
20
196
4.8
2017
2016
804
—
205
1,009
214
20
234
4.3
734
—
203
937
219
21
240
3.9
Our target for FFO before interest to adjusted interest coverage is four to five times. The ratio improved compared to 2017
due to lower interest on debt as we continued to execute our deleveraging plan.
Adjusted FFO to Adjusted Net Debt
As at Dec. 31
FFO
Less: Early termination of the Sundance PPAs received during the first quarter of 2018
Less: 50 per cent of dividends paid on preferred shares
Adjusted FFO
Period-end long-term debt(1)
Less: Cash and cash equivalents
Less: Principal portion of TransAlta OCP restricted cash
Add: 50 per cent of issued preferred shares
Fair value asset of hedging instruments on debt(2)
Adjusted net debt
Adjusted FFO to adjusted net debt (%)
2018
927
(157)
(20)
750
3,267
(89)
(27)
471
(10)
3,612
20.8
2017
2016
804
—
(20)
784
3,707
(314)
—
471
(30)
3,834
20.4
734
—
(21)
713
4,361
(305)
—
471
(163)
4,364
16.3
(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, 2018, Dec. 31, 2017, and Dec. 31, 2016.
Our adjusted FFO to adjusted net debt of 20.8 per cent remained consistent with 2017, as the significant reduction in our
net debt was offset by a decline in adjusted FFO. We reached the low end of our target range of 20 to 25 per cent in 2017
and maintained that level in 2018.
M20
TRANSALTA CORPORATION M20
TransAlta Corporation | 2018 Annual Integrated Report
Adjusted Net Debt to Comparable EBITDA
As at Dec. 31
Period-end long-term debt(1)
Less: Cash and cash equivalents
Less: Principal portion of TransAlta OCP restricted cash
Add: 50 per cent of issued preferred shares
Fair value asset of hedging instruments on debt(2)
Adjusted net debt
Comparable EBITDA
Less: Early termination of the Sundance PPAs received during the first quarter of 2018
Adjusted comparable EBITDA
Adjusted net debt to comparable EBITDA (times)
Management’s Discussion and Analysis
Management’s Discussion and Analysis
2018
3,267
(89)
(27)
471
(10)
3,612
1,123
(157)
966
3.7
2017
3,707
(314)
—
471
(30)
3,834
1,062
—
1,062
3.6
2016
4,361
(305)
—
471
(163)
4,364
1,144
—
1,144
3.8
(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, 2018, Dec. 31, 2017, and Dec. 31, 2016.
Our adjusted net debt to comparable EBITDA ratio increased compared to 2017, mainly due to the decrease in adjusted
comparable EBITDA during the year, after adjusting for the payment for the early termination of the Sundance B and C
PPAs. Our target for adjusted net debt to comparable EBITDA is 3.0 to 3.5 times.
Ability to Deliver Financial Results
The metrics we use to track our performance are comparable EBITDA, FFO and FCF. The following table compares target
to actual amounts for each of the three past fiscal years:
Year ended Dec. 31
Comparable EBITDA
FFO
FCF
2018
2017
2016
Target(1)
1,000-1,050
1,025-1,100
990-1,100
Actual
Adjusted Actual(2)
Target(1)
Actual
Adjusted Actual(3)
Target(1)
Actual
Adjusted Actual(3)
1,123
988
1,062
1,000
1,144
1,068
750-800
765-820
755-835
927
770
804
770
734
734
300-350
270-310
250-300
524
367
328
311
257
257
(1) Represents our revised outlook. As a result of strong performance in the first quarter of 2018, we revised the following 2018 targets: comparable EBITDA from the
previously announced target range of $950 million to $1,050 million to $1,000 to $1,050 million, FFO from the target range of $725 million to $800 million to
$750 million to $800 million FCF target range from $275 million to $350 million to the target range of$300 million to $350 million. In the second quarter of 2017
we reduced the following 2017 targets: Comparable EBITDA from target range of $1,025 million to $1,135 million to $1,025 to $1,100 million, FFO from the target
range of $765 million to $855 million to $765 million to $820 million FCF target range from $300 million to $365 million to the target range of $270 million to
$310 million.
(2) Comparable EBITDA for all periods was adjusted to remove the impact of unrealized mark-to-market gains or losses. Additionally, 2018 was adjusted to remove
the $157 million for the termination of the Sundance B and C PPAs as this was not included in the target. 2017 was also adjusted to remove the $34 million related to
the OEFC indexation dispute. 2016 was adjusted for the $80 million impact for non-cash adjustments related to the Keephills 1 provision.
(3) 2018 amounts were adjusted to remove the $157 million for the termination of the Sundance B and C PPAs as this was not included in the targets. 2017 amounts
were adjusted to remove the OEFC indexation dispute: FFO was reduced by $34 million and FCF was reduced by $17 million.
M21
TRANSALTA CORPORATION M21
TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
Transition to Clean Power in Alberta
Significant and Subsequent Events
Alberta Renewable Energy Program Project - Windrise
In the fourth quarter of 2018, TransAlta's 207 MW Windrise wind project was selected by the AESO as one of the two
successful projects in the third round of the Renewable Electricity Program. The Windrise facility, which is in the county
of Willow Creek, is underpinned by a 20-year Renewable Electricity Support Agreement with the AESO. The project is
expected to cost approximately $270 million and is targeted to reach commercial operation during the second quarter of
2021.
Gas Supply for Coal-to-Gas Conversions
On Dec. 17, 2018, the Corporation exercised its option to acquire 50 per cent ownership in the Pioneer Pipeline. Tidewater
will construct and operate the 120 km natural gas pipeline, which will have an initial throughput of 130 MMcf/d with the
potential to expand to approximately 440 MMcf/d. The Pioneer Pipeline will allow TransAlta to increase the amount of
natural gas it co-fires at its Sundance and Keephills coal-fired units, resulting in lower carbon emissions and costs. As well,
the Pioneer Pipeline will provide a significant amount of the gas required for the full conversion of the coal units to natural
gas. The investment for TransAlta will amount to approximately $90 million. Construction of the pipeline commenced in
November 2018 and the Pioneer Pipeline is expected to be fully operational by the second half of 2019. TransAlta’s
investment is subject to final regulatory approvals, which are expected to be finalized in the first half of 2019.
The decision to work with Tidewater advances the time frame for the construction of the Pioneer Pipeline and permits the
acceleration of plant conversions. TransAlta remains of the view that having at least two pipelines supplying natural gas
would reduce operational risks and continues to advance discussions with other parties to construct additional pipelines
to meet the remaining gas supply requirements for the facilities.
Sundance and Keephills Units 1 and 2 Coal-to-Gas Conversion Strategy
On Dec. 6, 2017, the Corporation updated its strategy to accelerate its transition to gas and renewables generation. During
2018, the Corporation mothballed and retired the following Sundance Units:
▪
▪
▪
▪
retired Sundance Unit 1 on Jan. 1, 2018;
retired Sundance Unit 2 on July 31, 2018;
temporarily mothballed Sundance Unit 3 on April 1, 2018, for a period of up to two years; and
temporarily mothballed Sundance Unit 5 on April 1, 2018, for a period of up to one year, which has recently been
extended to two years.
TransAlta is no longer planning to temporarily mothball Sundance Unit 4 and will perform maintenance during the first half
of 2019.
On December 18, 2018, the federal government published the Regulations Limiting Carbon Dioxide Emissions from Natural
Gas-fired Generation of Electricity. The regulations provide rules for new gas-fired electricity facilities, as well as specific
provisions for coal-to-gas conversions. In addition to extending their operating lives, the benefits of converting units to gas
generation include: significantly lowering carbon emissions and costs; significantly lowering operating and sustaining
capital costs; and increasing operating flexibility. TransAlta expects to convert its Sundance Units 3 to 6 and Keephills Units
1 to 3 in the 2020 to 2023 time frame.
Sundance Units 1 and 2
Canadian federal regulations stipulate that all coal plants built before 1975 must cease to operate on coal by the end of
2019, which includes Sundance Units 1 and 2. Given that Sundance Unit 1 was shut down two years early, the federal
Minister of Environment and Climate Change agreed to extend the life of Sundance Unit 2 from 2019 to 2021. This provided
the Corporation with the flexibility to respond to the regulatory environment for coal-to-gas conversions and the new
upcoming Alberta capacity market. However, in July 2018, TransAlta retired Sundance Unit 2. This decision was driven
largely by Sundance Unit 2's age, size and short useful life relative to other units, and the capital requirements needed to
return the unit to service.
Sundance Units 1 and 2 collectively made up 560 MW of the 2,141 MW capacity of the Sundance power plant, which served
as a baseload provider for the Alberta electricity system. The PPA with the Balancing Pool relating to Sundance Units 1
and 2 expired on Dec. 31, 2017.
M22
TRANSALTA CORPORATION M22
TransAlta Corporation | 2018 Annual Integrated Report Management’s Discussion and Analysis
Management’s Discussion and Analysis
In the third quarter of 2018, the Corporation recognized an impairment charge of $38 million ($28 million after-tax) relating
to the retirement of Sundance Unit 2. During the second quarter of 2017, the Corporation recognized an impairment
charge on Sundance Unit 1 of $20 million ($15 million after-tax) due to the Corporation’s decision to early retire Sundance
Unit 1.
Kent Hills 3 Wind Project
During 2017, a subsidiary of TransAlta Renewables Inc., Kent Hills Wind LP ("KHWLP"), entered into a long-term contract
with New Brunswick Power Corporation (“NB Power”) for the sale of all power generated by an additional 17.25 MW of
capacity from the Kent Hills 3 expansion wind project. At the same time, the term of the Kent Hills 1 contract with NB
Power was extended from 2033 to 2035, matching the life of the Kent Hills 2 and Kent Hills 3 wind projects.
On Oct. 19, 2018, TransAlta Renewables announced that the expansion was fully operational, bringing the total
generating capacity of the Kent Hills wind farm to 167 MW.
Acquisition of Two US Wind Projects
On Feb. 20, 2018, TransAlta Renewables announced it had entered into an arrangement to acquire two construction-ready
projects in the Northeastern United States. The wind development projects consist of: i) a 90 MW project located in
Pennsylvania that has a 15-year PPA with Microsoft Corp. ("Big Level"), and ii) a 29 MW project located in New Hampshire
with two 20-year PPAs ("Antrim") (collectively, the "US Wind Projects"), with counterparties that have Standard & Poor's
credit ratings of A+ or better. The commercial operation date for both projects is expected during the second half of 2019.
A subsidiary of TransAlta acquired Big Level on Feb. 20, 2018, whereas the acquisition of Antrim remains subject to certain
closing conditions, including the receipt of a favourable regulatory ruling. The Corporation expects the Antrim acquisition
to close in early 2019.
On April 20, 2018, TransAlta Renewables completed the acquisition of an economic interest in the US Wind Projects from
a subsidiary of TransAlta (“TA Power”). Pursuant to the arrangement, a TransAlta subsidiary owns the US Wind Projects
directly and TA Power issued to TransAlta Renewables tracking preferred shares that pay quarterly dividends based on
the pre-tax net earnings of the US Wind Projects. The tracking preferred shares have preference over the common shares
of TA Power held by TransAlta, in respect of dividends and the distribution of assets in the event of the liquidation,
dissolution or winding-up of TA Power. The construction and acquisition costs of the two US Wind Projects are expected
to be funded by TransAlta Renewables and a $25 million promissory note receivable and are estimated to be US$240
million. TransAlta Renewables will fund these costs either by acquiring additional preferred shares issued by TA Power or
by subscribing for interest-bearing notes issued by the project entity. The proceeds from the issuance of such preferred
shares or notes will be used exclusively in connection with the acquisition and construction of the US Wind Projects.
TransAlta Renewables expects to fund these acquisition and construction costs using its existing liquidity and tax equity.
During the year ended Dec. 31, 2018, TransAlta Renewables funded approximately $61 million (US$48 million) of
construction costs for Big Level. On Jan. 2, 2019, TransAlta Renewables funded an additional $45 million (US$33 million)
of construction costs.
TransAlta Renewables Acquires Three Renewable Assets from the Corporation
On May 31, 2018, TransAlta Renewables acquired from a subsidiary of the Corporation an economic interest in the 50 MW
Lakeswind wind farm in Minnesota and 21 MW of solar projects located in Massachusetts ("Mass Solar") through the
subscription of tracking preferred shares of a subsidiary of the Corporation. In addition, TransAlta Renewables acquired
from a subsidiary of the Corporation ownership of the 20 MW Kent Breeze wind farm located in Ontario. The total purchase
price for the three assets was approximately $166 million, including the assumption of $62 million of tax equity obligations
and project debt, for net cash consideration of $104 million. The Corporation continues to operate these assets on behalf
of TransAlta Renewables.
On June 28, 2018, TransAlta Renewables subscribed for an additional $33 million of tracking preferred shares of a
subsidiary of the Corporation related to Mass Solar, in order to fund the repayment of Mass Solar's project debt.
In connection with these acquisitions, the Corporation recorded a $12 million impairment charge, of which $11 million was
recorded against property, plant and equipment ("PP&E") and $1 million against intangibles.
TransAlta Renewables Closes $150 Million Offering of Common Shares
On June 22, 2018, TransAlta Renewables closed a bought deal offering of 11,860,000 common shares through a syndicate
of underwriters. The common shares were issued at a price of $12.65 per common share for gross proceeds of
approximately $150 million ($144 million of net proceeds).
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TransAlta Corporation | 2018 Annual Integrated Report Management’s Discussion and Analysis
Management’s Discussion and Analysis
The net proceeds were used to partially repay drawn amounts under TransAlta Renewables' credit facility, which was drawn
in order to fund recent acquisitions. The additional liquidity under the credit facility is to be used for general corporate
purposes, including ongoing construction costs associated with the US Wind Projects, described above.
The Corporation did not purchase any additional common shares under the offering and, following the closing, owned 161
million common shares, representing approximately 61 per cent of the outstanding common shares of TransAlta
Renewables.
$345 Million Financing
On July 20, 2018, the Corporation monetized the payments under the OCA with the Government of Alberta by closing a
$345 million bond offering through its indirect wholly owned subsidiary, TransAlta OCP LP ("TransAlta OCP"). The offering
was a private placement that was secured by, among other things, a first ranking charge over the OCA payments payable
by the Government of Alberta. The amortizing bonds bear interest at a rate of 4.509 per cent per annum, payable semi-
annually and maturing on Aug. 5, 2030. The bonds have a rating of BBB, with a stable trend, by DBRS. Under the terms of
the OCA, the Corporation receives annual cash payments on or before July 31 of approximately $40 million (approximately
$37 million, net to the Corporation), commencing Jan. 1, 2017, and terminating at the end of 2030. The net proceeds were
used to partially repay the 6.40 per cent debentures, as described below.
Early Redemption of $400 million of Debentures
On Aug. 2, 2018, the Corporation early redeemed all of its then outstanding 6.40 per cent debentures, due Nov. 18, 2019,
for the principal amount of $400 million . The redemption price was approximately $425 million in aggregate, including a
prepayment premium and accrued and unpaid interest.
Normal Course Issuer Bid
On March 9, 2018 the Corporation announced that the Toronto Stock Exchange ("TSX") accepted the notice filed by the
Corporation to implement an NCIB for a portion of its common shares. Pursuant to the NCIB, the Corporation may
repurchase up to a maximum of 14,000,000 common shares, representing approximately 4.86 per cent of issued and
outstanding common shares as at March 2, 2018. Purchases under the NCIB may be made through open market
transactions on the TSX and any alternative Canadian trading platforms on which the common shares are traded, based
on the prevailing market price. Any common shares purchased under the NCIB will be cancelled.
The period during which TransAlta is authorized to make purchases under the NCIB commenced on March 14, 2018, and
ends on March 13, 2019, or such earlier date on which the maximum number of common shares are purchased under the
NCIB or the NCIB is terminated at the Corporation's election.
Under TSX rules, not more than 102,039 common shares (being 25 per cent of the average daily trading volume on the TSX
of 408,156 common shares for the six months ended February 28, 2018) can be purchased on the TSX on any single trading
day under the NCIB, with the exception that one block purchase in excess of the daily maximum is permitted per calendar
week.
During the year ended Dec. 31, 2018, the Corporation purchased and cancelled 3,264,500 common shares at an average
price of $7.02 per common share, for a total cost of $23 million. Further transactions under the NCIB, if any, will depend
on market conditions. The Corporation retains discretion whether to make purchases under the NCIB, and to determine
the timing, amount and acceptable price of any such purchases, subject at all times to applicable TSX and other regulatory
requirements.
Early Redemption of Senior Notes
On March 15, 2018, the Corporation early redeemed all of its outstanding 6.650 per cent US $500 million senior notes due
May 15, 2018, for approximately $617 million (US$516 million). A $5 million early redemption premium was recognized
in net interest expense for the three months ended March 31, 2018.
Management and Board of Directors Changes
Donald Tremblay, the former Chief Financial Officer ("CFO"), left the Corporation, effective May 9, 2018. Brett Gellner,
Chief Strategy and Investment Officer, acted as Interim CFO, in addition to his current role, during the interim period.
During the fourth quarter of 2018, we appointed Christophe Dehout as our CFO. Mr. Dehout brings broad experience in
power generation and extensive knowledge of capital markets, mergers and acquisitions, corporate finance and corporate
transformations.
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TransAlta Corporation | 2018 Annual Integrated Report Management’s Discussion and Analysis
Management’s Discussion and Analysis
On January 25, 2019, we announced the retirement decisions of Timothy Faithfull and Ambassador Gordon Giffin. Earlier
in 2018, Mr. Faithfull had indicated to the Board his intention to retire from the Board of Directors immediately following
TransAlta's 2019 Annual Shareholders Meeting and, also in 2018, Ambassador Gordon Giffin announced his intention to
retire as director and Board Chair in 2020. The Board is undertaking a process to identify a new Chair through the course
of 2019.
Balancing Pool Provides Notice to Terminate the Alberta Sundance Power Purchase Arrangements
On Sept. 18, 2017, the Corporation received formal notice from the Balancing Pool for the termination of the Sundance B
and C PPAs effective March 31, 2018.
The termination of the Sundance B and C PPAs by the Balancing Pool was expected and the Corporation is working to
ensure it receives the termination payment that it believes it is entitled to under the Sundance B and C PPAs and applicable
legislation. The Balancing Pool paid the Corporation approximately $157 million on March 29, 2018, as part of the net book
value payment required on termination of the Sundance B and C PPAs. The Balancing Pool, however, excluded certain
mining and corporate assets that the Corporation believes should be included in the net book value calculation, which
amounts to an additional $56 million. The dispute is currently proceeding through arbitration.
Please refer to Note 4 of the audited annual 2018 consolidated financial statements for significant events impacting prior
year results.
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TransAlta Corporation | 2018 Annual Integrated Report Management’s Discussion and Analysis
Management’s Discussion and Analysis
The following chart highlights significant changes in the Consolidated Statements of Financial Position from Dec. 31,
2017, to Dec. 31, 2018:
Financial Position
Assets
Increase/
(decrease) Primary factors explaining change
Cash and cash equivalents
(225) Timing of receipts and payments.
Restricted cash (current & long-
term)
Trade and other receivables
Inventory
Finance lease receivables (long
term)
Property, plant, and equipment, net
36 Restricted cash related to the TransAlta OCP bonds ($35 million)
(177) Timing of customer receipts, collection of Mississauga recontracting receivable
($108 million), partially offset by the Antrim promissory note receivable ($25
million)
23
Increase in Canadian Coal ($50 million) partially offset by a reduction in purchased
emission credits ($13 million) and a reduction in parts and materials inventory ($5
million)
(24) Principal repayments
(414) Depreciation for the period ($649 million), revisions to decommissioning and
restoration costs ($32 million) and asset impairments ($49 million), partially offset
by additions ($294 million) and favourable changes in foreign exchange rates ($39
million)
Intangible assets
9 Additions of ($53 million) and net transfers from PP&E ($6 million), partially offset
by amortization ($50 million)
Risk management assets (current
and long term)
(95) Contract settlements and unfavourable market price movements, partially offset by
favourable changes in foreign exchange rates
Other
Total change in assets
(9)
(876)
Increase/
Liabilities and equity
(decrease)
Primary factors explaining change
Accounts payable and accrued
liabilities
(98) Timing of payments and accruals
Income taxes payable
(54) Primarily due to the payment of taxes on FMG's repurchase of the Solomon
Power Station
Credit facilities, long term debt, and
finance lease obligations (including
current portion)
(440) Repayment of long-term debt ($1,179 million), partially offset by drawings on the
credit facility ($312 million), long-term debt issued ($345 million) and
unfavourable changes in foreign exchange ($95 million)
Decommissioning and other
provisions (current and long term)
Contract liabilities
Defined benefit obligation and
other long term liabilities
(14) Liabilities settled ($41 million) and an increase in risk-adjusted discount rates
($37 million), partially offset by accretion ($24 million), new liabilities incurred
($22 million), remaining payment for Big Level acquisition ($8 million) and
unfavourable changes in foreign exchange ($10 million)
25
Increased due to IFRS 15 transition adjustment ($17 million), consideration
received ($13 million) and interest accrued and expensed during the period ($6
million), partially offset by transfers to revenue ($10 million)
(10) Decrease in the defined benefit obligation ($8 million) and reduced employee
incentive plan liability ($7 million), partially offset by increased other long-term
liabilities ($5 million)
Deferred income tax liabilities
(48) Decrease in taxable temporary differences
Equity attributable to shareholders
Non-controlling interests
(329) Net loss ($198 million), net other comprehensive loss ($12 million) common share
dividends ($57 million), preferred share dividends ($50 million), shares purchased
under NCIB ($23 million), impact of changes in our accounting policies ($14
million), partially offset by changes in non-controlling interests in TransAlta
Renewables ($24 million)
78 Net earnings ($108 million), changes in non-controlling interests in TransAlta
Renewables from share issuance ($133 million) and intercompany FVOCI
investments ($16 million), partially offset by distributions paid and payable ($180
million)
Other
Total change in liabilities and
equity
14
(876)
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TransAlta Corporation | 2018 Annual Integrated Report Management’s Discussion and Analysis
Management’s Discussion and Analysis
The following chart highlights significant changes in the Consolidated Statements of Cash Flows for the years ended Dec.
31, 2017, and Dec. 31, 2016, compared to the year ended Dec. 31, 2018:
Cash Flows
Year ended Dec. 31
Cash and cash equivalents, beginning of
year
2018 2017
314
305
Increase/
(decrease) Primary factors explaining change
9
Provided by (used in):
Operating activities
820
626
194 Higher cash flow from operations before working capital ($124
million) and a favourable change in non-cash working capital
($70 million)
Investing activities
(394)
87
Financing activities
(651)
(703)
(481) Lower proceeds on sale of Wintering Hills wind facility and
Solomon ($476 million), unfavourable change in non-cash
investing capital ($153 million) and the acquisition of Big Level
and Antrim ($30 million), partially offset by lower additions to
property, plant, and equipment ($63 million), lower tax expense
relating to investing activities ($56 million), lower additions to
intangibles ($31 million), and the lower issuance of loan
receivable ($39 million)
52 Increase in borrowings under credit facilities ($286 million),
higher issuance of long-term debt ($85 million), and higher
proceeds on the sale of non-controlling interest in a subsidiary
($144 million), partially offset by higher repayments of long-term
debt ($365 million), lower realized gains on financial instruments
($58 million) and repurchase of common shares ($23 million)
Translation of foreign currency cash
Cash and cash equivalents, end of year
—
89
(1)
314
1
(225)
Year ended Dec. 31
2017 2016
Increase/
(decrease) Primary factors explaining change
Cash and cash equivalents, beginning of
year
305
54
251
Provided by (used in):
Operating activities
626
744
(118) Unfavourable change in non-cash working capital of ($187
million), partially offset by higher cash earnings ($69 million)
Investing activities
87
(327)
Financing activities
(703)
(163)
414 Proceeds on sale of Wintering Hills wind facility and Solomon
power station disposition ($478 million), net loan receivable
($38 million), and restricted cash ($30 million)
(540) Higher repayment of long-term debt ($726 million), lower
issuance of long-term debt ($101 million), and lower proceeds
on sale of non-controlling interest in subsidiary ($162 million),
partially offset by lower borrowings under credit facility ($341
million), higher realized gains on financial instruments ($108
million), and lower dividends paid on common shares ($23
million)
Translation of foreign currency cash
(1)
(3)
Cash and cash equivalents, end of year
314
305
2
9
Financial instruments are used for proprietary trading purposes and to manage our exposure to interest rates, commodity
Financial Instruments
prices, and currency fluctuations, as well as other market risks. We may 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
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TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
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 mainly used for cash flow 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 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.
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.
Cash Flow Hedges
Foreign currency forward contracts may be used to hedge foreign exchange exposures resulting from anticipated contracts
and firm commitments denominated in foreign currencies, primarily related to capital expenditures, and currency
exposures related to US-denominated debt.
Physical and financial swaps, forward sale and purchase contracts, futures contracts, and options may be 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 may be used to offset the exposures resulting from foreign-denominated
long-term debt. Interest rate swaps may be 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 other
comprehensive income ("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.
Under IFRS 9, which we adopted on Jan. 1, 2018, hedge accounting requirements were simplified, to introduce a more
principles based approach for qualifying hedges, aligned with an entity's approach to risk management, and to revise and
simplify the hedge effectiveness requirements.
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.
Foreign-denominated long-term debt is 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. Our net investment hedges using US-
Net Investment Hedges
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
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TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
foreign-denominated expenses with revenues, such as offsetting revenues from our US operations with interest payments
on our US dollar debt.
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
Non-Hedges
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.
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
Fair Values
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 consolidated financial statements. At Dec. 31, 2018, Level III instruments had a net asset carrying value
of $695 million (2017 - $771 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, 2017.
The following table outlines our expectation on key financial targets and related assumptions for 2019:
2019 Financial Outlook
Measure
Target
Comparable EBITDA
FCF
Dividend
$875 million to $975 million
$270 million to $330 million
$0.16 per share annualized, 14 to 17 per cent payout of FCF
Range of key power price assumptions
Market
Alberta Spot
Alberta Contracted
Mid-C Spot (US$)
Mid-C Contracted (US$)
Power Prices ($/MWh)
$50 to $60
$50 to $55
$20 to $25
$47 to $53
Other assumptions relevant to 2019 financial outlook
Sustaining Capital
Productivity Capital
$160 million to $190 million
$10 million to $15 million
Sundance coal capacity factor
30%
Hydro/ Wind Resource
Long term average
Availability and Capacity
Availability of our coal fleet is expected to be in the range of 87 to 89 per cent in 2019. Availability of our other generating
Operations
assets (gas, renewables) is expected to be in the range of 92 to 96 per cent in 2019. We will be accelerating our transition
to gas and renewables generation, and continue on our coal-to-gas conversion strategy as set out in the Significant and
Subsequent Events section of this MD&A.
Market Pricing and Hedging Strategy
For 2019, power prices in Alberta are expected to be slightly higher than 2018 due to a full year of lower supply as a result
of the mothballing and shutdown of certain coal-fired units in 2018. Pacific Northwest power prices for 2019 are expected
to be lower than 2018 as 2018 prices were impacted by specific events that are not expected to occur in the future. Ontario
power prices are expected to remain consistent with 2018 prices.
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Management’s Discussion and Analysis
Management’s Discussion and Analysis
The objective of our portfolio management strategy is to deliver a high confidence for annual FCF which also provides for
positive exposure to price volatility in Alberta. Given our cash operating costs, we can be more or less hedged in a given
period, and we expect to realize our annual FCF targets through a combination of forward hedging and selling generation
into the spot market.
Fuel Costs
In Alberta, we expect the 2019 cash fuel costs for coal to be slightly lower than the 2018 costs and total fuel costs to be
lower due to increased co-firing with natural gas among the merchant units.
In the Pacific Northwest, our US Coal mine, adjacent to our power plant, is in the reclamation stage. Fuel at US Coal has
been purchased primarily from external suppliers in the Powder River Basin and delivered by rail. In 2017 we amended
our fuel and rail contract such that our costs fluctuate partly with gas prices. The delivered fuel cost in 2019 is expected to
be consistent with 2018 costs.
Most of our generation from gas is sold under contracts with pass-through provisions for fuel. For gas generation with no
pass-through provisions, 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 2019 objective for Energy Marketing is for the segment to contribute
between $75 million to $85 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.
Net Interest Expense
Net interest expense for 2019 is expected to be lower than in 2018 largely due to lower levels of debt. 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. In addition, interest expense will increase as a result of implementing IFRS 16. See the Accounting
Changes section of this MD&A for further details.
Liquidity and Capital Resources
We expect to maintain adequate available liquidity under our committed credit facilities. We currently have access to $1.0
billion in liquidity including $89 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 maturity in 2020.
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Management’s Discussion and Analysis
Management’s Discussion and Analysis
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
2019
Estimated
spend
Spent to
date(1)
Estimated
spend
Target
completion
date
Details
Project
Big Level wind development
project(2)
Antrim wind development
project(3)
Pioneer gas pipeline
partnership
Windrise wind development
project
214
97
90
270
84
25
15
—
130
Q3 2019
90 MW wind project with a 15-year PPA
72
75
Q3 2019
29 MW wind project with two 20-year PPAs
Q4 2019
50 per cent ownership in the 120 km natural
gas pipeline to supply gas to Sundance and
Keephills
47
Q2 2021
207 MW wind project with a 20-year
Renewable Electricity Support Agreement
with AESO
Total
671
124
324
(1) Represents amounts spent as of Dec. 31, 2018.
(2) The numbers reflected above are in CAD but the actual cash spend on this project is in USD and therefore these amounts will fluctuate with changes in foreign exchange
rates. The estimated total spend is USD$165 million, spent to date is USD$65 million and estimated total spend in 2019 is USD$100 million. TransAlta Renewables
will fund the construction costs using its existing liquidity and tax equity.
(3) The numbers reflected above are in CAD but the actual cash spend on this project is in USD and therefore these amounts will fluctuate with changes in foreign exchange
rates. The estimated total spend is USD$75 million, spent to date is USD$19 million and expected total spend in 2019 is USD$56 million. TransAlta Renewables will
fund the acquisition and construction costs using its existing liquidity and tax equity. The project remains subject to certain closing conditions, including the receipt of a
favourable regulatory ruling.
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
Routine capital(1)
Description
Capital required to maintain our existing generating capacity
Planned major maintenance
Regularly scheduled major maintenance
Mine capital
Finance leases
Total sustaining capital
Capital related to mining equipment and land purchases
Payments on finance leases
Insurance recoveries of sustaining
capital expenditures
Insurance proceeds related to the fire at Wyoming Wind and
Canadian Coal equipment
Total sustaining capital
Productivity capital
Projects to improve power production efficiency and
corporate improvement initiatives
Total sustaining and productivity capital
(1) Includes hydro life extension expenditures.
69
121
28
17
235
—
235
24
259
Spent in
2017
Spent in
2018
Expected
spend in
2019
50 - 60
70 - 80
20 - 25
20 - 25
50
58
42
18
168 160 - 190
(7)
—
161 160 - 190
21
10 - 15
182 170 - 205
Significant planned major outages at TransAlta's operated units for 2019 include the following:
▪
two outages for major maintenance at Keephills Unit 1 and Sundance Unit 4 within our Canadian Coal segment during
Q1 and Q2 2019;
one major outage in our Canadian Gas segment related to our Sarnia facility during Q2 2019;
distributed planned maintenance expenditures across the entire Hydro fleet; and
distributed expenditures across our wind fleet, focusing on planned component replacements.
▪
▪
▪
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Management’s Discussion and Analysis
Management’s Discussion and Analysis
Lost production as a result of planned major maintenance, excluding planned major maintenance for US Coal, which is
scheduled during a period of dispatch optimization, is estimated as follows for 2019:
GWh lost
Coal
Gas and
renewables
Total
500 - 550
400 - 450
900 - 1,000
Funding of Capital Expenditures
Funding for these planned capital expenditures is expected to be provided by cash flow from operating activities and existing
liquidity. We have access to approximately $1.0 billion in liquidity, if required. The funds required for committed growth,
sustaining capital, and productivity projects are not expected to be significantly impacted by the current economic
environment.
Other Consolidated Analysis
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
Asset Impairment Charges and Reversals
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.
Alberta Merchant CGU
During 2018, 2017, and 2016, uncertainty continued to exist within the province of Alberta regarding the Government's
Climate Leadership Plan, the future design parameters of the Alberta electricity market, and federal policies on the carbon
levy and GHG emissions. Economic conditions also contributed to continued oversupply conditions and depressed market
prices throughout 2015 to 2017. The Corporation assessed whether these factors, and events arising during the latter part
of 2016, which are more fully discussed below, presented an indicator of impairment for its Alberta Merchant CGU. In
consideration of the composition of this CGU, the Corporation 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 for any of these years, but for all years, a sensitivity analysis associated with these factors was
performed to confirm the continued existence of adequate excess of estimated recoverable amount over book value. This
analysis of the Alberta Merchant CGU continued to demonstrate a substantial cushion at the Alberta Merchant CGU in
each of 2018, 2017, and 2016, due to the Corporation’s large merchant renewable fleet in the province.
2018
Sundance Unit 2
In the third quarter of 2018, the Corporation recognized an impairment charge on Sundance Unit 2 in the amount of $38
million, due to the Corporation’s decision to retire Sundance Unit 2. Previously, the Corporation had expected Sundance
Unit 2 to remain mothballed for a period of up to two years and therefore remain within the Alberta Merchant CGU where
significant cushion exists. The impairment assessment was based on value in use and included the estimated future cash
flows expected to be derived from the Unit until its retirement on July 31, 2018. Discounting did not have a material impact.
Lakeswind and Kent Breeze
On May 31, 2018, TransAlta Renewables acquired an economic interest in Lakeswind through the subscription of tracking
preferred shares of a subsidiary of the Corporation and also purchased Kent Breeze. In connection with these acquisitions,
the assets were fair valued using discount rates that average approximately 7 per cent. Accordingly, the Corporation has
recorded an impairment charge of $12 million using the valuation in the agreement as the indicator of fair value less cost
of disposal in 2018. The impairment charge had an $11 million impact on PP&E, and a $1 million impact on Intangible assets.
2017
Sundance Unit 1
In the second quarter of 2017, the Corporation recognized an impairment charge on Sundance Unit 1 in the amount of $20
million, due to the Corporation’s decision to early retire Sundance Unit 1. Previously, the Corporation had expected
Sundance Unit 1 to operate in the merchant market in 2018 and 2019 and therefore remain within the Alberta Merchant
CGU where significant cushion exists. The impairment assessment was based on value in use and included the estimated
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Management’s Discussion and Analysis
Management’s Discussion and Analysis
future cash flows expected to be derived from the Unit until its retirement on Jan. 1, 2018. Discounting did not have a
material impact.
No separate stand-alone impairment test was required for Sundance Unit 2, as mothballing the Unit maintained the
Corporation’s flexibility to operate the Unit as part of the Corporation’s Alberta Merchant CGU to 2021.
2016
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. In connection with this sale, the Wintering Hills assets were accounted for as held
for sale at Dec. 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 in 2016.
Project Development Costs
During 2018, the Corporation wrote-off $23 million in project development costs related to projects that are no longer
proceeding.
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
Unconsolidated Structured Entities or Arrangements
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.
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
Guarantee Contracts
projects, and purchase obligations. At Dec. 31, 2018, we provided letters of credit totaling $720 million (2017 - $677
million) and cash collateral of $105 million (2017 - $67 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.
Contractual commitments are as follows:
Commitments
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 Transition Bill
Total
2019
2020
2021
2022
2023
2024 and
thereafter
Total
28
9
158
64
8
130
18
161
324
6
15
10
160
86
8
486
16
152
79
7
13
6
27
32
8
91
9
129
144
6
11
4
24
17
7
947
5
123
—
6
12
3
24
8
4
141
5
84
—
6
157
—
95
34
45
236
32
488
241
80
1,439
3,234
10
63
694
1,343
—
—
547
31
906
1,019
465
1,144
287
2,474
6,295
(1) Commitments related to Sheerness and Genesee 3 may be impacted by the cessation of coal-fired emissions on or before Dec. 31, 2030.
(2) Includes amounts under certain evergreen contracts on the assumption of the Corporation’s continued operations.
(3) Excludes impact of derivatives.
(4) Interest on long-term debt is based on debt currently in place with no assumption as to refinancing on maturity.
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Management’s Discussion and Analysis
Management’s Discussion and Analysis
As part of the TransAlta Energy Transition Bill signed into law in the State of Washington and the subsequent Memorandum
of Agreement ("MoA"), we have committed to fund US$55 million in total over the remaining life of the US 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. As at Dec. 31, 2018, the
Corporation has funded approximately US$33 million of the commitment.
Line Loss Rule Proceeding
TransAlta has been participating in a line loss rule proceeding before the Alberta Utilities Commission ("AUC"). The AUC
Contingencies
determined that it has the ability to retroactively adjust line loss charges going back to 2006 and directed the AESO to,
among other things, perform such retroactive calculations. The various decisions by the AUC are, however, subject to appeal
and challenge. A recent decision by the AUC determined the methodology to be used retroactively and it is now possible
to estimate the total retroactive potential exposure faced by TransAlta for its non-PPA MWs. The current estimate of
exposure based on known data is $15 million and therefore the Corporation increased the provision from $7.5 million to
$15 million in 2018.
FMG Disputes
The Corporation is currently engaged in two disputes with FMG. The first arose as a result of FMG’s purported termination
of the South Hedland PPA. TransAlta has sued FMG, seeking payment of amounts invoiced and not paid under the South
Hedland PPA, as well as a declaration that the PPA is valid and in force. FMG, on the other hand, seeks a declaration that
the PPA was lawfully terminated.
The second matter involves FMG’s claims against TransAlta related to the transfer of the Solomon Power Station to FMG.
FMG claims certain amounts related to the condition of the facility while TransAlta claims certain outstanding costs that
should be reimbursed.
Balancing Pool Dispute
Pursuant to a written agreement, the Balancing Pool paid the Corporation approximately $157 million on March 29, 2018
as part of the net book value payment required on termination of the Sundance B and C PPAs. The Balancing Pool, however,
excluded certain mining and corporate assets that the Corporation believes should be included in the net book value
calculation, which amounts to an additional $56 million. The dispute is currently proceeding through arbitration.
The selection and application of accounting policies is an important process that has developed as our business activities
Critical Accounting Policies and Estimates
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 annual audited 2018 consolidated financial statements.
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 Audit and Risk Committee
("ARC") and our independent auditors. The ARC has reviewed and approved our disclosure relating to critical accounting
estimates in this MD&A.
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These critical accounting estimates are described as follows:
Management’s Discussion and Analysis
Management’s Discussion and Analysis
Revenue from Contracts with Customers
Revenue Recognition
The Corporation has adopted IFRS 15 Revenue from Contracts with Customers (IFRS 15) with an initial adoption date of Jan.
1, 2018. The Corporation has elected to adopt IFRS 15 retrospectively with the modified retrospective method of transition
practical expedient and has elected to apply IFRS 15 only to contracts that are active at the date of initial application.
Comparative information has not been restated and is reported under IAS 18 Revenue (IAS 18). The Corporation's
accounting policies for the current and prior periods for revenue recognition are outlined in Note 2 of the annual audited
2018 consolidated financial statements. The significant judgments and estimates have been highlighted below.
The majority of our revenues from contracts with customers are derived from the sale of generation capacity, electricity,
thermal energy, renewable attributes and byproducts of power generation. The Corporation evaluates whether the
contracts it enters into meet the definition of a contract with a customer at the inception of the contract and on an ongoing
basis if there is an indication of significant changes in facts and circumstances. Revenue is measured based on the
transaction price specified in a contract with a customer. Revenue is recognized when control of the good or services is
transferred to the customer. For certain contracts, revenue may be recognized at the invoiced amount, as permitted using
the invoice practical expedient, if such amount corresponds directly with the Corporation’s performance to date. The
Corporation excludes amounts collected on behalf of third parties from revenue.
Identification of Performance Obligations
Each promised good or service is accounted for separately as a performance obligation if it is distinct. The Corporation’s
contracts may contain more than one performance obligation.
Where contracts contain multiple promises for goods or services, management exercises judgment in determining whether
goods or services constitute distinct goods or services or a series of distinct goods or services that are substantially the
same and that have the same pattern of transfer to the customer. The determination of a performance obligation affects
whether the transaction price is recognized at a point in time or over time. Management considers both the mechanics of
the contract and the economic and operating environment of the contract in determining whether the goods or services
in a contract are distinct.
Transaction Price
The Corporation allocates the transaction price in the contract to each performance obligation. Transaction price allocated
to performance obligations may include variable consideration. Variable consideration is included in the transaction price
for each performance obligation when it is highly probable that a significant reversal of the cumulative variable revenue
will not occur. Variable consideration is assessed at each reporting period to determine whether the constraint is lifted.
The consideration contained in some of the Corporation's contracts with customers is primarily variable, and may include
both variability in quantity and pricing, such as: revenues can be dependent upon future production volumes which are
driven by customer or market demand or by the operational ability of the plant; revenues can be dependent upon the
variable cost of producing the energy; revenues can be dependent upon market prices; and revenues can be subject to
various indices and escalators.
In determining the transaction price and estimates of variable consideration, management considers past history of
customer usage and capacity requirements, in estimating the goods and services to be provided to the customer. The
Corporation also considers the historical production levels and operating conditions for its variable generating assets.
Allocation of Transaction Price to Performance Obligations
When multiple performance obligations are present in a contract, transaction price is allocated to each performance
obligation in an amount that depicts the consideration the Corporation expects to be entitled to in exchange for transferring
the good or service.
The Corporation’s contracts generally outline a specific amount to be invoiced to a customer associated with each
performance obligation in the contract. Where contracts do not specify amounts for individual performance obligations,
the Corporation estimates the amount of the transaction price to allocate to individual performance obligations based on
their standalone selling price, which is primarily estimated based on the amounts that would be charged to customers under
similar market conditions.
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Management’s Discussion and Analysis
Management’s Discussion and Analysis
Satisfaction of Performance Obligations
The satisfaction of performance obligations requires management to use judgment as to when control of the underlying
good or service transfers to the customer. Determining when a performance obligation is satisfied affects the timing of
revenue recognition. Management considers both customer acceptance of the good or service, and the impact of laws and
regulations such as certification requirements, in determining when this transfer occurs. Management also applies
judgment in determining whether the invoice practical expedient can be relied upon in measuring progress toward complete
satisfaction of performance obligations. The invoice practical expedient permits recognition of revenue at the invoiced
amount, if that invoiced amount corresponds directly with the entity's performance to date.
The Corporation recognizes a significant financing component where the timing of payment from the customer differs
from the Corporation’s performance under the contract and where that difference is the result of the Corporation financing
the transfer of goods and services.
Revenue from Other Sources
Lease Revenue
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. 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.
Revenue from Derivatives
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.
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 described below.
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
Financial Instruments
orderly transaction between market participants at the measurement date. Fair values can be determined by reference to
prices for instruments in active markets to which we have access. In the absence of an active market, we determine fair
values based on valuation models or by reference to other similar products in active markets.
Fair values determined using valuation models require the use of assumptions. In determining those assumptions, we look
primarily to external readily observable market inputs. However, if not available, we use inputs that are not based on
observable market data.
Level Determinations and Classifications
The Level I, II and III classifications in the fair value hierarchy utilized by the Corporation are defined below. The fair value
measurement of a financial instrument is included in only one of the three levels, the determination of which is based on
the lowest level input that is significant to the derivation of the fair value.
Level I
Fair values are determined using inputs that are quoted prices (unadjusted) in active markets for identical assets or liabilities
that we have the ability to access. In determining Level I fair values, we use quoted prices for identically traded commodities
obtained from active exchanges such as the New York Mercantile Exchange.
Level II
Fair values are determined, directly or indirectly, using inputs that are observable for the asset or liability.
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Management’s Discussion and Analysis
Management’s Discussion and Analysis
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.
Our Commodity Exposure Management Policy, 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 for contracts included
in the Level III fair value measurements at Dec. 31, 2018, is an estimated total upside of $150 million (2017 - $156 million
upside) and total downside of $150 million (2017 - $157 million) impact to the carrying value of the financial instruments.
Fair values are stressed for volumes and prices. The amount of $116 million upside (2017 - $130 million upside) and $116
million downside (2017 - $130 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$20-US$35 (Dec.
31, 2017 - US$25-US$34) 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.
At the end of each reporting period, we assess whether there is any indication that a PP&E or intangible asset is impaired.
Valuation of PP&E and Associated Contracts
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
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Management’s Discussion and Analysis
Management’s Discussion and Analysis
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. The 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. No changes arose
in our CGUs in 2018.
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. As a result of our review in 2018 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.
Deferred project development costs include external, direct and incremental costs that are necessary for completing an
Project Development Costs
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.
Each significant component of an item of PP&E is depreciated over its estimated useful life. A component is a tangible asset
Useful Life of PP&E
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 2018, total depreciation and amortization expense was $710 million (2017 - $708 million, 2016 - $664 million), of which
$136 million (2017 - $73 million, 2016 - $63 million) relates to mining equipment and is included in fuel and purchased
power.
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Management’s Discussion and Analysis
Management’s Discussion and Analysis
As a result of the OCA with the Government of Alberta described in the Significant and Subsequent Events section of
this MD&A, we will cease coal-fired emissions by the end of 2030. On Jan. 1, 2017, the useful lives of the PP&E and
amortizable intangibles associated with some of our Alberta coal assets were reduced to 2030. See the Accounting
Changes section of this MD&A for further details.
We evaluate goodwill for impairment at least annually, or more frequently if indicators of impairment exist. If the carrying
Valuation of Goodwill
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 2018, 2017 and 2016 annual goodwill impairment reviews, the Corporation determined the
recoverable amounts of the CGUs 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. No reasonably possible change in the assumptions would have resulted in an impairment of goodwill.
In determining whether the Corporation’s PPAs and other long-term electricity and thermal sales contracts contain, or are,
Leases
leases, management must use judgment in assessing whether the fulfilment 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.
In accordance with IFRS, we use the liability method of accounting for income taxes. Under the liability method, deferred
Income Taxes
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 $28 million (2017 - $24 million) have been recorded on the Consolidated Statements of
Financial Position as at Dec. 31, 2018. These assets primarily relate to net operating loss carryforwards. We believe there
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Management’s Discussion and Analysis
Management’s Discussion and Analysis
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 $501 million (2017 - $549 million) have been recorded on the Consolidated Statements
of Financial Position as at Dec. 31, 2018. 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.
We provide selected pension and post-employment benefits to employees. The cost of providing these benefits is
Employee Future Benefits
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.
We recognize decommissioning and restoration provisions for PP&E in the period in which they are incurred if there is a
Decommissioning and Restoration Provisions
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, 2018, the decommissioning and restoration provisions recorded on the Consolidated Statements of Financial
Position were $407 million (2017 - $437 million). During 2017, mainly as a result of the OCA, the discount rates used for
the Canadian coal and mining operations decommissioning provisions were changed to use the 5 to 15-year rates. The use
of lower, shorter-term discount rates increased the corresponding liabilities. On average, these rates decreased by
approximately 1.60 to 2.10 per cent. Additionally, the amount and timing of cash outflows for certain Canadian coal plants
and mining operations was also revised, resulting in an increase to the corresponding liabilities.
We estimate the undiscounted amount of cash flow required to settle the decommissioning and restoration provisions is
approximately $1 billion, which will be incurred between 2019 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
4
2
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TRANSALTA CORPORATION M40
TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
Where necessary, we recognize provisions arising from ongoing business activities, such as interpretation and application
Other Provisions
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.
Accounting Changes
IFRS 15 Revenue from Contracts with Customers
Current Accounting Changes
We adopted IFRS 15 Revenue from Contracts with Customers with an initial adoption date of Jan. 1, 2018.
We elected to apply the modified retrospective method of transition. Under this method, the comparative periods
presented in the annual audited 2018 consolidated financial statements will not be restated, and comparative period
revenues continue to be reported as recognized following IAS 18 Revenue. Instead of restating prior years' revenues, we
recognized the cumulative impact of the initial application of the standard in the deficit as at Jan. 1, 2018. The cumulative
impact of applying the significant financing component requirements of IFRS 15 to an impacted contract resulted in a $13
million (net of tax impacts) increase to the deficit, an increase to the contract liability of $17 million, and a decrease in
deferred income tax liabilities of $4 million.
IFRS 15 requires that, in determining the transaction price, the promised amount of consideration is to be adjusted for the
effects of the time value of money if the timing of payments specified in a contract provides either party with a significant
benefit of financing the transfer of goods or services to the customer (“significant financing component”). The objective
when adjusting the promised amount of consideration for a significant financing component is to recognize revenue at an
amount that reflects the price that the customer would have paid, had they paid cash in the future when the goods or
services are transferred to them. We were required to apply this to one of our contracts with a customer. The application
of the significant financing component requirements results in the recognition of interest expense over the financing period
and a higher amount of revenue.
Additionally, we no longer recognize revenue (or fuel costs) related to non-cash consideration for natural gas supplied by
a customer at one of our gas plants, as it was determined under IFRS 15 that we do not obtain control of the customer-
supplied natural gas. This change had no impact on the cumulative impact of initial adoption as recognized in Deficit at Jan.
1, 2018.
Note 2 and Note 3, respectively, of our annual audited 2018 consolidated financial statements include a more detailed
discussion of our accounting policies under IFRS 15 and our adoption of IFRS 15.
IFRS 9 Financial Instruments
Effective Jan. 1, 2018, we adopted IFRS 9, which introduces new requirements for:
▪
▪
▪
the classification and measurement of financial assets and financial liabilities;
the recognition and measurement of impairment of financial assets; and
a new hedge accounting model.
In accordance with the transition provisions of the standard, we elected to not restate prior periods' comparative financial
statements.
Under the new classification and measurement requirements, financial assets must be classified and measured at either
amortized cost, at fair value through profit or loss, or at fair value through other comprehensive income. The classification
and measurement depends on the contractual cash flow characteristics of the financial asset and the entity’s business
model for managing the financial asset. The classification requirements for financial liabilities are largely unchanged. While
the Corporation had no direct impact of adoption the IFRS 9 classification and measurement requirements, a $1 million
increase in the deficit resulted from the increase in equity attributable to non-controlling interests due to the IFRS 9
classification and measurement impacts at TransAlta Renewables.
IFRS 9 introduces a new impairment model for financial assets measured at amortized cost. The expected credit loss model
requires entities to account for expected credit losses on financial assets at the date of initial recognition, and to account
for changes in expected credit losses at each reporting date to reflect changes in credit risk. The loss allowance for a financial
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TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
asset is measured at an amount equal to the lifetime expected credit loss if its credit risk has increased significantly since
initial recognition. If the credit risk on a financial asset has not increased significantly since initial recognition, its loss
allowance is measured at an amount equal to the 12-month expected credit loss. The Corporation’s management reviewed
and assessed its existing financial assets for impairment using reasonable and supportable information in accordance with
the requirements of IFRS 9 to determine the credit risk of the respective items at the date they were initially recognized,
and compared that to the credit risk as at Jan. 1, 2018. There were no significant increases in credit risk determined upon
application of IFRS 9.
The new general hedge accounting model is intended to be simpler and more closely focused on how an entity manages its
risks and introduces new effectiveness testing requirements focused on the principle of an economic relationship and
eliminates the requirement for retrospective assessment of hedge effectiveness. The Corporation's qualifying hedging
relationships in place as at Jan. 1, 2018, also qualified for hedge accounting in accordance with IFRS 9 and were therefore
regarded as continuing hedging relationships. No rebalancing of any of the hedging relationships was necessary on Jan. 1,
2018.
Note 2 and Note 3, respectively, of our annual audited 2018 consolidated financial statements include a more detailed
discussion of our accounting policies under IFRS 9 and our adoption of IFRS 9.
Change in Estimates – Useful Lives
As a result of the OCA with the Government of Alberta described in the Significant and Subsequent Events section of this
MD&A, we will cease coal-fired emissions by the end of 2030. On Jan. 1, 2018, the useful lives of some of the Corporation's
mine assets were adjusted to align with the Corporation's coal-to-gas conversion plans. As a result, depreciation expense
included in fuel and purchased power increased in total by approximately $38 million. On Jan. 1, 2017, the useful lives of
the PP&E and amortizable intangibles associated with some of our Alberta coal assets were reduced to 2030. As a result,
depreciation expense and intangibles amortization for the year ended Dec. 31, 2017, increased in total by approximately
$58 million. The useful lives may be revised or extended in compliance with the Corporation’s accounting policies,
dependent upon future operating decisions and events, such as coal-to-gas conversions.
Due to our decision to retire Sundance Unit 1 effective Jan. 1, 2018 (see the Significant and Subsequent Events section of
this MD&A for further details), the useful lives of the Sundance Unit 1 PP&E and amortizable intangibles were reduced in
the second quarter of 2017 by two years to Dec. 31, 2017. As a result, depreciation expense and intangibles amortization
for the year ended Dec. 31, 2017, increased by approximately $26 million.
Since Sundance Unit 1 was shut down two years early, the Canadian federal Minister of Environment and Climate Change
agreed to extend the life of Sundance Unit 2 from 2019 to 2021. As such, during the third quarter of 2017, we extended
the life of Sundance Unit 2 to 2021. As a result, depreciation expense and intangibles amortization for the year ended Dec.
31, 2017, decreased in total by approximately $4 million.
Accounting standards that have been previously issued by the IASB, but are not yet effective and have not been applied
Future Accounting Changes
by us, include:
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. In addition, the nature and timing of
expenses related to leases will change, as IFRS 16 replaces the straight-line operating leases expense with the depreciation
expense for the assets and interest expense on the lease liabilities. For lessors, the accounting remains essentially
unchanged.
IFRS 16 is effective for annual periods beginning on or after Jan. 1, 2019. The standard is required to be adopted either
retrospectively or using a modified retrospective approach. On transition, TransAlta has elected to apply IFRS 16 using the
modified retrospective approach effective Jan. 1, 2019. In applying IFRS 16 for the first time, the Corporation has used the
following practical expedients permitted by the standard:
▪
Exemption for short-term leases that have a remaining lease term of less than 12 months as at Jan. 1, 2019 and low
value leases;
Excluding initial direct costs for the measurement of the right-of-use asset at the date of initial application;
Using hindsight in determining the lease term where the contract contains options to extend or terminate the lease;
▪
▪
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TRANSALTA CORPORATION M42
TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
▪
Adjusting the right-of-use assets by the amount of IAS 37 onerous contract provision immediately before the date of
initial application; and
▪ Measuring the right-of-use assets at an amount equal to the lease liability, adjusted by the amount of any prepaid or
accrued lease payments relating to that lease recognized in the statement of financial position immediately before
the date of initial application.
The Corporation has substantially completed its assessment of existing operating leases. The Corporation estimates that
we will recognize right-of-use lease assets and related lease liabilities for existing operating leases where we are the lessee
in the range of $42 million to $52 million. These changes will be partially offset by the derecognition of a finance lease asset
and a finance lease liability related to a contractual arrangement that was accounted for as a finance lease under IAS 17
but is no longer considered a lease under IFRS 16.
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,
Competitive Forces
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.
Approximately 58 per cent of our gross installed capacity is
located in Alberta and approximately 50 per cent of this is
Alberta
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. The Sundance 1
and 2 Alberta PPAs expired at the end of 2017, the Sundance
3 to 6 PPAs were terminated effective March 31, 2018, and
the Keephills 1 and 2, Sheerness and Hydro PPAs will expire
at the end of 2020. The Balancing Pool acts as buyer for the
Keephills and Sheerness PPAs as a result of the terminations
in 2016 by the original buyers.
Average Spot Electricity Prices
h
W
M
/
$
n
d
C
22
18
50
2018
2017
2016
In the fourth quarter of 2017, we announced our strategy of mothballing certain facilities as well as our plan to convert
our coal-fired generation to gas-fired generation, and we announced updates to this in December 2018. See the Significant
and Subsequent Events section of this MD&A for further details.
Coal generation sold under certain 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.
Alberta's annual demand increased approximately 3 per cent from 2017 to 2018. The increase in demand was reflected
in the average pool price, which increased from $22.19/MWh in 2017 to $50.29/MWh in 2018. The majority of the pool
price increase was due to higher carbon compliance costs from thermal generation. The higher prices also positively
impacted our merchant wind and hydro portfolio.
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TRANSALTA CORPORATION M43
TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
Our market share of offer control in Alberta in 2018 was approximately 22 per cent (16 per cent if the Sundance mothballed
units are excluded from offer control).
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 a Memorandum of Understanding 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 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.
Pursuant to the Electric Utilities Act (Alberta), the Balancing Pool announced the complete termination of the Sundance 3
to 6 PPAs, effective March 31, 2018. As of April 1, 2018, the Sundance plant has been operated as a merchant facility.
There has been no announcement yet concerning the Keephills PPA.
TransAlta continues to operate the Keephills PPA generating units in their ordinary course and receives the capacity and
energy payments due to TransAlta under the PPAs.
Coal-to-Gas Conversions
On December 18, 2018, the federal government published the Regulations Limiting Carbon Dioxide Emissions from Natural
Gas-fired Generation of Electricity. The final regulation provides specific provisions for coal-to-gas conversions. The rules
for converted units will allow converted plants to operate for a set number of years following the end-of-life for the unit
under the coal regulations based on a one-time performance test at the time of conversion.
We are planning the conversion of the units at Sundance and Keephills to gas-fired generation in the 2020 to 2023 time
frame. The conversions will provide competitive, reliable, low-cost power to the Alberta market and are expected to position
them well in the proposed capacity market. We expect the first capacity auction to occur in 2020 for delivery in November
2021.
In July 2018, we retired the then mothballed Sundance Unit 2 due to its shorter useful life relative to other units, age,
size and the capital requirements needed to return the unit to service.
Our capacity in the US Pacific Northwest is represented by
our 1,340 MW Centralia coal plant. Half of the plant capacity
US Pacific Northwest
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.
Average Spot Electricity Prices
h
W
M
/
$
S
U
21
21
31
2018
2017
2016
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 during low-priced
periods.
We maintain the right to redevelop Centralia as a gas plant after coal capacity retires, with an opportunity for expedited
permitting provided for in our agreement for coal transition established with the State of Washington in 2011.
Contracted Gas and Renewables
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TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
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), Parkeston
(2026 expiry) and Fort Saskatchewan (2030 expiry) plants in this manner.
The following discusses TransAlta’s main categories of capital: Financial, Power-Generating Portfolio, Human, Intellectual,
TransAlta’s Capital
Social and Relationship, and Natural.
Our goal over the last few 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
Financial Capital
agencies. We responded to this pressure by taking significant action starting in 2014 to reduce our indebtedness and
strengthen our financial metrics.
Moody’s lowered the rating of our senior unsecured debt to Ba1 with a stable outlook in December 2015. The direct
financial impact of this downgrade has been limited. In June 2018 Moody’s revised its rating outlook to positive from
stable. During 2018, Fitch Ratings reaffirmed the Corporation’s Unsecured Debt rating and Issuer Rating of BBB- with
a stable outlook; DBRS Limited reaffirmed the Corporation’s Unsecured Debt rating and Medium-Term Notes
rating of BBB (low), the Preferred Shares rating of Pfd-3 (low) and Issuer Rating of BBB (low) with a stable outlook; and
Standard and Poor’s reaffirmed the Corporation’s Unsecured Debt rating and Issuer Rating of BBB- with a negative outlook.
The Corporation is focused on strengthening its financial position and cash flow coverage ratios to achieve stable
investment grade credit ratings. Credit ratings provide information relating to the Corporation's financing costs, liquidity
and operations and affect the Corporation's ability to obtain short-term and long-term financing and/or the cost of such
financing. 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. Risks associated with
our credit ratings are discussed in the Liquidity Risk section of this MD&A.
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TRANSALTA CORPORATION M45
TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
Capital Structure
Our capital structure consists of the following components as shown below:
As at Dec. 31
TransAlta Corporation
Recourse debt - CAD debentures
Recourse debt - US senior notes
Credit facilities
US tax equity financing
Other
Less: cash and cash equivalents
Less: principal portion of restricted cash on TransAlta OCP
Less: fair value asset of economic hedging instruments on debt(1)
Net recourse debt
Non-recourse debt
Finance lease obligations
2018
$
647
943
174
28
11
(16)
(27)
(10)
%
9
13
2
—
—
—
—
—
2017
$
1,046
1,499
—
31
13
(294)
—
(30)
1,750
24
2,265
469
63
6
1
208
69
2016
$
1,045
2,151
—
39
15
%
14
19
—
—
—
(4)
(290)
—
—
29
3
1
—
(163)
2,797
245
73
Total consolidated net debt - TransAlta Corporation
2,282
31
2,542
33
3,115
TransAlta Renewables
Credit facility
Less: cash and cash equivalents
Net recourse debt
Non-recourse debt
Total consolidated net debt - TransAlta Renewables
Total consolidated net debt
Non-controlling interests
Equity attributable to shareholders
Common shares
Preferred shares
165
(73)
92
767
859
3,141
1,137
3,059
942
2
(1)
1
11
12
43
16
42
13
27
(20)
7
814
821
3,363
1,059
3,094
942
—
—
—
11
11
44
14
40
12
—
(15)
(15)
793
778
3,893
1,152
3,094
942
%
12
25
—
—
—
(3)
—
(2)
32
3
1
36
—
—
—
9
9
45
14
36
11
Contributed surplus, deficit and accumulated other comprehensive
income
Total capital
(1,004)
7,275
(14)
100
(710)
(9)
(525)
7,748
100
8,556
(6)
100
(1) During the first quarter of 2017, we discontinued hedge accounting on certain US-denominated debt hedges. The foreign currency derivatives remain in place as
economic hedges. See the Financial Instruments section of this MD&A for further details.
We continued strengthening our financial position during 2018 and have reduced our total consolidated net debt by almost
$800 million since the end of 2016 and enhanced shareholder value by:
2018:
▪
early redeeming our outstanding 6.650 per cent US$500 million senior notes due May 15, 2018, for approximately
$617 million (US$516 million) using proceeds from the Sundance B and C PPAs termination payment and existing
liquidity;
early redeeming our outstanding 6.40 per cent $400 million debentures due Nov. 2019, for approximately $425
million;
paying out the US$25 million non-recourse debt related to the Mass Solar projects;
purchasing and cancelling 3,264,500 common shares at an average price of $7.02 per share through our NCIB program,
for a total cost of $23 million;
▪
▪
▪
2017:
▪
▪
making a scheduled US$400 million senior note repayment using existing liquidity. This repayment was hedged with
a cross-currency swap entered into on issuance of the debt that effectively reduced our Canadian dollar repayment
by approximately $107 million; and
early redeeming all of Canadian Hydro Developers Inc.’s ("CHD") outstanding non-recourse debentures.
See the Significant and Subsequent Events section of this MD&A for further details.
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TRANSALTA CORPORATION M46
TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
Throughout 2016, 2017 and 2018, we continued implementing our strategy to raise debt secured by our contracted cash
flows and completed the following debt offerings:
▪
a non-recourse bond in the amount of $345 million on July 20, 2018, with principal and interest payable semi-annually,
maturing on Aug. 5, 2030, secured by the payments we receive under the OCA;
a project-level bond in the amount of $260 million on Oct. 2, 2017, with principal and interest payable quarterly,
maturing on Nov. 30, 2033, secured by our Kent Hills wind farm;
a non-recourse bond in the amount of $202.5 million on Dec. 7, 2016, 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 on June 3, 2016, with principal and interest payable semi-annually,
and maturing on June 30, 2032, secured by our New Richmond Wind project in Quebec.
▪
▪
▪
These actions align with our strategy of issuing project-level amortizing debt to proactively manage upcoming debt
maturities.
Between 2019 and 2021, we have approximately $707 million of debt maturing. We expect to continue our deleveraging
strategy over the next three years as part of our balanced capital allocation plan.
The strengthening of the US dollar has increased our long-term debt balances by $76 million as at Dec. 31, 2018. Almost
all our US-denominated debt is hedged either through financial contracts or net investments in our US operations. During
the period, these changes in our US-denominated debt were offset as follows:
As at Dec. 31
Effects of foreign exchange on carrying amounts of US operations
(net investment hedge)(1) and finance lease receivable
Foreign currency cash flow hedges on debt
Economic hedges and other
Unhedged
Total
2018
2017
42
11
21
2
76
(43)
(45)
(18)
(7)
(113)
(1) During the first quarter of 2017, we discontinued hedge accounting on certain US-denominated debt hedges. The foreign currency derivatives remain in place as
economic hedges. See the Financial Instruments section of this MD&A for further details.
Our credit facilities provide us with significant liquidity. At Dec. 31, 2018, we had $2.0 billion (2017 - $2.0 billion) of
committed credit facilities, of which $0.9 billion (2017 - $1.4 billion) was available for use. We are in compliance with the
terms of the credit facilities. At Dec. 31, 2018, the $1.1 billion (2017 - $0.6 billion) of credit utilized under these facilities
was comprised of actual drawings of $0.3 billion (2017 - nil) and letters of credit of $0.7 billion (2017 - $0.6 billion). These
facilities are comprised of a $1.3 billion committed syndicated bank facility expiring in 2022, TransAlta Renewables $500
million committed syndicated bank credit facility expiring in 2022, and three bilateral credit facilities, totalling $240 million,
expiring in 2020.
The Melancthon Wolfe Wind, Pingston, TAPC Holdings LP, New Richmond, KHWLP and OCP non-recourse bonds with a
carrying value of $1,235 million (Dec. 31, 2017 - $1,022 million) are subject to customary financing conditions and
covenants that may restrict the Corporation’s ability to access funds generated by the facilities’ operations. Upon meeting
certain distribution tests, typically performed once per quarter, the funds can be distributed by the subsidiary entities to
their respective parent entity. These conditions include meeting a debt service coverage ratio prior to distribution, which
was met by these entities in the fourth quarter. However, funds in these entities that have accumulated since the fourth
quarter test will remain there until the next debt service coverage ratio can be calculated in the first quarter of 2019. At
Dec. 31, 2018, $33 million (Dec. 31, 2017 -$35 million) of cash was subject to these financial restrictions.
Additionally, certain non-recourse bonds require that certain reserve accounts be established and funded through cash
held on deposit and/or by providing letters of credit. The Corporation has elected to use letters of credit as at Dec. 31,
2018.
Working Capital
Including the current portion of long-term debt, the excess of current assets over current liabilities was $439 million as at
Dec. 31, 2018 (2017 - $101 million). Our working capital increased year over year mainly due to a decrease in long-term
debt due within the next year (last year, we had a US$500 million senior note due). Excluding the current portion of long-
term debt of $148 million, the excess of current assets over liabilities was $587 million as at Dec. 31, 2018 (2017 - $848
million), a decrease of $261 million, mainly due to the lower cash and cash equivalents and trade and other receivables.
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TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
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. Our Series C and Series E
Cumulative Redeemable Rate Reset Preferred Shares failed to receive the required number of minimum votes in 2017 to
give effect to conversions into Series D and Series F, respectively; accordingly, both the Series C and Series E Preferred
Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the
Board. The Series G preferred shares will reset in 2019.
The following tables outline the common and preferred shares issued and outstanding:
As at
Feb. 26, 2019
Dec. 31, 2018
Dec. 31, 2017
Number of shares (millions)
Common shares issued and outstanding, end of period
284.6
284.6
287.9
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
10.2
1.8
11.0
9.0
6.6
38.6
Non-Controlling Interests
As of Dec. 31, 2018, we own 60.9 per cent (2017 – 64.0 per cent) of TransAlta Renewables. In 2018, our ownership percent
decreased due to TransAlta Renewables issuing approximately 12 million common shares under a bought deal offering and
approximately one million common shares under their Dividend Reinvestment Plan. We did not participate in either of
these issuances.
In 2017, the South Hedland Power Station achieved commercial operation on July 28, 2017, and on Aug. 1, 2017, the
Corporation converted its 26.1 million Class B shares held in TransAlta Renewables into 26.4 million common shares of
TransAlta Renewables. At that time, the Corporation’s common share equity participation percentage in TransAlta
Renewables increased to 64 per cent from 59.8 per cent.
In 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. On Nov. 9, 2017, TransAlta Renewables
paid the debentures early, for $218 million in total, comprised of principal of $215 million and accrued interest of $3 million.
In November 2016, the economic interest was converted to direct ownership of Sarnia, Ragged Chute and Le Nordais by
TransAlta Renewables.
TransAlta Renewables is a publicly traded company whose common shares are listed on the TSX under the symbol “RNW”.
TransAlta Renewables holds a diversified, highly contracted portfolio of assets with comparatively lower carbon intensity.
We remain committed to maintaining our position as the majority shareholder and sponsor of TransAlta Renewables, with
a stated goal of maintaining our interest between 60 to 80 per cent.
We also own 50.01 per cent of TA Cogen, which owns, operates or has an interest in three natural-gas-fired facilities and
one coal-fired generating facility. In 2016, we recontracted our Mississauga cogeneration, which resulted in a pre-tax gain
of approximately $191 million, accelerated depreciation of $46 million and recognized a fuel charge for the de-designation
of gas hedges of $14 million. The Mississauga, Ottawa, Windsor and Fort Saskatchewan facilities are owned through our
50.01 per cent interest in TA Cogen. Since we own a controlling interest in TA Cogen and TransAlta Renewables, we
consolidate the entire earnings, assets and liabilities in relation to those assets.
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TransAlta Corporation | 2018 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
Interest income
Capitalized interest
Loss on redemption of bonds
Interest on finance lease obligations
Credit facility fees, bank charges, and other interest
Keephills 1 outage interest accruals (reversals)
Other(1)
Accretion of provisions
Net interest expense
Management’s Discussion and Analysis
Management’s Discussion and Analysis
2018
184
(11)
(2)
24
3
13
—
15
24
2017
218
2016
218
(7)
(9)
6
3
18
—
(3)
21
(2)
(16)
1
3
19
(10)
(4)
20
229
250
247
(1) During 2018, approximately $5 million of costs were expensed due to project level financing that is no longer practicable and approximately $7 million relates to
the significant financing component required under IFRS 15.
Although interest on debt was down due to lower debt levels, net interest expense was higher in 2018 due to the $5 million
prepayment premium relating to the early redemption of the US$500 million senior notes, $5 million of costs expensed in
connection to a project-level financing that is no longer practicable, the $19 million prepayment premium relating to the
early redemption of the $400 million debenture and lower capitalized interest.
Net interest expense increased during 2017 compared to 2016, due to lower capitalized interest and the redemption
premium recognized on the early redemption of the CHD debentures, which more than offset higher interest income.
During 2016, reversals of interest previously accrued relating to our Keephills 1 outage arbitration reduced interest
expense.
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 common and preferred shares dividends declared each quarter during 2018:
Payable date
Common
dividends
Preferred Series dividends per share
Declaration date Common shares
Preferred shares
per share
A
B
C
E
G
Feb 2, 2018
Apr 1, 2018
Mar 31, 2018
Apr 19, 2018
Jul 3, 2018
Jul 3, 2018
Jul 19, 2018
Oct 1, 2018
Sept. 30, 2018
Oct 10, 2018
Jan 1, 2019
Dec 14, 2018
Apr 1, 2019
Dec 31, 2018
Mar 31, 2019
0.04
0.04
0.04
0.04
0.04
0.16931
0.17889
0.25169
0.32463
0.33125
0.16931
0.19951
0.25169
0.32463
0.33125
0.16931
0.20984
0.25169
0.32463
0.33125
0.16931
0.22301
0.25169
0.32463
0.33125
0.16931
0.23073
0.25169
0.32463
0.33125
Non-Controlling Interests
Reported earnings attributable to non-controlling interests for the year ended Dec. 31, 2018, increased $66 million to
$108 million compared to 2017. Earnings were up at TransAlta Renewables in 2018 due to higher finance income from its
investment in the Australian business and the 2017 impairment of an investment. Earnings from TA Cogen were lower in
2018 mainly due to the settlement of the contract indexation dispute with the OEFC relating to the Ottawa and Windsor
facilities positively impacting 2017 earnings.
Reported earnings attributable to non-controlling interests for the year ended Dec. 31, 2017, decreased by $65 million
compared to 2016. Net earnings were negatively impacted by the impairment of TransAlta Renewables’ investment in the
Australian business recognized as a result of the sale of the Solomon Power Station to FMG and the purported termination
of its South Hedland PPA and by higher net interest expense due to higher outstanding borrowings. The Mississauga
recontracting has also impacted net earnings, as we recognized a $191 million gain in 2016’s results.
TRANSALTA CORPORATION M49
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TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
We monitor availability closely as a key metric to achieving our financial targets. We adjust our maintenance and sustaining
Power-Generating Portfolio Capital
capital expenditures to optimize financial returns on our investments and to align with our strategic orientations.
Availability and Production
Our availability target for our Canadian Coal fleet was 87 to
89 per cent for 2018. We achieved 93 per cent availability in
Canadian Coal. Our availability target for our other
generating assets (gas and renewables) was in the range of 95
per cent in 2018. Canadian Gas achieved 93 per cent,
Australian Gas 94 per cent and Wind and Solar exceeded 95
per cent at 95.4 per cent.
Our availability for the entire fleet in 2018, after adjusting for
dispatch optimization at US Coal, was 91.3 per cent (2017 -
86.8 per cent, 2016 - 89.2 per cent) and was improved over
last year. Lower outages and derates at Canadian Coal and
higher availability at Canadian Gas due to lower outages were
partially offset by the impact of unplanned outages and
derates at US Coal in the latter half of the year.
Production for the year ended Dec. 31, 2018, decreased
8,491 GWh compared to 2017. The decrease was mainly at
Canadian Coal where production decreased 8,229 GWh
primarily due to the mothballing and retirement of certain
Sundance units. Production at US Coal was down 104 GWh
due to the timing of dispatch optimization. Production at
Wind and Solar was also down by 92 GWh mainly due to lower
wind resources in Alberta and the United States, partially
offset by higher wind resources in Eastern Canada.
2018
2017
2016
2018
2017
2016
Adjusted Availability (%)
91.3%
86.8%
89.2%
Production (GWh)
28,409
36,900
38,157
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. In 2017, we initiated Project Greenlight across
the entire organization with the intent to deliver committed improvements across the Corporation. Savings achieved in
Canadian Coal, Mining and Canadian Gas were offset by increased costs from US Coal and Australian Gas. Increases in
OM&A are detailed in the Segmented Comparable Results section of this MD&A.
The following table outlines our generation comparable OM&A over the last three years:
Year ended Dec. 31
Generation comparable OM&A
Greenlight transformation costs included in OM&A:
Canadian Coal
US Coal
Gas, Wind and Solar, and Hydro
Adjusted generation comparable OM&A
2018
405
2017
412
(6)
(2)
(5)
392
(20)
(2)
(7)
383
2016
396
—
—
—
396
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TransAlta Corporation | 2018 Annual Integrated Report
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.
Management’s Discussion and Analysis
Management’s Discussion and Analysis
Year ended Dec. 31
Routine capital
Mine capital
Planned major maintenance
Finance leases
Total sustaining capital expenditures
Productivity capital
Flood-recovery capital
Total sustaining and productivity capital expenditures
Insurance recoveries of sustaining capital expenditures
Net amount
2018
2017
2016
50
42
58
18
168
21
—
189
(7)
182
69
28
121
17
235
24
—
259
—
259
83
23
148
16
270
8
2
280
(1)
279
Lost production as a result of planned major maintenance is as follows:
Year ended Dec. 31
GWh lost(1)
2018
381
2017
1,234
2016
938
(1) Lost production excludes periods of planned major maintenance at US Coal, which occur during periods of dispatch optimization.
Total sustaining capital expenditures were $67 million lower compared to 2017 and total productivity capital was $3 million
lower in 2018 compared to 2017. The productivity capital expenditures relate to the funding of some Project Greenlight
transformation initiatives. In certain cases, payback is expected to be achieved within three years. We also completed
planned major outages at Genessee Unit 3, Centralia Unit 2 and Sarnia.
Acquisition of Two US Wind Projects
Strategic Growth and Corporate Transformation
On Feb. 20, 2018, TransAlta Renewables announced that it had entered into an arrangement to acquire two wind
construction-ready projects in the United States. Construction of the projects has started. The wind development projects
consist of: i) a 90 MW project located in Pennsylvania that has a 15-year PPA with Microsoft Corp. ("Big Level") and ii) a
29 MW project located in New Hampshire with two 20-year PPAs ("Antrim") (collectively, the "US Wind Projects"), with
counterparties that have Standard & Poor's credit ratings of A+ or better. The acquisition of Antrim remains subject to
certain closing conditions, including the receipt of a favourable regulatory ruling. The Corporation expects the acquisition
to close in early 2019. See the Significant and Subsequent Events section of this MD&A for further details.
Kent Hills Wind Farm
During 2017, TransAlta Renewables entered into a 17-year power purchase agreement with NB Power for the sale of all
power generated by an additional 17.25 MW of capacity from the Kent Hills wind farm. On Oct. 19, 2018, TransAlta
Renewables announced that the expansion is fully operational, bringing total generating capacity of the Kent Hills wind
farm to 167 MW.
Pioneer Gas Pipeline Partnership
On Dec. 17, 2018, the Corporation exercised its option to acquire 50 per cent ownership in the Pioneer Pipeline. Tidewater
will construct and operate the 120 km natural gas pipeline, which will have an initial throughput of 130 MMcf/d with the
potential to expand to approximately 440 MMcf/d. The Pioneer Pipeline will allow TransAlta to increase the amount of
natural gas it co-fires at its Sundance and Keephills coal-fired units, resulting in lower carbon emissions and costs. As well,
the Pioneer Pipeline is expected to provide a significant amount of the gas required for the full conversion of the coal units
to natural gas. The investment for TransAlta will amount to approximately $90 million. Construction of the pipeline
commenced in November 2018 and it is expected to be fully operational by the second half of 2019. TransAlta’s investment
is subject to final regulatory approvals.
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TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
Windrise Wind Project
On Dec. 17, 2018, TransAlta's 207 MW Windrise wind project was selected by the AESO as one of the two successful
projects in the third round of the Renewable Electricity Program. The Windrise project is situated on 11,000 acres of land
located in the county of Willow Creek, Alberta. The project is underpinned by a 20-year Renewable Electricity Support
Agreement with the AESO and is expected to cost approximately $270 million and is targeted to reach commercial
operation during the second quarter of 2021.
Brazeau Hydro Pumped Storage
The Brazeau Hydro Pumped Storage project will generate and support clean electricity in the Province of Alberta. It will
store water that can be used to both generate power when it is needed and store excess power supply when demand is
low. The Brazeau Hydro Pumped Storage project is a priority for us, as it has existing infrastructure that reduces the cost
and environmental footprint of the project, is situated close to existing transmission infrastructure and allows for increased
renewables development by balancing intermittent generation from wind and solar.
The Brazeau Hydro Pumped Storage project is expected to have new capacity up to 900 MW, bringing the total Brazeau
facility from 755 MW to 1,255 MW, post-completion. We estimate an investment in the range of $1.5 billion to $2.7 billion.
During the first nine months of 2018, we invested approximately $2 million to advance the environmental study, work with
stakeholders and execute geotechnical work to help further our design and construction phase. Further advancement of
the project is dependent on securing a long-term contract.
In May 2018, the AESO released a report stating that dispatchable renewable resources are not needed in the Alberta
market before 2030. The value and benefit of the Brazeau Hydro Pumped Storage project would be well beyond the 2030
period. The Corporation still believes that generation from pumped storage should be part of future calls for power under
the Alberta Renewables program. The Corporation is not spending additional development dollars on the project at this
time but will continue to work with governments to find the appropriate financial mechanisms for bringing low-cost, green,
dispatchable renewables into the market to support low prices and emissions for Alberta customers.
Project Greenlight
Project Greenlight is a multi-year program to transform our business and the delivery of the Corporation’s strategy.
Business units are focusing both on cash flow improvements and the way the Corporation is delivering sustainable value.
Through this program we delivered on projects that improved performance by improving generation efficiency, improving
heat rates, lowering fuel costs, reducing GHG emissions, reducing operating and maintenance costs, optimizing our capital
spend, avoiding new costs, reducing overhead costs and financing costs, improving working capital, monetizing assets,
streamlining processes and achieving efficiencies. Value savings were offset by current year program costs and project
costs, made up of mostly capital expenditures. We estimate that the Project Greenlight initiatives generated net $70 million
in gross margin, OM&A expense and capital savings. This enabled financial flexibility for new investments. We invested
approximately $16 million (2017 - $29 million) in this program and an additional $21 million (2017 - $25 million) in
productivity capital in 2018.
Contractual Profile
Approximately 70 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. During the
fourth quarter of 2017, we entered into a long-term contract for the Fort Saskatchewan natural gas facility, commencing
Jan. 1, 2020. The contract has an initial 10-year term. In 2016, we entered into a long-term contract for the Akolkolex hydro
facility in B.C., expiring in 2045. Our South Hedland Power Station reached commercial operations on July 28, 2017, and
is contracted until 2042.
Engaging our workforce, developing our employees and minimizing safety incidents are the keys to human capital value
Human Capital
creation at TransAlta. The most material impacts on our human capital performance are having an engaged workforce and
keeping our employees safe.
As at Dec. 31, 2018, we had 1,883 (2017 - 2,228) active employees. This number has decreased by fifteen per cent over
2017, following reduction in positions at our coal fleet and restructuring initiatives to reduce costs and increase efficiency.
A number of unfilled positions have also been eliminated.
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Management’s Discussion and Analysis
Management’s Discussion and Analysis
With approximately 50 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 value creation. Our corporate culture 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. 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.
Our organizational structure consists of six levels, which helps facilitate pace and decision-making in our organization. Our
business operates as a business-centric model, with Coal & Mining, Gas & Renewables, Australia, and Energy Marketing &
Trading defined as our four primary businesses. Our Corporate function oversees our business and provides strategic
alignment.
Gender Diversity
A number of case studies have highlighted the link between gender diversity and additional business value. TransAlta is an
active supporter of gender diversity as a driver for value, but also as an ethical business practice. Our commitment to
increased female participation in our business is evidenced by our female participation rates on both our executive and
Board. As at Dec. 31, 2018, women made up 50 per cent of our executive team and 40 per cent of our Board. This is well
above our peers in the electricity sector. The Canadian Electricity Association reported that averages for women in
executive and on Boards in 2017 was 25.5 and 31.5, per cent respectively. This is also well above the Catalyst Accord,
which is signed by a number of leading organizations in Canada, that all support targets to ensure women comprise 30 per
cent of executive and Board roles by 2022.
Year ended Dec. 31
Women on executive team
Women on Board
TransAlta (per cent)
Industry average (per cent)
Catalyst Accord targets (per cent)
50
40
25
31
30
30
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 retirement savings plans. We have registered pension plans in Canada and the
US, as well as a superannuation plan in Australia. The plans cover substantially all employees of the Corporation, its domestic
subsidiaries, and specific named employees working internationally. These plans have defined benefit (“DB”) and defined
contribution (“DC”) options, and in Canada there was an additional DB supplemental pension plan (“SPP”) for members
whose annual earnings exceeded the Canadian income tax limit. The DB SPP was closed as of Dec. 31, 2015, and a new DC
SPP commenced for only executive members effective Jan. 1, 2016. Current executives as of Dec. 31, 2015, were
grandfathered in the DB SPP. The Australian superannuation plan is compulsory for employers with contributions required
at a rate set by the government, currently 9.5 per cent of employees’ wages and salaries.
The Canadian and US defined benefit pension plans are closed to new entrants, with the exception of the Highvale pension
plan acquired in 2013. The US 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
and actuarial valuations. We provide other health and dental benefits for disabled members and retired members, typically
up to the age of 65. The Canadian retiree benefits plan was closed for all new hired employees as of March 1, 2017. The
supplemental pension plan is non-registered and 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.
Talent and Employee Development
Talent and employee development is viewed as a key pillar of organizational health. In 2018, we extended our Change
Leadership Forum to our managers, building upon senior management training in 2017. The two-day session is focused on
organizational transformation with an emphasis on identifying root causes of barriers related to driving change.
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Management’s Discussion and Analysis
Management’s Discussion and Analysis
In 2018, we completed a six-month peer lead leadership training program, called Elevate, for our professionals and subject
matter experts. This builds on training of 75 middle management professionals in 2017. The program is focused on
establishing a learner’s mindset, building trust and influence, strengths-based leadership, being transparent, providing
feedback, collaboration as a team and innovation.
In addition to Elevate, we continued our two-day leadership program in 2018 for all of our employees. The program, called
Execution Engine, was designed to build capabilities for our people to create an organization that is both efficient and
adaptive, while living our values. The training program was built on research into what is needed for our people to help
drive and sustain change. To date, approximately 830 employees (or 44 per cent) have taken this course. Employees learn
project management (i.e., idea generation, planning, problem solving and prioritization), effective communication (i.e.,
presentations, meetings and emails), how to get the best out of people (coaching and influencing) and health (organizational
health and personal resilience).
In addition, we seek unique ways to expose employees to energy transformation and disruption. Employees are encouraged
to target development in areas to support this. In 2018, we sent 25 of our employees to the Energy Disruptors conference
in Calgary, which was highlighted by Richard Branson as a keynote. Learning from global leaders working on the energy
transition, this group returned to integrate ideas and solutions into our business, through our Project Greenlight program.
Safety
The safety of our people, communities and environment is one of our seven core values. 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 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 the Corporation.
Our approach to safety was revised in 2015 when we added to our work on occupational safety with a renewed focus on
process safety. In collaboration with ScottishPower, an organization known for achieving leading safety performance, we
launched our Total Safety Management System. The management system builds on our occupational safety program, Target
Zero, which is focused on protecting our workers on site, through personal protection equipment, inspections, safety
controls, job safety analyses, field-level hazard assessments and safety communications. Our Total Safety Management
System adds a focus on preventing incidents from our equipment and processes through definition and measurement of
safety-critical performance measures and operating limits.
In 2018, the first full year of implementation of a safety culture transformation within our Coal and Mining business was
completed. The bulk of the Canadian Coal employees were provided with new tools and capability to improve their own
personal safety and that of their workmates. In addition there have been improvements in safety standards, amenities,
housekeeping and safety leadership implemented in parallel.
This combination of initiatives has led to progress and results. In 2018 our Injury Frequency Rate (“IFR”) was 0.54 (2017 -
0.72). IFR is defined as the number of injuries (lost-time and medical) for every 200,000 hours worked. Our ultimate goal
is to achieve zero injury incidents, but annually we seek improvement over the prior year. Our target IFR in 2019 is 0.43, a
20 per cent reduction over 2018 performance.
In 2017, we introduced a new key performance indicator to help us further improve our safety performance. Total Incident
Frequency (“TIF”) tracks the total number of injuries (medical aids, lost-time injuries, restricted works and first aids) relative
to employee hours worked. First aids can be minor (such as a cut or scratch); nevertheless, incident awareness and
understanding provide us with preventative safety knowledge, which translates into education for employees and injury
avoidance. Our TIF in 2018 was 1.98, which was a 44 per cent improvement over 2017 performance. We are targeting a
TIF of 1.58 in 2019, a 20 per cent reduction over 2017 performance. As noted above, our long-term goal is zero.
Year ended Dec. 31
IFR
TIF
2018
0.54
1.98
2017
0.72
3.54
2016
0.85
—
On December 29, 2018, we were notified of an incident that occurred and resulted in the fatality of an employee of Coalview
Centralia LLC, which operates a fine coal recovery project within the Centralia mine site. Coalview Centralia LLC is a
company that provides reclamation services to TransAlta and is not otherwise affiliated with the Corporation. We are all
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TransAlta Corporation | 2018 Annual Integrated Report Management’s Discussion and Analysis
Management’s Discussion and Analysis
deeply saddened by this situation and our thoughts and prayers are with the families, co-workers and friends impacted.
Safety is an integral value at TransAlta and we continue to work every day to make our work environments safe.
We reward our business units for safety leadership annually at our President's Awards. This year the award for Safety
Leadership and Performance was given to our Hydro fleet for achieving target zero in 2018. No medical aids and injuries
occurred in 2018, despite 145,000 exposure hours while operating 27 facilities. It was a fantastic achievement from our
Hydro business unit and provides inspiration for our other business units.
At TransAlta we define intellectual capital as our knowledge-based assets. Measuring these assets serves two purposes.
Intellectual Capital
First, we seek to understand our knowledge-based assets to improve our management and performance of these assets.
Second, we seek to understand these assets to communicate their real value. The following highlights some of our
knowledge-based assets, which we believe provide us with a competitive edge and that contribute to shareholder value.
Brand Recognition
Our employee culture is supported by a purpose-based, long-term and sustainable business strategy, which is growth in
affordable and clean power generation. TransAlta has operated power generation assets for over 100 years, which reflects
this approach to long-term and sustainable business. A long-term commitment to business and partnerships lends itself to
goodwill and brand recognition, something we value and don’t take for granted. We believe our low-cost and clean power
strategy, supported by our internal values and sustainable approach to business, will help support and continue to increase
our brand recognition positively.
Diversified Knowledge
The experience and acumen of our employees further enhances our capital value creation. Our business has been operating
for over 100 years, and many of our employees have been with us for 30 plus years.
Our experience in developing and operating power generation technologies is highlighted below. The transition of our coal
assets to natural gas is a natural fit with our operating experience. Relative to coal, gas operations have lower operating
costs, have increased operating reliability and flexibility, require less manpower and reduce GHG and air emissions. Our
trading and marketing business complements our knowledge of operating power generation assets.
Power generation type
Operating experience (years)
Hydro
Natural Gas
Coal
Wind
Solar
107
68
68
16
3
Innovation: Idea Generation and Project Management
We believe that global marketplace disruption is a new normal and we recognize that to adapt to the pace of change and
remain competitive, our employees and processes must be nimble, adaptive and supporting working more efficiently, while
at speed. For further details on our investment in our workforce, please see the Talent and Employee Development
discussion in the Human Capital subsection of this MD&A.
This is evidenced by our ongoing internal transformation, called Project Greenlight, which is entering its third year since
implementation. This project is focused on bottom-up innovation, specifically fostering a culture of idea generation,
development of ideas into projects with defined KPIs, milestones and execution or delivery dates, and ongoing project
management to ensure success. Where we fail, we idea generate, build and test again. Since inception, we have spent
considerable time educating and training our employees to both think differently and then manage their business case
from idea to delivering sustained value. Year three is the final year of the project and we plan to transition Project Greenlight
into the business as a sustained process.
For further details on our investment in our workforce, please see the Talent and Employee Development discussion in the
Human Capital subsection of this MD&A.
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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 and developer of wind technology in Canada and are now one of the largest wind generators 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 a 21
MW solar facility in Massachusetts.
As we move towards our vision of becoming the leading clean power corporation in Canada by 2025, we continue to seek
solutions to innovate and create value for investors, society and the environment. This is evidenced by our announcements
of the accelerated coal-to-gas conversion plans, the expansion of our Kent Hills wind farm in New Brunswick, the 90 MW
Big Level and 29 MW Antrim wind development projects in the US, the 207 MW Windrise wind development project in
Alberta, proposed solar development on our reclaimed mine site at our Centralia facility in Washington State, and the
exploration of hydro expansion.
We are keeping 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 more information on innovation at
TransAlta, please visit www.transalta.com/about-us/innovation.
In addition, our teams continuously explore the 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. The following are further examples of how we have developed innovative solutions to optimize and maximize
value from our fleet:
Operations Diagnostic Centre
TransAlta has run 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
Our Operational Integrity program is the integration of sustainability, specifically safety, into asset management. It is a
program designed to achieve process and equipment safety by understanding and monitoring key operational risks and
implementing mitigation measures. Consider it proactive safety. In 2017, we put into place our Total Safety Management
System, which integrates our work in process safety with our existing strength in occupational safety programs. We
continue to see a positive increase in self-reporting and addressing process safety hazards as awareness and new tools are
being introduced. This is evidenced by our trend in safety incidents, which decreased in 2018 to an IFR of 0.54 (2017 -
0.72). This was one of our best safety performance years in our history. Our goal is zero and the Operational Integrity
program is a tried and tested tool to help propel us closer to this goal.
Creating shared value for our stakeholders is the key to social and relationship value creation at TransAlta. The most
Social and Relationship Capital
material impacts on our social and relationship performance are public health and safety, anti-competitive behaviour and
fostering better relationships with Indigenous neighbours, communities, stakeholders, governments, industry and
landowners where we operate.
Public Health and Safety
We seek to ensure public health and safety through measures that include restricting physical access to our operating sites
and minimizing our environmental impact. It is our goal to keep safe our employees and the peoples and communities where
we operate.
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We specifically look to minimize the following risks:
▪
▪
▪
▪
harm to person(s),
damage to property,
increased liability due to negligence, and
loss of organizational reputation and integrity.
We actively monitor air emissions from our coal and gas plants. Our large coal facilities have Continuous Emissions
Monitoring Systems in place, which help us monitor our pollutant emission levels to ensure they are in line with acceptable
limits. When we are in breach of regulatory limits we report this to regulatory bodies and conduct a root cause analysis to
understand how we can eliminate future breaches from occurring. In 2018, we had two mercury exceedance events at our
Centralia coal plant and one NOx stack breach at our Sundance facility. All of the events were captured through our
monitoring systems and resolved quickly as a result. These incidents were all reported to regulatory bodies and were
deemed to be minor.
Of note, our coal plants currently capture 80 per cent of mercury emissions and the majority of particulate matter emissions.
Both mercury and particulate matter emissions 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 dated Nov. 19, 2015, and
conducted by University of Alberta scientist Dr. Warren Kindzierski, using provincial government monitoring data over
nine years, also show that 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 industry, vehicles and wood-burning
fireplaces.
Assuming reasonably anticipated growth and operating scenarios, we expect future GHG emissions and air pollution
emissions performance will be dramatically reduced in respect of our existing assets as we execute our coal-to-gas
conversion strategy. GHG emissions from coal are expected to be cut within the range of 60 per cent or 12 million tonnes
carbon dioxide equivalent (CO2e). We currently capture 80 per cent of mercury emissions at our coal plants and mercury
emissions will be eliminated following the coal-to-gas conversion. Particulate matter and sulphur dioxide emissions will be
virtually eliminated or considered negligible post-coal-to-gas conversion and diesel burn. Our nitrogen dioxide emissions
will also be reduced in the range of approximately 50 per cent.
Indigenous Relationships and Partnerships
The focus of our efforts in this area is to fulfill TransAlta’s principles for engagement and ensure we live up to its
commitments with Indigenous neighbours. Efforts are focused on building and maintaining solid relationships and
establishing strong communication channels that enable TransAlta to share information on operations and growth
initiatives, gather feedback to inform project planning and understand priorities and interests to better address concerns.
Specifically, our Aboriginal Relations team continues to develop and enhance aboriginal relations in areas of employment,
economic development, community engagement, and investment.
Each year, TransAlta provides seven $3,000 bursaries for post-secondary and three $1,000 bursaries for trades students
to support the success of Indigenous students in their educational programs. TransAlta’s criteria for accessing the bursary
includes any educational pursuit that will support the wellbeing of Indigenous peoples and communities. The bursary is
open to all Indigenous applicants that have completed high school. Through agreements and ongoing relationship
commitments TransAlta makes information on employment positions available to Indigenous communities and provides
sub-contractors terms and conditions to include Indigenous content considerations for procurement initiatives.
In 2017, we once again achieved the Canadian Council for Aboriginal Business’s silver-level Progressive Aboriginal
Relations (PAR) certification. Certification occurs ever three years. In 2016, we introduced our STAR tracking program,
which functions as a communication record-keeping and engagement measurement tool. This capacity fulfills 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.
In 2018, to further support access to education TransAlta created an Indigenous Gap program with the Southern Alberta
Institute of Technology (SAIT) to provide support to Indigenous students who need high school upgrading in order to enter
a trade program.
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In 2017, we supported an Indigenous Leadership Program at Banff Centre for Arts and Creativity. Approximately 250
Indigenous leaders from over 120 communities attended the leadership programs with help from TransAlta and other
supporters.
Over the past five years, TransAlta’s support has provided 39 scholarships for members of Indigenous communities to
attend the programs and take that learning back to their communities. Those participants have come from communities
across Alberta and British Columbia including the First Nations of Alexis Nakota Sioux, Bearspaw, Chiniki, Enoch Cree,
Ermineskin Cree, Fort McKay, Kainai, Montana, Paul, Piikani, Samson Cree, Siksika, Squamish, Tsuu T’ina, and Wesley.
Stakeholder Relationships
Relationships matter to TransAlta. Driven by our values, we seek to maximize value creation for our stakeholders and
TransAlta.
TransAlta Stakeholders
Regardless of who our stakeholders are or who they represent, our goal is to act in the best interests of the Corporation
and to create either financial, environmental or social value for both our stakeholders and TransAlta. Major stakeholder
categories can be summarized as shareholders, debt holders, business partners, contractors, consultants, customers,
community organizations, employees, governments, Indigenous groups, industry and professional bodies, media, NGOs,
public and regulatory affairs, residents and suppliers. This too encompasses our value chain. Our mindset is value creation
across this chain through the development of relationships and partnerships.
Engagement Framework
Our stakeholder engagement framework is modelled and closely tied to the stakeholder engagement aspect of ISO 14001,
which is an internationally recognized environmental management standard. This framework is a streamlined corporate-
wide approach to ensure that engagement and relationship-building practices are consistent across TransAlta’s locations
and types of work.
Methods of Engagement
In order to run our business successfully, we are in consistent two-way communication with the majority of our
stakeholders, some more than others. As an example, our dialogue with customers is daily, iterative and takes on many
forms including meetings (in-person, virtual, and one-one), calls, emails, newsletters and feedback systems (online loops).
It is both proactive and reactive. Our approach and our goal is to be proactive, which is communicating consistent messaging
and information, while being transparent. There are often times we will need to be reactive, such as to a customer complaint,
and we commit to timely and professional resolution using values-based dialogue. We then work to identify how to mitigate
further issues, moving back to our proactive approach.
Part of our business is growth, which we achieve by developing or purchasing new assets. We proactively engage with many
stakeholders in all of our geographic operating areas in Australia, Canada and the United States in order to develop and
maintain relationships; assess needs and fit; and to seek out collaborative and sustainable value creation opportunities.
Recently we completed construction of our South Hedland 150 MW combined-cycle plant in Western Australia. The project
took four years from RFP to commercial operation. Achieving construction and commercial operation was the outcome of
successful stakeholder engagement and collaboration. We recently announced our coal-to-gas transition plan, secured by
way of collaborative stakeholder engagement. This plan involved signing a Memorandum of Understanding with the Alberta
government, which highlights the project fit for Alberta, not just TransAlta. The coal-to-gas project is expected to
significantly reduce the environmental impact from coal (a reduction in air pollution and GHG emissions) while enabling
the transition and addition of 5,000 MW of renewable energy by 2030.
More details on our stakeholder engagement activities can be found via our social media channels.
Engagement Tracking and Reporting
Our Stakeholder and Indigenous Relations tracking program functions as a Corporation-wide communication record-
keeping tool, which is managed by our Stakeholder and Indigenous Relations team. This capacity fulfills 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 an in-house application, this tool has no operating cost
or fees and has the ability to grant different levels of access to information. Furthermore, the tool can store email
conversations, documents and voice-mail messages related to any project, event or issue, and use them in reports. It can
also produce an array of statistical reports showing frequencies and volumes of engagement based on project, stakeholder,
stakeholder group, issue or keywords.
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Engagement and Board Communication
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 Corporation and other stakeholders to communicate with the Board.
For example, employees and other stakeholders may communicate with the Board, through the Audit and Risk Committee
("ARC"), by writing to the ARC; employees and other stakeholders may also communicate with the Board, through the ARC,
by making submissions via the Corporation’s toll-free telephone or online Ethic Helpline (see the Whistleblower System
below for more details). Shareholders are also invited to communicate directly with the Board under the Corporation’s
Shareholder Engagement Policy, which outlines the Corporation’s approach to proactive director-shareholder engagement
at and in between the Corporation’s annual shareholders meetings. Under the Shareholder Engagement Policy,
shareholders can request meetings with members of the Board and can submit questions or inquiries to the Board, which
the Corporation will respond to. A copy of the Shareholder Engagement Policy is available on our website at https://
www.transalta.com/about-us/governance/shareholder-engagement-policy/. 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 Corporation’s approach to executive compensation (say-on-pay). The Corporation is committed to
ensuring continued good relations and communications with its shareholders and other stakeholders and regularly
evaluates its practices in light of any new governance initiatives or developments in order to maintain sound corporate
governance practices.
Customers
In early 2018 we launched our new energy services for customers. Our customer solutions team has partnered with best-
in-class energy service providers to help businesses achieve:
energy consumption and energy cost management;
▪
market price risks and volume exposure mitigation;
▪
sustainability initiatives such as self-generated electricity; and
▪
monitoring of energy market design changes, price signals and applicable and available incentives.
▪
Our energy services include solar, energy-efficiency audits, distributed generation and building automation. To learn more,
please visit the Energy Services customer page on our website at https://www.transalta.com/customers/.
Supply Chain
We continue to seek solutions to advance supply chain sustainability. In 2017 we partnered with Ivalua Inc. to optimize
our global supply chain management operations. After an exhaustive review of all leading vendors, Ivalua was selected for
its comprehensive Source-to-Pay platform, flexible architecture and overall ability to give TransAlta a competitive
advantage. Key business values that we expect include increased supply chain efficiency, reduced lead times, lower costs
and improved supplier performance.
We continue to offer our business units optional sustainability terms and conditions for inclusion within supplier
agreements. These terms and conditions include suppliers communicating their sustainability policies, strategy and
performance; documented systems for labour practices; environmental management systems; disclosure of environmental
infringements; disclosure of anti-competitive behaviour; disclosure on climate change management; third-party
certifications on products; and demonstration of community investments. Furthermore, as we explore major projects, we
are assessing vendors both at the RFP evaluation stage and in up-front information requests on such elements as safe work
practices, environmental practices and Indigenous spend. This means, for example, getting information on:
▪
▪
▪
▪
estimated value of services that will be procured though local Indigenous businesses (in RFP template);
estimated number of local Indigenous persons that will be employed (in RFP template);
understanding overall community spend and engagement; and
understanding through interview processes and stakeholder work the state of community relations.
In addition, in early 2019, the Board of Directors adopted a Supplier Code of Conduct that applies to all vendors and
suppliers of TransAlta. Under the Code, suppliers of goods and services to TransAlta are required to adhere to our core
values, including as it pertains to health and safety, ethical business conduct and environmental leadership. The Code also
allows suppliers to report ethical or legal concerns related to the Code via TransAlta’s Ethics Helpline.
Local Communities
TransAlta creates value for local communities through the generation of an essential service. We provide reliable, cost-
efficient and clean power in Australia, Canada and the United States.
With the phase-out of coal, communities surrounding our plants will be impacted as our workforce will substantially decline.
However, our proposed coal-to-gas conversions provide the opportunity to maintain some jobs at the power plants for
substantially longer than would have been possible if the plants continued to only burn coal. Electricity and energy have
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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 a smart and long-term energy transition in Alberta to minimize disruption and negative economic
impact, and to provide support for facility redevelopment, funds for retraining and economic diversification in the province.
Community Investments
During 2018, TransAlta contributed $2.4 million in donations and sponsorships (2017 - $2.6 million). One of our major
community investments is to United Way campaigns across Canada and the US. This year, TransAlta employees, retirees,
contractors and the Corporation raised over $1.1 million for the United Way.
In 2018, we had a focus on youth education and achieved our target to direct $0.75 million of community investment to
this cause. Some of our partnerships included the University of Calgary, Southern and Northern Alberta Institutes of
Technology, Mount Royal University, Banff Centre for Arts and Creativity (Indigenous leadership scholarships), Mother
Earth Children's Charter School (Indigenous kindergarten to Grade 9), Calgary Stampede (The Young Canadians - ages
seven to 18), national Canada and US Indigenous scholarships (post-secondary for trades and academic) and the Alberta
Council for Environmental Education.
On July 30, 2015, we announced a US$55 million community investment 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
by closing the Centralia facility’s two units, one in 2020 and the other in 2025. In order to invest the $55 million, three
funding boards were formed: The Weatherization Board ($10 million), the Economic & Community Development Board
($20 million) and the Energy Technology Board ($25 million). To date, the Weatherization Board has invested $5.9 million,
the Economic & Community Development Board $12 million and the Energy Technology Board $3.9 million.
We continue to increase financial value from natural or environmental capital-related business activities, while reducing
Natural Capital
our carbon footprint. Comparable EBITDA from renewable energy generation in 2018 was $322 million (2017 - $289
million). Our revenue in 2018 from carbon-related offsets was $21.6 million (2017 - $27.7 million). In addition, in 2018 the
sale of coal byproducts and waste-related recycling generated financial value in the range of $25 million to $35 million.
The following are key natural capital KPI trends:
Year ended Dec. 31
Renewable energy comparable EBITDA
Carbon offsets revenue
GHG emissions (million tonnes CO2e)
2018
322.0
21.6
20.8
2017
289.0
27.7
29.9
2016
277.0
29.0
30.7
Natural Capital Management
All energy sources used to generate electricity have some impact on the environment. While we are pursuing a business
strategy that includes investing in 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 a clean energy transition. We are planning
the conversion of our Alberta coal units to natural gas in the 2020 to 2023 time frame.
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. Other material
impacts that we manage and track performance on includes our environmental management systems, environmental
incidents and spills, land use, water usage and waste management.
We maintain procedures for environmental incidents similar to our safety practices, 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.
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Environmental Performance
Reducing the environmental impact of our activities benefits not only our operations and financial results, but also the
communities in which we operate. We expect that increased scrutiny will be placed on environmental emissions and
compliance, and we therefore have a proactive approach to minimizing risks to our results. Our Board provides oversight
with respect to the Corporation’s monitoring of environmental regulations and public policy changes and to the
establishment and adherence to environmental practices, procedures and polices in response to legal/regulatory and
industry compliance or best practices.
Our performance on managing environmental impacts, reducing our environmental impact and capitalizing on
environmental initiatives includes the following.
Renewable Energy
Over the last 10 years, we have added approximately 1,200 MW in renewable energy capacity. Over 1,000 MW has been
wind energy development and today we are positioned as an industry leader in wind energy. We continue to operate over
900 MW of hydro energy and our experience with hydro operations is over 100 years. In 2015 we made our first solar
investment, 21 MW in Massachusetts, and we continue to look for opportunities to develop and operate solar energy. Our
production from renewable energy in 2018 offset the equivalent of approximately 2.9 million tonnes of CO2e or the removal
of approximately 620,000 cars from the roads in 2018.
Carbon Offsets
In 2018, 200 MW of our Alberta wind capacity was eligible to generate offsets at a rate of $30 tonne CO2e. Annual revenue
generation from these offsets was in the range of $10 million to $15 million. In 2019, as per rules associated with the new
Alberta Carbon Competitiveness Incentive Regulation, our offset eligibility capacity will expand to include additional capacity
from our wind fleet and hydro fleet. As a result we anticipate offset revenue to rise to approximately $25 million in 2019.
Coal Transition
Our coal-to-gas conversion plan in Alberta is expected to vastly improve our environmental performance. Energy use, GHG
emissions, air emissions, waste generation and water usage is expected to significantly decline. A conversion of coal-fired
power generation to gas-fired generation is expected to eliminate all mercury emissions, the majority of sulphur dioxide
emissions ("SO2") and significantly reduce our nitrogen dioxide emissions ("NOX").
Environmental Management Systems
All of our 73 facilities have Environmental Management Systems (“EMS”) in place, the majority of which closely align with
the internationally recognized ISO 14001 EMS standard. We have operated our facilities in line with ISO 14001 for 19
years, and our systems and knowledge of management systems are therefore mature. We no longer certify our Alberta
coal plants as ISO 14001, but the plants continue to run best practice EMS. 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.
Environmental Incidents and Spills
We recorded seven significant environmental incidents in 2018 (2017 - five incidents), which was below our target of nine.
We categorize significant as violations or non-compliance to regulations or exceedance of limits in company operating
approvals that resulted in or had the potential to result in enforcement action. This was another year of excellent
performance that reflects our continuous improvement in tracking, reporting and identifying potential hazards. Five of our
incidents occurred at our coal facilities and two incidents occurred at our gas facilities. None of these incidents resulted in
a material environmental impact.
The following are the environmental incidents by fuel types:
Year ended Dec. 31
Coal
Gas and renewables
Total environmental incidents
2018
2017
2016
5
2
7
5
—
5
13
3
16
Incident types in 2018 were primarily regulatory in nature, whereby we had minor infringements on set regulatory
requirements. These included two mercury exceedances at our Centralia coal facility, a nitrogen dioxide stack exceedance
at our Sundance coal facility, failure to properly notify the regulator of un-salvaged topsoil, per EPEA Approval Condition
3.2.1, at our Sunhills mine, and a pH exceedance on an oil/water separator at our Sarnia gas facility. We also had two releases,
one liquid and one gas. These included a secondary mine drainage water excursion from our Sunhills mine and a refrigerant
release at our Ottawa gas facility. All incidents were managed in line with our EMS practice and resolved quickly. We
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continue to target improvement and our corporate-wide 2019 target is five or fewer incidents. We also continue to track
and manage all non-reportable (minor) environmental incidents, which helps us identify what causes 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 estimated volume of spills in 2018 was 5 m3 (2017 - 15 m3).
Air Emissions
Air emissions in 2018 decreased significantly compared with 2017 levels. The reduction was due to a significant reduction
in coal power generation from our Sundance coal facility and increased generation from co-firing with gas at our merchant
facilities. SO2 emissions decreased by 47 per cent, NOx emissions decreased by 37 per cent, particulate matter emissions
decreased by 62 per cent and mercury emissions decreased by 41 per cent. These reductions highlight our commentary in
our 2017 annual integrated report, which noted that we will dramatically reduce air emissions through our planned
conversion of two coal units at Sundance, Alberta and the three coal units at Keephills, Alberta to gas-fired generation in
the 2020 to 2023 time frame.
We continue to capture 80 per cent of mercury emissions at our coal plants and by 2025 our post-coal era, mercury
emissions will be eliminated. Particulate matter and SO2 emissions will also be virtually eliminated or considered negligible
post-coal power generation. NOx emissions will also be reduced to levels under 20,000 tonnes annually.
We are well underway and remain on track to achieve our target of 95 per cent SO2 emission reductions by 2030. Since
2005, we have reduced SO2 emissions by 72 per cent. As noted above, we are on track to achieve our SO2 target by 2025,
well ahead of our 2030 goal. In 2018 we revised our NOx reduction target to 2030 from 95 per cent to 50 per cent. This
allows flexibility as we convert coal facilities to natural gas and expand our natural gas fleet.
Year ended Dec. 31
Sulphur dioxide (tonnes)
Nitrogen dioxide (tonnes)
Particulate matter (tonnes)
Mercury (kilograms)
2018
19,300
28,000
7,800
70
2017
36,200
44,400
14,500
110
2016
39,600
48,400
13,800
130
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 2018 we withdrew 245
million m3 and returned approximately 208 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
2018
245
208
37
2017
213
172
41
2016
239
197
42
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 a greater water management role than they
have played in the past. In 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.
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Land Use
The largest land use associated with our operations is for surface mining of coal. Of the three mines we have operated, the
Whitewood mine in Alberta is completely reclaimed and the land certification process is ongoing. Our Centralia mine in
Washington State is currently in the reclamation phase (35 per cent reclaimed), and our Highvale mine in Alberta is actively
mined with certain sections undergoing reclamation. Our reclamation plans are set out on a life-cycle basis and include
contouring disturbed areas, re-establishing 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 2018, we reclaimed 28 acres (11 hectares) at our Highvale mine, which was below our target of 74 acres (30 hectares).
This was due to weather conditions limiting the amount of final placement of topsoil. Topsoil placement is the final stage
of reclamation. We reallocated resources to other stages of reclamation (such as ground leveling) to move us closer to final
reclamation in following years, which keeps us on track with our long-range reclamation plan. The Centralia mine is no
longer actively used for coal operations, but reclamation activity is ongoing. In 2018 we reclaimed 113 acres (46 hectares)
of land. Since 1991, over 3,000 acres have been reclaimed and approximately 1.7 million seedlings have been planted as
part of the reclamation work.
In 2016, we decommissioned our Cowley Ridge wind plant, which was Canada’s first commercial wind plant when it was
constructed in 1993 and reached its end of life in 2016. During this process, our wind operations team recycled:
▪
▪
▪
▪
54 towers weighing over 9,000 kilograms ("kg");
61 nacelles, which is the housing of the turbine generating components, weighing 10,000 kg;
19 transformers weighing over 4,000 kg; and
32,000 litres of oil.
Our recycling efforts meant that we diverted close to 1,200,000 kg from the land fill. This job was completed safely, and in
addition generated around $0.15 million of value from the recycled components. This work reflects TransAlta’s values of
innovation and safety, while maintaining a positive environmental impact at our operations.
Waste
In 2018 our operations generated approximately 1.3 million tonnes of waste. Waste volumes are all primarily non-
hazardous. Only 0.1 per cent of waste volumes are hazardous materials. In 2018, only 0.1 per cent of waste was directed
to landfill. From the remaining 99.9 per cent, 56 per cent was returned to the mine (ash from coal combustion), 43 per cent
was reused and the remaining 0.3 per cent was recycled.
Our reuse waste or byproduct waste is resold in to markets. Byproduct sales and associated annual revenue generation
typically ranges from $25 million to $35 million. Our operating teams are diligent at not only minimizing waste, but also
maximizing 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.
Energy Use
TransAlta uses energy in a number of different ways. We burn coal, gas and diesel to generate electricity. We harness the
kinetic energy of water and wind to generate electricity. We also use the sun 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. As an energy
corporation, we naturally look for ways to optimize or create efficiencies related to the use of energy. Our coal-to-gas
conversions display one innovative way we intend to reduce a significant amount of energy use and significantly reduce
our environmental impact, while returning the generation of reliable and low-cost power supply to Albertan customers.
The following captures our energy use (millions of gigajoules). On a comparable basis, our energy use declined by 30 per
cent over 2017 as a result of coal retirements and reduced coal generation from our Sundance facility. Our coal-to-gas
conversions will significantly reduce our energy usage as gas uses less energy for generation of a MWh.
Year ended Dec. 31
Coal
Gas and renewables
Corporate
Total energy use
2018
309.8
48.6
0.1
358.5
2017
447.4
49.4
0.1
496.9
2016
469.1
59.2
0.1
528.4
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Weather
Abnormal weather events can impact our operations and give rise to risks. In addition, normal year-over-year variations
in wind, solar, water and temperatures give rise to various levels of volume risk depending on the input fuel of each facility;
events outside the design parameters of our facilities give rise to equipment risk; and fluctuations in temperatures can
cause commodity price risk through impact on customer demand for heating or cooling. Refer to the Governance and Risk
Management section of this MD&A for further discussion of each risk and our related management strategy.
During the past five years, some deviations from expected weather patterns have negatively impacted our annual financial
results:
▪
the southern Alberta flood of 2013 disrupted our hydro operations and caused us to invest in substantial repair work.
Our losses have been largely covered through insurance;
warm weather in Alberta in 2015 increased derates at our coal facilities due to its impact on the Sundance cooling
ponds. These cooling ponds are susceptible to warm weather; however, we anticipate that decreased coal production
from the retirement of Sundance Units 1 and 2, respectively, in the medium term will reduce the stress from such
occurrence; and
our Alberta mine was susceptible to significant rain starting in August 2016, which resulted in several weeks of flooding
and threatened our coal deliveries. We focused on improving drainage infrastructure and using stockpiles to mitigate
future risks.
▪
▪
Climate Change
We believe in open and transparent reporting on climate change. Our climate change reporting is structured as per guidance
from the Financial Stability Board's Task Force on Climate-Related Financial Disclosures ("TCFD") recommendations. The
following highlights our management, performance and leadership of climate change related impacts. For more detailed
information, please visit our Climate Change Management webpage: https://www.transalta.com/sustainability/climate-
change-management/
Governance
The highest level of oversight on climate change related business impacts is at our Board level, specifically by our
Governance Safety and Sustainability Committee (“GSSC”) of the Board and the Audit and Risk Committee ("ARC") of the
Board. Business impacts related to climate change are assessed by our executive team quarterly and reported to the Board
GSSC and ARC, as applicable.
Strategy
Our corporate vision is to be a leading clean power company by 2025. To support this vision our strategic goals include
growth in renewable energy and gas, while reducing a significant amount of emissions from our coal fleet by way of coal-
to-gas conversions and coal retirements.
Our corporate goal is to reduce our GHG emissions by 19.7 million tonnes by 2030 compared to 2015 levels, while we grow
renewable energy and gas. Our modeling shows that our target aligns us, under many scenarios, with science-based target
setting, which highlights the resilience of our business to 2 degrees of global warming. We have not officially validated a
science-based target, but continue to monitor and model our future performance with the Sectoral Decarbonization
Approach from the Science Based Target Initiative.
Aligned with our corporate strategy, our business units or operations consistently seek energy-efficiency improvements,
development of emissions offset portfolios to achieve emissions reductions at competitive costs, and development of clean
combustion technologies.
We seek investment in climate change related mitigation solutions, such as renewable energy development, where we can
maximize value creation for our shareholders, local communities and the environment. 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 goals for undertaking such actions are to enhance 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 over 2,200 MW of hydro, wind and solar power. We are one of the largest producers of wind
power in Canada and the largest producer of hydro power in Alberta. Production from renewable energy in 2018 resulted
in avoidance of approximately 2.9 million tonnes of CO2e, which is equivalent to removing over 620,000 vehicles from
North American roads over the same year. For further details on governance and risk, see the Governance and Risk
Management section of this MD&A.
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Risk Management
Risks and opportunities are identified at the business unit level and through corporate functions (government relations,
regulatory, emissions trading and sustainability). Furthermore, risks and opportunities are monitored through our
Corporation-wide risk management processes and actively managed on a priority basis. As noted above risks and
opportunities are reviewed by our executive team quarterly and reported to the Board GSSC and ARC, as applicable.
The following highlights identified climate change risk or opportunities, which have been assessed and integrated into
business operations.
Risk or opportunity
Management approach
Policy requirements
Carbon pricing
TransAlta supports smart regulation and carbon pricing that ensures economic growth and certainty for
investment. We have also demonstrated co-operation and collaboration on climate-related policy, while
ensuring we protect value for employees and shareholders. This is evidenced by our Off-Coal Agreement
with the Alberta Government, totallng $524 million and MOU to convert coal plants to gas. Further
climate-related policy updates can be found in the Regional Regulation and Compliance subsection of
this MD&A
Our Corporate function attributes 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. This information is directed to the business
unit level for further integration. Identified climate change risks or opportunities and carbon pricing are
recognized in the annual TransAlta long-and-medium range forecasting processes. We capture economic
profit from carbon markets through generation of renewable energy credits or offsets and via our
emission trading function, which seeks to commoditize and profit from carbon trading.
New technology
We have demonstrated upside in growing renewables and gas-powered generation. From 2000 to 2018
we have grown renewables capacity from approximately 900 MW to over 2,200 MW. We have recently
announced development of three wind projects, totaling over 330 MW of future capacity.
Adaptation and mitigation Our clean power strategy means that all new investment must meet clean standards in order to mitigate
potential future risk related to carbon policy and pricing. Our target is for 100 per cent of net generation
capacity to be from gas and renewables capacity by 2025. Our coal-to-gas conversion plan in Alberta is
an adaptive measure to climate change related policy. Using existing infrastructure significantly reduces
capital costs compared with new gas builds and also results in the avoidance of approximately $15/MW
in carbon-related pricing (assuming a $30 per tonne carbon price). Our new gas facility at South Hedland
Power Station is built with adaptation in mind. The facility will operate with a best-in-class emission
intensity, and the facility uses less water than traditional gas plants as we use dry cooling towers as
opposed to the normal wet cooling towers (wet cooling towers have heavy water consumption). The
plant is designed to withstand a category 5 cyclone, which can frequent the northwest region of
Western Australia. Category 5 is the highest cyclone rating. Floods, which can occur in the area, have
been mitigated by constructing the facility above the normal flood levels.
Water stress
Our thermal plants require water for operation. The majority of our thermal facilities are operated in low
water stress environments. Our most water-stressed area of operation is at Sarnia; however, due to the
nature of the operation, 98 per cent of water is recycled. The plant is a cogeneration facility. At all of our
coal facilities we hold licences to pull water from low stressed areas. In Australia we purchase water for
operations, and despite operating in remote locations, these areas are not currently water-stressed.
Water purchasing will allow us to minimize local water stress if this becomes an issue. Our operating cost
increase exposure due to water in Australia is low as our thermal operations are small.
Greenhouse Gas Emissions
In 2018, we estimate that 20.8 million tonnes of GHGs with an intensity of 0.77 tonnes per MWh (2017-29.9 million tonnes
of GHGs with an intensity of 0.86 tonnes per MWh) were emitted as a result of normal operating activities. Our significant
reduction in GHG emissions is the result of coal closures and reduced coal power generation from our Sundance facility in
Alberta and increased co-firing with gas at our merchant coal facilities. Notably, our 2018 emissions reductions, supported
achieving our 2021 target to reduce GHG emissions by 30 per cent over 2015 levels of 32.2 million tonnes CO2e. This
target was achieved well ahead of schedule and supports our clean power transition.
Our 2018 data are estimates based on best available data at the time of report production. GHGs include water vapour,
CO2, methane, nitrous oxide, sulphur hexafluoride, hydrofluorocarbons and perfluorocarbons. The majority of our
estimated GHG emissions are comprised of CO2 emissions from stationary combustion. Emissions intensity data has been
aligned with the “Setting Organizational Boundaries: Operational Control” methodology set out in The Greenhouse Gas
Protocol: A Corporate Accounting and Reporting Standard developed by the World Resources Institute and the World Business
Council for Sustainable Development. As per the methodology, TransAlta reports emissions on an operation control basis,
which means that we report 100 per cent of emissions at facilities in which we are the operator. Emissions intensity is
calculated by dividing total operational emissions by 100 per cent of production (MWh) from operated facilities, regardless
of financial ownership.
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The following are our GHG emissions in million tonnes CO2:
Year ended Dec. 31
Coal
Gas and renewables
Total GHG emissions
Management’s Discussion and Analysis
2018
18.3
2.4
20.8
2017
27.4
2.5
29.9
2016
27.7
3.0
30.7
Our total GHG emissions include both scope 1 and scope 2 emissions. The GHG Protocol Corporate Standard classifies a
company’s GHG emissions into three ‘scopes’. Scope 1 emissions are direct emissions from owned or controlled sources.
Scope 2 emissions are indirect emissions from the generation of purchased energy. Scope 3 emissions are all indirect
emissions (not included in scope 2) that occur in the value chain of the reporting company, including both upstream and
downstream emissions. Scope 1 emissions in 2018 were estimated to be 20.6 million tonnes CO2e. Scope 2 emissions were
estimated to be 0.2 million tonnes CO2e. We estimate our scope 3 emissions to be in the range of six million tonnes.
Future performance on GHG emissions will reduce as we retire or convert coal plants to gas and grow our renewable energy
and gas fleet, while optimizing our existing fleet. Our target to is to reduce 60 per cent or 19.7 million tonnes of GHG
emissions by 2030 over 2015 levels, which is line with UN Sustainable Development Goal ("SDG") Goal 13, Climate Action.
Since 2015 we have reduced 9.1 million tonnes, which represents a reduction of 35 per cent.
The following highlights our longer-term track record on GHG emission reductions since 2005 and our projected emissions
in 2030.
Year ended Dec. 31
Total GHG emissions
2030
12.5
2018
20.8
2005
41.9
In 2018, TransAlta maintained its scoring on the Carbon Disclosure Project Climate Change investor request. Our overall
score was a B, which places us as ahead of our peers when it comes to carbon disclosure, management, performance and
leadership. In 2017 we were highlighted by the Chartered Professional Accountants of Canada (“CPA 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. Our 2016 Integrated Report was selected as a finalist for CPA
Canada’s Award of Excellence in Corporate Reporting - of note, our Climate Change disclosure was highlighted as
“outstanding” by CPA Canada judges.
Regional Regulation and Compliance
Climate change related legislation will continue to have an impact on our business. We work with governments and the
public to develop appropriate frameworks that support our business, protect the environment and promote sustainable
development. We are committed to complying with legislative and regulatory requirements and to minimizing the
environmental impact of our operations.
Future changes to carbon regulations could 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 and other environmental 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
On June 21, 2018, the Greenhouse Gas Pollution Pricing Act (GGPPA) was passed. Under this Act, the Canadian federal
government implemented a national price on GHG emissions. The price will begin at $20 per tonne of CO2e for emissions
in 2019, rising by $10 per year, until reaching $50 per tonne in 2022.
On Jan. 1, 2019, the GGPPA’s “backstop” mechanisms came into effect for large emitters in jurisdictions that did not have
an independent carbon pricing program or where the existing program was not deemed equivalent to the federal system
- Ontario, Manitoba, New Brunswick, Saskatchewan, Prince Edward Island, Yukon and Nunavut. The backstop mechanism
has two components: a carbon levy for small emitters and regulation for large emitters called the Output-Based Pricing
System (OBPS). The carbon levy sets a carbon price per tonne of GHG emissions related to transportation fuels, heating
fuels and other small emission sources.
The OBPS is an intensity-based standard where large emitters must meet an industry specific emission intensity
performance standard per unit of production. A large emitter’s emission intensity per unit of product must meet their
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industry’s OBPS intensity performance standard. If the facility's emission intensity is below or above the performance
standard, the facility will generate carbon credits or carbon obligations equal to the difference between the industry’s
emission intensity performance standard and the regulated facility’s emission intensity.
Federal Gas Regulation
On Dec. 18, 2018, the federal government published the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired
Generation of Electricity. Under the regulation, new and significantly modified natural-gas-fired electricity facilities with a
capacity greater than 150 MWs must meet a standard of 420 tCO2e per gigawatt hour (tCO2e/GWh) to operate. Units with
a capacity of between 25 MW and 150 MW must meet a standard of 550 tCO2e/GWh.
The rules for converted units will allow the plants to operate for a set number of years following the end-of-life for the unit
under the coal regulations based on a one-time performance test at the time of conversion. For our units, these rules are
expected to provide 8 or 10 additional years of operating life to each of our units.
Federal Coal Regulation
On Dec. 18, 2018, amendments to the Reduction of Carbon Dioxide Emissions from Coal-Fired Generation of Electricity
Regulations came into force under the Canadian Environmental Protection Act, 1999. The amended regulations will require
coal units to meet an emission level of 420 tCO2e/GWh by the earlier of end-of-life under the 2012 regulations or Dec.
31, 2029.
Alberta
On November 22, 2015, the Government of Alberta announced the Alberta Climate Leadership Plan. The government
has now largely delivered on its commitments through legislation to require:
▪
▪
▪
▪
the elimination of coal generation by 2030;
the creation of the Renewable Energy Program (REP) to meet the commitment that renewables account for 30
per cent of Alberta's electricity system by 2030. Under the REP, the system operator, the AESO, is tasked with
running procurement processes for government approved volumes of renewable power. To date, the AESO has
run three separate Requests for Proposals (RFP). The RFPs have resulted in 20-year contracts for approximately
1,360 MWs of wind power projects. These projects are scheduled to be grid integrated between 2019 and 2021;
the Carbon Competitiveness Incentive Regulation (CCIR) replaces the previous large emitters regulation, Specified
Gas Emitters Regulation (SGER), moving from a facility-specific compliance standard to a product or sector
performance compliance standard; and
a carbon levy was introduced on most carbon emissions not covered by the CCIR.
On Jan. 1, 2018, the Alberta government transitioned from the SGER to the CCIR. Under the CCIR, the regulatory
compliance moved from a facility-specific compliance standard to a product or sector performance compliance standard.
Currently, the provincial government has announced that the carbon price will remain at $30/tCO2e going forward and
will not increase to the federally mandated price increase of $40/tCO2e in 2021 and $50/tCO2e in 2022; however, increases
may be implemented by the federal government under their program equivalency review. The electricity sector
performance standard was set at 370 tCO2e/GWh but will decline over time. All renewable assets that received crediting
under the SGER will continue to receive credits under CCIR on a one-to-one basis. All other renewables that did not receive
credits under the previous standards will now be able to opt in to the CCIR and get carbon crediting up to the electricity
sector performance standard in perpetuity. Once wind projects' crediting under SGER protocol ends, these projects will
also be able to opt in to the CCIR system and be credited up to the performance standard for the rest of their operational
life.
British Columbia
Beginning April 1, 2018, BC increased its carbon tax rate to $35/tCO2e and committed to raise the price $5 per year until
it reaches $50 per tonne in 2021.
BC Hydro has indicated there will be no additional contracts for independent power producer renewable projects with
capacity above 15 MW. It has also suspended the purchase of energy from its Standing Offer Program for small projects
up to 15 MW pending a review of the program.
Ontario
On Oct. 31, 2018, the Ontario government passed the Cap and Trade Cancellation Act. This Act removed all existing provincial
carbon emission regulations and costs on large emitters.
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The Canadian federal Greenhouse Gas Pollution Pricing Act requires provinces to have GHG gas regulations and prices in
place that align with the federal GGPPA. On Oct. 23, the federal government announced that the federal program would
be implemented in Ontario as of Jan. 1, 2019. Small emitters will face a carbon levy and large emitters, under covered
industries, with annual GHG emission greater than 50,000 tCO2e will be subject to the OBPS. Ontario is now subject to
the federal government’s backstop carbon levy price for small emitters and the OBPS for large emitters.
On Nov. 29th, 2018, the Ontario government unveiled a new climate change policy called Preserving and Protecting our
Environment for Future Generations: A Made-In-Ontario Environment Plan. The plan aims to keep the province working
toward meeting the emissions-reduction goal of achieving 30 per cent reduction of 2005 levels by 2030. The plan commits
to developing emission performance standards to achieve reductions from large emitters and references Saskatchewan’s
OBPS as an example. The government has indicated that it will be consulting and developing the program in 2019. The
plan's specifics related to the electricity sector have not yet been defined and are expected to be determined through the
program development process.
Australia
On Dec. 13, 2014, the Australian government enacted legislation to implement the Emissions Reduction Fund (the "ERF").
The AUD 2.55 billion ERF is the centrepiece of the Australian government's policy and provides a policy framework to cut
emissions by five per cent below 2000 levels by 2020 and 26 to 28 per cent below 2005 emissions by 2030.
The ERF's safeguard mechanism, commencing from July 1, 2016, is designed to ensure emissions reductions purchased by
the Australian government through the ERF are not displaced by significant increases in emissions elsewhere in the
economy. The ERF and its safeguard mechanism provide incentives to reduce emissions across the Australian economy.
The Australian government has also committed to develop a National Energy Productivity Plan with a target to improve
Australia's energy productivity by 40 per cent between 2015 and 2030. The ERF is not expected to have a material impact
on our Australian assets as a result of the Australian assets being primarily composed of gas-fired generation.
In addition, on June 23, 2015, the federal Australian government also reformed the Renewable Energy Target ("RET")
scheme. The RET should add at least 33,000 gigawatt-hours (GWh) of renewable sources by 2020. This would double the
amount of large-scale renewable energy being delivered compared to current levels and result in approximately 23.5 per
cent of Australia's electricity generation being sourced from renewable projects.
Pacific Northwest
In 2010, the Washington Governor's office and Ecology negotiated agreements with TransAlta related to the operation of
Centralia’s two coal power electricity generating units. TransAlta agreed to retire its two Centralia coal units - one in 2020
and the other in 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 US Coal given these commitments. The related TransAlta Energy
Transition Bill was signed into law in 2011 and provides a framework to transition from coal to other forms of generation
in the State of Washington.
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2018 Sustainability Performance
The information in this section 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
Stakeholder Communication and Value Creation
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.
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.
2018 Sustainability Targets
Financial
Results
Comments
1. Maintain our investment
grade rating
Achieve and maintain
investment grade credit metrics
Partly
achieved
2. Increase focus on FFO and
EBITDA
Deliver comparable EBITDA
and FFO in the range of $1,000
million to $1,050 million and
$750 million to $800 million,
respectively(1)
Achieved
TransAlta maintains investment grade ratings
from three out of four rating agencies: S&P (BBB-)
negative outlook, DBRS (BBB low) stable outlook,
and Fitch (BBB-) stable outlook.
For the year ended Dec. 31, 2018, adjusted
comparable EBITDA was $988 million and
adjusted FFO was $770 million. Comparable
EBITDA was adjusted to remove the impact of
unrealized mark-to-market gains or losses.
Additionally, Comparable EBITDA and FFO were
adjusted to remove the $157 million for the
termination of Sundance B and C PPAs as this was
not included in the targets.
(1) Represents our revised outlook. As a result of strong performance in the first quarter of 2018, we revised the following 2018 targets: comparable EBITDA from the
previously announced target range of $950 million to $1,050 million to $1,000 to $1,050 million, and FFO from the target range of $725 million to $800 million to
$750 million to $800 million.
3. Reduce safety incidents
Human and Intellectual
Achieve an Injury Frequency
Rate below 0.53
Results
Mostly
Achieved
Comments
Although we narrowly missed our target, we
achieved one of our lowest IFRs in our history.
Our 2018 IFR was 0.54, a 25 per cent
improvement over 2017 performance
Achieve a Total Incident
Frequency rate below 2.83
Achieved
Our 2018 TIF was 1.98, a 25 per cent
improvement over 2017 performance
4. Human resources
Maintain voluntary turnover
percentage under eight per
cent
Not achieved Our voluntary turnover in 2018 was 20 per cent.
We seek to maintain voluntary turnover or
attrition under eight per cent as this is considered
a healthy amount of attrition for a corporation. As
we transition away from coal-fired generation
and its associated jobs we face significant
workforce challenges with retention
5. Support employee
development
Continue development plans
for all high-potential employees
at the top three levels of the
organization
Achieved
In 2018, we completed a six-month (peer-led)
leadership training program, called Elevate, for
our high-potential employees at the top three
levels of the organization. The program was
focused on establishing a learner’s mindset,
building trust and influence, strengths-based
leadership, being transparent, providing
feedback, collaboration as a team and innovation
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6. Minimize fleet-wide
environmental incidents
Keep recorded incidents (including
spills and air infractions) below 9
Natural
Results
Achieved
7. Increase mine reclaimed
acreage
Replace annual topsoil rate at
Highvale mine at a rate of 74
acres/year
Not achieved
9. Reduce air emissions
Achieve a 95 per cent reduction
from 2005 levels of TransAlta coal
facility NOx and SO2 emissions by
2030
On track
10. Reduce GHG emissions
a) Our goal is to reduce our total
GHG emissions in 2021 to 30 per
cent below 2015 levels, in line
with a commitment to the UN
SDGs
Achieved
b) Our goal is to reduce our total
GHG emissions in 2030 to 60 per
cent below 2015 levels, in line
with a commitment to the UN
SDGs and to prevent two degrees
Celsius of global warming
On track
Management’s Discussion and Analysis
Comments
We recorded seven significant
environmental incidents in 2018, none of
which had a material environmental
impact. This was below our target of nine,
but was a 40 per cent increase over 2017
performance
Due to weather conditions, not all topsoil
was placed to fully meet our target. Top
Soil is the last stage of reclamation,
despite weather constraints, we did
manage to complete 28 acres. Instead, we
reallocated resources to other stages of
reclamation to move other areas closer to
final reclamation (such as ground
leveling). Overall we reduced reclamation
spend by $2.1 million and maintained
progress towards our long-range
reclamation plan
We are well underway and on track to
achieve our target of 95 per cent emission
reductions of SO2 and NOx by 2030. Since
2005, we have reduced NOx emissions by
58 per cent and SO2 emissions by 72 per
cent. In 2018 we reduced approximately
16,000 tonnes of NOx emissions and
17,000 tonnes of SO2 emissions over
2017 levels
We achieved this target in 2018, well
ahead of our target for 2021. In 2018 we
reduced approximately 9.1 million tonnes
of CO2e over 2017 levels due to reduced
coal power generation from our Sundance
facility and co-firing at our merchant coal
facilities
We are well underway and on track to
achieve our target of 60 per cent GHG
emission reductions by 2030. Since 2015,
we have reduced emissions by 36 per
cent. In 2018 we reduced approximately
9.1 million tonnes of CO2e over 2017
levels
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11. Support quality education for
youth
Social and Relationship
Support equal access to all levels of
education for youth and
Indigenous peoples
Results
Achieved
Our education goal and targets
support UN SDG Goal 4: Quality
Education related to ensuring
“inclusive and equitable quality
education” and related to
“eliminating gender disparities in
education”
Direct approximately $0.75 million
of community investment spending
to youth education
Achieved
12. Increase internal best practice
Aboriginal engagement
awareness
Develop sustainability and
Indigenous engagement materials
for integration within our
developmental leadership
programs at TransAlta
Achieved
Management’s Discussion and Analysis
Management’s Discussion and Analysis
Comments
TransAlta provides an Aboriginal bursary
to support education for Indigenous
peoples that includes bursaries for both
trades and post-secondary. TransAlta’s
criteria for accessing the bursary are open
to any educational pursuit that will
support the well being of Indigenous
peoples and communities. The bursary is
open to all Indigenous applicants that have
completed high school. TransAlta has also
created a Indigenous Gap program with
SAIT to give support to Indigenous
students where it is needed.
Our community investments have
supported the University of Calgary,
Southern and Northern Alberta Institute
of Technology, Mount Royal University,
Banff Centre for Arts and Creativity
(Indigenous leadership scholarships),
Mother Earth Children's Charter School
(Indigenous kindergarten to Grade 9),
Calgary Stampede (The Young Canadians -
ages 7 to 18), national Canada and US
Indigenous scholarships (post-secondary
for trades and academic) and the Alberta
Council for Environmental Education
An Indigenous Awareness presentation
was developed, that includes historical
facts and basic concepts around
consultation and engagement, which will
be shared with all employees. The same
presentation will be used at the Schulich
School of Engineering at the University of
Calgary in 2018 for one of their ethics
courses
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13. TransAlta will be a leading
clean power company by 2030
Comprehensive
By 2022, we will convert six coal
plant units from coal-fired
generation to gas-fired generation
Results
On track
Our clean power goal and targets
support the UN SDG Goal 7:
Affordable and Clean Energy related
to ensuring “access to affordable,
reliable, sustainable and modern
energy”
By 2025, 100 per cent of our
owned asset company-wide net
generation capacity will be from
gas and renewables
On track
We will continue to seek new
opportunities to grow our portfolio
of 2,265 MW wind, hydro and solar
assets
Achieved
Continue to explore viability of the
Brazeau 900 MW pumped hydro
expansion – doubling our hydro
capacity in Alberta
Not achieved
Management’s Discussion and Analysis
Comments
In 2018 we exercised our option to
acquire a 50 per cent ownership in the
Pioneer Pipeline connecting Tidewater's
Brazeau River Complex to TransAlta's
generating units at Sundance and
Keephills. Our investment is subject to
regulatory approval
We continued our coal-to-gas transition
plans in 2018, while announcing new
renewable energy growth projects. Please
see above and below for more detail.
In 2018 we announced development of
three wind development projects, totaling
over 320 MW of additional renewable
energy capacity. Projects include a 90 MW
wind facility in Pennsylvania (US), a 29
MW wind facility in New Hampshire (US)
and a 207 MW wind facility in Alberta
(Canada)
that dispatchable
In May 2018, the AESO released a report
stating
renewable
resources are not needed in the Alberta
market before 2030. The value and benefit
of the Brazeau Hydro Pumped Storage
project would be well beyond the 2030
period. The Corporation still believes that
generation from pumped storage should be
part of future calls for power under the
Alberta Renewable Electricity Program. The
Corporation is not spending additional
development dollars on the project at this
time, but will continue to work with
governments to
find the appropriate
financial mechanisms for bringing low-cost,
green, dispatchable renewables into the
market to support low prices and emissions
for Alberta customers
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Management’s Discussion and Analysis
Our 2019 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
2019 Sustainable Development Targets
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 0.43
Human and Intellectual
Achieve a Total Incident Frequency Rate below 1.58
2. Minimize fleet-wide environmental
incidents
Keep recorded incidents (including spills and air
infractions) below five
Annual Performance Status
20 per cent improvement over
2018 performance (0.54)
20 per cent improvement over
2018 performance (1.98)
Annual Performance Status
44 per cent improvement over
2018 target
3. Increase mine reclaimed acreage
Replace annual topsoil at Highvale mine at a rate of
110 acres/year
57 per cent increase over 2018
target (70 acres)
4. Reduce air emissions
5. Reduce GHG emissions
Our GHG goal and targets support UN
SDG Goal 13: Climate Action related
to ensuring “integrate climate change
measures into national policies,
strategies and planning."
Achieve a 95 per cent reduction from 2005 levels of
TransAlta SO2 emissions and 50 per cent reduction in NOx
emissions by 2030
Our goal is to reduce our total GHG emissions in 2030 to
60 per cent below 2015 levels, in line with a commitment
to the UN SDGs and prevention of two degrees Celsius of
global warming (our GHG and clean power targets assume
reasonably anticipated growth and operating scenarios)
Revised NOx target to align
with coal-to-gas conversion
strategy and growth in gas
estimations
Consistent with 2018
6. Support quality education for
youth
Support equal access to all levels of education for youth
and Indigenous peoples through financial support and
employment opportunities
Social and Relationship
Annual Performance Status
Consistent with 2018 target
Our education goal and target support
UN SDG Goal 4: Quality Education
related to ensuring “inclusive and
equitable quality education” and
related to “eliminating gender
disparities in education”
7. TransAlta will be a leading clean
power company by 2025
Convert at least two coal units at Sundance, Alberta and
three coal units at Keephills, Alberta to gas-fired
generation in the 2020 to 2023 time frame
Comprehensive
Annual Performance Status
Revised 2018 target
Our clean power goal and targets
support the UN SDG Goal 7:
Affordable and Clean Energy related
to ensuring “access to affordable,
reliable, sustainable and modern
energy”
Aim that by 2025, 100 per cent of our owned net
generation capacity will be from clean power (renewables
and gas)
Consistent with 2018 target
Seek new opportunities to grow our renewable portfolio of
2,265 MW wind, hydro and solar assets
Consistent with 2018 target
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Management’s Discussion and Analysis
Management’s Discussion and Analysis
Our business activities expose us to a variety of risks and opportunities including, but not limited to, regulatory changes,
Governance and Risk Management
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.
The key elements of our governance practices are:
▪
Governance
▪
▪
▪
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 President and 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 robust annual evaluations and continuing education of our directors;
and
our management and Board facilitate and foster an open dialogue with shareholders and community stakeholders.
▪
▪
Commitment to ethical conduct is the foundation of our corporate governance model. We have adopted the following
codes of conduct to guide our business decisions and everyday business activities:
▪
▪
▪
▪
▪
Corporate Code of Conduct, which applies to all employees and officers of TransAlta and its subsidiaries,
Directors’ Code of Conduct,
Supplier's 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, directors, consultants
and suppliers with respect to, among other things, the protection and proper use of our assets. The codes also provide
guidelines with respect to securing our assets, avoiding 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 and Directors' Code of Conduct each 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 and directors must comply.
Our employees, officers and directors are reminded annually about the importance of ethics and professionalism in their
daily work, and must certify annually that they have reviewed and understand their responsibilities as set forth in the
respective codes of conduct. This certification also requires our employees, officers and directors to acknowledge that
they have complied with the standards set out in the respective code during the last calendar year.
The Board provides stewardship of the Corporation and ensures that the Corporation establishes key policies and
procedures for the identification, assessment and management of principal risks and strategic plans. The Board monitors
and assesses the performance and progress of the Corporation’s goals through candid and timely reports from the CEO
and the senior management team. We have also established an annual evaluation process whereby our directors are
provided with an opportunity to evaluate the Board, Board committees, individual directors and the Chair’s performance.
In order to allow the Board to establish and manage the financial, environmental, and social elements of our governance
practices, the Board has established the Audit and Risk Committee (“ARC”), the Governance, Safety and Sustainability
Committee ("GSSC"), and the Human Resources Committee (the “HRC”).
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 consolidated 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.
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Management’s Discussion and Analysis
Management’s Discussion and Analysis
The GSSC 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 GSSC is also responsible for Board
recruitment, succession planning and for the nomination of directors to the Board and its committees. In addition, the GSSC
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 GSSC also receives an annual report on the annual codes 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 GSSC 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 CEO, 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 and report on 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 Senior Vice-President of Business Development and is
comprised of the Chief Financial Officer, Chief Legal and Compliance Officer, Senior Vice-President of Business
Development and Managing Director & Corporate Controller. 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 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) National Instrument 52-110 Audit Committees; iii) National Policy 58-201 Corporate
Governance Guidelines; and iv) National Instrument 58-101 Disclosure of Corporate Governance Practices. As a “foreign
private issuer” under US 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 information
circular.
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Management’s Discussion and Analysis
Management’s Discussion and Analysis
Our risk controls have several key components:
Risk Controls
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, the ARC, senior
management, and/or the Commodity Risk & Compliance Committee, as applicable. Reporting to this latter 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, contractors, shareholders or other stakeholders may confidentially or
anonymously report any potential legal or ethical concerns, including concerns relating to accounting, internal control
accounting, auditing or financial matters or relating to alleged violations of our codes of conduct. These concerns can be
submitted confidentially and anonymously, either directly to the ARC or through TransAlta’s toll-free telephone or online
Ethics Helpline. The ARC Chair is immediately notified of any material complaints and, otherwise, the ARC receives a report
at every quarterly committee meeting on all findings related to any material complaints or complaints relating to accounting
or financial reporting or alleged breaches in internal controls over financial reporting.
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, 2018, associated with our proprietary
commodity risk management activities was $2 million (2017 - $5 million). Refer to the Commodity Price Risk section of
this MD&A for further discussion.
Risk is an inherent factor of doing business. The following section addresses some, but not all, risk factors that could affect
our future plans, performance, results or outcomes and our activities in mitigating those risks. These risks do not occur in
Risk Factors
isolation, but must be considered in conjunction with each other. For a further discussion of risk factors affecting the
Corporation, readers are encouraged to read the Risk Factors section of our Annual Information Form for the year ended
Dec. 31, 2018, available on our website at www.transalta.com and under our profile on SEDAR at www.sedar.com and on
EDGAR at www.edgar.gov.
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 2018. Each item in the sensitivity analysis assumes all other potential
variables are held constant. While these sensitivities are applicable to the period and the magnitude of changes on which
they are based, they may not be applicable in other periods, under other economic circumstances, or for a greater magnitude
of changes. The changes in rates should also not be assumed to be proportionate to earnings in all instances.
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Management’s Discussion and Analysis
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:
▪
▪
▪
▪
actively managing our assets and their condition in order to be proactive in plant maintenance so that our plants are
available to produce when required;
monitoring water resources throughout Alberta to the best of our ability and optimizing this resource against real-
time electricity market opportunities;
placing our facilities in locations 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 to mitigate regional or fuel-specific events.
The sensitivity of volumes to our net earnings is shown below:
Factor
Availability/production
Increase or
decrease (%)
1
Approximate impact
on net earnings
9
Generation Equipment and Technology Risk
There is a risk of equipment failure due to wear and tear, latent defect, design error or operator error, among other things,
which could have a material adverse effect on the Corporation. Although our generation facilities have generally operated
in accordance with expectations, there can be no assurance that they will continue to do so. Our plants are exposed to
operational risks such as failures due to cyclic, thermal, and corrosion damage in boilers, generators, and turbines, and
other issues that can lead to outages and increased volume risk. If plants do not meet availability or production targets
specified in their PPA or other long-term contracts, we may be required to compensate the purchaser for the loss in the
availability of production or record reduced energy or capacity payments. For merchant facilities, an outage can result in
lost merchant opportunities. Therefore, an extended outage could have a material adverse effect on our business, financial
condition, results of operations or our cash flows.
As well, we are exposed to procurement risk for specialized parts that may have long lead times. If we are unable to procure
these parts when they are needed for maintenance activities, we could face an extended period where our equipment is
unavailable to produce electricity.
We manage our generation equipment and technology risk by:
▪
▪
▪
▪
▪
▪
▪
▪
▪
▪
▪
operating our generating facilities within defined and proven operating standards that are designed to maximize the
availability of our generating facilities for the longest period of time;
performing preventive maintenance on a regular basis;
adhering to a comprehensive plant maintenance program and regular turnaround schedules;
adjusting maintenance plans by facility to reflect the equipment type and age;
having sufficient business interruption coverage in place in the event of an extended outage;
having force majeure clauses in our thermal and other PPAs and other long-term contracts;
using proven technology in our generating facilities;
monitoring technological advances and evaluating their impact upon our existing generating fleet and related
maintenance programs;
negotiating strategic supply agreements with selected vendors to ensure key components are available in the event
of a significant outage;
entering into long-term arrangements with our strategic supply partners to ensure availability of critical spare parts;
and
developing a long-term asset management strategy with the objective of maximizing the life cycles of our existing
facilities and/or replacing of selected generating assets.
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.
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Management’s Discussion and Analysis
Management’s Discussion and Analysis
We manage the financial exposure associated with fluctuations in electricity price risk by:
▪
▪
▪
▪
entering into long-term contracts that specify the price at which electricity, steam and other services are provided;
maintaining a portfolio of short-, medium- and long-term contracts to mitigate our exposure to short-term fluctuations
in commodity prices;
purchasing natural gas coincident with production for merchant plants so spot market spark spreads are adequate to
produce and sell electricity at a profit; and
ensuring limits and controls are in place for our proprietary trading activities.
In 2018, we had approximately 85 per cent (2017 - 92 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 cost of fuels used in production by:
▪
▪
▪
entering into long-term contracts that specify the price at which fuel is to be supplied to our plants;
hedging emissions costs by entering into various emission trading arrangements; and
selectively using hedges, where available, to set prices for fuel.
In 2018, 67 per cent (2017 - 57 per cent) of our cost of gas used in generating electricity was contractually fixed or passed
through to our customers and 85 per cent (2017 - 83 per cent) of our purchased coal costs were contractually fixed.
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 US 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.
We manage coal supply risk by:
▪
▪
▪
▪
▪
▪
▪
▪
▪
▪
ensuring that the majority of the coal used in electrical generation in Alberta is from reserves permitted through coal
rights we have purchased or for which we have long-term supply contracts, thereby limiting our exposure to
fluctuations in the supply of coal from third parties;
using longer-term mining plans to ensure the optimal supply of coal from our mines;
sourcing the majority of the coal used at US 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 US Coal;
ensuring coal inventories on hand at Canadian Coal and US Coal are at appropriate levels for usage requirements;
ensuring efficient coal handling and storage facilities are in place so that the coal being delivered can be processed in
a timely and efficient manner;
monitoring and maintaining coal specifications, and carefully matching the specifications mined with the requirements
of our plants;
co-firing natural gas with coal;
monitoring the financial viability of US coal suppliers; and
hedging diesel exposure in mining and transportation costs.
Environmental Compliance Risk
Environmental compliance risks are risks to our business associated with existing and/or changes in environmental
regulations. New emission reduction objectives for the power sector are being established by governments in Canada
(including as set forth in the Alberta Climate Leadership Plan) and the US. We anticipate continued and growing scrutiny
by investors and other stakeholders 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
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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:
Management’s Discussion and Analysis
Management’s Discussion and Analysis
▪
▪
▪
▪
▪
▪
▪
▪
▪
▪
▪
▪
▪
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 US 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 GSSC.
Credit Risk
Credit risk is the risk to our business associated with changes in the creditworthiness of entities with which we have
commercial exposures. This risk results from the ability of a counterparty to either fulfil its financial or performance
obligations to us or where we have made a payment in advance of the delivery of a product or service. The inability to collect
cash due to us or to receive products or services may have an adverse impact upon our net earnings and cash flows.
We manage our exposure to credit risk by:
▪
▪
▪
▪
▪
▪
▪
establishing and adhering to policies that define credit limits based on the creditworthiness of counterparties, contract
term limits and the credit concentration with any specific counterparty;
requiring formal sign-off on contracts that include commercial, financial, legal and operational reviews;
requiring security instruments, such as parental guarantees, letters of credit, and cash collateral or third-party credit
insurance if a counterparty goes over its limits. Such security instruments can be collected if a counterparty fails to
fulfil its obligation; 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, 2017. We had no material
counterparty losses in 2018. 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.
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Management’s Discussion and Analysis
Management’s Discussion and Analysis
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, 2018:
Trade and other receivables(1)
Long-term finance lease receivables
Risk management assets(1)
Loan receivable(2)
Total
Investment grade
(Per cent)
Non-investment grade
(Per cent)
Total
(Per cent)
Total
amount
86
100
99
—
14
—
1
100
100
100
100
100
731
191
808
77
1,807
(1) Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts.
(2) The counterparties have no external credit ratings.
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 $13 million (2017 - $40 million).
Currency Rate Risk
We have exposure to various currencies as a result of our investments and operations in foreign jurisdictions, the earnings
from those operations, the acquisition of equipment and services and foreign-denominated commodities from foreign
suppliers, and our US-denominated debt. Our exposures are primarily to the US and Australian currencies. Changes in the
values of these currencies in relation to the Canadian dollar may affect our earnings or the value of our foreign investments
to the extent that these positions or cash flows are not hedged or the hedges are ineffective.
We manage our currency rate risk by establishing and adhering to policies that include:
▪
▪
▪
▪
▪
hedging our net investments in US operations using US-denominated debt;
entering into forward foreign exchange contracts to hedge future foreign-denominated expenditures including our
US-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 US exposure will be managed with
a combination of interest expense on our US-denominated debt and forward foreign exchange contracts; the
Australian exposure will be managed with forward foreign exchange contracts.
The sensitivity of our net earnings to changes in foreign exchange rates has been prepared using management’s assessment
that an average four cent increase or decrease in the US 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
Approximate impact
on net earnings
$
0.04
$27 million before tax
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.
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Management’s Discussion and Analysis
Management’s Discussion and Analysis
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, 2018, we have liquidity of $1.0 billion comprised of amounts not drawn under our committed credit facilities
and cash on hand that is available to draw on for projects in 2019.
We manage liquidity risk by:
▪
▪
▪
▪
▪
monitoring liquidity on trading positions;
preparing and revising longer-term financing plans to reflect changes in business plans and the market availability of
capital;
reporting liquidity risk exposure for commodity risk management activities on a regular basis to the Commodity Risk
& Compliance Committee, senior management and the ARC;
maintaining investment grade credit ratings; and
maintaining sufficient undrawn committed credit lines to support potential liquidity requirements.
Interest Rate Risk
Changes in interest rates can impact our borrowing costs and the capacity revenues we receive from our Alberta PPA
plants. Changes in our cost of capital may also affect the feasibility of new growth initiatives.
We manage interest rate risk by establishing and adhering to policies that include:
▪
▪
employing a combination of fixed and floating rate debt instruments; and
monitoring the mixture of floating and fixed rate debt and adjusting where necessary to ensure a continued efficient
mixture of these types of debt.
At Dec. 31, 2018, approximately 14 per cent (2017 - six 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 (%)
Approximate impact
on net earnings
15%
$1 million before tax
Project Management Risk
On capital projects, we face risks associated with cost overruns, delays and performance.
We manage project risks by:
▪
▪
▪
▪
▪
▪
▪
ensuring all projects are reviewed to see that established processes and policies are followed, risks have been properly
identified and quantified, input assumptions are reasonable and returns are realistically forecasted prior to senior
management and Board of Director 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 before starting construction;
developing and following through with comprehensive plans that include critical paths identified, key delivery points
and backup plans;
managing project closeouts so that any learnings from the project are incorporated into the next significant project,
fixing the price and availability of the equipment, foreign currency rates, warranties and source agreements as much
as is economically feasible before proceeding with the project; and
entering into labour agreements to provide security around cost and productivity.
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TRANSALTA CORPORATION M81
TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
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:
▪
▪
▪
▪
▪
potential disruption as a result of labour action at our generating facilities;
reduced productivity due to turnover in positions;
inability to complete critical work due to vacant positions;
failure to maintain fair compensation with respect to market rate changes; and
reduced competencies due to insufficient training, failure to transfer knowledge from existing employees or
insufficient expertise within current employees.
We manage this risk by:
▪
▪
▪
▪
monitoring industry compensation and aligning salaries with those benchmarks,
using incentive pay to align employee goals with corporate goals,
monitoring and managing target levels of employee turnover, and
ensuring new employees have the appropriate training and qualifications to perform their jobs.
In 2018, 50 per cent (2017 - 52 per cent) of our labour force was covered by 10 (2017 - 11) collective bargaining agreements.
In 2018, four (2017 - four) agreements were renegotiated. We anticipate the successful negotiation of five collective
agreements in 2019.
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 the new regulation to be formulated to give effect to the Alberta Climate Leadership Plan in 2020, 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 industry and government agency led 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 and regulatory agencies 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 to 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 M82
TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
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:
▪
▪
▪
▪
▪
▪
▪
▪
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 and transparent
basis;
applying innovative technologies to improve our operations, work environment and environmental footprint;
maintaining positive relationships with various levels of government;
pursuing sustainable development as a longer-term corporate strategy;
ensuring that each business decision is made with integrity and in line with our corporate values;
communicating the impact and rationale of business decisions to stakeholders in a timely manner; and
maintaining strong corporate values that support reputation risk management initiatives, including the annual code
of conduct sign-off.
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.
Cybersecurity Risk
We rely on our information technology to process, transmit and store electronic information and data used for the safe
operation of our assets. In today's ever evolving cybersecurity landscape, any attacks or other breaches of network or
information systems may cause disruptions to our business operations. Cyberattackers may use a range of techniques,
from exploiting vulnerabilities within our user-base, to using sophisticated malicious code on a single or distributed basis
to try to breach our network security controls. Attackers may also use a combination of techniques in their attempt to
evade safeguards such as firewalls, intrusion prevention systems and antivirus software that exist on our network
infrastructure systems. A successful cyberattack may allow for the unauthorized interception, destruction, use or
dissemination of our information and may cause disruptions to our business operations.
We continuously take measures to secure our infrastructure against potential cyberattacks that may damage our
infrastructure, systems and data. Our cybersecurity 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. We have also
established security awareness programs to help educate our users on cybersecurity risks and their responsibilities in
helping protect 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 facilities and infrastructure and data, there can be no assurance that these
measures will be sufficient or 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.
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
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TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
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 (%)
Approximate impact
on net earnings
1
$1 million
Legal Contingencies
We are occasionally named as a party in various disputes, claims and legal or 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 dispute, claim or
proceeding will be resolved in our favour or our liabilities with respect to such claims will not have a material adverse effect
on us or our business, operations or financial results.
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 Dec. 31, 2018. 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. All insurance policies are subject to standard exclusions. Cyber coverage is not currently
purchased.
Fourth Quarter
Consolidated Financial Highlights
Three months ended Dec. 31
Revenues
Net earnings (loss) attributable to common shareholders
Cash flow from operating activities
Comparable EBITDA(1)
FFO(1)
FCF(1)
Net earnings (loss) per share attributable to common shareholders, basic and diluted
FFO per share(1)
FCF per share(1)
Dividends declared per common share(2)
Dividends declared per preferred share(2)
2018
622
(122)
132
233
217
98
2017
638
(145)
81
275
219
101
(0.43)
(0.50)
0.76
0.34
0.08
0.52
0.76
0.35
0.04
0.26
(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 Discussion of Consolidated Financial Results section of this MD&A for further discussion of these
items, including, where applicable, reconciliations to measures calculated in accordance with IFRS.
(2) Dividends declared vary year over year due to timing of dividend declarations.
We delivered consistent results in the fourth quarter with FCF of $98 million, compared to $101 million last year. FFO was
Financial Highlights
$217 million, which was comparable to the fourth quarter of 2017, as the business continues to deliver solid performance.
Net loss attributable to common shareholders in the fourth quarter of 2018 was $122 million ($0.43 net loss per share)
compared to a net loss of $145 million ($0.50 net earnings per share) in the same period of 2017, an improvement of $23
million compared to last year. This was driven by an income tax recovery of $16 million compared to income tax expense
of $105 million in 2017, which was high due to the US tax rate reduction. This improvement was partially offset by lower
comparable EBITDA of $42 million and the write-off of project development costs of $23 million in the fourth quarter of
2018.
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TRANSALTA CORPORATION M84
TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
Segmented cash flows generated by the business measures the net cash generated by each of our segments after sustaining
and productivity capital expenditures, reclamation costs and provisions. It also excludes non-cash mark-to-market gains
Segmented Cash Flows Generated by the Business and Operational Performance
or losses. This is the cash flows available to pay our interest and cash taxes, distributions to our non-controlling partners
and dividends to our preferred shareholders, grow the business, pay down debt and return capital to our shareholders.
Segmented cash flows and operational performance for the business during the quarter is as follows:
Three months ended Dec. 31
Availability (%)(1)
Production (GWh)(1)
Segmented cash inflow (outflow)(2)
Canadian Coal
US Coal
Canadian Gas
Australian Gas(3)
Wind and Solar
Hydro
Generation cash inflow
Energy Marketing
Corporate
Total comparable cash inflow
2018
91.5
8,276
2017
88.4
10,374
16
21
59
35
74
11
216
10
(34)
192
11
15
56
33
73
10
198
15
(28)
185
(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) This is not defined under IFRS. Presenting this item 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 Discussion of Consolidated Financial Results section of this MD&A for further discussion of these items,
including, where applicable, reconciliations to measures calculated in accordance with IFRS.
(3) 2017 cash flow revised to reflect the impacts of the change in the long-term receivable in Australian Gas.
Adjusted availability for the three months ended Dec. 31, 2018, improved compared with the same period in 2017. Lower
production for the three months ended Dec. 31, 2018, compared to the same period in 2017 is primarily due to the
termination of the Sundance B and C PPAs and derates, partially offset by higher dispatch optimization in US Coal and
higher Ancillary Services within our Hydro segment.
Cash flows generated by the business totalled $192 million in the fourth quarter, an increase of $7 million compared with
last year’s performance. Increased cash flows are largely due to the strong merchant prices in the Alberta market, lower
sustaining capital spend and the settlement of a long-term receivable in Australian Gas, partially offset by higher carbon
compliance costs.
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TRANSALTA CORPORATION M85
TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
We evaluate our performance and the performance of our business segments using a variety of measures. Certain of the
Discussion of Consolidated Financial Results
financial measures discussed in this MD&A, including the comparable figures below are not defined under IFRS and,
therefore, should not be considered in isolation or as an alternative to or to be more meaningful than net earnings
attributable to common shareholders or cash flow from operating activities, as determined in accordance with IFRS, when
assessing our financial performance or liquidity. These measures are not necessarily comparable to a similarly titled
measure of another company. Each business segment assumes responsibility for its operating results measured to
comparable EBITDA and cash flows generated by the business. Gross margin is also a useful measure as it provides
management and investors with a measurement of operating performance that is readily comparable from period to period.
A reconciliation of net earnings (loss) attributable to common shareholders to comparable EBITDA results is set out below:
Comparable EBITDA
Three months ended Dec. 31
2018
2017
Net earnings (loss) attributable to common shareholders
Net earnings attributable to non-controlling interests
Preferred share dividends
Net earnings (loss)
Adjustments to reconcile net income to comparable EBITDA
Income tax expense
Gain on sale of assets and other
Foreign exchange (gain) loss
Net interest expense
Depreciation and amortization
Comparable reclassifications
Decrease in finance lease receivables
Mine depreciation included in fuel cost
Australian interest income
Adjustments to earnings to arrive at comparable EBITDA
Impacts associated with Mississauga recontracting(1)
Asset impairment charge (reversal)
Comparable EBITDA
(122)
43
20
(59)
(16)
—
—
50
152
15
37
1
30
23
233
(145)
19
10
(116)
105
(1)
(6)
57
180
15
20
1
20
—
275
(1) Impacts associated with Mississauga recontracting for the three months ended Dec. 31, 2018, are as follows: revenue $30 million (2017 - $29 million) and recovery
related to renegotiated land lease of nil (2017 - $9 million).
(2) Asset impairment charges for the three months ended Dec. 31, 2018, include a write-off of project development costs of $23 million.
A summary of our comparable EBITDA by segments for the three months ended Dec. 31, 2018 and 2017 is as follows:
Three months ended Dec. 31
Comparable EBITDA
Canadian Coal
US Coal
Canadian Gas
Australian Gas
Wind and Solar
Hydro
Energy Marketing
Corporate
Total comparable EBITDA
M86
2018
2017
56
(1)
73
32
72
17
12
(28)
233
66
21
62
29
78
14
25
(20)
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TRANSALTA CORPORATION M86
TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
Comparable EBITDA decreased by $42 million for the fourth quarter 2018, compared to 2017, primarily as a result of:
▪
▪
▪
▪
▪ Wind and Solar results were down $6 million period-over-period mainly due to lower production, partially offset by
Our Canadian Coal results were down $10 million mainly due to higher carbon compliance costs in 2018.
US Coal results were down $22 million primarily due to unfavourable changes on unrealized mark-to-market positions.
Our Canadian Gas business was up $11 million period-over-period due to higher market price impacts.
Australian Gas was up $3 million and was fairly consistent with prior year results.
higher prices in Alberta.
Hydro results were $3 million higher period-over-period due to higher Ancillary Service revenues.
Energy Marketing’s comparable EBITDA was down $13 million during the fourth quarter of 2018 compared to 2017
mainly because the 2017 results were very strong in the Alberta market.
Corporate costs increased by $8 million in the fourth quarter mainly due to higher contractor costs.
▪
▪
▪
FFO per share and FCF per share are calculated as follows using the weighted average number of common shares
outstanding during the period. FFO, FFO per share, FCF and FCF per share are non-IFRS measures, are not defined under
Funds from Operations and Free Cash Flow
IFRS, and therefore, should not be considered in isolation or as an alternative to or to be more meaningful than cash flow
from operating activities as determined in accordance with IFRS, when assessing our financial performance or liquidity.
See the Additional IFRS Measures and Non-IFRS Measures section above and elsewhere in this MD&A for further details.
The table below reconciles our cash flow from operating activities to our FFO and FCF:
Three months ended Dec. 31
Cash flow from operating activities
Change in non-cash operating working capital balances
Cash flow from operations before changes in working capital
Adjustments
Decrease in finance lease receivable
Other
FFO
Deduct:
Sustaining capital
Productivity capital
Dividends paid on preferred shares
Distributions paid to subsidiaries’ non-controlling interests
Other
FCF
Weighted average number of common shares outstanding in the period
FFO per share
FCF per share
2018
2017
132
69
201
15
1
217
(56)
(9)
(10)
(43)
(1)
98
286
0.76
0.34
81
121
202
15
2
219
(62)
(9)
(10)
(36)
(1)
101
288
0.76
0.35
FFO was down $2 million during the fourth quarter of 2018 compared to the same period in 2017. FCF decreased by $3
million period-over-period as we continued to reduce our sustaining capital spend as a result of our decision to mothball
certain Sundance units.
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TRANSALTA CORPORATION M87
TransAlta Corporation | 2018 Annual Integrated Report Management’s Discussion and Analysis
Management’s Discussion and Analysis
The table below provides a reconciliation of our comparable EBITDA to our FFO and FCF:
Three months ended Dec. 31
Comparable EBITDA
Provisions
Unrealized (gains) losses from risk management activities
Interest expense
Current income tax expense
Realized foreign exchange gain (loss)
Decommissioning and restoration costs settled
Other non-cash items
FFO
Deduct:
Sustaining capital
Productivity capital
Dividends paid on preferred shares
Distributions paid to subsidiaries’ non-controlling interests
Other
Comparable FCF
Weighted average number of common shares outstanding in the period
Comparable FFO per share
Comparable FCF per share
2018
233
2017
275
—
27
(40)
(10)
1
(8)
14
217
(56)
(9)
(10)
(43)
(1)
98
286
0.76
0.34
(10)
(8)
(52)
(6)
8
(7)
19
219
(62)
(9)
(10)
(36)
(1)
101
288
0.76
0.35
M88
TRANSALTA CORPORATION M88
TransAlta Corporation | 2018 Annual Integrated Report Management’s Discussion and Analysis
Management’s Discussion and Analysis
Our results are seasonal due to the nature of the electricity market and related fuel costs. Higher maintenance costs are
Selected Quarterly Information
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 US 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.
Revenues
Comparable EBITDA
FFO
Net earnings (loss) attributable to common shareholders
Net earnings (loss) per share attributable to common shareholders, basic
and diluted(1)
Revenues
Comparable EBITDA
FFO
Net earnings (loss) attributable to common shareholders
Net earnings (loss) per share attributable to common shareholders, basic
and diluted(1)
Q1 2018
Q2 2018
Q3 2018
Q4 2018
588
416
318
65
446
225
188
(105)
593
249
204
(86)
622
233
217
(122)
0.23
(0.36)
(0.30)
(0.43)
Q1 2017
Q2 2017
Q3 2017
Q4 2017
578
274
202
—
—
503
268
187
(18)
588
245
196
(27)
638
275
219
(145)
(0.06)
(0.09)
(0.50)
(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.
Reported net earnings, comparable EBITDA, and FFO are generally higher in the first and fourth quarters due to higher
demand associated with winter cold in the markets in which we operate and lower planned outages.
Net earnings attributable to common shareholders has also been impacted by the following variations and events:
▪
▪
effects of impairment charges during the second, third and fourth quarters of 2018 and second quarter of 2017;
recognition of the $157 million early termination payment received regarding Sundance B and C PPAs during the first
quarter of 2018;
a recovery of a writedown of deferred tax assets in the second quarter of 2017;
change in income tax rates in the US in the fourth quarter of 2017;
effects of non-comparable unrealized gains on intercompany financial instruments that are attributable only to the
non-controlling interests in the first quarter of 2017;
effects of changes in useful lives of certain Canadian Coal assets during the first, second and third quarters of 2017;
and
effects of an impairment of $137 million in 2017 on intercompany financial instruments that is attributable only to
the non-controlling interests.
▪
▪
▪
▪
▪
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TRANSALTA CORPORATION M89
TransAlta Corporation | 2018 Annual Integrated Report
Management’s Discussion and Analysis
Management’s Discussion and Analysis
Management is responsible for establishing and maintaining adequate internal control over financial reporting (‘‘ICFR’’)
Disclosure Controls and Procedures
and disclosure controls and procedures (“DC&P’’). There have been no changes in our ICFR or DC&P during the year ended
Dec. 31, 2018, that have materially affected, or are reasonably likely to materially affect, our ICFR or DC&P.
ICFR is a framework designed to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of consolidated financial statements for external purposes in accordance with IFRS. Management has used
the Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (2013 framework) in order to assess the effectiveness of the Corporation’s ICFR.
DC&P refer to controls and other procedures designed to ensure that information required to be disclosed in the reports
we file or submit under securities legislation are recorded, processed, summarized and reported within the time frame
specified in securities legislation. DC&P 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 securities legislation 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.
Together, the ICFR and DC&P frameworks provide internal control over financial reporting and disclosure. In designing
and evaluating our ICFR and DC&P, 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 as such may not
prevent or detect all misstatements, and management is required to apply its judgment in evaluating and implementing
possible controls and procedures. Further, the effectiveness of ICFR is subject to the risk that controls may become
inadequate because of changes in conditions or that the degree of compliance with policies or procedures may change.
Management has evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the
effectiveness of our ICFR and DC&P as of the end of the period covered by this report. Based on the foregoing evaluation,
our Chief Executive Officer and Chief Financial Officer have concluded that, as at Dec. 31, 2018, the end of the period
covered by this report, our ICFR and DC&P were effective.
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TRANSALTA CORPORATION M90
TransAlta Corporation | 2018 Annual Integrated Report Consolidated Financial Statements
Consolidated Financial Statements
Management's Report
The Consolidated Financial Statements and other financial information included in this annual report have been prepared
To the Shareholders of TransAlta Corporation
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 controls. 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
Christophe Dehout
Chief Financial Officer
February 26, 2019
F1
TRANSALTA CORPORATION F1
TransAlta Corporation | 2018 Annual Integrated Report
Consolidated Financial Statements
Consolidated Financial Statements
Management’s Annual Report on Internal Control over Financial Reporting
The following report is provided by management in respect of TransAlta Corporation’s (“TransAlta”) internal control over
To the Shareholders of TransAlta Corporation
financial reporting (as defined in Rules 13a-15f and 15d-15f under the United States Securities Exchange Act of 1934 and
National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings).
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. 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 2018
Consolidated Financial Statements of TransAlta included $588 million and $521 million of total and net assets, respectively,
as of December 31, 2018, and $244 million and $27 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,
2018, 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,
2018, 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
Christophe Dehout
Chief Financial Officer
February 26, 2019
F2
TRANSALTA CORPORATION F2
TransAlta Corporation | 2018 Annual Integrated Report Consolidated Financial Statements
Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
Opinion on Internal Control over Financial Reporting
To the Shareholders and Directors of TransAlta Corporation
We have audited TransAlta Corporation’s internal control over financial reporting as of December 31, 2018, 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”). In our opinion, TransAlta Corporation maintained, in
all material respects, effective internal control over financial reporting as of December 31, 2018, based on the COSO
criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(“PCAOB”), the Consolidated Statements of Financial Position of TransAlta Corporation as of December 31, 2018 and
2017, and the related Consolidated Statements of Earnings (Loss), Comprehensive Income (Loss), Changes in Equity and
Cash Flows for each of the three years in the period ended December 31, 2018 and the related notes and our report dated
February 26, 2019 expressed an unqualified opinion thereon.
Basis for Opinion
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
TransAlta Corporation’s internal control over financial reporting based on our audit. We are a public accounting firm
registered with the PCAOB and are required to be independent with respect to TransAlta Corporation in accordance with
the US federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the
PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. 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.
Definition and Limitations of Internal Control Over Financial Reporting
A company’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
International Financial Reporting Standards as issued by the International Accounting Standards Board. A company’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 International Financial Reporting Standards as issued by the International
Accounting Standards Board, 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 2018 consolidated
financial statements of TransAlta and constituted $588 million and $521 million of total and net assets, respectively, as of
December 31, 2018, and $244 million and $27 million of revenues and net loss, respectively, for the year then ended. Our
audit of internal control over financial reporting of TransAlta Corporation did not include an evaluation of the internal
control over financial reporting of the Sheerness and Genesee Unit 3 joint arrangements.
Chartered Professional Accountants
Calgary, Canada
February 26, 2019
F3
TRANSALTA CORPORATION F3
TransAlta Corporation | 2018 Annual Integrated Report
Consolidated Financial Statements
Consolidated Financial Statements
Independent Auditors’ Report of Registered Public Accounting Firm
Opinion on the Consolidated Financial Statements
To the Shareholders and Directors of TransAlta Corporation
We have audited the accompanying Consolidated Statements of Financial Position of TransAlta Corporation as of
December 31, 2018 and 2017, the related Consolidated Statements of Earnings (Loss), Comprehensive Income (Loss),
Changes in Equity and Cash Flows, for each of the years then ended, and the related notes (collectively referred to as the
“Consolidated Financial Statements“). In our opinion, the Consolidated Financial Statements present fairly, in all material
respects, the financial position of TransAlta Corporation at December 31, 2018 and 2017, and the results of its operations
and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with International
Financial Reporting Standards as issued by the International Accounting Standards Board.
Report on internal control over financial reporting
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(“PCAOB”), TransAlta Corporation’s internal control over financial reporting as of December 31, 2018, based on criteria
established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of
the Treadway Commission (“COSO”), and our report dated February 26, 2019 expressed an unqualified opinion thereon.
Basis for Opinion
These consolidated financial statements are the responsibility of TransAlta Corporation‘s management. Our responsibility
is to express an opinion on TransAlta Corporation‘s Consolidated Financial Statements based on our audits. We are a public
accounting firm registered with the PCAOB and are required to be independent with respect to TransAlta Corporation in
accordance with the US federal securities laws and the applicable rules and regulations of the Securities and Exchange
Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material
misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material
misstatement of the Consolidated Financial Statements, whether due to error or fraud, and performing procedures that
respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures
in the Consolidated Financial Statements. Our audits also included evaluating the accounting principles used and significant
estimates made by management, as well as evaluating the overall presentation of the Consolidated Financial Statements.
We believe that our audits provide a reasonable basis for our opinion.
Chartered Professional Accountants
We have served as TransAlta Corporation and its predecessor entities' auditor since 1947
Calgary, Canada
February 26, 2019
F4
TRANSALTA CORPORATION F4
TransAlta Corporation | 2018 Annual Integrated Report
Consolidated Financial Statements
Consolidated Financial Statements
Consolidated Statements of Earnings (Loss)
Year ended Dec. 31 (in millions of Canadian dollars except where noted)
2018
2017
2016
Revenues (Note 5)
Fuel and purchased power (Note 6)
Gross margin
Operations, maintenance and administration (Note 6)
Depreciation and amortization
Asset impairment charges (reversals) (Note 7)
Taxes, other than income taxes
Net other operating expense (income) (Note 9)
Operating income
Finance lease income
Net interest expense (Note 10)
Foreign exchange gain (loss)
Gain on sale of assets and other
Earnings (loss) before income taxes
Income tax expense (recovery) (Note 11)
Net earnings (loss)
Net earnings (loss) attributable to:
TransAlta shareholders
Non-controlling interests (Note 12)
Net earnings (loss) attributable to TransAlta shareholders
Preferred share dividends (Note 25)
Net earnings (loss) attributable to common shareholders
Weighted average number of common shares outstanding in the year (millions)
2,249
1,100
1,149
2,307
1,016
1,291
515
574
73
31
(204)
160
8
(250)
(15)
1
(96)
(6)
(90)
(198)
108
(90)
(198)
50
(248)
287
517
635
20
30
(49)
138
54
(247)
(1)
2
(54)
64
(118)
(160)
42
(118)
(160)
30
(190)
288
2,397
963
1,434
489
601
28
31
(193)
478
66
(229)
(5)
4
314
38
276
169
107
276
169
52
117
288
Net earnings (loss) per share attributable to common shareholders, basic and diluted
(Note 24)
(0.86)
(0.66)
0.41
See accompanying notes.
F5
TRANSALTA CORPORATION F5
TransAlta Corporation | 2018 Annual Integrated Report
Consolidated Financial Statements
Consolidated Financial Statements
Consolidated Statements of Comprehensive Income (Loss)
Year ended Dec. 31 (in millions of Canadian dollars)
Net earnings (loss)
2018
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(4)
(Note 4)
Gains (losses) on financial instruments designated as hedges of foreign operations,
net of tax(5)
Reclassification of losses on financial instruments designated as hedges of divested
foreign operations, net of tax(6)
(Note 4)
Gains (losses) on derivatives designated as cash flow hedges, net of tax(7)
Reclassification of gains on derivatives designated as cash flow hedges to net earnings,
net of tax(8)
Total items that will be reclassified subsequently to net earnings
Other comprehensive income
Total comprehensive income (loss)
Total comprehensive income (loss) attributable to:
TransAlta shareholders
Non-controlling interests (Note 12)
(90)
15
—
15
84
—
(41)
—
(8)
(46)
(11)
4
(86)
(210)
124
(86)
2017
(118)
2016
276
(6)
(1)
(7)
(80)
(9)
50
14
214
(107)
82
75
(43)
(74)
31
(43)
8
(1)
7
(71)
—
18
—
179
(48)
78
85
361
215
146
361
(1) Net of income tax expense of 5 million for the year ended Dec. 31, 2018 (2017 - 4 million recovery, 2016 - 4 million expense).
(2) Net of income tax of nil for the year ended Dec. 31, 2018 (2017 - nil , 2016 - nil).
(3) Net of income tax of nil for the year ended Dec. 31, 2018 (2017 - nil, 2016 - 11 million expense).
(4) Net of reclassification of income tax of nil for the year ended Dec. 31, 2018 (2017 - 11 million expense, 2016 - nil).
(5) Net of income tax of nil for the year ended Dec. 31, 2018 (2017 - 2 million expense, 2016 - 5 million expense).
(6) Net of reclassification of income tax of nil for the year ended Dec. 31, 2018 (2017 - 2 million recovery, 2016 - nil).
(7) Net of income tax recovery of 1 million for the year ended Dec. 31, 2018 (2017 - 77 million recovery, 2016 - 92 million expense).
(8) Net of reclassification of income tax expense of 11 million for the year ended Dec. 31, 2018 (2017 - 31 million expense, 2016 - 41 million expense).
See accompanying notes.
F6
TRANSALTA CORPORATION F6
TransAlta Corporation | 2018 Annual Integrated Report
Consolidated Financial Statements
Consolidated Financial Statements
As at Dec. 31 (in millions of Canadian dollars)
Consolidated Statements of Financial Position
Cash and cash equivalents
Restricted cash (Note 22)
Trade and other receivables (Note 13)
Prepaid expenses
Risk management assets (Note 14 and 15)
Inventory (Note 16)
Restricted cash (Note 22)
Long-term portion of finance lease receivables (Note 8)
Property, plant and equipment (Note 17)
Cost
Accumulated depreciation
Goodwill (Note 18)
Intangible assets (Note 19)
Deferred income tax assets (Note 11)
Risk management assets (Note 14 and 15)
Other assets (Note 20)
Total assets
Accounts payable and accrued liabilities
Current portion of decommissioning and other provisions (Note 21)
Risk management liabilities (Note 14 and 15)
Income taxes payable
Dividends payable (Note 24 and 25)
Current portion of long-term debt and finance lease obligations (Note 22)
Credit facilities, long-term debt and finance lease obligations (Note 22)
Decommissioning and other provisions (Note 21)
Deferred income tax liabilities (Note 11)
Risk management liabilities (Note 14 and 15)
Contract liabilities (Note 5)
Defined benefit obligation and other long-term liabilities (Note 23)
Equity
Common shares (Note 24)
Preferred shares (Note 25)
Contributed surplus
Deficit
Accumulated other comprehensive income (Note 26)
Equity attributable to shareholders
Non-controlling interests (Note 12)
Total equity
Total liabilities and equity
Commitments and contingencies (Note 33)
On behalf of the Board:
See accompanying notes.
Gordon D. Giffin
Director
Beverlee F. Park
Director
2018
89
66
756
13
146
242
1,312
—
191
13,202
(7,038)
6,164
464
373
28
662
234
9,428
497
70
90
10
58
148
873
3,119
386
501
41
87
287
3,059
942
11
(1,496)
481
2,997
1,137
4,134
9,428
2017
314
—
933
24
219
219
1,709
30
215
12,973
(6,395)
6,578
463
364
24
684
237
10,304
595
67
101
64
34
747
1,608
2,960
403
549
40
62
297
3,094
942
10
(1,209)
489
3,326
1,059
4,385
10,304
TRANSALTA CORPORATION F7
F7
TransAlta Corporation | 2018 Annual Integrated Report
Consolidated Financial Statements
Consolidated Financial Statements
(in millions of Canadian dollars)
Consolidated Statements of Changes in Equity
Common
shares
Preferred
shares
Contributed
surplus Deficit
Accumulated
other
comprehensive
income(1)
Attributable
to
shareholders
Attributable
to
non-
controlling
interests
Total
Balance, Dec. 31, 2016
Net earnings
3,094
—
942
—
(933)
(160)
399
—
3,511
(160)
1,152
4,663
42
(118)
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)
Effect of share-based payment
plans
Distributions paid, and payable, to
non-controlling interests
Balance, Dec. 31, 2017
Impact of change in accounting
policy (Note 3)
Adjusted balance as at Jan. 1,
2018
Net earnings (loss)
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 fair value through
other comprehensive income
investments
Total comprehensive income
Common share dividends
Preferred share dividends
—
—
—
—
—
—
—
—
—
3,094
—
3,094
—
—
—
—
—
—
—
Shares purchased under NCIB
(35)
Changes in non-controlling
interests in TransAlta
Renewables (Note 4)
Effect of share-based payment
plans
Distributions paid, and payable, to
non-controlling interests
Balance, Dec.31, 2018
—
—
—
—
—
—
—
—
—
—
—
—
942
—
942
—
—
—
—
—
—
—
—
—
—
—
9
—
—
—
—
—
—
—
—
1
—
10
—
10
—
—
—
—
—
—
—
—
—
1
—
11
—
—
—
—
(160)
(34)
(30)
(52)
—
—
(1,209)
(14)
(1,223)
(198)
—
—
—
—
(198)
(57)
(50)
12
20
—
—
(25)
(25)
—
—
—
(11)
31
—
—
48
—
(25)
106
(6)
—
(43)
(34)
(30)
—
1
(172)
(172)
106
(6)
11
(74)
(34)
(30)
(48)
1
—
3,326
1,059
4,385
(14)
3,312
(198)
1
(13)
1,060
4,372
108
(90)
43
(54)
15
(16)
(210)
(57)
(50)
(23)
24
1
—
—
—
—
16
124
—
—
—
43
(54)
15
—
(86)
(57)
(50)
(23)
133
157
—
1
(180)
(180)
106
(6)
11
86
—
—
4
—
—
489
—
489
—
43
(54)
15
(16)
(12)
—
—
—
4
—
—
3,059
942
(1,496)
481
2,997
1,137
4,134
(1) Refer to Note 26 for details on components of, and changes in, accumulated other comprehensive income (loss).
See accompanying notes.
F8
TRANSALTA CORPORATION F8
TransAlta Corporation | 2018 Annual Integrated Report
Consolidated Financial Statements
Consolidated Financial Statements
Consolidated Statements of Cash Flows
Year ended Dec. 31 (in millions of Canadian dollars)
Operating activities
2018
2017
2016
Net earnings (loss)
Depreciation and amortization (Note 34)
Gain (loss) on sale of assets (Note 4)
Accretion of provisions (Note 21)
Decommissioning and restoration costs settled (Note 21)
Deferred income tax expense (recovery) (Note 11)
Unrealized (gain) loss from risk management activities
Unrealized foreign exchange (gain) loss
Provisions
Asset impairment charges (reversals) (Note 7)
Other non-cash items
Cash flow from operations before changes in working capital
Change in non-cash operating working capital balances (Note 30)
Cash flow from operating activities
Investing activities
Additions to property, plant and equipment (Note 17 and 34)
Additions to intangibles (Note 19 and 34)
Restricted cash (Note 22)
Loan receivable (Note 20)
Acquisition of renewable energy facilities, net of cash acquired (Note 4)
Proceeds on sale of property, plant and equipment
Proceeds on sale of Wintering Hills facility and Solomon disposition (Note 4)
Income tax expense on Solomon disposition (Note 4 and 11)
Realized gains (losses) on financial instruments
Decrease in finance lease receivable
Other
Change in non-cash investing working capital balances
Cash flow from (used in) investing activities
Financing activities
Net increase (decrease) in borrowings under credit facilities (Note 22)
Repayment of long-term debt (Note 22)
Issuance of long-term debt (Note 22)
Dividends paid on common shares (Note 24)
Dividends paid on preferred shares (Note 25)
Net proceeds on sale of non-controlling interest in subsidiary (Note 4)
Repurchase of common shares under NCIB (Note 24)
Realized gains (losses) on financial instruments
Distributions paid to subsidiaries' non-controlling interests (Note 12)
Decrease in finance lease obligations (Note 22)
Other
Change in non-cash financing working capital balances
Cash flow from (used in) financing activities
Cash flow from (used in) operating, investing, and financing activities
Effect of translation on foreign currency cash
Increase (decrease) 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.
(90)
710
—
24
(31)
(34)
30
28
7
73
147
864
(44)
820
(277)
(20)
(35)
1
(30)
2
2
—
2
59
(2)
(96)
(394)
312
(1,179)
345
(46)
(40)
144
(23)
48
(165)
(18)
(31)
2
(651)
(225)
—
(225)
314
89
87
188
(118)
708
(1)
23
(19)
(15)
(48)
22
(7)
20
175
740
(114)
626
(338)
(51)
(30)
(38)
—
3
478
(56)
6
59
(3)
57
87
26
(814)
260
(46)
(40)
—
—
106
(172)
(17)
(6)
—
(703)
10
(1)
9
305
314
14
230
276
664
(1)
20
(23)
15
58
(1)
(123)
28
(242)
671
73
744
(358)
(21)
—
—
—
6
—
—
(6)
56
2
(6)
(327)
(315)
(88)
361
(69)
(42)
162
—
(2)
(151)
(16)
(3)
—
(163)
254
(3)
251
54
305
27
235
F9
TRANSALTA CORPORATION F9
TransAlta Corporation | 2018 Annual Integrated Report
(Tabular amounts in millions of Canadian dollars, except as otherwise noted)
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
(Tabular amounts in millions of Canadian dollars, except as otherwise noted)
TransAlta Corporation (“TransAlta” or the “Corporation”) was incorporated under the Canada Business Corporations Act in
1. Corporate Information
March 1985. The Corporation became a public company in December 1992. Its head office is located in Calgary, Alberta.
A. Description of the Business
I. Generation Segments
The six generation segments of the Corporation are as follows: Canadian Coal, US Coal, Canadian Gas, Australian Gas,
Wind and Solar, and Hydro. The Corporation directly or indirectly owns and operates hydro, wind and solar, natural gas
and coal-fired facilities, and related mining operations in Canada, the United States (“US”), 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 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, investor relation functions and
corporate development. Charges directly or reasonably attributable to other segments are allocated thereto.
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”).
B. Basis of Preparation
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 TransAlta's Board of Directors (the "Board") on
February 26, 2019.
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
C. Basis of Consolidation
the ability to affect the returns through its power over the subsidiary. The financial statements of the subsidiaries are
prepared for the same reporting period and apply consistent accounting policies as the parent company.
F10
TRANSALTA CORPORATION F10
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
2. Significant Accounting Policies
I. Revenue from Contracts with Customers
The Corporation has adopted IFRS 15 Revenue from Contracts with Customers (IFRS 15) with an initial adoption date of Jan.
A. Revenue Recognition
1, 2018. As a result, the Corporation has changed its accounting policy for revenue recognition, which is outlined below.
The Corporation has elected to adopt IFRS 15 retrospectively with the modified retrospective method of transition
practical expedient and has elected to apply IFRS 15 only to contracts that are active at the date of initial adoption.
Comparative information has not been restated and is reported under IAS 18 Revenue (IAS 18). Refer to section III below
for the accounting policy for prior years.
The majority of the Corporation’s revenues from contracts with customers are derived from the sale of generation capacity,
electricity, thermal energy, renewable attributes and byproducts of power generation. The Corporation evaluates whether
the contracts it enters into meet the definition of a contract with a customer at the inception of the contract and on an
ongoing basis if there is an indication of significant changes in facts and circumstances. Revenue is measured based on the
transaction price specified in a contract with a customer. Revenue is recognized when control of the good or services is
transferred to the customer. For certain contracts, revenue may be recognized at the invoiced amount, as permitted using
the invoice practical expedient, if such amount corresponds directly with the Corporation’s performance to date. The
Corporation excludes amounts collected on behalf of third parties from revenue.
Performance Obligations
Each promised good or service is accounted for separately as a performance obligation if it is distinct. The Corporation’s
contracts may contain more than one performance obligation.
Transaction Price
The Corporation allocates the transaction price in the contract to each performance obligation. Transaction price allocated
to performance obligations may include variable consideration. Variable consideration is included in the transaction price
for each performance obligation when it is highly probable that a significant reversal of the cumulative variable revenue
will not occur. Variable consideration is assessed at each reporting period to determine whether the constraint is lifted.
The consideration contained in some of the Corporation's contracts with customers is primarily variable, and may include
both variability in quantity and pricing, such as: revenues can be dependent upon future production volumes which are
driven by customer or market demand or by the operational ability of the plant; revenues can be dependent upon the
variable cost of producing the energy; revenues can be dependent upon market prices; and revenues can be subject to
various indices and escalators.
When multiple performance obligations are present in a contract, transaction price is allocated to each performance
obligation in an amount that depicts the consideration the Corporation expects to be entitled to in exchange for transferring
the good or service. The Corporation estimates the amount of the transaction price to allocate to individual performance
obligations based on their relative standalone selling prices, which is primarily estimated based on the amounts that would
be charged to customers under similar market conditions.
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Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
Recognition
The nature, timing of recognition of satisfied performance obligations, and payment terms for the Corporation’s goods
and services are described below:
Good or Service
Capacity
Contract Power
Thermal Energy
Renewable Attributes
Generation byproducts
Description
Capacity refers to the availability of an asset to deliver goods or services. Customers typically
pay for capacity for each defined time period (i.e., monthly) in an amount representative of
availability of the asset for the defined time period. Obligations to deliver capacity are
satisfied over time and revenue is recognized using a time-based measure. Contracts for
capacity are typically long term in nature. Payments are typically received from customers
on a monthly basis.
The sale of contract power refers to the delivery of units of electricity to a customer under
the terms of a contract. Customers pay a contractually specified price for the output at the
end of predefined contractual periods (i.e., monthly). Obligations to deliver electricity are
satisfied over time and revenue is recognized using a units-based output measure (i.e.,
megawatt hours). Contracts for power are typically long term in nature and payments are
typically received on a monthly basis.
Thermal energy refers to the delivery of units of steam to a customer under the terms of a
contract. Customers pay a contractually specified price for the output at the end of
predefined contractual periods (i.e., monthly). Obligations to deliver steam are satisfied over
time and revenue is recognized using a units-based output measure (i.e., gigajoules).
Contracts for thermal energy are typically long term in nature. Payments are typically
received from customers on a monthly basis.
Renewable attributes refers to the delivery of renewable energy certificates, green
attributes and other similar items. Customers may contract for renewable attributes in
conjunction with the purchase of power, in which case the customer pays for the attributes
in the month subsequent to the delivery of the power. Alternatively, customers pay upon
delivery of the renewable attributes. Obligations to deliver renewable attributes are
satisfied at a point in time, generally upon delivery of the item.
Generation byproducts refers to the sale of byproducts from the use of coal in the
Corporation’s Canadian and US coal operations, and the sale of coal to third parties.
Obligations to deliver byproducts are satisfied at a point in time, generally upon delivery of
the item. Payments are received upon satisfaction of delivery of the byproducts.
The Corporation recognizes a contract asset or contract liability for contracts where either party has performed. A contract
liability is recorded when the Corporation receives consideration before the performance obligations have been satisfied.
A contract asset is recorded when the Corporation has rights to consideration for the completion of a performance
obligation before it has invoiced the customer. The Corporation recognizes unconditional rights to consideration separately
as a receivable. Contract assets and receivables are evaluated at each reporting period to determine whether there is any
objective evidence that they are impaired.
The Corporation recognizes a significant financing component where the timing of payment from the customer differs
from the Corporation’s performance under the contract and where that difference is the result of the Corporation financing
the transfer of goods and services.
Significant Judgments
Identification of performance obligations
Where contracts contain multiple promises for goods or services, management exercises judgment in determining whether
goods or services constitute distinct goods or services or a series of distinct goods or services that are substantially the
same and that have the same pattern of transfer to the customer. The determination of a performance obligation affects
whether the transaction price is recognized at a point in time or over time. Management considers both the mechanics of
the contract and the economic and operating environment of the contract in determining whether the goods or services
in a contract are distinct.
Transaction price
In determining the transaction price and estimates of variable consideration, management considers past history of
customer usage and capacity requirements, in estimating the goods and services to be provided to the customer. The
Corporation also considers the historical production levels and operating conditions for its variable generating assets.
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Notes to Consolidated Financial Statements
Allocation of transaction price to performance obligations
The Corporation’s contracts generally outline a specific amount to be invoiced to a customer associated with each
performance obligation in the contract. Where contracts do not specify amounts for individual performance obligations,
the Corporation estimates the amount of the transaction price to allocate to individual performance obligations based on
their standalone selling price, which is primarily estimated based on the amounts that would be charged to customers under
similar market conditions.
Satisfaction of performance obligations
The satisfaction of performance obligations requires management to use judgment as to when control of the underlying
good or service transfers to the customer. Determining when a performance obligation is satisfied affects the timing of
revenue recognition. Management considers both customer acceptance of the good or service, and the impact of laws and
regulations such as certification requirements, in determining when this transfer occurs. Management also applies
judgment in determining whether the invoice practical expedient can be relied upon in measuring progress toward complete
satisfaction of performance obligations. The invoice practical expedient permits recognition of revenue at the invoiced
amount, if that invoiced amount corresponds directly with the entity's performance to date.
II. Revenue from Other Sources
Lease revenue
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. 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 the Corporation retains 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.
Revenue from derivatives
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.
III. Revenue Recognition Policy in Prior Years
The majority of the Corporation’s revenues are derived from the sale of physical power, the 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.
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
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Notes to Consolidated Financial Statements
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.
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
B. Foreign Currency Translation
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.
I. Financial Instruments
Effective Jan. 1, 2018, the Corporation adopted IFRS 9. In accordance with the transition provisions of the standard, the
C. Financial Instruments and Hedges
Corporation has elected to not restate prior periods. Refer to section III below for information on its prior accounting policy.
The Corporation's accounting policies under IFRS 9 are outlined below.
Classification and Measurement
IFRS 9 introduces the requirement to classify and measure financial assets based on their contractual cash flow
characteristics and the Corporation’s business model for the financial asset. All financial assets and financial liabilities,
including derivatives, are recognized at fair value on the Consolidated Statements of Financial Position when the
Corporation becomes party to the contractual provisions of a financial instrument or non-financial derivative contract.
Financial assets must be classified and measured at either amortized cost, at fair value through profit or loss (“FVTPL”), or
at fair value through other comprehensive income (“FVTOCI”).
Financial assets with contractual cash flows arising on specified dates, consisting solely of principal and interest, and that
are held within a business model whose objective is to collect the contractual cash flows are subsequently measured at
amortized cost. Financial assets measured at FVTOCI are those that have contractual cash flows arising on specific dates,
consisting solely of principal and interest, and that are held within a business model whose objective is to collect the
contractual cash flows and to sell the financial asset. All other financial assets are subsequently measured at FVTPL.
Financial liabilities are classified as FVTPL when the financial liability is held for trading. All other financial liabilities are
subsequently measured at amortized cost.
The Corporation enters into a variety of derivative financial instruments to manage its exposure to commodity price risk,
interest rate risk, and foreign currency exchange risk, including fixed price financial swaps, long-term physical power sale
contracts, foreign exchange forward contracts and designating foreign currency debt as a hedge of net investments in
foreign operations.
Derivatives are initially recognized at fair value at the date the derivative contracts are entered into and are subsequently
remeasured to their fair value at the end of each reporting period. The resulting gain or loss is recognized in net earnings
immediately, unless the derivative is designated and effective as a hedging instrument, in which case the timing of the
recognition in net earnings is dependent on the nature of the hedging relationship.
Derivatives embedded in non-derivative host contracts that are not financial assets within the scope of IFRS 9 (e.g., financial
liabilities) are treated as separate derivatives when they meet the definition of a derivative, their risks and characteristics
are not closely related to those of the host contracts and the host contracts are not measured at FVTPL. Derivatives
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Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
embedded in hybrid contracts that contain financial asset hosts within the scope of IFRS 9 are not separated and the entire
contract is measured at either FVTPL or amortized cost, as appropriate.
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 are also derecognized when the Corporation has transferred its rights to receive cash flows from the asset
or has assumed an obligation to pay the received cash flows to a third party under a "pass-through" arrangement and either
transferred substantially all the risks and rewards of the asset, or transferred control of the asset. TransAlta will continue
to recognize the asset and any associated liability if TransAlta retains substantially all of the risks and rewards of the asset,
or retains control of the asset. Continuing involvement that takes the form of a guarantee over the transferred asset is
measured at the lower of the original carrying amount of the asset and the maximum amount of consideration that TransAlta
could be required to repay.
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.
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.
Impairment of Financial Assets
TransAlta recognizes an allowance for expected credit losses for financial assets measured at amortized cost as well as
certain other instruments. The loss allowance for a financial asset is measured at an amount equal to the lifetime expected
credit loss if its credit risk has increased significantly since initial recognition, or if the financial asset is a purchased or
originated credit-impaired financial asset. If the credit risk on a financial asset has not increased significantly since initial
recognition, its loss allowance is measured at an amount equal to the 12-month expected credit loss.
For trade receivables, lease receivables and contract assets recognized under IFRS 15, TransAlta applies a simplified
approach for measuring the loss allowance. Therefore, the Corporation does not track changes in credit risk but instead
recognizes a loss allowance at an amount equal to the lifetime expected credit losses at each reporting date.
The assessment of the expected credit loss is based on historical data and adjusted by forward-looking information.
Forward-looking information utilized includes third-party default rates over time, dependent on credit ratings.
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 relationship qualifies for hedge accounting if, at inception, it is formally designated and documented as a hedge, and the
hedging instrument and the hedged item have values that generally move in opposite direction because of the hedged risk.
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.
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.
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TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
For fair value hedges relating to items carried at amortized cost, any adjustment to carrying value is amortized through
profit or loss over the remaining term of the hedge using the effective interest rate ("EIR") method. The EIR amortization
may begin as soon as an adjustment exists and no later than when the hedged item ceases to be adjusted for changes in its
fair value attributable to the risk being hedged.
If the hedged item is derecognized, the unamortized fair value is recognized immediately in profit or loss.
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. The cash flow hedge reserve is adjusted to
the lower of the cumulative gain or loss on the hedging instrument and the cumulative change in fair value of the hedged
item.
If cash flow hedge accounting is discontinued, the amounts previously recognized in AOCI must remain in AOCI if the
hedged future cash flows are still expected to occur. Otherwise, the amount will be immediately reclassified to net earnings
as a reclassification adjustment. After discontinuation, once the hedged cash flow occurs, any amount remaining in AOCI
must be accounted for depending on the nature of the underlying transaction.
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.
III. Financial Instruments and Hedges Accounting Policy for Prior Years
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. Other 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. Other 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
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Notes to Consolidated Financial Statements
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.
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.
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.
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.
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 costs 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.
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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.
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.
Cash and cash equivalents are comprised of cash and highly liquid investments with original maturities of three months or
less.
D. Cash and Cash Equivalents
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
E. Collateral Paid and Received
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.
I. Fuel
The Corporation’s inventory balance is comprised of coal and natural gas used as fuel, which is measured at the lower of
F. Inventory
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 its 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, Materials and Supplies
Parts, materials and supplies are recorded at the lower of cost, measured at moving average costs, and net realizable value.
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
G. Property, Plant and Equipment
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
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Notes to Consolidated Financial Statements
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
2-12 years
2-30 years
3-60 years
3-30 years
2-12 years
2-30 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.
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
H. Intangible Assets
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.
Intangible assets are initially recognized at cost, which is comprised of all directly attributable costs necessary to create,
produce and prepare the intangible asset to be capable of operating in the manner intended by management.
Subsequent to initial recognition, intangible assets continue to be measured using the cost model, and are reported at cost
less accumulated amortization and impairment losses, if any. Amortization is included in depreciation and amortization
and fuel and purchased power in the Consolidated Statements of Earnings (Loss).
Amortization commences when the intangible asset is available for use, and is computed on a straight-line basis over the
intangible asset’s estimated useful life, except for coal rights, which are amortized using a unit-of-production basis, based
on the estimated mine reserves. Estimated useful lives of intangible assets may be determined, for example, with reference
to the term of the related contract or licence agreement. The estimated useful lives and amortization methods are reviewed
annually with the effect of any changes being accounted for prospectively.
Intangible assets consist of power sale contracts with fixed prices higher than market prices at the date of acquisition, coal
rights, software and intangibles under development. Estimated useful lives of intangible assets are as follows:
Software
Power sale contracts
2-7 years
5-20 years
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Notes to Consolidated Financial Statements
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.
I. Impairment of Tangible and Intangible Assets Excluding Goodwill
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 occur 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, if there has been an increase in the recoverable amount, the impairment
loss previously recognized is reversed. 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.
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
J. Goodwill
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.
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
K. Project Development Costs
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.
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
L. Income Taxes
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
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Notes to Consolidated Financial Statements
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.
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
M. Employee Future Benefits
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.
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.
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
N. Provisions
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.
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Notes to Consolidated Financial Statements
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.
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
O. Share-Based Payments
that vests in installments 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.
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
P. Emission Credits and Allowances
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.
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
Q. Assets Held for Sale
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.
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.
R. Leases
Power purchase arrangements (“PPA”) and other long-term contracts may contain, or may be considered, leases where the
fulfilment 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
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Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
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 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
S. Borrowing Costs
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.
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
T. Non-Controlling Interests
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.
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:
U. Joint Arrangements
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.
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
V. Government Incentives
item, it is recognized in net earnings over the same period in which the related costs or revenues are recognized. When the
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Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
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.
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.
W. Earnings per Share
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.
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
X. Business Combinations
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.
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
Y. Stripping Costs
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.
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
Z. Significant Accounting Judgments and Key Sources of Estimation Uncertainty
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:
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.
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Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
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 and 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 2016 to 2018 is found in Notes 7 and 18.
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 fulfilment 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.
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 11 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 14. 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
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Notes to Consolidated Financial Statements
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. 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. Information on the write-off of project
development costs is disclosed in Note 7(B).
VI. Provisions for Decommissioning and Restoration Activities
TransAlta recognizes provisions for decommissioning and restoration obligations as outlined in Note 2(N) and Note 21.
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.
VII. 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)(III).
VIII. Employee Future Benefits
The Corporation provides pension and other post-employment benefits, such as health and dental benefits, to employees.
The cost of providing these benefits is dependent upon many factors, including actual plan experience and estimates and
assumptions about future experience.
The liability for pension and post-employment benefits and associated costs included in annual compensation expenses
are impacted by estimates related to:
▪
employee demographics, including age, compensation levels, employment periods, the level of contributions made to
the plans and earnings on plan assets,;
the effects of changes to the provisions of the plans; and
changes in key actuarial assumptions, including rates of compensation and health-care cost increases, and discount
rates.
▪
▪
Due to the complexity of the valuation of pension and post-employment benefits, a change in the estimate of any one of
these factors could have a material effect on the carrying amount of the liability for pension and other post-employment
benefits or the related expense. These assumptions are reviewed annually to ensure they continue to be appropriate. See
Note 28 for disclosures on employee future benefits.
IX. 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 21 with respect to other provisions.
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TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
3. Accounting Changes
I. IFRS 15 Revenue from Contracts with Customers
A. Current Accounting Changes
In May 2014, the IASB issued IFRS 15 Revenue from Contracts with Customers ("IFRS 15"), 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.
The Corporation has adopted IFRS 15 with an initial adoption date of Jan. 1, 2018. As a result, the Corporation has changed
its accounting policy for revenue recognition, which is outlined in Note 2(A).
The Corporation has elected to adopt IFRS 15 retrospectively with the modified retrospective method of transition
practical expedient and has elected to apply IFRS 15 only to contracts that are not completed contracts at the date of initial
application. Comparative information has not been restated and is reported under IAS 18 Revenue ("IAS 18"), which is
outlined in Note 2(A)(iii).
The Corporation recognized the cumulative impact of the initial application of the standard in the deficit as at Jan. 1, 2018.
Applying the significant financing component requirements to a specific contract resulted in an increase to the contract
liability of $17 million, a decrease in deferred income tax liabilities of $4 million and an increase to the deficit of $13 million.
IFRS 15 requires that, in determining the transaction price, the promised amount of consideration is to be adjusted for the
effects of the time value of money if the timing of payments specified in a contract provides either party with a significant
benefit of financing the transfer of goods or services to the customer (“significant financing component”). The objective
when adjusting the promised amount of consideration for a significant financing component is to recognize revenue at an
amount that reflects the price that the customer would have paid, had they paid cash in the future when the goods or
services are transferred to them. The application of the significant financing component requirement results in the
recognition of interest expense over the financing period and a higher amount of revenue.
Additionally, the Corporation no longer recognizes revenue (or fuel costs) related to non-cash consideration for natural
gas supplied by a customer at one of its gas plants , as it was determined under IFRS 15 that the Corporation does not obtain
control of the customer-supplied natural gas.
Refer to the discussion in Note 2(A) and in Note 5 for a breakdown of the Corporation's revenues from contracts with
customers and revenues from other sources.
The following tables summarize the financial statement line items impacted by adopting IFRS 15 as at and for the year
ended Dec. 31, 2018:
Condensed Consolidated Statement of Earnings (Loss)
Year ended Dec. 31, 2018
Revenues
Fuel, carbon costs and purchased power
Net interest expense
Net earnings impact
Reported in accordance
with IAS 18 and IAS 11
Adjustments As reported under IFRS 15
2,253
(1,109)
(243)
(88)
(4)
9
(7)
(2)
2,249
(1,100)
(250)
(90)
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TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
Condensed Consolidated Statements of Financial Position
As at Dec. 31, 2018
Deferred income tax liabilities
Contract liability
Deficit
Reported in accordance
with IAS 18 and IAS 11
Adjustments As reported under IFRS 15
505
68
(1,481)
(4)
19
(15)
501
87
(1,496)
There were no impacts to the statement of cash flows as a result of adopting IFRS 15.
II. IFRS 9 Financial Instruments
Effective Jan. 1, 2018, the Corporation adopted IFRS 9, which introduces new requirements for:
▪
▪
▪
the classification and measurement of financial assets and liabilities;
the recognition and measurement of impairment of financial assets; and
general hedge accounting.
In accordance with the transition provisions of the standard, the Corporation has elected to not restate prior periods. The
impact of adopting IFRS 9 was recognized in the deficit at Jan. 1, 2018. While the Corporation had no direct impact of
adopting IFRS 9, a $1 million increase in the deficit resulted from the increase in equity attributable to non-controlling
interests due to IFRS 9 impacts at TransAlta Renewables Inc. ("TransAlta Renewables").
The Corporation's accounting policies under IFRS 9 are outlined in Note 2(C) and the key impacts are outlined below. For
more information on the Corporation's accounting policies under IAS 39 for the period ended Dec. 31, 2017, refer to note
2 of the Corporation’s 2017 annual consolidated financial statements.
a. Classification and Measurement
IFRS 9 introduces the requirement to classify and measure financial assets based on their contractual cash flow
characteristics and the Corporation’s business model for the financial asset. All financial assets and financial liabilities,
including derivatives, are recognized at fair value on the Consolidated Statements of Financial Position when the
Corporation becomes party to the contractual provisions of a financial instrument or non-financial derivative contract.
Financial assets must be classified and measured at either amortized cost, at FVTPL, or at FVTOCI. Refer to Note 2 (C) for
further details.
The Corporation’s management reviewed and assessed the classifications of its existing financial instruments as at Jan. 1,
2018, based on the facts and circumstances that existed at that date, as shown below. None of the reclassifications had a
significant impact on the Corporation’s financial position, earnings (loss), other comprehensive income (loss) or total
comprehensive income (loss) after the date of initial application.
Financial instrument
Cash and cash equivalents
Restricted cash
Trade and other receivables
Long-term portion of finance lease receivables
Loan receivable (other assets)
Risk management assets (current and long-term) -
derivatives held for trading
Risk management assets (current and long-term) -
derivatives designated as hedging instruments
Accounts payable and accrued liabilities
Dividends payable
Risk management liabilities (current and long-term) -
derivatives held for trading
Risk management liabilities (current and long-term) -
derivatives designated as hedging instruments
IAS 39 category
IFRS 9 classification
Loans and receivables
Loans and receivables
Loans and receivables
Loans and receivables
Loans and receivables
Held for trading
Derivatives designated as
hedging instruments
Other financial liabilities
Other financial liabilities
Held for trading
Derivatives designated as
hedging instruments
Amortized cost
Amortized cost
Amortized cost
Amortized cost
Amortized cost
FVTPL
FVOCI
Amortized cost
Amortized cost
FVTPL
FVOCI
Credit facilities and long-term debt
Other financial liabilities
Amortized cost
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Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
b. Impairment of Financial Assets
IFRS 9 introduces a new impairment model for financial assets measured at amortized cost as well as certain other
instruments. The expected credit loss model requires entities to account for expected credit losses on financial assets at
the date of initial recognition, and to account for changes in expected credit losses at each reporting date to reflect changes
in credit risk.
The Corporation’s management reviewed and assessed its existing financial assets for impairment using reasonable and
supportable information in accordance with the requirements of IFRS 9 to determine the credit risk of the respective items
at the date they were initially recognized, and compared that to the credit risk as at Jan. 1, 2018. There were no significant
increases in credit risk determined upon application of IFRS 9 and no loss allowance was recognized.
c. General Hedge Accounting
IFRS 9 retains the three types of hedges from IAS 39 (fair value hedges, cash flow hedges and hedges of a net investment
in a foreign operation), but increases flexibility as to the types of transactions that are eligible for hedge accounting.
The effectiveness test of IAS 39 is replaced by the principle of an “economic relationship”, which requires that the hedging
instrument and the hedged item have values that generally move in opposite direction because of the hedged risk.
Additionally, retrospective hedge effectiveness testing is no longer required under IFRS 9.
In accordance with IFRS 9’s transition provisions for hedge accounting, the Corporation has applied the IFRS 9 hedge
accounting requirements prospectively from the date of initial application on Jan. 1, 2018, and comparative figures have
not been restated. The Corporation’s qualifying hedging relationships under IAS 39 in place as at Jan. 1, 2018 also qualified
for hedge accounting in accordance with IFRS 9, and were therefore regarded as continuing hedging relationships. No
rebalancing of any of the hedging relationships was necessary on Jan. 1, 2018. As the critical terms of the hedging
instruments match those of their corresponding hedged items, all hedging relationships continue to be effective under
IFRS 9’s effectiveness assessment. The Corporation has not designated any hedging relationships under IFRS 9 that would
not have met the qualifying hedge accounting criteria under IAS 39. Further details of the Corporation's hedging activities
are disclosed in Notes 14 and 15.
The Corporation’s risk management objective and strategy, including risk management instruments and their key terms,
are detailed in Notes 15A and 15C.
In certain cases, the Corporation purchases non-financial items in a foreign currency, for which it may enter into forward
contracts to hedge foreign currency risk on the anticipated purchases. Both IAS 39 and IFRS 9 require hedging gains and
losses to be basis adjusted to the initial carrying amount of non-financial hedged items once recognized (such as PP&E),
but under IFRS 9, these adjustments are no longer considered reclassification adjustments and do not affect OCI. Under
IFRS 9, these amounts will be directly transferred to the asset and will be reflected in the statement of changes in equity
as a reclassification from AOCI.
The application of IFRS 9 hedge accounting requirements has no other impact on the results and financial position of the
Corporation for the current or prior years.
III. Change in Estimates - Useful Lives
As a result of the Off-Coal Agreement (“OCA”) with the Government of Alberta described in Note 4(O), the Corporation
has adjusted the useful lives of some of its mine assets to align with the Corporation's coal-to-gas conversion plans. In
addition, on Jan. 1, 2017, the useful lives of the PP&E and amortizable intangibles associated with some of the Corporation’s
Alberta coal assets were reduced to 2030. As a result, depreciation expense and intangibles amortization for the year ended
Dec. 31, 2018, increased by approximately $38 million (2017 - $58 million). The useful lives may be revised or extended in
compliance with the Corporation’s accounting policies, dependent upon future operating decisions and events, such as
coal-to-gas conversions.
Due to the Corporation’s decision to retire Sundance Unit 1 effective Jan. 1, 2018 (see Note 4(A) for further details), the
useful lives of the Sundance Unit 1 PP&E and amortizable intangibles were reduced in the second quarter of 2017 by two
years to Dec. 31, 2018. As a result, depreciation expense and intangibles amortization for the year ended Dec. 31, 2017,
increased by approximately $26 million.
Since Sundance Unit 1 was shut down two years early, the Canadian federal Minister of Environment & Climate Change
agreed to extend the life of Sundance Unit 2 from 2019 to 2021. As such, during the third quarter of 2017, the Corporation
extended the life of Sundance Unit 2 to 2021 (see Note 4(A) for further details). As a result, depreciation expense and
intangibles amortization for the year ended Dec. 31, 2017, decreased in total by approximately $4 million. However, in the
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TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
third quarter of 2018, the Corporation retired Sundance Unit 2 and recorded an impairment loss for the remaining net
book value of the asset (see Note 4(A) and Note 7 for further details).
Accounting standards that have been previously issued by the IASB, but are not yet effective and have not been applied
by the Corporation include IFRS 16 Leases. In January 2016, the IASB issued IFRS 16 Leases, which replaces the current
B. Future Accounting Changes
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. In
addition, the nature and timing of expenses related to leases will change, as IFRS 16 replaces the straight-line operating
leases expense with the depreciation expense for the assets and interest expense on the lease liabilities. For lessors, the
accounting remains essentially unchanged.
IFRS 16 is effective for annual periods beginning on or after Jan. 1, 2019. The standard is required to be adopted either
retrospectively or using a modified retrospective approach. On transition, TransAlta has elected to apply IFRS 16 using the
modified retrospective approach effective Jan. 1, 2019. In applying IFRS 16 for the first time, the Corporation has used the
following practical expedients permitted by the standard:
▪
Exemption for short-term leases that have a remaining lease term of less than 12 months as at Jan. 1, 2019 and low
value leases;
Excluding initial direct costs for the measurement of the right-of-use asset at the date of initial application;
Using hindsight in determining the lease term where the contract contains options to extend or terminate the lease;
Adjusting the right-of-use assets by the amount of IAS 37 onerous contract provision immediately before the date of
initial application; and
▪
▪
▪
▪ Measuring the right-of-use assets at an amount equal to the lease liability, adjusted by the amount of any prepaid or
accrued lease payments relating to that lease recognized in the statement of financial position immediately before
the date of initial application.
The Corporation has substantially completed its assessment of existing operating leases. The Corporation estimates that
we will recognize right-of-use lease assets and related lease liabilities for existing operating leases where we are the lessee
in the range of $42 million to $52 million. These changes will be partially offset by the derecognition of a finance lease asset
and a finance lease liability related to a contractual arrangement that was accounted for as a finance lease under IAS 17
but is no longer considered a lease under IFRS 16.
Certain comparative figures have been reclassified to conform to the current period’s presentation. These reclassifications
did not impact previously reported net earnings.
C. Comparative Figures
4. Significant Events
I. Alberta Renewable Energy Program Project - Windrise
In the fourth quarter of 2018, TransAlta's 207 MW Windrise wind project was selected by the Alberta Electric System
A. Transition to Clean Power in Alberta
Operator ("AESO") as one of the three successful projects in the third round of the Renewable Electricity Program. The
Windrise facility, which is in the county of Willow Creek, is underpinned by a 20-year Renewable Electricity Support
Agreement with the AESO. The project is expected to cost approximately $270 million and is targeted to reach commercial
operation during the second quarter of 2021.
II. Gas Supply for Coal-to-Gas Conversions
On Dec. 17, 2018, the Corporation exercised its option to acquire 50 percent ownership in the Pioneer gas pipeline
("Pioneer Pipeline"). Tidewater Midstream and Infrastructure Ltd. ("Tidewater") will construct and operate the 120 km
natural gas pipeline, which will have an initial throughput of 130 MMcf/d with the potential to expand to approximately
440 MMcf/d. The Pioneer Pipeline will allow TransAlta to increase the amount of natural gas it co-fires at its Sundance and
Keephills coal-fired units, resulting in lower carbon emissions and costs. As well, the Pioneer Pipeline will provide a
significant amount of the gas required for the full conversion of the coal units to natural gas. The investment for TransAlta
will amount to approximately $90 million. Construction of the pipeline commenced in November 2018 and the Pioneer
Pipeline is expected to be fully operational by the second half of 2019. TransAlta’s investment is subject to final regulatory
approvals, which are expected to be received in the first half of 2019.
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TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
The decision to work with Tidewater advances the time frame for the construction of the Pioneer Pipeline and permits the
acceleration of plant conversions. TransAlta remains of the view that having at least two pipelines supplying natural gas
would reduce operational risks and continues to advance discussions with other parties to construct additional pipelines
to meet the remaining gas supply requirements for the facilities.
III. Sundance and Keephills Units 1 and 2 Coal-to-Gas Conversion Strategy
On Dec. 6, 2017, the Corporation updated its strategy to accelerate its transition to gas and renewables generation. During
2018, the Corporation mothballed and retired the following Sundance Units:
▪
▪
▪
▪
retired Sundance Unit 1 on Jan. 1, 2018;
retired Sundance Unit 2 on July 31, 2018;
temporarily mothballed Sundance Unit 3 on April 1, 2018, for a period of up to two years; and
temporarily mothballed Sundance Unit 5 on April 1, 2018, for a period of up to one year, which has now been extended
to two years.
TransAlta is no longer planning to temporarily mothball Sundance Unit 4 and will perform maintenance during the first half
of 2019.
On December 18, 2018, the federal government published the Regulations Limiting Carbon Dioxide Emissions from Natural
Gas-fired Generation of Electricity. The regulations provide rules for new gas-fired electricity facilities, as well as specific
provisions for coal-to-gas conversions. In addition to extending their operating lives, the benefits of converting units to gas
generation include: significantly lowering carbon emissions and costs; significantly lowering operating and sustaining
capital costs; and increasing operating flexibility. TransAlta expects to convert some or all of its Sundance Units 3 to 6 and
Keephills Units 1 to 3 in the 2020 to 2023 period.
IV. Sundance Units 1 and 2
Canadian federal regulations stipulate that all coal plants built before 1975 must cease to operate on coal by the end of
2019, which includes Sundance Units 1 and 2. Given that Sundance Unit 1 was shut down two years early, the federal
Minister of Environment & Climate Change agreed to extend the life of Sundance Unit 2 from 2019 to 2021. This provided
the Corporation with the flexibility to respond to the regulatory environment for coal-to-gas conversions and the new
upcoming Alberta capacity market. However, in July 2018, TransAlta retired Sundance Unit 2. This decision was driven
largely by Sundance Unit 2's age, size and short useful life relative to other units, and the capital requirements needed to
return the unit to service.
Sundance Units 1 and 2 collectively made up 560 MW of the 2,141 MW capacity of the Sundance power plant, which serves
as a baseload provider for the Alberta electricity system. The PPA with the Balancing Pool relating to Sundance Units 1
and 2 expired on Dec. 31, 2017.
In the third quarter of 2018, the Corporation recognized an impairment charge of $38 million ($28 million after-tax) relating
to the retirement of Sundance Unit 2. During the second quarter of 2017, the Corporation recognized an impairment charge
on Sundance Unit 1 of $20 million ($15 million after-tax) due to the Corporation’s decision to early retire Sundance Unit
1. See Note 7 for further details.
During 2017, a subsidiary of TransAlta Renewables, Kent Hills Wind LP ("KHWLP"), entered into a long-term contract with
New Brunswick Power Corporation (“NB Power”) for the sale of all power generated by an additional 17.25 MW of capacity
B. Kent Hills 3 Wind Project
from the Kent Hills 3 expansion wind project. At the same time, the term of the Kent Hills 1 contract with NB Power was
extended from 2033 to 2035, matching the life of the Kent Hills 2 and Kent Hills 3 wind projects.
On Oct. 19, 2018, TransAlta Renewables announced that the expansion is fully operational, bringing total generating
capacity of the Kent Hills wind farm to 167 MW.
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TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
On Feb. 20, 2018, TransAlta Renewables announced it had entered into an arrangement to acquire two construction-ready
projects in the Northeastern United States. The wind development projects consist of: i) a 90 MW project located in
C. Acquisition of Two US Wind Projects
Pennsylvania that has a 15-year PPA with Microsoft Corp. ("Big Level"), and ii) a 29 MW project located in New Hampshire
with two 20-year PPAs ("Antrim") (collectively, the "US Wind Projects"), with counterparties that have Standard & Poor's
credit ratings of A+ or better. The commercial operation date for both projects is expected during the second half of 2019.
A subsidiary of TransAlta acquired Big Level on Feb. 20, 2018,and the acquisition of Antrim remains subject to certain
closing conditions, including the receipt of a favourable regulatory ruling. The Corporation expects the Antrim acquisition
to close in early 2019.
On April 20, 2018, TransAlta Renewables completed the acquisition of an economic interest in the US Wind Projects from
a subsidiary of TransAlta (“TA Power”). Pursuant to the arrangement, a TransAlta subsidiary owns the US Wind Projects
directly and TA Power issued to TransAlta Renewables tracking preferred shares that pay quarterly dividends based on
the pre-tax net earnings of the US Wind Projects. The tracking preferred shares have preference over the common shares
of TA Power held by TransAlta, in respect of dividends and the distribution of assets in the event of the liquidation,
dissolution or winding-up of TA Power. The construction and acquisition costs of the two US Wind Projects are expected
to be funded by TransAlta Renewables and a $25 million promissory note receivable and are estimated to be US$240
million. TransAlta Renewables will fund these costs either by acquiring additional preferred shares issued by TA Power or
by subscribing for interest-bearing notes issued by the project entity. The proceeds from the issuance of such preferred
shares or notes will be used exclusively in connection with the acquisition and construction of the US Wind Projects.
TransAlta Renewables expects to fund these acquisition and construction costs using its existing liquidity and tax equity.
During the year ended Dec. 31, 2018, TransAlta Renewables funded approximately $61 million (US$48 million) of
construction costs. On Jan. 2, 2019, TransAlta Renewables funded an additional $45 million (US$33 million) of construction
costs.
On May 31, 2018, TransAlta Renewables acquired from a subsidiary of the Corporation an economic interest in the 50 MW
Lakeswind wind farm in Minnesota and 21 MW of solar projects located in Massachusetts ("Mass Solar") through the
D. TransAlta Renewables Acquires Three Renewable Assets from the Corporation
subscription of tracking preferred shares of a subsidiary of the Corporation. In addition, TransAlta Renewables acquired
from a subsidiary of the Corporation ownership of the 20 MW Kent Breeze wind farm located in Ontario. The total purchase
price for the three assets was approximately $166 million, including the assumption of $62 million of tax equity obligations
and project debt, for net cash consideration of $104 million. The Corporation continues to operate these assets on behalf
of TransAlta Renewables.
The acquisition of Kent Breeze 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 assets and liabilities
acquired were recognized at the book values previously recognized by TransAlta at May 31, 2018, 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 $1
million in 2018.
On June 28, 2018, TransAlta Renewables subscribed for an additional $33 million of tracking preferred shares of a
subsidiary of the Corporation related to Mass Solar, to fund the repayment of Mass Solar's project debt.
In connection with these acquisitions, the Corporation recorded a $12 million impairment charge, of which $11 million was
recorded against PP&E and $1 million against intangibles. See Note 7 for further details.
On June 22, 2018, TransAlta Renewables closed a bought deal offering of 11,860,000 common shares through a syndicate
of underwriters (the "Offering"). The common shares were issued at a price of $12.65 per common share for gross proceeds
E. TransAlta Renewables Closes $150 Million Offering of Common Shares
of approximately $150 million ($144 million of net proceeds).
The net proceeds were used to partially repay drawn amounts under TransAlta Renewables' credit facility, which was drawn
in order to fund recent acquisitions. The additional liquidity under the credit facility is to be used for general corporate
purposes, including ongoing construction costs associated with the US Wind Projects, described in 4(C) above.
The Corporation did not purchase any additional common shares under the Offering and, following the closing, owned 161
million common shares, representing approximately 61 per cent of the outstanding common shares of TransAlta
Renewables. See Note 12 for further details of TransAlta's ownership of TransAlta Renewables.
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TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
On July 20, 2018, the Corporation monetized the payments under the OCA with the Government of Alberta by closing a
$345 million bond offering through its indirect wholly owned subsidiary, TransAlta OCP LP ("TransAlta OCP"). The offering
F. $345 Million Financing
was a private placement that was secured by, among other things, a first ranking charge over the OCA payments payable
by the Government of Alberta. The amortizing bonds bear interest at a rate of 4.509 per cent per annum, payable semi-
annually and maturing on Aug. 5, 2030. The bonds have a rating of BBB, with a Stable trend, by DBRS. Under the terms of
the OCA, the Corporation receives annual cash payments on or before July 31 of approximately $40 million (approximately
$37 million, net to the Corporation), commencing Jan. 1, 2017, and terminating at the end of 2030.
The net proceeds were used to partially repay the 6.40 per cent debentures, as described below.
On Aug. 2, 2018, the Corporation early redeemed all of its then outstanding 6.40 per cent debentures, due Nov. 18, 2019,
for the principal amount of$400 million. The redemption price was approximately $425 million in aggregate, including a
G. Early Redemption of $400 Million of Debentures
prepayment premium and accrued and unpaid interest. See Note 22 for further details.
On March 9, 2018 the Corporation announced that the Toronto Stock Exchange ("TSX") accepted the notice filed by the
Corporation to implement a normal course issuer bid ("NCIB") for a portion of its common shares. Pursuant to the NCIB, the
H. Normal Course Issuer Bid
Corporation may repurchase up to a maximum of 14,000,000 common shares, representing approximately 4.86 per cent
of issued and outstanding common shares as at March 2, 2018. Purchases under the NCIB may be made through open
market transactions on the TSX and any alternative Canadian trading platforms on which the common shares are traded,
based on the prevailing market price. Common shares purchased under the NCIB are cancelled.
The period during which TransAlta is authorized to make purchases under the NCIB commenced on March 14, 2018, and
ends on March 13, 2019, or such earlier date on which the maximum number of common shares are purchased under the
NCIB or the NCIB is terminated at the Corporation's election.
Under TSX rules, not more than102,039 common shares (being 25 per cent of the average daily trading volume on the TSX
of 408,156 common shares for the six months ended February 28, 2018) can be purchased on the TSX on any single trading
day under the NCIB, with the exception that one block purchase in excess of the daily maximum is permitted per calendar
week.
During the year ended Dec. 31, 2018, the Corporation purchased and cancelled 3,264,500 common shares at an average
price of $7.02 per common share, for a total cost of $23 million. See Note 24 for further details. Further transactions, if
any, under the NCIB will depend on market conditions. The Corporation retains discretion whether to make purchases
under the NCIB, and to determine the timing, amount and acceptable price of any such purchases, subject at all times to
applicable TSX and other regulatory requirements.
On March 15, 2018, the Corporation early redeemed all of its outstanding 6.650 per cent US $500 million senior notes due
May 15, 2018, for approximately $617 million (US$516 million). A $5 million early redemption premium was recognized
I. Early Redemption of Senior Notes
in net interest expense. See Note 22 for further details.
On Sept 18. 2017, the Corporation received formal notice from the Balancing Pool for the termination of the Sundance B
and C PPAs effective March 31, 2018.
J. Balancing Pool Provides Notice to Terminate the Alberta Sundance Power Purchase Arrangements
This announcement was expected and the Corporation took steps to re-take dispatch control for the units effective March
31, 2018. Pursuant to a written agreement, the Balancing Pool paid the Corporation approximately $157 million on March
29, 2018. The Corporation is disputing the termination payment it received. The Balancing Pool excluded certain mining
assets that the Corporation believes should be included in the net book value calculation for an additional termination
payment of $56 million. The dispute is currently proceeding through the PPA arbitration process.
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TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
K. Notice of Termination of South Hedland Power Purchase Agreement from Fortescue Metals Group
On Nov. 13, 2017, the Corporation announced that TEC Hedland Pty Ltd ("TEC Hedland"), a subsidiary of the Corporation,
received formal notice of termination of the South Hedland Power Purchase Agreement ("South Hedland PPA") from a
Limited
subsidiary of Fortescue Metals Group Limited ("FMG"). The South Hedland PPA allows FMG to terminate the agreement
if the power station has not reached commercial operation within a specified time period. FMG continues to be of the view
that South Hedland Power Station has yet to achieve commercial operation.
The Corporation believes that all conditions required to establish commercial operations, including all performance
conditions, have been achieved under the terms of the South Hedland PPA. These conditions include receiving a commercial
operation certificate, successfully completing and passing certain test requirements, and obtaining all permits and
approvals required from the North West Interconnected System and government agencies. Confirmation of commercial
operation has been provided by independent engineering firms, as well as by Horizon Power, the state-owned utility. The
Corporation is taking all steps necessary to protect its interests in the facility and ensure all cash flows promised under the
South Hedland PPA are realized. The South Hedland Power Station has been fully operational and able to meet FMG’s
requirements under the terms of the South Hedland PPA since July 2017.
TEC Hedland commenced proceedings in the Supreme Court of Western Australia on Dec. 4, 2017, to recover amounts
invoiced under the South Hedland PPA.
On Aug. 1, 2017, the Corporation received notice of FMG’s intention to repurchase the Solomon Power Station from TEC
Pipe Pty Ltd. ("TEC Pipe"), a wholly owned subsidiary of the Corporation, for approximately US$335 million. FMG
L. Re-acquisition of Solomon Power Station
completed its acquisition of the Solomon Power Station on Nov. 1, 2017, and TEC Pipe received US$325 million as
consideration. FMG has held back the balance from the purchase price. It is the Corporation’s view that this should not
have been held back and the Corporation is taking action in the Supreme Court of Western Australia to recover all, or a
significant portion of, this amount from FMG.
M. TransAlta Renewables' $260-Million Project Financing of New Brunswick Wind Assets and Early
On Oct. 2, 2017, TransAlta Renewables announced that its indirect majority-owned subsidiary, KHWLP, closed an
approximate $260 million bond offering, secured by, among other things, a first ranking charge over all assets of KHWLP.
Redemption of Outstanding Debentures
The bonds are amortizing and bear interest at a rate of 4.454 per cent, payable quarterly, and mature on Nov. 30, 2033. A
portion of the net proceeds was used to fund a portion of the construction costs for the 17.25 MW Kent Hills 3 wind project.
The remaining proceeds were advanced to its subsidiary Canadian Hydro Developers, Inc. ("CHD") and to Natural Forces
Technologies Inc., KHWLP’s partner, which owns approximately 17 per cent of KHWLP. Proceeds of $31 million are
classified as restricted cash as at Dec. 31, 2018, relating to the construction reserve account, and will be released upon
certain conditions being met, which are expected to be finalized in Q1 2019.
At the same time, CHD, a wholly owned subsidiary of TransAlta Renewables, provided notice that it would be early
redeeming all of its unsecured debentures. The debentures were scheduled to mature in June 2018. On Oct. 12, 2017,
CHD redeemed the unsecured debentures for $201 million, which included the principal of $191 million, an early
redemption premium of $6 million and accrued interest of $4 million. The $6 million early redemption premium was
recognized in net interest expense for the year ended Dec. 31, 2017.
On Sept. 17, 2017, the Corporation announced that the minimum election notices received did not meet the requirements
to give effect to the conversion of its Series E Preferred Shares into Series F Preferred Shares. As a result, none of the Series
N. Series E and C Preferred Share Conversion Results and Dividend Rate Reset
E Preferred Shares were converted into Series F Preferred Shares on Sept. 30, 2017, and the dividend rate remains fixed
for the subsequent five-year period. See Note 25 for further details.
On June 16, 2017, the Corporation announced that the minimum election notices received did not meet the requirements
to give effect to the conversion of its Series C Preferred Shares into the Series D Preferred Shares. As a result, none of the
Series C Preferred Shares were converted into Series D Preferred Shares on June 30, 2017, and the dividend remains fixed
for the subsequent five-year period. See Note 25 for further details.
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TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
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
O. Alberta Off-Coal Agreement
Sheerness coal-fired plants on or before Dec. 31, 2030.
Under the terms of the OCA, the Corporation will receive annual cash payments of approximately $37 million, net to the
Corporation, commencing in 2017 and terminating in 2030. Receipt of the payments is subject to certain terms and
conditions. The OCA’s main condition is the cessation of all coal-fired emissions on or before Dec. 31, 2030. Other
conditions include: maintaining prescribed spending on investment and investment-related activities in Alberta;
maintaining a significant business presence
(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.
in Alberta
The Corporation also 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.
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,
P. Force Majeure Relief - Keephills 1
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
in 2016. The buyer and the Balancing Pool are seeking to set the arbitration panel’s decision aside in the Court of Queen’s
Bench of Alberta. This application is scheduled to be heard from Feb. 27, 2019 to Mar. 1, 2019.
On Dec. 7, 2016, the Corporation announced that its indirect wholly owned subsidiary, TAPC Holdings LP, which holds the
Corporation’s interest in the Poplar Creek cogeneration facility, completed the private placement of a $202.5 million
Q. Poplar Creek Financing
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 of 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.
On Dec. 22, 2016, the Corporation announced it had signed the Non-Utility Generator Contract (the "NUG Contract") with
the Ontario Independent Electricity System Operator (the “IESO”) for its Mississauga cogeneration facility. The NUG
R. Mississauga Cogeneration Facility NUG Contract
Contract was 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 in December 2018. In December 2018, TransAlta exercised its option to terminate
its agreement with Boeing Canada Inc. effective Dec. 31, 2021. TransAlta is required to remove the plant and restore the
site within the three-year time frame.
The NUG Contract provided the Corporation with fixed monthly payments until Dec. 31, 2018, with no delivery obligations.
Further details on the NUG Contract and its impact to these financial statements can be found in Note 9(C).
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
S. Wintering Hills Assets Held for Sale
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 recorded an impairment charge of $28 million in 2016, included in the Wind and Solar
segment. Wintering Hills was sold on March 1, 2017, for net proceeds to the Corporation of $61 million.
F35
TRANSALTA CORPORATION F35
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
On June 3, 2016, TransAlta Renewables' indirect wholly owned 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
T. Project Financing of a Quebec Wind Asset by TransAlta Renewables
bonds are amortizing and bear interest at a rate of 3.963 per cent, payable semi-annually, and mature on June 30, 2032.
U. Investment in, and Acquisition by, TransAlta Renewables of the Sarnia Cogeneration Plant, Le
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
Nordais Wind Farm and Ragged Chute Hydro Facility (the “ Canadian Assets” )
of approximately 611 MW of highly contracted power generation assets located in Ontario and Québec.
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.
On Nov. 9, 2017, TransAlta Renewables repaid the debentures early, for $218 million in total, comprised of principal of
$215 million and accrued interest of $3 million. The convertible debenture was scheduled to mature on Dec. 31, 2020.
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 in 2016.
F36
TRANSALTA CORPORATION F36
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
5. Revenue
The majority of the Corporation's revenues are derived from the sale of physical power, capacity and green attributes,
leasing of power facilities, and from energy marketing and trading activities, which the Corporation disaggregates into the
A. Disaggregation of Revenue
following groups for the purpose of determining how economic factors affect the recognition of revenue.
Canadian
Coal
US
Coal
Canadian
Gas
Australian
Gas
Wind and
Energy
Solar Hydro
Marketing Corporate
Total
Year ended Dec. 31, 2018
Revenues from contracts with
customers
Revenue from leases(1)
Revenue from derivatives
Government incentives
Revenue from other(2)
517
68
9
—
(1) 115
—
—
328
318
224
—
4
—
4
91
68
—
—
6
206
27
(20)
16
53
282
132
7
—
—
17
156
Total revenue
912
442
232
165
Revenues from contracts with customers
Timing of revenue recognition
At a point in time
Over time
Total revenue from contracts
with customers
38
479
517
9
—
9
—
224
224
—
91
91
18
188
—
132
206
132
—
—
67
—
—
67
—
—
—
— 1,179
—
—
—
170
165
16
(7)
719
(7) 2,249
—
65
— 1,114
— 1,179
(1) Total rental income, including contingent rent related to certain PPAs and other long-term contracts that meet the criteria of operating leases. 2017 - $247 million,
2016 - $221 million.
(2) Includes merchant revenue and other miscellaneous.
The Corporation has recognized the following revenue-related contract assets and liabilities:
B. Contract Balances
Contract liabilities
Dec. 31, 2017
IFRS 15 transition adjustment
Amounts transferred to revenue included in opening balance
Consideration received
Increases due to interest accrued and expensed during the period
Amounts transferred to payables
Dec. 31, 2018
62
17
(10)
13
6
(1)
87
Contract liabilities are primarily comprised of consideration received from the Corporation’s Keephills Unit 3 joint
operation partner for which the Corporation has a future obligation to transfer goods and services to the partner under
the contract. Consideration received is dependent upon the Corporation’s mine capital replacement plan and revenue is
recognized as the Corporation satisfies its performance obligations under the contract of being available to deliver coal
and the delivery of coal.
As required by the new revenue standard, the Corporation is required to disclose the aggregate amount of the transaction
price allocated to remaining performance obligation (contract revenues that have not yet been recognized) for contracts
C. Remaining Performance Obligations
in place at the end of the reporting period. The following disclosures exclude revenues related to contracts that qualify for
the following practical expedients:
▪
The Corporation recognizes revenue from the contract in an amount that is equal to the amount invoiced where the
amount invoiced represents the value to the customer of the service performed to date. Certain of the Corporation’s
contracts at some of its wind, hydro, gas and solar facilities, and within its commercial and industrial business, qualify
F37
TRANSALTA CORPORATION F37
TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
for this practical expedient. For these contracts, the Corporation is not required to disclose information about the
remaining unsatisfied performance obligations.
Contracts with an original expected duration of less than 12 months.
▪
Additionally, in many of the Corporation’s contracts, elements of the transaction price are considered constrained, such as
for variable revenues dependent upon future production volumes that are driven by customer or market demand or market
prices that are subject to factors outside the Corporation’s influence. Future revenues that are related to constrained
variable consideration are not included in the disclosure of remaining performance obligations until the constraints are
resolved. Further, adjustments to revenue to recognize a significant financing component in a contract are not included in
the amounts disclosed for remaining performance obligations.
As a result, the amounts of future revenues disclosed below represent only a portion of future revenues that are expected
to be realized by the Corporation from its contractual portfolio.
Canadian Coal
At Dec. 31, 2018, the Corporation has PPAs with the Balancing Pool for capacity and electricity from two of its coal plants,
as dispatched, with contract end dates of Dec. 31, 2020. All generation produced is delivered to the customer. Certain
sources of revenue under one PPA contract are accounted for as a lease, and are excluded from these disclosures. Pricing
is comprised of multiple components, of both fixed and variable nature, consisting of a capacity payment based on a return
of capital, availability payments (from or to the customer) based on the 30-day rolling average pool price and actual
availability of the plant as compared to targeted availability specified in the PPAs, recovery of regulatory pass-through
costs, and payments for delivery of energy based on the variable cost of producing the energy. Energy-related payments
are variable depending on output from the plant, which is dependent upon market demand and the operational ability of
the plant. Revenues are generally recognized over time, on a monthly basis. Future revenues that are based upon variable
consideration are considered to be fully constrained and are excluded from these disclosures.
The Corporation also has several contracts for sale of byproducts of coal combustion from certain of its coal plants. The
contracts range in duration from one to three years. Generally, revenues vary based on market prices that are subject to
factors outside of the Corporation’s control, and the quantities delivered and sold, which are ultimately dependent upon
customer demand. These variable revenues are considered to be fully constrained, and will be recognized at a point in time
as the performance obligation, the delivery of byproducts, is satisfied. Accordingly, these revenues are excluded from these
disclosures.
The Corporation has a contract at its Alberta coal mine that requires it to be available to deliver coal as required, and to
provide byproduct disposal services for the plant. The duration of the contract is largely dependent upon the Corporation’s
coal-to-gas transition plans and decisions. Pricing terms are based on actual costs incurred to provide the coal, and will
vary over the life of the contract. Revenue will be recognized on the basis of the costs incurred and based on volumes of
coal delivered, which are variable and depend upon market demand for electricity, which is subject to factors outside of
the Corporation’s control. Accordingly, revenues related to remaining performance obligations associated with this
component of the contract are excluded from these disclosures as they are variable and considered to be fully constrained.
The customer also funds a portion of the required mine capital as part of the transaction price, which the Corporation has
determined constitutes a significant financing component. Revenues are dependent upon the Corporation’s mine capital
replacement plan and the recoveries, along with the significant financing component, and are amortized into revenue as
the Corporation satisfies its performance obligations of being available to deliver coal and the delivery of coal. The
significant financing component of these revenues is excluded from these disclosures.
Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2018, are
approximately $330 million, of which the Corporation expects to recognize approximately $245 million in total over the
next two fiscal years and on average, between approximately $7 million to $10 million annually thereafter for the duration
of the contracts.
US Coal
The Corporation’s long-term contract for the sale of electricity produced at its US Coal plant is considered a derivative and
is designated as an all-in-one hedge. Accordingly, while revenues for electricity delivered to the customer are recognized
pursuant to the contractual terms, the revenues are not accounted for under IFRS 15 and the contract has been excluded
from any required IFRS 15 disclosures.
The Corporation also has a contract for the sale of byproducts of coal combustion from its US Coal plant. Generally, revenues
vary based on market prices that are subject to factors outside of the Corporation’s control, and the quantities delivered
and sold, which are ultimately dependent upon customer demand. These variable revenues are considered to be fully
F38
TRANSALTA CORPORATION F38
TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
constrained, and will be recognized at a point in time as the performance obligation, the delivery of byproducts, is satisfied.
Accordingly, these revenues are excluded from these disclosures.
Canadian Gas
At Dec. 31, 2018, the Corporation has contracts with customers to deliver energy services from one of its gas plants in
Ontario. The contracts all consist of a single performance obligation requiring the Corporation to stand ready to deliver
electricity and steam. The following is a summary of the key terms:
The energy supply agreements require specified amounts of steam to be delivered to each customer, and have pricing terms
that include fixed and variable charges for electricity, capacity and steam, as well as a true-up based on contractual minimum
volumes of steam. The steam reconciliation is based on an estimate of the customer’s steam volume taken and the
contractual minimum volume, and various factors including the annual average market price of electricity and the average
locally posted and index prices of natural gas, as well as transportation. For steam volumes not taken by the customer, a
revenue-sharing mechanism provides for sharing of revenues earned by the Corporation using that steam to generate and
sell electricity. Capacity and electricity pricing vary from contract to contract and are subject to annual indexation at varying
rates. Electricity and steam delivered is ultimately dependent upon customer requirements, which is outside of the
Corporation’s control, These variable revenues under the contracts are considered to be fully constrained. Accordingly,
these revenues are excluded from these disclosures. The Corporation expects to recognize revenue as it delivers electricity
and steam until the completion of the contract in late 2022.
At the same gas plant, the Corporation has a contract with the local power authority with fixed capacity charges that are
adjusted for seasonal fluctuations, steam demand from the plant’s other customers, and for deemed net revenue related
to production of electricity into the market. As a result, revenues recognized in the future will vary as they are dependent
upon factors outside of the Corporation’s control and are considered to be fully constrained. Accordingly, these revenues
are excluded from these disclosures. The Corporation expects to recognize such revenue as it stands ready to deliver
electricity until the completion of the contract term on Dec. 31, 2025.
At Dec. 31, 2018, the Corporation has contracts with customers to deliver steam, hot water and chilled water from one of
its other gas plants in Ontario, extending through 2023. Prices under these contracts are at fixed base amounts per gigajoule
and are subject to escalation annually for both gas prices and inflation. The contracts include minimum annual take-or-pay
volumes.
Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2018, are
approximately $25 million in total, of which the Corporation expects to be on average, between approximately $4 million
to $6 million annually thereafter for the duration of the contracts.
The practical expedient allowing the recognition of revenue from the contract in an amount that is equal to the amount
invoiced is applied to some of the Corporation’s other gas facilities’ contracts in Ontario; accordingly, disclosures related
to remaining performance obligations are not provided for these contracts.
Australian Gas
At Dec. 31, 2018, the Corporation has PPAs with customers to deliver electricity from its gas plants located in Australia.
One contract is considered to be a lease and is excluded from these disclosures. The PPAs generally call for all available
generation to be provided to customers. Pricing terms include fixed and variable price components for delivered electricity
and fixed capacity payments. Prices may be subject to true-up adjustments for deviations from expected heat rates and
are subject to various escalators to reflect inflation. Electricity delivered is ultimately dependent upon customer
requirements, which is outside of the Corporation’s control. These variable revenues for electricity delivered are
considered to be fully constrained, and will be recognized at a point in time as the performance obligation, the delivery of
electricity, is satisfied. Accordingly, these revenues are excluded from these disclosures. The contracts have durations that
range from 2021 to 2042.
Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2018, are
approximately $2,280 million, of which the Corporation expects to recognize approximately $230 million in total over the
next three fiscal years and on average, between approximately $80 million to $110 million annually thereafter for the
duration of the contracts.
Wind and Solar
At Dec. 31, 2018, the Corporation had long-term contracts with customers to deliver electricity and the associated
renewable energy credits from two wind farms located in Alberta and Minnesota, for which the invoice practical expedient
is not applied. The PPAs generally require all available generation to be provided to customers at fixed prices, with certain
F39
TRANSALTA CORPORATION F39
TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
pricing subject to annual escalations for inflation. The Corporation expects to recognize such amounts as revenue as it
delivers electricity over the remaining terms of the contracts, until 2024 and 2034. Electricity delivered is ultimately
dependent upon the wind resource, which is outside of the Corporation’s control. Amounts delivered, and therefore
revenue recognized, in the future will vary. These variable revenues for electricity delivered are considered to be fully
constrained, and will be recognized at a point in time as the performance obligation, the delivery of electricity, is satisfied.
Accordingly, these revenues are excluded from these disclosures. The Corporation also has contracts to sell renewable
energy certificates generated at merchant wind facilities and expects to recognize revenues as it delivers the renewable
energy certificates to the purchaser over the remaining terms of the contracts, from 2019 through 2024.
Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2018, are
approximately $9 million, of which the Corporation expects to recognize between approximately $1 million to $2 million
annually through to contract expiry.
The practical expedient allowing the recognition of revenue from the contract in an amount that is equal to the amount
invoiced is applied to wind energy contracts in Ontario, New Brunswick, Quebec and Wyoming, and for all solar contracts;
accordingly, disclosures related to remaining performance obligations are not provided for these contracts.
Hydro
At Dec. 31, 2018, the Corporation has a PPA with the Balancing Pool to provide the capacity of 12 hydro plants throughout
the province of Alberta. The capacity payment is fixed on an annual basis. As part of the PPA, the Corporation also has a
financial obligation to the Balancing Pool determined on the basis of notional quantities of electricity delivered and the
pool price for the period. The Corporation expects to recognize revenue as it makes capacity available to the customer
until completion of the contract term at Dec. 31, 2020. The Corporation also has contracts for blackstart services at specific
hydro plants and a contract with the Government of Alberta to manage water on the Bow River for flood and drought
mitigation purposes, which all conclude within 2020.
Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2018, are
approximately $130 million, which the Corporation expects to recognize over the next two fiscal years.
The practical expedient allowing the recognition of revenue from the contract in an amount that is equal to the amount
invoiced is applied to all hydro energy contracts in Ontario, British Columbia and Washington; accordingly, disclosures
related to remaining performance obligations are not provided for these contracts.
Expenses classified by nature are as follows:
6. Expenses by Nature
Year ended Dec. 31
2018
2017
2016
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(1)
Coal inventory writedown (recovery)
Purchased power
Mine depreciation
Salaries and benefits(1)
Other operating expenses
Total
656
—
210
136
98
—
1,100
—
—
—
—
245
270
515
685
—
162
73
96
—
1,016
—
—
—
—
248
269
517
665
(4)
143
63
96
—
963
—
—
—
—
249
240
489
(1) $90 million in both 2017 and 2016 was reclassified from fuel to salaries and benefits to be consistent with the 2018 classification.
As part of the Corporation’s monitoring controls, long-range forecasts are prepared for each CGU. The long-range forecast
7. Asset Impairment Charges and Reversals
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
F40
TRANSALTA CORPORATION F40
TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
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.
During 2018, 2017 and 2016, uncertainty continued to exist within the province of Alberta regarding the Government's
Climate Leadership Plan, the future design parameters of the Alberta electricity market, and federal policies on the carbon
A. Alberta Merchant CGU
levy and greenhouse gas ("GHG") emissions. Economic conditions also contributed to continued oversupply conditions and
depressed market prices throughout 2015 to 2017. The Corporation assessed whether these factors, and events arising
during the latter part of 2016, which are more fully discussed below, presented an indicator of impairment for its Alberta
Merchant CGU. In consideration of the composition of this CGU, the Corporation 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 for any of these years, but for all years, a sensitivity analysis associated with these
factors was performed to confirm the continued existence of adequate excess of estimated recoverable amount over book
value. This analysis of the Alberta Merchant CGU continued to demonstrate a substantial cushion at the Alberta Merchant
CGU in each of 2018, 2017 and 2016, due to the Corporation’s large merchant renewable fleet in the province.
I. 2018
Sundance Unit 2
In the third quarter of 2018, the Corporation recognized an impairment charge on Sundance Unit 2 in the amount of $38
million, due to the Corporation’s decision to retire Sundance Unit 2. Previously, the Corporation had expected Sundance
Unit 2 to remain mothballed for a period of up to two years and therefore remain within the Alberta Merchant CGU where
significant cushion exists. The impairment assessment was based on value in use and included the estimated future cash
flows expected to be derived from the Unit until its retirement on July 31, 2018. Discounting did not have a material impact.
Lakeswind and Kent Breeze
On May 31, 2018, TransAlta Renewables acquired an economic interest in Lakeswind through the subscription of tracking
preferred shares of a subsidiary of the Corporation and also purchased Kent Breeze (see Note 4(D)). In connection with
these acquisitions, the assets were fair valued using discount rates that average approximately 7 per cent. Accordingly, the
Corporation has recorded an impairment charge of $12 million using the valuation in the agreement as the indicator of fair
value less cost of disposal in 2018. The impairment charge had an $11 million impact on PP&E and a $1 million impact on
intangible assets (See Note 17 and 19).
II. 2017
Sundance Unit 1
In the second quarter of 2017, the Corporation recognized an impairment charge on Sundance Unit 1 in the amount of $20
million, due to the Corporation’s decision to early retire Sundance Unit 1. Previously, the Corporation had expected
Sundance Unit 1 to operate in the merchant market in 2018 and 2019 and therefore remain within the Alberta Merchant
CGU where significant cushion exists. The impairment assessment was based on value in use and included the estimated
future cash flows expected to be derived from the Unit until its retirement on Jan. 1, 2018. Discounting did not have a
material impact.
No separate stand-alone impairment test was required for Sundance Unit 2, as mothballing the Unit maintained the
Corporation’s flexibility to operate the Unit as part of the Corporation’s Alberta Merchant CGU to 2021.
III. 2016
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(S)). In connection with this sale, the Wintering Hills assets were accounted
for as held for sale at Dec. 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 in 2016.
During 2018, the Corporation wrote off $23 million in project development costs related to projects that are no longer
proceeding.
B. Project Development Costs
F41
TRANSALTA CORPORATION F41
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
Amounts receivable under the Corporation’s finance leases associated with the Fort Saskatchewan cogeneration facility
8. Finance Lease Receivables
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
Total finance lease receivables
Included in the Consolidated Statements of Financial Position as:
Current portion of finance lease receivables (Note 13)
Long-term portion of finance lease receivables
2018
2017
Minimum
lease
payments
Present
value of
minimum
lease
payments
Minimum
lease
payments
Present
value of
minimum
lease
payments
66
82
126
274
—
274
29
74
112
215
—
215
30
80
140
250
35
215
24
191
215
68
110
140
318
44
274
59
215
274
Net other operating expense (income) includes the following:
9. Net Other Operating Expense (Income)
Year ended Dec. 31
Alberta Off-Coal Agreement
Termination of the Sundance B and C PPAs
Mississauga cogeneration facility NUG Contract
Insurance recoveries
Restructuring provision
2018
(40)
(157)
—
(7)
—
2017
(40)
—
(9)
—
—
2016
—
—
(191)
(3)
1
Net other operating expense (income)
(204)
(49)
(193)
The Corporation receives payments from the Government of Alberta for the cessation of coal-fired emissions from its
interest in the Keephills 3, Genesee 3 and Sheerness coal-fired plants on or before Dec. 31, 2030.
A. Alberta Off-Coal Agreement
Under the terms of the OCA, the Corporation receives annual cash payments on or before July 31 of approximately $40
million ($37 million, net to the Corporation), commencing Jan. 1, 2017, and terminating at the end of 2030. The Corporation
recognizes the off-coal payments evenly throughout the year. Receipt of the payments is subject to certain terms and
conditions. The OCA’s main condition is the cessation of all coal-fired emissions on or before Dec. 31, 2030. The affected
plants are not, however, precluded from generating electricity at any time by any method, other than generation resulting
in coal-fired emissions after Dec. 31, 2020. In July 2018, the Corporation obtained financing against the OCA payments
(See Note 4(O) and 22).
On Sept. 18, 2017, the Corporation received formal notice from the Balancing Pool of the termination of the Sundance B
and C PPAs effective March 31, 2018, and received a termination payment of $157 million during the first quarter of 2018.
B. Termination of the Sundance B and C PPAs
See Note 4(J) for further details.
F42
TRANSALTA CORPORATION F42
TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
2016
On Dec. 22, 2016, the Corporation announced it had signed a NUG Contract with the IESO for its Mississauga cogeneration
C. Mississauga Cogeneration Facility Contract
facility. The contract was effective on Jan. 1, 2017. The Corporation has agreed to terminate the prior contract with the
IESO 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.
2017
During the fourth quarter of 2017, the Corporation renegotiated the facility's land lease agreement at a lower cost than
previously estimated in 2016, and accordingly, recognized a gain of $9 million.
2018
In December 2018, TransAlta exercised its option to terminate its agreement with Boeing Canada Inc. effective Jan. 1,
2021. TransAlta is required to remove the plant and restore the site within the three-year time frame.
During 2018, the Corporation received $7 million in insurance recoveries, of which $6 million related insurance proceeds
for the tower fire at Wyoming Wind and a $1 million claim related to equipment repairs within Canadian Coal. There were
D. Insurance Recoveries
no insurance recoveries in 2017.
During 2016, the Corporation received $3 million in insurance recoveries, of which $2 million related to business
interruption insurance claims and $1 million related to claims for replacement and refurbishment of equipment for certain
wind facilities.
The components of net interest expense are as follows:
10. Net Interest Expense
Year ended Dec. 31
Interest on debt
Interest income
Capitalized interest (Note 17)
Loss on redemption of bonds (Note 22)
Interest on finance lease obligations
Credit facility fees, bank charges and other interest
Keephills 1 outage interest (reversals) (Note 4(P))
Other(1)
Accretion of provisions (Note 21)
Net interest expense
2018
184
(11)
(2)
24
3
13
—
15
24
2017
218
2016
218
(7)
(9)
6
3
18
—
(3)
21
(2)
(16)
1
3
19
(10)
(4)
20
229
250
247
(1) During 2018, approximately $5 million of costs were expensed due to project-level financing that is no longer practicable and approximately $7 million for the
significant financing component required under IFRS 15 (see Note 3).
F43
TRANSALTA CORPORATION F43
TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
11. Income Taxes
I. Rate Reconciliations
A. Consolidated Statements of Earnings
Year ended Dec. 31
Earnings before income taxes
Net earnings attributable to non-controlling interests not subject to tax
Adjusted earnings before income taxes
Statutory Canadian federal and provincial income tax rate (%)
Expected income tax expense (recovery)
Increase (decrease) in income taxes resulting from:
Lower effective foreign tax rates
Deferred income tax expense related to temporary difference on investment in
subsidiary
Writedown (reversal of writedown) of deferred income tax assets
Statutory and other rate differences
Other
Income tax expense (recovery)
Effective tax rate (%)
2018
2017
(96)
(19)
(115)
26.8
(31)
(3)
—
27
—
1
(6)
5
(54)
(35)
(89)
26.8
(24)
(11)
—
(15)
110
4
64
72
2016
314
(109)
205
26.7
55
(16)
11
(10)
1
(3)
38
19
F44
TRANSALTA CORPORATION F44
TransAlta Corporation | 2018 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(1)
Adjustments in respect of deferred income tax of previous years
Deferred income tax expense (recovery) related to the origination and reversal of
temporary differences
Deferred income tax expense related to temporary difference on investment in
subsidiary(2)
Deferred income tax expense resulting from changes in tax rates or laws(3)
Deferred income tax expense (recovery) arising from the writedown (reversal of
writedown) of deferred income tax assets(4)
Income tax expense (recovery)
Year ended Dec. 31
Current income tax expense
Deferred income tax expense (recovery)
Income tax expense (recovery)
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
2018
2017
2016
28
—
79
—
(61)
(110)
—
—
27
(6)
—
110
(15)
64
23
(3)
16
11
1
(10)
38
2018
2017
2016
28
(34)
(6)
79
(15)
64
23
15
38
(1) During 2017, the Corporation recognized current tax expense of $56 million due to the disposition of the Solomon Power Station on Nov. 1, 2017.
(2) 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. 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.
(3) On Dec. 22, 2017, the US government enacted H.R.1, originally known as the Tax Cuts and Jobs Act, which includes legislation to decrease its federal corporate
income tax rate from 35 per cent to 21 per cent. The Corporation's net deferred tax liability associated with its directly owned US operations is made up of a deferred
tax asset and a deferred tax liability that net to $6 million. The decrease in the US federal corporate income tax rate resulted in a decrease to the deferred tax asset of
$104 million, all of which is recorded as deferred tax expense in the Consolidated Statement of Earnings, offset by a decrease to the deferred tax liability of $110
million, of which $1 million is recorded as deferred tax expense in the Consolidated Statement of Earnings with an offsetting $111 million deferred tax recovery
recorded in the Consolidated Statement of Other Comprehensive Income. 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.
(4) During the year ended Dec. 31, 2018, the Corporation recorded a writedown of deferred income tax assets of $27 million (2017 - $15 million writedown reversal,
2016 - $10 million writedown reversal). The deferred income tax assets relate mainly to the tax benefits of losses associated with the Corporation’s directly owned US
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 US operations to utilize the underlying tax losses, due to reduced price growth expectations. Net operating losses expire between 2021
and 2037 for losses generated prior to 2018.
The aggregate current and deferred income tax related to items charged or credited to equity are as follows:
B. Consolidated Statements of Changes in Equity
Year ended Dec. 31
2018
2017
Income tax expense (recovery) related to:
Net impact related to cash flow hedges
Net impact related to net investment hedges
Net actuarial gains (losses)
Income tax expense reported in equity
(12)
—
5
(7)
(108)
(7)
(4)
(119)
2016
51
16
4
71
F45
TRANSALTA CORPORATION F45
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
Significant components of the Corporation’s deferred income tax assets (liabilities) are as follows:
C. Consolidated Statements of Financial Position
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 US-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
2018
547
113
(896)
(145)
68
48
35
23
—
(207)
(266)
(473)
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
2018
28
(501)
(473)
2017
541
117
(1,009)
(160)
74
50
42
16
22
(307)
(218)
(525)
2017
24
(549)
(525)
(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.
As of Dec. 31, 2018, the Corporation had recognized a net liability of nil (2017 - $4 million) related to uncertain tax positions.
D. Contingencies
The Corporation’s subsidiaries and operations that have non-controlling interests are as follows:
12. Non-Controlling Interests
Subsidiary/Operation
TransAlta Cogeneration L.P.
TransAlta Renewables
Kent Hills Wind LP(1)
(1) Owned by TransAlta Renewables.
Non-controlling interest as at Dec. 31, 2018
49.99% - Canadian Power Holdings Inc.
39.1% - 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 gas and renewable power generation facilities in
Canada and owns economic interests in various other gas and renewable facilities of the Corporation.
F46
TRANSALTA CORPORATION F46
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
Summarized financial information relating to subsidiaries with significant non-controlling interests is as follows:
The net earnings, distributions and equity attributable to non-controlling interests include the 17 per cent non-controlling
A. TransAlta Renewables
interest in the 167 MW Kent Hills wind farm located in New Brunswick.
The South Hedland Power Station achieved commercial operation on July 28, 2017. On Aug. 1, 2017, the Corporation
converted its 26.1 million Class B shares held in TransAlta Renewables into 26.4 million common shares of TransAlta
Renewables. At that time, the Corporation’s equity participation percentage in TransAlta Renewables increased to 64 per
cent from 59.8 per cent. The Class B shares were converted at a ratio greater than 1:1 because the construction and
commissioning costs for the project were below the referenced costs agreed to with TransAlta Renewables.
On May 31, 2018, TransAlta Renewables implemented a dividend reinvestment plan ("DRIP") for Canadian holders of
common shares of TransAlta Renewables. Commencing with the dividend paid on July 31, 2018, eligible shareholders may
elect to automatically reinvest monthly dividends into additional common shares of the Corporation.
As a result of the conversion of Class B shares, the DRIP and 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
April 29, 2014 to May 6, 2015
May 7, 2015 to Nov. 25, 2015
Nov. 26, 2015 to Jan. 5, 2016
Jan. 6, 2016 to July 31, 2017
Aug. 1, 2017 to June 21, 2018
June 22, 2018 to July 30, 2018
July 31, 2018 to Nov. 29, 2018
Nov. 30, 2018 to Dec. 31, 2018
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
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)
Ownership and voting
rights percentage
Equity participation
percentage
70.3
76.1
66.6
64.0
64.0
61.1
61.0
60.9
70.3
72.8
62.0
59.8
64.0
61.1
61.0
60.9
2016
259
1
40
2
18
83
2017
145
3,483
(356)
(1,075)
(2,197)
(812)
36.0
2018
2017
462
241
281
94
110
79
459
13
(24)
11
—
85
2018
250
3,497
(159)
(1,192)
(2,396)
(961)
39.1
F47
TRANSALTA CORPORATION F47
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
Year ended Dec. 31
B. TA Cogen
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)
As at Dec. 31
13. Trade and Other Receivables
Trade accounts receivable
Mississauga recontracting receivable
Net trade receivables
Promissory note receivable(1)
Collateral paid (Note 15)
Current portion of finance lease receivables (Note 8)
Current portion of loan receivable (Note 20)
Income taxes receivables
Trade and other receivables
2018
2017
2016
185
175
29
29
14
14
86
61
61
31
31
87
274
211
258
105
128
68
2018
2017
82
354
(54)
(28)
(354)
(176)
193
404
(73)
(26)
(498)
(247)
49.99
49.99
2018
2017
597
—
597
25
105
24
—
5
756
693
108
801
—
67
59
5
1
933
(1) The promissory note receivable relates to funding provided for the Antrim wind development project (see Note 4(C) for further details).
F48
TRANSALTA CORPORATION F48
TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
14. Financial Instruments
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:
A. Financial Assets and Liabilities – Classification and Measurement
Carrying value as at Dec. 31, 2018
Financial assets
Cash and cash equivalents(1)
Restricted cash
Trade and other receivables
Long-term portion of finance lease receivables
Risk management assets
Current
Long-term
Other assets
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 nil.
(2) Includes current portion.
Carrying value as at Dec. 31, 2017
Financial assets
Cash and cash equivalents(1)
Restricted cash
Trade and other receivables
Long-term portion of finance lease receivables
Risk management assets
Current
Long-term
Other assets
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 nil.
(2) Includes current portion.
Derivatives
used for
hedging
Derivatives
held for
trading
(FVTPL)
Amortized
cost
Other
financial
assets
(FVTPL)
—
—
—
—
60
629
—
—
—
1
1
—
—
—
—
—
86
33
—
—
—
89
40
—
89
66
731
191
—
—
37
497
58
—
—
3,267
—
—
25
—
—
—
15
—
—
—
—
—
Derivatives
used for
hedging
Derivatives
classified as
held for
trading
Loans and
receivables
Other
financial
liabilities
—
—
—
—
82
638
—
—
—
8
2
—
—
—
—
—
137
46
—
—
—
93
38
—
314
30
933
215
—
—
33
—
—
—
—
—
—
—
—
—
—
—
—
595
34
—
—
Total
89
66
756
191
146
662
52
497
58
90
41
3,267
Total
314
30
933
215
219
684
33
595
34
101
40
3,707
3,707
F49
TRANSALTA CORPORATION F49
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
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
B. Fair Value of Financial Instruments
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.
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, 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, that 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.
F50
TRANSALTA CORPORATION F50
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
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 certain unobservable 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.
As at Dec. 31
Description
Long-term power sale - US
Long-term power sale - Alberta
Unit contingent power purchases
Structured products - Eastern US
Long-term wind energy sale - Eastern US
Others
2018
2017
Base fair value Sensitivity Base fair value
Sensitivity
801
4
18
6
(39)
4
+116
-116
+1
-1
+4
-4
+5
-5
+21
-21
+3
-3
853
(1)
44
17
—
5
+130
-130
+2
-2
+7
-9
+8
-7
—
+9
-9
i. Long-Term Power Sale - US
The Corporation has a long-term fixed price power sale contract in the US 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 2020, 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 using a fundamental-based forecast (the provider is an independent and widely
accepted industry expert for scenario and planning views). Prior to the second quarter of 2018, the base price forecast was
developed using an additional independent industry forecast. Forward power price ranges per MWh used in determining
the Level III base fair value at Dec. 31, 2018, are US$20-US$35 (Dec. 31, 2017 - US$25-US$34). The sensitivity analysis
has been prepared using the Corporation’s assessment that a US$6 (Dec. 31, 2017 - US$6) price increase or decrease in
the forward power prices is a reasonably possible change.
The contract is denominated in US dollars. With the strengthening of the US dollar relative to the Canadian dollar from
Dec. 31, 2017 to Dec. 31, 2018, the base fair value and the sensitivity values have increased by approximately $62 million
and $9 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 FVTPL.
For periods beyond 2023, 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 prices per MWh used in determining the Level III base fair
value at Dec. 31, 2018, are $40 (Dec. 31, 2017 - $63 -$67). 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.
F51
TRANSALTA CORPORATION F51
TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
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 FVTPL.
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, 2018, are nil (Dec. 31, 2017 - nil)
and 2.2 per cent to 16.9 per cent (Dec. 31, 2017 – 2.2 per cent to 2.8 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 1.1 per cent to 1.9 per cent (Dec. 31, 2017 - 1.1 per cent to 1.9 per cent) and a change in volumetric discount
rates of approximately 8.6 per cent to 27.3 per cent (Dec. 31, 2017 - 7.8 per cent and 10.5 per cent), which approximate
one standard deviation for each input.
iv. Structured Products - Eastern US
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, 2018, are 75 per cent to 109 per cent
and 63 per cent to 104 per cent (Dec. 31, 2017 – 75 per cent to 159 per cent and 71 per cent to 88 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 4 per cent to 7 per cent (Dec. 31, 2017 - 7 per cent) and a change in non-standard shape
factors of approximately 4 per cent to 9 per cent (Dec. 31, 2017 - 6 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, 2018, are 25 per cent to 84 per
cent and 70 per cent (Dec. 31, 2017 – 18 per cent to 54 per cent and 70 per cent), respectively. The sensitivity analysis has
been prepared using the Corporation’s assessment of a reasonably possible change in implied volatilities ranges and
correlations of approximately 37 per cent to 49 per cent and 30 per cent, respectively (2017 - 27 per cent to 32 per cent
and 10 per cent, respectively).
v. Long-Term Wind Energy Sale - Eastern US
In relation to the acquisition of Big Level (See Note 4(C)), the Corporation has a long-term contract for differences whereby
the Corporation receives a fixed price per MWh and pays the prevailing real-time energy market price per MWh as well as
the physical delivery of renewable energy credits ("RECs") based on proxy generation. Commercial operation of the facility
is expected to occur in the second half of 2019, with the contract extending for 15 years after commercial operation. The
contract is accounted for at fair value through profit or loss.
The key unobservable inputs used in the valuation of the contract are expected proxy generation volumes and forward
prices for power and RECs beyond 2023 and 2022, respectively. Forward power and REC price ranges per MWh used in
determining the Level III base fair value at Dec. 31, 2018, are US$42-US$68 and US$7-US$8, respectively. The sensitivity
analysis has been prepared using the Corporation’s assessment that a change in expected proxy generation volumes of 10
per cent, a change in energy prices of US$6 and a change in REC prices of US$1 as reasonably possible changes.
F52
TRANSALTA CORPORATION F52
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
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.
Commodity risk management assets and liabilities classified by fair value levels as at Dec. 31, 2018, are as follows: Level I
- $3 million net asset (Dec. 31, 2017 - $1 million net liability), Level II - $19 million net liability (Dec. 31, 2017 - $42 million
net liability) and Level III - $695 million net asset (Dec. 31, 2017 - $771 million net asset).
Significant changes in commodity net risk management assets (liabilities) during the year ended Dec. 31, 2018, are primarily
attributable to the settlement of contracts, partially offset by favourable foreign exchange rates.
The following tables summarize the key factors impacting the fair value of the Level III commodity risk management assets
and liabilities by classification level during the years ended Dec. 31, 2018 and 2017, respectively:
Opening balance
Changes attributable to:
Market price changes on existing contracts
Market price changes on new contracts
Contracts settled
Change in foreign exchange rates
Transfers into (out of) Level III
Net risk management assets at end of period
Additional Level III information:
Gains recognized in other comprehensive income
Total gains included in earnings before income taxes
Unrealized gains (losses) included in earnings before
income taxes relating to net assets held at period end
Year ended Dec. 31, 2018
Year ended Dec. 31, 2017
Hedge Non-hedge Total
Hedge Non-hedge Total
719
(7)
—
(90)
67
—
689
60
90
—
52
771
726
32
758
(9)
4
(16)
4
(42)
(132)
5
(4)
6
—
—
72
(4)
695
60
90
(42)
(42)
100
—
(57)
(50)
—
719
50
57
—
(2)
33
(10)
(2)
1
52
—
29
19
98
33
(67)
(52)
1
771
50
86
19
III. Other Risk Management Assets and Liabilities
Other risk management assets and liabilities primarily include risk management assets and liabilities that are used in
managing exposures on non-energy marketing transactions such as interest rates, the net investment in foreign operations
and other foreign currency risks. Hedge accounting is not always applied.
Other risk management assets and liabilities with a total net liability fair value of $2 million as at Dec. 31, 2018 (Dec. 31,
2017 - $34 million net asset) are classified as Level II fair value measurements. The significant changes in other net risk
management assets during the year ended Dec. 31, 2018, are primarily attributable to the settlement of contracts.
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 - Dec. 31, 2018
Long-term debt - Dec. 31, 2017
(1) Includes current portion.
Fair value(1)
Level I
Level II
Level III
—
—
3,181
3,708
—
—
Total
3,181
3,708
Total
carrying
value(1)
3,204
3,638
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.
F53
TRANSALTA CORPORATION F53
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
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. The fair values of the loan receivable (see Note
20) and the finance lease receivables (see Note 8) approximate the carrying amounts.
The majority of derivatives traded by the Corporation are based on adjusted quoted prices on an active exchange or extend
C. Inception Gains and Losses
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 (losses)
Change in foreign exchange rates
Amortization recorded in net earnings during the year
Unamortized net gain at end of year
2018
105
(14)
5
(47)
49
2017
148
12
(7)
(48)
105
2016
202
10
(4)
(60)
148
15. Risk Management Activities
The Corporation is exposed to market risk from changes in commodity prices, foreign exchange rates, interest rates, credit
risk and liquidity risk. These risks affect the Corporation’s earnings and the value of associated financial instruments that
A. Risk Management Strategy
the Corporation holds. In certain cases, the Corporation seeks to minimize the effects of these risks by using derivatives
to hedge its risk exposures. The Corporation’s risk management strategy, policies and controls are designed to ensure that
the risks it assumes comply with the Corporation’s internal objectives and its risk tolerance.
The Corporation has two primary streams of risk management activities: i) financial exposure management and ii)
commodity exposure management. Within these activities, risks identified for management include commodity risk,
interest rate risk, liquidity risk, equity price risk and foreign currency risk.
The Corporation seeks to minimize the effects of commodity risk, interest rate risk and foreign currency risk by using
derivative financial instruments to hedge risk exposures. Of these derivatives, the Corporation may apply hedge accounting
to those hedging commodity price risk and foreign currency risk.
The use of financial derivatives is governed by the Corporation’s policies approved by the Board, which provide written
principles on commodity risk, interest rate risk, liquidity risk, equity price risk and foreign currency risk, as well as the use
of financial derivatives and non-derivative financial instruments.
Liquidity risk, credit risk and equity price risk are managed through means other than derivatives or hedge accounting.
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 derivatives at fair value through profit and loss . The net realized and unrealized gains or losses from changes
in the fair value of these derivatives are reported in net earnings in the period the change occurs.
The Corporation designates certain derivatives as hedging instruments to hedge commodity price risk, foreign currency
exchange risk in cash flow hedges, and hedges of net investments in foreign operations. Hedges of foreign exchange risk
on firm commitments are accounted for as cash flow hedges.
F54
TRANSALTA CORPORATION F54
TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
At the inception of the hedge relationship, the Corporation documents the relationship between the hedging instrument
and the hedged item, along with its risk management objectives and its strategy for undertaking various hedge transactions.
At the inception of the hedge and on an ongoing basis, the Corporation also documents whether the hedging instrument
is effective in offsetting changes in fair values or cash flows of the hedged item attributable to the hedged risk, which is
when the hedging relationships meet all of the following hedge effectiveness requirements:
▪
▪
▪
There is an economic relationship between the hedged item and the hedging instrument;
The effect of credit risk does not dominate the value changes that result from that economic relationship; and
The hedge ratio of the hedging relationship is the same as that resulting from the quantity of the hedged item that
the Corporation actually hedges and the quantity of the hedging instrument that the entity actually uses to hedge
that quantity of hedged item.
If a hedging relationship ceases to meet the hedge effectiveness requirement relating to the hedge ratio, but the risk
management objective for that designated hedging relationship remains the same, the Corporation adjusts the hedge ratio
of the hedging relationship so that it continues to meet the qualifying criteria.
Aggregate net risk management assets and (liabilities) are as follows:
B. Net Risk Management Assets and Liabilities
As at Dec. 31, 2018
Commodity risk management
Current
Long-term
Net commodity risk management assets
Other
Current
Long-term
Net other risk management assets (liabilities)
Cash flow
hedges
Not
designated
as a hedge
59
628
687
—
—
—
—
(8)
(8)
(3)
1
(2)
Total
59
620
679
(3)
1
(2)
Total net risk management assets (liabilities)
687
(10)
677
As at Dec. 31, 2017
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)
Cash flow
hedges
Not
designated
as a hedge
74
636
710
—
—
—
710
7
11
18
37
(3)
34
52
Total
81
647
728
37
(3)
34
762
F55
TRANSALTA CORPORATION F55
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
I. Netting Arrangements
Information about the Corporation’s financial assets and liabilities that are subject to enforceable master netting
arrangements or similar agreements is as follows:
As at Dec. 31
2018
2017
Gross amounts recognized
Gross amounts set-off
Net amounts as presented in the
Consolidated Statements of
Financial Position
Current
financial
assets
Long-term
financial
assets
Current
financial
liabilities
Long-term
financial
liabilities
Current
financial
assets
Long-term
financial
assets
Current
financial
liabilities
Long-term
financial
liabilities
210
—
666
—
(121)
—
(50)
—
281
(43)
637
—
(159)
43
(38)
—
210
666
(121)
(50)
238
637
(116)
(38)
C. Nature and Extent of Risks Arising from Financial Instruments
I. Market Risk
a. Commodity Price Risk Management
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.
To mitigate the risk of adverse commodity price changes, the Corporation uses three tools:
▪
▪
a framework of risk controls;
a pre-defined hedging plan, including fixed price financial power swaps and long-term physical power sale contracts
to hedge commodity price for electricity generation; and
a committee dedicated to overseeing the risk and compliance program in trading and ensuring the existence of
appropriate controls, processes, systems and procedures to monitor adherence to the program.
▪
The Corporation has executed commodity price hedges for its Centralia coal plant and for its portfolio of merchant power
exposure in Alberta, including a long-term physical power sale contract at Centralia and fixed price financial swaps for the
Alberta portfolio to hedge the prices. Both hedging strategies fall under the Corporation’s risk management strategy used
to hedge commodity price risk.
There is no source of hedge ineffectiveness for the merchant power exposure in Alberta.
Market risk exposures are measured using Value at Risk (VaR) supplemented by sensitivity analysis. There has been no
change to the Corporation’s exposure to market risks or the manner in which these risks are managed or measured.
i. Commodity Price Risk Management – 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.
F56
TRANSALTA CORPORATION F56
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
Changes in market prices associated with proprietary trading activities affect net earnings in the period that the price
changes occur. VaR at Dec. 31, 2018, associated with the Corporation’s proprietary trading activities was $2 million (2017
- $5 million, 2016 - $2 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. 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, 2018, associated with the Corporation’s commodity derivative instruments used in generation hedging
activities was $18 million (2017 - $16 million, 2016 - $19 million). 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, 2018, associated with
these transactions was $13 million (2017 - $5 million, 2016 - $7 million).
iii. Commodity Price Risk Management - Hedges
The Corporation’s outstanding commodity derivative instruments designated as hedging instruments are as follows:
As at Dec. 31
Type
(thousands)
Electricity (MWh)
2018
2017
Notional
amount
sold
2,128
Notional
amount
purchased
Notional
amount
sold
Notional
amount
purchased
—
1,997
44
During 2018, unrealized pre-tax gains of $4 million (2017 - $2 million, 2016 - $0 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.
iv. Commodity Price Risk Management - Non-Hedges
The Corporation’s outstanding commodity derivative instruments not designated as hedging instruments are as follows:
As at Dec. 31
Type
(thousands)
Electricity (MWh)
Natural gas (GJ)
Transmission (MWh)
Emissions (tonnes)
2018
2017
Notional
amount
sold
Notional
amount
purchased
58,885
80,413
29
3,134
37,023
110,488
11,163
2,948
Notional
amount
sold
14,688
74,195
1
516
Notional
amount
purchased
7,348
103,805
3,455
717
b. Interest Rate Risk Management
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 Alberta coal PPAs. Changes in the cost of capital may also affect the feasibility of new growth initiatives.
The Corporation's credit facility and the Poplar Creek non-recourse bond are the only debt instruments subject to floating
interest rates, which represents 14 per cent of the Corporation’s debt as at Dec. 31, 2018 (2017 - 6 per cent).
F57
TRANSALTA CORPORATION F57
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
Interest rate risk is managed with the use of derivatives. No derivatives related to interest rate risk were outstanding as
at Dec. 31, 2018, 2017 or 2016.
c. Currency Rate Risk
The Corporation has exposure to various currencies, such as the US 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.
The Corporation may enter into the following hedging strategies to mitigate currency rate risk, including:
•
•
Foreign exchange forward contracts to mitigate adverse changes in foreign exchange rates on project-related
expenditures and distributions received in foreign currencies.
Foreign exchange forward contracts and cross-currency swaps to manage foreign exchange exposure on foreign-
denominated debt not designated as a net investment hedge.
• Designating foreign currency debt as a hedge of the net investment in foreign operations to mitigate the risk due
to fluctuating exchange rates related to certain foreign subsidiaries.
i. Net Investment Hedges
When designating foreign currency debt as a hedge of the Corporation’s net investment in foreign subsidiaries, the
Corporation has determined that the hedge is effective as the foreign currency of the net investment is the same as the
currency of the hedge, and therefore an economic relationship is present.
The Corporation’s hedges of its net investment in foreign operations were comprised of US-dollar-denominated long-term
debt with a face value of US$400 million (2017 - US$480 million). During 2016, the Corporation de-designated its foreign
currency forward contracts from its net investment hedges. The cumulative unrealized losses on these contracts are
deferred in AOCI until the disposal of the related foreign operation.
ii. Cash Flow Hedges
The Corporation had no significant foreign currency cash flow hedges outstanding at Dec. 31, 2018 or 2017.
iii. Non-Hedges
As part of the sale of the economic interest in Australian Assets to TransAlta Renewables, the Corporation agreed to
mitigate the risks to TransAlta Renewables shareholders of adverse changes in the USD and AUD in respect of cash flows
from the Australian Assets in relation to the Canadian dollar to June 30, 2020. The financial effects of the 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 to June 30, 2020. Hedge accounting was not applied to these foreign currency contracts. In early 2017, the
Corporation revised its hedging strategies related to cash flows from its foreign operations. These foreign currency
contracts became part of the Corporation's revised strategy, as opposed to a separate hedge program.
The Corporation also uses foreign currency contracts to manage its expected foreign operating cash flows. Hedge
accounting is not applied to these foreign currency contracts.
As at Dec. 31
Notional
amount
sold
Notional
amount
purchased
2018
Fair value
asset
(liability)
Notional
amount
purchased
Maturity
2017
Fair value
asset
(liability)
Maturity
Foreign exchange forward contracts - foreign-denominated receipts/expenditures
AUD218
USD164
CAD205
CAD214
(5) 2019-2022
(7) 2019-2022
CAD157
CAD104
(9) 2018-2021
11
2018-2021
Foreign exchange forward contracts - foreign-denominated debt
USD100
—
10
—
2022
USD230
(4)
2018
USD270
35
2018
CAD124
Cross currency swaps - foreign-denominated debt
—
F58
TRANSALTA CORPORATION F58
TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
During the first quarter of 2017, the Corporation discontinued hedge accounting for certain foreign currency cash flow
hedges on US$690 million of debt. Changes in the risk management assets and liabilities related to these discontinued
hedge positions have been reflected within net earnings prospectively.
iv. Impacts of currency rate risk
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 (2017 and 2016 - 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
2018
2017
2016
Currency
USD
AUD
Total
Net earnings
increase
(decrease)(1) OCI gain(1),(2)
Net earnings
increase(1) OCI gain(1),(2)
Net earnings
decrease(1) OCI gain(1),(2)
(13)
(7)
(20)
—
—
—
(5)
(7)
(12)
—
—
—
(5)
(7)
(12)
—
—
—
(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, third-party credit insurance 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. 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, 2018:
Trade and other receivables(1)
Long-term finance lease receivables
Risk management assets(1)
Loans and notes receivable(2)
Total
Investment
grade
(Per cent)
Non-
investment
grade
(Per cent)
Total
(Per cent)
Total
amount
86
100
99
—
14
—
1
100
100
100
100
100
731
191
808
77
1,807
(1) Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts.
(2) Includes the promissory note receivable for $25 million (see Note 13), the loan receivable of $37 million and the note receivable for $15 million (see Note 20). The
counterparties have no external credit ratings.
An impairment analysis is performed at each reporting date using a provision matrix to measure expected credit losses.
The provision rates are based on historical rates of default by segment of trade receivables as well as forward-looking
credit ratings and forecasted default rates. In addition to the calculation of expected credit losses, TransAlta monitors key
forward looking information as potential indicators that historical bad debt percentages, forward-looking S&P credit
ratings and forecasted default rates would no longer be representative of future expected credit losses. The calculation
reflects the probability-weighted outcome, the time value of money and reasonable and supportable information that is
available at the reporting date about past events, current conditions and forecasts of future economic conditions. TransAlta
evaluates the concentration of risk with respect to trade receivables as low, as its customers are located in several
jurisdictions and industries. The Corporation did not have significant expected credit losses as at Dec. 31, 2018.
F59
TRANSALTA CORPORATION F59
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
The Corporation’s maximum exposure to credit risk at Dec. 31, 2018, 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, 2018, was $13 million (2017 - $40
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 US bonds one notch from Baa3 to Ba1. As at Dec. 31, 2018, 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; reporting liquidity risk exposure for
proprietary trading activities on a regular basis to the Risk Management Committee, senior management and the Board;
maintaining investment grade credit ratings; and maintaining sufficient undrawn committed credit lines to support
potential liquidity requirements. The Corporation does not use derivatives or hedge accounting to manage liquidity risk.
A maturity analysis of the Corporation’s financial liabilities is as follows:
2019
2020
2021
2022
2023
2024 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
497
130
58
(3)
18
161
58
919
—
486
89
(3)
16
152
—
740
—
91
137
(3)
9
129
—
363
—
947
125
7
5
123
—
1,207
(1) Excludes impact of hedge accounting.
(2) Not recognized as a financial liability on the Consolidated Statements of Financial Position.
—
141
113
—
5
84
—
343
—
1,439
157
—
10
694
—
2,300
Total
497
3,234
679
(2)
63
1,343
58
5,872
IV. Equity Price Risk
a. 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.
F60
TRANSALTA CORPORATION F60
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
The following table outlines the terms and conditions of derivative hedging instruments and how they affect the amount,
timing and uncertainty of future cash flows:
D. Hedging Instruments - Uncertainty of Future Cash Flows
2019
2020
2021
2022
2023
2024 and
thereafter
Maturity
Cash flow hedges
Commodity Derivative Instruments
Electricity
Notional amount (thousands MWh)
Average Price ($ per MWh)
3,950
66.86
3,465
70.75
3,424
74.16
3,329
76.81
3,329
78.74
5,966
81.59
I. Effect of Hedges
E. Effects of Hedge Accounting on the Financial Position and Performance
The impact of the hedging instruments on the statement of financial position is, as follows:
As at Dec. 31, 2018
Commodity price risk
Cash flow hedges
Physical power sales
Foreign currency risk
Net investment hedges
Foreign-denominated debt
Notional
amount
Carrying
amount
Line item in the statement
of financial position
Change in fair
value used for
measuring
ineffectiveness
23 MMWh
687
Risk management assets
USD400 CAD546
Credit facilities, long-term
debt and finance lease
obligations
60
41
The impact of the hedged items on the statement of financial position is, as follows:
As at Dec. 31, 2018
Commodity price risk
Cash flow hedges
Power forecast sales - Centralia
Net investment hedges
Net investment in foreign subsidiaries
Change in fair value used for
measuring ineffectiveness
Cash flow hedge reserve
60
508
Change in fair value used for
measuring ineffectiveness
Foreign currency translation reserve
41
84
The hedging gain recognized in OCI before tax is equal to the change in fair value used for measuring effectiveness. There
is no ineffectiveness recognized in profit or loss.
F61
TRANSALTA CORPORATION F61
TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
The impact of hedged items designated in hedging relationships on OCI and net earnings is:
Derivatives in cash
flow hedging
relationships
Commodity contracts
Foreign exchange forwards on
commodity contracts
Foreign exchange forwards on
project hedges
Foreign exchange forwards on
US debt
Cross-currency swaps
Forward starting interest rate
swaps
OCI impact
Year ended Dec. 31, 2018
Effective portion
Ineffective portion
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
(9) Revenue
(67) Revenue
Fuel and
purchased power
Fuel and purchased
power
—
— Revenue
Property, plant
and equipment
Foreign exchange
(gain) loss
Foreign exchange
(gain) loss
—
—
—
— Interest expense
(9) OCI impact
— Revenue
Foreign exchange
(gain) loss
Foreign exchange
(gain) loss
Foreign exchange
(gain) loss
—
3
—
7
Interest expense
(57) Net earnings impact
—
—
—
—
—
—
—
—
Over the next 12 months, the Corporation estimates that approximately $68 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.
Derivatives in cash
flow hedging
relationships
Commodity contracts
Foreign exchange forwards on
commodity contracts
Foreign exchange forwards on
project hedges
Foreign exchange forwards on
US debt
Cross-currency swaps
Forward starting interest rate
swaps
Year ended Dec. 31, 2017 (as reported under IAS 39)
Effective portion
Ineffective portion
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
163 Revenue
(172) Revenue
Fuel and
purchased power
Fuel and purchased
power
—
— Revenue
Property, plant
and equipment
Foreign exchange
(gain) loss
(1)
—
Foreign exchange
(gain) loss
(26)
— Revenue
Foreign exchange
(gain) loss
Foreign exchange
(gain) loss
Foreign exchange
(gain) loss
—
3
24
— Interest expense
7
Interest expense
—
—
—
—
—
—
—
—
OCI impact
136 OCI impact
(138) Net earnings impact
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, in 2017 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 9(C) for
further details.
F62
TRANSALTA CORPORATION F62
TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
Year ended Dec. 31, 2016 (as reported under IAS 39)
Effective portion
Ineffective portion
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
304 Revenue
(169) Revenue
Fuel and
purchased power
Fuel and purchased
power
44
(5) Revenue
Property, plant,
and equipment
Foreign exchange
(gain) loss
(1)
(2)
Foreign exchange
(gain) loss
(25)
(16) Revenue
Foreign exchange
(gain) loss
Foreign exchange
(gain) loss
—
53
Foreign exchange
(gain) loss
(23)
— Interest expense
6
Interest expense
—
31
(15)
—
—
—
—
16
Derivatives in cash
flow hedging
relationships
Commodity contracts
Foreign exchange forwards on
commodity contracts
Foreign exchange forwards on
project hedges
Foreign exchange forwards on
US debt
Cross-currency swaps
Forward starting interest rate
swaps
OCI impact
271 OCI impact
(105) Net earnings impact
II. Effect of Non-Hedges
For the year ended Dec. 31, 2018, the Corporation recognized a net unrealized loss of $29 million (2017 - gain of $45
million, 2016 - loss of $63 million) related to commodity derivatives.
For the year ended Dec. 31, 2018, a gain of $3 million (2017 - gain of $28 million, 2016 - gain of $9 million) related to foreign
exchange and other derivatives was recognized, which is comprised of net unrealized gains of $4 million (2017 - losses of
$2 million, 2016 - gains of $4 million) and net realized losses of $1 million (2017 - gains of $30 million, 2016 - gains of $5
million).
I. Financial Assets Provided as Collateral
F. Collateral
At Dec. 31, 2018, the Corporation provided $105 million (2017 - $67 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 included in accounts receivable in the Consolidated Statements of Financial Position.
II. Financial Assets Held as Collateral
At Dec. 31, 2018, the Corporation held $17 million (2017 - $21 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 included in accounts payable in the Consolidated
Statements 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, 2018, the Corporation had posted collateral of $120 million (Dec. 31, 2017 - $131 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 $120 million (Dec. 31,
2017 - $96 million) of collateral to its counterparties.
F63
TRANSALTA CORPORATION F63
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
Inventory held in the normal course of business, which includes coal, emission credits, parts and materials, and natural gas,
16. Inventory
is valued at the lower of cost and net realizable value. Inventory held for trading, 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, 2016
Net addition
Change in foreign exchange rates
Balance, Dec. 31, 2017
Net addition
Change in foreign exchange rates
Balance, Dec. 31, 2018
No inventory is pledged as security for liabilities.
2018
113
108
7
4
10
242
2017
118
58
11
9
23
219
213
11
(5)
219
20
3
242
F64
TRANSALTA CORPORATION F64
TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
A reconciliation of the changes in the carrying amount of PP&E is as follows:
17. Property, Plant and Equipment
Land
Coal
generation
Gas
generation
Renewable
generation
Mining property
and equipment
Assets under
construction
Capital spares
and other(1)
Total
Cost
As at Dec. 31, 2016
Additions
Additions - finance lease
Disposals
Impairment charge - Sundance Unit 1 (Note 4)
Revisions and additions to decommissioning and
restoration costs
Retirement of assets
Change in foreign exchange rates
Transfers(2)(3)
As at Dec. 31, 2017
Additions(4)
Additions - finance lease
Disposals
Impairment charges (Note 7)
Revisions and additions to decommissioning
and restoration costs
Retirement of assets
Change in foreign exchange rates
Transfers
As at Dec. 31, 2018
Accumulated depreciation
As at Dec. 31, 2016
Depreciation
Retirement of assets
Disposals
Change in foreign exchange rates
Transfers(2)
As at Dec. 31, 2017
Depreciation
Retirement of assets
Disposals
Change in foreign exchange rates
Transfers
As at Dec. 31, 2018
Carrying amount
As at Dec. 31, 2016
As at Dec. 31, 2017
As at Dec. 31, 2018
95
5,876
1,525
3,212
1,265
—
—
—
—
—
—
(1)
1
95
—
—
(3)
—
—
—
2
—
94
—
—
—
—
—
—
—
—
—
—
—
—
—
95
95
94
—
—
—
(20)
82
(84)
(87)
—
—
(16)
—
12
(3)
3
121
5,888
461
1,982
—
—
—
(38)
(12)
(47)
105
41
—
—
—
—
(1)
(17)
(13)
13
—
—
(1)
—
15
(4)
(23)
29
—
14
(1)
—
42
(22)
(7)
24
3,228
1,315
1
—
—
(11)
(3)
(6)
26
51
—
10
(1)
—
(16)
(16)
7
39
5,937
1,964
3,286
1,338
3,212
1,027
351
(62)
—
(67)
(3)
67
(2)
(11)
(1)
(8)
3,431
1,072
306
(56)
—
84
—
79
(13)
—
(3)
(7)
922
123
(3)
(1)
(4)
—
1,037
123
(2)
—
6
(3)
3,765
1,128
1,161
2,664
2,457
2,172
498
910
836
2,290
2,191
2,125
659
76
(18)
—
(4)
—
713
125
(12)
(1)
5
—
830
606
602
508
407
334
—
—
—
—
—
(2)
(644)
95
275
—
—
—
—
—
4
(174)
200
—
—
—
—
—
—
—
—
—
—
—
—
—
407
95
200
393
12,773
4
—
(1)
—
—
(6)
(2)
(18)
338
14
(19)
(20)
151
(119)
(119)
(26)
370
12,973
8
—
(3)
—
—
(4)
—
12
383
284
10
(7)
(49)
(32)
(90)
131
(18)
13,202
129
5,949
18
(5)
—
—
—
635
(90)
(12)
(76)
(11)
142
6,395
16
—
(4)
—
—
649
(83)
(5)
92
(10)
154
7,038
264
228
229
6,824
6,578
6,164
(1) Includes major spare parts and stand-by equipment available, but not in service, and spare parts used for routine, preventive or planned maintenance, and the
Australian gas pipeline.
(2) In 2017, net transfers of $14 million relate to the transfer of gas equipment to finance lease receivables.
(3) During the second quarter of 2017, the Corporation reclassified approximately $13 million of capital spares and other assets to inventory.
(4) Includes $7 million related to the acquisition of Big Level.
The Corporation capitalized $2 million of interest to PP&E in 2018 (2017 - $9 million) at a weighted average rate of 4.454
per cent (2017 – 5.87 per cent). Finance lease additions in 2018 and 2017 are for mining equipment at the Highvale mine.
The carrying amount of total assets under finance leases as at Dec. 31, 2018, was $65 million (2017 - $65 million).
F65
TRANSALTA CORPORATION F65
TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
Goodwill acquired through business combinations has been allocated to CGUs that are expected to benefit from the
18. Goodwill
synergies of the acquisitions. Goodwill by segments are as follows:
As at Dec. 31
Hydro
Wind and Solar
Energy Marketing
Total goodwill
2018
2017
259
175
30
464
259
174
30
463
For the purposes of the 2018 annual goodwill impairment review, the Corporation determined the recoverable amounts
of the Wind and Solar segment 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. In 2018, the Corporation relied
on the recoverable amounts determined in 2016 for the Hydro and Energy Marketing segments in performing the 2018
annual goodwill impairment review. No impairment of goodwill arose for any segment.
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 2018
models ranged between $6 to $179 per MWh during the forecast period (2017 - $22 to $218 per MWh). Discount rates
used for the goodwill impairment calculation in 2018 ranged from 5.3 per cent to 6.2 per cent (2017 – 5.5 per cent to 6.0
per cent). No reasonable possible change in the assumptions would have resulted in an impairment of goodwill.
F66
TRANSALTA CORPORATION F66
TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
A reconciliation of the changes in the carrying amount of intangible assets is as follows:
19. Intangible Assets
Coal rights
Software
and other
Power
sale
contracts
Intangibles
under
development
Total
Cost
As at Dec. 31, 2016
Additions
Change in foreign exchange rates
Transfers
As at Dec. 31, 2017
Additions(1)
Retirements and disposals(2)
Change in foreign exchange rates
Transfers
As at Dec. 31, 2018
Accumulated amortization
As at Dec. 31, 2016
Amortization
Change in foreign exchange rates
Transfers
As at Dec. 31, 2017
Amortization
Retirements and disposals
Change in foreign exchange rates
Transfers
As at Dec. 31, 2018
Carrying amount
As at Dec. 31, 2016
As at Dec. 31, 2017
As at Dec. 31, 2018
178
—
—
—
178
—
—
—
7
185
115
8
—
2
125
9
—
—
(17)
117
63
53
68
268
31
(3)
18
314
—
(2)
3
24
339
163
24
1
—
188
32
(1)
2
—
221
105
126
118
223
—
—
—
223
—
—
—
14
237
60
9
—
(2)
67
9
—
—
20
96
163
156
141
24
20
—
(15)
29
53
—
—
(36)
46
—
—
—
—
—
—
—
—
—
—
24
29
46
693
51
(3)
3
744
53
(2)
3
9
807
338
41
1
—
380
50
(1)
2
3
434
355
364
373
(1) Includes $33 million related to the acquisition of Big Level.
(2) Includes the impairment charge of $1 million relating to Kent Breeze. See Note 7 for further details.
F67
TRANSALTA CORPORATION F67
TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
The components of other assets are as follows:
20. Other Assets
As at Dec. 31
South Hedland prepaid transmission access and distribution costs
Deferred licence fees
Project development costs
Deferred service costs
Long-term prepaids and other assets
Loan receivable
Keephills Unit 3 transmission deposit
Total other assets
2018
2017
72
11
47
12
53
37
2
75
13
53
15
44
33
4
234
237
South Hedland prepaid electricity transmission and distribution costs are costs that are amortized on a straight-line basis
over the South Hedland PPA contract life.
Deferred licence fees consist primarily of licences 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 licences relate.
Project development costs are primarily comprised of the Corporation’s Sundance 7 project in Alberta and project costs
for the Pioneer Pipeline project (Note 4(A)). 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 four years and an option for its partner to re-enter the development projects of TAMA Power at accumulated
cost during this period. Some projects were written off in 2018 as they are no longer proceeding (see Note 7(B)).
Deferred service costs are TransAlta’s contracted payments for shared capital projects required at the Genesee Unit 3 and
Keephills Unit 3 sites. These costs are amortized over the life of these projects.
Long-term prepaids and other assets include the funded portion of the TransAlta Energy Transition Bill commitments
discussed in Note 33.
The loan receivable relates to the advancement by the Corporation's subsidiary, Kent Hills Wind LP, of $37 million (2017
- $38 million) (net) of the Kent Hills Wind bond financing proceeds to its 17 per cent partner. The loan bears interest at
4.55 per cent, with interest payable quarterly, commencing on Dec. 31, 2017, is unsecured and matures on Oct. 2, 2022.
The current portion of nil (2017 - $5 million) is included in accounts receivable and the long-term portion of the $37 million
(2017 - $33 million) is included in other assets.
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 four years to 2021, as long as certain performance
criteria are met.
F68
TRANSALTA CORPORATION F68
TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
The change in decommissioning and other provision balances is as follows:
21. Decommissioning and Other Provisions
Decommissioning and
restoration
Other
Total
Balance, Dec. 31, 2016
Liabilities incurred
Liabilities settled
Liabilities disposed(1)
Accretion
Revisions in estimated cash flows(2)
Revisions in discount rates(2)
Reversals
Change in foreign exchange rates
Balance, Dec. 31, 2017
Liabilities incurred
Liabilities settled
Accretion
Acquisition of liabilities (Big Level)
Revisions in estimated cash flows
Revisions in discount rates
Reversals
Change in foreign exchange rates
Balance, Dec. 31, 2018
293
3
(19)
(8)
23
41
110
—
(6)
437
5
(31)
24
2
(37)
—
7
407
50
19
(31)
—
—
1
—
(4)
(2)
33
17
(10)
—
8
3
—
(5)
3
49
343
22
(50)
(8)
23
42
110
(4)
(8)
470
22
(41)
24
8
5
(37)
(5)
10
456
(1) Relates to the disposition of the Solomon power station and the sale of the Wintering Hills wind facility.
(2) During 2017, mainly as a result of the OCA (see Note 4(O)), the discount rates used for the Canadian coal and mining operations decommissioning provisions were
changed to the use of 5 to 15-year rates. The use of lower, shorter-term discount rates increased the corresponding liabilities. On average, these rates decreased by
approximately 1.60 to 2.10 per cent. Additionally, the amount and timing of cash outflows for certain Canadian coal plants and mining operations was also revised,
resulting in an increase to the corresponding liabilities.
Balance, Dec. 31, 2017
Current portion
Non-current portion
Balance, Dec. 31, 2018
Current portion
Non-current portion
Decommissioning and
restoration
437
40
397
407
35
372
Other
33
27
6
49
35
14
Total
470
67
403
456
70
386
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
A. Decommissioning and Restoration
estimates that the undiscounted amount of cash flow required to settle these obligations is approximately $1 billion, which
will be incurred between 2019 and 2073. The majority of the costs will be incurred between 2020 and 2050. At Dec. 31,
2018, the Corporation had provided a surety bond in the amount of US$139 million (2017 - US$139 million) in support of
future decommissioning obligations at the Centralia coal mine. At Dec. 31, 2018, the Corporation had provided letters of
credit in the amount of $122 million (2017 - $120 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.
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.
B. Other Provisions
F69
TRANSALTA CORPORATION F69
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
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.
22. Credit Facilities, Long-Term Debt and Finance Lease Obligations
The amounts outstanding are as follows:
A. Amounts Outstanding
As at Dec. 31
2018
2017
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
Carrying
value
339
647
943
1,236
39
3,204
63
3,267
(130)
(18)
(148)
3,119
Face
value
339
651
955
1,250
39
3,234
Interest(1)
Carrying
value
3.8%
5.8%
5.4%
4.4%
9.2%
27
1,046
1,499
1,022
44
3,638
69
3,707
(729)
(18)
(747)
2,960
Face
value
27
1,051
1,510
1,032
44
3,664
Interest(1)
2.8%
6.0%
6.0%
4.3%
9.2%
(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, 2018 - US$0.7 billion (Dec. 31, 2017 - US$1.2 billion).
(4) Includes US$1 million at Dec. 31, 2018 (Dec. 31, 2017 - US$27 million).
(5) Includes US$21 million at Dec. 31, 2018 (Dec. 31, 2017 - US$24 million) of tax equity financing.
Credit facilities are comprised of the Corporation's $1.25 billion committed syndicated bank credit facility expiring in 2022,
TransAlta Renewable's $500 million committed syndicated bank credit facility expiring in 2022 and the Corporation's three
bilateral credit facilities totalling $240 million expiring in 2020. The $1.75 billion (Dec. 31, 2017 - $1.5 billion) committed
syndicated bank facilities are 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, US LIBOR, or US base rate - in accordance with a pricing grid that is standard for such facilities.
During 2018, the Corporation's US$200 million committed facility was cancelled and the Corporation's committed
syndicated bank credit facility was increased by $250 million.
During 2017:
▪
TransAlta Renewables entered into a syndicated credit agreement giving it access to a $500 million committed credit
facility. The agreement is fully committed for four years. Interest rates on the credit facilities vary depending on the
option selected - Canadian prime, bankers' acceptances, US LIBOR, or US base rate - in accordance with a pricing grid
that is standard for such facilities. The facility is subject to a number of customary covenants and restrictions in order
to maintain access to the funding commitments. In conjunction with the credit agreement, the $350 million credit
facility provided by TransAlta was cancelled.
The Corporation has a total of $2.0 billion (Dec. 31, 2017 - $2.0 billion) of committed credit facilities, including TransAlta
Renewables’ credit facility of $0.5 billion (Dec. 31, 2017 - $0.5 billion). In total, $0.9 billion (Dec. 31, 2017 - $1.4 billion) is
not drawn. At Dec. 31, 2018, the $1.1 billion (Dec. 31, 2017 - $627 million) of credit utilized under these facilities was
comprised of actual drawings of $339 million (Dec. 31, 2017 - $27 million) and letters of credit of $720 million (Dec. 31,
F70
TRANSALTA CORPORATION F70
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
2017 - $677 million). The Corporation is in compliance with the terms of the credit facilities and all undrawn amounts are
fully available. In addition to the $0.9 billion available under the credit facilities, the Corporation also has $89 million of
available cash and cash equivalents and $35 million ($27 million principal portion) in cash restricted for repayment of the
OCP bonds (see section E below).
Debentures bear interest at fixed rates ranging from 5.0 per cent to 7.3 per cent and have maturity dates ranging from
2020 to 2030.
On Aug. 2, 2018, the Corporation early redeemed all of its outstanding 6.40 per cent debentures, which were due Nov. 18,
2019, for the principal amount of $400 million. The redemption price was $425 million in aggregate, including a $19 million
prepayment premium recognized in net interest expense and $6 million in accrued and unpaid interest to the redemption
date.
Senior notes bear interest at rates ranging from 4.5 per cent to 6.5 per cent and have maturity dates ranging from 2022 to
2040.
During 2018, the Corporation early redeemed its outstanding 6.650 per cent US$500 million senior notes due May 15,
2018. The repayment was hedged with foreign exchange forwards and cross currency swaps. The redemption price for the
notes was approximately $617 million (US$516 million), including a $5 million early redemption premium, recognized in
net interest expense, and $14 million in accrued and unpaid interest to the redemption date.
During 2017, the Corporation's US$400 million 1.90 per cent senior note matured and was paid out using existing liquidity.
The repayment was hedged with a currency swap. The maturity value of the bond was $434 million.
A total of US$400 million (2017 - US$480 million) of the senior notes has been designated as a hedge of the Corporation’s
net investment in US foreign operations.
Non-recourse debt consists of bonds and debentures that have maturity dates ranging from 2023 to 2033 and bear interest
at rates ranging from 2.95 per cent to 6.26 per cent.
Paid out the US$25 million non-recourse debt related to its Mass Solar projects.
During 2018, the Corporation:
▪
▪ Monetized the OCA and closed a $345 million bond offering through its indirect wholly owned subsidiary TransAlta
OCP by way of private placement. The non-recourse amortizing bonds bear interest from their date of issuance at a
rate of 4.509 per cent per annum, payable semi-annually and maturing on Aug. 5, 2030.
During 2017, TransAlta Renewables closed a $260 million non-recourse bond offering by way of a private placement. At
the same time, the Corporation early redeemed the $191 million face value CHD non-recourse debentures on Oct. 12,
2017. The redemption price was $201 million, including an early redemption premium of $6 million, recognized in net
interest expense and accrued and unpaid interest of $4 million.
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.
TransAlta’s debt has terms and conditions, including financial covenants, that are considered normal and customary. As at
Dec. 31, 2018, the Corporation was in compliance with all debt covenants.
The Melancthon Wolfe Wind, Pingston, TAPC Holdings LP, New Richmond, KHWLP and OCP non-recourse bonds with a
carrying value of $1,235 million (Dec. 31, 2017 - $1,022 million) are subject to customary financing conditions and
B. Restrictions on Non-Recourse Debt
covenants that may restrict the Corporation’s ability to access funds generated by the facilities’ operations. Upon meeting
certain distribution tests, typically performed once per quarter, the funds are able to be distributed by the subsidiary
entities to their respective parent entity. These conditions include meeting a debt service coverage ratio prior to
distribution, which was met by these entities in the fourth quarter. However, funds in these entities that have accumulated
since the fourth quarter test will remain there until the next debt service coverage ratio can be calculated in the first quarter
of 2019. At Dec. 31, 2018, $33 million (Dec. 31, 2017 -$35 million) of cash was subject to these financial restrictions.
F71
TRANSALTA CORPORATION F71
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
Additionally, certain non-recourse bonds require that certain reserve accounts be established and funded through cash
held on deposit and/or by providing letters of credit. The Corporation has elected to use letters of credit as at Dec. 31,
2018.
Non-recourse debts of $766 million in total (Dec. 31, 2017 - $848 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 certain renewable
C. Security
generation facilities with total carrying amounts of $1,021 million at Dec. 31, 2018 (Dec. 31, 2017 - $1,107 million). At Dec.
31, 2018, a non-recourse bond of approximately $127 million (Dec. 31, 2017 - $174 million) was secured by a first ranking
charge over the equity interests of the issuer that issued the non-recourse bond.
The new TransAlta OCP bonds with a carrying value of $342 million are secured by the assets of TransAlta OCP, including
the right to annual capital contributions and OCA payments from the Government of Alberta. Under the OCA, the
Corporation receives annual cash payments on or before July 31 of approximately $40 million (approximately $37 million,
net to the Corporation), commencing Jan. 1, 2017, and terminating at the end of 2030.
D. Principal Repayments
Principal repayments(1)
(1) Excludes impact of derivatives.
2019
130
2020
486
2021
91
2022
947
2023
141
2024 and
thereafter
1,439
Total
3,234
The Corporation has $31 million (Dec. 31, 2017 - $30 million) of restricted cash related to the Kent Hills project financing
that is held in a construction reserve account. The proceeds will be released from the construction reserve account upon
E. Restricted Cash
certain conditions being met, which are expected to be finalized in Q1 2019.
The Corporation also has $35 million (Dec. 31, 2017 - nil) of restricted cash related to the TransAlta OCP bonds, which is
required to be held in a debt service reserve account to fund the next scheduled debt repayment in February 2019.
Amounts payable for mining assets and other finance leases are as follows:
F. Finance Lease Obligations
As at Dec. 31
2018
2017
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
Minimum
lease
payments
Present value of
minimum lease
payments
Minimum
lease
payments
Present value of
minimum lease
payments
20
38
11
69
—
69
21
39
10
70
7
63
18
45
63
20
35
8
63
—
63
20
43
15
78
9
69
18
51
69
Letters of credit issued by TransAlta are drawn on its committed syndicated credit facility, its $240 million bilateral
committed credit facilities and its uncommitted $100 million demand letter of credit facility. Letters of credit issued by
G. Letters of Credit
TransAlta Renewables are drawn on its uncommitted $100 million demand letter of credit facility.
F72
TRANSALTA CORPORATION F72
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
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, 2018, was $720 million (2017 - $677
million) with no (2017 - nil) amounts exercised by third parties under these arrangements.
The components of defined benefit obligation and other long-term liabilities are as follows:
23. Defined Benefit Obligation and Other Long-Term Liabilities
As at Dec. 31
Defined benefit obligation (Note 28)
Long-term incentive accruals (Note 27)
Other
Total(1)
2018
227
9
51
287
2017
235
16
46
297
(1) 2017 deferred revenues of $62 million have been reclassified on the statement of financial position to contract liabilities as required under IFRS 15. See Note 3(A)
and Note 5(B) for further details.
24. Common Shares
TransAlta is authorized to issue an unlimited number of voting common shares without nominal or par value.
A. Issued and Outstanding
As at Dec. 31
Issued and outstanding, beginning of year
Purchased and cancelled under the NCIB
Amounts receivable under Employee Share Purchase Plan
Issued and outstanding, end of year
2018
2017
Common
shares
(millions)
287.9
(3.3)
284.6
—
284.6
Common
shares
(millions)
287.9
—
287.9
—
287.9
Amount
3,094
(35)
3,059
—
3,059
Amount
3,095
—
3,095
(1)
3,094
Shares purchased by the Corporation under the NCIB are recognized as a reduction to share capital equal to the average
carrying value of the common shares. Any difference between the aggregate purchase price and the average carrying
B. NCIB Program
value of the common shares is recorded in retained earnings.
The following are the effects of the Corporation's purchase and cancellation of the common shares during the year ended
Dec. 31, 2018:
Total shares purchased(1)
Average purchase price per share
Total cost
Weighted average book value of shares cancelled
Increase to retained earnings
3,264,500
$
7.02
23
35
12
(1) Includes 204,000 shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date.
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
C. Shareholder Rights Plan
F73
TRANSALTA CORPORATION F73
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
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 acquires 20 per cent or more of the Corporation’s common
shares, other than by way of a “permitted bid” or a "competing 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.
Year ended Dec. 31
D. Earnings per Share
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
2018
(248)
287
(0.86)
2017
(190)
288
(0.66)
2016
117
288
0.41
On Oct. 10, 2018, the Corporation declared a quarterly dividend of $0.04 per common share, payable on Jan. 1, 2019.
E. Dividends
On Dec. 14, 2018, the Corporation declared a quarterly dividend of $0.04 per common share, payable on Apr. 1, 2019.
There have been no other transactions involving common shares between the reporting date and the date of completion
of these consolidated financial statements.
25. Preferred Shares
All preferred shares issued and outstanding are non-voting cumulative redeemable fixed rate first preferred shares.
A. Issued and Outstanding
As at Dec. 31
Series
Series A
Series B
Series C
Series E
Series G
Issued and outstanding, end of year
2018
2017
Number of
shares
(millions)
Number of
shares
(millions)
Amount
Amount
10.2
1.8
11.0
9.0
6.6
38.6
248
45
269
219
161
942
10.2
1.8
11.0
9.0
6.6
38.6
248
45
269
219
161
942
I. Series E Cumulative Redeemable Rate Reset Preferred Shares Conversion
On Sept. 17, 2017, the Corporation announced that, after taking into account all election notices received by the Sept. 15,
2017, deadline for the conversion of the Cumulative Redeemable Rate Reset Preferred Shares, Series E (the “Series E
Shares”) into Cumulative Redeemable Floating Rate Preferred Shares Series F (the “Series F Shares”), there were 133,969
Series E Shares tendered for conversion, which was less than the one million shares required to give effect to conversions
into Series F Shares. Therefore, none of the Series E Shares were converted into Series F Shares on Sept. 30, 2017. As a
result, the Series E Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when
declared by the Board. The annual dividend rate for the Series E Shares for the five-year period from and including Sept.
30, 2017, to, but excluding, Sept. 30, 2022, will be 5.194 per cent, which is equal to the five-year Government of Canada
bond yield of 1.544 per cent, determined as of Aug. 31, 2017, plus 3.65 per cent, in accordance with the terms of the Series
E Shares.
II. Series C Cumulative Redeemable Rate Reset Preferred Shares Conversion
On June 16, 2017, the Corporation announced that after, taking into account all election notices received by the June 15,
2017, deadline for the conversion of the Cumulative Redeemable Rate Reset Preferred Shares, Series C (the “Series C
F74
TRANSALTA CORPORATION F74
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
Shares”) into Cumulative Redeemable Floating Rate Preferred Shares Series D (the “Series D Shares”), there were 827,628
Series C Shares tendered for conversion, which was less than the one million shares required to give effect to conversions
into Series D Shares. Therefore, none of the Series C Shares were converted into Series D Shares on June 30, 2017. As a
result, the Series C Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when
declared by the Board. The annual dividend rate for the Series C Shares for the five-year period from and including June
30, 2017, to, but excluding, June 30, 2022, will be 4.027 per cent, which is equal to the five-year Government of Canada
bond yield of 0.927 per cent, determined as of May 31, 2017, plus 3.10 per cent, in accordance with the terms of the Series
C Shares.
III. 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, 2018.
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 the 90 day
Treasury Bill rate plus 2.03%.
IV. 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:
▪
Redeemable at the option of the Corporation, in whole or in part, for $25.00 per share, plus all declared and unpaid
dividends at the time of redemption.
Convertible at the holder’s option into a specified series of non-voting cumulative redeemable floating rate first
preferred shares that pay cumulative floating rate quarterly cash dividends, as approved by the Board, based on the
sum of the then Government of Canada 90-day Treasury Bill rate (the floating rate “Benchmark”) plus a specified
spread. The cumulative floating rate first preferred shares are also redeemable at the option of the Corporation and
convertible back into each original cumulative fixed rate first preferred share series, at each subsequent Rate Reset
Date, on the same terms as noted above.
▪
Characteristics specific to each first preferred share series as at Dec. 31, 2018, are as follows:
Series
Rate during term
Annual dividend
rate per share ($)
Next
conversion
date
Rate spread
over Benchmark
(per cent)
Convertible to
Series
A
B
C
D
E
F
G
H
Fixed
Floating
Fixed
Floating
Fixed
Floating
Fixed
Floating
0.67725
0.93575
1.00675
—
March 31, 2021
March 31, 2021
June 30, 2022
—
1.29850
Sept. 30, 2022
—
—
1.32500
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
F75
TRANSALTA CORPORATION F75
TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
The following table summarizes the preferred share dividends declared in 2018, 2017 and 2016:
B. Dividends
Total dividends declared ($)
Series
A
B
C
E
G
Total for the year
2018
2017
2016
9
1
14
15
11
50
5
1
9
8
7
30
10
1
16
14
11
52
The components of, and changes in, accumulated other comprehensive income (loss) are as follows:
26. Accumulated Other Comprehensive Income
2018
2017
Currency translation adjustment
Opening balance, Jan. 1
Losses on translating net assets of foreign operations, net of reclassifications to net earnings, net of tax(1)
Gains 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 (losses) on defined benefit plans, net of tax(4)
Balance, Dec. 31
Other
Opening balance, Jan. 1
Change in ownership of TransAlta Renewables
Intercompany investments at FVOCI
Balance, Dec. 31
Accumulated other comprehensive income
(1) Net of income tax of nil for the year ended Dec. 31, 2018 (2017 - 11 million ).
(2) Net of income tax of nil for the year ended Dec. 31, 2018 (2017 - 4 million ).
(3) Net of income tax of 12 million for the year ended Dec. 31, 2018 (2017 - 108 million ).
(4) Net of income tax of 5 million for the year ended Dec. 31, 2018 (2017 - 4 million ).
(26)
84
(41)
17
562
(54)
508
(44)
15
(29)
(3)
4
(16)
(15)
481
(1)
(89)
64
(26)
456
106
562
(38)
(6)
(44)
(18)
4
11
(3)
489
F76
TRANSALTA CORPORATION F76
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
The Corporation has the following share-based payment plans:
27. Share-Based Payment Plans
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
A. Performance Share Unit (“ PSU” ) and Restricted Share Unit (“ RSU” ) Plan
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 two to three performance measures that are established at the time of each grant. 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 TSX.
The pre-tax compensation expense related to PSUs and RSUs in 2018 was $8 million (2017 - $15 million , 2016 - $17
million), which is included in operations, maintenance and administration expense in the Consolidated Statements of
Earnings (Loss).
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
B. Deferred Share Unit (“ DSU” ) Plan
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 nil in 2018
(2017 - $1 million, 2016 - $3 million).
The Corporation is authorized to grant options to purchase up to an aggregate of 13 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
C. Stock Option Plans
all full-time employees, including executives, designated by the Human Resources Committee from time to time.
In February 2018, the Corporation granted executive officers of the Corporation a total of 0.7 million stock options with
an exercise price of $7.45 that vest after a three-year period and expire seven years after issuance. In March 2017, the
Corporation granted executive officers of the Corporation a total of 0.7 million stock options with an exercise price of $7.25
that vest after a three-year period and expire seven years after issuance. 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 these grants during 2018 was
approximately $1 million (2017 - approximately $1 million, 2016 - less than $1 million).
The total options outstanding and exercisable under these stock option plans at Dec. 31, 2018, are outlined below:
Range of exercise prices
($ per share)
5.00 - 8.00
22.00 - 30.00(1)
5.00 - 30.00
(1) Options currently exercisable.
Options outstanding
Weighted
average
remaining
contractual
life (years)
Weighted
average
exercise
price
($ per share)
Number of
options
(millions)
2.3
0.5
2.8
5
1.1
4.3
6.71
23.69
9.66
F77
TRANSALTA CORPORATION F77
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
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
D. Employee Share Purchase Plan
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, 2018, amounts receivable from employees under the plan was nil (2017 - less than $1 million).
On Jan. 14, 2016, the Corporation suspended its employee share purchase plan.
28. Employee Future Benefits
The Corporation sponsors registered pension plans in Canada and the US covering substantially all employees of the
Corporation in these countries and specific named employees working internationally. These plans have defined benefit
A. Description
and defined contribution options, and in Canada there is an additional non-registered supplemental plan for eligible
employees whose annual earnings exceed the Canadian income tax limit. Except for the Highvale pension plan acquired in
2013, the Canadian and US defined benefit pension plans are closed to new entrants. The US defined benefit pension plan
was frozen effective Dec. 31, 2010, resulting in no future benefits being earned. The supplemental pension plan was closed
as of Dec. 31, 2015, and a new defined contribution supplemental pension plan commenced for executive members effective
Jan. 1, 2016. Current executives as of Dec .31, 2015, were grandfathered into the old supplemental plan.
The latest actuarial valuation for accounting purposes of the US pension plan was at Jan. 1, 2018. The latest actuarial
valuation for accounting purposes of the Highvale and Canadian pension plans was at Dec. 31, 2016. 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, 2018.
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 US.
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 posted
a letter of credit in March 2018 for the amount of $80 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 US plans were as at Dec. 31, 2016, and Jan. 1, 2018, respectively. The measurement date used to determine the present
value obligation for both plans was Dec. 31, 2018.
The Corporation provides several defined contribution plans, including an Australian superannuation plan and a US 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 F78
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
The costs recognized in net earnings during the year on the defined benefit, defined contribution and other post-
employment benefits plans are as follows:
B. Costs Recognized
Year ended Dec. 31, 2018
Current service cost
Administration expenses
Interest cost on defined benefit obligation
Interest on plan assets
Defined benefit expense
Defined contribution expense
Net expense
Year ended Dec. 31, 2017
Current service cost
Administration expenses
Interest cost on defined benefit obligation
Interest on plan assets
Defined benefit expense
Defined contribution expense
Net expense
Year ended Dec. 31, 2016
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
9
1
18
(13)
15
10
25
2
—
3
—
5
—
5
1
—
1
—
2
—
2
12
1
22
(13)
22
10
32
Registered
Supplemental
Other
Total
7
2
20
(15)
14
11
25
2
—
3
—
5
—
5
1
—
1
—
2
—
2
10
2
24
(15)
21
11
32
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
F79
TRANSALTA CORPORATION F79
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
The status of the defined benefit pension and other post-employment benefit plans is as follows:
C. Status of Plans
As at Dec. 31, 2018
Supplemental
Registered
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, 2017
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
368
(514)
(146)
(5)
(141)
(146)
13
(80)
(67)
(5)
(62)
(67)
Other
—
(25)
(25)
(1)
(24)
(25)
Registered
Supplemental
Other
416
(561)
(145)
(4)
(141)
(145)
12
(87)
(75)
(6)
(69)
(75)
—
(27)
(27)
(2)
(25)
(27)
Total
381
(619)
(238)
(11)
(227)
(238)
Total
428
(675)
(247)
(12)
(235)
(247)
The fair value of the plan assets of the defined benefit pension and other post-employment benefit plans is as follows:
D. Plan Assets
Registered
Supplemental
Other
Total
As at Dec. 31, 2016
Interest on plan assets
Net return on plan assets
Contributions
Benefits paid
Administration expenses
Effect of translation on US plans
As at Dec. 31, 2017
Interest on plan assets
Net return on plan assets
Contributions
Benefits paid
Administration expenses
Effect of translation on US plans
As at Dec. 31, 2018
423
15
26
6
(51)
(2)
(1)
416
13
(25)
5
(42)
(1)
2
368
10
—
—
6
(4)
—
—
12
—
—
6
(5)
—
—
13
—
—
—
—
—
—
—
—
—
—
1
(1)
—
—
—
433
15
26
12
(55)
(2)
(1)
428
13
(25)
12
(48)
(1)
2
381
F80
TRANSALTA CORPORATION F80
TransAlta Corporation | 2018 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
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
Year ended Dec. 31, 2018
Equity securities
Canadian
US
International
Private
Bonds
AAA
AA
A
BBB
Below BBB
Money market and cash and cash equivalents
Total
Year ended Dec. 31, 2017
Equity securities
Canadian
US
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
—
(2)
(1)
65
26
101
—
48
64
39
21
3
14
381
—
—
—
1
—
—
—
—
—
—
1
Level I
Level II
Level III
—
—
—
—
—
—
—
1
—
(1)
—
76
31
118
—
43
71
44
25
5
14
427
—
—
—
1
—
—
—
—
—
—
1
65
26
101
1
48
64
39
22
3
12
381
Total
76
31
118
1
43
71
44
26
5
13
428
Plan assets do not include any common shares of the Corporation at Dec. 31, 2018, and Dec. 31, 2017. The Corporation
charged the registered plan $0.1 million for administrative services provided for the year ended Dec. 31, 2018 (2017 - $0.1
million).
F81
TRANSALTA CORPORATION F81
TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
The present value of the obligation for the defined benefit pension and other post-employment benefit plans is as follows:
E. Defined Benefit Obligation
Registered
Supplemental
Other
Total
Present value of defined benefit obligation as at Dec. 31, 2016
Current service cost
Interest cost
Benefits paid
Actuarial gain arising from demographic assumptions
Actuarial loss arising from financial assumptions
Actuarial gain (loss) arising from experience adjustments
Effect of translation on US plans
Present value of defined benefit obligation as at Dec. 31, 2017
Current service cost
Interest cost
Benefits paid
Actuarial (gain) loss arising from financial assumptions
Actuarial (gain) loss arising from experience adjustments
Effect of translation on US plans
Present value of defined benefit obligation as at Dec. 31, 2018
554
7
20
(51)
4
26
3
(2)
561
9
18
(42)
(35)
—
3
514
82
2
3
(4)
1
3
—
—
87
2
3
(5)
(7)
—
—
80
27
1
1
—
—
—
(1)
(1)
27
1
1
(1)
(2)
(1)
—
25
663
10
24
(55)
5
29
2
(3)
675
12
22
(48)
(44)
(1)
3
619
The weighted average duration of the defined benefit plan obligation as at Dec. 31, 2018 is 14 years.
The expected employer contributions for 2019 for the defined benefit pension and other post-employment benefit plans
are as follows:
F. Contributions
Expected employer contributions
Registered
Supplemental
5
4
Other
2
Total
11
F82
TRANSALTA CORPORATION F82
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
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:
G. Assumptions
(per cent)
Accrued benefit obligation
Discount rate
Rate of compensation increase
Assumed health care cost trend rate
Health care cost escalation(1)(3)
Dental care cost escalation
Benefit cost for the year
Discount rate
Rate of compensation increase
Assumed health care cost trend rate
Health care cost escalation(2)(4)
Dental care cost escalation
Provincial health care premium escalation
As at Dec. 31, 2018
As at Dec. 31, 2017
Registered Supplemental Other
Registered
Supplemental Other
3.9
2.5
—
—
3.3
2.6
—
—
—
3.8
3.0
—
—
3.3
3.0
—
—
—
3.9
—
7.1
4.0
3.4
—
7.6
4.0
—
3.3
2.9
—
—
3.7
2.6
—
—
—
3.3
3.0
—
—
3.6
3.0
—
—
—
3.4
—
7.8
4.0
3.7
—
7.9
4.0
—
(1) 2018 Post- and pre-65 rates: decreasing gradually to 4.5% by 2029 and remaining at that level thereafter for the US and decreasing gradually by 0.3% per year to
4.5% in 2027 for Canada.
(2) 2018 Post- and pre-65 rates: decreasing gradually to 4.5% by 2027 and remaining at that level thereafter for the US and decreasing gradually by 0.30% per year
to 4.5% in 2027 for Canada.
(3) 2017 Post- and pre-65 rates: decreasing gradually to 4.5% by 2027 and remaining at that level thereafter for the US and decreasing gradually by 0.30% per year
to 4.5% in 2027 for Canada.
(4) 2017 Post- and pre-65 rates: decreasing gradually to 4.5% by 2026 and remaining at that level thereafter for the US and decreasing gradually by 0.30% per year
to 5% in 2024 for Canada.
The following table outlines the estimated increase in the net defined benefit obligation assuming certain changes in key
assumptions:
H. Sensitivity Analysis
Year ended Dec. 31, 2018
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
US plans
Registered Supplemental Other
Pension Other
70
10
—
18
11
1
—
3
3
—
2
—
2
—
—
1
1
—
—
—
F83
TRANSALTA CORPORATION F83
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
Joint arrangements at Dec. 31, 2018, included the following:
29. Joint Arrangements
Joint operations
Segment
Ownership
(per cent) Description
Sheerness
Genesee Unit 3
Keephills Unit 3
Goldfields Power
Coal
Coal
Coal
Gas
Fort Saskatchewan Gas
Fortescue River
Gas Pipeline
McBride Lake
Soderglen
Pingston
Gas
Wind
Wind
Hydro
50
50
50
50
60
43
50
50
50
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
Hydro facility in British Columbia operated by TransAlta
30. Cash Flow Information
Year ended Dec. 31
A. Change in Non-Cash Operating Working Capital
(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
B. Changes in Liabilities from Financing Activities
Balance
Dec. 31,
2017
Net
cash
flows
New
leases
2018
2017
2016
58
19
—
(21)
(97)
(3)
(44)
(228)
(75)
8
(7)
186
2
(114)
Dividends
declared
Foreign exchange
impact Other
Long-term debt and finance lease
obligations
Dividends payable (common and
preferred)
Total liabilities from financing
activities
3,707
(540)
34
(86)
3,741
(626)
10
—
10
—
107
107
95
—
95
(5)
3
(2)
Balance
Dec. 31,
2016
Net
cash
flows
New
leases
Dividends
declared
Foreign exchange
impact Other
Long-term debt and finance lease
obligations
Dividends payable (common and
preferred)
Total liabilities from financing
activities
4,361
(545)
54
(86)
4,415
(631)
14
—
14
—
64
64
(115)
—
(115)
(8)
2
(6)
(23)
5
(4)
11
81
3
73
Balance
Dec. 31,
2018
3,267
58
3,325
Balance
Dec. 31,
2017
3,707
34
3,741
F84
TRANSALTA CORPORATION F84
TransAlta Corporation | 2018 Annual Integrated Report
TransAlta’s capital is comprised of the following:
31. Capital
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: principal portion of restricted cash on OCP Bonds(3)
Less: fair value asset of hedging instruments on long-term debt(4)
Total capital
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
2018
3,267
3,059
942
11
2017
3,707
3,094
942
10
(1,496)
(1,209)
481
1,137
(89)
(27)
(10)
489
1,059
(314)
—
(30)
7,275
7,748
Increase/
(decrease)
(440)
(35)
—
1
(287)
(8)
78
225
(27)
20
(473)
(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 principal portion of restricted cash on OCP bonds because this cash is restricted specifically to repay outstanding debt.
(4) The Corporation includes the fair value of economic and designated 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 2018, the Corporation continued to focus on reducing overall debt. The Corporation’s overall capital management
strategy and its objectives in managing capital have remained unchanged from Dec. 31, 2017, and are as follows:
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
A. Maintain an Investment Grade Credit Rating
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 Standard & Poor's (negative outlook), DBRS (stable outlook)
and Fitch Ratings (stable outlook). In December 2015, Moody's downgraded the Corporation below investment grade to
Ba1 with a stable outlook and in June 2018 Moody’s revised their rating outlook to positive from stable. During 2018, Fitch
Ratings reaffirmed the Corporation’s Unsecured Debt rating and Issuer Rating of BBB- with a stable outlook; DBRS
Limited reaffirmed the Corporation’s Unsecured Debt rating and Medium-Term Notes rating of BBB (low), the Preferred
Shares rating of Pfd-3 (low), and Issuer Rating of BBB (low) with a stable outlook; and Standard and Poor’s reaffirmed the
Corporation’s Unsecured Debt rating and Issuer Rating of BBB- with negative outlook. The Corporation is focused on
strengthening its financial position and cash flow coverage ratios to achieve stable investment grade credit ratings. Credit
ratings provide information relating to the Corporation's financing costs, liquidity and operations and affect the
Corporation's ability to obtain short-term and long-term financing and/or the cost of such financing. 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.
F85
TRANSALTA CORPORATION F85
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
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.
These ratios are summarized in the table below:
As at Dec. 31
Funds from operations before interest to adjusted interest coverage (times)
Adjusted funds from operations to adjusted net debt (%)
Adjusted net debt to comparable earnings before interest,
taxes, depreciation and amortization (times)
2018
4.8
20.8
3.7
2017
4.3
20.4
Target
4 to 5
20 to 25
3.6
3.0 to 3.5
Funds from Operations (“FFO”) before Interest to Adjusted Interest Coverage is calculated as FFO plus interest on debt
(net of capitalized interest) divided by interest on debt plus 50 per cent of dividends paid on preferred shares. 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. The Corporation’s
goal is to maintain this ratio in a range of four to five times.
Adjusted FFO to Adjusted Net Debt is calculated as 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). 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. 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 2018, the Corporation continued to strengthen its financial position and reduce debt.
Management routinely monitors forecasted net earnings, cash flows, capital expenditures and scheduled repayment of
debt with a goal of meeting the above ratio targets and to meet dividend and PP&E expenditure requirements.
B. Ensure Sufficient Cash and Credit is Available to Fund Operations, Pay Dividends, Distribute
For the years ended Dec. 31, 2018 and 2017, cash inflows and outflows are summarized below. The Corporation
Payments to Subsidiaries’ Non-Controlling Interests, Invest in PP&E and Make Acquisitions
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)
Inflow
(1) Includes growth capital associated with the South Hedland Power Station.
2018
2017
Increase
(decrease)
820
44
864
(46)
(40)
(165)
(277)
336
626
114
740
(46)
(40)
(172)
(338)
144
194
(70)
124
—
—
7
61
192
TransAlta maintains sufficient cash balances and committed credit facilities to fund periodic net cash outflows related to
its business. At Dec. 31, 2018, $0.9 billion (2017 - $1.4 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.
F86
TRANSALTA CORPORATION F86
TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
Details of the Corporation’s principal operating subsidiaries at Dec. 31, 2018, are as follows:
32. Related-Party Transactions
Subsidiary
TransAlta Generation Partnership
TransAlta Cogeneration, L.P.
Country
Canada
Canada
TransAlta Centralia Generation, LLC
US
TransAlta Energy Marketing Corp.
Canada
TransAlta Energy Marketing (U.S.), Inc.
US
TransAlta Energy (Australia), Pty Ltd.
Australia
TransAlta Renewables Inc.
Canada
Ownership
(per cent)
Principal activity
100
50.01
100
100
100
100
60.9
Generation and sale of electricity
Generation and sale of electricity
Generation and sale of electricity
Energy marketing
Energy marketing
Generation and sale of electricity
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
Share-based payments
2018
2017
2016
17
11
2
4
24
14
2
8
20
8
2
10
In addition to commitments disclosed elsewhere in the financial statements, the Corporation has other contractual
33. Commitments and Contingencies
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
Growth
TransAlta Energy Transition Bill
Total
2019
2020
2021
2022
2023
2024 and
thereafter
Total
28
9
158
64
8
324
6
597
15
10
160
86
8
79
7
365
13
6
27
32
8
144
6
236
11
4
24
17
7
—
6
69
12
3
24
8
4
—
6
57
157
—
95
34
45
—
—
236
32
488
241
80
547
31
331
1,655
Several of the Corporation’s plants have fixed price natural gas purchase and related transportation contracts in place.
Other purchase contracts relate to commitments for goods and services.
A. Natural Gas, Transportation and Other Purchase Contracts
F87
TRANSALTA CORPORATION F87
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
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
B. Transmission
tariff rate whether it is awarded immediately or delivered in the future after additional facilities are constructed.
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 with dates extending to
C. Coal Supply and Mining Agreements
2020.
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
commitments have been reduced due to the cessation of coal-fired emissions from the Genesee 3 and Sheerness coal-
fired plants on or before Dec. 31, 2030.
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.
D. Long-Term Service Agreements
TransAlta has operating leases in place for buildings, vehicles and various types of equipment.
E. Non-Cancellable Operating Leases
During the year ended Dec. 31, 2018, $8 million (2017 - $7 million, 2016 - $9 million) was recognized as an expense in
respect of these operating leases. Sublease payments received during 2018, 2017 and 2016 were less than $1 million. No
contingent rental payments were made in respect of these operating leases.
Commitments for growth relate to the Big Level, Antrim and Windrise wind development projects, the coal-to-gas
conversions, and to the Corporation's 50% share of the Pioneer Pipeline project.
F. Growth
On July 30, 2015, the Corporation announced that it would formalize its commitment to invest US$55 million over the
remaining nine-year life of the Centralia coal plant to support energy efficiency, economic and community development,
G. TransAlta Energy Transition Bill Commitments
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, 2018, the Corporation has funded approximately US$33
million of the commitment, which is recognized in other assets in the Consolidated Statements of Financial Position.
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.
H. Other
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.
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
I. Contingencies
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 has been participating in a line loss rule proceeding before the Alberta Utilities Commission ("AUC"). The
AUC determined that it has the ability to retroactively adjust line loss charges going back to 2006 and directed the AESO
to, among other things, perform such retroactive calculations. The various decisions by the AUC are, however, subject to
appeal and challenge. A recent decision by the AUC determined the methodology to be used retroactively and it is now
possible to estimate the total retroactive potential exposure faced by the Corporation for its non-PPA MWs. The current
F88
TRANSALTA CORPORATION F88
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
estimate of exposure based on known data is $15 million and therefore the Corporation increased the provision from $7.5
million to $15 million in 2018.
II. FMG Disputes
The Corporation is currently engaged in two disputes with Fortescue Metals Group Ltd. ("FMG"). The first arose as a result
of FMG’s purported termination of the South Hedland PPA. TransAlta has sued FMG, seeking payment of amounts invoiced
and not paid under the South Hedland PPA, as well as a declaration that the PPA is valid and in force. FMG, on the other
hand, seeks a declaration that the PPA was lawfully terminated.
The second matter involves FMG’s claims against TransAlta related to the transfer of the Solomon Power Station to FMG.
FMG claims certain amounts related to the condition of the facility while TransAlta claims certain outstanding costs that
should be reimbursed.
III. Balancing Pool Dispute
Pursuant to a written agreement, the Balancing Pool paid the Corporation approximately $157 million on March 29, 2018,
as part of the net book value payment required on termination of the Sundance B and C PPAs. The Balancing Pool, however,
excluded certain mining and corporate assets that the Corporation believes should be included in the net book value
calculation, which amounts to an additional $56 million. The dispute is currently proceeding through arbitration.
34. Segment Disclosures
The Corporation has eight reportable segments as described in Note 1.
A. Description of Reportable Segments
I. Earnings Information
B. Reported Segment Earnings (Loss) and Segment Assets
Australian
Canadian
Gas
Coal
Year ended Dec. 31, 2018
Canadian
Gas
US
Coal
Wind and
Energy
Solar Hydro
Marketing Corporate
Total
912
666
246
171
241
38
13
(198)
442
314
128
61
74
—
5
—
(19)
(12)
—
—
232
96
136
48
43
—
1
—
44
8
165
8
157
37
49
—
—
—
71
—
282
17
265
50
110
12
8
(6)
91
—
156
6
150
38
30
—
3
—
79
—
67
—
67
24
2
—
—
—
41
—
Revenues
Fuel and purchased power
Gross margin
Operations, maintenance and
administration
Depreciation and amortization
Asset impairment charge
Taxes, other than income taxes
Net other operating expense
(income)
Operating income (loss)
Finance lease income
Net interest expense
Foreign exchange loss
Gain on sale of assets and
other
Losses before income taxes
(7) 2,249
(7) 1,100
— 1,149
86
25
23
1
515
574
73
31
— (204)
(135)
160
—
8
(250)
(15)
1
(96)
F89
TRANSALTA CORPORATION F89
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
Year ended Dec. 31, 2017
Revenues
Fuel and purchased power
Gross margin
Operations, maintenance and
administration
Depreciation and amortization
Asset impairment charge
Taxes, other than income taxes
Net other operating expense
(income)
Operating income (loss)
Finance lease income
Net interest expense
Foreign exchange loss
Gain on sale of assets
Earnings before income taxes
Year ended Dec. 31, 2016
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 expense
(income)
Operating income (loss)
Finance lease income
Net interest expense
Foreign exchange loss
Gain on sale of assets
Earnings before income taxes
Canadian
Coal
US
Coal
Canadian
Gas
Australian
Gas
Wind and
Energy
Solar Hydro
Marketing Corporate
Total
999
585
414
192
317
20
13
(40)
(88)
—
435
293
142
51
73
—
4
—
14
—
261
101
160
50
38
—
1
(9)
80
11
135
14
121
31
37
—
—
—
53
43
287
17
270
48
111
—
8
—
103
—
121
6
115
37
31
—
3
—
44
—
69
—
69
24
2
—
—
—
43
—
— 2,307
— 1,016
— 1,291
84
26
—
1
—
517
635
20
30
(49)
(111)
138
—
54
(247)
(1)
2
(54)
Canadian
Coal
US
Coal
Canadian
Gas
Australian
Gas
Wind Hydro
Marketing Corporate
Total
Energy
1,048
451
597
178
242
—
13
(2)
354
281
73
54
61
—
4
—
166
(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
—
— 2,397
—
963
— 1,434
69
26
—
1
1
489
601
28
31
(193)
(97)
478
—
66
(229)
(5)
4
314
Included in revenues of the Wind and Solar Segment for the year ended Dec. 31, 2018 is $16 million (2017 -$18 million,
2016 - $19 million) of incentives received under a Government of Canada program in respect of power generation from
qualifying wind projects.
F90
TRANSALTA CORPORATION F90
TransAlta Corporation | 2018 Annual Integrated Report
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
II. Selected Consolidated Statements of Financial Position Information
As at Dec. 31, 2018
Goodwill
PP&E
Intangible assets
As at Dec. 31, 2017
Goodwill
PP&E
Intangibles
Canadian
Coal
US
Coal
Canadian
Gas
Australian
Gas
Wind and
Energy
Solar Hydro
Marketing Corporate
Total
—
—
2,587
332
81
7
—
391
4
—
554
41
175
1,799
173
259
481
4
30
1
11
—
464
19 6,164
52
373
Canadian
Coal
US
Coal
Canadian
Gas
Australian
Gas
Wind and
Energy
Solar Hydro
Marketing Corporate
Total
—
—
2,902
370
91
7
—
416
3
—
606
42
174
1,764
149
259
497
3
30
1
13
—
463
22 6,578
56
364
III. Selected Consolidated Statements of Cash Flows Information
Additions to non-current assets are as follows:
Year ended Dec. 31, 2018
Additions to non-current
assets:
PP&E
Intangible assets
Year ended Dec. 31, 2017
Additions to non-current
assets:
PP&E
Intangibles
Year ended Dec. 31, 2016
Additions to non-current
assets:
PP&E
Intangibles
Canadian
Coal
US
Coal
Canadian
Gas
Australian
Gas
Wind and
Energy
Solar Hydro
Marketing Corporate
Total
101
3
14
—
21
—
6
—
117
—
16
—
—
—
2
17
277
20
Canadian
Coal
US
Coal
Canadian
Gas
Australian
Gas
Wind and
Energy
Solar Hydro
Marketing Corporate
Total
116
5
35
1
31
—
114
29
20
—
16
—
—
—
6
16
338
51
Canadian
Coal
US
Coal
Canadian
Gas
Australian
Gas
Wind and
Energy
Solar Hydro
Marketing Corporate
Total
159
3
15
1
11
1
107
—
16
—
43
—
—
—
7
16
358
21
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 (Loss)
Depreciation included in fuel and purchased power (Note 6)
Depreciation and amortization on the Consolidated Statements of Cash Flows
2018
2017
2016
574
136
710
635
73
708
601
63
664
F91
TRANSALTA CORPORATION F91
TransAlta Corporation | 2018 Annual Integrated Report Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
I. Revenues
C. Geographic Information
Year ended Dec. 31
Canada
US
Australia
Total revenue
II. Non-Current Assets
2018
1,573
511
165
2,249
2017
1,663
509
135
2,307
2016
1,828
450
119
2,397
As at Dec. 31
Canada
US
Australia
Total
Property, plant and
equipment
2018
4,953
657
554
6,164
2017
5,353
619
606
6,578
Intangible assets
Other assets
Goodwill
2018
273
59
41
373
2017
297
25
42
364
2018
101
50
83
234
2017
105
43
89
237
2018
417
47
—
464
2017
417
46
—
463
During the year ended Dec. 31, 2018, sales to one customer represented 19 per cent of the Corporation’s total revenue
(2017 - one customer represented 28 per cent).
D. Significant Customer
F92
TRANSALTA CORPORATION F92
TransAlta Corporation | 2018 Annual Integrated Report
Exhibit 1
Exhibit 1
(Unaudited)
Exhibit 1
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, 2018:
Earnings coverage on long-term debt supporting the Corporation’s Shelf Prospectus
0.23 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.
F93
TRANSALTA CORPORATION F93
TransAlta Corporation | 2018 Annual Integrated Report Eleven-Year Financial and Statistical Summary
(in millions of Canadian dollars, except where noted)
(in millions of Canadian dollars, except where noted)
2016
2017
2018
626
87
820
(394)
744
(327)
2,397
478
117
0.41
0.13
0.30
8.92
2,307
138
(190)
2,249
160
(248)
(0.66)
n/a
0.16
8.28
(0.86)
n/a
0.20
7.16
9,428
59
3,119
1,137
942
2,055
(10)
7,275
10,996
334
3,722
1,152
942
2,569
(163)
8,556
10,304
433
2,960
1,059
942
2,384
(30)
7,748
Eleven-Year Financial and Statistical Summary
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(2)
CASH FLOWS
Cash flow from operating activities
Cash flow from (used in) investing activities
COMMON SHARE INFORMATION (per share)
Net earnings (loss)
Comparable earnings(1)
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(1)(5) (times)
Return on equity attributable to common shareholders
Comparable return on equity attributable to common shareholders(1)
Return on capital employed
Comparable return on capital employed(1)
Earnings coverage (times)
Dividend payout ratio based on comparable funds from operations(1)(5)
Comparable EBITDA(1)(5) (in millions of Canadian dollars)
Dividend coverage(1)(5) (times)
Dividend yield
Adjusted comparable funds from operations to adjusted net debt(1)(5)
FFO before interest to adjusted interest coverage(1)(5) (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 US)
Gas(4)
Renewables (wind, solar and hydro)
Equity investments
Total generating capacity
Total generation production (GWh)
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. For 2017, comparable
earnings measures are no longer being calculated or reported on.
(3) 2017, 2016, 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.
(5) 2016 and 2015 revised due to revisions to EBITDA or FFO measures in MD&A.
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
49.7
39.4
3.7
(15.76)
n/a
0.7
n/a
0.2
6.1
1,123
18.3
2.9
20.8
4.8
287
285
49.5
41.8
3.6
(10.00)
n/a
2.1
n/a
0.6
4.3
1,062
14.1
2.1
20.4
4.3
288
288
51
44.2
3.8
5.4
1.7
5.3
4.4
1.7
8.1
1,144
11.1
4
16.3
3.9
288
288
4,571
1,395
2,308
—
8,273
28,409
5,131
1,403
2,289
—
8,823
36,900
5,131
1,482
2,334
—
8,947
38,157
7.9
5.44
5.59
8.50
6.88
7.45
7.54
3.76
7.43
1,883
2,228
2,341
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 +
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”)
188
TRANSALTA CORPORATION 200
TransAlta Corporation | 2018 Annual Integrated Report
2015
2014
2013
2012
2011
2010
2009
2008
Eleven-Year Financial and Statistical Summary
Eleven-Year Financial and Statistical Summary
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
5.4
-1.2
-2.3
4.6
3
1.5
30
867
3.3
14.7
14.3
3.7
280
284
2,380
5,126
1,405
2,350
—
8,881
40,673
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
5.8
5.1
1.7
26.4
1,036
5.7
7.9
16.9
3.8
273
275
2,786
5,111
1,531
2,204
—
8,846
45,002
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
2,772
5,111
1,779
2,202
396
9,488
42,482
2,210
(214)
(615)
9,503
582
3,610
330
—
3,018
50
7,590
520
(1,048)
-2.62
0.5
1.16
8.78
21.37
14.11
15.12
61
59
4.6
-25.9
4.9
-3.1
5.3
(1.00)
25.1
1,015
4.7
7.7
16.7
3.3
235
255
2,084
4,551
1,731
2,058
390
8,730
38,750
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
3.8
10.6
8.4
8.3
7
2.7
24
1,044
3.5
5.5
20.1
4.4
222
224
2,235
4,325
1,567
1,974
390
8,256
41,012
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
6.6
6
2.2
40
955
4
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)
0.9
0.9
1.16
13.41
25.3
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
2,389
2,343
4,688
1,648
1,950
390
8,676
48,614
4,967
1,843
1,965
—
8,775
45,736
3,110
533
235
7,815
194
2,564
469
—
2,510
—
5,737
1,038
(581)
1.18
1.46
1.08
12.7
37.5
21
24.3
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
2,200
4,942
1,913
1,218
—
8,073
48,891
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
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
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
Dividend coverage = comparable cash flow from operating activities / cash dividends
paid on common shares
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
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
189
TRANSALTA CORPORATION 201
TransAlta Corporation | 2018 Annual Integrated Report
Plant Summary
Plant Summary
As of January
2019
Facility
Installed
capacity(MW)(1)
Ownership
(%)
Owned capacity
(MW)(1)(2)
Coal
12 facilities
Total Coal
Gas
11 facilities
Total Gas
Wind
21 facilities
Total Wind
Solar
1 facility
Total Solar
Hydro
27 facilities
Total Hydro
Sundance, AB
Keephills, AB
Keephills 3, AB
Genesee 3, AB
Sheerness, AB
Centralia, WA
Poplar Creek, AB(9)
Fort Saskatchewan, AB
Sarnia, ON*
Ottawa, ON
Windsor, ON
Parkeston, WA*(11)
Southern Cross, WA*(10)(11)
South Hedland, WA* (11)
Summerview 1, AB*
Summerview 2, AB*
Ardenville, AB*
Blue Trail, AB*
Castle River, AB* (12)
McBride Lake, AB*
Soderglen, AB*
Cowley North, AB*
Sinnott, AB*
Macleod Flats, AB*
Melancthon, ON* (13)
Wolfe Island, ON*
Kent Breeze, ON*
Kent Hills, NB*
Le Nordais, QC*
New Richmond, QC*
Wyoming Wind, WY*
Lakeswind, MN*
Mass Solar, MA* (14)
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 (8)*
Ragged Chute, ON*
Misema, ON*
Galetta, ON*
Appleton, ON*
Moose Rapids, ON*
Skookumchuck, WA
1,581
790
463
466
790
1,340
5,430
230
118
499
74
72
110
245
150
1,498
70
66
69
66
44
75
71
20
7
3
200
198
20
167
98
68
144
50
1,434
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
100%
100%
50%
50%
25%
100%
100%
30%
100%
50%
50%
50%
100%
100%
100%
100%
100%
100%
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%
9,331
Total
* TransAlta Renewables Inc. facility.
(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, 2018,
TransAlta owns approximately 61% of the outstanding shares of TransAlta Renewables.
(3) Merchant capacity refers to uprates on unit 3 (15 MW), unit 4 (53 MW), unit 5 (53
MW) and unit 6 (44 MW).
(4) PPA refers to Power Purchase Arrangement.
(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).
190
Region
Revenue source
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
United States
Merchant(3)
Alberta PPA(4)/ Merchant(5)
Merchant
Merchant
Alberta PPA / Merchant (6)
LTC(7)/Merchant
Contract expiry
date
—
2020
—
—
2020
2020-2025 (8)
Western Canada
Western Canada
Eastern Canada
Eastern Canada
Eastern Canada
Australia
Australia
Australia
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Eastern Canada
Eastern Canada
Eastern Canada
Eastern Canada
Eastern Canada
Eastern Canada
United States
United States
United States
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Western Canada
Eastern Canada
Eastern Canada
Eastern Canada
Eastern Canada
Eastern Canada
United States
LTC
LTC
LTC
LTC/ Merchant
LTC/ Merchant
2030
2029
2022-2025
2017-2033
2031
LTC
LTC
LTC
Merchant
Merchant
Merchant
Merchant
Merchant
LTC
Merchant
Merchant
Merchant
Merchant
LTC
LTC
LTC
LTC
LTC
LTC
LTC
LTC
LTC
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
2026
2023
2042
—
—
—
—
—
2024
—
—
—
—
2026-2028
2029
2031
2035
2033
2033
2028
2034
2032-2035
2020
2020
2020
2020
2020
2020
2020
2020
—
2020
2020
—
2020
—
2020
—
—
2025
2023
2031
2045
2029
2027
2030
2030
2030
2020
1,581
790
232
233
198
1,340
4,373
230
35
499
37
36
55
245
150
1,287
70
66
69
66
44
38
35
20
7
3
200
198
20
139
98
68
144
50
1,332
21
21
355
120
112
54
50
36
19
17
15
14
13
13
5
3
3
3
2
25
23
19
10
7
3
2
1
1
1
926
7,939
(7) LTC refers to Long-Term Contract.
(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) Includes seven individual turbines at other locations.
(13) Comprised of two facilities.
(14) Comprised of four ground-mounted projects and four roof-top projects.
TRANSALTA CORPORATION 202
TransAlta Corporation | 2018 Annual Integrated Report
Sustainability Performance Indicators
Sustainability Performance Indicators
Corporate Statistics
Environment Health & Safety Management Systems
2018
2017
2016
Facilities with ISO 14001 and/or OHSAS 18001-based management systems
(percentage)(1)
Management system audits(2)
97
17
97
20
97
35
Environmental Performance
2018
2017
2016
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)(4)
Greenhouse gas emissions(5)
Carbon dioxide (tonnes CO2e) √
Methane (tonnes CO2e) √
Nitrous oxide (tonnes CO2e) √
Sulfur hexafluoride (tonnes CO2e)
Total greenhouse gas emissions(6) (tonnes CO2e) √
Greenhouse gas emission intensity(7) (tonnes CO2e / MWh) √
Air emissions(8)
Total sulphur dioxide emissions (tonnes) √
Sulphur dioxide emission intensity(9) (kg / MWh) √
Total nitrogen oxide emissions (tonnes) √
Nitrogen oxide emission intensity(9) (kg / MWh) √
Total particulate matter emissions (tonnes) √
Particulate matter emission intensity(9) (kg / MWh) √
Total mercury emissions (kilograms) √
Mercury emission intensity(9) (mg / MWh) √
Water management(10)
Water intake (million m3) √
Water discharge (million m3) √
Water consumption (million m3) √
Water intensity (m3/MWh)(11) √
10,001,100
14,956,400
15,735,300
69,372,900
55,520,900
62,486,700
9,544,200
1,414,600
4,384,700
46,179,400
1,476,700
1,487,200
38,361,500
44,045,200
40,224,800
75,100
279,800
73,100
154,300
115,600
112,000
290,100
75,500
125,800
96,200
78,800
359,300
58,300
127,500
56,500
358,477,500
496,910,700
528,442,800
20,595,600
29,627,700
30,381,300
68,900
115,400
10
107,100
185,100
10
114,200
224,600
20
20,779,900
29,919,900
30,720,100
0.77
0.86
0.83
19,300
0.73
28,000
1.05
7,800
0.29
70
2.5
245
208
37
1.4
36,200
1.05
44,400
1.29
14,500
0.42
110
3.29
213
172
41
1.18
39,600
1.08
48,400
1.33
13,800
0.38
130
3.52
239
197
42
1.63
191
TRANSALTA CORPORATION 203
TransAlta Corporation | 2018 Annual Integrated Report
Sustainability Performance Indicators
Waste management(12)
Non-hazardous
Landfill (tonnes) √
Landfill (L) √
Ash disposal: mine (tonnes) (13)√
Ash disposal: lagoon (tonnes) (14) √
Recycled (tonnes) √
Recycled (L) √
Reuse (tonnes) √
Storage (tonnes) √
Hazardous(15)
Landfill (tonnes) √
Landfill (L) √
Recycled (tonnes) √
Recycled (L) √
Land use and reclamation(16)
Land used in mining activities – disturbed (cumulative hectares) √
Land used in mining activities – reclaimed (cumulative hectares) √
Land reclamation(17) (% of land disturbed) √
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(18) √
Environmental enforcement actions(19)
Environmental fines ($ thousands)
Spills(20)
Volume of significant spills (m3)
Sustainability Performance Indicators
1,900
68,100
461,200
276,900
1,800
3,200
63,500
2,100
518,400
1,338,600
1,315,000
485,500
1,400
3,718,100
4,122,700
564,400
827,400
—
—
40
45,100
40
40
14,600
12,740
527,700
18,000
212,100
700,700
8,300
40
13,110
60
16,255,300
20,140,400
17,209,600
12,400
4,700
38
7,700
3,900
12,100
4,600
38
7,400
3,900
11,700
11,300
7
1
6
5
5
—
—
15
11,800
4,600
39
7,200
2,700
9,900
16
—
—
61
192
TRANSALTA CORPORATION 204
TransAlta Corporation | 2018 Annual Integrated Report 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(21) (%)
Voluntary employee turnover rate(22) (%)
Diversity
Women in workforce (%)
Women in senior management (%)
Women on Board of Directors (%)
Health and safety
Health and safety enforcement actions(23)
Health and safety fines ($ thousands)
Employee & contractor fatalities √
Lost time incident (LTI) (absence from work)(24) √
Medical aids (MA) (no absence from work)(25) √
Total injuries to employees & contractors √
Total injury frequency rate (IFR) (employees and contractors)(26) √
Total incident frequency (TIF) (employees and contractors)(27)
Sustainability Performance Indicators
Sustainability Performance Indicators
2018
2017
2016
1,883
1,810
22
51
50
2,228
2,125
24
79
57
20.22
10.65
20
50
40
—
—
—
1
12
13
19
26
40
4
—
—
6
15
21
0.54
1.98
0.72
3.54
2,341
2,267
26
48
53
6.71
18
26
33
4
5.4
—
4
20
24
0.85
3.29
Community relations
Community investments ($ millions)(28)
2.4
2.6
2.5
3 2018 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.
193
TRANSALTA CORPORATION 205
TransAlta Corporation | 2018 Annual Integrated Report Sustainability Performance Indicators
Discussion and Notes on Numbers
Sustainability Performance Indicators
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.
4.
5.
6.
7.
8.
9.
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 73 facilities.
Internal audits conducted against ISO management systems, regulatory frameworks and 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 (GHG) emissions reporting, which
is the application of an Operational Control boundary.
Our 2016 energy data was revised in 2017, due to changes in our 2016 diesel combustion at our Centralia facility and 2016 natural gas combustion and diesel
combustion at our Sarnia facility. Centralia 2016 diesel combustion was misreported in 2016. Sarnia 2016 energy data was misreported due to IT system-related
errors. Sarnia 2016 vehicle diesel usage was applied incorrectly. Diesel usage was for a diesel backup generator and volumes were applied to diesel combustion
and not diesel consumption from vehicles.
GHG emissions are calculated and reported from TransAlta-operated facilities in line with carbon regulations 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.
Gross GHG emissions or gross carbon dioxide equivalent (CO2e) emissions is the sum of carbon dioxide, methane, nitrous oxide and sulfur hexafluoride.
Coincidentally the sum of scope 1 and 2 emissions will equate to gross CO2e emissions or gross GHG emissions. Our 2016 GHG data was revised in 2017, due to
changes in our 2016 diesel combustion at our Centralia facility and 2016 natural gas combustion and diesel combustion at our Sarnia facility. Please see Note 3
for revision explanations.
GHG emission intensity is calculated by dividing total operational emissions by 100 per cent of production (MWh) from operated facilities, irrespective of financial
ownership. Our 2017 nitrous oxide emissions were revised in 2018 to 185,100 tonnes CO2e (previously reported as 190,900 tonnes CO2e) as a result of double
counting mobile combustion emissions at our Highvale mine. Our Australia 2016 production data was revised in 2017 due to metering issues in 2016. As a result
our GHG intensity for 2016 dropped from 0.84 to 0.83 tonnes CO2e/MWh.
Air emissions are reported from TransAlta-operated facilities, following the same approach we use for GHG reporting, which is the application of an Operational
Control boundary. Air emissions are expressed in tonnes, except for mercury emissions, which are represented in kilograms. Total particulate matter emissions
(TPM) include both PM2.5 and PM10. In 2018 we revised our historical TPM emissions to include road dust total particulate matter emissions from our Highvale
coal mine in Alberta. Our previous approach was to report on TPM stack emissions only, but as part of our continuous improvement process we have included road
dust emissions. As a result, historical TPM volumes and emission intensities were adjusted to include TPM from Highvale mine road dust .
Air emission intensities are calculated by dividing total operational emissions by 100 per cent of production (MWh) from operated facilities, irrespective of financial
ownership.
10. Water usage is reported from TransAlta-operated facilities, following the same approach we use for GHG reporting, which is the 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. Sundance 2015 and 2016 historical water data was revised in 2017 due to misalignment in
reporting between corporate and business unit data. Water volumes that are discharged to our cooling pond, adjacent to Wabamum Lake, were being applied as
intake volumes. These volumes are discharge volumes and have been reallocated accordingly.
11. Water intensity is calculated by dividing total operational water consumption (m3) by 100 per cent of production (MWh) from operated facilities, irrespective of
financial ownership.
12. Non-hazardous waste includes, but is not limited to, the disposal of water treatment chemicals, coal refuse (including ash byproducts), metals, paper, cardboard
and building materials. Due to a vendor issue at our Hydro business unit, hazardous waste to landfill was estimated in 2018 using the average of hazardous waste
to landfill from 2015-2017.
Total land use is mining land use plus land used by plants, offices and equipment.
13. 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.
14. Ash disposal: lagoon is fly ash and bottom ash from Keephills coal production, which is treated and then sent to ash lagoons for disposal.
15. 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.
16.
17. Disturbed land use Highvale mine volumes were reconciled in 2017 to match Alberta regulatory reporting data. Actual disturbed volumes in 2017 were 160
hectares and these volumes were reconciled with 80 hectares to ensure our total land disturbed volumes align. As a result our land reclamation percentage was
down one per cent compared with 2016 data.
Environmental incidents are violations or non-compliance to regulations or exceedance of limits in company operating approvals that resulted in or had the potential
to result in enforcement action.
Environmental enforcement actions are violations or non-compliance to regulations or exceedance of limits in company operating approvals that result in
enforcement action, including stop work orders, fines or suspension of operating approvals
Spills volumes that require reporting to a regulatory agency or result in low level damage to ecosystem.
TransAlta has over 900 unionized workers working primarily at our operations.
20.
21.
22. Voluntary turnover is aligned with our Human Resources voluntary turnover reporting methodology. As per this methodology, voluntary turnover is any full-time,
18.
19.
part- time or contingent employee initiated exit, excluding retirement. Summer students and temporary workers are not considered within voluntary turnover.
23. Health and safety enforcement actions are those resulting in a violation or non-compliance to regulations or exceedance of limits in company operating approvals
that result in enforcement action including stop work orders, fines or suspension of operating approvals.
Lost-time injuries (LTIs) are injuries that resulted in the worker being away from work beyond the day of the injury.
24.
25. Medical aids (MAs) are injuries that resulted in medical treatment beyond first aid.
26.
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.
Total incident frequency (TIF) tracks the total number of injuries (medical aids, lost-time injuries, restricted works and first aids) relative to employee hours worked.
27.
28. Cumulative of donations and sponsorship totals in the respective calendar year. This investment figure does not include donations from our employees.
194
TRANSALTA CORPORATION 206
TransAlta Corporation | 2018 Annual Integrated Report Independent Sustainability Assurance Statement
Independent Sustainability Assurance Statement
To the Board of Directors and Management of TransAlta Corporation (“TransAlta”).
Scope of Ernst & Young LLP (“EY”) Engagement
Our responsibilities included providing limited
assurance over a selection of performance indicators as
presented in the Addendum to this statement.
Subject Matter
We have performed limited assurance procedures for
the following quantitative performance indicators
(“Subject Matter”) for the year ending December 31,
2018.
▪
▪
▪
Sulphur dioxide emissions and emission intensity
(tonnes, kg/MWh)
Nitrogen oxide emissions and emission intensity
(tonnes, kg/MWh)
Particulate matter emissions and emission
intensity (tonnes, kg/MWh)
▪ Mercury emissions and emission intensity (kg, mg/
MWh)
Carbon dioxide emissions (tonnes CO2e)
▪
▪ Methane emissions (tonnes CO2e)
▪
▪
Nitrous oxide emissions (tonnes CO2e)
Total greenhouse gas emissions and emissions
intensity (tonnes CO2e, tonnes CO2e/MWh)
Total environmental incidents
Lost-time incident for employees and contractors
(LTI) (absence from work)
▪
▪
▪ Medical aids (MA) for employees and contractors
▪
▪
(no absence from work)
Total injuries to employees and contractors
Employee and contractor total injury frequency
rate (injuries/200,000 hours)
Employee and contractor fatalities
▪
▪ 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)
*
*
Land use - disturbed and reclaimed
▪
Criteria
TransAlta has prepared its specified performance
information in accordance with industry standards and,
where relevant, internally developed criteria.
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.
EY Responsibilities
Our limited assurance procedures have been planned
and performed in accordance with the International
Standard on Assurance Engagements 3000 Assurance
Engagements other than Audits or Reviews of
Historical 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 management’s internal controls when
determining the nature and extent of our procedures,
our assurance engagement was not designed to
provide assurance on internal controls and,
accordingly, we express no conclusions thereon.
This assurance statement has been prepared for
TransAlta for the purpose of assisting management in
determining whether the Subject Matter is in
accordance with the criteria and for no other purpose.
Our assurance statement is made solely to TransAlta in
accordance with the terms of our 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.
195
TRANSALTA CORPORATION 207
TransAlta Corporation | 2018 Annual Integrated Report
Independent Sustainability Assurance Statement
Independent Sustainability Assurance Statement
Independence and Competency Statement
In conducting our engagement, we have complied with
the applicable requirements of the Code of Ethics for
Professional Accountants issued by the International
Ethics Standards Board for Accountants.
EY Conclusion
Based on our procedures for this limited assurance
engagement described in this statement, nothing has
come to our attention that causes us to believe that the
Subject Matter is not, in all material respects, reported
in accordance with the relevant criteria.
Assurance Procedures
We planned and performed our work to obtain all the
evidence, information and explanations considered
necessary 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.
▪
▪
▪
Limitations of EY Work Performed
Our scope of work did not include expressing
conclusions in relation to:
▪
The materiality, completeness or accuracy of data
sets or information relating to areas other than the
selected performance data, and any site-specific
information.
▪ Management’s forward-looking statements.
Any comparisons made by TransAlta against
▪
historical data.
The appropriateness of definitions for internally
developed criteria.
▪
Ernst & Young LLP
Calgary, Canada
February 26, 2019
196
TRANSALTA CORPORATION 208
TransAlta Corporation | 2018 Annual Integrated Report Shareholder Information
Shareholder Information
Special Services for Registered Shareholders
Service
Description
Direct deposit for dividend payments
Automatically have dividend payments deposited to your bank account
Account consolidations
Eliminate costly duplicate mailings by consolidating account registrations
Address changes and share transfers
Receive tax splits and dividends without the delays resulting from address and ownership
changes
Stock Splits and Share Consolidations
Date
May 8, 1980
Feb. 1, 1988
December 31, 1992
Events
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 2018
Payment Date
April 1, 2018
July 3, 2018
Oct 1, 2018
Jan. 1, 2019
Apr. 1, 2019
Record Date
Mar. 1, 2018
Jun. 1, 2018
Sept. 4, 2018
Dec. 3, 2018
Mar. 1, 2019
Ex-Dividend Date
Dividend
Feb. 28, 2018
May 31, 2018
Aug. 31, 2018
Nov. 30, 2018
Feb. 28, 2019
$0.04
$0.04
$0.04
$0.04
$0.04
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.
197
TRANSALTA CORPORATION 209
TransAlta Corporation | 2018 Annual Integrated Report
Shareholder Information
Shareholder Information
Dividend Declaration for Preferred Shares
Series A: Fixed cumulative preferential cash dividends are paid quarterly when declared by the Board at the annual rate
of $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 $1.01 per share from and including June 30, 2017, to, but excluding June 30, 2022.
Series E: Fixed cumulative preferential cash dividends are paid quarterly when declared by the Board at the annual rate
of $1.30 per share from and including September 30, 2017, to, but excluding Sept. 30, 2022.
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 2018
Series A
Payment Date
Mar. 31, 2018
Jul. 3, 2018
Sept. 30, 2018
Dec. 31, 2018
Mar. 31, 2019
Series B
Payment Date
Mar. 31, 2018
Jul. 3, 2018
Sept. 30, 2018
Dec. 31, 2018
Mar. 31, 2019
Series C
Payment Date
Mar. 31, 2018
Jul. 3, 2018
Sept. 30, 2018
Dec. 31, 2018
Mar. 31, 2019
Series E
Payment Date
Mar. 31, 2018
Jul. 3, 2018
Sept. 30, 2018
Dec. 31, 2018
Mar. 31, 2019
Series G
Payment Date
Mar. 31, 2018
Jul. 3, 2018
Sept. 30, 2018
Dec. 31, 2018
Mar. 31, 2019
Record Date
Mar. 1, 2018
Jun. 1, 2018
Sept. 4, 2018
Dec. 3, 2018
Mar. 1, 2019
Record Date
Mar. 1, 2018
Jun. 1, 2018
Sept. 4, 2018
Dec. 3, 2018
Mar. 1, 2019
Record Date
Mar. 1, 2018
Jun. 1, 2018
Sept. 4, 2018
Dec. 3, 2018
Mar. 1, 2019
Record Date
Mar. 1, 2018
Jun. 1, 2018
Sept. 4, 2018
Dec. 3, 2018
Mar. 1, 2019
Record Date
Mar. 1, 2018
Jun. 1, 2018
Sept. 4, 2018
Dec. 3, 2018
Mar. 1, 2019
Ex-Dividend Date
Feb. 28, 2018
May 31, 2018
Aug. 31, 2018
Nov. 30, 2018
Feb. 28, 2019
Ex-Dividend Date
Feb. 28, 2018
May 31, 2018
Aug. 31, 2018
Nov. 30, 2018
Feb. 28, 2019
Ex-Dividend Date
Feb. 28, 2018
May 31, 2018
Aug. 31, 2018
Nov. 30, 2018
Feb. 28, 2019
Ex-Dividend Date
Feb. 28, 2018
May 31, 2018
Aug. 31, 2018
Nov. 30, 2018
Feb. 28, 2019
Ex-Dividend Date
Feb. 28, 2018
May 31, 2018
Aug. 31, 2018
Nov. 30, 2018
Feb. 28, 2019
Dividend
$0.16931
$0.16931
$0.16931
$0.16931
$0.16931
Dividend
$0.23073
$0.22301
$0.20984
$0.19951
$0.17889
Dividend
$0.25169
$0.25169
$0.25169
$0.25169
$0.25169
Dividend
$0.32463
$0.32463
$0.32463
$0.32463
$0.32463
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.
Voting Rights
Common shareholders receive one vote for each common share held.
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Shareholder Information
Shareholder Information
Annual Meeting
The Annual and Special Meeting of Shareholders will be held at 10:30 a.m. MST, on Tuesday, April 16, 2019, at the
Doherty Hall (Stampede Park) 623 13 Ave SE, Calgary, Alberta.
Transfer Agent
AST Trust Company (Canada)*
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
Email: inquiries@astfinancial.com
Fax
514.985.8843
Website
www.astfinancial.com/ca-en
Exchanges Ticker Symbols
Toronto Stock Exchange (TSX) TransAlta Corporation common shares: TSX: TA, NYSE: TAC
New York Stock Exchange (NYSE) TransAlta Corporation preferred shares: TSX: TA.PR.D, TA.PR.E,
TA.PR.F, TA.PR.H, TA.PR.J
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 Fax
Calgary/outside North America:
403.267.2520
Email
investor_relations@transalta.com
403.267.7405
Website
www.transalta.com
* AST Trust Company (Canada), formerly CST Trust Company, changed its name on July 20, 2017. 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.
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Shareholder Highlights
Shareholder Highlights
Total Shareholder Return vs. S&P/TSX Composite Index
Year ended Dec. 31 ($)
TransAlta
S&P/TSX
09
100
100
10
95
118
11
100
107
12
77
115
13
74
130
14
61
144
15
31
132
16
49
160
17
50
175
18
38
159
This chart compares what $100 invested in TransAlta and the S&P/TSX Composite Index at the end of 2009 would be worth today, assuming the reinvestment of all
dividends.
Source: FactSet
Ten-Year Market Value vs. Book Value
Year ended Dec. 31 ($ per share)
Market Value
Book Value
09
23.48
13.41
10
21.15
12.85
11
21.02
12.08
12
13
14
15.12
13.48
10.52
8.78
7.92
8.52
15
4.91
8.52
16
7.43
8.92
17
7.45
8.28
18
5.59
7.17
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).
Source: FactSet and TransAlta
Monthly Volume and Market Prices
2018
Jan
9
Feb
10
Mar
18
Apr
8
May
10
Jun
8
Jul
17
Aug
18
Sep
10
Oct
11
Nov
8
Dec
16
6.80
7.16
6.98
6.76
6.67
6.60
7.41
7.67
7.27
6.95
7.12
5.59
Volume (millions)
TSX closing price ($
per share)
Source: FactSet
Return on Common Shareholders' Equity
(%)
09
6.9
10
9.6
11
10.6
12
(25.9)
13
(3.2)
14
6.3
15
(1.2)
16
5.4
17
18
(10.0)
(15.5)
ROE
Source: TransAlta
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Corporate Information
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 US
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
(US/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
Christophe Dehout
Chief Financial Officer
Jane N. Fedoretz
Chief Talent & Transformation Officer
Brett M. Gellner
Chief Strategy & Investment Officer
John H. Kousinioris
Chief Growth Officer & President of TransAlta
Renewables Inc.
Dawn E. de Lima
Chief Officer - Business & Operational Services
Kerry O'Reilly
Chief Legal & Compliance Officer
Wayne A. Collins
Executive Vice-President, Coal and Mining Operations
Jennifer M. Pierce
Senior Vice-President, Business Development
Aron J. Willis
Senior Vice-President, Commercial, Gas & Renewables
Operations
Todd J. Stack
Managing Director, Corporate Controller
Brent Ward
Managing Director, Treasury
Scott T. Jeffers
Managing Director, Corporate Secretary
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Glossary of Key Terms
Glossary of Key Terms
A long-term arrangement established by regulation for
the sale of electric energy from formerly regulated
Alberta Power Purchase Arrangement (PPA)
generating units to PPA buyers.
A measure of time, expressed as a percentage of
continuous operation 24 hours a day, 365 days a year,
Availability
that a generating unit is capable of generating
electricity, regardless of whether or not it is actually
generating electricity.
A device for generating steam for power, processing or
heating purposes, or for producing hot water for
Boiler
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.
The rated continuous load-carrying ability, expressed in
megawatts, of generation equipment.
Capacity
A generating facility that produces electricity and
another form of useful thermal energy (such as heat or
Cogeneration
steam) used for industrial, commercial, heating or
cooling purposes.
An electric generating technology in which electricity is
produced from otherwise lost waste heat exiting from
Combined Cycle
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.
To lower the rated electrical capability of a power
generating facility or unit.
Derate
Literally means “greater force.” These clauses excuse a
party from liability if some unforeseen event beyond
Force Majeure
the control of that party prevents it from performing its
obligations under the contract.
A metric unit of energy commonly used in the energy
industry. One GJ equals 947,817 British Thermal Units
Gigajoule (GJ)
(Btu).
A measure of electric power equal to 1,000 megawatts.
Gigawatt (GW)
A measure of electricity consumption equivalent to the
use of 1,000 megawatts of power over a period of one
Gigawatt Hour (GWh)
hour.
A gas that has the potential to retain heat in the
atmosphere, including water vapour, carbon dioxide,
Greenhouse Gas (GHG)
methane, nitrous oxide, hydrofluorocarbons and
perfluorocarbons.
A measure of conversion, expressed as Btu/MWh, of
the amount of thermal energy required to generate
Heat Rate
electrical energy.
A measure of electric power equal to 1,000,000 watts.
Megawatt (MW)
A measure of electricity consumption equivalent to the
use of 1,000,000 watts of power over a period of one
Megawatt Hour (MWh)
hour.
A term used to describe assets that are not contracted
and are exposed to market pricing.
Merchant
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Glossary of Key Terms
Glossary of Key Terms
The maximum capacity or effective rating, modified for
ambient limitations, that a generating unit or power
Net Maximum Capacity
plant can sustain over a specific period, less the
capacity used to supply the demand of station service
or auxiliary needs.
Periodic planned shutdown of a generating unit for
major maintenance and repairs. Duration is normally in
Turnaround
weeks. The time is measured from unit shutdown to
putting the unit back on line.
Power generated from renewable terrestrial
mechanisms including wind, geothermal, solar and
Renewable Power
biomass with regeneration.
A measure of gross margin per MW (sales price less
cost of natural gas).
Spark Spread
A machine for generating rotary mechanical power
from the energy of a stream of fluid (such as water,
Turbine
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.
The shutdown of a generating unit due to an
unanticipated breakdown.
Unplanned Outage
To increase the rated electrical capability of a power
generating facility or unit.
Uprate
A measure used to manage exposure to market risk
from commodity risk management activities.
Value at Risk (VaR)
In an effort to be environmentally responsible, please notify your financial institution if you are receiving duplicate
In an effort to be environmentally responsible, please notify your financial institution if you are receiving duplicate mail ings of this annual report.
mailings of this annual report. The TransAlta design and TransAlta wordmark are trademarks of TransAlta Corporation.
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 certified by the Forest Stewardship Council, which is an
This report was printed in Canada. The paper, paper mills and printer are all certified by the Forest Stewardship Council,
international network that promotes environmentally appropriate and socially beneficial management of the world’s forests.
which is an international network that promotes environmentally appropriate and socially beneficial management of the
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Design & Production: One Design Inc.
Printing: Merrill Corporation
TRANSALTA CORPORATION 215
TransAlta Corporation
110 - 12th Avenue SW
Box 1900, Station “M”
Calgary, Alberta
Canada T2P 2M1
403.267.7110
www.transalta.com