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The AES Corporation
4300 Wilson Boulevard
Arlington, VA 22203
USA
703-522-1315
www.aes.com
2016
Annual Report
AES EXECUTIVE LEADERSHIP TEAMAndrés GluskiPresident & Chief Executive OfficerMichael ChiltonSenior Vice President of Global Engineering & ConstructionBernerd Da SantosSenior Vice President and Chief Operating OfficerElizabeth HackensonSenior Vice President of Technology & Services and Chief Information OfficerTish Mendoza Senior Vice President of Global Human Resources & Internal Communications and Chief Human Resources OfficerBrian MillerExecutive Vice President, General Counsel & Corporate Secretary Thomas O’FlynnExecutive Vice President and Chief Financial OfficerAES BOARD OF DIRECTORS Charles Rossotti (Chairman)Senior Advisor, The Carlyle Group; former Commissioner, the IRS; former Founder and Chairman, American Management Systems, Inc.Andrés GluskiPresident and Chief Executive Officer, The AES CorporationCharles Harrington Chairman and CEO of Parsons CorporationKristina JohnsonCEO of Cube Hydro Partners; former Undersecretary for Energy at the Department of Energy; former Provost and Senior Vice President for Academic Affairs at the Johns Hopkins UniversityTarun KhannaJorge Paulo Lemann Professor at the Harvard Business SchoolHolly K. KoeppelManaging Partner and Co-Head of Corsair Infrastructure Management, L.P.Philip LaderFormer Chairman, WPP Group plc; Senior Advisor, Morgan Stanley; former U.S. Ambassador to the Court of St. James’sJames MillerFormer Chairman of PPL Corporation; former Executive Vice President of USEC Inc.; President for two ABB Group subsidiariesJohn MorseRetired Senior Vice President Finance and CFO Washington Post Company; former Partner Price Waterhouse (now PricewaterhouseCoopers); former Trustee and President Emeritus of the College Foundation of The University of VirginiaMoisés NaímDistinguished Fellow in the International Economics Program at the Carnegie Endowment for International Peace and international columnist and broadcaster; Former Editor in Chief for Foreign Policy magazine; Former Minister of Industry and Trade and the Central Bank for Venezuela; former Executive Director for the World BankCOMPANY INFORMATIONCorporate OfficeThe AES Corporation 4300 Wilson Boulevard Arlington, VA 22203 USA 703-522-1315Websitewww.aes.com @TheAESCorpStock InformationCommon stock of The AES Corporation trades under the symbol AES. The AES Corporation is proud to meet the listing requirements of the NYSE, the world’s leading equities market.Number of ShareholdersAs of December 31, 2016 there were approximately 4,384 AES shareholders of record and 659,182,232 shares of AES common stock outstanding. Transfer AgentThe AES Corporation has designated Computershare Investor Services (“Computershare”) to be its transfer agent for AES common stock.Please contact Computershare if you need assistance with lost or stolen AES stock certificates directly held by you, issues related to dividend checks, address changes, name changes and stock transfers.By mail: Computershare P.O. Box 30170 College Station, TX 77842-3170 Overnight: Computershare 211 Quality Circle, Suite 210 College Station, TX 77845 877-373-6374 www.computershare.comIndependent Auditors Ernst & Young LLPInvestors Please visit the Investors section of the AES website at www.aes.com, or you may contact a member of the AES Investor Relations team: General: invest@aes.com Ahmed Pasha, Vice President, Investor Relations: 703-682-6451Media InquiriesGeneral: mediainquiries@aes.com Amy Ackerman, Manager, External Communications: 703-682-6399AES Code of ConductAES is committed to demonstrating the highest standards of business ethics in all that we do. To that end, AES has adopted a Code of Conduct, which is available at our website.Note: Contains forward looking statements. Please see “Forward looking information” in AES’ 2016 Annual Report on Form 10-K.1 A non-GAAP financial measure. See Financial Notes on Page 7 for definition and reconciliation to the nearest GAAP number.80% 40%34%22%4%Capacity by Fuel TypeGW Capacity37of adjusted pre-tax contribution (ptc)¹ comes from 9 countries in the AmericasCoalGasRenewablesOil, Diesel, Pet CokeWe are the EnergyGWH Delivered in 201671Utilities79Million Distribution Customers The AES Corporation
We are a global power company with generation and distribution businesses.
Through our diverse portfolio of thermal and renewable fuel sources, we
provide affordable and sustainable energy to 17 countries. Our workforce
of 19,000 people is committed to operational excellence and meeting the
world’s changing power needs.
19,000 Employees
AES Values
1
Put Safety First
2
Act With Integrity
3
Honor Our Commitments
4
Strive for Excellence
5
Have Fun
Through Work
100+ Awards
Executive Leadership Team
Chairman and CEO letter
to AES Shareholders
2 | AES ANNUAL REPORT 2016
We are at a time of immense change and excitement
in our industry. The power grid of the 21st century will
look very different from what we have seen in the past,
offering cleaner and more affordable energy. Renewables
are increasingly cost competitive and have become the
dominant type of new build generation in most of our
markets. Existing thermal generation and energy storage
will become more integrated with newer renewable
sources to meet challenges posed by the intermittent
nature of wind and solar generation. We also see a
growing demand for natural gas, with the potential for
gas to replace oil-fired generation in several markets.
Our actions over the past several years have put AES in a great position to
be a premier provider of energy solutions across our markets during this
time of immense change. As we seek to meet the evolving needs of our
energy customers, we benefit from a strong balance sheet, a unique and
diverse global platform, proven success in deploying new technologies and a
talented global workforce.
In 2016 we expanded our renewables portfolio and grew our world-leading
battery-based energy storage business. We began selling our proprietary
Advancion® storage platform to utilities and other customers. We have
now deployed Advancion for projects we own and operate across seven
countries, with 436 MW in operation, under construction or in advanced
stage development. We also broke ground on a new gas-fired plant and
LNG regasification facility in Panama, enabling us to play a leading role in
delivering cleaner and lower-cost natural gas throughout Central America.
We have deployed new technologies such as drones and robotics to improve
safety and lower costs for our businesses, and we are continually seeking
innovative applications of technologies to improve our performance.
We continued to make progress on our strategic objectives throughout
2016. Our asset sales program has now achieved $3.6 billion in total sale
proceeds, allowing us to refocus our activities on select markets in which
we have the greatest competitive advantage. In the process, we achieved
our incremental $50 million cost savings and revenue enhancement target
and we are on track to reach $350 million in annual savings by 2018. We
brought on-line 2,976 MW of construction projects in 2016 to drive future
growth. We also achieved our financial guidance, reduced our corporate
debt and increased our dividend.
Despite 2016 being a successful year overall, we did experience some
headwinds. Several of our construction projects were delayed, most notably
the Alto Maipo hydroelectric project in Chile, which required a restructuring
of its financing and Power Purchase Agreement (PPA). We also had large
impairments at DPL in Ohio and our Buffalo Gap wind projects in Texas,
which reflect unsuccessful past investments.
The progress we did make in 2016 on our strategic objectives was reflected
in our stock performance. We had a very positive year and generated total
shareholder return of 26.3%, outperforming the S&P 500 (up 12.0%), the
S&P Utilities Index (up 16.3%) and U.S. listed independent power producers
(down 17.2%).
PROPORTIONAL
FREE CASH FLOW ($M)1
$1,417
$1,240
$891
4
1
0
2
5
1
0
2
6
1
0
2
ADJUSTED EPS1
$1.25
$1.18
$0.98
4
1
0
2
5
1
0
2
6
1
0
2
SHAREHOLDER DIVIDEND
2012
$0.04
$0.16
$0.20
2013
2014
2015
2016
2017
2018–
2020
$0.40
$0.44
$0.48 Expected
8–10%
Expected
Annual Growth
1. A non-GAAP financial measure. See Financial
Notes on Page 7 for definition and reconciliation.
AES ANNUAL REPORT 2016 | 3
2016 RESULTS AND ACCOMPLISHMENTS
Turning to our specific results and accomplishments in 2016, we delivered
on our financial guidance, continued to meet our commitments to our
shareholders and extended our progress on our strategy. In terms of future
growth in free cash flow and earnings, we expect 8%-10% growth in our
financial metrics through 2020.
As a result of our actions in 2016, we generated Proportional Free Cash Flow
of $1,417 million and Parent Free Cash Flow of $579 million. As expected,
our Adjusted Earnings Per Share was below our 2015 results, primarily due
to headwinds from foreign currency and commodity prices, as well as a
continued decline in demand in Brazil. We were able to offset much of the
impact, and our 2016 Adjusted EPS came in at $0.98. During the year, we
also achieved many of our strategic objectives. In addition to the cost savings
and completion of construction projects previously mentioned, we also:
• Announced or closed $500 million in proceeds from the sales or sell-
downs of eight businesses;
• Increased our quarterly dividend by 9.1%, to $0.12 per share, beginning in
the first quarter of 2017; and
• Advanced 3,389 MW of construction projects which are expected to
come on-line through 2019.
SUCCESSFUL EXECUTION OF OUR STRATEGY
Since late 2011, we have successfully delivered on our strategic goals and during
2016 we extended our progress. The actions we have taken since 2011, such
as cutting our costs, de-levering and reducing our complexity through asset sales
have put us in a strong position to execute on our strategic growth opportunities.
Reducing Complexity
We have been rebalancing our business mix by exiting certain businesses
to reduce risk and re-deploying our excess cash into debt repayment, share
repurchases, dividends and growth projects with long-term, U.S. Dollar-
denominated contracts. Since 2011, we have raised $3.6 billion in equity
proceeds from asset sales, decreasing the total number of countries where
we have operations from 28 to 17.
Leveraging Our Platforms for Long-Term Growth
We are focusing our growth on platform expansions in markets where we
already operate and have a competitive advantage to realize attractive
risk-adjusted returns. Since 2011, we have brought on-line 7,932 MW of new
projects, including 2,976 MW of platform expansion projects in 2016 alone.
We currently have 3,389 MW under construction, representing $6.4 billion
in total capital expenditures, with the majority of AES’ $1.1 billion in equity
already funded and expected to contribute a targeted return on our equity
of approximately 14%. These projects under construction are the most
significant driver of our near-term growth.
Allocating Capital in a Disciplined Manner
Our top priority is to maximize risk-adjusted returns to our shareholders, by
taking a long-term perspective on investing our free cash flow.
Since 2011, we have generated substantial cash by executing on our
strategy, which we allocated in line with our capital allocation framework:
• We used $2,263 million to prepay and refinance Parent debt;
• We returned $2,402 million to shareholders through share repurchases
and a quarterly dividend; and
552 MW Cochrane plant in Chile
ASSET SALE PROCEEDS
$3.6B
$510M
2016
$787M
2015
$1,207M
2014
$234M
2013
$900M 2011-2012
CAPACITY ADDITIONS (MW)
10,001
6,764
3,237
Expected
152
Expected
6,612
Added
1
1
0
2
2
1
0
2
3
1
0
2
4
1
0
2
5
1
0
2
6
1
0
2
7
1
0
2
9
1
–
8
1
0
2
4 | AES ANNUAL REPORT 2016
• We invested $1,336 million in our subsidiaries, largely for projects that
are currently under construction.
We remain committed to strengthening our credit, which is largely driven
by the successful completion of our construction program, cost reductions
and de-levering. Accordingly, we continue to be confident that we can
achieve investment grade stats by 2020.
CREATING LONG-TERM SHAREHOLDER VALUE
AES strives to create long-term shareholder value by providing safe and
reliable electricity-related services in the markets we serve. We have a
unique portfolio of businesses with significant presence in both mature
and rapidly growing developing markets. This makes AES well positioned to
deliver attractive long-term growth in cash flow, dividends and earnings.
Underlying Strengths of Our Businesses
As a result of our proactive contracting and portfolio rebalancing initiatives,
today, about 80% of our business is U.S. Dollar-based and about 83% is
either contracted generation or regulated utilities. The average remaining life
of the PPAs at our contracted businesses is six years, and when we complete
our projects currently under construction, this will be extended to ten years.
Long-term PPAs provide stability and predictability to our earnings and cash flow.
The majority of our businesses are low-cost, flexible and reliable electricity
providers with strong locational advantages. Our knowledge of these
markets and critical mass also puts us in a position to take advantage of
growth opportunities or quickly respond to changing conditions.
Future Growth
Future growth across our markets will be heavily weighted towards less
carbon-intensive natural gas, wind and solar generation. We will seek
opportunities in these growth areas for projects with long-term, U.S. Dollar-
denominated contracts. The targeted projects will improve the quality of
our cash flow and help us achieve our credit objectives, while reducing the
carbon intensity of our portfolio.
With respect to renewables, we see an attractive business opportunity in
light of several trends, such as:
• The dramatic drop in the cost of renewables that have made their energy
production competitive;
• Growing demand for renewables – renewables have become the dominant
type of new generation build across almost all of our markets; and
• The availability of long-term PPAs for renewables, providing predictable,
stable cash flows.
The intermittent nature of renewables does pose challenges for the grid.
We believe AES’ ability to leverage renewables by integrating them with
conventional generation and energy storage can meet these challenges and
give us a strong competitive advantage.
To that end, we recently agreed to acquire sPower, the largest independent
solar developer in the United States. sPower brings 1.3 GW of installed
capacity with an average remaining contract life of more than 20 years with
very credit-worthy offtakers and a first class management and development
team with a pipeline of more than 10 GW. We are very excited by the scale
and capabilities from this acquisition as we look to expand our renewables
portfolio across all our markets and integrate renewables with our extensive
conventional generation fleet and world-leading energy storage platform.
AES celebrates the 20th anniversay of listing
on the NYSE by ringing the closing bell
CAPITAL ALLOCATION
FOR 2016 ($M)
$100
$79
$312
$290
$394
Closing Cash Balance
Share Buyback
Shareholder Dividend
Investments in Subsidiaries
Debt Prepayment
Total of $1,175 Million in
Discretionary Cash
AES ANNUAL REPORT 2016 | 5
Andrés Gluski, President and Chief Executive Officer
Charles Rossotti, Chairman of the Board
SUSTAINABILITY
AES was named to the Dow Jones
Sustainability Index (DJSI) for North America
for the second year in a row by RobecoSAM.
AES was also named by Ethisphere as one
of the World’s Most Ethical Companies for
the second year in a row.
DELIVERING SUSTAINABLE RESULTS
As a leading sustainable power company, our diverse mix of generation
sources provides us the strength and flexibility to adapt to local and
regional market needs, maximize plant efficiency and deliver reliable,
affordable electricity. Our businesses do much more than just provide
power. Improving lives and making a lasting difference in the communities
in which our businesses operate has always been part of our values and
mission. It is our responsibility to provide infrastructure solutions that
support a sustainable social, economic and environmental future. Our
sustainability activities focus on specific areas, or material aspects, within
the context of five broad strategic initiatives:
• Financial Excellence
• Operational Excellence
• Environmental Performance
• Stakeholder Engagement
• AES People
Our values are at the heart of our operations and these values set us apart
from others in our industry. Every day, our people and businesses around
the world are guided by the following core values:
• Put Safety First
• Act With Integrity
• Honor Our Commitments
• Strive for Excellence
• Have Fun Through Work
Putting safety first for our people, contractors and communities, is our
number one value. Unfortunately, 2016 was a very disappointing year for us
as we experienced a major setback in our safety performance. Eight people
from our generation and distribution businesses, as well as construction
projects, died as a result of workplace injuries. We have a plan in place to
take the information we have from each of these events and use it to help
us deliver on our goal to create a workplace free of incidents.
In 2016, AES was named to the Dow Jones Sustainability Index (DJSI) for
North America for the third year in a row by RobecoSAM. We were also
named by Ethisphere as one of the World’s Most Ethical Companies for the
third year in a row.
CONCLUSION
Our global platform, diverse portfolio mix by generation sources and
technologies, and leading presence in many growing markets, make us well
positioned to meet evolving customer needs and maximize shareholder value.
We will continue to execute on our strategic objectives and seek to be the
low-cost operator of assets in attractive markets, while exercising disciplined
capital allocation that strengthens our credit and reduces overall volatility.
Thank you for your continued support.
Charles O. Rossotti
Chairman of the Board
March 1, 2017
Andrés Gluski
President and
Chief Executive Officer
March 1, 2017
6 | AES ANNUAL REPORT 2016
FINANCIAL MEASURES: NON-GAAP FINANCIAL MEASURES RECONCILIATION (UNAUDITED)
($ in millions, except per share amounts)
Reconciliation of Adjusted Earnings Per Share (1)
Diluted EPS From Continuing Operations
Unrealized derivative gains
Unrealized foreign currency transaction gains
Disposition/acquisition (gains)/losses
Impairment losses
Loss on extinguishment of debt
Less: net income tax benefit
Adjusted Earnings Per Share (1)
Reconciliation of Adjusted Pre-Tax Contribution (14)
Income (loss) from continuing operations attributable to AES
Add back income tax expense from continuing operations attributable to
AES
Pre-tax contribution
Adjustments:
Unrealized derivative gains
Unrealized foreign currency transaction (gains)/losses
Disposition/acquisition (gains)/losses
Impairment losses
Loss on extinguishment of debt
Adjusted Pre-Tax Contribution
Calculation of Maintenance Capital Expenditures for Free Cash Flow (15)
Reconciliation Below:
Maintenance Capital Expenditures
Environmental Capital Expenditures
Growth Capital Expenditures
Total Capital Expenditures
Reconciliation of Proportional Operating Cash Flow (16)
Consolidated Operating Cash Flow
Add: capital expenditures related to service concession assets (18)
Less: Proportional Adjustment Factor (17),(20)
Proportional Operating Cash Flow (16)
Reconciliation of Free Cash Flow (15)
Consolidated Operating Cash Flow
Add: capital expenditures related to service concession assets (18)
Less: Maintenance Capital Expenditures, net of reinsurance proceeds
Less: Non-Recoverable Environmental Capital Expenditures
Free Cash Flow (15)
Reconciliation of Proportional Free Cash Flow (15),(17)
Proportional Operating Cash Flow
Less: Proportional Maintenance Capital Expenditures, net of reinsurance
proceeds and Proportional Non-recoverable Environmental Capital
Expenditures (17),(19)
Year Ended December 31,
2015
2014
2016
$
—
(0.02)
0.04
0.01(2)
1.41(5)
0.05(8)
(0.51)(11)
$ 0.98
$
8
(148)
$ 0.48
(0.24)
0.14
(0.06)(3)
0.73(6)
0.26(9)
(0.06)(12)
$ 1.25
$ 331
275
(140)
606
(9)
23
6
933
29
$ 842
$
624
231
1,603
$ 2,458
$ 2,884
29
(1,032)
$ 1,881
$ 2,884
29
(624)
(45)
$ 2,244
$ 1,881
(464)
(166)
96
(42)
504
179
$ 1,177
$
612
322
1,524
$2,458
$ 2,134
165
(558)
$ 1,741
$ 2,134
165
(612)
(60)
$ 1,627
$ 1,741
(500)
$ 0.97
(0.19)
0.16
(0.50)(4)
0.57(7)
0.38(10)
(0.21)(13)
$ 1.18
$
705
179
884
(135)
110
(361)
415
274
$ 1,187
$
666
241
1,637
$ 2,544
$ 1,791
—
(359)
1,432
$ 1,791
—
(666)
(78)
$ 1,047
$ 1,432
(541)
Proportional Free Cash Flow (15),(17)
$ 1,417
$ 1,241
$ 891
AES ANNUAL REPORT 2016 | 7
(1) We define adjusted earnings per share (“Adjusted EPS”), a non-GAAP measure, as diluted earnings per share from continuing operations excluding gains or losses of
both consolidated entities and entities accounted for under the equity method due to (a) unrealized gains or losses related to derivative transactions, (b) unrealized
foreign currency gains or losses, (c) gains or losses due to dispositions and acquisitions of business interests, (d) losses due to impairments, and (e) costs due to the early
retirement of debt, adjusted for the same gains or losses excluded from consolidated entities. The GAAP measure most comparable to Adjusted EPS is diluted earnings
per share from continuing operations. AES believes that Adjusted EPS better reflects the underlying business performance of the Company and is considered in the
Company’s internal evaluation of financial performance. Factors in this determination include the variability due to unrealized gains or losses related to derivative trans-
actions, unrealized foreign currency gains or losses, losses due to impairments and strategic decisions to dispose or acquire business interests or retire debt, which affect
results in a given period or periods. Adjusted EPS should not be construed as an alternative to diluted earnings per share from continuing operations, which is determined
in accordance with GAAP.
(2) Amount primarily relates to the loss on deconsolidation of UK Wind of $20 million, or $0.03 per share and losses associated with the sale of Sul of $10 million, or $0.02;
partially offset by the gain on sale of DPLER of $22 million, or $0.03 per share.
(3) Amount primarily relates to the gains on the sale of Armenia Mountain of $22 million, or $0.03 per share and from the sale of Solar Spain and Solar Italy of $7 million, or
$0.01 per share.
(4) Amount primarily relates to the gain on the sale of a noncontrolling interest in Masinloc of $283 million, or $0.39 per share; and the gain from the sale of the U.K. wind
projects of $78 million, or $0.11 per share.
(5) Amount primarily relates to asset impairments at DPL of $859 million, or $1.30 per share; $159 million at Buffalo Gap II ($49 million, or $0.07 per share, net of NCI); and
$77 million at Buffalo Gap I ($23 million, or $0.03 per share, net of NCI).
(6) Amount primarily relates to the goodwill impairment at DPL of $317 million, or $0.46 per share, and asset impairments at Kilroot of $121 million ($119 million, or $0.17
per share, net of NCI), at Buffalo Gap III of $116 million ($27 million, or $0.04 per share, net of NCI), and at U.K. Wind (Development Projects) of $38 million ($30 million,
or $0.04 per share, net of NCI).
(7) Amount primarily relates to the goodwill impairments at DPLER of $136 million, or $0.19 per share, and at Buffalo Gap I & II of $28 million, or $0.04 per share; and asset
impairments at Ebute of $67 million ($64 million, or $0.09 per share, net of NCI), at Elsta of $41 million, or $0.06 per share; and the other-than-temporary impairments
at Entek of $86 million, $0.12 per share and at Silver Ridge Power of $42 million, or $0.06 per share.
(8) Amount primarily relates to the loss on early retirement of debt at the Parent Company of $19 million, or $0.03 per share.
(9) Amount primarily relates to the loss on early retirement of debt at the Parent Company of $116 million, or $0.17 per share and at IPL of $22 million ($17 million, or $0.02
per share, net of NCI).
(10) Amount primarily relates to the loss on early retirement of debt at the Parent Company of $200 million, or $0.28 per share, at DPL of $31 million, or $0.04 per share, at
Angamos of $20 million ($14 million, or $0.02 per share, net of NCI) and at U.K. wind projects of $18 million, or $0.02 per share.
(11) Amount primarily relates to the per share income tax benefit associated with asset impairment of $332 million, or $0.50 per share in the twelve months ended December
31, 2016.
(12) Amount primarily relates to the per share income tax benefit associated with losses on extinguishment of debt of $55 million, or $0.08 per share in the twelve months
ended December 31, 2015.
(13) Amount primarily relates to the per share income tax benefit associated with losses on extinguishment of debt of $90 million, or $0.12 per share and dispositions/acquisi-
tions of $67 million, or $0.09 per share in the twelve months ended December 31, 2014.
(14) We define adjusted PTC, a non-GAAP measure, as pre-tax income from continuing operations attributable to AES excluding gains or losses of both consolidated entities
and entities accounted for under the equity method due to (a) unrealized gains or losses related to derivative transactions, (b) unrealized foreign currency gains or losses,
(c) gains or losses due to dispositions and acquisitions of business interests, (d) losses due to impairments, and (e) costs due to the early retirement of debt, adjusted for
the same gains or losses excluded from consolidated entities. Adjusted PTC also includes net equity in earnings of affiliates on an after-tax basis. The GAAP measure
most comparable to Adjusted PTC is income from continuing operations attributable to AES. We believe that Adjusted PTC better reflects the underlying business
performance of the Company and is considered in the Company’s internal evaluation of financial performance. Factors in this determination include the variability due
to unrealized gains or losses related to derivative transactions, unrealized foreign currency gains or losses, losses due to impairments and strategic decisions to dispose or
acquire business interests or retire debt, which affect results in a given period or periods. Earnings before tax represents the business performance of the Company before
the application of statutory income tax rates and tax adjustments, including the effects of tax planning, corresponding to the various jurisdictions in which the Company
operates. Adjusted PTC should not be construed as an alternative to income from continuing operations attributable to AES, which is determined in accordance with
GAAP.
(15) Free cash flow (a non-GAAP financial measure) is defined as net cash from operating activities excluding capital expenditures related to service concession assets, less
maintenance capital expenditures (including non-recoverable environmental capital expenditures), net of reinsurance proceeds from third parties. AES believes that free
cash flow is a useful measure for evaluating our financial condition because it represents the amount of cash provided by operations less maintenance capital expendi-
tures as defined by our businesses, that may be available for investing or for repaying debt. Free cash flow should not be construed as an alternative to net cash from
operating activities, which is determined in accordance with GAAP.
(16) AES is a holding company that derives its income and cash flows from the activities of its subsidiaries, some of which are not wholly-owned by the Company.
Accordingly, the Company has presented certain financial metrics which are defined as Proportional (a non-GAAP financial measure) to account for the Company’s
ownership interest. Proportional metrics present the Company’s estimate of its share in the economics of the underlying metric. The Company believes that the
Proportional metrics are useful to investors because they exclude the economic share in the metric presented that is held by non-AES shareholders. For example, net
cash provided by operating activities (Operating Cash Flow) is a GAAP metric which presents the Company’s cash flow from operations on a consolidated basis, including
operating cash flow allocable to noncontrolling interests. Proportional Operating Cash Flow removes the share of operating cash flow allocable to noncontrolling
interests and therefore may act as an aid in the valuation of the Company. Proportional metrics are reconciled to the nearest GAAP measure. Certain assumptions have
been made to estimate our proportional financial measures. These assumptions include: (i) the Company’s economic interest has been calculated based on a blended
rate for each consolidated business when such business represents multiple legal entities; (ii) the Company’s economic interest may differ from the percentage implied
by the recorded net income or loss attributable to noncontrolling interests or dividends paid during a given period; (iii) the Company’s economic interest for entities
accounted for using the hypothetical liquidation at book value method is 100%; (iv) individual operating performance of the Company’s equity method investments is
not reflected; and (v) inter-segment transactions are included as applicable for the metric presented.
(17) The proportional adjustment factor, proportional maintenance capital expenditures (net of reinsurance proceeds) and proportional non-recoverable environmental
capital expenditures are calculated by multiplying the percentage owned by noncontrolling interests for each entity by its corresponding consolidated cash flow metric
and are totaled to the resulting figures. For example, Parent Company A owns 20% of Subsidiary Company B, a consolidated subsidiary. Thus, Subsidiary Company B
has an 80% noncontrolling interest. Assuming a consolidated net cash flow from operating activities of $100 from Subsidiary B, the proportional adjustment factor for
Subsidiary B would equal $80 (or $100 x 80%). The Company calculates the proportional adjustment factor for each consolidated business in this manner and then sums
these amounts to determine the total proportional adjustment factor used in the reconciliation. The proportional adjustment factor may differ from the proportion
of income attributable to noncontrolling interests as a result of (a) non-cash items which impact income but not cash and (b) AES’ ownership interest in the subsidiary
where such items occur.
(18) Service concession asset expenditures excluded from free cash flow and proportional free cash flow non-GAAP metrics. The Company adopted service concession
accounting effective January 1, 2015.
(19) Excludes IPL’s proportional recoverable environmental capital expenditures of $132 million, $205 million and $163 million for the years ended December 31, 2016, 2015
and 2014, respectively.
(20) Includes proportional adjustment amount for service concession asset expenditures of $15 million and $84 million for the years ended December 31, 2016 and 2015,
respectively. The Company adopted service concession accounting effective January 1, 2015.
8 | AES ANNUAL REPORT 2016
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
____________________________________
FORM 10-K
_____________________________________
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the Fiscal Year Ended December 31, 2016
-OR-
TRANSITION REPORT FILED PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 1-12291
THE AES CORPORATION
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
4300 Wilson Boulevard Arlington, Virginia
(Address of principal executive offices)
54 1163725
(I.R.S. Employer
Identification No.)
22203
(Zip Code)
Registrant's telephone number, including area code: (703) 522-1315
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Common Stock, par value $0.01 per share
AES Trust III, $3.375 Trust Convertible Preferred Securities
Name of Each Exchange on Which Registered
New York Stock Exchange
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes
No
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act.
Yes
No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes
No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12
months (or for such shorter period that the registrant was required to submit and post such files). Yes
No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and
will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a
smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in
Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
Accelerated filer
Non-accelerated filer
(Do not check if a smaller
reporting company)
Smaller reporting company
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
No
The aggregate market value of the voting and non-voting common equity held by non-affiliates on June 30, 2016, the last
business day of the Registrant's most recently completed second fiscal quarter (based on the adjusted closing sale price of
$12.48 of the Registrant's Common Stock, as reported by the New York Stock Exchange on such date) was approximately $8.22
billion.
The number of shares outstanding of Registrant's Common Stock, par value $0.01 per share, on February 17, 2017 was
659,183,208
Portions of Registrant's Proxy Statement for its 2017 annual meeting of stockholders are incorporated by reference in Parts
DOCUMENTS INCORPORATED BY REFERENCE
II and III
THE AES CORPORATION FISCAL YEAR 2016 FORM 10-K
TABLE OF CONTENTS
Glossary of Terms
PART I
ITEM 1. BUSINESS
ITEM 1A. RISK FACTORS
ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 2. PROPERTIES
ITEM 3. LEGAL PROCEEDINGS
ITEM 4. MINE SAFETY DISCLOSURES
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY
SECURITIES
ITEM 6. SELECTED FINANCIAL DATA
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Executive Summary
Overview of 2016 Results and Strategic Performance
Review of Consolidated Results of Operations
SBU Performance Analysis
Key Trends and Uncertainties
Capital Resources and Liquidity
Critical Accounting Policies and Estimates
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income
Consolidated Statements of Changes in Equity
Consolidated Statements of Cash Flows
Note 1 - General and Summary of Significant Accounting Policies
Note 2 - Inventory
Note 3 - Property, Plant and Equipment
Note 4 - Fair Value
Note 5 - Derivative Instruments and Hedging Activities
Note 6 - Financing Receivables
Note 7 - Investments in and Advances to Affiliates
Note 8 - Other Non-Operating Expense
Note 9 - Goodwill and Other Intangible Assets
Note 10 - Regulatory Assets and Liabilities
Note 11 - Debt
Note 12 - Commitments
Note 13 - Contingencies
Note 14 - Benefit Plans
Note 15 - Equity
Note 16 - Segment and Geographic Information
Note 17 - Share-Based Compensation
Note 18 - Redeemable Stock of Subsidiaries
Note 19 - Other Income and Expense
Note 20 - Asset Impairment Expense
Note 21 - Income Taxes
Note 22 - Discontinued Operations
Note 23 - Dispositions
Note 24 - Acquisitions
Note 25 - Earnings Per Share
Note 26 - Risks and Uncertainties
Note 27 - Related Party Transactions
Note 28 - Selected Quarterly Financial Data (Unaudited)
Note 29 - Subsequent Events
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9B. OTHER INFORMATION
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS, AND DIRECTOR INDEPENDENCE
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
PART IV - ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
SIGNATURES
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When the following terms and abbreviations appear in the text of this report, they have the meanings indicated
GLOSSARY OF TERMS
below:
Adjusted Earnings Per Share, a non-GAAP measure
Adjusted Pretax Contribution, a non-GAAP measure of operating performance
The Parent Company and its subsidiaries and affiliates
Allowance for Funds Used During Construction
Brazilian National Electric Energy Agency
Accumulated Other Comprehensive Loss
Accounting Standards Codification
National Authority of Public Services
Best Available Control Technology
Best Available Retrofit Technology
Brazilian Development Bank
Build, Operate and Transfer
Best Technology Available
United States Clean Air Act
Wholesale Electric Market Administrator in Argentina
Combined Cycle Gas Turbine
Brazilian equivalent to LIBOR
La Caisse de depot et placement du Quebec
Chief Executive Officer
Comprehensive Environmental Response, Compensation and Liability Act of 1980 (a.k.a. "Superfund")
Circulating Fluidized Bed Boiler
Combined Heat and Power
Contribuição para o Financiamento da Seguridade Social
Carbon Dioxide
Committee of Sponsoring Organizations of the Treadway Commission
Capacity Performance
Certificate of Public Convenience and Necessity
Clean Power Plan
Competitive Retail Electric Service
Cross-State Air Pollution Rule
U.S. Clean Water Act
Adjusted EPS
Adjusted PTC
AES
AFUDC
ANEEL
AOCL
ASC
ASEP
BACT
BART
BNDES
BOT
BTA
CAA
CAMMESA
CCGT
CDI
CDPQ
CEO
CERCLA
CFB
CHP
COFINS
CO2
COSO
CP
CPCN
CPP
CRES
CSAPR
CWA
Dodd-Frank Act Dodd-Frank Wall Street Reform and Consumer Protection Act
DP&L
DPL
DPLE
The Dayton Power & Light Company
DPL Inc.
DPL Energy, LLC, a wholly-owned subsidiary of DPL (renamed AES Ohio Generation, LLC effective
2/1/2016)
DPL Energy Resources, Inc.
Dominican Power Partners
Earnings before Interest, Taxes, Depreciation & Amortization
European Market Infrastructure Regulation
United States Environmental Protection Agency
Engineering, Procurement, and Construction
Energy Regulatory Commission
Electric Reliability Council of Texas
Electric Security Plan
European Union Greenhouse Gas Emission Trading Scheme
Euro Inter Bank Offered Rate
Electric Utility Steam Generating Unit
Electricity of Vietnam
Executive Vice President
Fuel Adjustment Charges
Financial Accounting Standards Board
Federal Energy Regulatory Commission
DPLER
DPP
EBITDA
EMIR
EPA
EPC
ERC
ERCOT
ESP
EU ETS
EURIBOR
EUSGU
EVN
EVP
FAC
FASB
FERC
FONINVEMEM Fund for the Investment Needed to Increase the Supply of Electricity in the Wholesale Market
FPA
FX
GAAP
GHG
GRIDCO
Federal Power Act
Foreign Exchange
Generally Accepted Accounting Principles in the United States
Greenhouse Gas
Grid Corporation of Odisha Ltd.
1
Gigawatt Hours
Hypothetical Liquidation Book Value
Indiana Department of Environmental Management
International Finance Corporation
IPALCO Enterprises, Inc.
Indiana, Indianapolis Power & Light Company
Independent Power Producers
Independent System Operator
Indiana Utility Regulatory Commission
Kilowatt Hours
London Inter Bank Offered Rate
Liquefied Natural Gas
Mercury and Air Toxics Standards
Midcontinent Independent System Operator, Inc.
Megawatts
Megawatt Hours
Noncontrolling Interest
Natsionalna Elektricheska Kompania (state-owned electricity public supplier in Bulgaria)
North American Electric Reliability Corporation
Natural Gas Combined Cycle
Notice of Violation
Nitrogen Dioxide
National Pollutant Discharge Elimination System
New Source Performance Standards
New York Independent System Operator, Inc.
New York Stock Exchange
Operations and Maintenance
Odisha Power Generation Corporation, Ltd.
GWh
HLBV
IDEM
IFC
IPALCO
IPL
IPP
ISO
IURC
kWh
LIBOR
LNG
MATS
MISO
MW
MWh
NCI
NEK
NERC
NGCC
NOV
NOX
NPDES
NSPS
NYISO
NYSE
O&M
OPGC
Parent Company The AES Corporation
PCB
Pet Coke
PIS
PJM
PM
PPA
PREPA
PSA
PSD
PSU
PUCO
PURPA
QF
RGGI
RMRR
RPM
RSU
RTO
SADI
SBU
SCE
SEC
SEM
SIC
SIN
SING
SIP
SNE
SO2
SSO
TA
TECONS
U.S.
VAT
Polychlorinated biphenyl
Petroleum Coke
Partially Integrated System
PJM Interconnection, LLC
Particulate Matter
Power Purchase Agreement
Puerto Rico Electric Power Authority
Power Supply Agreement
Prevention of Significant Deterioration
Performance Stock Unit
The Public Utilities Commission of Ohio
Public Utility Regulatory Policies Act
Qualifying Facility
Regional Greenhouse Gas Initiative
Routine Maintenance, Repair and Replacement
Reliability Pricing Model
Restricted Stock Unit
Regional Transmission Organization
Argentine Interconnected System
Strategic Business Unit
Southern California Edison
United States Securities and Exchange Commission
Single Electricity Market
Central Interconnected Electricity System
National Interconnected System
Northern Interconnected Electricity System
State Implementation Plan
National Secretary of Energy
Sulfur Dioxide
Standard Service Offer
Transportation Agreement
Term Convertible Preferred Securities
United States
Value Added Tax
2
VIE
Vinacomin
WACC
Variable Interest Entity
Vietnam National Coal-Mineral Industries Holding Corporation Ltd.
Weighted Average Cost of Capital
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PART I
In this Annual Report the terms “AES,” “the Company,” “us,” or “we” refer to The AES Corporation and all of its
subsidiaries and affiliates, collectively. The terms “The AES Corporation” and “Parent Company” refer only to the
parent, publicly held holding company, The AES Corporation, excluding its subsidiaries and affiliates.
FORWARD-LOOKING INFORMATION
In this filing we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and
future events or performance. Such statements are “forward-looking statements” within the meaning of the Private
Securities Litigation Reform Act of 1995. Although we believe that these forward-looking statements and the
underlying assumptions are reasonable, we cannot assure you that they will prove to be correct.
Forward-looking statements involve a number of risks and uncertainties, and there are factors that could
cause actual results to differ materially from those expressed or implied in our forward-looking statements. Some of
those factors (in addition to others described elsewhere in this report and in subsequent securities filings) include:
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the economic climate, particularly the state of the economy in the areas in which we operate, including the
fact that the global economy faces considerable uncertainty for the foreseeable future, which further
increases many of the risks discussed in this Form 10-K;
changes in inflation, demand for power, interest rates and foreign currency exchange rates, including our
ability to hedge our interest rate and foreign currency risk;
changes in the price of electricity at which our generation businesses sell into the wholesale market and our
utility businesses purchase to distribute to their customers, and the success of our risk management
practices, such as our ability to hedge our exposure to such market price risk;
changes in the prices and availability of coal, gas and other fuels (including our ability to have fuel
transported to our facilities) and the success of our risk management practices, such as our ability to hedge
our exposure to such market price risk, and our ability to meet credit support requirements for fuel and
power supply contracts;
changes in and access to the financial markets, particularly changes affecting the availability and cost of
capital in order to refinance existing debt and finance capital expenditures, acquisitions, investments and
other corporate purposes;
our ability to manage liquidity and comply with covenants under our recourse and non-recourse debt,
including our ability to manage our significant liquidity needs and to comply with covenants under our senior
secured credit facility and other existing financing obligations;
changes in our or any of our subsidiaries' corporate credit ratings or the ratings of our or any of our
subsidiaries' debt securities or preferred stock, and changes in the rating agencies' ratings criteria;
our ability to purchase and sell assets at attractive prices and on other attractive terms;
our ability to compete in markets where we do business;
our ability to manage our operational and maintenance costs, the performance and reliability of our
generating plants, including our ability to reduce unscheduled down times;
our ability to locate and acquire attractive "greenfield" or "brownfield" projects and our ability to finance,
construct and begin operating our "greenfield" or "brownfield" projects on schedule and within budget;
our ability to enter into long-term contracts, which limit volatility in our results of operations and cash flow,
such as PPAs, fuel supply, and other agreements and to manage counterparty credit risks in these
agreements;
variations in weather, especially mild winters and cooler summers in the areas in which we operate, the
occurrence of difficult hydrological conditions for our hydropower plants, as well as hurricanes and other
storms and disasters, and low levels of wind or sunlight for our wind and solar facilities;
our ability to meet our expectations in the development, construction, operation and performance of our
new facilities, whether greenfield, brownfield or investments in the expansion of existing facilities;
the success of our initiatives in other renewable energy projects, as well as GHG emissions reduction
projects and energy storage projects;
our ability to keep up with advances in technology;
the potential effects of threatened or actual acts of terrorism and war;
the expropriation or nationalization of our businesses or assets by foreign governments, with or without
adequate compensation;
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our ability to achieve reasonable rate treatment in our utility businesses;
changes in laws, rules and regulations affecting our international businesses;
changes in laws, rules and regulations affecting our North America business, including, but not limited to,
regulations which may affect competition, the ability to recover net utility assets and other potential
stranded costs by our utilities;
changes in law resulting from new local, state, federal or international energy legislation and changes in
political or regulatory oversight or incentives affecting our wind business and solar projects, our other
renewables projects and our initiatives in GHG reductions and energy storage, including tax incentives;
changes in environmental laws, including requirements for reduced emissions of sulfur, nitrogen, carbon,
mercury, hazardous air pollutants and other substances, GHG legislation, regulation and/or treaties and
coal ash regulation;
changes in tax laws and the effects of our strategies to reduce tax payments;
the effects of litigation and government and regulatory investigations;
our ability to maintain adequate insurance;
decreases in the value of pension plan assets, increases in pension plan expenses and our ability to fund
defined benefit pension and other postretirement plans at our subsidiaries;
losses on the sale or write-down of assets due to impairment events or changes in management intent with
regard to either holding or selling certain assets;
changes in accounting standards, corporate governance and securities law requirements;
our ability to maintain effective internal controls over financial reporting;
our ability to attract and retain talented directors, management and other personnel, including, but not
limited to, financial personnel in our foreign businesses that have extensive knowledge of accounting
principles generally accepted in the United States; and
information security breaches.
These factors in addition to others described elsewhere in this Form 10-K, including those described under
Item 1A.—Risk Factors, and in subsequent securities filings, should not be construed as a comprehensive listing of
factors that could cause results to vary from our forward-looking information.
We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of
new information, future events, or otherwise. If one or more forward-looking statements are updated, no inference
should be drawn that additional updates will be made with respect to those or other forward-looking statements.
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ITEM 1. BUSINESS
Item 1. Business is an outline of our strategy and our businesses by SBU, including key financial drivers.
Additional items that may have an impact on our businesses are discussed in Item 1A.—Risk Factors and Item 3.—
Legal Proceedings.
Executive Summary
Incorporated in 1981, AES is a diversified power generation and utility company, providing affordable,
sustainable energy through our diverse portfolio of thermal and renewable generation facilities as well as
distribution businesses. Our vision is to be the world's leading sustainable power company by leveraging our
unique electricity platforms and the knowledge of our people to provide the energy and infrastructure solutions our
customers truly need. Our people share a passion to help meet the world's current and increasing energy needs,
while providing communities and countries the opportunity for economic growth due to the availability of reliable,
affordable electric power.
Future growth across our company will be heavily weighted towards less carbon-intensive wind, solar and gas
generation. Growth in renewables not only provides an opportunity for direct investments in wind and solar
generation, but also presents significant potential for energy storage. We are a leader in lithium ion, battery-based
energy storage, with more than 400 MW in operation, under construction or in advanced development across seven
countries. We believe lithium ion-based energy storage will play a critical role in an increasingly renewables-based
generation mix. With our technological experience, presence in key markets and channel sales partnerships, we are
positioned to capitalize on this rapidly growing market.
Additionally, we have been expanding our LNG infrastructure in Central America, where we are helping to
displace oil-fired generation in favor of a cheaper and cleaner alternative. In the United States, at IPL, we recently
completed a multi-year rate-base investment in environmental upgrades to our coal plants and are in the process of
re-powering several units from coal to gas.
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Strategic Priorities
We have made significant progress towards meeting our strategic goals to maximize value for our
shareholders.
Focusing our growth in markets where we already operate and have a competitive advantage to realize attractive risk-
adjusted returns
Leveraging Our Platforms
In 2016, brought on-line nine projects for a total of 2,976 MW
3,389 MW currently under construction
Represents $6.4 billion in total capital expenditures
Majority of AES’ $1.1 billion in equity already funded
Expected to come on-line through 2019
Will continue to advance select projects from our development pipeline
Reducing Complexity
Exiting businesses and markets where we do not have a competitive advantage, simplifying our portfolio and reducing
risk
Since 2011
Sold assets to generate $3.6 billion in equity proceeds
Decreased total number of countries where we have operations from 28 to 17
In 2016, announced or closed $510 million in equity proceeds from sales or sell-downs of six businesses
Striving to be the low-cost manager of a portfolio of assets and deriving synergies and scale from our businesses
In 2015, launched a $150 million cost reduction and revenue enhancement initiative
Includes overhead reductions, procurement efficiencies and operational improvements
Achieved $50 million in savings in 2016 and expect to ramp up to a total of $150 million in 2018
Performance Excellence
Optimizing risk-adjusted returns in existing businesses and growth projects
Expanding Access to Capital
Adjust our global exposure to commodity, fuel, country and other macroeconomic risks
Building strategic partnerships at the project and business level with an aim to optimize our risk-adjusted returns in our
business and growth projects.
Allocating Capital in a Disciplined Manner
Maximizing risk-adjusted returns to our shareholders by investing our free cash flow to strengthen our credit and deliver
attractive growth in cash flow and earnings
In 2016, we generated substantial cash by executing on our strategy, which we allocated in line with our capital
allocation framework
Used $312 million to prepay and refinance Parent Company debt
Returned $369 million to shareholders through share repurchases and quarterly dividends
Increased our quarterly dividend by 9.1% to $0.12 per share beginning in the first quarter of 2017
Invested $394 million in our subsidiaries
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(1)
Investments in subsidiaries excludes $2.2 billion investment in DPL.
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Segments
We are organized into six market-oriented strategic business units ("SBUs"): US (United States), Andes
(Chile, Colombia, and Argentina), Brazil, MCAC (Mexico, Central America and the Caribbean), Europe, and Asia
— which are led by our SBU Presidents. Within our six SBUs, we have two lines of business. The first business line
is generation, where we own and/or operate power plants to generate and sell power to customers, such as utilities,
industrial users, and other intermediaries. The second business line is utilities, where we own and/or operate
utilities to generate or purchase, distribute, transmit and sell electricity to end-user customers in the residential,
commercial, industrial and governmental sectors within a defined service area. In certain circumstances, our utilities
also generate and sell electricity on the wholesale market.
The Company measures the operating performance of its SBUs using Adjusted PTC and Proportional Free
Cash Flow, both of which are non-GAAP measures. The Adjusted PTC and Proportional Free Cash Flow by SBU
for the year ended December 31, 2016 are shown below. The percentages for Adjusted PTC and Proportional Free
Cash Flow are the contribution by each SBU to the gross metric, i.e., the total Adjusted PTC by SBU, before
deductions for Corporate. See Item 7.—Management's Discussion and Analysis SBU Performance Analysis of this
Form 10-K for reconciliation and definitions of Adjusted PTC and Proportional Free Cash Flow.
The following summarizes our businesses within our six SBUs.
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Overview
Generation
We currently own and/or operate a generation portfolio of 30,379 MW, excluding the generation capabilities of
our integrated utilities. Our generation fleet is diversified by fuel type. See discussion below under Fuel Costs.
Performance drivers of our generation businesses include types of electricity sales agreements, plant
reliability and flexibility, fuel costs, seasonality, weather variations and economic activity, fixed-cost management,
and competition.
Electricity Sales Contracts — Our generation businesses sell electricity under medium- or long-term contracts
("contract sales") or under short-term agreements in competitive markets ("short-term sales").
Contract Sales — Most of our generation fleet sells electricity under contracts. Our medium-term contract
sales have a term of 2 to 5 years, while our long-term contracts have a term of more than 5 years. Across our
portfolio, the average remaining contract term is 6 years.
In contract sales, our generation businesses recover variable costs including fuel and variable O&M costs,
either through direct or indexation-based contractual pass-throughs or tolling arrangements. When the contract
does not include a fuel pass-through, we typically hedge fuel costs or enter into fuel supply agreements for a similar
contract period (see discussion under the Fuel Costs section below). These contracts are intended to reduce
exposure to the volatility of fuel prices and electricity prices by linking the business's revenues and costs. These
contracts also help us to fund a significant portion of the total capital cost of the project through long-term non-
recourse project-level financing.
Capacity Payments and Contract Sales — Most of our contract sales include a capacity payment that covers
projected fixed costs of the plant, including fixed O&M expenses and a return on capital invested. In addition, most
of our contracts require that the majority of the capacity payment be denominated in the currency matching our
fixed costs. We generally structure our business to eliminate or reduce foreign exchange risk by matching the
currency of revenue and expenses, including fixed costs and debt. Our project debt may consist of both fixed and
floating rate debt for which we typically hedge a significant portion of our exposure. Some of our contracted
businesses also receive a regulated market-based capacity payment, which is discussed in more detail in the
Capacity Payments and Short-Term Sales section below.
Thus, these contracts, or other related commercial arrangements, significantly mitigate our exposure to
changes in power and fuel prices, currency fluctuations and changes in interest rates. In addition, these contracts
generally provide for a recovery of our fixed operating expenses and a return on our investment, as long as we
operate the plant to the reliability and efficiency standards required in the contract.
Short-Term Sales — Our other generation businesses sell power and ancillary services under short-term
contracts with an average term of less than 2 years, including spot sales, directly in the short-term market, or, in
some cases, at regulated prices. The short-term markets are typically administered by a system operator to
coordinate dispatch. Short-term markets generally operate on merit order dispatch, where the least expensive
generation facilities, based upon variable cost or bid price, are dispatched first and the most expensive facilities are
dispatched last. The short-term price is typically set at the marginal cost of energy or bid price (the cost of the last
plant required to meet system demand). As a result, the cash flows and earnings associated with these businesses
are more sensitive to fluctuations in the market price for electricity. In addition, many of these wholesale markets
include markets for ancillary services to support the reliable operation of the transmission system. Across our
portfolio, we provide a wide array of ancillary services, including voltage support, frequency regulation and spinning
reserves.
In certain markets, such as Argentina and Kazakhstan, a regulator establishes the prices for electricity and
fuel and adjusts them periodically for inflation, changes in fuel prices and other factors. In these cases, our
businesses are particularly sensitive to changes in regulation.
Capacity Payments — Many of the markets in which we operate include regulated capacity markets. These
capacity markets are intended to provide additional revenue based upon availability without reliance on the energy
margin from the merit order dispatch. Capacity markets are typically priced based on the cost of a new entrant and
the system capacity relative to the desired level of reserve margin (generation available in excess of peak demand).
Our generating facilities selling in the short-term markets typically receive capacity payments based on their
availability in the market. Our most significant capacity revenues are earned by our generation capacity in Ohio and
Northern Ireland.
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Plant Reliability and Flexibility — Our contract and short-term sales provide incentives to our generation plants
to optimally manage availability, operating efficiency and flexibility. Capacity payments under contract sales are
frequently tied to meeting minimum standards. In short-term sales, our plants must be reliable and flexible to
capture peak market prices and to maximize market-based revenues. In addition, our flexibility allows us to capture
ancillary service revenue while meeting local market needs.
Fuel Costs — For our thermal generation plants, fuel is a significant component of our total cost of generation.
For contract sales, we often enter into fuel supply agreements to match the contract period, or we may hedge our
fuel costs. Some of our contracts have periodic adjustments for changes in fuel cost indices. In those cases, we
have fuel supply agreements with shorter terms to match those adjustments. For certain projects, we have tolling
arrangements where the power offtaker is responsible for the supply and cost of fuel to our plants.
In short-term sales, we sell power at market prices that are generally reflective of the market cost of fuel at the
time, and thus procure fuel supply on a short-term basis, generally designed to match up with our market sales
profile. Since fuel price is often the primary determinant for power prices, the economics of projects with short-term
sales are often subject to volatility of relative fuel prices. For further information regarding commodity price risk
please see Item 7A.—Quantitative and Qualitative Disclosures about Market Risk in this Form 10-K.
34% of the capacity of our generation fleet is coal-fired. In the U.S., most of our plants are supplied from
domestic coal. At our non-U.S. generation plants, and at our plant in Hawaii, we source coal internationally. Across
our fleet, we utilize our global sourcing program to maximize the purchasing power of our fuel procurement.
33% of the capacity of our generation plants are fueled by natural gas. Generally, we use gas from local
suppliers in each market. A few exceptions to this are AES Gener in Chile, where we purchase imported gas from
third parties, and our plants in the Dominican Republic, where we import LNG to utilize in the local market.
27% of the capacity of our generation plants are fueled by renewables, including hydro, wind and energy
storage, which do not have significant fuel costs.
6% of the capacity of our generation fleet utilizes oil, diesel and petroleum coke ("pet coke") for fuel. Oil and
diesel are sourced locally at prices linked to international markets, while pet coke is largely sourced from Mexico
and the U.S.
Renewable Generation Facilities — We currently own and operate 8,228 MW (4,293 proportional MW) of
renewable generation, including hydro, wind, energy storage, solar, biomass and landfill gas.
Seasonality, Weather Variations and Economic Activity — Our generation businesses are affected by seasonal
weather patterns throughout the year and, therefore, operating margin is not generated evenly by month during the
year. Additionally, weather variations, including temperature, solar and wind resources, and hydrological conditions,
may also have an impact on generation output at our renewable generation facilities. In competitive markets for
power, local economic activity can also have an impact on power demand and short-term prices for power.
Fixed-Cost Management — In our businesses with long-term contracts, the majority of the fixed O&M costs
are recovered through the capacity payment. However, for all generation businesses, managing fixed costs and
reducing them over time is a driver of business performance.
Competition — For our businesses with medium- or long-term contracts, there is limited competition during the
term of the contract. For short-term sales, plant dispatch and the price of electricity are determined by market
competition and local dispatch and reliability rules.
Utilities
AES' seven utility businesses distribute power to 9.4 million people in three countries. AES' two utilities in the
U.S. also include generation capacity totaling 6,314 MW. The utility businesses have a variety of structures, ranging
from integrated utility to pure transmission and distribution businesses.
In general, our utilities sell electricity directly to end-users, such as homes and businesses, and bill customers
directly. Key performance drivers for utilities include the regulated rate of return and tariff, seasonality, weather
variations, economic activity, reliability of service and competition. Revenue from utilities is classified as regulated in
the Consolidated Statements of Operations.
Regulated Rate of Return and Tariff — In exchange for the exclusive right to sell or distribute electricity in a
franchise area, our utility businesses are subject to government regulation. This regulation sets the prices ("tariffs")
that our utilities are allowed to charge retail customers for electricity and establishes service standards that we are
required to meet.
13
Our utilities are generally permitted to earn a regulated rate of return on assets, determined by the regulator
based on the utility's allowed regulatory asset base, capital structure and cost of capital. The asset base on which
the utility is permitted a return is determined by the regulator and is based on the amount of assets that are
considered used and useful in serving customers. Both the allowed return and the asset base are important
components of the utility's earning power. The allowed rate of return and operating expenses deemed reasonable
by the regulator are recovered through the regulated tariff that the utility charges to its customers.
The tariff may be reviewed and reset by the regulator from time to time depending on local regulations, or the
utility may seek a change in its tariffs. The tariff is generally based upon a certain usage level and may include a
pass-through to the customer of costs that are not controlled by the utility, such as the costs of fuel (in the case of
integrated utilities) and/or the costs of purchased energy. In addition to fuel and purchased energy, other types of
costs may be passed through to customers via an existing mechanism, such as certain environmental expenditures
that are covered under an environmental tracker at our utility in Indiana, IPL. Components of the tariff that are
directly passed through to the customer are usually adjusted through a summary regulatory process or an existing
formula-based mechanism. In some regulatory regimes, customers with demand above an established level are
unregulated and can choose to contract with other retail energy suppliers directly and pay wheeling and other non-
bypassable fees, which are fees to the distribution company for use of its distribution system.
The regulated tariff generally recognizes that our utility businesses should recover certain operating and fixed
costs, as well as manage uncollectible amounts, quality of service and non-technical losses. Utilities, therefore,
need to manage costs to the levels reflected in the tariff, or risk non-recovery of costs or diminished returns.
Seasonality, Weather Variations and Economic Activity — Our utility businesses are affected by seasonal
weather patterns throughout the year and, therefore, the operating revenues and associated operating expenses
are not generated evenly by month during the year. Additionally, weather variations may also have an impact based
on the number of customers, temperature variances from normal conditions and customers' historic usage levels
and patterns. The retail kWh sales, after adjustments for weather variations, are affected by changes in local
economic activity, energy efficiency and distributed generation initiatives, as well as the number of retail customers.
Reliability of Service — Our utility businesses must meet certain reliability standards, such as duration and
frequency of outages. Those standards may be specific with incentives or penalties for performance against these
standards. In other cases, the standards are implicit and the utility must operate to meet customer expectations.
Competition — Our integrated utilities, IPL and DP&L, operate as the sole distributor of electricity within their
respective jurisdictions. Our businesses own and operate all of the businesses and facilities necessary to generate,
transmit and distribute electricity. Competition in the regulated electric business is primarily from the on-site
generation for industrial customers; however, in Ohio, customers in our service territory have the ability to switch to
alternative suppliers for their generation service. Our integrated utilities, particularly DP&L, are exposed to the
volatility in wholesale prices to the extent our generating capacity exceeds the native load served under the
regulated tariff and short-term contracts. See the full discussion under the US SBU.
At our pure transmission and distribution businesses, such as those in Brazil and El Salvador, we face
relatively limited competition due to significant barriers to entry. At many of these businesses, large customers, as
defined by the relevant regulator, have the option to both leave and return to regulated service.
Development and Construction
We develop and construct new generation facilities. For our utility businesses, new plants may be built in
response to customer needs or to comply with regulatory developments and are developed subject to regulatory
approval that permits recovery of our capital cost and a return on our investment. For our generation businesses,
our priority for development is platform expansion opportunities, where we can add on to our existing facilities in our
key platform markets where we have a competitive advantage. We make the decision to invest in new projects by
evaluating the project returns and financial profile against a fair risk-adjusted return for the investment and against
alternative uses of capital, including corporate debt repayment and share buybacks.
In some cases, we enter into long-term contracts for output from new facilities prior to commencing
construction. To limit required equity contributions from The AES Corporation, we also seek non-recourse project
debt financing and other sources of capital, including partners where it is commercially attractive. For construction,
we typically contract with a third party to manage construction, although our construction management team
supervises the construction work and tracks progress against the project's budget and the required safety, efficiency
and productivity standards.
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Segments
The segment reporting structure uses the Company's management reporting structure as its foundation to
reflect how the Company manages the business internally. It is organized by geographic regions which provide a
socio-political-economic understanding of our business. For financial reporting purposes, the Company's corporate
activities are reported within "Corporate and Other" because they do not require separate disclosure. See Item 7.—
Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 16—Segment
and Geographic Information included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K
for further discussion of the Company's segment structure.
US SBU
Our US SBU has 18 generation facilities and two integrated utilities in the United States.
Generation — Operating installed capacity of our US SBU totals 11,929 MW. IPL's parent, IPALCO
Enterprises, Inc., and DPL Inc. are voluntary SEC registrants, and as such, follow public filing requirements of the
Securities Exchange Act of 1934. The following table lists our US SBU generation facilities:
Business
Location
Fuel
Southland—Alamitos
Southland—Redondo Beach
Southland—Huntington Beach
Shady Point
Buffalo Gap II (1),(2)
Hawaii
Warrior Run
Buffalo Gap III (1)
Buffalo Gap I (1)
Laurel Mountain
Distributed PV - Commercial &
Utility (1) (3)
Mountain View I & II
Mountain View IV
Laurel Mountain ES
Tait ES
Distributed PV - Residential (1) (3)
Warrior Run ES
Advancion Applications Center
U.S.-PA
Gas
U.S.-CA
Gas
U.S.-CA
Gas
U.S.-CA
Coal
U.S.-OK
Wind
U.S.-TX
Coal
U.S.-HI
Coal
U.S.-MD
Wind
U.S.-TX
Wind
U.S.-TX
U.S.-WV
Wind
U.S.-Various Solar
U.S.-CA
U.S.-CA
U.S.-WV
U.S.-OH
Wind
Wind
Energy
Storage
Energy
Storage
U.S.-Various Solar
U.S.-MD
Energy
Storage
Energy
Storage
AES
Equity
Interest
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
Gross
MW
2,075
1,392
474
360
233
206
205
170
119
98
89
67
49
32
20
14
10
2
5,615
Year Acquired
or Began
Operation
Contract
Expiration
Date
Customer(s)
2018 Southern California Edison
2018 Southern California Edison
2018 Southern California Edison
Oklahoma Gas & Electric
2018
Direct Energy
2017
Hawaiian Electric Co.
2022
First Energy
2030
2021
Direct Energy
2029-2042
Utility, Municipality,
Education, Non-Profit
2021 Southern California Edison
2032 Southern California Edison
2037-2040
Residential
1998
1998
1998
1991
2007
1992
2000
2008
2006
2011
2015-2016
2008
2012
2011
2013
2015
2016
2013
_____________________________
(1) AES owns these assets together with third-party tax equity investors with variable ownership interests. The tax equity investors receive a portion of the economic
attributes of the facilities, including tax attributes, that vary over the life of the projects. The proceeds from the issuance of tax equity are recorded as
noncontrolling interest in the Company's Consolidated Balance Sheets.
(2) Power Purchase Agreement with Direct Energy is for 80% of annual expected energy output.
(3) AES operates these facilities located throughout the U.S. through management or O&M agreements as of December 31, 2016.
Under construction — The following table lists our plants under construction in the US SBU:
Business
Eagle Valley CCGT
Distributed PV - Commercial
Location
U.S.-IN
U.S.-Various
Fuel
Gas
Solar
Gross MW AES Equity Interest
70%
100%
671
10
681
Expected Date of Commercial Operations
1H 2018
1H 2017
Utilities — The following table lists our U.S. utilities and their generation facilities:
Business
Location
DPL (1)
IPL (2)
U.S.-OH
U.S.-IN
Approximate Number of Customers
Served as of 12/31/2016
GWh Sold in
2016
519,000
490,000
1,009,000
16,757
14,186
30,943
Fuel
Coal/Gas/Oil
Coal/Gas/Oil
Gross
MW
3,066
3,248
6,314
AES Equity
Interest
Year Acquired or
Began Operation
100%
70%
2011
2001
_____________________________
(1) DPL subsidiary DP&L has the following plants: Tait Units 1-3 and diesels, Yankee Street, Yankee Solar, Monument and Sidney. DP&L jointly owned plants:
Conesville Unit 4, Killen, Miami Fort Units 7 & 8, Stuart and Zimmer. In addition to the above, DP&L also owns a 4.9% equity ownership in OVEC ("Ohio Valley
Electric Corporation"), an electric generating company. OVEC has two plants in Cheshire, Ohio and Madison, Indiana with a combined generation capacity of
15
approximately 2,109 MW. DP&L's share of this generation capacity is approximately 103 MW. AES Ohio Generation, LLC plants: Tait Units 4-7 and Montpelier
Units 1-4.
(2) CDPQ owns direct and indirect interests in IPALCO which total 30%. AES owns 85% of AES US Investments and AES US Investments owns 82.35% of IPALCO.
IPL plants: Georgetown, Harding Street, Petersburg and Eagle Valley (new CCGT currently under construction). 3.2 MW of IPL total is considered a transmission
asset.
The following map illustrates the location of our U.S. facilities:
U.S. Businesses
U.S. Utilities
IPALCO
Business Description — IPALCO owns all of the outstanding common stock of IPL. IPL is engaged primarily in
generating, transmitting, distributing and selling electric energy to approximately 490,000 retail customers in the city
of Indianapolis and neighboring areas within the state of Indiana. IPL has an exclusive right to provide electric
service to those customers. IPL's service area covers about 528 square miles with an estimated population of
approximately 939,000. IPL owns and operates four generating stations. IPL’s largest generating station,
Petersburg, is coal-fired. The second largest station, Harding Street, has converted its coal-fired units to natural gas
and uses natural gas and fuel oil to power combustion turbines. The third, Eagle Valley, retired its coal-fired units in
April 2016 and their CCGT is expected to be completed in the first half of 2018. The fourth station, Georgetown, is a
small peaking station that uses natural gas to power combustion turbines. As of December 31, 2016, IPL's net
electric generation capacity for winter is 2,993 MW and net summer capacity is 2,878 MW.
Market Structure — IPL is one of many transmission system owner members in the MISO. MISO is a RTO,
which maintains functional control over the combined transmission systems of its members and manages one of the
largest energy and ancillary services markets in the U.S. IPL offers the available electricity production of each of its
generation assets into the MISO day-ahead and real-time markets. MISO operates on a merit order dispatch,
considering transmission constraints and other reliability issues to meet the total demand in the MISO region.
Regulatory Framework - Retail Ratemaking — In addition to the regulations referred to below in Other
Regulatory Matters, IPL is subject to regulation by the IURC with respect to IPL's services and facilities; retail rates
and charges; the issuance of long-term securities; and certain other matters. The regulatory power of the IURC over
IPL's business is both comprehensive and typical of the traditional form of regulation generally imposed by state
public utility commissions. IPL's tariff rates for electric service to retail customers consist of basic rates and charges,
16
which are set and approved by the IURC after public hearings. The IURC gives consideration to all allowable costs
for ratemaking purposes including a fair return on the fair value of the utility property used and useful in providing
service to customers. In addition, IPL's rates include various adjustment mechanisms including, but not limited to: (i)
a rider to reflect changes in fuel and purchased power costs to meet IPL's retail load requirements, referred to as
the FAC, and (ii) a rider for the timely recovery of costs incurred to comply with environmental laws and regulations
referred to as the Environmental Compliance Cost Recovery Adjustment. These components function somewhat
independently of one another, but the overall structure of IPL's rates and charges would be subject to review at the
time of any review of IPL's basic rates and charges.
In March 2016, the IURC issued an order authorizing IPL to increase its basic rates and charges by
approximately $31 million annually. On December 22, 2016, IPL filed a petition with the IURC for authority to
increase its basic rates and charges, primarily to recover the cost of the new Eagle Valley CCGT. The Eagle Valley
CCGT was previously expected to be completed in the first half of 2017, but is now expected to be completed in the
first half of 2018. To address this change, on February 24, 2017, IPL filed a motion to withdraw the case without
prejudice or alternatively amend the petition at a later date. No assurances can be given as to the timing or
outcome of this proceeding.
Environmental Regulation — For information on compliance with environmental regulations see Item 1.—
United States Environmental and Land-Use Legislation and Regulations.
Replacement Generation — IPL has several generating units that have been recently retired or refueled.
These units were primarily coal-fired and represented 472 MW of net capacity in total. To replace this generation,
IPL has approval to build a 644 to 685 MW CCGT at its Eagle Valley Station site in Indiana and refuel its Harding
Street Station Units 5 and 6 from coal to natural gas (approximately 100 MW net capacity each) with a total budget
of $649 million. The current estimated cost of these projects is $632 million. IPL was granted authority to accrue
post in-service allowance for debt and equity funds used during construction, and to defer the recognition of
depreciation expense of the CCGT and refueling project. These costs to build and operate the CCGT and the
refueling project, other than fuel costs, will not be recoverable by IPL through rates until the conclusion of a base
rate case proceeding with the IURC after the assets have been placed in service. The CCGT is expected to be
completed in the first half of 2018, and the refueling project was completed in December 2015.
In July 2015 IPL received approval from the IURC for a CPN to refuel the Harding Street Station Unit 7 from
coal to natural gas (about 410 MW net capacity). The Harding Street Station Unit 7 conversion was completed in
the second quarter of 2016.
Key Financial Drivers — IPL's financial results are driven primarily by retail demand, weather, energy
efficiency and wholesale prices. In addition, IPL's financial results are likely to be driven by many factors including
but not limited to:
•
•
•
rate case outcomes
the timely recovery of capital expenditures through base rate growth
the passage of new legislation or implementation of regulations
Construction and Development — IPL's construction program is composed of capital expenditures necessary
for prudent utility operations and compliance with environmental laws and regulations, along with discretionary
investments designed to replace aging equipment or improve overall performance. Refer to the section above for a
description of our major construction projects.
DPL
Business Description — DPL is an energy holding company whose principal subsidiaries include DP&L and
AES Ohio Generation, LLC.
DP&L generates, transmits, distributes and sells electricity to approximately 519,000 customers in a 6,000
square mile area of West Central Ohio. DP&L, solely or through jointly owned facilities, owns 2,510 MW of
generation capacity and numerous transmission facilities.
AES Ohio Generation, LLC owns peaking generation units representing 556 MW located in Ohio and Indiana.
On January 1, 2016, DPL closed on the sale of DPLER to Interstate Gas Supply, Inc. DPLER, a competitive
retail marketer, sold retail electricity to more than 124,000 retail customers in Ohio and Illinois while owned by DPL.
Approximately 110,000 of those customers were also distribution customers of DP&L in Ohio.
Market Structure — Since January 2001, electric customers within Ohio have been permitted to choose to
purchase power under a contract with a CRES Provider or to continue to purchase power from their local utility
17
under SSO rates established by the tariff. DP&L and other Ohio utilities continue to have the exclusive right to
provide delivery service in their state certified territories, and DP&L has the obligation to provide retail generation
service to customers that did not choose an alternative supplier. Beginning in 2014, a portion of the SSO generation
supply was no longer supplied by DP&L, but was provided by third parties through a competitive bid process. A total
of 10%, 60% and 100% of the SSO load was sourced through competitive bid in 2014, 2015 and 2016, respectively.
The PUCO maintains jurisdiction over DP&L's delivery of electricity, SSO and other retail electric services. The
PUCO has issued extensive rules on how and when a customer can switch generation suppliers, how the local
utility will interact with CRES Providers and customers, including for billing and collection purposes, and which
elements of a utility's rates are "bypassable" (i.e., avoided by a customer that elects a CRES Provider) and which
elements are "non-bypassable" (i.e., charged to all customers receiving a distribution service irrespective of what
entity provides the retail generation service).
DP&L is a member of PJM. The PJM RTO operates the transmission systems owned by utilities operating in
all or parts of Pennsylvania, New Jersey, Maryland, Delaware, D.C., Virginia, Ohio, West Virginia, Kentucky, North
Carolina, Tennessee, Indiana and Illinois. PJM has an integrated planning process to identify potential needs for
additional transmission to be built to avoid future reliability problems. PJM also runs the day-ahead and real-time
energy markets, ancillary services market and forward capacity market for its members.
As a member of PJM, DP&L is also subject to charges and costs associated with PJM operations as approved
by the FERC. Prior to 2015, the RPM was PJM's capacity construct. In 2015, PJM implemented a new CP program,
replacing the RPM model. The CP program offers the potential for higher capacity revenues, combined with
substantially increased penalties for non-performance or under-performance during certain periods identified as
"capacity performance hours." This linkage between non- or under-performance during specific hours means that a
generation unit that is generally performing well on an annual basis, may incur substantial penalties if it happens to
be unavailable for service during some capacity performance hours. Similarly, a generation unit that is generally
performing poorly on an annual basis may avoid such penalties if its outages happen to occur only during hours that
are not capacity performance hours. An annual “stop-loss” provision exists that limits the size of penalties to 150%
of the net cost of new entry, which is a value computed by PJM. This level is likely to be larger than the capacity
price established under the CP program, so that there is potential that participation in the CP program could result
in capacity penalties that exceed capacity revenues. The purpose of the RPM and CP Program is to enable PJM to
obtain sufficient resources to reliably meet the needs of electric customers within the PJM footprint. PJM conducts
an auction to establish the price by zone.
The PJM CP auctions are held three years in advance for a period covering 12 months starting from June 1.
Auctions for the period covering June 1, 2020 through May 30, 2021 are expected to take place in May 2017.
Future auction results are dependent upon various factors including the demand and supply situation, capacity
additions and retirements and any changes in the current auction rules related to bidding for demand response and
energy efficiency resources in the capacity auctions. For DPL-owned generation, applicable capacity prices through
the auction year 2019/20 are as follows:
Auction Year (June 01-May 31)
Capacity Clearing Price ($/MW-Day)
2019/20
$100
2018/19
$165
2017/18
$152
2016/17
$134
2015/16
$136
2014/15
$126
The computed average capacity prices by calendar year are as follows:
Year
Computed Average Capacity Price ($/MW-Day)
2019
$127
2018
$159
2017
$145
2016
$135
2015
$132
The above tables reflect the capacity prices after the transitional auctions discussed earlier. Substantially all of
DP&L's capacity cleared in the CP auction. The results of these auctions could have a significant effect on DP&L's
revenues in the future.
Regulatory Framework - Retail Regulation and Rate Structure — DP&L is subject to regulation by the PUCO,
for its distribution services and facilities, retail rates and charges, reliability of service, compliance with renewable
energy portfolio, energy efficiency program requirements and certain other matters. DP&L's rates for electric service
to retail customers consist of basic rates and charges that are set and approved by the PUCO after public hearings.
In addition, DP&L's rates include various adjustment mechanisms including, but not limited to, the timely recovery of
costs incurred to comply with alternative energy, renewables, energy efficiency, and economic development costs.
These components function independently of one another, but the overall structure of DP&L's retail rates and
charges are subject to the rules and regulations established by the PUCO.
Since Ohio is deregulated, and allows customers to choose retail generation providers, DP&L is required to
provide retail generation service at SSO rates to any customer that has not signed a contract with a CRES provider.
18
SSO rates are subject to rules and regulations of the PUCO and are established based on DP&L's most recently
approved ESP. DP&L's distribution rates are regulated by the PUCO and are established through a traditional cost-
based rate-setting process. DP&L is permitted to recover its costs of providing distribution service as well as earn a
regulated rate of return on assets, determined by the regulator, based on the utility's allowed regulated asset base,
capital structure and cost of capital. DP&L's wholesale transmission rates are regulated by the FERC.
Although it had been in effect since January 2014, on June 20, 2016, the Supreme Court of Ohio ("Court")
issued an opinion in the appeal of DP&L’s ESP (ESP 2) that had been approved by the PUCO for the years
2014-2016 and which, among other matters, permitted DP&L to collect a non-bypassable Service Stability Rider
equal to $110 million per year from 2014-2016 and required DP&L to conduct competitive bid auctions to procure
generation supply for SSO service. DP&L's own generation was phased-out of supplying SSO service over the
three year period and beginning January 1, 2016 DP&L's SSO was 100% sourced through the competitive bid. In
the opinion, the Court stated that the PUCO’s approval of ESP 2 was reversed. In view of that reversal, DP&L filed
a motion to withdraw ESP 2 and implement rates consistent with those in effect prior to 2014 (ESP 1). Those rates
will be in effect until rates consistent with DP&L’s pending February 22, 2016 ESP (ESP 3) filing are approved and
effective.
DP&L originally filed its ESP 3 seeking an effective date of January 1, 2017. On October 11, 2016, DP&L
amended the application requesting to recover $145 million per year for seven years supporting the alternative
described in the original filing, named the Distribution Modernization Rider. This plan establishes the terms and
conditions for DP&L's SSO beginning June 1, 2017 to customers that do not choose a competitive retail electric
supplier. In its plan, DP&L recommends including renewable energy attributes as part of the product that is
competitively bid, and seeks recovery of approximately $11 million of regulatory assets. The plan also proposes a
new Distribution Investment Rider to allow DP&L to recover costs associated with future distribution equipment and
infrastructure needs. Additionally, the plan establishes new riders set initially at zero, related to energy reductions
from DP&L's energy efficiency programs, and certain environmental liabilities the Company may incur.
On January 30, 2017 DP&L, in conjunction with nine intervening parties, filed a settlement in the ESP 3 case,
which is subject to PUCO approval. DP&L and the intervening parties agreed to a six-year settlement that provides
a framework for energy rates and defines components which include, but are not limited to, the following:
• The establishment of a five-year Distribution Modernization Rider designed to collect $90 million in revenue per
year to pay debt obligations at DPL and DP&L and position DP&L to modernize and/or maintain its transmission
and distribution infrastructure;
• The establishment of a Distribution Investment Rider for distribution investments, with one component designed
to collect $35 million in revenue per year to enable the implementation of smart grid and advanced metering,
ending after the fifth year of the term of the ESP,
• A commitment by the Company to separate DP&L’s generation assets from its transmission and distribution
assets (if approved by FERC);
• A commitments to commence the sale process of our ownership interests in the Zimmer, Miami Fort and
Conesville coal-fired generation plants and;
• A commitment to develop or procure wind and/or solar energy projects in Ohio,
• Restrictions on DPL making dividend or tax sharing payments, various other riders, and competitive retail market
enhancements.
A hearing on the stipulation has been scheduled for March 2017. A final decision by the PUCO is expected at
the end of Q2 or early Q3 2017. If the PUCO agrees to the proposed settlement, the average residential customer
in the DP&L service territory, using 1,000 kWh on DP&L's Standard Service Offer, can expect a monthly bill
increase of $2.39. There can be no assurance that the ESP 3 stipulation will be approved as filed or on a timely
basis, and if the final ESP provides for terms that are more adverse than those submitted in DP&L's stipulation, our
results of operations, financial condition and cash flows could be materially impacted.
On November 30, 2015 DP&L filed an application to increase its distribution rate case using a 12-month test
year of June 1, 2015 to May 31, 2016 to measure revenue and expenses and a date certain of September 30, 2015
to measure its asset base. The Company is seeking an increase to distribution revenues of $66 million per year.
The Company has asked for recovery of certain regulatory assets as well as two new riders that would allow the
Company to recover certain costs on an ongoing basis. It has proposed a modified straight-fixed variable rate
design in an effort to decouple distribution revenues from electric sales. If approved as filed the rates are expected
to have a total bill impact of approximately 4% on a typical residential customer.
Environmental Regulation — In relation to MATS, DPL does not expect to incur material capital expenditures
to ensure compliance. For more information see Item 1.—United States Environmental and Land-Use Legislation
19
and Regulations.
Key Financial Drivers — DPL financial results are driven by retail demand, weather, energy efficiency and
wholesale prices on financial results. In addition, DPL financial results are likely to be driven by many factors
including, but not limited to:
• PJM capacity prices
• Outcome of DP&L's pending ESP 3 case, including the amount of non-bypassable revenue
• Outcome of DP&L's pending distribution rate case
• Operational performance of generation facilities
• Recovery in the power market, particularly as it relates to an expansion in dark spreads
• Sale or transfer to a DPL affiliate of DP&L generation assets
• DPL's ability to reduce its cost structure
Construction and Development — Planned construction additions primarily relate to new investments in and
upgrades to DP&L's power plant equipment and transmission and distribution system. Capital projects are subject
to continuing review and are revised in light of changes in financial and economic conditions, load forecasts,
legislative and regulatory developments and changing environmental standards, among other factors.
DPL is projecting to spend an estimated $414 million in capital projects for the period 2017 through 2019 with
65% attributable to Transmission and Distribution. DPL's ability to complete capital projects and the reliability of
future service will be affected by its financial condition, the availability of internal funds and the reasonable cost of
external funds. We expect to finance these construction additions with a combination of cash on hand, short-term
financing, long-term debt and cash flows from operations.
U.S. Generation
Business Description — In the U.S., we own a diversified generation portfolio in terms of geography,
technology and fuel source. The principal markets and locations where we are engaged in the generation and
supply of electricity (energy and capacity) are the Western Electric Coordinating Council, PJM, Southwest Power
Pool Electric Energy Network and Hawaii. AES Southland, in the Western Electric Coordinating Council, is our most
significant generating business.
Many of our U.S. generation plants provide baseload operations and are required to maintain a guaranteed
level of availability. Any change in availability has a direct impact on financial performance. The plants are generally
eligible for availability bonuses on an annual basis if they meet certain requirements. In addition to plant availability,
fuel cost is a key business driver for some of our facilities.
AES Southland
Business Description — In terms of aggregate installed capacity, AES Southland is one of the largest
generation operators in California, with an installed gross capacity of 3,941 MW, accounting for approximately 5% of
the state's installed capacity and 17% of the peak demand of Southern California Edison. The three coastal power
plants comprising AES Southland are in areas that are critical for local reliability and play an important role in
integrating the increasing amounts of renewable generation resources in California.
Market Structure — All of AES Southland's capacity is contracted through a long-term agreement (the “Tolling
Agreement”), which expires in May 31, 2018. A Resource Adequacy agreement has been executed that covers the
period from June 1, 2018 through 2020, but it is still subject to approval from the California Public Utilities
Commission. Under the current Tolling Agreement, AES Southland's largest revenue driver is unit availability, as
approximately 98% of its revenue comes from availability-related payments. Historically, AES Southland has
generally met or exceeded its contractual availability requirements under the Tolling Agreement and may capture
bonuses for exceeding availability requirements in peak periods.
Under the Tolling Agreement, the offtaker provides gas to the three facilities thus AES Southland is not
exposed to significant fuel price risk. If the units operate better than the guaranteed efficiency, AES Southland gets
credit for the gas that is not consumed. Conversely, AES Southland is responsible for the cost of fuel in excess of
what would have been consumed had the guaranteed efficiency been achieved. The business is also exposed to
replacement power costs for a limited period if dispatched by the offtaker and not able to meet the required
generation.
AES Southland delivers electricity into the California ISO's market through its Tolling Agreement counterparty.
20
Environmental Regulation — For a discussion of environmental regulatory matters affecting U.S. Generation,
see Item 1.—United States Environmental and Land-Use Legislation and Regulations.
Re-powering — In October 2014, AES Southland was awarded 20-year contracts by SCE to provide 1,284
MW of combined cycle gas-fired generation and 100 MW of interconnected battery-based energy storage. In
addition to replacing older gas-fired plants with more efficient gas-fired capacity, SCE chose advanced energy
storage as a cost effective way to ensure critical power system reliability. This new storage resource will provide
operational flexibility, enabling the efficient dispatch of other generating plants, lowering cost and emissions and
supporting the on-going addition of renewable power sources.
This new capacity will be built at the Company's existing power plant sites in Huntington Beach and Alamitos
Beach. For the gas-fired capacity, financing agreements are expected to be completed in mid-2017 with
construction expected to begin shortly thereafter, and commercial operation scheduled for 2020. For the energy
storage capacity, commercial operation is scheduled for 2021.
AES is pursuing permits to build both the gas-fired and energy storage capacity and will complete the
licensing process before financial close. The total cost for these projects is expected to be approximately $1.9
billion, which will be funded with a combination of non-recourse debt and AES equity.
Key Financial Drivers — AES Southland's contractual availability is the single most important driver of
operations. Its units are generally required to achieve at least 86% availability in each contract year. AES Southland
has historically met or exceeded its contractual availability.
Additional U.S. Generation Businesses
Business Description — Additional businesses include thermal, wind, and solar generating facilities, of which
AES Hawaii, our U.S. wind generation businesses and distributed solar are the most significant.
• AES Hawaii — AES Hawaii receives a fuel payment from its offtaker under a PPA expiring in 2022, which is
based on a fixed rate indexed to the Gross National Product - Implicit Price Deflator. Since the fuel payment is
not directly linked to market prices for fuel, the risk arising from fluctuations in market prices for coal is borne by
AES Hawaii.
To mitigate the risk from such fluctuations, AES Hawaii has entered into fixed-price coal purchase commitments
that end in December 2018; the business could be subject to variability in coal pricing beginning in January
2019. To mitigate fuel risk beyond December 2018, AES Hawaii plans to seek additional fuel purchase
commitments on favorable terms. However, if market prices rise and AES Hawaii is unable to procure coal
supply on favorable terms, the financial performance of AES Hawaii could be materially and adversely affected.
• U.S. Wind — AES has 736 MW of wind capacity in the U.S., located in California, Texas and West Virginia.
Typically, these facilities sell under long-term PPAs. AES financed most of these projects with tax equity
structures. The tax equity investors receive a portion of the economic attributes of the facilities, including tax
attributes that vary over the life of the projects. Based on certain liquidation provisions of the tax equity
structures, this could result in a net loss to AES consolidated results in periods in which the facilities report net
income. These non cash net losses will be expected to reverse during the life of the facilities. Some of the wind
projects are exposed to the volatility of energy prices and their revenue may change materially as energy prices
fluctuate in their respective markets of operations.
Buffalo Gap is located in Texas and is comprised of three wind projects with an aggregate generation capacity of
522 MW. Each wind project operates its own PPA with the exception of Buffalo Gap III. The energy price of the
entire production of Buffalo Gap I is guaranteed by a PPA expiring in 2021. The PPA of Buffalo Gap II guarantees
the energy price of 80% of the installed capacity while the energy price for the remaining 20% is dictated by the
prices in the ERCOT market. The PPA of Buffalo Gap II expires in December 2017. Once the PPAs expire, the
entire installed capacity of Buffalo Gap will be exposed to the volatility of energy prices in the ERCOT market
which could adversely affect revenues.
Laurel Mountain is a wind project located in West Virginia with an installed capacity of 98 MW. Laurel Mountain
does not operate under a long-term contract and sells its entire capacity and power generated into the PJM
market. The volatility and fluctuations of energy prices in PJM have a direct impact in the results of Laurel
Mountain.
AES manages the wind portfolio as part of its broader investments in the U.S., leveraging operational and
commercial resources to supplement the experienced subject matter experts in the wind industry to achieve
optimal results.
21
• AES Distributed Energy — AES has 103 MW of solar capacity in the U.S., located across multiple states.
Distributed Energy's Commercial and Utility division, which comprised 89 MW of solar capacity as of December
31, 2016, sells electricity generated by photovoltaic solar energy systems to public sector, utility, and non-profit
entities through power purchase agreements. AES has added 33 MW of commercial and utility capacity in 2016.
A majority of this new capacity has been financed with tax equity structures. Under these tax equity structures,
the tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes that
vary over the life of the projects. Based on certain liquidation provisions of the tax equity structures, this could
result in a net loss to AES consolidated results in periods in which the facilities report net income. These non
cash net losses will be expected to reverse during the life of the facilities.
AES manages the Distributed Energy portfolio as part of its broader investments in the U.S., leveraging
operational and commercial resources to supplement the experienced subject matter experts in the solar
industry to achieve optimal results.
Market Structure — For the non-renewable businesses included in our additional U.S. generation facilities,
coal and natural gas are used as the primary fuels. Coal has prices that are set by market factors internationally
while natural gas is generally set domestically. Price variations for these fuels can change the composition of
generation costs and energy prices in our generation businesses, and the prices of these fuels have been subject to
volatility in recent years.
Many of these generation businesses have entered into long-term PPAs with utilities or other offtakers. Some
coal-fired power plant businesses in the U.S. with PPAs have mechanisms to recover fuel costs from the offtaker,
including an energy payment that is partially based on the market price of coal. In addition, these businesses often
have an opportunity to increase or decrease profitability from payments under their PPAs depending on such items
as plant efficiency and availability, heat rate, ability to buy coal at lower costs through AES' global sourcing program
and fuel flexibility. Revenue may change materially as prices in fuel markets fluctuate, but the variable margin or
profitability should not be materially changed when market price fluctuations in fuel are borne by the offtaker.
Regulatory Framework — Several of our generation businesses in the U.S. currently operate as QFs as
defined under the PURPA. These businesses entered into long-term contracts with electric utilities that had a
mandatory obligation under PURPA requirements to purchase power from QFs at the utility's avoided cost (i.e., the
likely costs for both energy and capital investment that would have been incurred by the purchasing utility if that
utility had to provide its own generating capacity or purchase it from another source). To be a QF, a cogeneration
facility must produce electricity and useful thermal energy for an industrial or commercial process or heating or
cooling applications in certain proportions to the facility's total energy output and meet certain efficiency standards.
To be a QF, a small power production facility must generally use a renewable resource as its energy input and meet
certain size criteria.
Our non-QF generation businesses in the U.S. currently operate as Exempt Wholesale Generators as defined
under EPAct 1992. These businesses, subject to approval of FERC, have the right to sell power at market-based
rates, either directly to the wholesale market or to a third-party offtaker such as a power marketer or utility/industrial
customer. Under the FPA and FERC's regulations, approval from FERC to sell wholesale power at market-based
rates is generally dependent upon a showing to FERC that the seller lacks market power in generation and
transmission, that the seller and its affiliates cannot erect other barriers to market entry and that there is no
opportunity for abusive transactions involving regulated affiliates of the seller. To prevent market manipulation,
FERC requires sellers with market-based rate authority to file certain reports, including a triennial updated market
power analysis for markets in which they control certain threshold amounts of generation.
Other Regulatory Matters — The U.S. wholesale electricity market consists of multiple distinct regional
markets that are subject to both federal regulation, as implemented by the U.S. FERC, and regional regulation as
defined by rules designed and implemented by the RTOs, non-profit corporations that operate the regional
transmission grid and maintain organized markets for electricity. These rules for the most part govern such items as
the determination of the market mechanism for setting the system marginal price for energy and the establishment
of guidelines and incentives for the addition of new capacity. See Item 1A.—Risk Factors for additional discussion
on U.S. regulatory matters.
Environmental Regulation — For a discussion of environmental laws and regulations affecting the U.S.
business, see Item 1.—United States Environmental and Land-Use Legislation and Regulations.
Key Financial Drivers — U.S. Generation's financial results are driven by fuel costs and outages. The
Company has entered into long-term fuel contracts to mitigate the risks associated with fluctuating prices. In
addition, major maintenance requiring units to be off-line is performed during periods when power demand is
typically lower. The financial results of U.S. Wind are primarily driven by increased production due to faster and less
22
turbulent wind, and reduced turbine outages. In addition, PJM and ERCOT power prices impact financial results for
the wind projects that are operating without long-term contracts for all or some of their capacity.
Construction and Development — Planned capital projects include the AES Southland re-powering described
above. In addition to the new construction projects, U.S. Generation performs capital projects related to major plant
maintenance, repairs, and upgrades to be compliant with new environmental laws and regulations.
Andes SBU
Generation — Our Andes SBU has generation facilities in three countries — Chile, Colombia and Argentina.
AES Gener, which owns all of our assets in Chile, Chivor in Colombia and TermoAndes in Argentina, as detailed
below, is a publicly listed company in Chile. AES has a 66.7% ownership interest in AES Gener and this business is
consolidated in our financial statements.
Operating installed capacity of our Andes SBU totals 9,308 MW, of which 44%, 45% and 11% is located in
Argentina, Chile and Colombia, respectively. The following table lists our Andes SBU generation facilities:
AES
Equity
Interest
67%
67%
Year Acquired
or Began
Operation
Contract
Expiration
Date
2000 Short-term
2016
Business
Location
Fuel
Chivor
Tunjita
Colombia Subtotal
Guacolda (1)
Electrica Santiago (2)
Gener - SIC (3)
Electrica Angamos
Cochrane
Gener - SING (4)
Electrica Ventanas (5)
Electrica Campiche (6)
Andes Solar
Cochrane ES
Electrica Angamos ES
Gener - Norgener ES (Los
Andes)
Chile Subtotal
TermoAndes (7)
AES Gener Subtotal
Alicura
Paraná-GT
San Nicolás
Guillermo Brown (8)
Los Caracoles (8)
Cabra Corral
Ullum
Sarmiento
El Tunal
Argentina Subtotal
Colombia Hydro
Colombia Hydro
Chile
Chile
Chile
Chile
Chile
Chile
Chile
Chile
Chile
Chile
Chile
Chile
Coal/Pet Coke
Gas/Diesel
Hydro/Coal/
Diesel/Biomass
Coal
Coal
Coal/Pet Coke
Coal
Coal
Solar
Energy Storage
Energy Storage
Energy Storage
Argentina Gas/Diesel
Argentina Hydro
Argentina Gas/Diesel
Argentina Coal/Gas/Oil
Argentina Gas/Diesel
Argentina Hydro
Argentina Hydro
Argentina Hydro
Argentina Gas/Diesel
Argentina Hydro
Gross
MW
1,000
20
1,020
760
750
689
558
532
277
272
272
21
20
20
12
4,183
643
5,846
1,050
845
675
576
125
102
45
33
11
3,462
9,308
33%
67%
67%
67%
40%
67%
67%
67%
67%
40%
67%
67%
67%
100%
100%
100%
—%
—%
100%
100%
100%
100%
Customer(s)
Various
Various
Various
Minera Escondida, Minera
Spence, Quebrada Blanca
SQM, Sierra Gorda,
Quebrada Blanca
2000
2000
2000
2017-2032
2020-2037
2011
2026-2037
2016
2030-2034
2000
2017-2037 Minera Escondida, Codelco,
2025
2020
2037
SQM, Quebrada Blanca
Gener
Gener
Quebrada Blanca
2010
2013
2016
2016
2011
2009
2000 Short-term
2017
2019
2000
2001
1993
2016
2009
1995
1996
1996
1995
Various
Various
Energia Provincial Sociedad
del Estado (EPSE)
Various
Various
Various
_____________________________
(1) Guacolda plants: Guacolda 1, 2, 3, 4, and 5. Unconsolidated entities for which the results of operations are reflected in Equity in Earnings of Affiliates. The
Company's ownership in Guacolda is held through AES Gener, a 67%-owned consolidated subsidiary. AES Gener owns 50% of Guacolda, resulting in an AES
effective ownership in Guacolda of 33%.
(2) Electrica Santiago plants: Nueva Renca, Renca, Los Vientos and Santa Lidia.
(3) Gener — SIC plants: Alfalfal, Laguna Verde, Laguna Verde Turbogas, Laja, Maitenes, Queltehues, Ventanas 1, Ventanas 2 and Volcán.
(4) Gener — SING plants: Norgener 1 and Norgener 2.
(5) Electrica Ventanas plant: Ventanas 3.
(6) Electrica Campiche plant: Ventanas 4.
(7) TermoAndes is located in Argentina, but is connected to both the SING in Chile and the SADI in Argentina.
(8) AES operates these facilities through management or O&M agreements and owns no equity interest in these businesses.
23
Under construction — The following table lists our plants under construction in the Andes SBU:
Business
Alto Maipo
Chile Subtotal
Location
Chile
Fuel
Hydro
Gross MW AES Equity Interest
40%
531
531
531
Expected Date of Commercial Operations
1H 2019
The following map illustrates the location of our Andes facilities:
Andes Businesses
Chile
Business Description — In Chile, through AES Gener, we are engaged in the generation and supply of
electricity (energy and capacity) in the two principal markets: the SIC and SING. In terms of aggregate installed
capacity, AES Gener is the second largest generation operator in Chile with a calculated installed capacity of 4,131
MW, excluding energy storage and TermoAndes, and a market share of approximately 18% as of December 31,
2016.
AES Gener owns a diversified generation portfolio in Chile in terms of geography, technology, customers and
fuel source. AES Gener's installed capacity is located near the principal electricity consumption centers, including
Santiago, Valparaiso and Antofagasta. AES Gener's portfolio is composed of hydroelectric, coal, gas, diesel, solar
photovoltaic and biomass facilities, that allows the businesses to operate under a variety of market and hydrological
conditions, manage AES Gener's contractual obligations with regulated and unregulated customers and, as
required, provide backup energy to the spot market.
AES Gener has experienced significant growth in recent years by responding to market opportunities. The
company successfully completed a first expansion phase between 2007 and 2014 that added 6 new power plants
totaling 1,677 MW. It continued to grow in Chile through its second expansion phase that will add 1,236 MW. As of
the end of 2016, AES Gener has completed the construction of Guacolda Unit 5 (152 MW), Cochrane (532 MW)
and Andes Solar (21 MW). Additionally, we continue to advance in the construction of the 531 MW Alto Maipo run-
of-the-river hydroelectric plant in the SIC.
Our commercial policy in Chile aims to maximize margin while reducing cash flow volatility. In order to achieve
this, we contract a significant portion of our baseload capacity, currently coal and hydroelectric, under long-term
agreements with a diversified customer base, that includes both regulated and unregulated customers. Power
plants that are not considered within our baseload capacity (higher variable cost units, mainly diesel and gas fired
24
units) operate during scarce system supply conditions, such as dry hydrological conditions and plant outages,
selling their energy in the spot market. In Chile, sales on the spot market are made only to other generation
companies (entities that are members of the Economic Load Dispatch Center - "CISEN") at the system marginal
cost. In anticipation of the SIC and SING interconnection, the new Transmission Law created the CISEN, an entity
that will merge both system operators into one.
AES Gener currently has long-term contracts, with an average remaining term of approximately 11 years, with
regulated distribution companies and unregulated customers, such as mining and industrial companies. In general,
these long-term contracts include both fixed and variable payments along with indexation mechanisms that
periodically adjust prices based on the generation cost structure related to the United States Consumer Price Index,
the international price of coal, and in some cases, with pass-through of fuel and regulatory costs, including changes
in law.
In addition to energy payments, AES Gener also receives firm capacity payments for contributing to the
system's ability to meet peak demand. These payments are added to the final electricity price paid by both
unregulated and regulated customers. In each system, the CISEN annually determines the firm capacity amount
allocated to each power plant. A plant's firm capacity is defined as the capacity that it can guarantee at peak hours
during critical conditions, such as droughts, taking into account statistical information regarding maintenance
periods and water inflows in the case of hydroelectric plants. The capacity price is fixed by the National Energy
Commission in the semiannual node price report and indexed to the United States Consumer Price Index and other
relevant indices.
Market Structure — Chile has two main power systems, largely as a result of its geographic shape and size.
The SIC is the largest of these systems, with an installed capacity of 17,543 MW as of December 31, 2016. The
SIC serves approximately 92% of the Chilean population, including the densely populated Santiago Metropolitan
Region, and represents 75% of the country's electricity demand. The SING serves about 6% of the Chilean
population, representing 25% of Chile's electricity consumption, and mainly supplies mining companies.
In 2016, thermoelectric generation represented 67% of the total generation in Chile. In the SIC, thermoelectric
generation represents 48% of installed capacity, required to fulfill demand not satisfied by hydroelectric output and
is critical to guaranteeing reliable and dependable electricity supply under dry hydrological conditions. In the SING,
which includes the Atacama Desert, the driest desert in the world, thermoelectric capacity represents 92% of
installed capacity. The fuels used for generation, mainly coal, diesel and LNG, are indexed to international prices.
In the SIC, where hydroelectric plants represent a large part of the system's installed capacity, hydrological
conditions largely influence plant dispatch and, therefore, spot market prices, given that river inflows, snow melting
and initial water levels in reservoirs largely determine the dispatch of the system's hydroelectric and thermoelectric
generation plants. Rainfall and snowfall occur in Chile principally in the southern cone winter season (June to
August) and during the remainder of the year precipitation is scarce. When rain is abundant, energy produced by
hydroelectric plants can amount to more than 70% of total generation. In 2016 hydroelectric generation represented
36% of total energy production within the SIC, and 27% of the country’s total energy production.
Solar and wind installed capacity represents a small but growing part of the total capacity installed. In the SIC,
solar accounts for 3% of the power generation and 7% of the system’s installed capacity while in the SING solar
accounts for 4% of the power generation and 6% of the system’s capacity. As for wind, in the SIC, wind contributes
with 4% of the power generation and 7% of the system’s capacity, while in the SING wind generation represents 1%
of the power generation and with 2% of the system’s capacity.
Regulatory Framework — The government entity that has primary responsibility for the Chilean electricity
system is the Ministry of Energy, acting directly or through the National Energy Commission and the
Superintendency of Electricity and Fuels. The electricity sector is divided into three segments: generation,
transmission and distribution. In general terms, generation and transmission expansion are subject to market
competition, while transmission operation and distribution, are subject to price regulation. The transmission
segment consists of companies that transmit the electricity produced by generation companies at high voltage. The
individual and joint participation of companies operating in any other segment of the electricity sector cannot exceed
8% and 40%, respectively, of the total investment value of the national transmission system.
Companies in the SIC and the SING that own generation, transmission, sub-transmission or additional
transmission facilities, as well as unregulated customers directly connected to transmission facilities, are
coordinated through the CISEN, which minimizes the operating costs of the electricity system, while meeting all
service quality and reliability requirements. The principal purpose of the CISEN is to ensure that the most efficient
electricity generation available to meet demand is dispatched to customers. The CISEN dispatches plants in merit
order based on their variable cost of production, allowing for electricity to be supplied at the lowest available cost.
25
All generators can commercialize energy through contracts with distribution companies for their regulated and
unregulated customers or directly with unregulated customers. Unregulated customers are customers whose
connected capacity is higher than 2MW. Customers with connected capacity between 0.5 MW and 2.0 MW can opt
for a Regulated or Unregulated regime for a minimum period of four years. By law, both regulated and unregulated
customers are required to purchase all of their electricity requirements under contract. Generators may also sell
energy to other power generation companies on a short-term basis. Power generation companies may engage in
contracted sales among themselves at negotiated prices outside the spot market. Electricity prices in Chile, under
contract and on the spot market, are denominated in U.S. Dollars, although payments are made in Chilean Pesos.
In July 2016, modifications to the Transmission Law were enacted. This Law establishes that the transmission
system will be completely paid for by the end-users, gradually allocating the costs on the demand side from year
2019 through 2034.
Environmental Regulation — In 2011, a regulation on air emission standards for thermoelectric power plants
became effective. This regulation provides for stringent limits on emission of PM and gases produced by the
combustion of solid and liquid fuels, particularly coal. For existing plants, including those currently under
construction, the new limits for PM emissions went into effect at the end of 2013, and the new limits for SO2, NOx
and mercury emission were in effect since mid-2016, except for those plants operating in zones declared saturated
or latent zones (areas at risk of or affected by excessive air pollution), where these emission limits became effective
in June 2015. In order to comply with the new emission standards, AES Gener initiated investments in Chile at its
older coal facilities (Ventanas I and II and Norgener I and II, constructed between 1964 and 1997) in 2012. As of
December 31, 2016, AES Gener has concluded investments of approximately $229 million in order to comply within
the required time frame. Additionally, its equity method investee Guacolda started the installation of new emission
control equipment during 2013, and concluded investments of approximately $209 million in order to comply within
the required time frame.
On March 29, 2016, the Health Ministry enacted Supreme Decree N°43 (“DS 43”) ruling “Storage of
Hazardous Materials”, modifying the current applicable rules. This regulation will become fully effective in March
2018 for structural improvements of currently authorized storage facilities. The estimated investment required to
comply with DS 43 would be approximately $15 million.
During 2016, the Environmental Ministry worked on upgrading the Atmospheric Decontamination Plans for
Santiago, Ventanas and Huasco areas, each of which, as of December 31, 2016, are currently under different
stages of progress. Nueva Renca, Ventanas and Guacolda power plants may require an improvement of their
operational practices and additional investments to meet the expected new requirements during the year following
the enactment of the Decontamination Plan, which is expected for mid 2017.
Chilean law requires every electricity generator to supply a certain portion of its total contractual obligations
with Non-conventional Renewable Energy ("NCREs"). In October 2013, the NCRE law was amended, increasing
the NCRE requirements. The law distinguishes between energy contracts executed before and after July 1, 2013.
For contracts executed between August 31, 2007 and July 1, 2013, the NCRE requirement is equal to 5% in 2014
with annual contract increases of 0.5% until reaching 10% in 2024. The NCRE requirement for contracts executed
after July 1, 2013 is equal to 5% in 2013, with annual increases of 1% thereafter until reaching 12% in 2020, and
subsequently annual increases of 1.5% until it is equal to 20% in 2025. Generation companies are able to meet this
requirement by developing their own NCRE generation capacity (wind, solar, biomass, geothermal and small
hydroelectric technology), purchasing NCREs from qualified generators or by paying the applicable fines for non-
compliance. AES Gener currently fulfills the NCRE requirements by utilizing AES Gener's own solar and biomass
power plants and by purchasing NCREs from other generation companies. It has sold certain water rights to
companies that are developing small hydro projects, entering into power purchase agreements with these
companies in order to promote development of these projects, while at the same time meeting the NCRE
requirements. At present, AES Gener is in the process of negotiating additional NCRE supply contracts to meet the
future requirements.
In September 2014 a new tax law was enacted. The new law introduces an emission tax, or "green tax", that
assesses the emissions of PM, SO2, NOx and CO2 produced for installations with an installed capacity over 50 MW.
The first annual payment shall be made in April 2018 for emissions produced in 2017. In the case of CO2, the tax
will be equivalent to $5 per ton emitted. In the SING, all PPAs have "change of law" clauses, which would allow the
company to transfer this cost to customers. In the SIC, costs can only be passed through to unregulated customers,
as existing PPAs with distribution companies do not have change of law clauses. According to its PPAs, the
company is currently discussing the pass-through mechanism with each client. Additionally, the new tax systems
introduced by the new tax laws enacted in February 2016 will be effective from January 1, 2017 onwards. The
statutory income tax rate for most of our Chilean businesses will increase from 25% to 25.5% in 2017 and to 27%
26
for 2018 and future years. See Item 7.—Management's Discussion and Analysis of Financial Condition and Results
of Operations—Critical Accounting Policies and Estimates—Income Taxes for further details of the impacts of these
new laws.
In June 2015, the Chilean government published Decree N°7/2015, which allows the export of energy
generated by plants not dispatched in the SING to Argentina using the transmission line connecting the SING with
the SADI. This transmission line is owned by AES Gener and has a capacity of approximately 600 MW, but will be
operated at 200 MW according to the government permit and related technical studies. AES Gener signed an
agreement with CAMMESA and Chilean generators to export electricity to Argentina. In December 2016, Decree N°
7/2015 was amended to allow the export of energy generated by plants dispatched into the SING to Argentina.
During 2016, energy exported to Argentina reached 102 GWh.
Key Financial Drivers — Hedge levels at Gener provide some certainty and clarity on the underlying financial
drivers. In addition, financial results are likely to be driven by many factors including, but not limited to:
• Dry hydrology scenarios reduce hydro generation
• Forced outages may impact earnings
• Changes in current regulatory rulings could alter the ability to pass through or recover certain costs
• AES is exposed to the fluctuation of the Chilean peso, which may pose a risk to earnings; our hedging
strategy reduces this risk, but some residual risk to earnings remains
• Tax policy changes
• Current legislation is trending towards promoting renewable energy and strengthening regulations on thermal
generation assets, posing a risk to future coal margins
• Market price risk when re-contracting
Construction and Development — Since 2007, AES Gener has constructed and commissioned approximately
2,400 MW of new capacity, representing a significant portion of the capacity increase in the SIC and SING during
the period. During 2016, AES Gener achieved important milestones related to the construction of their projects:
• Cochrane project began operations (Unit 2 on October 12 and Unit 1 on July 9) adding 532 MW to the SING.
• Cochrane Energy Storage began operations in October 2016 adding 20 MW of batteries contributing to system
stability in the SING.
• Andes Solar with 21 MW began operations in May 2016
Additionally, in the SIC, we continue advancing in the construction of our Alto Maipo project, a 531 MW two
unit run-of-river hydroelectric power plant, adjacent to our existing Alfalfal plant, located 50 km from Santiago. Alto
Maipo is the largest project in construction in the SIC market and it includes 67 km of tunnel works, two caverns, 17
km of transmission lines as part of the construction, and is 90% underground. Alto Maipo has three main
contractors and covers three adjacent valleys in the Chilean Andes. As of today, the project employs approximately
4,300 people and expects to reach a peak close to 4,500. The project units are scheduled to reach commercial
operation in the first half of 2019.
We are expanding our business by evaluating opportunities in the desalination business line through two
initiatives: i) brownfield projects, which take advantage of existing infrastructure in thermoelectric power plants
(marine works, easy access to power, strategic location, permits, etc.), providing shorter development time lines
and more competitive water tariffs to offtakers; and ii) greenfield projects, mainly for mining companies which either
purchase industrial water through water purchase agreements, or either invite external companies to compete in a
bidding process to develop a project under a build-own-operate-and-transfer scheme where the water facility along
its pipeline is transferred to the mining operation at the end of a defined period. In Chile, most of the water demand
comes from mining operations, either directly or indirectly (their service providers), hence negative outlooks in the
mineral markets have translated in the postponement of most of the mining projects and their corresponding water
demands.
Colombia
Business Description — We operate in Colombia through AES Chivor, a subsidiary of AES Gener, who owns a
hydroelectric plant with an installed capacity of 1,000 MW, and Tunjita, a 20 MW run-of-river hydroelectric, both
located approximately 160 km east of Bogota. As of December 31, 2016, AES Chivor's net power production in
reached 4,373 GWh. AES Chivor’s installed capacity accounted for approximately 6.1% of system capacity by the
end of the year. Chivor remains dependent on prevailing hydrological conditions in the region in which it operates.
Hydrological conditions largely influence generation and the spot prices at which AES Chivor sells its non-
27
contracted generation in Colombia.
AES Chivor's commercial strategy aims to reduce margin volatility by selling a significant portion of the
expected generation under short term contracts, mainly with distribution companies. These contracts are awarded
in public auctions and normally last from one to three years. The remaining generation is sold on the spot market to
other generation and trading companies at the system marginal cost, allowing us to maximize the operating margin.
Additionally, AES Chivor receives reliability payments to compensate for the plant availability during periods of
power scarcity, such as adverse hydrological conditions, in order to prevent power shortages.
Market Structure — Electricity supply in Colombia is concentrated in one main system, the SIN which
encompasses one-third of Colombia's territory, providing coverage to 97% of the country's population. The SIN's
installed capacity totaled 16,690 MW as of December 31, 2016, comprised of 70% hydroelectric generation, 29%
thermoelectric generation and 1% other. The dominance of hydroelectric generation and the marked seasonal
variations in Colombia's hydrology result in price volatility in the short-term market. In 2016, 72% of total energy
demand was supplied by hydroelectric plants with the remaining supply from thermoelectric generation of 27% and
cogeneration and self-generation power of 1%. From 2003 to 2016, electricity demand in the SIN has grown at a
compound annual growth rate of 2.9% and the Mining and Energetic Planning Unit projects an average compound
annual growth rate in electricity demand of 3.0% per year for the next 10 years.
Regulatory Framework — Since 1994, the electricity sector in Colombia has operated under a competitive
market framework for the generation and sale of electricity and a regulated framework for transmission and
distribution. The distinct activities of the electricity sector are governed by various laws as well as the regulations
and technical standards issued by the CREG. Other government entities that play an important role in the electricity
industry include the Ministry of Mines and Energy, which defines the government's policy for the energy sector; the
Public Utility Superintendency of Colombia, which is in charge of overseeing and inspecting the utility companies;
and the Mining and Energetic Planning Unit, which is in charge of planning the expansion of the generation and
transmission network.
The generation sector is organized on a competitive basis with companies selling their generation in the
wholesale market at the short-term price or under bilateral contracts with other participants, including distribution
companies, generators and traders, and unregulated customers at freely negotiated prices. Generation companies
must submit price bids and report the quantity of energy available on a daily basis. The National Dispatch Center
dispatches generators in merit order based on bid offers in order to ensure that demand will be satisfied by the
lowest cost combination of available generating units.
Regulatory Framework - Tax Regulation — On December 29, 2016, Law 1819 was enacted in Colombia,
which introduced a tax reform with several changes in the Colombian tax system, and became effective on January
1, 2017. This tax reform reduced the statutory corporate tax rate of companies to 40% in 2017, 37% in 2018, and
33% in 2019 onwards. The law also created a new withholding tax on dividend distributions based on a tax rate of
5%, applicable on distribution of Colombian profits generated from the taxable year 2017 onwards.
Other Regulatory Considerations — After the phenomenon of El Niño put the energy supply at risk, regulatory
agencies and the government have carried out various studies to make adjustments to the market. The subjects
susceptible to revision include the following:
• Adjustments to the scarcity price so that it reflects a true value of thermal plants that operate in periods of crisis.
• A plan to implement an option to assign firm energy obligations without the need for reliability auctions but with
obligation of signing energy contracts with non-regulated demand.
• Possible participation of renewable plants in the market and its effect in the formation of prices and operation of
the market.
• The implementation of the standardized contract market, and
• The possibility of entering into the intraday markets and markets of the previous day are still being considered.
Other topics that the regulator could analyze in 2017, but with a secondary priority are: An international
interconnection scheme, review of the AGC market and analysis of other ancillary services, and possible
modification of the current regulation for emergency situations.
Key Financial Drivers — Hydrological conditions largely influence Chivor's generation level. Maintaining the
appropriate contract level, while working to maximize revenue, through sale of excess generation, is key to Chivor's
results of operations Hedge levels at Chivor provide certainty and clarity on the underlying financial drivers, hedging
the net cash flows of Chivor, up to 90%. In addition to hydrology financial results are likely to be driven by many
factors including, but not limited to:
28
• Forced outages may impact earnings
• AES is exposed to fluctuation of the Colombian peso, which pose a risk to earnings; our hedging strategy
reduces this risk, but some residual risk to earnings remains
• Chivor has exposure to the spot market as hedge levels are lower in the future
Construction and Development — In Colombia, AES Gener completed the construction of the Tunjita project in
June 2016 that added 20 MW of capacity to the Chivor plant.
Argentina
Business Description — As of December 31, 2016, AES Argentina operates 4,105 MW which represents 12%
of the country's total installed capacity. The installed capacity in the SADI includes the TermoAndes plant, a
subsidiary of AES Gener, which is connected both to the SADI and the Chilean SING. AES Argentina has a
diversified generation portfolio of ten generation facilities, comprised of 68% thermoelectric and 32% hydroelectric
capacity. All of the thermoelectric capacity has the capability to burn alternative fuels. Approximately 76% of the
thermoelectric capacity can operate with natural gas or diesel oil, and the remaining 24% can operate with natural
gas, fuel oil, or coal.
AES Argentina primarily sells its production to the wholesale electric market where prices are largely
regulated. In 2016, approximately 94% of the energy was sold in the wholesale electric market and 6% was sold
under contract, as a result of the Energy Plus sales made by TermoAndes.
All of the thermoelectric facilities not affected by the Resolution 95/2013, a regulation passed in March 2013
discussed below, including the portion of TermoAndes plant committed to Energy Plus Contracts, are able to use
natural gas and receive gas supplied through contracts with Argentine producers. In recent years, gas supply
restrictions in Argentina, particularly during the winter season, have affected some of the plants, such as the
TermoAndes plant. The TermoAndes plant commenced operations in 2000, selling exclusively into the Chilean
SING. In 2008, following requirements from the Argentine authorities, TermoAndes connected its two gas turbines
to the SADI, while maintaining its steam turbine connected to the SING. However, since December 2011,
TermoAndes has been selling the plant's full capacity in the SADI.
Market Structure — The SADI electricity market is managed by CAMMESA. As of December 31, 2016, the
installed capacity of the SADI totaled 33,901 MW. In 2016, 66% of total energy demand was supplied by
thermoelectric plants, 26% by hydroelectric plants and 8% from nuclear, wind and solar plants.
Thermoelectric generation in the SADI is principally fueled by natural gas. However, since 2004 due to natural
gas shortages, in addition to increasing electricity demand, the use of alternative fuels in thermoelectric generation,
such as oil and coal, has increased. Given the importance of hydroelectric facilities in the SADI, hydrological
conditions determining river flow volumes and initial water levels in reservoirs largely influence hydroelectric and
thermoelectric plant dispatch. Rainfall occurs principally in the southern cone winter season (June to August).
Regulatory Framework — The Argentine regulatory framework divides the electricity sector into generation,
transmission and distribution. The wholesale electric market is made up of generation companies, transmission
companies, distribution companies and large customers who are allowed to buy and sell electricity. Generation
companies can sell their output in the short-term market or to customers in the contract market. CAMMESA is
responsible for dispatch coordination and determination of short-term prices. The Electricity National Regulatory
Agency is in charge of regulating public service activities and the Ministry of Federal Planning, Public Investment
and Services, through the Energy Secretariat, regulates system dispatch and grants concessions or authorizations
for sector activities.
Since 2001, significant modifications have been made to the electricity regulatory framework. These
modifications include the freezing of tariffs, the cancellation of inflation adjustment mechanisms and the introduction
of a complex pricing system in the wholesale electric market, which have materially affected electricity generators,
transporters and distributors, and generated substantial price differences within the market. Since 2004, as a result
of energy market reforms and overdue accounts receivables owed by the government to generators operating in
Argentina, AES Argentina contributed certain accounts receivables to fund the construction of new power plants
under FONINVEMEM agreements. These receivables accrue interest and are collected in monthly installments over
10 years once the related plants begin operations. At this point, three funds have been created to construct three
facilities. The three plants are operating and payments are being received. AES Argentina will receive a pro rata
ownership interest in these newly built plants once the accounts receivables have been paid. See Item 7.—Capital
Resources and Liquidity—Long-Term Receivables and Note 7—Financing Receivables for further discussion of
receivables in Argentina.
29
In March 2013, the Secretariat of Energy released Resolution 95/2013, which affects the remuneration of
generators whose sales prices had been frozen since 2003. This regulation is applicable to generation companies
with certain exceptions. It defined a compensation system based on compensating for fixed costs, non-fuel variable
costs and an additional margin. Resolution 95/2013 converted the Argentine electric market to an "average cost"
compensation scheme.
Thermal units must achieve an availability target, which varies by technology, in order to receive full fixed cost
revenues. The Resolution also established that all fuels, except coal, are to be provided by CAMMESA.
Thermoelectric natural gas plants not affected by the Resolution, such as TermoAndes, are able to purchase gas
directly from the producers for Energy Plus sales.
In May 2014, the Argentine government passed Resolution No. 529/214 ("Resolution 529") which retroactively
updated the prices of Resolution 95/2013 to February 1, 2014, changed target availability and added a
remuneration for non-periodic maintenance. This remuneration is aimed to cover the expenses that the generator
incurs when performing major maintenances in its units. Since 2014, this resolution has been updated annually, the
most recent of which was issued in March 2016.
On February 2, 2017, the Ministry of Energy issued Resolution 19/2017 establishing changes to the Energia
Base price framework. Effective in February 2017, the framework will maintain the current tolling agreement
structure, as fuels will continue to be sourced by CAMMESA. A key change will be introduced to the tariff structure
which will now have prices set in USD and also eliminates all future non-cash retention of margins.
In December 2015, the finance minister lifted foreign currency controls, allowing the peso to float under the
administration of Argentinean Central Bank. The newly freed currency fell by more than 30%. Over the course of
2016, the Argentinean Peso devalued by approximately 22%. At December 31, 2016, all transactions at our
businesses in Argentina were translated using the official exchange rate published by the Argentine Central Bank.
See Note 7—Financing Receivables in Item 8.—Financial Statements and Supplementary Data of this Form 10-K
for further information on the long-term receivables. Further weakening of the Argentine Peso and local economic
activity could cause significant volatility in our results of operations, cash flows, the ability to pay dividends to the
Parent Company, and the value of our assets.
Key Financial Drivers — Financial results are likely to be driven by many factors including, but not limited to:
• Forced outages may impact earnings
• FX exposure to fluctuations of the Argentine Peso
• Hydrology
• Timely collection of FONINVEMEM installment and outstanding receivables (See Note 7—Financing
Receivables in Item 8.—Financial Statements and Supplementary Data for further discussion)
Level of gas prices for contracted generation (Energy Plus)
•
Brazil SBU
Our Brazil SBU has generation and distribution businesses. Tietê and Eletropaulo are publicly listed
companies in Brazil. AES has a 24% economic interest in Tietê and a 17% economic interest in Eletropaulo. These
businesses are consolidated in our financial statements as we maintain control over their operations.
Generation — Operating installed capacity of our Brazil SBU totals 2,658 MW in AES Tietê plants, located in
the state of São Paulo. As of December 31, 2016, Tietê represents approximately 10% of the total generation
capacity in the state of São Paulo and is one of the largest generation companies in Brazil. We also have another
generation plant, AES Uruguaiana, located in southern Brazil with an installed capacity of 640 MW. The following
table lists our Brazil SBU generation facilities:
Business
Location
Fuel
Tietê (1)
Uruguaiana
Brazil
Brazil
Hydro
Gas
Gross
MW
2,658
640
3,298
AES Equity Interest
24%
46%
Year Acquired or
Began Operation
1999
2000
Contract
Expiration Date
2029
Customer(s)
Various
_____________________________
(1) Tietê plants with installed capacity: Água Vermelha (1,396 MW), Bariri (143 MW), Barra Bonita (141 MW), Caconde (80 MW), Euclides da Cunha (109 MW),
Ibitinga (132 MW), Limoeiro (32 MW), Mogi-Guaçu (7 MW), Nova Avanhandava (347 MW), Promissão (264 MW), Sao Joaquim (3 MW) and Sao Jose (4 MW).
Utilities — Eletropaulo operates in the metropolitan area of São Paulo and adjacent regions, distributing
electricity to 24 municipalities in a total area of 4,526 km2, covering a region of high demographic density and the
largest concentration of GDP in the country. Serving approximately 18 million people and 7 million consumer units,
30
Eletropaulo is the largest power distributor in Brazil, according to the 2015 ranking of the Brazilian Association of
the Distributors of Electric Energy (Abradee). On October 31, 2016, the Company completed the sale of its wholly-
owned subsidiary AES Sul, a distribution business in Brazil. The following table describes our Brazil utility:
Business
Location
Eletropaulo
Brazil
Approximate Number of Customers Served as
of 12/31/2016
GWh Sold in 2016
AES Equity Interest (% Rounded)
Year Acquired
7,015,909
34,464
17%
1998
The following map illustrates the location of our Brazil facilities:
Brazil Businesses
Brazil Utility
Business Description — Eletropaulo distributes electricity to the greater São Paulo area, Brazil's main
economic and financial center. AES owns 17% of the economic interest in Eletropaulo, our partner, BNDES, owns
19% and the remaining shares are publicly held or held by government-related entities. On December 30, 2016
AES purchased par shares from BNDES and increased its participation in Eletropaulo from 16% to 17%. AES is the
controlling shareholder and manages and consolidates this business. Eletropaulo holds a 30-year concession that
expires in 2028. In December 2016, Eletropaulo underwent a corporate restructuring which is expected to, among
other things, prepare for the listing of its shares on the Novo Mercado, a segment of the Brazilian stock exchange.
Regulatory Framework — In Brazil, ANEEL, a government agency, sets the tariff for each distribution company
based on a return on asset base methodology, which also benchmarks operational costs against other distribution
companies. The tariff charged to regulated customers consists of two elements: (i) pass-through of non-
manageable costs under a determined methodology ("Parcel A"), including energy purchase costs, sector charges
and transmission and distribution system expenses; and (ii) a manageable cost component ("Parcel B"), including
operation and maintenance costs (defined by ANEEL), recovery of investments and a component for a return to the
distributor. The return to distributors is calculated as the net asset base multiplied by the regulatory weighted-
average cost of capital, which is set for all industry participants during each tariff reset cycle. The current regulatory
weighted-average cost of capital for Eletropaulo, after tax, is 8.1%.
Each year ANEEL reviews each distributor's tariff for an annual tariff adjustment. The annual tariff adjustments
allow for pass-through of Parcel A costs and inflation impacts on Parcel B costs, adjusted for expected efficiency
gains and quality performances. Distribution companies are required to contract between 100% and 105% of
anticipated energy needs through the regulated auction market. If contracted levels fall below required levels
distribution companies may be subject to limitations on the pass-through treatment of energy purchase costs as
well as penalties. As the costs incurred on energy purchases made by our distribution company are passed through
31
to customers with adjustments on a yearly basis, working capital can be sensitive to significant increases in energy
prices. In order to reduce potential working capital needs, in 2015 ANEEL established the tariff flag mechanism,
which allows temporary tariff changes to customers on a monthly basis depending on energy purchase prices. The
resources collected by the tariff flag mechanism are centralized in an account and shared among distribution
companies in proportion to their respective exposure to the spot market.
Every four years, ANEEL resets each distributor's tariff to incorporate the revised regulatory weighted-average
cost of capital and determination of the distributor's net asset base as well as operational costs. Eletropaulo's tariff
reset occurs every four years and the next tariff reset will be in July 2019. The 4th Tariff Reset for AES Eletropaulo
occurred on July 4, 2015, representing an average tariff increase of 15.23%.
Between the tariff reset periods, the regulator applies the annual adjustments. On July 4, 2016 ANEEL
approved a negative tariff adjustment for Eletropaulo, mainly due to a decrease in energy purchase and sector
charges costs. The average tariff decrease was 8.1%.
In 2013, ANEEL challenged the parameters of a tariff reset for Eletropaulo implemented in July 2012 and
retroactive to 2011. ANEEL asserted that during the period between 2007 and 2011, certain assets that were
included in the regulatory asset base should not have been included and that Eletropaulo should refund customers
for the return on the disputed assets earned during this period. On December 17, 2013, ANEEL determined, at the
administrative level, that Eletropaulo should adjust the prior 2007-2011 regulatory asset base and refund customers
in the amount of $269 million over a period of up to four tariff processes beginning in July 2014. The Company
recognized a regulatory liability of approximately $269 million in 2013, since ANEEL had compelled the Company to
refund customers, and started reimbursing customers in July 2014. Eletropaulo filed for an administrative appeal
requesting ANEEL to reconsider its decision and requested that the decision be suspended until the appeal process
is completed. The injunction was granted and, although for a period was suspended, it has been restored and in
effect since December 2014.
Given ANEEL's failure to suspend the injunction through the appeals process in the Brazilian courts thus far,
the tariff reset resulted in management's reassessment of the probability of refunding customers these disputed
amounts. Therefore, at this point, the Company considers it only reasonably possible that Eletropaulo will be
required to refund these amounts to customers prior to the ultimate resolution of the pending court case. As a result,
during 2015, the Company reversed the remaining regulatory liability for this contingency of $161 million.
Eletropaulo believes it has meritorious arguments on this matter and will continue to pursue its objections to
ANEEL's rulings vigorously, however there can be no assurance that Eletropaulo will prevail.
Key Financial Drivers — Eletropaulo's financial results is likely to be driven by many factors including, but not
limited to:
• Hydrology, impacting quantity of energy sold and energy purchased
• Brazilian economic scenario and tariff increases, impacting energy consumption growth, losses and
delinquency
• Quality indicators recovery plan
• Ability of Eletropaulo to pass through costs via productivity gains
• Ability of Eletropaulo to solve involuntary exposure
• Capital structure optimization to reduce leverage and interest costs
• The CTEEP Eletrobrás case (see Item 3.—Legal Proceedings for further information)
Eletropaulo is affected by the demand for electricity, which is driven by economic activity, weather patterns
and customers' consumption behavior. Operating performance is also driven by the quality of service, efficient
management of operating and maintenance costs as well as the ability to control non-technical losses. Finally,
annual tariff adjustments and periodic tariff resets by ANEEL impact results from operations.
Brazil Generation
Business Description — Tietê has a portfolio of 12 hydroelectric power plants with total installed capacity of
2,658 MW in the state of São Paulo. Tietê was privatized in 1999 under a 30-year concession expiring in 2029. AES
owns a 24% economic interest in Tietê, our partner, the BNDES, owns 28% and the remaining shares are publicly
held or held by government-related entities. AES is the controlling shareholder and manages and consolidates this
business.
Tietê sold nearly 100% of its physical guarantee, approximately 11,194 GWh, to Eletropaulo under a long-term
PPA, which expired in December 2015. The contract was price-adjusted annually for inflation, and as of December
32
31, 2015, the price was R$218/MWh. After the expiration of contract with Eletropaulo, Tietê's strategy is to contract
most of its physical guarantee, as described in Regulatory Framework section below, and sell the remaining portion
in the spot market. Tietê's strategy is reassessed from time to time according to changes in market conditions,
hydrology and other factors. Tietê has been continuously selling its available energy from 2016 forward through
medium-term bilateral contracts of three to five years.
As of December 31, 2016, Tietê's contracted portfolio position is 95% and 88% with average prices of R$157/
MWh and R$159/MWh (inflation adjusted until December 2016) for 2016 and 2017, respectively. As Brazil is mostly
a hydro-based country with energy prices highly tied to the hydrological situation, the deterioration of the hydrology
since the beginning of 2014 caused an increase in energy prices going forward. Tietê is closely monitoring and
analyzing system supply conditions to support energy commercialization decisions.
Under the concession agreement, Tietê has an obligation to increase its capacity by 15%. Tietê, as well as
other concession generators, have not yet met this requirement due to regulatory, environmental, hydrological and
fuel constraints. The state of São Paulo does not have a sufficient potential for wind power and only has a small
remaining potential for hydro projects. As such, the capacity increases in the state will mostly be derived from
thermal gas capacity projects. Due to the highly complex process to obtain an environmental license for coal
projects, Tietê decided to fulfill its obligation with gas-fired projects in line with the federal government plans.
Petrobras refuses to supply natural gas and to offer capacity in its pipelines and regasification terminals. Therefore,
there are no regulations for natural gas swaps in place, and it is unfeasible to bring natural gas to AES Tietê. A legal
case has been initiated by the state of São Paulo requiring the investment to be performed. Tietê is in the process
of analyzing options to meet the obligation.
Uruguaiana is a 640 MW gas-fired combined cycle power plant located in the town of Uruguaiana in the state
of Rio Grande do Sul, commissioned in December 2000. AES manages and has a 46% economic interest in the
plant with the remaining interest held by BNDES. The plant's operations were suspended in April 2009 due to the
unavailability of gas. AES has evaluated several alternatives to bring gas supply on a competitive basis to
Uruguaiana. One of the challenges is the capacity restrictions on the Argentinean pipeline, especially during the
winter season when gas demand in Argentina is very high. The plant operated on a short-term basis during
February and March 2013, March through May 2014, and February through May 2015 due to the short-term supply
of LNG for the facility. The plant did not operate in 2016. Uruguaiana continues to work toward securing gas on a
long-term basis.
Market Structure — Brazil has installed capacity of 150,136 MW, which is 65% hydroelectric, 19% thermal and
16% renewable (biomass and wind). Brazil's national grid is divided into four subsystems. Tietê is in the Southeast
and Uruguaiana is in the South subsystems of the national grid.
Regulatory Framework — In Brazil, the Ministry of Mines and Energy determines the maximum amount of
energy that a plant can sell, called physical guarantee, which represents the long-term average expected energy
production of the plant. Under current rules, physical guarantee can be sold to distribution companies through long-
term regulated auctions or under unregulated bilateral contracts with large consumers or energy trading companies.
The National System Operator ("ONS") is responsible for coordinating and controlling the operation of the
national grid. The ONS dispatches generators based on hydrological conditions, reservoir levels, electricity demand
and the prices of fuel and thermal generation. Given the importance of hydro generation in the country, the ONS
sometimes reduces dispatch of hydro facilities and increases dispatch of thermal facilities to protect reservoir levels
in the system.
In Brazil, the system operator controls all hydroelectric generation dispatch and reservoir levels. A mechanism
known as the Energy Reallocation Mechanism ("MRE") was created to share hydrological risk across MRE hydro
generators. If the hydro plants generate less than the total MRE physical guarantee, the hydro generators may
need to purchase energy in the short-term market to fulfill their contract obligations. When total hydro generation is
higher than the total MRE physical guarantee, the surplus is proportionally shared among its participants and they
are able to make extra revenue selling the excess energy on the spot market. The consequences of unfavorable
hydrology are (i) thermal plants more expensive to the system being dispatched, (ii) lower hydropower generation
with deficits in the MRE and (iii) high spot prices. ANEEL defines the spot price cap for electricity in the Brazilian
market. The spot price caps as defined by ANEEL and average spot prices by calendar year are as follows (R$/
MWh):
Year
Spot price cap as defined by ANEEL
Average spot rate
2017
534
2016
423
94
2015
388
287
2014
822
689
33
Key Financial Drivers — As the system is highly dependent on hydroelectric generation, Tietê and Uruguaiana
are are affected by the hydrology in the overall sector. They are also affected by the availability of Tietê's plants and
reliability of the Uruguaiana facility. The availability of gas is also a driver for continued operations at Uruguaiana.
Tietê's financial results are likely to be driven by many factors including, but not limited to:
• Hydrology, impacting quantity of energy generated in MRE
• Demand growth
• Re-contracting price
• Asset management and plant availability
• Cost management
• Ability to execute on its growth strategy
MCAC SBU
Our MCAC SBU has a portfolio of distribution businesses and generation facilities, including renewable
energy, in five countries, with a total capacity of 3,239 MW and distribution networks serving 1.4 million customers
as of December 31, 2016.
Generation — The following table lists our MCAC SBU generation facilities:
Business
Location
Fuel
Andres
Itabo (1)
DPP (Los Mina)
Dominican Republic Subtotal
AES Nejapa
Moncagua
El Salvador Subtotal
Merida III
Dominican
Republic
Dominican
Republic
Dominican
Republic
Gas
Coal/Gas
Gas
El Salvador
El Salvador Solar
Landfill Gas
Mexico
Gas
Termoelectrica del Golfo (TEG)
Mexico
Termoelectrica del Penoles (TEP) Mexico
Mexico Subtotal
Bayano
Panama
Changuinola
Chiriqui-Esti
Estrella de Mar I
Chiriqui-Los Valles
Panama
Panama
Panama
Panama
Pet Coke
Pet Coke
Hydro
Hydro
Hydro
Heavy Fuel
Oil
Hydro
Chiriqui-La Estrella
Panama
Hydro
Panama Subtotal
Puerto Rico
Illumina
Puerto Rico Subtotal
US-PR
US-PR
Coal
Solar
Gross
MW
319
295
236
850
6
3
9
505
275
275
1,055
260
223
120
72
54
48
777
524
AES
Equity
Interest
90%
45%
90%
100%
100%
55%
99%
99%
49%
90%
49%
49%
49%
49%
100%
24
100%
548
3,239
Year Acquired
or Began
Operation
Contract
Expiration
Date
2003
2000
1996
2011
2015
2000
2007
2007
1999
2011
2003
2015
1999
1999
2002
2012
2018
2017
2022
2035
2035
2025
2027
2027
2030
2030
2030
2020
2030
2030
Customer(s)
Ede Este/Non-Regulated
Users/Linea Clave
Ede Este/Ede Sur/Ede
Norte
CDEEE
CAESS
EEO
Comision Federal de
Electricidad
CEMEX
Penoles
Electra Noreste/Edemet/
Edechi/Other
AES Panama
Electra Noreste/Edemet/
Edechi/Other
Electra Noreste/Edemet/
Edechi/Other
Electra Noreste/Edemet/
Edechi/Other
Electra Noreste/Edemet/
Edechi/Other
2027 Puerto Rico Electric Power
Authority
2032 Puerto Rico Electric Power
Authority
_____________________________
(1)
Itabo plants: Itabo complex (two coal-fired steam turbines and one gas-fired steam turbine).
Under construction — The following table lists our plants under construction in the MCAC SBU:
Business
Location
Fuel
Gross
MW
AES Equity Interest
Expected Date of Commercial
Operations
DPP (Los Mina) Conversion
Dominican ES
Dominican Republic Subtotal
Colón
Panama Subtotal
Dominican Republic Gas
Dominican Republic
Energy Storage
Panama
Gas
122
20
142
380
380
522
90%
90%
50%
1H 2017
1H 2017
1H 2018
34
Utilities — Our distribution businesses are located in El Salvador and distribute power to 1.4 million people in
the country. These businesses consist of four companies, each of which operates in defined service areas. The
following table lists our MCAC utilities:
Business
Location
Approximate Number of Customers Served
as of 12/31/2016
GWh Sold in 2016
AES Equity Interest
Year Acquired or Began
Operation
CAESS
CLESA
DEUSEM
EEO
El Salvador
El Salvador
El Salvador
El Salvador
590,971
388,341
78,063
298,026
1,355,401
2,232
894
133
576
3,835
75%
80%
74%
89%
2000
1998
2000
2000
The following map illustrates the location of our MCAC facilities:
MCAC Businesses
MCAC Utilities
El Salvador
Business Description — AES is the majority owner of four of the five distribution companies operating in El
Salvador. The distribution companies are operated by AES on an integrated basis under a single management
team. AES El Salvador's territory covers 77% of the country. AES El Salvador accounted for 4,151 GWh of market
energy purchases during 2016, or about 63% market share of the country's total energy purchases.
MCAC Generation
Dominican Republic
Business Description — AES Dominicana consists of three operating subsidiaries, Itabo, Andres and DPP.
AES has 24% of the system capacity of 850 MW and supplies approximately 37% of energy demand through these
generation facilities. AES has a strategic partnership with the Estrella and Linda Groups ("Estrella-Linda"), an
investor group based in the Dominican Republic. Estrella-Linda is a consortium of two leading Dominican industrial
groups: Estrella and Grupo Linda. The two partners manage a diversified business portfolio, including construction
services, cement, agribusiness, metalwork, plastics, textiles, paints, transportation, insurance and media.
Itabo is 45% owned by AES, 5% by Estrella-Linda, 49.97% owned by FONPER, a government-owned utility
and the remaining 0.03% is owned by employees. Itabo owns and operates two thermal power generation units with
a total of 295 MW of installed capacity. Itabo's PPAs with government-owned distribution companies expired in July
2016 and thus two new short term contracts with Ede Sur and Ede Este were signed until new long term contracts
take place. The Dominican Corporation of State Electrical Companies is sponsoring a bidding process, released in
35
August 2016, which is expected to be awarded in April 2017 in order to secure supply and competitive pricing for
actual and future distribution energy requirements. The existing business strategy is to secure between 80% and
85% of the open position through new PPAs with distribution companies and large users. Price and PPA structure
will be subject to the terms of the bidding process.
Andres and DPP are owned 90% by AES and 10% by Estrella-Linda. Andres has a combined cycle gas
turbine and generation capacity of 319 MW as well as the only LNG import facility in the country, with 160,000 cubic
meters of storage capacity. DPP (Los Mina) has two open cycle natural gas turbines and generation capacity of 236
MW. Both Andres and DPP have in aggregate 555 MW of installed capacity, of which 450 MW is mostly contracted
until 2018 with government-owned distribution companies and large customers.
AES Dominicana has a long-term LNG purchase contract through 2023 for 33.6 trillion btu/year with a price
linked to NYMEX Henry Hub. The LNG contract terms allow the diversion of the cargoes to various markets in Latin
America. These plants capitalize on the competitively-priced LNG contract by selling power where the market is
dominated by fuel oil-based generation. Andres has a long-term contract to sell re-gasified LNG to industrial users
within the Dominican Republic using compression technology to transport it within the country thereby capturing
demand from industrial and commercial customers.
Market Structure - Electricity and Natural Gas — The Dominican Republic has one main interconnected
system with approximately 3,553 MW of installed capacity, composed primarily of thermal generation (80%),
hydroelectric power plants (17%) and wind plants (3%).
Regulatory Framework — The regulatory framework in the Dominican Republic consists of a decentralized
industry including generation, transmission and distribution, where generation companies can earn revenue through
short- and long-term PPAs, ancillary services and a competitive wholesale generation market. All electric
companies (generators, transmission and distributors), are subject to and regulated by the General Electricity Law.
Two main agencies are responsible for monitoring and ensuring compliance with the General Electricity Law,
the National Energy Commission and the Superintendence of Electricity. The National Energy Commission is in
charge of drafting and coordinating the legal framework and regulatory legislation, proposing and adopting policies
and procedures to assure best practices, drafting plans to ensure the proper functioning and development of the
energy sector and promoting investment. The Superintendence of Electricity's main responsibilities include
monitoring and supervising compliance with legal provisions and rules, monitoring compliance with the technical
procedures governing generation, transmission, distribution and commercialization of electricity and supervising
electric market behavior in order to avoid monopolistic practices.
The electricity tariff applicable to regulated customers is subject to regulation within the concessions of the
distribution companies. Clients with demand above 1 MW are classified as unregulated customers and their tariffs
are unregulated.
Fuels and hydrocarbons are regulated by a specific law which establishes prices to end customers and a tax
on consumption of fossil fuels. For natural gas there are regulations related to the procedures to be followed to
grant licenses and concessions: i) distribution, including loading, transportation and compression plants; ii) the
installation and operation of natural gas stations, including consumers and potential modifications of existing
facilities; and iii) conversion equipment suppliers for vehicles. The regulation is administered by the Industrial and
Commerce Ministry who supervises commercial and industrial activities in the Dominican Republic as well as the
fuels and natural gas commercialization to the end users.
Key Financial Drivers — Financial results are likely to be driven by many factors including, but not limited to:
• Changes in spot prices due to fluctuations in commodity prices, (since fuel is a pass-through cost under the
PPAs, any variation in oil prices will impact the spot sales for both Andres and Itabo)
• Contracting levels and the extent of capacity awarded
• Supply shortages in the near term (next two to three years) may provide opportunities for short term upside,
but new generation is expected to come online beginning 2018
• Additional sales derived from domestic natural gas demand are expected to continue providing income and
growth based on the entry of future projects and the fees from the infrastructure service.
In addition, the financial weakness of the three state-owned distribution companies due to low collection rates
and high levels of non-technical losses has led to delays in payments for the electricity supplied by generators. At
times when outstanding receivable balances have accumulated, AES Dominicana has accepted payment through
other means, such as government bonds, in order to reduce the balance. There can be no guarantee that
alternative collection methodologies will always be an avenue available for payment options.
36
Construction and Development — DPP is converting its existing plant from open cycle to combined cycle. The
project will recycle DPP's heat emissions and increase total power output by approximately 114 MW of gross
capacity at an estimated cost of $260 million, fully financed with non-recourse debt. The EPC contract was signed
on July 2, 2014, and the additional capacity is expected to become operational in the first half of 2017. Based on
the increased capacity, AES Dominicana executed a PPA for 270 MW for a 6.5 year term beginning in 2017.
Panama
Business Description — AES owns and operates five hydroelectric plants and one thermoelectric power plant,
Estrella del Mar I, which commenced operations in March 2015, representing 705 MW and 72 MW of hydro and
thermal capacity respectively, for a total of 777 MW equivalent to 23% of the installed capacity in Panama. The
majority of hydro sources in Panama are based on run-of-river technology, with the exception of the 260 MW
Bayano plant.
A portion of the PPAs with distribution companies will expire in December 2018 reducing the total contracted
capacity of the company from 496 MW to 430 MW. Another portion contracted through Estrella del Mar I will expire
in June 2020, reducing the total contracted capacity to 350 MW until December 2030.
Market Structure — Panama's current total installed capacity is 3,350 MW, of which 52% is hydroelectric, 8%
wind, 2% solar and the remaining 38% thermal generation from diesel, bunker fuel and coal.
The Panamanian power sector is composed of three distinct operating business units: generation, distribution
and transmission, all of which are governed by Electric Law 6 enacted in 1997.
Generators can enter into long-term PPAs with distributors or unregulated consumers. In addition, generators
can enter into alternative supply contracts with each other. Outside of the PPA market, generators may buy and sell
energy in the short-term market.
The National Dispatch Center implements the economic dispatch of electricity in the wholesale market. The
National Dispatch Center's objectives are to minimize the total cost of generation and maintain the reliability and
security of the electric power system, taking into account the price of water, which determines the dispatch of hydro
plants with reservoirs. Short-term power prices are determined on an hourly basis by the last dispatched generating
unit.
In Panama, dry hydrological conditions remained until June 2016, due to the presence of the El Niño
phenomenon, affecting the generation output from hydroelectric facilities compared to the prior year. AES Panama
had to purchase energy on the spot market to fulfill its contract obligations as its generation output was below
contract levels. The drop in the commodities prices helped to reduce the replacement cost and the financial impact
of spot purchases compared to the prior year. Despite the hydrology conditions, spot prices were down to $60/MWh
from $91/MWh in 2015, limiting the amount recognized through the 2014-2016 Government Compensation
Agreement to $1 million out of the possible $30 million for 2016. On March 31, 2014, the government of Panama
agreed to reduce the financial impact of spot electricity purchases and transmission constraints equivalent to a 70
MW reduction in contracted capacity for the period 2014-2016 by compensating AES Panama for spot purchases
above the contracted price of $82.45/MWh, up to $40 million in 2014, $30 million in 2015 and $30 million in 2016.
Regulatory Framework — The SNE has the responsibilities of planning, supervising and controlling policies of
the energy sector within Panama. With these responsibilities, the SNE proposes laws and regulations to the
executive agencies that promote the procurement of electrical energy, hydrocarbons and alternative energy for the
country.
The regulator of public services, known as the ASEP, is an autonomous agency of the government. ASEP is
responsible for the control and oversight of public services including electricity and the transmission and distribution
of natural gas utilities and the companies that provide such services.
Generators can only contract up to their firm capacity. Physical generation of energy is determined by the
National Dispatch Center regardless of contractual arrangements.
Key Financial Drivers — Financial results are likely to be driven by many factors including, but not limited to:
•
In the event of low hydrology, high commodity prices will increase the business exposure and the cost of
replacement power to fulfill our contractual commitments, partially mitigated by additional generation from
Estrella del Mar I.
• Fluctuations in commodity prices, mainly oil prices, affect the thermal generation cost impacting the spot
prices and the opportunity cost of water.
37
• Constraints imposed by the capacity of the transmission line connecting the west side of the country with the
load center are expected to continue until the end of 2017 keeping surplus power trapped, particularly during
the wet season.
• Country demand as GDP growth is expected to remain strong over the short and medium term.
Given that most of AES' portfolio is run-of-river, hydrological conditions have an important influence on its
profitability. Variations in actual hydrology can result in excess or a short energy balance relative to our contract
obligations. During the low inflow period of January through May, generation tends to be lower and AES Panama
may purchase energy in the short-term market to cover contractual obligations. During the remainder of the year
(June to December), generation tends to be higher and energy generated in excess of contract volumes is sold to
the short-term market. In addition to hydrological conditions, commodity prices affect short-term electricity prices.
Construction and Development — Continuing with the strategy to reduce reliance on hydrology started with
the acquisition of the power barge, Estrella del Mar I, in August 2015 AES executed a partnership agreement with
Deeplight Corporation, a minority partner, with the purpose to construct, operate and maintain a natural gas power
generation plant and a liquefied natural gas terminal, in order to purchase and sell energy and capacity as well as
commercialize natural gas and other ancillary activities related to natural gas. As of December 31, 2016, amounts
capitalized include $254 million recorded in Construction in Progress and the project is scheduled to initiate
operations in the first half of 2018.
Mexico
Business Description — AES has 1,055 MW of installed capacity in Mexico, including the 550 MW
Termoeléctrica del Golfo ("TEG") and Termoeléctrica Peñoles ("TEP") facilities and Merida III ("Merida"), a 505 MW
generation facility.
The TEG and TEP pet coke-fired plants, located in San Luis Potosi, supply power to their offtakers under long-
term PPAs expiring in 2027 with a 90% availability guarantee. TEG and TEP secure their fuel under a long-term
contract.
Merida is a CCGT, located in Merida, on Mexico's Yucatan Peninsula. Merida sells power to the Federal
Commission of Electricity ("CFE") under a capacity and energy based long-term PPA through 2025. Additionally, the
plant purchases natural gas and diesel fuel under a long-term contract, the cost of which is then passed through to
CFE under the terms of the PPA.
In line with AES' strategy of building strategic partnerships, on January 18, 2016 the 50/50 joint venture
partnership agreement with Grupo BAL was fully executed. The joint venture will co-invest in power and related
infrastructure projects in Mexico.
Market Structure — Mexico has a single national electricity grid, the National Power System, covering nearly
all of Mexico's territory. Mexico has an installed capacity totaling 68 GW with a generation mix of 72% thermal, 18%
hydroelectric and 10% other. Electricity consumption is split between the following end users: industrial of 58%,
residential of 26% and commercial and service of 16%.
Regulatory Framework — Following the constitutional changes approved in December 2013, during 2014 and
2015 the Mexican government issued a package of secondary regulations, including the Electricity Law, and
operational dispositions, with the objective to start the implementation of a new regulatory framework with the
following characteristics:
• The energy market liberalization in January 2016 through the implementation of: wholesale electricity market
(day ahead and real time market), ancillary services, capacity, Clean Energy Certificates, and Financial
Transmission Rights market.
• CFE's, former state-owned electric monopoly, vertical and horizontal disintegration into different segments of the
value chain: generation, transmission, distribution and commercialization.
• CENACE as new ISO is responsible for managing the wholesale electricity market, transmission and distribution
infrastructure, planning the network developments, guaranteeing open access to network infrastructure,
executing competitive mechanisms to cover regulated demand, and setting transmission charges.
Implementation of annual mid and long term auctions to secure supply for the regulated demand, establishing a
PPA with CFE as the Basic Supplier.
•
According to the new regulatory framework, new assets developed under the new framework or assets
transferred to the new regime and in operation after the approval of the Electricity Law (August 2014) are eligible to
participate in the new markets. Additionally, projects developed and operated under the Electric Public Service Law
38
(self-supply framework) like TEG/TEP, could choose to participate. Until the new framework is further analyzed,
AES will continue operating under the same conditions. Merida III and TEG/TEP will continue providing power
under long-term contracts and selling any excess or surplus energy produced to CFE.
Key Financial Drivers — Financial results are likely to be driven by many factors including, but not limited to:
• Operational performance (as the companies are fully contracted and better performance provides additional
financial benefits including performance incentives and/or excess energy sales (in the case of TEG/TEP).
• The energy prices of TEG/TEP for the sales in excess over its long-term contracts are driven by the average
•
production cost of CFE which is highly dependent on natural gas and oil.
If the average production cost of CFE is higher than the cost of generating with pet coke, our businesses in
Mexico will benefit provided that they are able to sell energy in excess of their PPAs.
Puerto Rico
Business Description — AES Puerto Rico owns and operates a coal-fired cogeneration plant and a solar plant
of 524 MW and 24 MW, respectively, representing approximately 9% of the installed capacity in Puerto Rico. Both
plants have long-term PPAs expiring in 2027 and 2032, respectively, with PREPA, a state-owned entity that supplies
virtually all of the electric power consumed in Puerto Rico and generates, transmits and distributes electricity to
1.5 million customers. See Item 7.—Key Trends and Uncertainties—Macroeconomic and Political—Puerto Rico for
further discussion of the long-term PPA with PREPA.
El Salvador
Business Description — AES El Salvador also owns AES Nejapa, a 6 MW power plant generating electricity
with methane gas from a landfill, fully contracted with CAESS. During 2015, AES El Salvador began operations of a
AES Moncagua, a 2.5 MW solar facility located in the East of the country, which is fully contracted with EEO.
The sector is governed by the General Electricity Law and the general and specific orders are issued by
Superintendencia General de Electricidad y Telecomunicacions ("SIGET"). SIGET, jointly with the distribution
companies in El Salvador, completed the tariff reset process in December 2012 and defined the tariff calculation to
be applicable for the five year period 2013-2017.
Europe SBU
Generation — Our Europe SBU has generation facilities in five countries. Operating installed capacity of our
Europe SBU totaled 6,619 MW. The following table lists our Europe SBU generation facilities:
Business
Location
Fuel
Maritza
St. Nikola
Bulgaria Subtotal
Amman East
IPP4
Bulgaria
Bulgaria
Jordan
Jordan
Jordan Subtotal
Kazakhstan
Ust-Kamenogorsk CHP
Shulbinsk HPP (1)
Kazakhstan
Kazakhstan
Sogrinsk CHP
Ust-Kamenogorsk HPP (1) Kazakhstan
Kazakhstan Subtotal
Elsta (2)
Netherlands
Netherlands ES
Netherlands
Coal
Wind
Gas
Heavy Fuel
Oil/Gas
Coal
Hydro
Coal
Hydro
Gas
Energy
Storage
Netherlands Subtotal
Ballylumford
Kilroot (3)
Kilroot ES
United Kingdom Subtotal
United Kingdom Gas
United Kingdom Coal/Oil
United Kingdom Energy
Storage
Gross
MW
690
156
846
381
250
631
1,398
702
345
331
2,776
630
AES
Equity
Interest
100%
89%
37%
36%
100%
—%
100%
—%
50%
10
100%
100%
99%
100%
640
1,015
701
10
1,726
6,619
Year Acquired
or Began
Operation
Contract
Expiration
Date
Customer(s)
2011
2010
2026
2025
Natsionalna Elektricheska
Natsionalna Elektricheska
2009
2033-2034
2014
2039
National Electric Power
Company
National Electric Power
Company
Short-term
2020
Short-term
2020
Various
Titanium Magnesium Kombiant
Various
Titanium Magnesium Kombiant
2018
Dow Benelux/Delta/
Nutsbedrijven/Essent Energy
2023
Power NI/Single Electricity
Market (SEM)
SEM
1997
1997
1997
1997
1998
2015
2010
1992
2015
_____________________________
(1) AES operates these facilities under concession agreements until 2017.
(2) Unconsolidated entity, the results of operations of which are reflected in Equity in Earnings of Affiliates.
39
(3)
Includes Kilroot Open Cycle Gas Turbine ("OCGT").
The following map illustrates the location of our Europe facilities:
Europe Businesses
Bulgaria
Business Description — Our Maritza plant is a 690 MW lignite fuel plant that was commissioned in June 2011.
Maritza is fully compliant with the European Union Industrial Emission Directive, which became effective in January
2016. Maritza's entire power output is contracted with NEK under a 15-year PPA, capacity and energy based, with a
fuel pass-though, expiring in 2026. The lignite and limestone are supplied under 15-year fuel supply contracts.
AES also owns an 89% economic interest in the St. Nikola wind farm with 156 MW of installed capacity. St.
Nikola was commissioned in March 2010. Its entire power output is contracted with NEK under a 15-year PPA
expiring in March 2025.
Market Structure — The maximum market capacity in 2016 was approximately 13 GW. Thermal generation,
which is mostly coal-fired, and nuclear power plants account for 61% of the installed capacity.
Regulatory Framework — The electricity sector in Bulgaria operates under the Energy Act of 2004 which
allows the sale of electricity to take place freely at negotiated prices, at regulated prices between parties or on the
organized market. In 2016 the government of Bulgaria made advances toward market liberalization and has
engaged with the World Bank to develop a model for a fully liberalized electricity market in Bulgaria. The final report
with recommendations from the World Bank was finalized in December 2016. The Independent Bulgarian Energy
Exchange (IBEX) started commercial operation of the power exchange in January 2016 with the introduction of Day
Ahead market platform. In September 2016, IBEX expanded its trading platform for bilateral forward contracts. The
next step of the development of IBEX is the introduction of intra-day trading, which is expected in mid-2017.
Our investments in Bulgaria rely on long-term PPAs with NEK, the state-owned electricity public supplier and
energy trading company. NEK had been facing some liquidity issues and had been delayed in making payments
under the PPAs with Maritza and St. Nikola. In August 2015, the ninth amendment of Maritza's PPA was executed,
under which Maritza and NEK agreed to reduce the capacity payment to Maritza by 14% through the PPA term
without impacting the energy price component. In exchange, NEK paid Maritza its overdue receivables. The
amendment became effective in April 2016 upon full payment of the overdue receivables by NEK. Maritza has
experienced timely collection of outstanding receivables from NEK since May 2016.
The Directorate-General for Competition of the European Commission (“DG Comp”) continues to review NEK’s
respective PPAs with Maritza and an unrelated generator pursuant to the European Commission’s state aid rules.
Although no formal investigation has been launched by DG Comp, Maritza has met with the DG Comp case team
and representatives of Bulgaria to discuss the agency’s review. Maritza expects that the parties will engage in
40
further discussions on the issues surrounding the review. At this time, we cannot predict the outcome of such
discussions, nor can we predict how DG Comp might resolve its review if the anticipated discussions fail to result in
an agreement concerning the review. Maritza believes that its PPA is legal and in compliance with all applicable
laws, and it will take all actions necessary to protect its interests, whether through negotiated agreement or
otherwise. However, there can be no assurances that this matter will be resolved favorably; if it is not, there could
be a material adverse impact on Maritza’s and the Company’s respective financial statements.
In 2015, a number of measures were introduced to the regulation of the energy sector that significantly
improved the liquidity of NEK. As a result, NEK is forecast to end the year 2016 with a $7 million net profit, more
than a $102 million improvement over year 2015 and more than a $316 million improvement over year 2014.
However, the financial situation of NEK remains subject to political conditions and regulatory changes in Bulgaria.
Key Financial Drivers — Both businesses, Maritza and St. Nikola, operate under PPA contracts. For the
duration of the PPA, the financial results are primarily driven by, but not limited to:
•
the availability of the operating units
the level of wind resource for St. Nikola
•
• NEK's ability to meet the terms of the PPA contract
United Kingdom
Business Description — AES' generation businesses in the United Kingdom are located in Northern Ireland
and operate in the Irish SEM (1,726 MW). The Northern Ireland generation facilities consist of two plants within the
Greater Belfast region. Our Kilroot plant is a 701 MW coal-fired plant with an additional 10 MW of energy storage
facility and our Ballylumford plant is a 1,015 MW gas-fired plant. These plants provide approximately 62% of the
Northern Ireland installed capacity and 16% of the combined installed capacity for the island of Ireland.
Kilroot is a merchant plant that bids into the SEM. the plant earns margin when scheduled in merit, out of
merit, for capacity payments, and for ancillary services. Out of merit dispatch, through which costs are recovered,
occurs when there are system constraints related to wind generation, voltage and transmission.
Ballylumford is partially contracted for 600 MW under a PPA with PPB that expires in 2023 with the remaining
capacity bid into the SEM market. 310 MW of this merchant capacity has a supplemental Local Reserve Services
Agreement ("LRSA") with the system operator. Ballylumford earns margin from availability payments received under
the PPA, capacity payments offered through the SEM and revenues from the LRSA. Additionally, Ballylumford
receives margin from out of merit dispatch through which the costs of operation are recovered as well as ancillary
services.
Market Structure — The majority of the generation capacity in the SEM is represented by gas-fired power
plants, which results in market sensitivity to gas prices. Wind generation capacity represents approximately 25% of
the total generation capacity. The governments of Northern Ireland and the Republic of Ireland plan further
increases in renewable energy sources. Market availability and liquidity of hedging products are weak, reflecting the
limited size and immaturity of the market, the predominance of vertical integration and lack of forward pricing. There
are essentially three products (baseload, mid-merit and peaking) which are traded between the generators and
suppliers.
Regulatory Framework — The SEM is an energy market established in 2007 and is based on a gross
mandatory pool within which all generators with a capacity higher than 10 MW must trade the physical delivery of
power. Generators are centrally dispatched based on merit order and physical constraints of the system. The SEM
structure is under review by the regulatory authorities with a new structure due to be introduced in the second
quarter of 2018.
In addition, there is a capacity payment mechanism to ensure that sufficient generating capacity is offered to
the market. The capacity payment is derived from a regulated Euro-based capacity payment pool, established a
year ahead by the regulatory authority. Capacity payments are based on the declared availability of a unit and have
a degree of volatility to reflect seasonal influences, demand and the actual out-turn of generation declared available
over each trading period.
Environmental Regulation — In 2011, the European Commission adopted the Industrial Emission Directive
("IED") that establishes the Emission Limit Values ("ELV") for SO2, NOx and dust emissions effective January 1,
2016. Both Ballylumford and Kilroot are required to comply with the IED. The Ballylumford C Station is compliant
without the need for investment. Both Ballylumford B Station and Kilroot required investment to be in compliance.
41
The IED provides for two options that may be implemented by the European Union member states other than
compliance with the new ELV's the Transitional National Plan or Limited Life Time Derogation.
Kilroot has opted into the Transitional National Plan which allows the plant to operate between 2016-2020,
being exempt from compliance with ELVs, but observing a ceiling set for maximum annual emissions that is based
on the last 10 years average emissions and operating hours. Kilroot has invested approximately $10 million in
Umbrella Selective Non Catalytic Reduction technology, which reduces the plant's NOx emissions enabling the plant
to increase its capacity factor within the ceiling of NOx emissions and earn energy margin. The Transitional National
Plan also established a UK wide NOx trading scheme which Kilroot avails of as required. Further technical
modifications are being evaluated which could make the plant fully compliant with the IED from 2020.
Without investment, the Ballylumford B station of 540 MW did not meet the standards of the IED. In 2014, AES
secured a LRSA with the Transmission System Operator ("TSO") to refurbish two of the three units to be compliant
with ELVs under IED, providing at least 250 MW of capacity from 2016 to 2018 with an option to extend to 2020 by
the TSO. The project was executed in 2015 with an achieved combined gross output of 310 MW.
Key Financial Drivers — For our businesses in the SEM market, the financial results will be driven by, but not
limited to, the following:
• Regulatory changes to the market structure and payment mechanism
• Availability of the operating units
• Commodity prices (gas, coal and CO2) and sufficient market liquidity to hedge prices in the short-term
• Electricity demand in the SEM (including impact of wind generation)
Kazakhstan
Business Description — Our businesses account for approximately 6% of the total annual generation in
Kazakhstan. Of the total capacity of 2,776 MW, 1,033 MW is hydroelectric and operates under a concession
agreement until the beginning of October 2017 and 1,743 MW is coal-fired capacity which is owned outright. The
thermal plants are designed to produce heat with electricity as a co- or by-product.
The Kazakhstan businesses act as merchant plants for electricity sales by entering into bilateral contracts
directly with consumers for periods of generally no more than one year. There are limited opportunities for the
plants to be in contracted status, as there is no central offtaker, and the few businesses that could take a whole
plant's generation tend to have in-house generation capacity.
The hydroelectric plants are run-of-river and rely on river flow and precipitation, particularly snow. Due to the
presence of a large multi-year storage dam upstream and a season minimum river flow rate agreement with Russia
downstream, the plants are protected against significant downside risk to their volume in years with low
precipitation. AES does not control water flow which impacts our generation.
Ust Kamenogorsk CHP provides heat to the city of Ust Kamenogorsk through the city heat network company
(Ust Kamenogorsk Heat Nets). Ust Kamenogorsk CHP is their only source of supply.
Market Structure — The Kazakhstan electricity market totals approximately 21,307 MW, of which 17,504 MW
is available. The bulk of the generating capacity in Kazakhstan is thermal with coal as the main fuel. As coal is
abundantly available in Kazakhstan, most plants are designed to burn local coal. The geographical remoteness of
Kazakhstan, in combination with its abundant resources, results in coal prices that are not reflective of world coal
prices, current delivered cost is less than $12 per metric ton. In addition, the government closely monitors coal
prices, due to their impact on the price of socially necessary heating and on electricity tariffs.
Regulatory Framework — All Kazakhstan generating companies sell electricity at or below their respective
tariff-cap level. These tariff-cap levels have been fixed by the Kazakhstan government for the period 2009-2018 for
each of the fifteen groups of generators. These groups were determined by the Ministry of Energy, based on a
number of factors including plant type and fuel used.
In July 2012, Kazakhstan enacted an amendment to its Electricity Law requiring electricity producers to
reinvest all profits generated during the years 2013-2015 as part of annual investment obligation agreements,
thereby limiting the businesses ability to distribute dividends. These investment obligation agreements had to be
equal to the sum of the planned annual depreciation and profit. Selection of investment projects was at the
discretion of electricity producers, but the Ministry of Energy had the right to reject submitted proposals. An
electricity producer without an investment obligation agreement executed by the Ministry of Energy was not allowed
to charge tariffs exceeding its incremental cost of production, excluding depreciation.
42
In November 2015, Kazakhstan enacted amendments to its Electricity Law to eliminate the obligation for
power plants to sign annual investment obligation agreements for 2016-2018, thereby allowing the businesses to
distribute dividends. In addition, the amendment stated that a centrally organized capacity market will be
established by 2019 and that the Kazakhstan government plans to prolong price cap regulation by fixing new caps
on energy and capacity tariffs for each group of power plants.
Kazakhstan government has approved a renewable energy law which set feed-in tariffs for renewable energy
and set a renewable energy target of 3% by 2020 and 10% by 2030. This renewable energy law imposes an
obligation on all non-renewable power plants to purchase renewable energy at the renewable energy tariff and
resell it to customers at their own, lower price cap level.
Heat production in Kazakhstan is also regulated as a natural monopoly. The heat tariffs are set on a cost-plus
basis by making an application to the Committee of Natural Monopoly Regulation and Competition Protection, the
regulator. Currently, tariffs are only for multi-year periods, but with some annual adjustments for fuel cost.
Key Financial Drivers — The financial results for assets in Kazakhstan are driven by many factors including,
but not limited to:
• Availability of the operating units;
• Regulated electricity tariff-cap levels and heat tariff levels
• Weather conditions,
• Regulatory changes to the market structure and payment mechanism
• Cost of coal and Kazakhstan currency exchange rate fluctuation.
Jordan
Business Description — In Jordan, AES has a 37% controlling interest in Amman East, a 381 MW oil/gas-fired
plant fully contracted with the national utility under a 25-year PPA and a 36% controlling interest in the IPP4 plant in
Jordan, a 250 MW oil/gas-fired peaker plant which commenced operations in July 2014, fully contracted with the
national utility under a 25-year PPA. As we have controlling interest in these businesses, we consolidate the results
in our operations.
Asia SBU
Generation — Our Asia SBU has generation facilities in three countries. Operating installed capacity totals
2,300 MW. The following table lists our Asia SBU generation facilities:
Business
Location
Fuel
Gross
MW
AES Equity
Interest
OPGC (1)
India Subtotal
Masinloc
Masinloc ES
Philippines Subtotal
Mong Duong 2
Vietnam Subtotal
India
Coal
Philippines Coal
Philippines Energy Storage
Vietnam
Coal
49%
51%
51%
51%
420
420
630
10
640
1,240
1,240
2,300
Year Acquired or
Began Operation
1998
Contract Expiration
Date
Customer(s)
2026
GRID Corporation Ltd.
2008 Mid and long-term
2016
Various
2015
2040
EVN
_____________________________
(1)
Unconsolidated entity for which the results of operations are reflected in Equity in Earnings of Affiliates.
Under construction — The following table lists our plants under construction in the Asia SBU:
Business
Location
Fuel
OPGC II
India Subtotal
Masinloc 2
Philippines Subtotal
India
Coal
Philippines
Coal
Gross MW AES Equity Interest
49%
Expected Date of Commercial Operations
2H 2018
1H 2019
51%
1,320
1,320
335
335
1,655
43
The following map illustrates the location of our Asia facilities:
Asia Businesses
India
Business Description — OPGC is a 420 MW coal-fired generation facility located in the state of Odisha. OPGC
has a 30-year PPA with GRIDCO Limited, a state utility, expiring in 2026. The PPA is composed of a capacity
payment based on fixed parameters and a variable component, including a pass-through of actual fuel costs. OPGC
is an unconsolidated entity and results are reported as Net Equity in Earnings of Affiliates in our Consolidated
Statements of Operations.
Environmental Regulation — The Ministry of Environment, Forest and Climate Change in India has recently
amended the Environment (Protection) Rules with stricter emission limits for new and existing thermal power plants
via their notification issued in December 2015. All existing plants installed before December 31, 2003 are required
to meet revised emission limits within two years and any new thermal power plants that will be operational from
January 1, 2017 are required to operate with the revised emission limits. An FGD system needs to be installed in
the existing units of OPGC for complying with SO2 emissions requirements. The business has evaluated the options
and the cost implications for the operating plant including design modification and schedule implications for the
expansion project. The larger impact of these amendments and requirements of substantial investments to meet the
revised environmental guidelines across the power sector in India, borne by the public and private power generation
companies, is still under review. We believe the cost of complying with the new environmental regulations will be a
pass-through in the GRIDCO tariff for both existing and expansion units. Ministry of Power has issued a revised
Tariff Policy in January 2016 to bring more regulatory certainty, attract private investment, ensure distribution
efficiency and promote renewable energy.
Construction and Development — As noted above, AES has one coal-fired project under development with a
total capacity of 1,320 MW which is an expansion of our existing OPGC business. The project started construction
in April 2014 and is currently expected to begin operations in the second half of 2018. As of December 31, 2016,
total capitalized costs at the project level were $598 million (the Company's share is $293 million as part of our
investment in subsidiary). In addition, AES has capitalized $18 million in construction management costs which are
not attributable to the partner. Currently, 50% of the expansion capacity is contracted with the state offtaker,
GRIDCO, for a period of 25 years, with a normative after-tax rate of return of 15.5% with an opportunity to capture
additional 0.5% tied to timely completion of the project. The rest of the 50% of the generation capacity is proposed
to be offered to GRIDCO under a fresh regulated PPA due to restrictions on power sale under new guidelines.
In August 2014, the Supreme Court of India invalidated the allocation of captive coal blocks. The government
of India has subsequently enacted new laws allowing coal block allocation to companies with limited levels of
private ownership, based on which the coal blocks have been allocated to a subsidiary of OPGC, Odisha Coal and
Power Ltd., which is an OPGC joint venture with another company wholly-owned by the government of Odisha. This
new company meets the lower private ownership stipulations for allocation of mines.
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Key Financial Drivers — Financial results are likely to be driven by many factors including, but not limited to:
• Operating performance of the facility
• Regulatory and environmental policy changes
Philippines
Business Description — The Masinloc power project in the Philippines is a 630 MW gross coal-fired plant
located in Zambales, Philippines and is interconnected to the Luzon Grid, and is owned 51% by AES. More than
95% of Masinloc's current peak capacity is contracted through medium to long-term bilateral contracts primarily with
Meralco, the largest distribution company in the Philippines, several electric cooperatives and industrial customers.
In January 2013, Masinloc entered into a new PSA with its main customer, Meralco, as the previous PSA
expired in December 2012. The PSA is for seven years and included an additional three-year extension option,
which the parties agreed to exercise in March 2016. Payments are primarily capacity-based. The PSA is primarily
priced in U.S. dollars, aligning the revenues with the majority of variable and fixed costs (fuel, debt, insurance) and
minimizing currency exchange risks. Masinloc's remaining contracts on the existing units expire between 2017 and
2026.
Market Structure — The Philippine power market is divided into three grids representing the country's three
major island groups — Luzon, Visayas and Mindanao. Luzon, which includes Manila and is the country's largest
island, has limited interconnection with Visayas and represents 85% of the total demand of both regions. Luzon and
Visayas together have an installed capacity of 17,294 MW.
There is diversity in the mix of the Luzon — Visayas generation. For Luzon, coal accounts for 49% of
generation, followed by natural gas at 32%, and the remaining 19% is comprised by oil, geothermal, and renewable
resources (i.e. hydro, solar, and wind, with the latter two having priority dispatch with feed-in tariff). For Visayas,
geothermal is the top energy source and accounts for 47% of generation followed by coal at 39%, and the
remaining 14% comprised by oil, geothermal, and renewable resources.
The primary customers for electricity are private distribution utilities, electric cooperatives, and large
contestable (industrial and commercial) customers. Over 90% of the system's total energy requirement is currently
being sold/purchased through medium (three to five years) to long (six to ten years) term bilateral contracts. The
remaining energy is sold through the Wholesale Electricity Spot Market ("WESM"), which is the real-time, bid-based
and hourly market for energy where the sellers and the buyers adjust their differences between their production/
demand and their contractual commitments.
Regulatory Framework — The Philippines has divided its power sector into generation, transmission,
distribution and supply under the Electric Power Industry Reform Act of 2001. This Act primarily aims to increase
private sector participation in the power sector and to privatize the Philippine government's generation and
transmission assets. Generation and supply are open and competitive sectors, while transmission and distribution
are regulated sectors. Sale of power is conducted primarily through medium or long-term bilateral contracts
between generation companies and distribution utilities specifying the volume, price and conditions for the sale of
energy and capacity, which are approved by the ERC. Power is traded in the WESM which operates under a gross
pool, central dispatch and net settlement protocols. Parties to bilateral contracts settle their transactions outside of
the WESM and distribution companies or electricity cooperatives buy their imbalance (i.e., power requirements not
covered by bilateral contracts) from the WESM. Distribution utilities and electric cooperatives are allowed to pass on
to their end-users the bilateral contract rates, including WESM purchases, approved by the ERC.
Other Regulatory Considerations — Pursuant to Electric Power Industry Reform Act of 2001, Retail
Competition & Open Access ("RCOA") commenced on June 26, 2013, under which retail electricity suppliers, who
are duly licensed by the ERC, may supply directly to contestable customers (end-users with an average demand of
at least 1 MW), with distribution companies or electricity cooperatives providing non-discriminatory wire services. In
order to ensure implementation of RCOA and stimulate transition of contestable customers, ERC issued rules
implementing mandatory contestability. Under the said rules, all contestable customers are mandated to enter into
power supply contracts with retail electricity suppliers by February 2017 instead of purchasing power from their local
distribution utility.
Masinloc has obtained a retail electricity supplier license from the ERC and currently markets power to
contestable customers. Unlike Masinloc’s contracts with distribution utilities, its contract with contestable customers
do not require ERC approval to be implemented.
Environmental Regulation — To promote renewable energy, the Philippine government enacted the
Renewable Energy Act of 2008 which provides incentives for the development, utilization and commercialization of
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renewable energy resources such as solar, wind, small hydroelectric and biomass energies. In addition, the
government also adopted a feed-in tariff scheme which was detailed under ERC Res No.16 s. 2010, where an
eligible producer of renewable energy is entitled to a guaranteed payment of a fixed rate feed-in tariff for each
kilowatt-hour of energy it supplies to the grid. The feed-in tariff to be approved shall be specific for each emerging
renewable energy technology and shall be extended on a first-to-build basis as there is an established cap per
technology on eligibility under the feed-in tariff scheme.
Other Environmental Regulation — Over the past year, the government of the Philippines has sought to
reduce its environmental impact, including the country’s carbon footprint. As such, the Department of Environment
and Natural Resources is promoting stricter environmental compliance, particularly on the effluent discharge
standards. The new effluent standards issued in May 2016 have restricted discharge temperature limit compared to
previous standards. It is yet uncertain if the new standards will be applicable to the projects under construction
which received environmental clearance before the new standards were issued.
Construction and Development — AES started construction on a 335 MW gross Masinloc expansion project in
March 2016. The total capitalized cost at December 31, 2016 is $133 million. An engineering, procurement and
construction contract was entered into with POSCO Engineering and Construction of Korea and their wholly owned
Philippine affiliate company, Ventanas Philippine Construction Incorporated, in December 2015, with full notice to
proceed issued on March 2016. The project is expected to be commercially operating in 2019. Progress is
advancing as planned and the project is expected to be completed on schedule and within budget. The additional
capacity is targeted for sale to distribution utilities, electric cooperatives, and industrial and commercial customers in
the Luzon and Visayas grids. Approximately 50% of this additional capacity has already been contracted with an
expectation to have additional capacity contracted by the date of commercial operations.
Key Financial Drivers — Financial results are likely to be driven by many factors including, but not limited to:
• Operating performance of the facility
• Demand from contracted customers
• Whole sale electricity price in the market
Vietnam
Business Description — The Mong Duong II power project is a 1,242 MW gross coal-fired plant located in
Quang Ninh Province of Vietnam and was constructed under a BOT contract (the project will be transferred to
Vietnamese government after 25 years). AES-VCM Mong Duong Power Company Limited ("the BOT Company") is
a limited liability joint venture owned by affiliates of AES (51%), Posco Energy Corporation (30%) and China
Investment Corporation (19%). This is the first and largest coal-fired BOT project using pulverized coal fired boiler
technology in Vietnam. The BOT Company has entered a PPA with EVN, the national utility, and a Coal Supply
Agreement with Vinacomin, a state owned entity, both with a 25 year term starting from Commercial Operation
Date.
Since April 22, 2015, both units of the power facility have been in commercial operations, six months earlier
than the committed schedule with the Vietnamese government. The BOT Company makes available the
dependable capacity and delivers electrical energy to EVN and, in return, EVN makes payments to the BOT
Company.
Market Structure — The Vietnam power market is divided into three regions (North, Central and South), with
total installed capacity of approximately 41GW, an 8% increase from 2015 (38GW). The total demand in 2016 was
159.5 billion kWh with the highest demand of 76.7 billion kWh in the South and 66.5 billion kWh in the North.
The fuel mix in Vietnam is comprised of hydropower 35% (priority dispatch with low tariff), coal 36%, gas 19%,
diesel and small hydro generation 4%, oil 2% (dispatched during emergencies or during peak demand), thermo-gas
1% and the remaining 3% imported from China and Lao. The government has a plan to increase thermal power
capacity, primarily with coal, to reduce the dependence on hydroelectricity. According to the Master Plan VII revised
in March 2016, the total targeted installed capacity for 2020 is approximately 60,000 MW, in which coal-fired power
will account for 43%, hydropower and pumped storage hydropower 30%, gas-fired thermo-power 15%, renewable
energy 10%, and imported power 2%.
EVN owns 57% of installed generation capacity followed by Petro Vietnam 11%, Vinacomin 4%, BOT projects
11% and others 17%. EVN is a state-owned company that is solely in charge of buying and selling electricity all over
Vietnam. The government is planning to decrease EVN's ownership and increase private sector participation in the
power market.
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Regulatory Framework — The electricity sector is overseen by several key government entities, including the
National Assembly, the Prime Minister, the Ministry of Industry and Trade and the Electricity Regulatory Agency of
Vietnam, which is under the supervision of the Ministry of Industry and Trade. These entities are responsible for the
issuance of laws, guidance, and implementing regulations for the sector. The Ministry of Industry and Trade, in
particular, is responsible for formulating a program to restructure the power industry, develop the electricity market
and promulgating electricity market regulations. The fuel supply is owned by the government through Vinacomin
and Petro Vietnam. The government plans to equitize EVN-owned generation companies and separate generation,
System and Market Provider and distribution into three different independent operations in order to establish the
competitive power market.
Other Regulatory Considerations — According to Decision 63/2013/QD-TTG dated August 2013, the roadmap
of the power market of Vietnam consists of three phases. The first phase established a competitive electricity
market and was finished at the end of 2014. The second phase: (i) period of 2015-2016 for establishment of a pilot
competitive wholesale electricity market; and (ii) period of 2017-2021 for implementation of a competitive wholesale
electricity market. The third phase: (i) period of 2022-2023 for establishment of a pilot competitive retail electricity
market; and (ii) from 2024 onward for implementation of competitive retail electricity market. EVN, a long standing
monopoly in the whole chain of generation, transmission and distribution, is being restructured to allow spin-off of
several subsidiaries into either independent state-owned enterprises or joint stock companies. The BOT power
plants will not participate in the power market; alternatively the single buyer will bid the tariff on the power pool on
their behalf.
Environmental Regulation — Mong Duong II BOT Power Plant complies strictly with environmental
requirements involving local regulations and IFC Environmental, Health and Safety Guidelines for thermal power
plants.
Key Financial Drivers — Financial results are likely to be driven by many factors including, but not limited to
the operating performance of the facility.
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Financial Data by Country
See the table with our consolidated operations for each of the three years ended December 31, 2016, 2015
and 2014, and property, plant and equipment as of December 31, 2016 and 2015, by country, in Note 16 —
Segment and Geographic Information included in Item 8.— Financial Statements and Supplementary Data of this
Form 10-K for further information.
Environmental and Land-Use Regulations
The Company faces certain risks and uncertainties related to numerous environmental laws and regulations,
including existing and potential GHG legislation or regulations, and actual or potential laws and regulations
pertaining to water discharges, waste management (including disposal of coal combustion residuals), and certain
air emissions, such as SO2, NOX, PM, mercury and other hazardous air pollutants. Such risks and uncertainties
could result in increased capital expenditures or other compliance costs which could have a material adverse effect
on certain of our U.S. or international subsidiaries, and our consolidated results of operations. For further
information about these risks, see Item 1A.—Risk Factors—Our businesses are subject to stringent environmental
laws and regulations; Our businesses are subject to enforcement initiatives from environmental regulatory
agencies; and Regulators, politicians, non-governmental organizations and other private parties have expressed
concern about greenhouse gas, or GHG, emissions and the potential risks associated with climate change and are
taking actions which could have a material adverse impact on our consolidated results of operations, financial
condition and cash flows in this Form 10-K. For a discussion of the laws and regulations of individual countries
within each SBU where our subsidiaries operate, see discussion within Item 1.—Business of this Form 10-K under
the applicable SBUs.
Many of the countries in which the Company does business also have laws and regulations relating to the
siting, construction, permitting, ownership, operation, modification, repair and decommissioning of, and power sales
from, electric power generation or distribution assets. In addition, international projects funded by the International
Finance Corporation, the private sector lending arm of the World Bank, or many other international lenders are
subject to World Bank environmental standards or similar standards, which tend to be more stringent than local
country standards. The Company often has used advanced generation technologies in order to minimize
environmental impacts, such as CFB boilers and advanced gas turbines, and environmental control devices such
as flue gas desulphurization for SO2 emissions and selective catalytic reduction for NOx emissions.
Environmental laws and regulations affecting electric power generation and distribution facilities are complex,
change frequently and have become more stringent over time. The Company has incurred and will continue to incur
capital costs and other expenditures to comply with these environmental laws and regulations. See Item 7.—
Management's Discussion and Analysis of Financial Condition and Results of Operations—Environmental Capital
Expenditures in this Form 10-K for more detail. The Company and its subsidiaries may be required to make
significant capital or other expenditures to comply with these regulations. There can be no assurance that the
businesses operated by the subsidiaries of the Company will be able to recover any of these compliance costs from
their counterparties or customers such that the Company's consolidated results of operations, financial condition
and cash flows would not be materially affected.
Various licenses, permits and approvals are required for our operations. Failure to comply with permits or
approvals, or with environmental laws, can result in fines, penalties, capital expenditures, interruptions or changes
to our operations. Certain subsidiaries of the Company are subject to litigation or regulatory action relating to
environmental permits or approvals. See Item 3.—Legal Proceedings in this Form 10-K for more detail with respect
to environmental litigation and regulatory action.
United States Environmental and Land-Use Legislation and Regulations
In the U.S. the CAA and various state laws and regulations regulate emissions of air pollutants, including SO2,
NOX, PM, GHGs, mercury and other hazardous air pollutants. Certain applicable rules are discussed in further
detail below.
CSAPR — CSAPR addresses the "good neighbor" provision of the CAA, which prohibits sources within each
state from emitting any air pollutant in an amount which will contribute significantly to any other state’s
nonattainment, or interference with maintenance of, any NAAQS. The CSAPR requires significant reductions in SO2
and NOX emissions from power plants in many states in which subsidiaries of the Company operate. Once fully
implemented, the rule requires SO2 emission reductions of 73%, and NOX reductions of 54%, from 2005 levels. The
CSAPR is implemented, in part, through a market-based program under which compliance may be achievable
through the acquisition and use of emissions allowances created by the EPA. The CSAPR contemplates limited
interstate and unlimited intra-state trading of emissions allowances by covered sources. Initially, the EPA issued
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emissions allowances to affected power plants based on state emissions budgets established by the EPA under the
CSAPR. The Company is required to comply with the CSAPR in several states, including Ohio, Indiana, Oklahoma
and Maryland. The Company complies with CSAPR through operation of existing controls and purchases of
allowances on the open market, as needed. While the Company's 2015 CSAPR compliance costs were immaterial,
the future availability of and cost to purchase allowances to meet the emission reduction requirements is uncertain
at this time.
The EPA issued an interim final rule establishing the following deadlines for implementation of the CSAPR:
• January 1, 2015: Phase 1 (2015 and 2016) began for annual trading programs. Existing units must have begun
monitoring and reporting SO2 and NOx emissions.
• May 1, 2015: Phase 1 began for ozone-season NOx trading program. Existing units must have begun monitoring
and reporting NOx emissions.
• December 1, 2015 (and each Dec. 1 thereafter): Date by which sources must demonstrate compliance with
ozone-season NOx trading program (i.e., allowance transfer deadline).
• March 1, 2016 (and each March 1 thereafter): Date by which sources must demonstrate compliance with annual
trading programs (i.e., allowance transfer deadline).
• January 1, 2017: Phase 2 (2017 and beyond) begins for annual trading programs. Assurance provisions in
effect.
• May 1, 2017: Phase 2 (2017 and beyond) begins for ozone-season NOx trading program. Assurance provisions
in effect.
On October 26, 2016, the EPA published a final rule to update the CSAPR to address the 2008 ozone NAAQS
("CSAPR Update Rule"). The CSAPR Update Rule finds that NOx ozone season emissions in 22 states (including
Indiana, Maryland, Ohio and Oklahoma) affect the ability of downwind states to attain and maintain the 2008 ozone
NAAQS, and, accordingly, the EPA issued federal implementation plans that both updated existing CSAPR NOx ozone
season emission budgets for electric generating units within these states and implemented these budgets through
modifications to the CSAPR NOx ozone season allowance trading program. Implementation will start in the 2017 ozone
season (May-September 2017). Affected facilities will receive fewer ozone season NOx allowances in 2017 and later,
resulting in the need to purchase additional allowances. At this time, we cannot predict what the impact will be with
respect to these new standards and requirements, but it could be material if certain facilities will need to purchase
additional allowances based on reduced allocations.
MATS — Pursuant to Section 112 of the CAA, the EPA published a final rule in 2012 called the MATS
establishing National Emissions Standards for Hazardous Air Pollutants from coal and oil-fired electric utility steam
generating units. The rule required all affected power plants to comply with the applicable MATS standards by April
2015, with the possibility of obtaining a one year extension, if needed, to complete the installation of necessary
controls. All of the Company's U.S. coal-fired plants operated by the Company's subsidiaries are currently in
compliance with MATS.
There currently are challenges to the EPA’s determination that it was appropriate and necessary to regulate
hazardous air pollutant emissions from electric generating units - the basis for the MATS rule - proceeding in the
United States Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”) but, in the meantime, the
MATS rule remains in effect. We currently cannot predict the outcome of this litigation, or its impact, if any, on our
MATS compliance or ultimate costs.
New Source Review ("NSR") — The NSR requirements under the CAA impose certain requirements on major
emission sources, such as electric generating stations, if changes are made to the sources that result in a
significant increase in air emissions. Certain projects, including power plant modifications, are excluded from these
NSR requirements, if they meet the RMRR exclusion of the CAA. There is ongoing uncertainty, and significant
litigation, regarding which projects fall within the RMRR exclusion. The EPA has pursued a coordinated compliance
and enforcement strategy to address NSR compliance issues at the nation's coal-fired power plants. The strategy
has included both the filing of suits against power plant owners and the issuance of NOVs to a number of power
plant owners alleging NSR violations. See Item 3.—Legal Proceedings in this Form 10-K for more detail with
respect to environmental litigation and regulatory action, including a NOV issued by the EPA against IPL concerning
NSR and prevention of significant deterioration issues under the CAA.
In 2000, DP&L's Stuart Station received a NOV from the EPA alleging that certain activities undertaken in the
past are outside the scope of the RMRR exclusion. Hutchings Station also received such a NOV in 2009.
Additionally, generation units partially owned by DP&L but operated by other utilities have received such NOVs
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relating to equipment repairs or replacements alleged to be outside the RMRR exclusion. The NOVs issued to
DP&L-operated plants have not been pursued through litigation by the EPA.
If NSR requirements were imposed on any of the power plants owned by the Company's subsidiaries, the
results could have a material adverse impact on the Company's business, financial condition and results of
operations. In connection with the imposition of any such NSR requirements on IPL, the utility would seek recovery
of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions,
but not fines or penalties; however, there can be no assurances that they would be successful in that regard.
Regional Haze Rule — The EPA's "Regional Haze Rule" is intended to reduce haze and protect visibility in
designated federal areas, and sets guidelines for determining BART at affected plants and how to demonstrate
"reasonable progress" towards eliminating man-made haze by 2064. The Regional Haze Rule required states to
consider five factors when establishing BART for sources, including the availability of emission controls, the cost of
the controls and the effect of reducing emission on visibility in Class I areas (including wilderness areas, national
parks and similar areas). The statute requires compliance within five years after the EPA approves the relevant SIP
or issues a federal implementation plan, although individual states may impose more stringent compliance
schedules.
EPA previously determined that states included in the CSAPR would not be required to make source-specific
BART determinations for BART-affected electric generating units, reasoning that the emissions reductions required
by the CSAPR were "better than BART." Concurrently, EPA also finalized a limited disapproval of certain states'
plans — including Ohio's — that previously relied on the EPA's Clean Air Interstate Rule to improve visibility and
substituted a Federal Implementation Plan that relies on the CSAPR. Environmental groups have challenged EPA's
determination than the CSAPR is "better than BART." The challenge currently is proceeding in the D.C. Circuit.
The second phase of the Regional Haze Rule begins in 2019 and states must submit regional haze plans for
this second implementation period in 2021, to continue to demonstrate reasonable progress towards reducing
visibility impairment in Class I areas. States may need to require additional emissions controls for visibility impairing
pollutants, including on BART sources, during the second implementation period. We currently cannot predict the
impact of this second implementation period, if any, on any of our Company’s U.S. subsidiaries.
National Ambient Air Quality Standards ("NAAQS") — Under the CAA, the EPA sets NAAQS for six principal
pollutants considered harmful to public health and the environment, including ozone, particulate matter, NOx and
SO2, which result from coal combustion. Areas meeting the NAAQS are designated "attainment areas" while those
that do not meet the NAAQS are considered "nonattainment areas." Each state must develop a plan to bring
nonattainment areas into compliance with the NAAQS, which may include imposing operating limits on individual
plants. The EPA is required to review NAAQS at five-year intervals.
Based on the current and potential future ambient standards, certain of the states in which the Company's
subsidiaries operate have determined or will be required to determine whether certain areas within such states
meet the NAAQS. Some of these states may be required to modify their State Implementation Plans to detail how
the states will regain their attainment status. As part of this process, it is possible that the applicable state
environmental regulatory agency or the EPA may require reductions of emissions from our generating stations to
reach attainment status for ozone, fine particulate matter, NOx or SO2. The compliance costs of the Company's U.S.
subsidiaries could be material.
On September 30, 2015, IDEM published its final rule establishing reduced SO2 limits for IPL facilities in
accordance with a new one-hour standard of 75 parts per billion, for the areas in which IPL's Harding Street,
Petersburg, and Eagle Valley Generating Stations operate. The compliance date for these requirements was
January 1, 2017. No impact is expected for Eagle Valley or Harding Street Generating Stations because these
facilities ceased coal combustion prior to the compliance date. It is expected that improvements to the existing
FGDs at Petersburg will be required in order to comply. IPL estimates costs for compliance at Petersburg at
approximately $29 million for measures that enhance the performance and integrity of the FGDs systems. On May
31, 2016, IPL filed its SO2 NAAQS compliance plans with the IURC. IPL is seeking approval for a CPCN for these
measures at its Petersburg Generating Station. IPL expects to recover through its environmental rate adjustment
mechanism any operating or capital expenditures related to compliance with these requirements. Recovery of these
costs is sought through an Indiana statute that allows for 80% recovery of qualifying costs through a rate
adjustment mechanism, with the remainder recorded as a regulatory asset to be considered for recovery in the next
base rate case proceeding. However, there can be no assurances that IPL will be successful in that regard. In light
of the uncertainties at this time, we cannot predict the impact of these permit requirements on our consolidated
results of operations, cash flows, or financial condition, but it may be material.
Greenhouse Gas Emissions — In January 2011, the EPA began regulating GHG emissions from certain
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stationary sources under the so-called "Tailoring Rule." The regulations are being implemented pursuant to two
CAA programs: the Title V Operating Permit program and the program requiring a permit if undergoing certain new
construction or major modifications, known as the PSD. Obligations relating to Title V permits include record-
keeping and monitoring requirements. Sources subject to PSD can be required to implement BACT. In June 2014,
the U.S. Supreme Court ruled that the EPA had exceeded its statutory authority in issuing the Tailoring Rule by
regulating under the PSD program sources based solely on their GHG emissions. However, the U.S. Supreme
Court also held that the EPA could impose GHG BACT requirements for sources already required to implement
PSD for certain other pollutants. Therefore, if future modifications to our U.S.-based businesses' sources require
PSD review for other pollutants, it may trigger GHG BACT requirements. The EPA has issued guidance on what
BACT entails for the control of GHG and has now proposed NSPS for modified and reconstructed units (see below)
that will serve as a floor (maximum emission rate) for future BACT requirements. Individual states are now required
to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. The ultimate
impact of the BACT requirements applicable to us on our operations cannot be determined at this time as our U.S.-
based businesses will not be required to implement BACT until one of them constructs a new major source or
makes a major modification of an existing major source. However, the cost of compliance could be material.
On October 23, 2015, the EPA's rule establishing NSPS for new electric generating units became effective.
The NSPS establish CO2 emissions standards of 1400 lbs/MWh for newly constructed coal-fueled electric
generating plants, which reflects the partial capture and storage of CO2 emissions from the plants. The NSPS for
large, newly constructed NGCC facilities is 1,000 lbs/MWh. These standards apply to any electric generating unit
with construction commencing after January 8, 2014. The EPA also promulgated NSPS applicable to modified and
reconstructed electric generating units, which will serve as a floor for future BACT determinations for such units.
The NSPS applicable to modified and reconstructed coal-fired units will be 1,800 lbs CO2/MWh for sources with
heat input greater than 2,000 MMBtu per hour. For smaller sources, below 2,000 MMBtu per hour, the standard is
2,000 lbs CO2/MWh. The NSPS could have an impact on the Company's plans to construct and/or modify or
reconstruct electric generating units in some locations.
On December 22, 2015, the EPA's final CO2 emission rules for existing power plants under Clean Air Act
Section 111(d) (called the CPP) also became effective. The CPP provides for interim emissions performance rates
that must be achieved beginning in 2022 and final emissions performance rates that must be achieved starting in
2030. Under the CPP, states are required to meet state-wide emission rate standards or equivalent mass-based
standards, with the goal being a 32% reduction in total U.S. power sector emissions from 2005 levels by 2030. The
CPP requires states to submit, by 2016, implementation plans to meet the standards or a request for an extension
to 2018. If a state fails to develop and submit an approvable implementation plan, the EPA will finalize a federal plan
for that state. The full impact of the CPP will depend on the following:
• whether and how the states in which the Company's U.S. businesses operate respond to the CPP;
• whether the states adopt an emissions trading regime and, if so, which trading regime;
• how other states respond to the CPP, which will affect the size and robustness of any emissions trading market;
and
• how other companies may respond in the face of increased carbon costs.
Several states and industry groups challenged the NSPS for CO2 in the D.C. Circuit. Oral argument on the
challenges is scheduled for April 2017. We cannot predict at this time the likely outcome of these challenges but, if
the NSPS is vacated, it also likely would result in the invalidation of the CPP, as EPA’s authority to issue the CPP
under Section 111(d) of the Clean Air Act is triggered only be EPA’s promulgation of NSPS under Section 111(b) of
the Clean Air Act.
In addition, several states and industry groups filed petitions in the D.C. Circuit challenging the CPP and
requested a stay of the rule while the challenge was considered. The D.C. Circuit denied the stay and granted
requests to consider the challenges on an expedited basis. As a result, the D.C. Circuit may issue an opinion on
these challenges prior to the end of 2016. On February 9, 2016, the U.S. Supreme Court issued orders staying
implementation of the CPP pending resolution of challenges to the rule. The challenges have been fully briefed and
argued before the D.C. Circuit and could be decided by the court at any time. Challenges to the D.C. Circuit’s
decision could then be filed with the Supreme Court.
The Company will likely not know the answers to the above questions regarding the CPP until 2018 or later. As
the first compliance period will not end until 2025, and because we cannot predict whether the CPP will survive the
legal challenges, it is too soon to determine the CPP's potential impact on our business, operations or financial
condition, but any such impact could be material.
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Cooling Water Intake — The Company's facilities are subject to a variety of rules governing water use and
discharge. In particular, the Company's U.S. facilities are subject to the CWA Section 316(b) rule issued by the EPA
that seeks to protect fish and other aquatic organisms by requiring existing steam electric generating facilities to
utilize the BTA for cooling water intake structures. On August 15, 2014, the EPA published its final standards to
protect fish and other aquatic organisms drawn into cooling water systems at large power plants and other industrial
facilities. These standards require subject facilities that utilize at least 25% of the withdrawn water exclusively for
cooling purposes and have a design intake flow of greater than two million gallons per day to choose among seven
BTA options to reduce fish impingement. In addition, facilities that withdraw at least 125 million gallons per day for
cooling purposes must conduct studies to assist permitting authorities to determine whether and what site-specific
controls, if any, would be required to reduce entrainment of aquatic organisms. This decision-making process would
include public input as part of permit renewal or permit modification. It is possible this process could result in the
need to install closed-cycle cooling systems (closed-cycle cooling towers), or other technology. Finally, the
standards require that new units added to an existing facility to increase generation capacity are required to reduce
both impingement and entrainment that achieves one of two alternatives under national BTA standards for
entrainment. It is not yet possible to predict the total impacts of this recent final rule at this time, including any
challenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures
are necessary, they could be material.
AES Southland's current plan to comply with the California State Water Resources Board's ("SWRCB")
regulations will see all once-through-cooled ("OTC") generating units retired from service by December 31, 2020.
New air-cooled combined cycle gas turbine generators and battery energy storage systems will be constructed at
the AES Alamitos and AES Huntington Beach generating stations and the OTC generating units at the AES
Redondo Beach generating station will be retired. The execution of the Implementation Plan for compliance with the
SWRCB's OTC policy is entirely dependent on the Company's ability to execute on long-term power purchase
agreements to support project financing of the replacement generating units at AES Alamitos and AES Huntington
Beach. The SWRCB is currently reviewing the Implementation Plan and latest update information to evaluate the
impact on electrical system reliability, which could result in the extension of OTC compliance dates for specific units.
The Company’s California subsidiaries have signed 20-year term power purchase agreements with Southern
California Edison for the new generating capacity which have been approved by the California Public Utilities
Commission. Approvals and permits to construct the new generating units are pending approval by the California
Energy Commission and South Coast Air Quality Management District. Construction is scheduled to begin in June
2017 at AES Huntington Beach and July 2017 at AES Alamitos.
Power plants will be required to comply with the more stringent of state or federal requirements. At present,
the California state requirements are more stringent and have earlier compliance dates than the federal EPA
requirements, and are therefore applicable to the Company's California assets. Challenges to the federal EPA's rule
have been consolidated in the U.S. Court of Appeals for the Second Circuit, although implementation of the rule has
not been stayed while the challenges proceed. The Company anticipates once-through cooling and CWA Section
316(b) compliance regulations and costs would have a material impact on our consolidated financial condition or
results of operations.
Water Discharges — Certain of the Company's U.S.-based businesses are subject to National Pollutant
Discharge Elimination System permits that regulate specific industrial waste water and storm water discharges to
the waters of the U.S. under the CWA. On June 29, 2015, the EPA and the U.S. Army Corps of Engineers published
a final rule defining federal jurisdiction over waters of the U.S.. This rule, which became effective on August 28,
2015, may expand or otherwise change the number and types of waters or features subject to federal permitting.
On October 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order to temporarily stay the "Waters
of the U.S." rule nationwide while that court determines whether it has authority to hear the challenges to the
rule. The order was in response to challenges brought by 18 states and followed an August 2015 court decision in
the U.S. District Court of North Dakota to stay the rule in 13 other states. We cannot predict the duration of the
nationwide or partial stay of the rule or the outcome of this litigation; however, if the rule ultimately survives the legal
challenges, it could have a material impact on our business, financial condition or results of operations.
On January 7, 2013, the Ohio Environmental Protection Agency issued an NPDES permit for J.M. Stuart
Station. The primary issues involve the temperature and thermal discharges from the Station including the point at
which the water quality standards are applied, i.e., whether water quality standards apply at the point where the
Station discharge canal discharges into the Ohio River, or whether, as the EPA alleges, the discharge canal is an
extension of Little Three Mile Creek and the water quality standards apply at the point where water enters the
discharge canal. In addition, there are a number of other water-related permit requirements established with respect
to metals and other materials contained in the discharges from the Station. The NPDES permit establishes interim
standards related to the thermal discharge for 54 months that are comparable to current levels of discharge by
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Stuart Station. Permanent standards for both temperature and overall thermal discharges are established as of 55
months after the permit is effective, except that an additional transitional period of approximately 22 months is
allowed if compliance with the permanent standards is to be achieved through a plan of construction and various
milestones on the construction schedule are met. It is believed that compliance with the permit as written will
require capital expenses that will be material to DP&L. The cost of compliance and the timing of such costs is
uncertain and may vary considerably depending on a compliance plan that would need to be developed, the type of
capital projects that may be necessary, and the uncertainties that may arise in the likely event that permits and
approvals from other governmental entities would likely be required to construct and operate any such capital
project. DP&L has appealed various aspects of the final permit to the Environmental Review Appeals Commission,
although a hearing date is not currently scheduled. The compliance schedule in the final permit has been modified
to accommodate the timing of the hearing. The outcome of such appeal is uncertain.
On August 28, 2012, the IDEM issued NPDES permits to the IPL Petersburg, Harding Street and Eagle Valley
generating stations, which became effective in October 2012. NPDES permits regulate specific industrial
wastewater and storm water discharges to the waters of Indiana under Sections 402 and 405 of the U.S. Clean
Water Act. These permits set new water quality-based effluent discharge limits for the Harding Street and
Petersburg facilities, as well as monitoring and other requirements designed to protect aquatic life, with full
compliance required by October 2015. In April 2013, IPL received an extension to the compliance deadline through
September 29, 2017 for IPL's Harding Street and Petersburg facilities through agreed orders with IDEM. IPL
conducted studies to determine the operational changes and control equipment necessary to comply with the new
limitations. In October 2014, IPL filed its wastewater compliance plans for its power plants with the IURC. On July
29, 2015, the IURC approved a Certificate of Public Convenience and Necessity to convert Unit 7 at the Harding
Street Station from coal-fired to natural gas-fired (about 410 MW net capacity) at a cost of up to $71 million (the
IURC later approved IPL’s updated cost estimate for the Harding Street Station refuels including $64 million for Unit
7), and also to install and operate wastewater treatment technologies at Harding Street Station and Petersburg
Generating Station at a cost of up to $326 million. The IURC order also granted IPL authority for timely rate
recovery for 80% of the costs of these projects and authority to defer the remaining 20% as a regulatory asset to be
considered for recovery through IPL’s next basic rate case proceeding. However, there can be no assurances that
IPL will be successful in that regard.
On November 3, 2015, the EPA published its final ELG rule to reduce toxic pollutants discharged into waters of
the U.S. by power plants. These effluent limitations for existing and new sources include dry handling of fly ash,
closed-loop or dry handling of bottom ash and more stringent effluent limitations for flue gas de-sulfurization
wastewater. Compliance time lines for existing sources will be established by the applicable permitting authorities
and will be set as soon as determined possible, but no sooner than November 1, 2018 and no later than December
31, 2023. IPL plans to install a dry bottom ash handling system in response to the CCR rule described below in
advance of the ELG compliance date. As such, the impact of the ELG rule is not expected to be material. While we
are still evaluating the impacts of the final rule for DP&L, we anticipate that implementation of the requirements will
have a material adverse effect on our results of operations, financial condition and cash flows.
Selenium Rule — NPDES permits may be updated to include Selenium water quality based effluent limits
based on a site specific evaluation process which includes determining if there is a reasonable potential to exceed
the revised final Selenium water quality standards for the specific receiving water body utilizing actual and/or project
discharge information for the generating facilities. As a result, it is not yet possible to predict the total impacts of this
final rule at this time, including any challenges to such final rule and the outcome of any such challenges. However,
if additional capital expenditures are necessary, they could be material. IPL would seek recovery of these capital
expenditures; however, there is no guarantee it would be successful in this regard.
Waste Management — In the course of operations, the Company's facilities generate solid and liquid waste
materials requiring eventual disposal or processing. With the exception of coal combustion residuals ("CCR"), the
wastes are not usually physically disposed of on our property, but are shipped off site for final disposal, treatment or
recycling. CCR, which consists of bottom ash, fly ash and air pollution control wastes, is disposed of at some of our
coal-fired power generation plant sites using engineered, permitted landfills. Waste materials generated at our
electric power and distribution facilities may include asbestos, CCR, oil, scrap metal, rubbish, small quantities of
industrial hazardous wastes such as spent solvents, tree and land clearing wastes and PCB contaminated liquids
and solids. The Company endeavors to ensure that all of its solid and liquid wastes are disposed of in accordance
with applicable national, regional, state and local regulations. On October 19, 2015, an EPA rule regulating CCR
under the Resource Conservation and Recovery Act as nonhazardous solid waste became effective. The rule
established nationally applicable minimum criteria for the disposal of CCR in new and currently operating landfills
and surface impoundments, and may impose closure and/or corrective action requirements for existing CCR
landfills and impoundments under certain specified conditions. The primary enforcement mechanisms under this
53
regulation would be actions commenced by the states and private lawsuits. On December 16, 2016, President
Obama signed into law the Water Infrastructure Improvements for the Nation Act (WIN Act), which includes
provisions to implement the CCR rule through a state permitting program, or if the state chooses not to participate,
a possible federal permit program.
The existing ash ponds at IPL's Petersburg Station do not meet certain structural stability requirements set
forth in the CCR rule. As such, IPL would be required to cease use of the ash ponds by April 17, 2017. However,
IDEM has granted IPL a variance extending that deadline to April 11, 2018. In order to handle the bottom ash
material that would otherwise be sluiced to the ash ponds, IPL plans to install a dry bottom ash handling system at
an estimated cost of approximately $47 million. On May 31, 2016, IPL filed its CCR compliance plans with the
IURC. IPL is seeking approval for a CPCN to install the bottom ash dewatering system at its Petersburg generating
station. IPL expects to recover through its environmental rate adjustment mechanism any operating or capital
expenditures related to the installation of this system. Recovery of these costs is sought through an Indiana statute
that allows for 80% recovery of qualifying costs through a rate adjustment mechanism with the remainder recorded
as a regulatory asset to be considered for recovery in the next base rate case proceeding. However, there can be
no assurances that IPL will be successful in that regard. In light of the uncertainties at this time, we cannot predict
the impact of these requirements on our consolidated results of operations, cash flows, or financial condition, but it
may be material.
CERCLA — The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (aka
"Superfund") may be the source of claims against certain of the Company's U.S. subsidiaries from time to
time. There is ongoing litigation at a site known as the South Dayton Landfill where a group of companies already
recognized as potentially responsible parties have sued DP&L and other unrelated entities seeking a contribution
toward the costs of assessment and remediation. DP&L is actively opposing such claims. In 2003, DP&L received
notice that the EPA considers DP&L to be a potentially responsible party at the Tremont City landfill Superfund
site. EPA has taken no further action with respect to DP&L since 2003 regarding the Tremont City landfill. The
Company is unable to determine whether there will be any liability, or the size of any liability that may ultimately be
assessed against DP&L at these two sites, but any such liability could be material to DP&L.
Unit Retirement and Replacement Generation — In the second quarter of 2013, IPL retired in place five oil-
fired peaking units with an average life of approximately 61 years (approximately 168 MW net capacity in total), as
such units were not equipped with the advanced environmental control technologies needed to comply with existing
and expected environmental regulations. Although these units represented approximately 5% of IPL's generating
capacity, they were seldom dispatched by Midcontinent Independent System Operator, Inc. in recent years due to
their relatively higher production cost and in some instances repairs were needed. In addition to these recently
retired units, IPL has several other generating units that it expects to retire or refuel by 2017. These units are
primarily coal-fired and represent 472 MW of net capacity in total. To replace this generation, in April 2013, IPL filed
a petition and case-in-chief with the IURC in April 2013 seeking a CPCN to build a 550 to 725 MW CCGT at its
Eagle Valley Station site in Indiana and to refuel Harding Street Station Units 5 and 6 from coal to natural gas (106
MW net capacity each). In May 2014, the IURC issued an order on the CPCN authorizing the refueling project and
granting approval to build a 644 to 685 MW CCGT at a total budget of $649 million. The current estimated cost of
these projects is $632 million. IPL was granted authority to accrue post in-service allowance for debt and equity
funds used during construction and to defer the recognition of depreciation expense of the CCGT and refueling
project until such time that IPL is allowed to collect both a return and depreciation expense on the CCGT and
refueling project. The CCGT is expected to be placed into service in the first half of 2018, and the refueling project
was completed in December 2015. The costs to build and operate the CCGT and for the refueling project, other
than fuel costs, will not be recoverable by IPL through rates until the conclusion of a base rate case proceeding with
the IURC after the assets have been placed in service. For a discussion of the retirement of AES Southland's OTC
generating units due to U.S. cooling water intake regulations, please see — Cooling Water Intake, above.
International Environmental Regulations
For a discussion of the material environmental regulations applicable to the Company's businesses located
outside of the U.S., see Environmental Regulation under the discussion of the various countries in which the
Company's subsidiaries operate in Business—Our Organization and Segments, above.
Customers
We sell to a wide variety of customers. No individual customer accounted for 10% or more of our 2016 total
revenue. In our generation business, we own and/or operate power plants to generate and sell power to wholesale
customers such as utilities and other intermediaries. Our utilities sell to end-user customers in the residential,
commercial, industrial and governmental sectors in a defined service area.
54
Executive Officers
The following individuals are our executive officers:
Michael Chilton, 57 years old, was named Senior Vice President, Construction & Engineering, for the
Company in December 2014. Prior to his current role, Mr. Chilton was the Managing Director of Construction from
2009 to 2011 and Vice President, Operations Support from 2012 to 2014. Before joining AES, Mr. Chilton held
various leadership roles in Kennametal and GE, including: Regional Director for Kennametal Asia (2006-2009), with
GE as President & CEO of Xinhua Controls Solutions based in China (2005-2006), Managing Director for
Contractual Services Asia based in Singapore (2001-2005), Quality Leader for Energy Services based in Atlanta
(1999-2001), Master Black Belt for Energy Sales based in Tokyo (1998-1999) and President of Joint Conversion
company in Nuclear Energy based in Wilmington (1995-1998). Mr. Chilton has a BS in Chemical Engineering from
University of Missouri, a MBA from University of Arkansas and a JD from Kaplan University.
Bernerd Da Santos, 54 years old, was appointed Chief Operating Officer and Senior Vice President in
December 2014. Previously, Mr. Da Santos held several positions at the Company including Chief Financial Officer,
Global Finance Operations (2012-2014), Chief Financial Officer of Global Utilities (2011-2012), Chief Financial
Officer of Latin America and Africa (2009-2011), Chief Financial Officer of Latin America (2007-2009), Managing
Director of Finance for Latin America (2005-2007) and VP and Controller of EDC (Venezuela). Prior to joining AES
in 2000, Mr. Da Santos held a number of financial leadership positions at EDC. Mr. Da Santos is a member of the
Board of Directors of Companhia Brasiliana de Energia, AES Tietê, AES Eletropaulo, AES Gener, Companhia de
Alumbrado Electrico de San Salvador ("CAESS"), Empresa Electrica de Oriente ("EEO"), Companhia de Alumbrado
Electrico de Santa Ana, and Indianapolis Power & Light. Mr. Da Santos holds a Bachelor's degree with Cum Laude
distinction in Business Administration and Public Administration from Universidad José Maria Vargas, a Bachelor's
degree with Cum Laude distinction in Business Management and Finance, and an MBA with Cum Laude distinction
from Universidad José Maria Vargas.
Andrés R. Gluski, 59 years old, has been President, CEO and a member of our Board of Directors since
September 2011 and is Chairman of the Strategy and Investment Committee of the Board. Prior to assuming his
current position, Mr. Gluski served as EVP and Chief Operating Officer ("COO") of the Company since March 2007.
Prior to becoming the COO of AES, Mr. Gluski was EVP and the Regional President of Latin America from 2006 to
2007. Mr. Gluski was Senior Vice President ("SVP") for the Caribbean and Central America from 2003 to 2006,
CEO of La Electricidad de Caracas ("EDC") from 2002 to 2003 and CEO of AES Gener (Chile) in 2001. Prior to
joining AES in 2000, Mr. Gluski was EVP and Chief Financial Officer ("CFO") of EDC, EVP of Banco de Venezuela
(Grupo Santander), Vice President ("VP") for Santander Investment, and EVP and CFO of CANTV (subsidiary of
GTE). Mr. Gluski has also worked with the International Monetary Fund in the Treasury and Latin American
Departments and served as Director General of the Ministry of Finance of Venezuela. From 2013-2016, Mr. Gluski
served on President Obama's Export Council. Mr. Gluski currently serves on, the US-Brazil CEO Forum and the
US-India CEO Forum. He is a member of the Board of Waste Management and AES Gener in Chile and AES
Brasiliana in Brazil. Mr. Gluski is also Chairman of the Americas Society/Council of the Americas, and Director of
the Edison Electric Institute and the US-Philippines Society. Mr. Gluski is a magna cum laude graduate of Wake
Forest University and holds an M.A. and a Ph.D. in Economics from the University of Virginia.
Elizabeth Hackenson, 56 years old, was named Chief Information Officer ("CIO") and SVP of AES in October
2008. Prior to assuming her current position, Ms. Hackenson was the SVP and CIO at Alcatel-Lucent from 2006 to
2008, where she managed the development of technology programs for Applications, Operations and Infrastructure.
Previously, she also served as the EVP and CIO for MCI from 2004 to 2006. Her corporate tenure has spanned
several Fortune 100 companies including, British Telecom (Concert), AOL (UUNET) and EDS. She served in a
variety of senior management positions, working on the management and delivery of information technology
services to support business needs across a corporate-wide enterprise. Ms. Hackenson serves on the Boards of
DP&L and its parent company DPL, Inc. AES Cochrane and AES Chivor. She also serves as a Director on the
Greater Washington Board of Trade and Red 5 Security and is a Strategic Advisor to the Paladin Group. Ms.
Hackenson earned her degree from New York State University.
Tish Mendoza, 41 years old, is Chief Human Resources Officer and Senior Vice President, Global Human
Resources and Internal Communications. Prior to assuming her current position, Ms. Mendoza was the Vice
President of Human Resources, Global Utilities from 2011 to 2012 and Vice President of Global Compensation,
Benefits and HRIS, including Executive Compensation, from 2008 to 2011 and acted in the same capacity as the
Director of the function from 2006 to 2008. In 2015, Ms. Mendoza was appointed a member of the Boards of AES
Chivor S.A. and DP&L, and sits on AES' compensation and benefits committees. She is also currently serving as
co-chair of Evanta Global HR, and is part of its governing body in Washington, DC. Prior to joining AES, Ms.
Mendoza was Vice President of Human Resources for a product company in the Treasury Services division of JP
55
Morgan Chase and Vice President of Human Resources and Compensation and Benefits at Vastera, Inc, a former
technology and managed services company. Ms. Mendoza earned certificates in leadership and human resource
management, and a Bachelor's degree in Business Administration and Human Resources.
Brian A. Miller, 51 years old, has been EVP, General Counsel, and Corporate Secretary of the Company
since 2005. Mr. Miller is responsible for the management and operation of the company's global legal and
governance matters, stakeholder management and regulatory affairs, and ethics and compliance efforts. Mr. Miller
joined the Company in 2001 and has served in various positions including VP, Deputy General Counsel, Corporate
Secretary, Business Development, General Counsel for North America and Assistant General Counsel. He is a
member of the Board of Directors for the Business Council for International Understanding, a business association
established at President Eisenhower's initiative in 1955 to promote international understanding between
government and business executives. He also serves on the Board of the US-Kazakhstan Business Association. He
is chairman of the Boards of Directors of Dayton Power and Light, and Indianapolis Power and Light, and serves on
the Advisory Boards of AES companies in Bulgaria, the Dominican Republic and the Philippines. Previously, Brian
served on other international Boards of Directors, including AES Chivor, AES' affiliate in Colombia, from 2013
through 2015; AES Entek, a joint venture, from 2008 through July of 2014, which was created to develop
businesses in the energy sector in Turkey; and Silver Ridge, a joint venture between AES and Riverstone Holdings
LLC, from 2008 through July of 2014, which was created to develop, manage and operate solar power business in
Europe, Asia, Latin America and the United States. Prior to joining AES, he was counsel in the New York office of
the law firm Chadbourne & Parke, LLP. Mr. Miller received a Bachelor's degree in History and Economics from
Boston College and holds a Juris Doctorate from the University of Connecticut School Of Law.
Thomas M. O'Flynn, 57 years old, has served as EVP and CFO of the Company since September
2012. Previously, Mr. O'Flynn served as Senior Advisor to the Private Equity Group of Blackstone, an investment
and advisory group and held this position from 2010 to 2012. During this period, Mr. O'Flynn also served as COO
and CFO of Transmission Developers, Inc., a Blackstone-controlled company that develops innovative power
transmission projects in an environmentally responsible manner. From 2001 to 2009, he served as the CFO of
PSEG, a New Jersey-based merchant power and utility company. He also served as President of PSEG Energy
Holdings from 2007 to 2009. From 1986 to 2001, Mr. O'Flynn was in the Global Power and Utility Group of Morgan
Stanley. He served as a Managing Director for his last five years and as head of the North American Power Group
from 2000 to 2001. He was responsible for senior client relationships and led a number of large merger, financing,
restructuring and advisory transactions. Mr. O'Flynn is the chairman of the IPALCO and AES US Investments
Boards and previously served as a member of the Boards of DP&L and its parent company, DPL, Inc. Mr. O'Flynn
served on the Board of Silver Ridge Power, a joint venture between AES and Riverstone Holdings LLC from
September 2012 through July 2014. He is also currently on the Board of Directors of the New Jersey Performing
Arts Center and was the inaugural Chairman of the Institute for Sustainability and Energy at Northwestern
University, of which he is still an active Board member. Mr. O'Flynn has a BA in Economics from Northwestern
University and an MBA in Finance from the University of Chicago.
How to Contact AES and Sources of Other Information
Our principal offices are located at 4300 Wilson Boulevard, Arlington, Virginia 22203. Our telephone number is
(703) 522-1315. Our website address is http://www.aes.com. Our annual reports on Form 10-K, quarterly reports on
Form 10-Q and current reports on Form 8-K and any amendments to such reports filed pursuant to Section 13(a) or
Section 15(d) of the Securities Exchange Act of 1934 (the "Exchange Act") are posted on our website. After the
reports are filed with, or furnished to the SEC, they are available from us free of charge. Material contained on our
website is not part of and is not incorporated by reference in this Form 10-K. You may also read and copy any
materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549.
You may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-
SEC-0330. The SEC maintains an internet website that contains the reports, proxy and information statements and
other information that we file electronically with the SEC at www.sec.gov.
Our CEO and our CFO have provided certifications to the SEC as required by Section 302 of the Sarbanes-
Oxley Act of 2002. These certifications are included as exhibits to this Annual Report on Form 10-K.
Our CEO provided a certification pursuant to Section 303A of the New York Stock Exchange Listed Company
Manual on May 13, 2016.
Our Code of Business Conduct ("Code of Conduct") and Corporate Governance Guidelines have been
adopted by our Board of Directors. The Code of Conduct is intended to govern, as a requirement of employment,
the actions of everyone who works at AES, including employees of our subsidiaries and affiliates. Our Ethics and
Compliance Department provides training, information, and certification programs for AES employees related to the
56
Code of Conduct. The Ethics and Compliance Department also has programs in place to prevent and detect
criminal conduct, promote an organizational culture that encourages ethical behavior and a commitment to
compliance with the law, and to monitor and enforce AES policies on corruption, bribery, money laundering and
associations with terrorists groups. The Code of Conduct and the Corporate Governance Guidelines are located in
their entirety on our website. Any person may obtain a copy of the Code of Conduct or the Corporate Governance
Guidelines without charge by making a written request to: Corporate Secretary, The AES Corporation, 4300 Wilson
Boulevard, Arlington, VA 22203. If any amendments to, or waivers from, the Code of Conduct or the Corporate
Governance Guidelines are made, we will disclose such amendments or waivers on our website.
ITEM 1A. RISK FACTORS
You should consider carefully the following risks, along with the other information contained in or incorporated
by reference in this Form 10-K. Additional risks and uncertainties also may adversely affect our business and
operations including those discussed in Item 7.—Management's Discussion and Analysis of Financial Condition and
Results of Operations in this Form 10-K. If any of the following events actually occur, our business, financial results
and financial condition could be materially adversely affected.
We routinely encounter and address risks, some of which may cause our future results to be different,
sometimes materially different, than we presently anticipate. The categories of risk we have identified in Item 1A.—
Risk Factors of this Form 10-K include the following:
risks related to our high level of indebtedness;
risks associated with our ability to raise needed capital;
•
•
• external risks associated with revenue and earnings volatility;
•
•
risks associated with our operations; and
risks associated with governmental regulation and laws.
These risk factors should be read in conjunction with Item 7.—Management's Discussion and Analysis of
Financial Condition and Results of Operations, and the Consolidated Financial Statements and related notes
included elsewhere in this report.
Risks Related to our High Level of Indebtedness
We have a significant amount of debt, a large percentage of which is secured, which could adversely
affect our business and the ability to fulfill our obligations.
As of December 31, 2016, we had approximately $20.5 billion of outstanding indebtedness on a consolidated
basis. All outstanding borrowings, if any, under The AES Corporation's senior secured credit facility are secured by
certain of our assets, including the pledge of capital stock of many of The AES Corporation's directly held
subsidiaries. Most of the debt of The AES Corporation's subsidiaries is secured by substantially all of the assets of
those subsidiaries. Since we have such a high level of debt, a substantial portion of cash flow from operations must
be used to make payments on this debt. Furthermore, since a significant percentage of our assets are used to
secure this debt, this reduces the amount of collateral that is available for future secured debt or credit support and
reduces our flexibility in dealing with these secured assets. This high level of indebtedness and related security
could have other important consequences to us and our investors, including:
• making it more difficult to satisfy debt service and other obligations at the holding company and/or individual
subsidiaries;
•
•
•
•
increasing the likelihood of a downgrade of our debt, which could cause future debt costs and/or payments to
increase under our debt and related hedging instruments and consume an even greater portion of cash flow;
increasing our vulnerability to general adverse industry and economic conditions, including but not limited to
adverse changes in foreign exchange rates and commodity prices;
reducing the availability of cash flow to fund other corporate purposes and grow our business;
limiting our flexibility in planning for, or reacting to, changes in our business and the industry;
• placing us at a competitive disadvantage to our competitors that are not as highly leveraged; and
•
limiting, along with the financial and other restrictive covenants relating to such indebtedness, among other
things, our ability to borrow additional funds as needed or take advantage of business opportunities as they
arise, pay cash dividends or repurchase common stock.
The agreements governing our indebtedness, including the indebtedness of our subsidiaries, limit, but do not
prohibit the incurrence of additional indebtedness. To the extent we become more leveraged, the risks described
57
above would increase. Further, our actual cash requirements in the future may be greater than expected.
Accordingly, our cash flows may not be sufficient to repay at maturity all of the outstanding debt as it becomes due
and, in that event, we may not be able to borrow money, sell assets, raise equity or otherwise raise funds on
acceptable terms or at all to refinance our debt as it becomes due. See Note 11—Debt included in Item 8. of this
Form 10-K for a schedule of our debt maturities.
The AES Corporation is a holding company and its ability to make payments on its outstanding
indebtedness, including its public debt securities, is dependent upon the receipt of funds from its
subsidiaries by way of dividends, fees, interest, loans or otherwise.
The AES Corporation is a holding company with no material assets other than the stock of its subsidiaries. All
of The AES Corporation's revenue is generated through its subsidiaries. Accordingly, almost all of The AES
Corporation's cash flow is generated by the operating activities of its subsidiaries. Therefore, The AES
Corporation's ability to make payments on its indebtedness and to fund its other obligations is dependent not only
on the ability of its subsidiaries to generate cash, but also on the ability of the subsidiaries to distribute cash to it in
the form of dividends, fees, interest, tax sharing payments, loans or otherwise.
However, our subsidiaries face various restrictions in their ability to distribute cash to The AES Corporation.
Most of the subsidiaries are obligated, pursuant to loan agreements, indentures or non-recourse financing
arrangements, to satisfy certain restricted payment covenants or other conditions before they may make
distributions to The AES Corporation. In addition, the payment of dividends or the making of loans, advances or
other payments to The AES Corporation may be subject to other contractual, legal or regulatory restrictions or may
be prohibited altogether. Business performance and local accounting and tax rules may limit the amount of retained
earnings that may be distributed to us as a dividend. Subsidiaries in foreign countries may also be prevented from
distributing funds to The AES Corporation as a result of foreign governments restricting the repatriation of funds or
the conversion of currencies. Any right that The AES Corporation has to receive any assets of any of its subsidiaries
upon any liquidation, dissolution, winding up, receivership, reorganization, bankruptcy, insolvency or similar
proceedings (and the consequent right of the holders of The AES Corporation's indebtedness to participate in the
distribution of, or to realize proceeds from, those assets) will be effectively subordinated to the claims of any such
subsidiary's creditors (including trade creditors and holders of debt issued by such subsidiary).
The AES Corporation's subsidiaries are separate and distinct legal entities and, unless they have expressly
guaranteed any of The AES Corporation's indebtedness, have no obligation, contingent or otherwise, to pay any
amounts due pursuant to such debt or to make any funds available whether by dividends, fees, loans or other
payments.
Even though The AES Corporation is a holding company, existing and potential future defaults by
subsidiaries or affiliates could adversely affect The AES Corporation.
We attempt to finance our domestic and foreign projects primarily under loan agreements and related
documents which, except as noted below, require the loans to be repaid solely from the project's revenues and
provide that the repayment of the loans (and interest thereon) is secured solely by the capital stock, physical
assets, contracts and cash flow of that project subsidiary or affiliate. This type of financing is usually referred to as
non-recourse debt or "non-recourse financing." In some non-recourse financings, The AES Corporation has
explicitly agreed to undertake certain limited obligations and contingent liabilities, most of which by their terms will
only be effective or will be terminated upon the occurrence of future events. These obligations and liabilities take
the form of guarantees, indemnities, letters of credit, letter of credit reimbursement agreements and agreements to
pay, in certain circumstances, the project lenders or other parties.
As of December 31, 2016, we had approximately $20.5 billion of outstanding indebtedness on a consolidated
basis, of which approximately $4.7 billion was recourse debt of The AES Corporation and approximately $15.8
billion was non-recourse debt. In addition, we have outstanding guarantees, indemnities, letters of credit, and other
credit support commitments which are further described in this Form 10-K in Item 7.—Management's Discussion
and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Parent Company
Liquidity.
Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding
indebtedness. The total debt classified as current in our Consolidated Balance Sheets related to such defaults was
$128 million as of December 31, 2016. While the lenders under our non-recourse financings generally do not have
direct recourse to The AES Corporation (other than to the extent of any credit support given by The AES
Corporation), defaults thereunder can still have important consequences for The AES Corporation, including,
without limitation:
58
•
reducing The AES Corporation's receipt of subsidiary dividends, fees, interest payments, loans and other
sources of cash since the project subsidiary will typically be prohibited from distributing cash to The AES
Corporation during the pendency of any default;
• under certain circumstances, triggering The AES Corporation's obligation to make payments under any financial
guarantee, letter of credit or other credit support which The AES Corporation has provided to or on behalf of
such subsidiary;
• causing The AES Corporation to record a loss in the event the lender forecloses on the assets;
•
•
•
triggering defaults in The AES Corporation's outstanding debt and trust preferred securities. For example, The
AES Corporation's senior secured credit facility and outstanding senior notes include events of default for certain
bankruptcy related events involving material subsidiaries. In addition, The AES Corporation's senior secured
credit facility includes certain events of default relating to accelerations of outstanding material debt of material
subsidiaries or any subsidiaries that in the aggregate constitute a material subsidiary;
the loss or impairment of investor confidence in the Company; or
foreclosure on the assets that are pledged under the non-recourse loans, therefore eliminating any and all
potential future benefits derived from those assets.
None of the projects that are currently in default are owned by subsidiaries that individually or in the aggregate
meet the applicable standard of materiality in The AES Corporation's senior secured credit facility or other debt
agreements in order for such defaults to trigger an event of default or permit acceleration under such indebtedness.
However, as a result of future mix of distributions, write-down of assets, dispositions and other matters that affect
our financial position and results of operations, it is possible that one or more of these subsidiaries, individually or in
the aggregate, could fall within the applicable standard of materiality and thereby upon an acceleration of such
subsidiary's debt, trigger an event of default and possible acceleration of the indebtedness under The AES
Corporation's senior secured credit facility or other indebtedness of The AES Corporation.
Risks Associated with our Ability to Raise Needed Capital
The AES Corporation, or the Parent Company, has significant cash requirements and limited sources
of liquidity.
The AES Corporation requires cash primarily to fund:
interest and preferred dividends;
• principal repayments of debt;
•
• acquisitions;
• construction and other project commitments;
• other equity commitments, including business development investments;
• equity repurchases and/or cash dividends on our common stock;
•
• Parent Company overhead costs.
taxes; and
The AES Corporation's principal sources of liquidity are:
• dividends and other distributions from its subsidiaries;
• proceeds from debt and equity financings at the Parent Company level; and
• proceeds from asset sales.
For a more detailed discussion of The AES Corporation's cash requirements and sources of liquidity, please
see Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Capital
Resources and Liquidity in this Form 10-K.
While we believe that these sources will be adequate to meet our obligations at the Parent Company level for
the foreseeable future, this belief is based on a number of material assumptions, including, without limitation,
assumptions about our ability to access the capital or commercial lending markets, the operating and financial
performance of our subsidiaries, exchange rates, our ability to sell assets, and the ability of our subsidiaries to pay
dividends and other distributions. Any number of assumptions could prove to be incorrect, and, therefore there can
be no assurance that these sources will be available when needed or that our actual cash requirements will not be
greater than expected. For example, in recent years, certain financial institutions have gone bankrupt. In the event
that a bank who is party to our senior secured credit facility or other facilities goes bankrupt or is otherwise unable
59
to fund its commitments, we would need to replace that bank in our syndicate or risk a reduction in the size of the
facility, which would reduce our liquidity. In addition, our cash flow may not be sufficient to repay at maturity the
entire principal outstanding under our credit facility and our debt securities and we may have to refinance such
obligations. There can be no assurance that we will be successful in obtaining such refinancing on terms
acceptable to us or at all and any of these events could have a material effect on us.
Our ability to grow our business could be materially adversely affected if we were unable to raise
capital on favorable terms.
From time to time, we rely on access to capital markets as a source of liquidity for capital requirements not
satisfied by operating cash flows. Our ability to arrange for financing on either a recourse or non-recourse basis and
the costs of such capital are dependent on numerous factors, some of which are beyond our control, including:
• general economic and capital market conditions;
•
•
•
the availability of bank credit;
investor confidence;
the financial condition, performance and prospects of The AES Corporation in general and/or that of any
subsidiary requiring the financing as well as companies in our industry or similar financial circumstances; and
• changes in tax and securities laws which are conducive to raising capital.
Should future access to capital not be available to us, we may have to sell assets or decide not to build new
plants or expand or improve existing facilities, either of which would affect our future growth, results of operations or
financial condition.
A downgrade in the credit ratings of The AES Corporation or its subsidiaries could adversely affect
our ability to access the capital markets which could increase our interest costs or adversely affect our
liquidity and cash flow.
If any of the credit ratings of The AES Corporation or its subsidiaries were to be downgraded, our ability to
raise capital on favorable terms could be impaired and our borrowing costs could increase. Furthermore, depending
on The AES Corporation's credit ratings and the trading prices of its equity and debt securities, counterparties may
no longer be as willing to accept general unsecured commitments by The AES Corporation to provide credit
support. Accordingly, with respect to both new and existing commitments, The AES Corporation may be required to
provide some other form of assurance, such as a letter of credit and/or collateral, to backstop or replace any credit
support by The AES Corporation. There can be no assurance that such counterparties will accept such guarantees
or that AES could arrange such further assurances in the future. In addition, to the extent The AES Corporation is
required and able to provide letters of credit or other collateral to such counterparties, it will limit the amount of
credit available to The AES Corporation to meet its other liquidity needs.
We may not be able to raise sufficient capital to fund developing projects in certain less developed
economies which could change or in some cases adversely affect our growth strategy.
Part of our strategy is to grow our business by developing businesses in less developed economies where the
return on our investment may be greater than projects in more developed economies. Commercial lending
institutions sometimes refuse to provide non-recourse project financing in certain less developed economies, and in
these situations we have sought and will continue to seek direct or indirect (through credit support or guarantees)
project financing from a limited number of multilateral or bilateral international financial institutions or agencies. As a
precondition to making such project financing available, the lending institutions may also require governmental
guarantees for certain project and sovereign related risks. There can be no assurance, however, that project
financing from the international financial agencies or that governmental guarantees will be available when needed,
and if they are not, we may have to abandon the project or invest more of our own funds which may not be in line
with our investment objectives and would leave less funds for other projects.
External Risks Associated with Revenue and Earnings Volatility
Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a
result of risks associated with the wholesale electricity markets, which could have a material adverse effect
on our financial performance.
Some of our businesses sell electricity in the spot markets in cases where they operate at levels in excess of
their power sales agreements or retail load obligations. Our businesses may also buy electricity in the wholesale
spot markets. As a result, we are exposed to the risks of rising and falling prices in those markets. The open market
wholesale prices for electricity can be volatile and often reflect the fluctuating cost of fuels such as coal, natural gas
60
or oil derivative fuels in addition to other factors described below. Consequently, any changes in the supply and cost
of coal, natural gas, or oil derivative fuels may impact the open market wholesale price of electricity.
Volatility in market prices for fuel and electricity may result from among other things:
• plant availability in the markets generally;
• availability and effectiveness of transmission facilities owned and operated by third parties;
• competition;
• electricity usage;
• seasonality;
foreign exchange rate fluctuation;
•
• availability and price of emission credits;
• hydrology and other weather conditions;
•
illiquid markets;
transmission or transportation constraints or inefficiencies;
•
• availability of competitively priced renewables sources;
increased adoption of distributed generation;
•
• available supplies of natural gas, crude oil and refined products, and coal;
• generating unit performance;
• natural disasters, terrorism, wars, embargoes, and other catastrophic events;
• energy, market and environmental regulation, legislation and policies;
• geopolitical concerns affecting global supply of oil and natural gas;
• general economic conditions in areas where we operate which impact energy consumption; and
• bidding behavior and market bidding rules.
Our financial position and results of operations may fluctuate significantly due to fluctuations in
currency exchange rates experienced at our foreign operations.
Our exposure to currency exchange rate fluctuations results primarily from the translation exposure associated
with the preparation of the Consolidated Financial Statements, as well as from transaction exposure associated with
transactions in currencies other than an entity's functional currency. While the Consolidated Financial Statements
are reported in U.S. Dollars, the financial statements of many of our subsidiaries outside the U.S. are prepared
using the local currency as the functional currency and translated into U.S. Dollars by applying appropriate
exchange rates. As a result, fluctuations in the exchange rate of the U.S. Dollar relative to the local currencies
where our subsidiaries outside the U.S. report could cause significant fluctuations in our results. In addition, while
our expenses with respect to foreign operations are generally denominated in the same currency as corresponding
sales, we have transaction exposure to the extent receipts and expenditures are not denominated in the
subsidiary's functional currency. Moreover, the costs of doing business abroad may increase as a result of adverse
exchange rate fluctuations. Our financial position and results of operations could be affected by fluctuations in the
value of a number of currencies. See Item 7A.—Quantitative and Qualitative Disclosures about Market Risk to this
Form 10-K for further information.
We may not be adequately hedged against our exposure to changes in commodity prices or interest
rates.
We routinely enter into contracts to hedge a portion of our purchase and sale commitments for electricity, fuel
requirements and other commodities to lower our financial exposure related to commodity price fluctuations. As part
of this strategy, we routinely utilize fixed price or indexed forward physical purchase and sales contracts, futures,
financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. We also enter into
contracts which help us manage our interest rate exposure. However, we may not cover the entire exposure of our
assets or positions to market price or interest rate volatility, and the coverage will vary over time. Furthermore, the
risk management practices we have in place may not always perform as planned. In particular, if prices of
commodities or interest rates significantly deviate from historical prices or interest rates or if the price or interest
rate volatility or distribution of these changes deviates from historical norms, our risk management practices may
not protect us from significant losses. As a result, fluctuating commodity prices or interest rates may negatively
impact our financial results to the extent we have unhedged or inadequately hedged positions. In addition, certain
types of economic hedging activities may not qualify for hedge accounting under U.S. GAAP, resulting in increased
61
volatility in our net income. The Company may also suffer losses associated with "basis risk" which is the difference
in performance between the hedge instrument and the targeted underlying exposure. Furthermore, there is a risk
that the current counterparties to these arrangements may fail or are unable to perform part or all of their obligations
under these arrangements.
Our coal-fired facilities in the U.S. continue to face substantial challenges as a result of high coal prices
relative to natural gas, particularly those which are merchant plants that are exposed to market risk and those that
have hybrid merchant risk, meaning those businesses that have a PPA in place but purchase fuel at market prices
or under short term contracts. For our businesses with PPA pricing that does not perfectly pass through our fuel
costs, the businesses attempt to manage the exposure through flexible fuel purchasing and timing of entry and
terms of our fuel supply agreements; however, these risk management efforts may not be successful and the
resulting commodity exposure could have a material impact on these businesses and/or our results of operations.
Supplier and/or customer concentration may expose the Company to significant financial credit or
performance risks.
We often rely on a single contracted supplier or a small number of suppliers for the provision of fuel,
transportation of fuel and other services required for the operation of certain of our facilities. If these suppliers
cannot perform, we would seek to meet our fuel requirements by purchasing fuel at market prices, exposing us to
market price volatility and the risk that fuel and transportation may not be available during certain periods at any
price, which could adversely impact the profitability of the affected business and our results of operations, and could
result in a breach of agreements with other counterparties, including, without limitation, offtakers or lenders.
At times, we rely on a single customer or a few customers to purchase all or a significant portion of a facility's
output, in some cases under long-term agreements that account for a substantial percentage of the anticipated
revenue from a given facility. We have also hedged a portion of our exposure to power price fluctuations through
forward fixed price power sales. Counterparties to these agreements may breach or may be unable to perform their
obligations. We may not be able to enter into replacement agreements on terms as favorable as our existing
agreements, or at all. If we were unable to enter into replacement PPAs, these businesses may have to sell power
at market prices. A breach by a counterparty of a PPA or other agreement could also result in the breach of other
agreements, including, without limitation, the debt documents of the affected business.
The failure of any supplier or customer to fulfill its contractual obligations to The AES Corporation or our
subsidiaries could have a material adverse effect on our financial results. Consequently, the financial performance
of our facilities is dependent on the credit quality of, and continued performance by, suppliers and customers.
The market pricing of our common stock has been volatile and may continue to be volatile in future
periods.
The market price for our common stock has been volatile in the past, and the price of our common stock could
fluctuate substantially in the future. Stock price movements on a quarter-by-quarter basis for the past two years are
presented in Item 5.—Market—Market Information of this Form 10-K. Factors that could affect the price of our
common stock in the future include general conditions in our industry, in the power markets in which we participate
and in the world, including environmental and economic developments, over which we have no control, as well as
developments specific to us, including, risks that could result in revenue and earnings volatility as well as other risk
factors described in Item 1A.—Risk Factors and those matters described in Item 7.—Management's Discussion and
Analysis of Financial Conditions and Results of Operations.
Risks Associated with our Operations
We do a significant amount of business outside the U.S., including in developing countries, which
presents significant risks.
A significant amount of our revenue is generated outside the U.S. and a significant portion of our international
operations is conducted in developing countries. Part of our growth strategy is to expand our business in certain
developing countries in which AES has an existing presence as such countries may have higher growth rates and
offer greater opportunities to expand from our platforms, with potentially higher returns than in some more
developed countries. International operations, particularly the operation, financing and development of projects in
developing countries, entail significant risks and uncertainties, including, without limitation:
• economic, social and political instability in any particular country or region;
• adverse changes in currency exchange rates;
• government restrictions on converting currencies or repatriating funds;
• unexpected changes in foreign laws and regulations or in trade, monetary or fiscal policies;
62
• high inflation and monetary fluctuations;
•
•
•
restrictions on imports of coal, oil, gas or other raw materials required by our generation businesses to operate;
threatened or consummated expropriation or nationalization of our assets by foreign governments;
risks relating to the failure to comply with the U.S. Foreign Corrupt Practices Act, United Kingdom Bribery Act or
other anti-bribery laws applicable to our operations;
• difficulties in hiring, training and retaining qualified personnel, particularly finance and accounting personnel with
GAAP expertise;
• unwillingness of governments and their agencies, similar organizations or other counterparties to honor their
contracts;
• unwillingness of governments, government agencies, courts or similar bodies to enforce contracts that are
economically advantageous to subsidiaries of the Company and economically unfavorable to counterparties,
against such counterparties, whether such counterparties are governments or private parties;
inability to obtain access to fair and equitable political, regulatory, administrative and legal systems;
•
• adverse changes in government tax policy;
• difficulties in enforcing our contractual rights or enforcing judgments or obtaining a favorable result in local
jurisdictions; and
• potentially adverse tax consequences of operating in multiple jurisdictions.
Any of these factors, by itself or in combination with others, could materially and adversely affect our business,
results of operations and financial condition. Our operations may experience volatility in revenues and operating
margin which have caused and are expected to cause significant volatility in our results of operations and cash
flows. The volatility is caused by regulatory and economic difficulties, political instability and currency devaluations
being experienced in many of these countries. This volatility reduces the predictability and enhances the uncertainty
associated with cash flows from these businesses. A number of our businesses are facing challenges associated
with regulatory changes.
The operation of power generation, distribution and transmission facilities involves significant risks
that could adversely affect our financial results. We and/or our subsidiaries may not have adequate risk
mitigation and/or insurance coverage for liabilities.
We are in the business of generating and distributing electricity, which involves certain risks that can adversely
affect financial and operating performance, including:
• changes in the availability of our generation facilities or distribution systems due to increases in scheduled and
unscheduled plant outages, equipment failure, failure of transmission systems, labor disputes, disruptions in fuel
supply, poor hydrologic and wind conditions, inability to comply with regulatory or permit requirements or
catastrophic events such as fires, floods, storms, hurricanes, earthquakes, dam failures, explosions, terrorist
acts, cyber attacks or other similar occurrences; and
• changes in our operating cost structure including, but not limited to, increases in costs relating to gas, coal, oil
and other fuel; fuel transportation; purchased electricity; operations, maintenance and repair; environmental
compliance, including the cost of purchasing emissions offsets and capital expenditures to install environmental
emission equipment; transmission access; and insurance.
Our businesses require reliable transportation sources (including related infrastructure such as roads, ports
and rail), power sources and water sources to access and conduct operations. The availability and cost of this
infrastructure affects capital and operating costs and levels of production and sales. Limitations, or interruptions in
this infrastructure or at the facilities of our subsidiaries, including as a result of third parties intentionally or
unintentionally disrupting this infrastructure or the facilities of our subsidiaries, could impede their ability to produce
electricity. This could have a material adverse effect on our businesses' results of operations, financial condition and
prospects.
In addition, a portion of our generation facilities were constructed many years ago. Older generating
equipment may require significant capital expenditures for maintenance. The equipment at our plants, whether old
or new, is also likely to require periodic upgrading, improvement or repair, and replacement equipment or parts may
be difficult to obtain in circumstances where we rely on a single supplier or a small number of suppliers. The
inability to obtain replacement equipment or parts may impact the ability of our plants to perform and could,
therefore, have a material impact on our business and results of operations. Breakdown or failure of one of our
operating facilities may prevent the facility from performing under applicable power sales agreements which, in
certain situations, could result in termination of a power purchase or other agreement or incurrence of a liability for
63
liquidated damages and/or other penalties.
As a result of the above risks and other potential hazards associated with the power generation, distribution
and transmission industries, we may from time to time become exposed to significant liabilities for which we may
not have adequate risk mitigation and/or insurance coverage. Power generation involves hazardous activities,
including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering
electricity to transmission and distribution systems. In addition to natural risks, such as earthquakes, floods,
lightning, hurricanes and wind, hazards, such as fire, explosion, collapse and machinery failure, are inherent risks in
our operations which may occur as a result of inadequate internal processes, technological flaws, human error or
actions of third parties or other external events. The control and management of these risks depend upon adequate
development and training of personnel and on the existence of operational procedures, preventative maintenance
plans and specific programs supported by quality control systems which reduce, but do not eliminate, the possibility
of the occurrence and impact of these risks.
The hazards described above, along with other safety hazards associated with our operations, can cause
significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment,
contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these
events may result in our being named as a defendant in lawsuits asserting claims for substantial damages,
environmental cleanup costs, personal injury and fines and/or penalties. We maintain an amount of insurance
protection that we believe is customary, but there can be no assurance that our insurance will be sufficient or
effective under all circumstances and against all hazards or liabilities to which we may be subject. A claim for which
we are not fully insured or insured at all could hurt our financial results and materially harm our financial condition.
Further, due to the cyclical nature of the insurance markets, we cannot provide assurance that insurance coverage
will continue to be available on terms similar to those presently available to us or at all. Any losses not covered by
insurance could have a material adverse effect on our financial condition, results of operations or cash flows.
Our businesses' insurance does not cover every potential risk associated with its operations. Adequate
coverage at reasonable rates is not always obtainable. In addition, insurance may not fully cover the liability or the
consequences of any business interruptions such as equipment failure or labor dispute. The occurrence of a
significant adverse event not fully or partially covered by insurance could have a material adverse effect on the
Company's business, results or operations, financial condition and prospects.
Any of the above risks could have a material adverse effect on our business and results of operations.
We may not be able to attract and retain skilled people, which could have a material adverse effect on
our operations.
Our operating success and ability to carry out growth initiatives depends in part on our ability to retain
executives and to attract and retain additional qualified personnel who have experience in our industry and in
operating a company of our size and complexity, including people in our foreign businesses. The inability to attract
and retain qualified personnel could have a material adverse effect on our business, because of the difficulty of
promptly finding qualified replacements. For example, we routinely are required to assess the financial impacts of
complicated business transactions which occur on a worldwide basis. These assessments are dependent on hiring
personnel on a worldwide basis with sufficient expertise in U.S. GAAP to timely and accurately comply with U.S.
reporting obligations. An inability to maintain adequate internal accounting and managerial controls and hire and
retain qualified personnel could have an adverse effect on our financial and tax reporting.
We have contractual obligations to certain customers to provide full requirements service, which
makes it difficult to predict and plan for load requirements and may result in increased operating costs to
certain of our businesses.
We have contractual obligations to certain customers to supply power to satisfy all or a portion of their energy
requirements. The uncertainty regarding the amount of power that our power generation and distribution facilities
must be prepared to supply to customers may increase our operating costs. A significant under- or over-estimation
of load requirements could result in our facilities not having enough or having too much power to cover their
obligations, in which case we would be required to buy or sell power from or to third parties at prevailing market
prices. Those prices may not be favorable and thus could increase our operating costs.
We may not be able to enter into long-term contracts, which reduce volatility in our results of
operations. Even when we successfully enter into long-term contracts, our generation businesses are often
dependent on one or a limited number of customers and a limited number of fuel suppliers.
Many of our generation plants conduct business under long-term sales and supply contracts, which helps
these businesses to manage risks by reducing the volatility associated with power and input costs and providing a
64
stable revenue and cost structure. In these instances, we rely on power sales contracts with one or a limited
number of customers for the majority of, and in some cases all of, the relevant plant's output and revenues over the
term of the power sales contract. The remaining terms of the power sales contracts of our generation plants range
from one to 25 years. In many cases, we also limit our exposure to fluctuations in fuel prices by entering into long-
term contracts for fuel with a limited number of suppliers. In these instances, the cash flows and results of
operations are dependent on the continued ability of customers and suppliers to meet their obligations under the
relevant power sales contract or fuel supply contract, respectively. Some of our long-term power sales agreements
are at prices above current spot market prices and some of our long-term fuel supply contracts are at prices below
current market prices. The loss of significant power sales contracts or fuel supply contracts, or the failure by any of
the parties to such contracts that prevents us from fulfilling our obligations thereunder, could adversely impact our
strategy by resulting in costs that exceed revenue, which could have a material adverse impact on our business,
results of operations and financial condition. In addition, depending on market conditions and regulatory regimes, it
may be difficult for us to secure long-term contracts, either where our current contracts are expiring or for new
development projects. The inability to enter into long-term contracts could require many of our businesses to
purchase inputs at market prices and sell electricity into spot markets, which may not be favorable.
We have sought to reduce counterparty credit risk under our long-term contracts in part by entering into power
sales contracts with utilities or other customers of strong credit quality and by obtaining guarantees from certain
sovereign governments of the customer's obligations. However, many of our customers do not have, or have failed
to maintain, an investment-grade credit rating, and our generation business cannot always obtain government
guarantees and if they do, the government does not always have an investment grade credit rating. We have also
sought to reduce our credit risk by locating our plants in different geographic areas in order to mitigate the effects of
regional economic downturns. However, there can be no assurance that our efforts to mitigate this risk will be
successful.
Competition is increasing and could adversely affect us.
The power production markets in which we operate are characterized by numerous strong and capable
competitors, many of whom may have extensive and diversified developmental or operating experience (including
both domestic and international) and financial resources similar to or greater than ours. Further, in recent years, the
power production industry has been characterized by strong and increasing competition with respect to both
obtaining power sales agreements and acquiring existing power generation assets. In certain markets, these factors
have caused reductions in prices contained in new power sales agreements and, in many cases, have caused
higher acquisition prices for existing assets through competitive bidding practices. The evolution of competitive
electricity markets and the development of highly efficient gas-fired power plants have also caused, or are
anticipated to cause, price pressure in certain power markets where we sell or intend to sell power. These
competitive factors could have a material adverse effect on us.
Some of our subsidiaries participate in defined benefit pension plans and their net pension plan
obligations may require additional significant contributions.
Certain of our subsidiaries have defined benefit pension plans covering substantially all of their respective
employees. Of the thirty one such defined benefit plans, five are at U.S. subsidiaries and the remaining plans are at
foreign subsidiaries. Pension costs are based upon a number of actuarial assumptions, including an expected long-
term rate of return on pension plan assets, the expected life span of pension plan beneficiaries and the discount
rate used to determine the present value of future pension obligations. Any of these assumptions could prove to be
wrong, resulting in a shortfall of pension plan assets compared to pension obligations under the pension plan. The
Company periodically evaluates the value of the pension plan assets to ensure that they will be sufficient to fund the
respective pension obligations. The Company's exposure to market volatility is mitigated to some extent due to the
fact that the asset allocations in our largest plans include a significant weighting of investments in fixed income
securities that are less volatile than investments in equity securities. Future downturns in the debt and/or equity
markets, or the inaccuracy of any of our significant assumptions underlying the estimates of our subsidiaries'
pension plan obligations, could result in an increase in pension expense and future funding requirements, which
may be material. Our subsidiaries who participate in these plans are responsible for satisfying the funding
requirements required by law in their respective jurisdiction for any shortfall of pension plan assets compared to
pension obligations under the pension plan. This may necessitate additional cash contributions to the pension plans
that could adversely affect the Parent Company and our subsidiaries' liquidity.
For additional information regarding the funding position of the Company's pension plans, see Item 7.—
Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting
Policies and Estimates—Pension and Other Postretirement Plans and Note 15—Benefit Plans included in Item 8.—
Financial Statements and Supplementary Data included in this Form 10-K.
65
Our business is subject to substantial development uncertainties.
Certain of our subsidiaries and affiliates are in various stages of developing and constructing power plants,
some but not all of which have signed long-term contracts or made similar arrangements for the sale of electricity.
Successful completion depends upon overcoming substantial risks, including, but not limited to, risks relating to
siting, financing, engineering and construction, permitting, governmental approvals, commissioning delays, or the
potential for termination of the power sales contract as a result of a failure to meet certain milestones. For additional
information regarding our projects under construction see Item 1.—Business—Our Organization and Segments
included in this Form 10-K.
In certain cases, our subsidiaries may enter into obligations in the development process even though the
subsidiaries have not yet secured financing, power purchase arrangements, or other aspects of the development
process. For example, in certain cases, our subsidiaries may instruct contractors to begin the construction process
or seek to procure equipment even where they do not have financing or a power purchase agreement in place (or
conversely, to enter into a power purchase, procurement or other agreement without financing in place). If the
project does not proceed, our subsidiaries may remain obligated for certain liabilities even though the project will
not proceed. Development is inherently uncertain and we may forgo certain development opportunities and we may
undertake significant development costs before determining that we will not proceed with a particular project. We
believe that capitalized costs for projects under development are recoverable; however, there can be no assurance
that any individual project will be completed and reach commercial operation. If these development efforts are not
successful, we may abandon a project under development and write off the costs incurred in connection with such
project. At the time of abandonment, we would expense all capitalized development costs incurred in connection
therewith and could incur additional losses associated with any related contingent liabilities.
In some of our joint venture projects and businesses, we have granted protective rights to minority
shareholders or we own less than a majority of the equity in the project or business and do not manage or
otherwise control the project or business, which entails certain risks.
We have invested in some joint ventures where our subsidiaries share operational, management, investment
and/or other control rights with our joint venture partners. In many cases, we may exert influence over the joint
venture pursuant to a management contract, by holding positions on the board of the joint venture company or on
management committees and/or through certain limited governance rights, such as rights to veto significant actions.
However, we do not always have this type of influence over the project or business in every instance and we may
be dependent on our joint venture partners or the management team of the joint venture to operate, manage, invest
or otherwise control such projects or businesses. Our joint venture partners or the management team of our joint
ventures may not have the level of experience, technical expertise, human resources, management and other
attributes necessary to operate these projects or businesses optimally, and they may not share our business
priorities. In some joint venture agreements where we do have majority control of the voting securities, we have
entered into shareholder agreements granting protective minority rights to the other shareholders.
The approval of joint venture partners also may be required for us to receive distributions of funds from jointly
owned entities or to transfer our interest in projects or businesses. The control or influence exerted by our joint
venture partners may result in operational management and/or investment decisions which are different from the
decisions our subsidiaries would make if they operated independently and could impact the profitability and value of
these joint ventures. In addition, in the event that a joint venture partner becomes insolvent or bankrupt or is
otherwise unable to meet its obligations to the joint venture or its share of liabilities at the joint venture, we may be
subject to joint and several liability for these joint ventures, if and to the extent provided for in our governing
documents or applicable law.
Our renewable energy projects and other initiatives face considerable uncertainties including,
development, operational and regulatory challenges.
Wind generation, our solar projects and our investments in projects such as energy storage are subject to
substantial risks. Projects of this nature have been developed through advancement in technologies which may not
be proven or whose commercial application is limited, and which are unrelated to our core business. Some of these
business lines are dependent upon favorable regulatory incentives to support continued investment, and there is
significant uncertainty about the extent to which such favorable regulatory incentives will be available in the future.
Furthermore, production levels for our wind and solar projects may be dependent upon adequate wind or
sunlight resulting in volatility in production levels and profitability. For example, for our wind projects, wind resource
estimates are based on historical experience when available and on wind resource studies conducted by an
independent engineer, and are not expected to reflect actual wind energy production in any given year.
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As a result, these types of renewable energy projects face considerable risk relative to our core business,
including the risk that favorable regulatory regimes expire or are adversely modified. In addition, because certain of
these projects depend on technology outside of our expertise in generation and utility businesses, there are risks
associated with our ability to develop and manage such projects profitably. Furthermore, at the development or
acquisition stage, because of the nascent nature of these industries or the limited experience with the relevant
technologies, our ability to predict actual performance results may be hindered and the projects may not perform as
predicted. There are also risks associated with the fact that some of these projects exist in markets where long-term
fixed price contracts for the major cost and revenue components may be unavailable, which in turn may result in
these projects having relatively high levels of volatility. Even where available, many of our renewable projects sell
power under a Feed-in-Tariff, which may be eliminated or reduced, which can impact the profitability of these
projects, or make money through the sale of Emission Reductions products, such as Certified Emissions
Reductions, Renewable Energy Certificates or Renewable Obligation Certificates, and the price of these products
may be volatile. These projects can be capital-intensive and generally are designed with a view to obtaining third
party financing, which may be difficult to obtain. As a result, these capital constraints may reduce our ability to
develop these projects or obtain third party financing for these projects.
Impairment of goodwill or long-lived assets would negatively impact our consolidated results of
operations and net worth.
As of December 31, 2016, the Company had approximately $1.2 billion of goodwill, which represented
approximately 3.2% of the total assets on its Consolidated Balance Sheets. Goodwill is not amortized, but is
evaluated for impairment at least annually, or more frequently if impairment indicators are present. We may be
required to evaluate the potential impairment of goodwill outside of the required annual evaluation process if we
experience situations, including but not limited to: deterioration in general economic conditions, or our operating or
regulatory environment; increased competitive environment; increase in fuel costs, particularly when we are unable
to pass through the impact to customers; negative or declining cash flows; loss of a key contract or customer,
particularly when we are unable to replace it on equally favorable terms; divestiture of a significant component of
our business; or adverse actions or assessments by a regulator. These types of events and the resulting analyses
could result in goodwill impairment, which could substantially affect our results of operations for those periods.
Additionally, goodwill may be impaired if our acquisitions do not perform as expected. See the risk factor Our
acquisitions may not perform as expected for further discussion.
Long-lived assets are initially recorded at fair value and are amortized or depreciated over their estimated
useful lives. Long-lived assets are evaluated for impairment only when impairment indicators, similar to those
described above for goodwill, are present, whereas goodwill is also evaluated for impairment on an annual basis.
Certain of our businesses are sensitive to variations in weather.
Our businesses are affected by variations in general weather patterns and unusually severe weather. Our
businesses forecast electric sales on the basis of normal weather, which represents a long-term historical average.
While we also consider possible variations in normal weather patterns and potential impacts on our facilities and our
businesses, there can be no assurance that such planning can prevent these impacts, which can adversely affect
our business. Generally, demand for electricity peaks in winter and summer. Typically, when winters are warmer
than expected and summers are cooler than expected, demand for energy is lower, resulting in less demand for
electricity than forecasted. Significant variations from normal weather where our businesses are located could have
a material impact on our results of operations.
In addition, we are dependent upon hydrological conditions prevailing from time to time in the broad
geographic regions in which our hydroelectric generation facilities are located. If hydrological conditions result in
droughts or other conditions that negatively affect our hydroelectric generation business, our results of operations
could be materially adversely affected.
Information security breaches could harm our business.
A security breach of our information technology systems or plant control systems used to manage and monitor
operations could impact the reliability of our generation fleets and/or the reliability of our transmission and
distribution systems. A security breach that impairs our technology infrastructure could disrupt normal business
operations and affect our ability to control our transmission and distribution assets, access customer information
and limit our communications with third parties. Our security measures may not prevent such security breaches.
Any loss or corruption of confidential or proprietary data through a breach could impair our reputation, expose us to
legal claims, or impact our ability to make collections or otherwise impact our operations, and materially adversely
affect our business and results of operations.
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Our acquisitions may not perform as expected.
Historically, acquisitions have been a significant part of our growth strategy. We may continue to grow our
business through acquisitions. Although acquired businesses may have significant operating histories, we will have
a limited or no history of owning and operating many of these businesses and possibly limited or no experience
operating in the country or region where these businesses are located. Some of these businesses may have been
government owned and some may be operated as part of a larger integrated utility prior to their acquisition. If we
were to acquire any of these types of businesses, there can be no assurance that:
• we will be successful in transitioning them to private ownership;
• such businesses will perform as expected;
•
integration or other one-time costs will not be greater than expected;
• we will not incur unforeseen obligations or liabilities;
• such businesses will generate sufficient cash flow to support the indebtedness incurred to acquire them or the
capital expenditures needed to develop them; or
•
the rate of return from such businesses will justify our decision to invest capital to acquire them.
Risks associated with Governmental Regulation and Laws
Our operations are subject to significant government regulation and our business and results of
operations could be adversely affected by changes in the law or regulatory schemes.
Our ability to predict, influence or respond appropriately to changes in law or regulatory schemes, including
any ability to obtain expected or contracted increases in electricity tariff or contract rates or tariff adjustments for
increased expenses, could adversely impact our results of operations or our ability to meet publicly announced
projections or analysts' expectations. Furthermore, changes in laws or regulations or changes in the application or
interpretation of regulatory provisions in jurisdictions where we operate, particularly at our utilities where electricity
tariffs are subject to regulatory review or approval, could adversely affect our business, including, but not limited to:
• changes in the determination, definition or classification of costs to be included as reimbursable or pass-through
costs to be included in the rates we charge our customers, including but not limited to costs incurred to upgrade
our power plants to comply with more stringent environmental regulations;
• changes in the determination of what is an appropriate rate of return on invested capital or a determination that a
utility's operating income or the rates it charges customers are too high, resulting in a reduction of rates or
consumer rebates;
• changes in the definition or determination of controllable or non-controllable costs;
• adverse changes in tax law;
• changes in law or regulation which limit or otherwise affect the ability of our counterparties (including sovereign
or private parties) to fulfill their obligations (including payment obligations) to us or our subsidiaries;
• changes in environmental law which impose additional costs or limit the dispatch of our generating facilities
within our subsidiaries;
• changes in the definition of events which may or may not qualify as changes in economic equilibrium;
• changes in the timing of tariff increases;
• other changes in the regulatory determinations under the relevant concessions;
• other changes related to licensing or permitting which affect our ability to conduct business; or
• other changes that impact the short or long term price-setting mechanism in the markets where we operate.
Any of the above events may result in lower margins for the affected businesses, which can adversely affect
our business.
In many countries where we conduct business, the regulatory environment is constantly changing and it may
be difficult to predict the impact of the regulations on our businesses. On July 21, 2010, President Obama signed
the Dodd-Frank Act. While the bulk of regulations contained in the Dodd-Frank Act regulate financial institutions and
their products, there are several provisions related to corporate governance, executive compensation, disclosure
and other matters which relate to public companies generally. The types of provisions described above are currently
not expected to have a material impact on the Company or its results of operations. Furthermore, while the Dodd-
Frank Act substantially expands the regulation regarding the trading, clearing and reporting of derivative
transactions, the Dodd-Frank Act provides for commercial end-user exemptions which may apply to our derivative
transactions. However, even with the exemption, the Dodd-Frank Act could still have a material adverse impact on
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the Company, as the regulation of derivatives (which includes capital and margin requirements for non-exempt
companies), could limit the availability of derivative transactions that we use to reduce interest rate, commodity and
currency risks, which would increase our exposure to these risks. Even if derivative transactions remain available,
the costs to enter into these transactions may increase, which could adversely (1) affect the operating results of
certain projects; (2) cause us to default on certain types of contracts where we are contractually obligated to hedge
certain risks, such as project financing agreements; (3) prevent us from developing new projects where interest rate
hedging is required; (4) cause the Company to abandon certain of its hedging strategies and transactions, thereby
increasing our exposure to interest rate, commodity and currency risk; (5) and/or consume substantial liquidity by
forcing the Company to post cash and/or other permitted collateral in support of these derivatives. In addition to the
Dodd-Frank Act, in 2012, the EMIR became effective. EMIR includes regulations related to the trading, reporting
and clearing of derivatives and the impacts described above could also result from our (or our subsidiaries') efforts
to comply with EMIR. It is also possible that additional similar regulations may be passed in other jurisdictions
where we conduct business. Any of these outcomes could have a material adverse effect on the Company.
Our business in the United States is subject to the provisions of various laws and regulations
administered in whole or in part by the FERC and NERC, including PURPA, the Federal Power Act, and the
EPAct 2005. Actions by the FERC, NERC and by state utility commissions can have a material effect on our
operations.
EPAct 2005 authorizes the FERC to remove the obligation of electric utilities under Section 210 of PURPA to
enter into new contracts for the purchase or sale of electricity from or to QFs if certain market conditions are met.
Pursuant to this authority, the FERC has instituted a rebuttable presumption that utilities located within the control
areas of the Midwest Independent Transmission System Operator, Inc., PJM Interconnection, L.L.C., ISO New
England, Inc., the NYISO and the Electric Reliability Council of Texas, Inc. are not required to purchase or sell
power from or to QFs above a certain size. In addition, the FERC is authorized under EPAct 2005 to remove the
purchase/sale obligations of individual utilities on a case-by-case basis. While this law does not affect existing
contracts, as a result of the changes to PURPA, our QFs may face a more difficult market environment when their
current long-term contracts expire.
EPAct 2005 repealed PUHCA 1935 and enacted PUHCA 2005 in its place. PUHCA 1935 had the effect of
requiring utility holding companies to operate in geographically proximate regions and therefore limited the range of
potential combinations and mergers among utilities. By comparison, PUHCA 2005 has no such restrictions and
simply provides the FERC and state utility commissions with enhanced access to the books and records of certain
utility holding companies. The repeal of PUHCA 1935 removed barriers to mergers and other potential combinations
which could result in the creation of large, geographically dispersed utility holding companies. These entities may
have enhanced financial strength and therefore an increased ability to compete with us in the U.S. generation
market.
In accordance with Congressional mandates in the EPAct 1992 and now in EPAct 2005, the FERC has
strongly encouraged competition in wholesale electric markets. Increased competition may have the effect of
lowering our operating margins. Among other steps, the FERC has encouraged RTOs and ISOs to develop demand
response bidding programs as a mechanism for responding to peak electric demand. These programs may reduce
the value of our peaking assets which rely on very high prices during a relatively small number of hours to recover
their costs. Similarly, the FERC is encouraging the construction of new transmission infrastructure in accordance
with provisions of EPAct 2005. Although new transmission lines may increase market opportunities, they may also
increase the competition in our existing markets.
While the FERC continues to promote competition, some state utility commissions have reversed course and
begun to encourage the construction of generation facilities by traditional utilities to be paid for on a cost-of-service
basis by retail ratepayers. Such actions have the effect of reducing sale opportunities in the competitive wholesale
generating markets in which we operate.
FERC has civil penalty authority over violations of any provision of Part II of the FPA which concerns
wholesale generation or transmission, as well as any rule or order issued thereunder. FERC is authorized to assess
a maximum civil penalty of $1 million per violation for each day that the violation continues. The FPA also provides
for the assessment of criminal fines and imprisonment for violations under the FPA. This penalty authority was
enhanced in EPAct 2005. With this expanded enforcement authority, violations of the FPA and FERC's regulations
could potentially have more serious consequences than in the past.
Pursuant to EPAct 2005, the NERC has been certified by FERC as the Electric Reliability Organization
("ERO") to develop mandatory and enforceable electric system reliability standards applicable throughout the U.S.
to improve the overall reliability of the electric grid. These standards are subject to FERC review and approval.
69
Once approved, the reliability standards may be enforced by FERC independently, or, alternatively, by the ERO and
regional reliability organizations with responsibility for auditing, investigating and otherwise ensuring compliance
with reliability standards, subject to FERC oversight. Monetary penalties of up to $1 million per day per violation
may be assessed for violations of the reliability standards.
Our utility businesses in the U.S. face significant regulation by their respective state utility commissions. The
regulatory discretion is reasonably broad in both Indiana and Ohio and includes regulation as to services and
facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the
classification of accounts, rates of depreciation, the increase or decrease in retail rates and charges, the issuance
of certain securities, the acquisition and sale of some public utility properties or securities and certain other matters.
These businesses face the risk of unexpected or adverse regulatory action which could have a material adverse
effect on our results of operations, financial condition, and cash flows. See Item 1.—Business—US SBU—U.S.
Businesses—U.S. Utilities for further information on the regulation faced by our U.S. utilities.
Our businesses are subject to stringent environmental laws and regulations.
Our businesses are subject to stringent environmental laws and regulations by many federal, regional, state
and local authorities, international treaties and foreign governmental authorities. These laws and regulations
generally concern emissions into the air, effluents into the water, use of water, wetlands preservation, remediation of
contamination, waste disposal, endangered species and noise regulation, among others. Failure to comply with
such laws and regulations or to obtain or comply with any necessary environmental permits pursuant to such laws
and regulations could result in fines or other sanctions. Environmental laws and regulations affecting power
generation and distribution are complex and have tended to become more stringent over time. Congress and other
domestic and foreign governmental authorities have either considered or implemented various laws and regulations
to restrict or tax certain emissions, particularly those involving air emissions and water discharges. See the various
descriptions of these laws and regulations contained in Item 1.—Business of this Form 10-K. These laws and
regulations have imposed, and proposed laws and regulations could impose in the future, additional costs on the
operation of our power plants. We have incurred and will continue to incur significant capital and other expenditures
to comply with these and other environmental laws and regulations. Changes in, or new development of,
environmental restrictions may force the Company to incur significant expenses or expenses that may exceed our
estimates. There can be no assurance that we would be able to recover all or any increased environmental costs
from our customers or that our business, financial condition, including recorded asset values or results of
operations, would not be materially and adversely affected by such expenditures or any changes in domestic or
foreign environmental laws and regulations.
Our businesses are subject to enforcement initiatives from environmental regulatory agencies.
The EPA has pursued an enforcement initiative against coal-fired generating plants alleging wide-spread
violations of the new source review and prevention of significant deterioration provisions of the CAA. The EPA has
brought suit against a number of companies and has obtained settlements with many of these companies over such
allegations. The allegations typically involve claims that a company made major modifications to a coal-fired
generating unit without proper permit approval and without installing best available control technology. The
principal, but not exclusive, focus of this EPA enforcement initiative is emissions of SO2 and NOx. In connection with
this enforcement initiative, the EPA has imposed fines and required companies to install improved pollution control
technologies to reduce emissions of SO2 and NOx. There can be no assurance that foreign environmental
regulatory agencies in countries in which our subsidiaries operate will not pursue similar enforcement initiatives
under relevant laws and regulations.
Regulators, politicians, non-governmental organizations and other private parties have expressed
concern about greenhouse gas, or GHG, emissions and the potential risks associated with climate change
and are taking actions which could have a material adverse impact on our consolidated results of
operations, financial condition and cash flows.
As discussed in Item 1.—Business, at the international, federal and various regional and state levels, rules are
in effect and policies are under development to regulate GHG emissions, thereby effectively putting a cost on such
emissions in order to create financial incentives to reduce them. In 2016, the Company's subsidiaries operated
businesses which had total CO2 emissions of approximately 67.7 million metric tonnes, approximately 30.2 million
of which were emitted by businesses located in the U.S. (both figures ownership adjusted). The Company uses CO2
emission estimation methodologies supported by "The Greenhouse Gas Protocol" reporting standard on GHG
emissions. For existing power generation plants, CO2 emissions data are either obtained directly from plant
continuous emission monitoring systems or calculated from actual fuel heat inputs and fuel type CO2 emission
factors. The estimated annual CO2 emissions from fossil fuel electric power generation facilities of the Company's
70
subsidiaries that are in construction or development and have received the necessary air permits for commercial
operations are approximately 7.7 million metric tonnes (ownership adjusted). This overall estimate is based on a
number of projections and assumptions that may prove to be incorrect, such as the forecasted dispatch, anticipated
plant efficiency, fuel type, CO2 emissions rates and our subsidiaries' achieving completion of such construction and
development projects. However, it is certain that the projects under construction or development when completed
will increase emissions of our portfolio and therefore could increase the risks associated with regulation of GHG
emissions. Because there is significant uncertainty regarding these estimates, actual emissions from these projects
under construction or development may vary substantially from these estimates.
The non-utility, generation subsidiaries of the Company often seek to pass on any costs arising from CO2
emissions to contract counterparties, but there can be no assurance that such subsidiaries of the Company will
effectively pass such costs onto the contract counterparties or that the cost and burden associated with any dispute
over which party bears such costs would not be burdensome and costly to the relevant subsidiaries of the
Company. The utility subsidiaries of the Company may seek to pass on any costs arising from CO2 emissions to
customers, but there can be no assurance that such subsidiaries of the Company will effectively pass such costs to
the customers, or that they will be able to fully or timely recover such costs.
Foreign, federal, state or regional regulation of GHG emissions could have a material adverse impact on the
Company's financial performance. The actual impact on the Company's financial performance and the financial
performance of the Company's subsidiaries will depend on a number of factors, including among others, the degree
and timing of GHG emissions reductions required under any such legislation or regulation, the cost of emissions
reduction equipment and the price and availability of offsets, the extent to which market based compliance options
are available, the extent to which our subsidiaries would be entitled to receive GHG emissions allowances without
having to purchase them in an auction or on the open market and the impact of such legislation or regulation on the
ability of our subsidiaries to recover costs incurred through rate increases or otherwise. As a result of these factors,
our cost of compliance could be substantial and could have a material adverse impact on our results of operations.
In January 2005, based on European Community "Directive 2003/87/EC on Greenhouse Gas Emission
Allowance Trading," the EU ETS commenced operation as the largest multi-country GHG emission trading scheme
in the world. On February 16, 2005, the Kyoto Protocol became effective. The Kyoto Protocol requires all developed
countries that have ratified it to substantially reduce their GHG emissions, including CO2. However, the United
States never ratified the Kyoto Protocol and, to date, compliance with the Kyoto Protocol and the EU ETS has not
had a material adverse effect on the Company's consolidated results of operations, financial condition and cash
flows.
In December 2015, the Parties to the United Nations Framework Convention on Climate Change ("UNFCCC")
convened for the 21st Conference of the Parties in Paris, France. The result was the so-called Paris Agreement.
The Paris Agreement has a long-term goal of keeping the increase in global average temperature to well below 2°C
above pre-industrial levels. In furtherance of this goal, participating countries submitted comprehensive national
climate action plans and have agreed to meet every five years to set more ambitious targets as required by science,
to report to each other and the public on how well they are doing to implement their targets and to track progress
towards the long-term goal through a robust transparency and accountability system. We anticipate that the Paris
Agreement will continue the trend towards the efforts to de-carbonize the global economy and to further limit GHG
emissions, including in those countries where the Company does business. It is difficult to predict the nature, timing
and scope of such regulation but it could have a material adverse effect on the Company's financial performance.
In the U.S., there currently is no federal legislation imposing a mandatory GHG emission reduction programs
(including for CO2) affecting the electric power generation facilities of the Company's subsidiaries. However, the
EPA has adopted regulations pertaining to GHG emissions that require new sources of GHG emissions of over
100,000 tons per year, and existing sources planning physical changes that would increase their GHG emissions by
more than 75,000 tons per year, to obtain new source review permits from the EPA prior to construction or
modification. Additionally, the EPA has promulgated a rule establishing New Source Performance Standards for CO2
emissions for newly constructed and modified/reconstructed fossil-fueled EUSGUs larger than 25 MW. The EPA
has also promulgated a rule, the CPP, which requires existing EUSGUs to begin reducing GHG emissions starting
in 2022 with the full reduction requirement in 2030. Under the CPP, states are required to develop and submit plans
that establish performance standards or, through emissions trading programs, otherwise meet a state-wide
emissions rate average or mass-based goal. For further discussion of the regulation of GHG emission, including the
U.S. Supreme Court's issued an order staying implementation of the CPP, see Item 1.—Business—Environmental
and Land-Use Regulations—United States Environmental and Land-Use Legislation and Regulations—Greenhouse
Gas Emissions above.
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Such regulations, and in particular regulations applying to modified or existing EUSGUs, could increase our
costs directly and indirectly and have a material adverse effect on our business and/or results of operations. See
Item 1.—Business of this Form 10-K for further discussion about these environmental agreements, laws and
regulations.
At the state level, the RGGI, a cap-and-trade program covering CO2 emissions from electric power generation
facilities in the Northeast, became effective in January 2009, and California has adopted comprehensive legislation
and regulation that requires GHG reductions from multiple industrial sectors, including the electric power generation
industry. At this time, other than with regard to RGGI (further described below) and proposed Hawaii regulations
relating to the collection of fees on GHG emissions, the impact of both of which we do not expect to be material, the
Company cannot estimate the costs of compliance with U.S. federal, regional or state GHG emissions reduction
legislation or initiatives, due to the fact that most of these proposals are not being actively pursued or are in the
early stages of development and any final regulations or laws, if adopted, could vary drastically from current
proposals; in the case of California, we anticipate no material impact due to the fact that we expect such costs will
be passed through to our offtakers under the terms of existing tolling agreements.
The auctions of RGGI allowances needed by power generators to comply with state programs implementing
RGGI occur approximately every quarter. Our subsidiary in Maryland is our only subsidiary that was subject to
RGGI in 2016. Of the approximately 30.2 million metric tonnes of CO2 emitted in the United States by our
subsidiaries in 2016 (ownership adjusted), approximately 1.1 million metric tonnes were emitted by our subsidiary in
Maryland. The Company estimates that the RGGI compliance costs could be approximately $3.2 million for 2017.
There is a risk that our actual compliance costs under RGGI will differ from our estimates by a material amount and
that our model could underestimate our costs of compliance.
In addition to government regulators, other groups such as politicians, environmentalists and other private
parties have expressed increasing concern about GHG emissions. For example, certain financial institutions have
expressed concern about providing financing for facilities which would emit GHGs, which can affect our ability to
obtain capital, or if we can obtain capital, to receive it on commercially viable terms. Further, rating agencies may
decide to downgrade our credit ratings based on the emissions of the businesses operated by our subsidiaries or
increased compliance costs which could make financing unattractive. In addition, plaintiffs have brought tort
lawsuits against the Company because of its subsidiaries' GHG emissions. While the litigation mentioned has been
dismissed, it is impossible to predict whether similar future lawsuits are likely to prevail or result in damages awards
or other relief. Consequently, it is impossible to determine whether such lawsuits are likely to have a material
adverse effect on the Company's consolidated results of operations and financial condition.
Furthermore, according to the Intergovernmental Panel on Climate Change, physical risks from climate
change could include, but are not limited to, increased runoff and earlier spring peak discharge in many glacier and
snow-fed rivers, warming of lakes and rivers, an increase in sea level, changes and variability in precipitation and in
the intensity and frequency of extreme weather events. Physical impacts may have the potential to significantly
affect the Company's business and operations, and any such potential impact may render it more difficult for our
businesses to obtain financing. For example, extreme weather events could result in increased downtime and
operation and maintenance costs at the electric power generation facilities and support facilities of the Company's
subsidiaries. Variations in weather conditions, primarily temperature and humidity also would be expected to affect
the energy needs of customers. A decrease in energy consumption could decrease the revenues of the Company's
subsidiaries. In addition, while revenues would be expected to increase if the energy consumption of customers
increased, such increase could prompt the need for additional investment in generation capacity. Changes in the
temperature of lakes and rivers and changes in precipitation that result in drought could adversely affect the
operations of the fossil fuel-fired electric power generation facilities of the Company's subsidiaries. Changes in
temperature, precipitation and snow pack conditions also could affect the amount and timing of hydroelectric
generation.
In addition to potential physical risks noted by the Intergovernmental Panel on Climate Change, there could be
damage to the reputation of the Company and its subsidiaries due to public perception of GHG emissions by the
Company's subsidiaries, and any such negative public perception or concerns could ultimately result in a decreased
demand for electric power generation or distribution from our subsidiaries. The level of GHG emissions made by
subsidiaries of the Company is not a factor in the compensation of executives of the Company.
If any of the foregoing risks materialize, costs may increase or revenues may decrease and there could be a
material adverse effect on the electric power generation businesses of the Company's subsidiaries and on the
Company's consolidated results of operations, financial condition and cash flows.
72
Tax legislation initiatives or challenges to our tax positions could adversely affect our results of
operations and financial condition.
Our subsidiaries have operations in the U.S. and various non-U.S. jurisdictions. As such, we are subject to the
tax laws and regulations of the U.S. federal, state and local governments and of many non-U.S. jurisdictions. From
time to time, legislative measures may be enacted that could adversely affect our overall tax positions regarding
income or other taxes. There can be no assurance that our effective tax rate or tax payments will not be adversely
affected by these legislative measures.
For example, the U.S. is considering corporate tax reform that may significantly change corporate tax rates,
business rules such as interest deductibility and capital expenditure cost recovery, and U.S. international tax rules.
Additionally, longstanding international tax norms that determine how and where cross-border international trade is
subjected to tax are evolving. The Organization for Economic Cooperation and Development ("OECD"), in
coordination with the G8 and G20, through its Base Erosion and Profit Shifting project (“BEPS") introduced a series
of recommendations that many tax jurisdictions have adopted, or may adopt in the future, as law. As these and
other tax laws, related regulations and double-tax conventions change, our financial results could be materially
impacted. Given the unpredictability of these possible changes and their potential interdependency, it is very difficult
to assess whether the overall effect of such potential tax changes would be cumulatively positive or negative for our
earnings and cash flow, but such changes could adversely impact our results of operations.
In addition, U.S. federal, state and local, as well as non-U.S., tax laws and regulations are extremely complex
and subject to varying interpretations. There can be no assurance that our tax positions will be sustained if
challenged by relevant tax authorities and if not sustained, there could be a material impact on our results of
operations.
We and our affiliates are subject to material litigation and regulatory proceedings.
We and our affiliates are parties to material litigation and regulatory proceedings. See Item 3.—Legal
Proceedings below. There can be no assurances that the outcome of such matters will not have a material adverse
effect on our consolidated financial position.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
We maintain offices in many places around the world, generally pursuant to the provisions of long- and short-
term leases, none of which we believe are material. With a few exceptions, our facilities, which are described in
Item 1—Business of this Form 10-K, are subject to mortgages or other liens or encumbrances as part of the
project's related finance facility. In addition, the majority of our facilities are located on land that is leased. However,
in a few instances, no accompanying project financing exists for the facility, and in a few of these cases, the land
interest may not be subject to any encumbrance and is owned outright by the subsidiary or affiliate.
ITEM 3. LEGAL PROCEEDINGS
The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The
Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount
of loss can be reasonably estimated. The Company believes, based upon information it currently possesses and
taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate
outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company's financial
statements. It is reasonably possible, however, that some matters could be decided unfavorably to the Company
and could require the Company to pay damages or make expenditures in amounts that could be material but cannot
be estimated as of December 31, 2016.
In 1989, Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) filed suit in the Fifth District Court in the state of Rio
de Janeiro (“FDC”) against Eletropaulo Eletricidade de São Paulo S.A. (“EEDSP”) relating to the methodology for
calculating monetary adjustments under the parties' financing agreement. In April 1999, the FDC found in favor of
Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the FDC to collect approximately R$2.0
billion ($602 million) from Eletropaulo as estimated by Eletropaulo (or approximately R$2.6 billion ($802 million) as
of September 2016, as estimated by Eletrobrás, and possibly legal costs) and a lesser amount from an unrelated
company, Companhia de Transmissão de Energia Elétrica Paulista (“CTEEP”) (Eletropaulo and CTEEP were spun
off of EEDSP pursuant to its privatization in 1998). In November 2002, the FDC rejected Eletropaulo's defenses in
the execution suit. On appeal, the case was remanded to the FDC for further proceedings to determine whether
Eletropaulo is liable for the debt. In December 2012, the FDC issued a decision that Eletropaulo is liable for the
73
debt. However, that decision was annulled on appeal and the case was remanded to the FDC for further
proceedings. On remand at the FDC, the FDC appointed an accounting expert to analyze the issues in the case. In
September 2015, the expert issued a preliminary report concluding that Eletropaulo is liable for the debt, without
quantifying the debt. Eletropaulo thereafter submitted questions to the expert and reports rebutting the expert's
preliminary report. In April 2016, Eletrobrás requested that the expert determine both the criteria to calculate the
debt and the amount of the debt. The FDC is considering whether the criteria can be determined by the expert or
must be determined by the FDC. After that issue is resolved, the expert may issue a final report. Ultimately, a
decision will be issued by the FDC, which will be free to reject or adopt in whole or in part the expert's report. If the
FDC again determines that Eletropaulo is liable for the debt, Eletrobrás will be entitled to resume the execution suit
in the FDC. If Eletrobrás does so, Eletropaulo will be required to provide security for its alleged liability. In addition,
in February 2008, CTEEP filed a lawsuit in the FDC against Eletrobrás and Eletropaulo seeking a declaration that
CTEEP is not liable for any debt under the financing agreement. Eletropaulo believes it has meritorious defenses to
the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no
assurances that it will be successful in its efforts. If Eletrobrás requests the seizure of the security noted above and
the FDC grants such request (or if a court determines that Eletropaulo is liable for the debt), Eletropaulo's results of
operations may be materially adversely affected and, in turn, the Company's results of operations may also be
materially adversely affected. Eletropaulo and the Company could face a loss of earnings and/or cash flows and
may have to provide loans or equity to support affected businesses or projects, restructure them, write down their
value, and/or face the possibility that Eletropaulo cannot continue operations or provide returns consistent with our
expectations, any of which could have a material impact on the Company.
In September 1996, a public civil action was asserted against Eletropaulo and Associação Desportiva Cultural
Eletropaulo (the “Associação”) relating to alleged environmental damage caused by construction of the Associação
near Guarapiranga Reservoir. The initial decision that was upheld by the Appellate Court of the state of São Paulo
in 2006 found that Eletropaulo should repair the alleged environmental damage by demolishing certain construction
and reforesting the area, and either sponsor an environmental project which would cost approximately R$2 million
($614 thousand) as of December 31, 2015, or pay an indemnification amount of approximately R$15 million ($5
million). Eletropaulo has appealed this decision to the Supreme Court and the Supreme Court affirmed the decision
of the Appellate Court. Following the Supreme Court's decision, the case has been remanded to the court of first
instance for further proceedings and to monitor compliance by the defendants with the terms of the decision. In
January 2014, Eletropaulo informed the court that it intended to comply with the court's decision by donating a
green area inside a protection zone and restore watersheds, the aggregate cost of which is expected to be
approximately R$2 million ($614 thousand). Eletropaulo also requested that the court add the current owner of the
land where the Associação facilities are located, Empresa Metropolitana de Águas e Energia S.A. (“EMAE”), as a
party to the lawsuit and order EMAE to perform the demolition and reforestation aspects of the court's decision. In
July 2014, the court requested the Secretary of the Environment for the State of São Paulo to notify the court of its
opinion regarding the acceptability of the green areas to be donated by Eletropaulo to the State of São Paulo. In
January 2015, the Secretary of the Environment for the State of São Paulo notified Eletropaulo and the court that it
would not accept Eletropaulo's proposed green areas donation. Instead of such green areas donation, the
Secretary of the Environment proposed in March 2015 that Eletropaulo undertake an environmental project to offset
the alleged environmental damage. Since March 2015, Eletropaulo and the Secretary of Environment have been
working together to define an environmental project, which will be submitted for approval by the Public
Prosecutor. The cost of such project is currently estimated to be R$3 million ($1 million).
In December 2001, GRIDCO served a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act
of 1996 on the Company, AES Orissa Distribution Private Limited (“AES ODPL”), and Jyoti Structures (“Jyoti”)
pursuant to the terms of the shareholders agreement between GRIDCO, the Company, AES ODPL, Jyoti and the
Central Electricity Supply Company of Orissa Ltd. (“CESCO”), an affiliate of the Company. In the arbitration,
GRIDCO asserted that a comfort letter issued by the Company in connection with the Company's indirect
investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO's
financial obligations to GRIDCO. GRIDCO appeared to be seeking approximately $189 million in damages, plus
undisclosed penalties and interest, but a detailed alleged damage analysis was not filed by GRIDCO. The Company
counterclaimed against GRIDCO for damages. In June 2007, a 2-to-1 majority of the arbitral tribunal rendered its
award rejecting GRIDCO's claims and holding that none of the respondents, the Company, AES ODPL, or Jyoti,
had any liability to GRIDCO. The respondents' counterclaims were also rejected. A majority of the tribunal later
awarded the respondents, including the Company, some of their costs relating to the arbitration. GRIDCO filed
challenges of the tribunal's awards with the local Indian court. GRIDCO's challenge of the costs award has been
dismissed by the court, but its challenge of the liability award remains pending. The Company believes that it has
74
meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings;
however, there can be no assurances that it will be successful in its efforts.
In March 2003, the office of the Federal Public Prosecutor for the State of São Paulo, Brazil (“MPF”) notified
Eletropaulo that it had commenced an inquiry into the BNDES financings provided to AES Elpa and AES Transgás,
the rationing loan provided to Eletropaulo, changes in the control of Eletropaulo, sales of assets by Eletropaulo, and
the quality of service provided by Eletropaulo to its customers. The MPF requested various documents from
Eletropaulo relating to these matters. In July 2004, the MPF filed a public civil lawsuit in the Federal Court of São
Paulo (“FCSP”) alleging that BNDES violated Law 8429/92 (“the Administrative Misconduct Act”) and BNDES's
internal rules by: (1) approving the AES Elpa and AES Transgás loans; (2) extending the payment terms on the AES
Elpa and AES Transgás loans; (3) authorizing the sale of Eletropaulo's preferred shares at a stock-market auction;
(4) accepting Eletropaulo's preferred shares to secure the loan provided to Eletropaulo; and (5) allowing the
restructurings of Light Serviços de Eletricidade S.A. and Eletropaulo. The MPF also named AES Elpa and AES
Transgás as defendants in the lawsuit because they allegedly benefited from BNDES's alleged violations. In May
2006, the FCSP ruled that the MPF could pursue its claims based on the first, second, and fourth alleged violations
noted above. The MPF subsequently filed an interlocutory appeal with the Federal Court of Appeals (“FCA”)
seeking to require the FCSP to consider all five alleged violations. In April 2015, the FCA issued a decision holding
that the FCSP should consider all five alleged violations. AES Elpa and AES Brasiliana (the successor of AES
Transgás) have appealed the April 2015 decision to the Superior Court of Justice. The lawsuit remains pending
before the FCSP. AES Elpa and AES Brasiliana believe they have meritorious defenses to the allegations asserted
against them and will defend themselves vigorously in these proceedings; however, there can be no assurances
that they will be successful in their efforts.
Pursuant to their environmental audit, AES Sul and AES Florestal discovered 200 barrels of solid creosote
waste and other contaminants at a pole factory that AES Florestal had been operating. The conclusion of the audit
was that a prior operator of the pole factory, Companhia Estadual de Energia (“CEEE”), had been using those
contaminants to treat the poles that were manufactured at the factory. On their initiative, AES Sul and AES Florestal
communicated with Brazilian authorities and CEEE about the adoption of containment and remediation measures.
In March 2008, the State Attorney of the state of Rio Grande do Sul, Brazil filed a public civil action against AES
Sul, AES Florestal and CEEE seeking an order requiring the companies to recover the contaminated area located
on the grounds of the pole factory and an indemnity payment of approximately R$6 million ($2 million) to the state's
Environmental Fund. In October 2011, the State Attorney Office filed a request for an injunction ordering the
defendant companies to contain and remove the contamination immediately. The court granted injunctive relief on
October 18, 2011, but determined only that defendant CEEE was required to proceed with the removal work. In May
2012, CEEE began the removal work in compliance with the injunction. The removal costs are estimated to be
approximately R$60 million ($18 million) and the work was completed in February 2014. In parallel with the removal
activities, a court-appointed expert investigation took place, which was concluded in May 2014. The court-appointed
expert final report was presented to the State Attorneys in October 2014, and in January 2015 to the defendant
companies. In March 2015, AES Sul and AES Florestal submitted comments and supplementary questions
regarding the expert report. The Company believes that it has meritorious defenses to the claims asserted against it
and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful
in its efforts.
In March 2009, AES Uruguaiana Empreendimentos S.A. (“AESU”) in Brazil initiated arbitration against YPF
S.A. (“YPF”) seeking damages and other relief relating to YPF's breach of the parties' gas supply agreement
(“GSA”). Thereafter, in April 2009, YPF initiated arbitration against AESU and two unrelated parties, Companhia de
Gas do Estado do Rio Grande do Sul and Transportador de Gas del Mercosur S.A. (“TGM”), claiming that AESU
wrongfully terminated the GSA and caused the termination of a transportation agreement (“TA”) between YPF and
TGM (“YPF Arbitration”). YPF sought an unspecified amount of damages from AESU, a declaration that YPF's
performance was excused under the GSA due to certain alleged force majeure events, or, in the alternative, a
declaration that the GSA and the TA should be terminated without a finding of liability against YPF because of the
allegedly onerous obligations imposed on YPF by those agreements. In addition, in the YPF Arbitration, TGM
asserted that if AESU were found liable for terminating the GSA, AESU should also be found liable for TGM's
alleged losses, under the TA. In April 2011, the arbitrations were consolidated into a single proceeding. In May
2013, the arbitral tribunal issued an award finding YPF liable to AESU and TGM. Thereafter, in April 2016, the
tribunal issued a damages award ordering YPF to pay damages to AESU and TGM. In January 2017, AESU and
YPF settled their dispute.
In October 2009, IPL received a NOV and Finding of Violation from the EPA pursuant to the CAA Section 113
(a). The NOV alleges violations of the CAA at IPL's three primarily coal-fired electric generating facilities dating back
to 1986. The alleged violations primarily pertain to the Prevention of Significant Deterioration and nonattainment
75
New Source Review requirements under the CAA. IPL management previously met with EPA staff regarding
possible resolutions of the NOV. At this time, we cannot predict the ultimate resolution of this matter. However,
settlements and litigated outcomes of similar cases have required companies to pay civil penalties, install additional
pollution control technology on coal-fired electric generating units, retire existing generating units, and invest in
additional environmental projects. A similar outcome in this case could have a material impact to IPL and could, in
turn, have a material impact on the Company. IPL would seek recovery of any operating or capital expenditures
related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances
that it would be successful in that regard.
In June 2011, the São Paulo Municipal Tax Authority (the “Tax Authority”) filed 60 tax assessments in São
Paulo administrative court against Eletropaulo, seeking to collect services tax (“ISS”) that allegedly had not been
paid on revenues for services rendered by Eletropaulo. Eletropaulo challenged the assessments on the grounds
that the revenues at issue were not subject to ISS. In October 2013, the First Instance Administrative Court (“FIAC”)
determined that Eletropaulo was liable for ISS, interest, and related penalties totaling approximately R$3.3 billion
($1.0 billion) as estimated by Eletropaulo. Eletropaulo thereafter appealed to the Second Instance Administrative
Court (“SIAC”). In January 2016, the Tax Authority nullified most of the ISS sought from Eletropaulo.In January
2017, the SIAC issued a decision confirming the reduction and rejecting certain other amounts of ISS as time-
barred, but finding that Eletropaulo was liable for the remainder of ISS totaling approximately R$200 million ($61
million). The matter is on appeal before the Municipal Council of Taxes. Eletropaulo believes it has meritorious
defenses and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be
successful in its efforts.
In January 2012, the Brazil Federal Tax Authority issued an assessment alleging that AES Tietê had paid PIS
and COFINS taxes from 2007 to 2010 at a lower rate than the tax authority believed was applicable. AES Tietê
challenged the assessment on the grounds that the tax rate was set in the applicable legislation. In April 2013, the
FIAC determined that AES Tietê should have calculated the taxes at the higher rate and that AES Tietê was liable
for unpaid taxes, interest, and penalties totaling approximately R$960 million ($295 million) as estimated by AES
Tietê. AES Tietê appealed to the SIAC. In January 2015, the SIAC issued a decision in AES Tietê's favor, finding
that AES Tietê was not liable for unpaid taxes. The public prosecutor subsequently filed an appeal, which was
denied as untimely. The Tax Authority thereafter filed a motion for clarification of the SIAC's decision, which was
denied in September 2016. The Tax Authority later filed a special appeal, but that appeal was rejected in October
2017. The Tax Authority has filed an interlocutory appeal, which is pending. AES Tietê believes it has meritorious
defenses to the claim and will defend itself vigorously in these proceedings; however, there can be no assurances
that it will be successful in its efforts.
In January 2015, DPL received NOVs from the EPA alleging violations of opacity at Stuart and Killen Stations,
and in October 2015, IPL received a similar NOV alleging violations at Petersburg Station. In February 2016, IPL
received an NOV from the EPA alleging violations of New Source Review (“NSR”) and other CAA regulations, the
Indiana SIP, and the Title V operating permit at Petersburg Station. It is too early to determine whether the NOVs
could have a material impact on our business, financial condition or results of our operations. IPL would seek
recovery of any operating or capital expenditures, but not fines or penalties, related to air pollution control
technology to reduce regulated air emissions; however, there can be no assurances that we would be successful in
this regard.
In September 2015, AES Southland Development, LLC and AES Redondo Beach, LLC filed a lawsuit against
the California Coastal Commission (the “CCC”) over the CCC's determination that the site of AES Redondo Beach
included approximately 5.93 acres of CCC-jurisdictional wetlands. The CCC has asserted that AES Redondo Beach
has improperly installed and operated water pumps affecting the alleged wetlands in violation of the California
Coastal Act and Redondo Beach Local Coastal Program and has ordered AES Redondo Beach to restore the site.
Additional potential outcomes of the CCC determination could include an order requiring AES Redondo Beach to
fund a wetland mitigation project and/or pay fines or penalties. AES Redondo Beach believes that it has meritorious
arguments and intends to vigorously prosecute such lawsuit, but there can be no assurances that it will be
successful.
In October 2015, Ganadera Guerra, S.A. (“GG”) and Constructora Tymsa, S.A. (“CT”) filed separate lawsuits
against AES Panama in the local courts of Panama. The claimants allege that AES Panama profited from a
hydropower facility (La Estrella) being partially located on land owned initially by GG and currently by CT, and that
AES Panama must pay compensation for its use of the land. The damages sought from AES Panama are
approximately $685 million (GG) and $100 million (CT). In October 2016, the court dismissed GG's claim because
of GG's failure to comply with a court order requiring GG to disclose certain information. It is expected that GG will
refile its lawsuit. Also, there are ongoing administrative proceedings concerning whether AES Panama is entitled to
76
acquire an easement over the land and whether AES Panama can continue to occupy the land. AES Panama
believes it has meritorious defenses and claims and will assert them vigorously; however, there can be no
assurances that it will be successful in its efforts.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
77
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
PART II
Recent Sales of Unregistered Securities
None.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Stock Repurchase Program — The Board authorization permits the Company to repurchase stock through a
variety of methods, including open market repurchases and/or privately negotiated transactions. There can be no
assurances as to the amount, timing or prices of repurchases, which may vary based on market conditions and
other factors. The Program does not have an expiration date and can be modified or terminated by the Board of
Directors at any time. During the year ended December 31, 2016, the Company repurchased 8.7 million shares of
its common stock at a total cost of $79 million under the existing stock repurchase program. The cumulative
repurchase from the commencement of the Program in July 2010 through December 31, 2016 is 154.3 million
shares at a total cost of $1.9 billion, at an average price per share of $12.12 (including a nominal amount of
commissions). As of December 31, 2016, $246 million remained available for repurchase under the Program.
No repurchases were made by The AES Corporation of its common stock during the fourth quarter of 2016.
Market Information
Our common stock is traded on the NYSE under the symbol "AES." The closing price of our common stock as
reported by the NYSE on February 17, 2017, was $11.46 per share. The Company repurchased 8,686,983,
39,684,131, and 21,900,246 shares of its common stock in 2016, 2015 and 2014, respectively. The following tables
present the high and low intraday sale prices of our common stock and cash dividends declared for the indicated
periods.
Sales Price
High
2016
Low
Cash Dividends
Declared
Sales Price
High
2015
Low
Cash Dividends
Declared
$
$
11.80
12.48
13.32
12.75
$
8.22
10.49
11.85
10.98
$
0.11
—
0.11
0.23
$
13.87
14.02
13.40
11.21
$
11.53
12.64
9.42
8.76
—
0.10
0.10
0.21
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Dividends
The Company commenced a quarterly cash dividend beginning in the fourth quarter of 2012. The Company
has increased this dividend annually as displayed below.
Commencing the fourth quarter of
Cash dividend
2016
$0.12
2015
$0.11
2014
$0.10
2013
$0.05
2012
$0.04
The fourth quarter 2016 cash dividend is to be paid beginning in the first quarter of 2017. There can be no
assurance that the AES Board will declare a dividend in the future or, if declared, the amount of any dividend. Our
ability to pay dividends will also depend on receipt of dividends from our various subsidiaries across our portfolio.
Under the terms of our senior secured credit facility, which we entered into with a commercial bank syndicate,
we have limitations on our ability to pay cash dividends and/or repurchase stock. Our subsidiaries' ability to declare
and pay cash dividends to us is also subject to certain limitations contained in the project loans, governmental
provisions and other agreements to which our subsidiaries are subject. See the information contained under
Item 12.—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters—
Securities Authorized for Issuance under Equity Compensation Plans of this Form 10-K.
Holders
As of February 17, 2017, there were approximately 4,335 record holders of our common stock.
78
Performance Graph
THE AES CORPORATION
PEER GROUP INDEX/STOCK PRICE PERFORMANCE
Source: Bloomberg
We have selected the Standard and Poor's ("S&P") 500 Utilities Index as our peer group index. The S&P 500
Utilities Index is a published sector index comprising the 28 electric and gas utilities included in the S&P 500.
The five year total return chart assumes $100 invested on December 31, 2010 in AES Common Stock, the
S&P 500 Index and the S&P 500 Utilities Index. The information included under the heading Performance Graph
shall not be considered "filed" for purposes of Section 18 of the Securities Exchange Act of 1934 or incorporated by
reference in any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934.
ITEM 6. SELECTED FINANCIAL DATA
The following table presents our selected financial data as of the dates and for the periods indicated. You
should read this data together with Item 7.—Management's Discussion and Analysis of Financial Condition and
Results of Operations and the Consolidated Financial Statements and the notes thereto included in Item 8.—
Financial Statements and Supplementary Data of this Form 10-K. The selected financial data for each of the years
in the five year period ended December 31, 2016 have been derived from our audited Consolidated Financial
Statements. Prior period amounts have been restated to reflect discontinued operations in all periods presented.
Effective July 1, 2014, the Company adopted new accounting guidance on discontinued operations. Please refer to
Note 1 in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further explanation. Our
historical results are not necessarily indicative of our future results.
Acquisitions, disposals, reclassifications and changes in accounting principles affect the comparability of
information included in the tables below. Please refer to the Notes to the Consolidated Financial Statements
included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further explanation of the
effect of such activities. Please also refer to Item 1A.—Risk Factors of this Form 10-K and Note 26—Risks and
Uncertainties to the Consolidated Financial Statements included in Item 8.—Financial Statements and
Supplementary Data of this Form 10-K for certain risks and uncertainties that may cause the data reflected herein
not to be indicative of our future financial condition or results of operations.
79
SELECTED FINANCIAL DATA
Statement of Operations Data for the Years Ended December 31:
Revenue
Income (loss) from continuing operations (1)
Income (loss) from continuing operations attributable to The AES Corporation,
net of tax
Income (loss) from discontinued operations attributable to The AES Corporation,
net of tax
Net income (loss) attributable to The AES Corporation
Per Common Share Data
Basic earnings (loss) per share:
Income (loss) from continuing operations attributable to The AES Corporation,
net of tax
Income (loss) from discontinued operations attributable to The AES Corporation,
net of tax
Basic earnings (loss) per share
Diluted earnings (loss) per share:
Income (loss) from continuing operations attributable to The AES Corporation,
net of tax
Income (loss) from discontinued operations attributable to The AES Corporation,
net of tax
Diluted earnings (loss) per share
Dividends Declared Per Common Share
Cash Flow Data for the Years Ended December 31:
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by (used in) financing activities
Total (decrease) increase in cash and cash equivalents
Cash and cash equivalents, ending
Balance Sheet Data at December 31:
Total assets
Non-recourse debt (noncurrent)
Non-recourse debt (noncurrent)—Discontinued operations
Recourse debt (noncurrent)
Redeemable stock of subsidiaries
Retained earnings (accumulated deficit)
The AES Corporation stockholders' equity
_____________________________
2016
$ 13,586
361
2015
2014
(in millions, except per share amounts)
$ 16,124
1,091
$ 15,093
700
$ 14,155
787
2013
2012
$ 16,072
(518)
8
(1,138)
331
(25)
705
64
254
(1,058)
(140)
146
$ (1,130) $
306
$
769
$
114
$
(912)
$
— $
0.48
$
0.98
$
0.34
$
(1.40)
(1.72)
(0.03)
$
(1.72) $
0.45
$
0.09
1.07
(0.19)
0.19
$
0.15
$
(1.21)
$
$
$
— $
0.48
$
0.97
$
0.34
$
(1.40)
(1.71)
(0.04)
(1.71) $
0.45
0.44
0.41
$
0.09
1.06
0.25
$
(0.19)
0.15
0.17
$
0.19
(1.21)
0.08
$ 2,884
(2,108)
(747)
48
1,305
$ 2,134
(2,366)
28
(260)
1,257
$ 1,791
(656)
(1,262)
(119)
1,517
$ 2,715
(1,774)
(1,136)
(253)
1,636
$ 2,901
(895)
(1,867)
280
1,889
$ 36,119
14,489
—
4,671
782
(1,146)
2,794
$ 36,470
12,943
13
4,966
538
143
3,149
$ 38,562
13,046
257
5,047
78
512
4,272
$ 39,981
12,646
469
5,485
78
(150)
4,330
$ 41,498
11,734
636
5,883
78
(264)
4,569
(1)
Includes pretax impairment expense of $1.1 billion, $602 million, $383 million, $596 million, and $1.9 billion for the years ended December 31, 2016, 2015,
2014, 2013 and 2012, respectively. See Note 8—Other Non-Operating Expense, Note 9—Goodwill and Other Intangible Assets and Note 20—Asset
Impairment Expense included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Key Topics in Management's Discussion and Analysis
Our discussion covers the following:
• Executive Summary
• Overview of 2016 Results and Strategic Performance
• Review of Consolidated Results of Operations
• SBU Performance Analysis
• Key Trends and Uncertainties
• Capital Resources and Liquidity
Executive Summary
Consolidated Net Cash Provided by Operating Activities for the year ended December 31, 2016 was $2,884
million, an increase of $750 million compared to the year ended December 31, 2015. The increase was primarily
driven by higher collections at the Company’s distribution business in Brazil, Eletropaulo and Sul, and the
settlement of overdue receivables at Maritza in Bulgaria. These positive contributions were offset by lower margins
across the SBUs (primarily due to lower wholesale prices and lower contributions from regulated customers in the
U.S., lower contracted rates in Tietê, the prior year liability reversal in Eletropaulo and unfavorable FX in
Kazakhstan), as well as the recovery of overdue receivables in the Dominican Republic in 2015, which benefited
80
2015 results. Proportional Free Cash Flow (a non-GAAP financial measure) for the year ended December 31, 2016
increased $176 million to $1,417 million compared to the year ended December 31, 2015, primarily due to the same
factors as Consolidated Net Cash Provided by Operating Activities.
Overview of 2016 Results
Earnings Per Share and Proportional Free Cash Flow Results in 2016 (in millions, except per share amounts)
Years Ended December 31,
Diluted earnings per share from continuing operations
Adjusted earnings per share (a non-GAAP measure) (1)
Net cash provided by operating activities
Proportional Free Cash Flow (a non-GAAP measure) (1) (2)
_____________________________
2016
2015
2014
$
— $
0.98
2,884
1,417
$
0.48
1.25
2,134
1,241
0.97
1.18
1,791
891
(1)
(2)
See reconciliation and definition under SBU Performance Analysis—Non-GAAP Measures.
Disclosure of Proportional Free Cash Flow will be discontinued beginning in the first quarter of 2017. See further discussion under SBU Performance Analysis
—Non-GAAP Measures.
Diluted earnings per share from continuing operations decreased primarily due to higher impairment expense
on long lived assets, lower gains on foreign currency derivatives, lower operating margins at our US, Brazil and
Europe SBUs, and lower equity in earnings of affiliates due to the gain earned in 2015 from the restructuring of
Guacolda; partially offset by a lower effective tax rate, the absence of goodwill impairment expense in the current
year, lower losses on extinguishment of debt and lower share count.
Adjusted EPS, a non-GAAP measure, decreased by 22% to $0.98 primarily driven by lower operating margins
at our US, Brazil, and Europe SBUs, lower equity in earnings of affiliates due to the gain earned in 2015 from the
restructuring of Guacolda; partially offset by a lower adjusted effective tax rate and lower share count.
Net cash provided by operating activities increased by 35% to $2.9 billion primarily driven by an increase in
collections at our Brazil utilities, the collection of overdue receivables at Maritza, and lower costs associated with
the fulfillment of our service concession arrangement and lower working capital requirements at Mong Duong.
These positive impacts were partially offset by the timing of payments at our Brazil utilities for higher energy
purchases made in the prior year, collections of overdue receivables in the prior year in the Dominican Republic,
and lower net income adjusted for non-cash items.
Proportional free cash flow, a non-GAAP measure, increased by 14% to $1.4 billion primarily driven by an
increase in collections at our Brazil utilities, the collection of overdue receivables at Maritza, and lower working
capital requirements at Mong Duong. These positive impacts were partially offset by the timing of payments at our
Brazil utilities for higher energy purchases made in the prior year, collections of overdue receivables in the prior
year in the Dominican Republic, and a decrease in Adjusted Operating Margin (a non-GAAP measure).
81
Review of Consolidated Results of Operations
Years Ended December 31,
(in millions, except per share amounts)
Revenue:
US SBU
Andes SBU
Brazil SBU
MCAC SBU
Europe SBU
Asia SBU
Corporate and Other
Intersegment eliminations
Total Revenue
Operating Margin:
US SBU
Andes SBU
Brazil SBU
MCAC SBU
Europe SBU
Asia SBU
Corporate and Other
Intersegment eliminations
Total Operating Margin
General and administrative expenses
Interest expense
Interest income
Loss on extinguishment of debt
Other expense
Other income
Gain on disposal and sale of businesses
Goodwill impairment expense
Asset impairment expense
Foreign currency transaction gains (losses)
Other non-operating expense
Income tax benefit (expense)
Net equity in earnings of affiliates
INCOME FROM CONTINUING OPERATIONS
Income (loss) from operations of discontinued businesses
Net loss from disposal and impairments of discontinued operations
NET INCOME (LOSS)
Noncontrolling interests:
(Income) from continuing operations attributable to noncontrolling interests
Net loss attributable to redeemable stocks of subsidiaries
Loss from discontinued operations attributable to noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON
STOCKHOLDERS:
Income from continuing operations, net of tax
Income (loss) from discontinued operations, net of tax
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION
Net cash provided by operating activities
DIVIDENDS DECLARED PER COMMON SHARE
_____________________________
NM — Not meaningful
2016
2015
2014
% Change 2016
vs. 2015
% Change 2015
vs. 2014
$
3,429
2,506
3,755
2,172
918
752
77
(23)
13,586
$
3,593
2,489
3,858
2,353
1,191
684
31
(44)
14,155
$
3,826
2,642
4,987
2,682
1,439
558
15
(25)
16,124
582
634
239
523
259
170
15
11
2,433
(194)
(1,431)
464
(13)
(103)
65
29
—
(1,096)
(15)
(2)
188
36
361
(19)
(1,119)
(777)
(364)
11
—
$ (1,130) $
$
$
8
(1,138)
$ (1,130) $
$
2,884
$
$
0.45
$
621
618
592
543
303
149
33
(1)
2,858
(196)
(1,344)
460
(182)
(58)
82
29
(317)
(285)
107
—
(472)
105
787
(25)
—
762
(456)
—
—
306
331
(25)
306
2,134
0.41
$
$
$
$
$
699
587
634
541
403
76
53
(13)
2,980
(187)
(1,451)
320
(261)
(65)
121
358
(164)
(91)
11
(128)
(371)
19
1,091
111
(55)
1,147
(386)
—
8
769
705
64
769
1,791
0.25
-5%
1%
-3%
-8%
-23%
10%
NM
48%
-4%
-6%
3%
-60%
-4%
-15%
14%
-55%
NM
-15%
-1%
6%
1%
-93%
78%
-21%
—%
NM
NM
NM
NM
NM
-66%
-54%
-24%
NM
NM
-20%
NM
NM
NM
-98%
NM
NM
35%
10%
-6%
-6%
-23%
-12%
-17%
23%
NM
-76%
-12%
-11%
5%
-7%
—%
-25%
96%
-38%
92%
-4%
5%
-7%
44%
-30%
-11%
-32%
-92%
93%
NM
NM
NM
27%
NM
-28%
NM
NM
-34%
18%
NM
NM
-60%
-53%
NM
-60%
19%
64%
Components of Revenue, Cost of Sales and Operating Margin — Revenue includes revenue earned from the
sale of energy from our utilities and the production of energy from our generation plants, which are classified as
regulated and non-regulated, respectively, on the Consolidated Statements of Operations. Revenue also includes
the gains or losses on derivatives associated with the sale of electricity.
Cost of sales includes costs incurred directly by the businesses in the ordinary course of business. Examples
include electricity and fuel purchases, operations & maintenance costs, depreciation and amortization expense, bad
debt expense and recoveries, and general administrative and support costs (including employee-related costs
directly associated with the operations of the business). Cost of sales also includes the gains or losses on
derivatives (including embedded derivatives other than foreign currency embedded derivatives) associated with the
purchase of electricity or fuel.
Operating margin is defined as revenue less cost of sales.
82
Consolidated Revenue and Operating Margin
(in millions)
Year Ended December 31, 2016
Consolidated Revenue — Revenue decreased in 2016 compared to 2015 primarily due to:
• Unfavorable FX impacts of $511 million, primarily in Brazil of $213 million, Argentina of $94 million, Kazakhstan
of $63 million and Colombia of $54 million.
• Brazil due to lower rates for energy sold in Brazil under new contracts at Tietê; operations in 2015 but not in
2016 at Uruguiana; the reversal of a contingent regulatory liability in 2015, and lower demand, partially offset by
the annual tariff adjustment at Eletropaulo.
• Lower pass-through costs at El Salvador and IPP4 in Jordan, the sale of DPLER in January 2016, and lower
rates at DPL.
These decreases were partially offset by:
• The full operations at Mong Duong in 2016 compared to Unit 1 in March 2015 with principal operations
commencing in April 2015
• The commencement of operations at Cochrane in Chile with Unit 1 operational in July 2016 and principal
operations in October).
• Higher environmental returns and new rate case at IPL.
Consolidated Operating Margin — Operating margin decreased in 2016 compared to 2015 primarily due to:
• Unfavorable FX impacts of $80 million, primarily in Kazakhstan, Argentina, and Colombia.
• Brazil driven by the revenue drivers above as well as higher fixed costs at Eletropaulo.
These decreases were partially offset by:
• Higher margin at Gener, impact from full operations at Mong Duong in Vietnam and Cochrane in Chile, and
higher margins at IPL as discussed above.
Year Ended December 31, 2015
Consolidated Revenue — Revenue decreased in 2015 compared to 2014 primarily due to:
• Unfavorable FX impacts of $2.2 billion, mainly in Brazil of $1.8 billion, Colombia of $179 million, and Bulgaria of
$74 million.
• US Utilities due to lower volumes primarily at DPL and outages, milder weather, and lower demand at IPL.
• Lower prices in the Dominican Republic and El Salvador (primarily resulting from lower pass-through costs).
These decreases were partially offset by:
• Brazil due to higher tariffs at Eletropaulo (including higher pass-through costs) and the reversal of a contingent
regulatory liability at Eletropaulo.
• Higher capacity prices at DPL.
• Commencement of principal operations at Mong Duong in April 2015.
83
Consolidated Operating Margin — Operating margin decreased in 2015 compared to 2014 primarily due to:
• Unfavorable FX impacts of $362 million, primarily in Brazil of $228 million and Colombia of $83 million.
• Brazil due to lower demand, lower hydrology, and higher fixed costs.
• The Dominican Republic due to lower prices and lower availability.
These decreases were partially offset by:
• Higher tariffs in Brazil as discussed above and lower spot prices on energy purchases at Tietê.
• Higher generation and lower energy purchases driven by improved hydrological conditions in Panama.
• Higher prices at Chivor driven by a strong El Niño.
• Higher availability at Gener and Masinloc.
See Item 7.—SBU Performance Analysis of this Form 10-K for additional discussion and analysis of operating
results for each SBU.
Consolidated Results of Operations — Other
General and administrative expenses
General and administrative expenses include expenses related to corporate staff functions and/or initiatives,
executive management, finance, legal, human resources and information systems, as well as global development
costs.
General and administrative expenses decreased in 2016 from 2015 primarily due to decreased employee-
related costs, partially offset by increased business development costs.
General and administrative expenses increased in 2015 from 2014 primarily due to increased business
development costs and employee-related costs partially offset by decreased professional fees.
Interest expense
Interest expense increased in 2016 from 2015 primarily due to a $97 million increase at Eletropaulo as a result
of the prior year reversal of $64 million in interest expense, previously recognized on a contingent regulatory
liability, and increased interest expense due to higher regulatory liabilities and interest rates in the current year.
Additionally, there was a $26 million increase at Mong Duong, mainly due to this entity no longer capitalizing
interest as a result of the commencement of operations in April 2015. These increases were partially offset by lower
interest expense of $22 million due to a reduction in debt principal at the Parent Company.
Interest expense decreased in 2015 from 2014 primarily due to lower interest expense of $63 million at the
Parent Company due to a reduction in debt principal, and a $64 million reversal of interest expense previously
recognized on a contingent regulatory liability at Eletropaulo. These decreases were partially offset by an increase
at Mong Duong as the plant commenced operations in April 2015 and ceased capitalizing interest.
Interest income
Interest income increased in 2016 from 2015 primarily due to higher interest income of $19 million recognized
on the financing element of the service concession arrangement at Mong Duong, which became fully operational in
April 2015, partially offset by lower interest income of $16 million in Argentina due to prior year recognition of
accumulated interest on VAT balances related to CAMESSA.
Interest income increased in 2015 from 2014 primarily due to interest income of $114 million recognized in
2015 on the financing element of the service concession arrangement at Muong Duong, as well as an increase of
$36 million at Eletropaulo resulting from higher interest rates and an increase in regulatory assets.
Loss on extinguishment of debt
Loss on extinguishment of debt was $13 million for the year ended December 31, 2016 primarily related to
expense of $14 million recognized on debt extinguishment at the Parent Company.
Loss on extinguishment of debt was $182 million for the year ended December 31, 2015. This loss was
primarily related to expense of $105 million, $22 million, and $19 million recognized on debt extinguishments at the
Parent Company, IPL, and the Dominican Republic, respectively.
Loss on extinguishment of debt was $261 million for the year ended December 31, 2014. This was primarily
related to expense of $193 million, $31 million, and $20 million recognized on debt extinguishments at the Parent
84
Company, DPL, and Gener, respectively.
Other income and expense
Other income decreased in 2016 from 2015 primarily due to gains on early contract termination in 2015 and
lower gains on asset sales in 2016; partially offset by an increase in allowance for funds used during construction as
a result of increased construction activity at IPL.
Other income decreased in 2015 from 2014 primarily due to lower gains on asset sales in 2015 and the 2014
reversal of a liability in Kazakhstan due to the expiration of a statute of limitations for the Republic of Kazakhstan to
claim payment from AES.
Other expense increased in 2016 from 2015 primarily due to the 2016 recognition a full allowance on a non-
trade receivable in the MCAC SBU as a result of payment delays and discussions with the counterparty. The
allowance relates to certain reimbursements the Company was expecting in connection with a legal matter.
Management believes the counterparty is obligated to pay and plans to continue to attempt to fully collect the non-
trade receivable.
Other expense decreased in 2015 from 2014 primarily due to lower losses on sales and disposal of assets at
Termo Andes and Eletropaulo.
See Note 19—Other Income and Expense included in Item 8.—Financial Statements and Supplementary Data
of this Form 10-K for further information.
Gain on disposal and sale of businesses
Gain on sale of businesses was $29 million for the year ended December 31, 2016, which was primarily
related to the gain on sale of DPLER, partially offset by a loss on the deconsolidation of U.K. Wind.
Gain on sale of businesses was $29 million for the year ended December 31, 2015, which was primarily
related to the sale of Armenia Mountain.
Gain on disposal and sale of investments for the year ended December 31, 2014 was $358 million, which was
primarily related to the sale of 45% of the Company's interest in Masinloc, as well as the sale of U.K. Wind
(Operating Projects).
Goodwill impairment expense
There were no goodwill impairments for the year ended December 31, 2016.
Goodwill impairment expense was $317 million for the year ended December 31, 2015 due to a goodwill
impairment at DP&L.
Goodwill impairment expense was $164 million for the year ended December 31, 2014. This expense
consisted of $136 million, $20 million and $8 million of goodwill impairments at DPLER, Buffalo Gap II and Buffalo
Gap I, respectively.
See Note 9—Goodwill and Other Intangible Assets included in Item 8.—Financial Statements and
Supplementary Data of this Form 10-K for further information.
Asset impairment expense
Asset impairment expense was $1.1 billion for the year ended December 31, 2016. This was primarily related
to asset impairments of $859 million, $159 million and $77 million at DPL, Buffalo Gap II and Buffalo Gap I,
respectively.
Asset impairment expense was $285 million for the year ended December 31, 2015 primarily due to asset
impairments of $121 million, $116 million and $37 million at Kilroot, Buffalo Gap III and U.K. Wind, respectively.
Asset impairment expense was $91 million for the year ended December 31, 2014 primarily due to asset
impairments of $67 million, $12 million and $12 million at Ebute, U.K. Wind and DPL, respectively.
See Note 20—Asset Impairment Expense included in Item 8.—Financial Statements and Supplementary Data
of this Form 10-K for further information.
Income tax expense
Income tax decreased to a benefit of $188 million in 2016 as compared to expense of $472 million in 2015.
The Company's effective tax rates were (137%) and 41% for the years ended December 31, 2016 and 2015,
respectively.
85
The net decrease in the 2016 effective tax rate was due, in part, to the 2016 asset impairments in the U.S. and
to the current year benefit related to a restructuring of one of our Brazilian businesses that increases tax basis in
long-term assets. Further, the 2015 rate was impacted by the items described below. See Note 20—Asset
Impairment Expense for additional information regarding the 2016 U.S. asset impairments.
Income tax expense increased $101 million, or 27%, to $472 million in 2015. The Company's effective tax
rates were 41% and 26% for the years ended December 31, 2015 and 2014, respectively.
The net increase in the 2015 effective tax rate was due, in part, to the nondeductible 2015 impairment of
goodwill at our U.S. utility, DP&L and Chilean withholding taxes offset by the release of valuation allowance at
certain of our businesses in Brazil, Vietnam and the U.S. Further, the 2014 rate was impacted by the sale of
approximately 45% of the Company’s interest in Masin AES Pte Ltd., which owns the Company’s business interests
in the Philippines and the 2014 sale of the Company’s interests in four U.K. wind operating projects. Neither of
these transactions gave rise to income tax expense. See Note 15—Equity for additional information regarding the
sale of approximately 45% of the Company’s interest in Masin-AES Pte Ltd. See Note 23—Dispositions for
additional information regarding the sale of the Company’s interests in four U.K. wind operating projects.
Our effective tax rate reflects the tax effect of significant operations outside the U.S., which are generally taxed
at rates lower than the U.S. statutory rate of 35%. A future proportionate change in the composition of income
before income taxes from foreign and domestic tax jurisdictions could impact our periodic effective tax rate. The
Company also benefits from reduced tax rates in certain countries as a result of satisfying specific commitments
regarding employment and capital investment. See Note 21—Income Taxes for additional information regarding
these reduced rates.
Foreign currency transaction gains (losses)
Foreign currency transaction gains (losses) in millions were as follows:
Years Ended December 31,
AES Corporation
Chile
Colombia
Mexico
Philippines
United Kingdom
Argentina
Other
Total (1)
_____________________________
2016
2015
2014
$
$
(50) $
(9)
(8)
(8)
12
13
37
(2)
(15) $
(31) $
(18)
29
(6)
8
11
124
(10)
107
$
(34)
(30)
17
(14)
11
12
66
(17)
11
(1)
Includes gains of $17 million, $247 million and $172 million on foreign currency derivative contracts for the years ended December 31, 2016, 2015 and 2014,
respectively.
The Company recognized a net foreign currency transaction loss of $15 million for the year ended
December 31, 2016 primarily due to losses of $50 million at The AES Corporation mainly due to remeasurement
losses on intercompany notes, and losses on swaps and options.
This loss was partially offset by gains of $37 million in Argentina, mainly due to the favorable impact of foreign
currency derivatives related to government receivables.
The Company recognized a net foreign currency transaction gain of $107 million for the year ended
December 31, 2015 primarily due to gains of:
• $124 million in Argentina, due to the favorable impact from foreign currency derivatives related to government
receivables, partially offset by losses from the devaluation of the Argentine Peso associated with U.S. Dollar
denominated debt, and losses at Termoandes (a U.S. Dollar functional currency subsidiary) primarily associated
with cash and accounts receivable balances in local currency,
• $29 million in Colombia, mainly due to the depreciation of the Colombian Peso, positively impacting Chivor (a
U.S. Dollar functional currency subsidiary) due to liabilities denominated in Colombian Pesos,
• $11 million in the United Kingdom, mainly due to the depreciation of the Pound Sterling, resulting in gains at
Ballylumford Holdings (a U.S. Dollar functional currency subsidiary) associated with intercompany notes payable
denominated in Pound Sterling, and
86
These gains were partially offset by losses of:
• $31 million at The AES Corporation primarily due to decreases in the valuation of intercompany notes receivable
denominated in foreign currency, resulting from the weakening of the Euro and British Pound during the year,
partially offset by gains related to foreign currency option purchases, and
• $18 million in Chile primarily due to the devaluation of the Chilean Peso at Gener (a U.S. Dollar functional
currency subsidiary) from working capital denominated in Chilean Pesos, partially offset by gains on foreign
currency derivatives.
The Company recognized a net foreign currency transaction gains of $11 million for the year ended December
31, 2014 primarily due to gains of:
• $66 million in Argentina, due to the favorable impact from foreign currency derivatives related to government
receivables, partially offset by losses from the devaluation of the Argentine Peso associated with U.S. Dollar
denominated debt, and losses at Termoandes (a U.S. Dollar functional currency subsidiary) primarily associated
with cash and accounts receivable balances in local currency, and the purchase of Argentine sovereign bonds,
• $17 million in Colombia, mainly due to a 23% depreciation of the Colombian Peso, positively impacting Chivor (a
U.S. Dollar functional currency subsidiary) due to liabilities denominated in Colombian Pesos, primarily income
tax payable and accounts payable,
• $12 million in the United Kingdom, mainly due to a 6% depreciation of the Pound Sterling, resulting in gains at
Ballylumford Holdings (a U.S. Dollar functional currency subsidiary) associated with intercompany notes payable
denominated in Pound Sterling, and gains related to foreign currency derivatives, and
• $11 million in the Philippines, mainly due to amortization of frozen embedded derivatives and a 4% appreciation
of the Philippine Peso against the U.S. Dollar, resulting in a revaluation of cash accounts, customer receivables,
and deferred tax asset.
These gains were partially offset by losses of:
• $34 million at The AES Corporation primarily due to decreases in the valuation of intercompany notes receivable
denominated in foreign currency, resulting from the weakening of the Euro and British Pound during the year,
partially offset by gains related to foreign currency option purchases,
• $30 million in Chile primarily due to a 16% devaluation of the Chilean Peso, resulting in a $39 million loss at
Gener (a U.S. Dollar functional currency subsidiary) from working capital denominated in Chilean Pesos,
primarily cash, accounts receivable and VAT receivables, partially offset by income of $9 million on foreign
currency derivatives, and
• $14 million in Mexico, primarily due to a 13% devaluation of the Mexican Peso, resulting in a loss at TEGTEP
and Merida (U.S. Dollar functional currency subsidiaries) from working capital denominated in Pesos (primarily
cash, recoverable tax, and VAT).
Other non-operating expense
There were no significant non-operating expenses for the years ended December 31, 2016 and 2015.
Other non-operating expense was $128 million for the year ended December 31, 2014 due to impairments
recognized at Entek and Silver Ridge.
See Note 8—Other Non-Operating Expense included in Item 8.—Financial Statements and Supplementary
Data of this Form 10-K for further information.
Net equity in earnings of affiliates
Net equity in earnings of affiliates decreased in 2016 compared to 2015 as a result of the restructuring of
Guacolda in September 2015, which resulted in a $66 million benefit. No comparable transaction occurred in 2016.
Net equity in earnings of affiliates increased in 2015 compared to 2014 as a result of the restructuring of
Guacolda in September 2015, which resulted in a $66 million benefit, as well as the impairment at Elsta in 2014.
See Note 7—Investments In and Advances to Affiliates included in Item 8.—Financial Statements and
Supplementary Data of this Form 10-K for further information.
87
Income from continuing operations attributable to noncontrolling interests
Income from continuing operations attributable to noncontrolling interests decreased in 2016 compared to
2015 as a result of:
• a decrease at Tietê due to lower earnings
• a decrease at Eletropaulo resulting from the the reversal of a contingent regulatory liability in 2015, and
• asset impairments at Buffalo Gap I and II;
Partially offset by:
• a lower asset impairment at Buffalo Gap III in 2015, and
•
income tax benefits at Eletropaulo.
Income from continuing operations attributable to noncontrolling interests increased in 2015 compared to 2014
as a result of:
• an increase at Mong Duong due to commencement of operations in 2015,
• an increase at Gener primarily due to the restructuring of Guacolda,
• an increase at Masinloc due to increased earnings in 2015 and the 2014 sale of a noncontrolling interest in that
business
Partially offset by:
• a decrease at Buffalo Gap III resulting from the asset impairment expense allocation to the tax equity partner,
and
• a decrease at Eletropaulo resulting from unfavorable foreign exchange and lower demand.
Loss from discontinued operations
Total loss from discontinued operations in 2016 and 2015 was due to the sale of AES Sul. The loss in 2016
includes an after tax loss on impairment of $382 million recognized in the second quarter of 2016 and an additional
after tax loss on sale of $737 million upon disposal of AES Sul in October 2016. There were no significant changes
in loss from operations related to the AES Sul discontinued business.
Total income from discontinued operations for the year ended December 31, 2014 was primarily due to AES
Sul, Cameroon, Saurashtra and U.S. wind projects.
See Note 22—Discontinued Operations included in Item 8.—Financial Statements and Supplementary Data of
this Form 10-K for further information.
Net income (loss) attributable to The AES Corporation
Net income (loss) attributable to The AES Corporation decreased in 2016 compared to 2015 as a result of:
impairments and loss on sale at discontinued businesses;
•
• higher impairment expense on long lived assets;
•
•
•
•
•
lower operating margins at our US, Brazil and Europe SBUs;
lower equity in earnings of affiliates due to the 2015 restructuring at Guacolda; and
lower gains on foreign currency derivatives.
These decreases were partially offset by:
lower effective tax rate;
lower debt extinguishment expense; and
• absence of goodwill impairment expense.
Net income attributable to The AES Corporation decreased in 2015 compared to 2014 as result of:
• Higher impairment expense
• Lower gains from the sale of businesses
These decreases were partially offset by:
• Lower debt extinguishment expense
88
SBU Performance Analysis
Non-GAAP Measures
Adjusted Operating Margin, Adjusted PTC, Adjusted EPS, and Proportional Free Cash Flow are non-GAAP
supplemental measures that are used by management and external users of our consolidated financial statements
such as investors, industry analysts and lenders.
Adjusted Operating Margin
We define Adjusted Operating Margin as Operating Margin, adjusted for the impact of NCI, excluding
unrealized gains or losses related to derivative transactions. See Review of Consolidated Results of Operations for
definitions of Operating Margin and cost of sales.
The GAAP measure most comparable to Adjusted Operating Margin is Operating Margin. We believe that
Adjusted Operating Margin better reflects the underlying business performance of the Company. Factors in this
determination include the impact of NCI, where AES consolidates the results of a subsidiary that is not wholly
owned by the Company, as well as the variability due to unrealized derivatives gains or losses. Adjusted Operating
Margin should not be construed as an alternative to Operating Margin, which is determined in accordance with
GAAP.
Reconciliation of Adjusted Operating Margin (in millions)
Operating Margin
Noncontrolling Interests Adjustment
Derivatives Adjustment
Total Adjusted Operating Margin
Years Ended December 31,
2015
2014
2016
$
$
2,433
(689)
9
1,753
$
$
2,858
(869)
19
2,008
$
$
2,980
(760)
8
2,228
89
Adjusted PTC
We define Adjusted PTC as pretax income from continuing operations attributable to The AES Corporation
excluding gains or losses due to (a) unrealized gains or losses related to derivative transactions, (b) unrealized
foreign currency gains or losses, (c) gains or losses due to dispositions and acquisitions of business interests,
(d) losses due to impairments, and (e) costs due to the early retirement of debt. Adjusted PTC also includes net
equity in earnings of affiliates on an after-tax basis adjusted for the same gains or losses excluded from
consolidated entities.
Adjusted PTC reflects the impact of NCI and excludes the items specified in the definition above. In addition to
the revenue and cost of sales reflected in Operating Margin, Adjusted PTC includes the other components of our
income statement, such as general and administrative expense in the corporate segment, as well as business
development costs; interest expense and interest income; other expense and other income; realized foreign
currency transaction gains and losses; and net equity in earnings of affiliates.
The GAAP measure most comparable to Adjusted PTC is income from continuing operations attributable to
The AES Corporation. We believe that Adjusted PTC better reflects the underlying business performance of the
Company and is considered in the Company's internal evaluation of financial performance. Factors in this
determination include the variability due to unrealized gains or losses related to derivative transactions, unrealized
foreign currency gains or losses, losses due to impairments and strategic decisions to dispose of or acquire
business interests or retire debt, which affect results in a given period or periods. In addition, earnings before tax
represents the business performance of the Company before the application of statutory income tax rates and tax
adjustments, including the effects of tax planning, corresponding to the various jurisdictions in which the Company
operates. Adjusted PTC should not be construed as an alternative to income from continuing operations attributable
to The AES Corporation, which is determined in accordance with GAAP.
Reconciliation of Adjusted PTC (in millions)
Income from continuing operations, net of tax, attributable to The AES Corporation
Income tax (benefit) expense attributable to The AES Corporation
Pretax contribution
Unrealized derivative (gains) losses
Unrealized foreign currency losses
Disposition/acquisition (gains) losses
Impairment losses
Loss on extinguishment of debt
Total Adjusted PTC
Years Ended December 31,
2016
2015
2014
8
(148)
(140)
(9)
23
6
933
29
842
$
$
331
275
606
(166)
96
(42)
504
179
1,177
$
$
705
179
884
(135)
110
(361)
415
274
1,187
$
$
90
Adjusted EPS
We define Adjusted EPS as diluted earnings per share from continuing operations excluding gains or losses of
both consolidated entities and entities accounted for under the equity method due to (a) unrealized gains or losses
related to derivative transactions, (b) unrealized foreign currency gains or losses, (c) gains or losses due to
dispositions and acquisitions of business interests, (d) losses due to impairments, and (e) costs due to the early
retirement of debt.
The GAAP measure most comparable to Adjusted EPS is diluted earnings per share from continuing
operations. We believe that Adjusted EPS better reflects the underlying business performance of the Company and
is considered in the Company's internal evaluation of financial performance. Factors in this determination include
the variability due to unrealized gains or losses related to derivative transactions, unrealized foreign currency gains
or losses, losses due to impairments and strategic decisions to dispose of or acquire business interests or retire
debt, which affect results in a given period or periods. Adjusted EPS should not be construed as an alternative to
diluted earnings per share from continuing operations, which is determined in accordance with GAAP.
91
Adjusted EPS
Diluted earnings per share from continuing operations
Unrealized derivative gains
Unrealized foreign currency losses
Disposition/acquisition (gains) losses
Impairment losses
Loss on extinguishment of debt
Less: Net income tax benefit
Adjusted EPS
_____________________________
Years Ended December 31,
2015
2014
2016
$
$
—
(0.02)
0.04
0.01
1.41
0.05
(0.51)
0.98
(1)
(4)
(7)
(10)
$
0.48
$
0.97
(0.24)
0.14
(0.06)
0.73
0.26
(0.06)
1.25
(2)
(5)
(8)
(11)
$
(0.19)
0.16
(0.50)
0.57
0.38
(0.21)
1.18
(3)
(6)
(9)
(12)
$
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
Amount primarily relates to the loss on deconsolidation of UK Wind of $20 million, or $0.03 per share and losses associated with the sale of Sul of $10 million,
or $0.02; partially offset by the gain on sale of DPLER of $22 million, or $0.03 per share.
Amount primarily relates to the gains on the sale of Armenia Mountain of $22 million, or $0.03 per share and from the sale of Solar Spain and Solar Italy of $7
million, or $0.01 per share.
Amount primarily relates to the gain on the sale of a noncontrolling interest in Masinloc of $283 million, or $0.39 per share; and the gain from the sale of the
U.K. wind projects of $78 million, or $0.11 per share.
Amount primarily relates to asset impairments at DPL of $859 million, or $1.30 per share; $159 million at Buffalo Gap II ($49 million, or $0.07 per share, net of
NCI); and $77 million at Buffalo Gap I ($23 million, or $0.03 per share, net of NCI).
Amount primarily relates to the goodwill impairment at DPL of $317 million, or $0.46 per share, and asset impairments at Kilroot of $121 million ($119 million,
or $0.17 per share, net of NCI), at Buffalo Gap III of $116 million ($27 million, or $0.04 per share, net of NCI), and at U.K. Wind (Development Projects) of $38
million ($30 million, or $0.04 per share, net of NCI).
Amount primarily relates to the goodwill impairments at DPLER of $136 million, or $0.19 per share, and at Buffalo Gap I & II of $28 million, or $0.04 per share;
and asset impairments at Ebute of $67 million ($64 million, or $0.09 per share, net of NCI), at Elsta of $41 million, or $0.06 per share; and the other-than-
temporary impairments at Entek of $86 million, $0.12 per share and at Silver Ridge Power of $42 million, or $0.06 per share.
Amount primarily relates to the loss on early retirement of debt at the Parent Company of $19 million, or $0.03 per share.
Amount primarily relates to the loss on early retirement of debt at the Parent Company of $116 million, or $0.17 per share and at IPL of $22 million ($17
million, or $0.02 per share, net of NCI).
Amount primarily relates to the loss on early retirement of debt at the Parent Company of $200 million, or $0.28 per share, at DPL of $31 million, or $0.04 per
share, at Angamos of $20 million ($14 million, or $0.02 per share, net of NCI) and at U.K. wind projects of $18 million, or $0.02 per share.
(10) Amount primarily relates to the per share income tax benefit associated with asset impairment of $332 million, or $0.50 per share in the twelve months ended
December 31, 2016.
(11) Amount primarily relates to the per share income tax benefit associated with losses on extinguishment of debt of $55 million, or $0.08 per share in the twelve
months ended December 31, 2015.
(12) Amount primarily relates to the per share income tax benefit associated with losses on extinguishment of debt of $90 million, or $0.12 per share and
dispositions/acquisitions of $67 million, or $0.09 per share in the twelve months ended December 31, 2014.
Proportional Free Cash Flow
We define proportional free cash flow as cash flows from operating activities less maintenance capital
expenditures (including non-recoverable environmental capital expenditures), adjusted for the estimated impact of
noncontrolling interests. The proportionate share of cash flows and related adjustments attributable to
noncontrolling interests in our subsidiaries comprise the proportional adjustment factor presented in the
reconciliation below. Upon the Company's adoption of the accounting guidance for service concession
arrangements effective January 1, 2015, capital expenditures related to service concession assets that would have
been classified as investing activities on the Consolidated Statement of Cash Flows are now classified as operating
activities. See Note 1—General and Summary of Significant Accounting Policies of this Form 10-K for further
information on the adoption of this guidance.
Beginning in the quarter ended March 31, 2015, the Company changed the definition of proportional free cash
flow to exclude the cash flows for capital expenditures related to service concession assets that are now classified
within net cash provided by operating activities on the Consolidated Statement of Cash Flows. The proportional
adjustment factor for these capital expenditures is presented in the reconciliation below.
We also exclude environmental capital expenditures that are expected to be recovered through regulatory,
contractual or other mechanisms. An example of recoverable environmental capital expenditures is IPL's
investment in MATS-related environmental upgrades that are recovered through a tracker. See Item 1.—US SBU—
IPL—Environmental Matters for details of these investments.
The GAAP measure most comparable to proportional free cash flow is cash flows from operating activities. We
believe that proportional free cash flow better reflects the underlying business performance of the Company, as it
measures the cash generated by the business, after the funding of maintenance capital expenditures, that may be
available for investing in growth opportunities or repaying debt. Factors in this determination include the impact of
noncontrolling interests, where AES consolidates the results of a subsidiary that is not wholly-owned by the
Company.
92
The presentation of free cash flow has material limitations. Proportional free cash flow should not be construed
as an alternative to cash from operating activities, which is determined in accordance with GAAP. Proportional free
cash flow does not represent our cash flow available for discretionary payments because it excludes certain
payments that are required or to which we have committed, such as debt service requirements and dividend
payments. Our definition of proportional free cash flow may not be comparable to similarly titled measures
presented by other companies.
Beginning in the first quarter of 2017, we will no longer include these non-GAAP proportional free cash flow
disclosures that have historically been provided and will instead disclose non-GAAP free cash flows only on a
consolidated basis. Our use of proportional free cash flow was intended to provide investors with an understanding
of the portion of free cash flows attributable to AES after the impact of non-controlling interests. However, since the
concept of a non-controlling interest is not contemplated under GAAP with respect to the statement of cash flows,
we will no longer be able to disclose proportional free cash flow in light of recent interpretive guidance issued by the
SEC staff.
Reconciliation of Proportional Free Cash Flow (in millions)
Years Ended December 31,
Net Cash Provided by Operating Activities
Add: capital expenditures related to service concession assets (1)
Adjusted Operating Cash Flow
Less: proportional adjustment factor on operating cash activities (2) (3)
Proportional Adjusted Operating Cash Flow
Less: proportional maintenance capital expenditures, net of reinsurance proceeds (2)
Less: proportional non-recoverable environmental capital expenditures (2) (4)
Proportional Free Cash Flow
_____________________________
2016
2015
2014
2016/2015
Change
2015/2014
Change
$ 2,884
29
2,913
(1,032)
1,881
(425)
(39)
$ 1,417
$ 2,134
165
2,299
(558)
1,741
(449)
(51)
$ 1,241
$ 1,791
—
1,791
(359)
1,432
(485)
(56)
$ 891
$
$
750
(136)
614
(474)
140
24
12
176
$
$
343
165
508
(199)
309
36
5
350
(1)
(2)
(3)
(4)
Service concession asset expenditures are excluded from the proportional free cash flow non-GAAP metric.
The proportional adjustment factor, proportional maintenance capital expenditures (net of reinsurance proceeds) and proportional non-recoverable
environmental capital expenditures are calculated by multiplying the percentage owned by noncontrolling interests for each entity by its corresponding
consolidated cash flow metric and are totaled to the resulting figures. For example, Parent Company A owns 20% of Subsidiary Company B, a consolidated
subsidiary. Thus, Subsidiary Company B has an 80% noncontrolling interest. Assuming a consolidated net cash flow from operating activities of $100 from
Subsidiary B, the proportional adjustment factor for Subsidiary B would equal $80 (or $100 x 80%). The Company calculates the proportional adjustment
factor for each consolidated business in this manner and then sums these amounts to determine the total proportional adjustment factor used in the
reconciliation. The proportional adjustment factor may differ from the proportion of income attributable to noncontrolling interests as a result of (a) non-cash
items which impact income but not cash and (b) AES' ownership interest in the subsidiary where such items occur.
Includes proportional adjustment amount for service concession asset expenditures of $15 million and $84 million for the years ended December 31, 2016
and 2015, respectively. The Company adopted service concession accounting effective January 1, 2015.
Excludes IPL's proportional recoverable environmental capital expenditures of $132 million, $205 million and $163 million for the years ended December 31,
2016, 2015 and 2014, respectively.
93
Parent Free Cash Flow (a non-GAAP measure)
The Company defines Parent Free Cash Flow as dividends and other distributions received from our operating
businesses less certain cash costs at the Parent Company level, primarily interest payments, overhead, and
development costs. Parent Free Cash Flow is used to fund shareholder dividends, share repurchases, growth
investments, recourse debt repayments, and other uses by the Parent Company. Refer to Item 1—Business—
Overview for further discussion of the Parent Company's capital allocation strategy.
US SBU
A summary of Operating Margin, Adjusted Operating Margin, Adjusted PTC, and Proportional Free Cash Flow
($ in millions) is as follows:
For the Years Ended December 31,
2016
2015
2014
Operating Margin
Noncontrolling Interests Adjustment (1)
Derivatives Adjustment
Adjusted Operating Margin
Adjusted PTC
Proportional Free Cash Flow
_____________________________
$
$
$
$
582
(75)
6
513
347
614
$
$
$
$
621
(38)
15
598
360
591
$
$
$
$
699
—
12
711
445
646
$ Change
2016 vs. 2015
$
(39) $
$ Change
2015 vs. 2014
(78)
% Change
2016 vs. 2015
-6%
% Change
2015 vs. 2014
-11%
$
$
$
(85) $
(13) $
$
23
(113)
(85)
(55)
-14%
-4%
4%
-16%
-19%
-9%
(1)
See Item 1. Business for the respective ownership interest for key business. In addition, AES owns 70% of IPL as of March 2016 compared to 75% beginning
April 2015, 85% beginning in February 2015 and 100% prior to February 2015.
94
Fiscal year 2016 versus 2015
Operating margin decreased $39 million, or 6%, which was driven primarily by the following:
US Generation
Southland related to an increase in depreciation expense as a result of a change in estimated useful lives of the plants
Impact from sale of Armenia Mountain in July 2015
Warrior Run due to lower availability and higher maintenance cost primarily due to major outages in 2016
Laurel Mountain due to lower regulation dispatch as well as lower energy and regulation pricing
Other
Total US Generation Decrease
DPL
Impact of lower wholesale prices and completion of DP&L’s transition to a competitive-bid market
Decrease in RTO capacity and other revenues primarily due to lower capacity cleared in the auction
Lower depreciation expense due to June 2016 fixed asset impairment and decrease in generating facility maintenance and
other expenses
Other
Total DPL Decrease
IPL
Higher retail margin driven by environmental revenues and higher rates due to a new rate order
Change in accrual resulting from the implementation of new rates
Other
Total IPL Increase
Total US SBU Operating Margin Decrease
$
$
(17)
(10)
(8)
(8)
(4)
(47)
(42)
(21)
17
2
(44)
36
18
(2)
52
(39)
Adjusted Operating Margin decreased $85 million for the US SBU due to the drivers above, excluding the
impact of unrealized derivative gains and losses and adjusted for the impact of noncontrolling interests.
Adjusted PTC decreased $13 million driven by the decrease of $85 million in Adjusted Operating Margin
described above, partially offset by a gain on contract termination at DP&L, lower interest expense at DPL and IPL
in part due to the sell-down impacts as discussed above and the impact of HLBV at our Distributed Energy business
as a result of new projects achieving COD in 2016.
Proportional Free Cash Flow increased $23 million, primarily driven by a $93 million decrease in coal
purchases due to the ongoing conversion of coal generation assets to natural gas at IPL, a build-up of inventory
due to mild winter weather in December 2015, and inventory optimization efforts at DPL. Additionally, Proportional
Free Cash Flow benefited from a $32 million increase in accounts payable due to the timing of vendor payments,
$17 million in net settlements of accounts receivable primarily resulting from the sale of DPLER in 2016, and lower
interest payments of $19 million due to timing and lower interest rates. These positive impacts were partially offset
by an $81 million decrease in Adjusted Operating Margin (net of non-cash impacts of $4 million, primarily related to
the implementation of IPL’s new rates and depreciation), and a $84 million decrease in the timing of receivables
collections resulting primarily from higher rates at IPL, more favorable weather in 2016, and the impact of DPLER’s
declining customer base in 2015.
Fiscal year 2015 versus 2014
Operating margin decreased by $78 million, or 11%, which was driven primarily by the following:
DPL
Impact of more of DP&L's generation being sold in the wholesale market at lower prices in 2015 compared to supplying DP&L
retail customers in 2014, lower generation driven by plant outages in 2015, and unfavorable weather; partially offset by the
impact of outages and lower gas availability occurring in Q1 2014
Increase in capacity margin due to increase in PJM capacity price
Total DPL Decrease
US Generation
Lower production and prices across the US Wind businesses
Lower availability and dispatch at Hawaii
Other
Total US Generation Decrease
IPL
Lower wholesale margin due to lower market prices of electricity and outages
Higher fixed costs primarily due to higher maintenance expense attributed to plant outages and higher depreciation expense
due to MATS assets
Higher retail margins
Other
Total IPL Decrease
Total US SBU Operating Margin Decrease
$
$
(53)
26
(27)
(20)
(10)
4
(26)
(26)
(18)
20
(1)
(25)
(78)
Adjusted Operating Margin decreased $113 million at the US SBU due to the drivers above, excluding the
95
impact of unrealized derivative gains and losses and adjusted for the impact of noncontrolling interests.
Adjusted PTC decreased $85 million driven by the decrease of $113 million in Adjusted Operating Margin
described above as well as a decrease in the Company's share of earnings under the HLBV allocation of
noncontrolling interest at Buffalo Gap, partially offset by IPL due to lower interest expense related to the impact of
the sell down and increased AFUDC, and DPL due to lower interest expense.
Proportional Free Cash Flow decreased $55 million, primarily driven by the $113 million decrease in Adjusted
Operating Margin described above, and a $22 million increase in maintenance and non-recoverable capital
expenditures. These negative impacts were partially offset by a $22 million increase due to the collection of
previously deferred storm costs, a one-time payment of $19 million in 2014 to terminate an unfavorable coal
contract, higher collections of $16 million due to settlement of a receivable balance related to the sale of MC2 in
2015, and the timing of inventory payments of $16 million at DPL. Additionally, Proportional Free Cash Flow was
favorably impacted by the timing of power purchase payments of $7 million and the timing of $9 million of
receivables collections at IPL.
ANDES SBU
A summary of Operating Margin, Adjusted Operating Margin, Adjusted PTC, and Proportional Free Cash Flow
($ in millions) is as follows:
For the Years Ended December 31,
2016
2015
2014
Operating Margin
Noncontrolling Interests Adjustment (1)
Adjusted Operating Margin
Adjusted PTC
Proportional Free Cash Flow
_____________________________
$
$
$
$
634
(192)
442
390
264
$
$
$
$
618
(152)
466
482
224
$
$
$
$
587
(143)
444
421
176
$ Change
2016 vs. 2015
16
$
$ Change
2015 vs. 2014
31
$
% Change
2016 vs. 2015
3%
% Change
2015 vs. 2014
5%
$
$
$
(24) $
(92) $
$
40
22
61
48
-5%
-19%
18%
5%
14%
27%
(1)
See Item 1. Business for the respective ownership interest for key business. In addition, AES owned 71% of Gener and Chivor prior to sell down effective
December 2015 which resulted in ownership of 67%. The Alto Maipo (under construction) and Cochrane plants are owned 40%.
Fiscal year 2016 versus 2015
Including the unfavorable impact of foreign currency translation and remeasurement of $36 million, operating
margin increased $16 million, or 3%, which was driven primarily by the following:
Gener
Lower spot prices on energy and fuel purchases
Start of operations of Cochrane Plant
Other
Total Gener Increase
Argentina
Higher rates driven by annual price review granted by Resolution 22/2016
Lower availability mainly associated with planned major maintenance
Higher fixed costs primarily driven by higher inflation and by higher maintenance cost
Unfavorable FX remeasurement impacts
Total Argentina Decrease
Chivor
Higher volume of energy sales to Spot Market
Unfavorable FX remeasurement impacts
Lower spot sales prices
Other
Total Chivor Decrease
Total Andes SBU Operating Margin Increase
$
$
82
36
(3)
115
61
(20)
(44)
(21)
(24)
14
(15)
(72)
(2)
(75)
16
Adjusted Operating Margin decreased $24 million for the year due to the drivers above, adjusted for the impact
of noncontrolling interests.
Adjusted PTC decreased $92 million, driven by the decrease in Equity Earnings of $54 million mainly related
to Guacolda’s reorganization in September 2015, the decrease of $24 million in Adjusted Operating Margin and the
increase of $12 million in interest expense primarily associated to lower interest capitalization after beginning of
commercial operations at Cochrane.
Proportional Free Cash Flow increased $40 million, primarily driven by $57 million in collections of financing
receivables and the timing of maintenance remuneration from CAMMESSA in Argentina, a $25 million positive
impact related to a one-time interest rate swap termination payment at Ventanas in July 2015, a decrease of $58
million in working capital requirements at Chivor mainly related to collections of prior period sales, and a $23 million
reduction in proportional maintenance and non-recoverable capital expenditures due to lower expenditures on
96
emissions control equipment at Chile. These positive impacts were partially offset by a reduction of $4 million in
Adjusted Operating Margin (net of non-cash impacts), $43 million of lower VAT refunds related to our Cochrane and
Alto Maipo construction projects, higher net tax payments of $56 million primarily related to withholding taxes paid
on Chilean distributions to AES Affiliates and higher taxable income in Colombia, and $18 million of higher interest
payments primarily as a consequence of debt refinancing at higher interest rates and lower interest capitalization
under construction projects.
Fiscal year 2015 versus 2014
Including the unfavorable impact of foreign currency translation and remeasurement of $87 million, operating
margin increased $31 million, or 5%, which was driven primarily by the following:
Gener
Higher margins associated to Nueva Renca Plant tolling agreement
Higher volume of energy sales mainly related to higher availability
Other
Total Gener Increase
Argentina
Higher rates driven by an annual price review and additional contributions introduced by Resolution 482
Higher fixed costs primarily driven by higher inflation and by higher maintenance cost
Unfavorable FX remeasurement impacts
Other
Total Argentina Increase
Chivor
Unfavorable FX remeasurement impacts
Higher rates driven by a strong El Niño impact on prices
Higher volume of energy sales mainly associated to higher generation
Other
Total Chivor Decrease
Total Andes SBU Operating Margin Increase
$
$
26
21
(2)
45
49
(45)
(4)
4
4
(83)
60
12
(7)
(18)
31
Adjusted Operating Margin increased $22 million for the year due to the drivers above, adjusted for the impact
of noncontrolling interests.
Adjusted PTC increased $61 million driven by a restructuring of Guacolda in Chile which increased our equity
investment and resulted in additional Equity Earnings of $46 million as well as realized FX gains, lower interest
expense at Chivor and the $22 million in Adjusted Operating Margin described above. This was partially offset by
lower equity earnings at Guacolda of $16 million (excluding restructuring impact above) mainly driven by a 2014
gain on sale of a transmission line.
Proportional Free Cash Flow increased $48 million, primarily driven by $107 million higher VAT refunds at
Cochrane and Alto Maipo, $27 million of non-recurring maintenance collections in Argentina, and a $17 million
decrease in interest payments. These positive impacts were partially offset by $49 million of higher tax payments
and $25 million of lower collections primarily from contract customers at Chivor, and a $25 million impact related to
a one-time interest rate swap termination payment at Ventanas in July 2015.
BRAZIL SBU
A summary of Operating Margin, Adjusted Operating Margin, Adjusted PTC, and Proportional Free Cash Flow
($ in millions) is as follows:
$ Change
2016 vs. 2015
$
(353) $
$ Change
2015 vs. 2014
(42)
% Change
2016 vs. 2015
-60%
% Change
2015 vs. 2014
-7%
$
$
$
(79) $
(89) $
$
139
1
10
(42)
-62%
-75%
479%
1%
9%
-323%
For the Years Ended December 31,
2016
2015
2014
Operating Margin
Noncontrolling Interests Adjustment (1)
Adjusted Operating Margin
Adjusted PTC
Proportional Free Cash Flow
_____________________________
$
$
$
$
239
(190)
49
29
110
$
$
$
$
$
592
(464)
$
128
$
118
(29) $
634
(507)
127
108
13
(1)
See Item 1. Business for the respective ownership interest for key business.
97
Fiscal year 2016 versus 2015
Including the unfavorable impact of foreign currency translation of $6 million, operating margin decreased
$353 million, or 60%, which was driven primarily by the following:
Tietê
Lower rates for energy sold under new contracts
Unfavorable FX impacts
Higher fixed costs due to higher legal settlements
Lower rates for energy purchases mainly due to decrease in spot market prices
Other
Total Tietê Decrease
Eletropaulo
Negative impact of reversal of contingent regulatory liability in 2015
Higher fixed costs mainly due to higher bad debt and employee-related costs
Lower demand mainly due to economic decline
Higher regulatory penalties in 2016 partially offset by regulatory penalties contingency provision in 2015
Higher tariffs
Other
Total Eletropaulo Decrease
Uruguaiana
Operations in 2015 compared to not operating in 2016
Total Uruguaiana Decrease
Other Business Drivers
Total Brazil SBU Operating Margin Decrease
$
$
(239)
(14)
(13)
78
(2)
(190)
(97)
(68)
(59)
(30)
116
(3)
(141)
(20)
(20)
(2)
(353)
Adjusted Operating Margin decreased $79 million primarily due to the drivers discussed above, adjusted for
the impact of noncontrolling interests.
Adjusted PTC decreased $89 million, driven by the decrease of $79 million in Adjusted Operating Margin
described above as well as higher interest expense of $10 million related to the reversal of a contingent regulatory
liability at Eletropaulo in 2015.
Proportional Free Cash Flow increased by $139 million, primarily driven by favorable timing of $309 million in
net collections of higher costs deferred in net regulatory assets in the prior year at Eletropaulo and Sul as a result of
unfavorable hydrology in prior periods, favorable timing of $133 million in collections on current year energy sales,
and lower energy purchases of $23 million at Tietê due to favorable hydrology. These positive impacts were partially
offset by unfavorable timing of $241 million in payments for energy purchases and regulatory charges at
Eletropaulo and Sul, and a $72 million decrease in in Adjusted Operating Margin (net of $7 million in non-cash
impacts, primarily due to the reversal of a contingent regulatory liability at Eletropaulo in 2015).
Fiscal year 2015 versus 2014
Including the unfavorable impact of foreign currency translation of $228 million, operating margin decreased
$42 million, or 7%, which was driven primarily by the following:
Tietê
Energy purchases at lower rates primarily due to lower spot prices
Unfavorable FX impacts
Higher volume purchased on the spot market due to higher assured energy requirement
Other
Total Tietê Increase
Uruguaiana
Higher generation from a longer period of temporary restart of operations
Total Uruguaiana Increase
Eletropaulo
Higher fixed costs, primarily due to higher bad debt expense, storms and employee-related costs
Unfavorable FX impacts
Contingency related to performance indicators
Lower volumes due to lower demand
Reversal of a contingent regulatory liability (excluding FX)
Higher tariffs
Total Eletropaulo Decrease
Other Business Drivers
Total Brazil SBU Operating Margin Decrease
$
$
311
(152)
(113)
(8)
38
11
11
(142)
(74)
(59)
(35)
135
82
(93)
2
(42)
Adjusted Operating Margin increased $1 million primarily due to the drivers discussed above, adjusted for the
impact of noncontrolling interests.
98
Adjusted PTC increased $10 million, driven by the increase of $1 million in Adjusted Operating Margin
described above as well as favorable net interest income recognized on receivables at Eletropaulo.
Proportional Free Cash Flow decreased by $42 million, primarily driven by a $99 million decrease in Sul's
Adjusted Operating Margin classified as a discontinued operation (not included in the $1 million increase in
Adjusted Operating Margin described above), higher energy purchases of $59 million at Tietê due to the timing of
purchases in the spot market at higher prices, unfavorable timing of $32 million of higher costs deferred in net
regulatory assets at Sul as result of unfavorable hydrology, and $17 million of higher interest payments at Sul due to
a higher debt balance and higher interest rate. These negative impacts were partially offset by favorable timing of
$121 million in payments for energy purchases and regulatory charges at Eletropaulo and Sul, $31 million of lower
income tax payments at Tietê, and favorable timing of $14 million in net collections of higher costs deferred in net
regulatory assets in the prior year at Eletropaulo.
MCAC SBU
A summary of Operating Margin, Adjusted Operating Margin, Adjusted PTC, and Proportional Free Cash Flow
($ in millions) is as follows:
For the Years Ended December 31,
2016
2015
2014
Operating Margin
Noncontrolling Interests Adjustment (1)
Derivatives Adjustment
Adjusted Operating Margin
Adjusted PTC
Proportional Free Cash Flow
_____________________________
$
$
$
$
523
(108)
(2)
413
267
168
$
$
$
$
543
(106)
1
438
327
498
$
$
$
$
541
(59)
—
482
352
281
$ Change
2016 vs. 2015
$
(20) $
$ Change
2015 vs. 2014
2
% Change
2016 vs. 2015
-4%
% Change
2015 vs. 2014
— %
$
$
$
(25) $
(60) $
(330) $
(44)
(25)
217
-6%
-18%
-66%
(9)%
(7)%
77 %
(1)
See Item 1. Business for the respective ownership interest for key business. In addition, AES owned 92% of Andres and Los Mina and 46% of Itabo in the
Dominican Republic until December 2015 when the ownership changed to 90% at Andres and Los Mina and 45% at Itabo.
Fiscal year 2016 versus 2015
Operating margin decreased $20 million, or 4%, which was driven primarily by the following:
Mexico
Lower availability and related costs
Other
Total Mexico Decrease
El Salvador
Higher fixed costs
Lower energy sales margin
Total El Salvador Decrease
Panama
Expenses related to the ongoing construction of a natural gas generation plant and a liquefied natural gas terminal
Commencement of power barge operations at the end of March 2015
Other
Total Panama Decrease
Dominican Republic
Higher contracted and spot energy sales
Total Dominican Republic Increase
Other Business Drivers
Total MCAC SBU Operating Margin Decrease
$
$
(11)
(6)
(17)
(6)
(4)
(10)
(19)
13
(3)
(9)
24
24
(8)
(20)
Adjusted Operating Margin decreased $25 million due to the drivers above, adjusted for the impact of
noncontrolling interests and excluding unrealized gains and losses on derivatives.
Adjusted PTC decreased $60 million, driven by the decrease in Adjusted Operating Margin of $25 million as
described above as well as a 2015 compensation agreement regarding early termination of the original Barge PPA
of $10 million and a $26 million allowance recognized in 2016 at Puerto Rico.
Proportional Free Cash Flow decreased $330 million, primarily driven by $212 million of lower collections in
the Dominican Republic mainly due to collections of overdue receivables in September 2015, the $25 million
decrease in Adjusted Operating Margin described above, $47 million of decreased collections in Puerto Rico due to
lower sales, $14 million of higher tax payments in El Salvador due to higher taxable income in 2015, and a $10
million impact from compensation received in the prior-year from the off-taker in Panama related to an early
termination of the barge PPA.
99
Fiscal year 2015 versus 2014
Operating margin increased $2 million, or 0.4%, which was driven primarily by the following:
Panama
Higher generation and lower energy purchases, driven by improved hydrological conditions
Commencement of power barge operations at the end of March 2015
Lower compensation from the government of Panama due to lower volumes of energy purchased at lower spot prices
Other
Total Panama Increase
El Salvador
One-time unfavorable adjustment to unbilled revenue in 2014
Lower energy losses and higher demand
Total El Salvador Increase
Dominican Republic
Lower commodity prices resulting in lower spot prices and lower than expected gas sales demand with excess gas used for
generation at lower margins
Lower availability
Lower frequency regulation revenues
Total Dominican Republic Decrease
Puerto Rico
One-time reversal of bad debt in 2014 and higher maintenance expense
Total Puerto Rico Decrease
Mexico
Higher fuel costs, lower spot sales and lower availability
Total Mexico Decrease
Other Business Drivers
Total MCAC SBU Operating Margin Increase
$
$
118
18
(34)
(6)
96
12
11
23
(29)
(28)
(21)
(78)
(11)
(11)
(29)
(29)
1
2
Adjusted Operating Margin decreased $44 million due to the drivers above adjusted for the impact of
noncontrolling interests and excluding unrealized gains and losses on derivatives.
Adjusted PTC decreased $25 million, driven by the decrease in Adjusted Operating Margin of $44 million
described above. These results were partially offset by a compensation agreement regarding early termination of
the original Barge PPA of $10 million and 2014 losses on a legal dispute settlement of $4 million in Panama as well
as lower interest expense due to lower debt at Puerto Rico.
Proportional Free Cash Flow increased $217 million, primarily due to the favorable timing of $220 million of
collections, mainly related to the collection of overdue receivables in the Dominican Republic in September 2015.
Proportional Free Cash Flow also benefited from a $17 million impact of lower energy purchases in El Salvador due
to lower fuel prices, and a $10 million impact from compensation received from the off-taker in Panama related to
an early termination of the barge PPA. These favorable impacts were partially offset by the $44 million decrease in
Adjusted Operating Margin as described above.
EUROPE SBU
A summary of Operating Margin, Adjusted Operating Margin, Adjusted PTC, and Proportional Free Cash Flow
($ in millions) is as follows:
$ Change
2016 vs. 2015
$
(44) $
$ Change
2015 vs. 2014
(100)
% Change
2016 vs. 2015
-15%
% Change
2015 vs. 2014
-25%
$
$
$
(51) $
(48) $
$
314
(97)
(113)
41
-18%
-20%
132%
-26%
-32%
21%
For the Years Ended December 31,
2016
2015
2014
Operating Margin
Noncontrolling Interests Adjustment (1)
Derivatives Adjustment
Adjusted Operating Margin
Adjusted PTC
Proportional Free Cash Flow
$
$
$
$
259
(33)
(1)
225
187
552
$
$
$
$
303
(30)
3
276
235
238
$
$
$
$
403
(26)
(4)
373
348
197
_____________________________
(1)
See Item 1. Business for the respective ownership interest for key business.
100
Fiscal year 2016 versus 2015
Including the unfavorable impact of foreign currency translation of $36 million, operating margin decreased
$44 million, or 15%, which was driven primarily by the following:
Kazakhstan
Unfavorable FX impact due to KZT depreciation against USD
Other
Total Kazakhstan Decrease
Maritza
Lower contracted capacity prices due to PPA amendment
Other
Total Maritza Decrease
Ballylumford
Higher contracted revenues
Lower plant capacity resulting from the retirement of one generation facility
Total Ballylumford Increase
Total Europe SBU Operating Margin Decrease
$
$
(29)
(1)
(30)
(18)
(2)
(20)
27
(21)
6
(44)
Adjusted Operating Margin decreased $51 million due to the drivers above adjusted for noncontrolling
interests and excluding unrealized gains and losses on derivatives.
Adjusted PTC decreased $48 million, driven primarily by the decrease of $51 million in Adjusted Operating
Margin described above.
Proportional Free Cash Flow increased $314 million, primarily driven by $360 million of increased collections
at Maritza from NEK, net of payments to the fuel supplier (MMI), and a decrease in maintenance and non-
recoverable environmental capital expenditures of $21 million. These favorable increases were partially offset by
the $51 million decrease in Adjusted Operating Margin and a $24 million decrease in CO2 allowances due to a price
decrease.
Fiscal year 2015 versus 2014
Including the unfavorable impact of foreign currency translation of $47 million, operating margin decreased
$100 million, or 25%, which was driven primarily by the following:
Maritza
Unfavorable FX impacts due to Euro depreciation against USD
Lower rates due to non-operating costs passed through the tariff
Higher availability in 2015
Total Maritza Decrease
Kilroot
Lower dispatch and lower market prices due to gas/coal spread as well as lower capacity prices
Higher fixed costs primarily driven by maintenance cost due to timing of outages
Lower depreciation due to impairment in Q3 2015
Other
Total Kilroot Decrease
Ballylumford
Lower availability and lower capacity prices
Write down of non-primary fuel inventory
Total Ballylumford Decrease
Other
Reduction due to the sale of Ebute in 2014
Lower Heat Rate margin at Jordan
Total Other Decrease
Total Europe SBU Operating Margin Decrease
$
(30)
(8)
8
(30)
(23)
(3)
7
1
(18)
(8)
(4)
(12)
(34)
(6)
(40)
(100)
$
Adjusted Operating Margin decreased $97 million due to the drivers above adjusted for noncontrolling
interests and excluding unrealized gains and losses on derivatives.
Adjusted PTC decreased $113 million, driven by the decrease of $97 million in Adjusted Operating Margin
described above, and by higher depreciation and unfavorable FX impact from Elsta as well as unfavorable impact
due to the reversal of a liability in 2014 in Kazakhstan. These results partially offset by lower interest expenses in
Bulgaria.
Proportional Free Cash Flow increased $41 million, primarily driven by $69 million of increased collections at
Maritza from NEK, net of payments to the fuel supplier (MMI), a $22 million benefit at IPP4 Jordan due to the
commencement of operations in July 2014, and lower interest expense of $38 million due primarily to the sale of UK
Wind in 2014. These favorable increases were partially offset by the $97 million decrease in Adjusted Operating
101
Margin described above.
ASIA SBU
A summary of Operating Margin, Adjusted Operating Margin, Adjusted PTC, and Proportional Free Cash Flow
($ in millions) is as follows:
For the Years Ended December 31,
2016
2015
2014
Operating Margin
Noncontrolling Interests Adjustment (1)
Derivatives Adjustment
Adjusted Operating Margin
Adjusted PTC
Proportional Free Cash Flow
_____________________________
$
$
$
$
170
(91)
1
80
96
136
$
$
$
$
149
(79)
—
70
96
87
$
$
$
$
76
(25)
—
51
46
82
(1)
See Item 1. Business for the respective ownership interest for key business.
Fiscal year 2016 versus 2015
$ Change
2016 vs. 2015
21
$
$ Change
2015 vs. 2014
73
$
% Change
2016 vs. 2015
14%
% Change
2015 vs. 2014
96%
$
$
$
$
10
— $
$
49
19
50
5
14%
—%
56%
37%
109%
6%
Operating margin increased $21 million, or 14%, which was driven primarily by the following:
Mong Duong
Impact of full year operations for 2016 compared to commencement of principal operations in April 2015
Total Mong Duong Increase
Other business drivers
Total Asia SBU Operating Margin Increase
$
$
16
16
5
21
Adjusted Operating Margin increased $10 million due to the drivers above adjusted for the impact of
noncontrolling interests.
Adjusted PTC was neutral driven by the increase of $10 million in Adjusted Operating Margin described above
offset by lower equity earnings at OPGC in India due to lower tariffs and the net impact of higher interest expense
and higher interest income at Mong Duong.
Proportional Free Cash Flow increased $49 million, primarily driven by a decrease of $29 million in working
capital requirements at Mong Duong due to a build up in the prior year in preparation for commencement of plant
operations, and an increase in Adjusted Operating Margin of $35 million (net of non-cash service concession
expense of $24 million). These positive impacts were partially offset by higher interest expense of $18 million as
interest is no longer capitalized as part of service concession asset expenditures.
Fiscal year 2015 versus 2014
Operating margin increased $73 million, or 96%, which was driven primarily by the following:
Masinloc
Higher availability
One-time unfavorable impact in 2014 due to market operator's retrospective adjustment to energy prices in Nov and Dec 2013
Lower fixed costs and lower tax assessments in 2015 relative to 2014
Other
Total Masinloc Increase
Mong Duong
Commencement of principal operations in April 2015
Total Mong Duong Increase
Other Business Drivers
Total Asia SBU Operating Margin Increase
$
$
27
15
7
3
52
24
24
(3)
73
Adjusted Operating Margin increased $19 million due to the drivers above adjusted for the impact of
noncontrolling interests.
Adjusted PTC increased $50 million, driven by the increase of $19 million in Adjusted Operating Margin
described above, and the additional net impact of $28 million at Mong Duong due to a component of service
concession revenue recognized as interest income, net of higher interest expense as interest is no longer
capitalized. See Note 1—General and Summary of Significant Accounting Policies in Part II.—Item 8.—Financial
Statements and Supplementary Data for further information regarding the accounting for service concession
arrangements.
Proportional Free Cash Flow increased $5 million, primarily driven by an increase in Adjusted Operating
Margin of $28 million (net of $9 million in non-cash items, primarily service concession expense and the
102
retrospective adjustment to energy prices noted above), and $58 million in higher interest income recognized at
Mong Duong as a result of the financing component under service concession accounting. These positive impacts
were partially offset by $26 million in higher working capital requirements at Mong Duong due to a build-up in
preparation of the commencement of operations, $22 million in higher interest payments at Mong Duong, $11
million of higher tax payments at Masinloc, and $9 million in higher working capital requirements at Masinloc due
primarily to the timing of coal purchases.
Key Trends and Uncertainties
During 2017 and beyond, we expect to face the following challenges at certain of our businesses.
Management expects that improved operating performance at certain businesses, growth from new businesses and
global cost reduction initiatives may lessen or offset their impact. If these favorable effects do not occur, or if the
challenges described below and elsewhere in this section impact us more significantly than we currently anticipate,
or if volatile foreign currencies and commodities move more unfavorably, then these adverse factors (or other
adverse factors unknown to us) may impact our operating margin, net income attributable to The AES Corporation
and cash flows. We continue to monitor our operations and address challenges as they arise. For the risk factors
related to our business, see Item 1.—Business and Item 1A.—Risk Factors of this Form 10-K.
Macroeconomic and Political
During 2016, the political environments in some countries where our subsidiaries conduct business have
changed which could result in significant impacts to tax laws, and environmental and energy policies. Additionally,
we operate in multiple countries and as such are subject to volatility in exchange rates at the subsidiary level. See
Item 7A.—Quantitative and Qualitative Disclosures About Market Risk for further information.
Brazil — President Michel Temer, with majority congressional support, continues to implement the fiscal
reforms needed to improve the country’s finances. While uncertainty dominates the political arena, if enacted,
President Temer's market reforms would improve the the economic outlook, which may benefit our businesses in
Brazil.
In October 2016, AES completed the sale of the Company's 100% ownership interest in AES Sul and
recognized an after-tax loss on disposal of $737 million. This after-tax loss excludes the impact of contingent
proceeds linked to the favorable settlement of pending litigation, which is not guaranteed. If the case is decided in
the Company's favor, amounts would be remitted to AES over an unknown period of time. Any potential gain from
the eventual resolution of this contingency would be presented separately as Discontinued Operations.
United Kingdom — On June 23, 2016, the United Kingdom (U.K.) held a referendum in which voters approved
an exit from the European Union (“E.U.”), commonly referred to as “Brexit”. As a result of the referendum, it is
expected that the British government will begin negotiating the terms of the U.K.’s future relationship with the E.U.
Although it is unclear what the long-term global implications will be, it is possible that the European or U.K.
economy could weaken and our businesses may experience a decline in demand. While the full impact of the Brexit
is uncertain, these changes may adversely affect our operations and financial results. The most immediate impact
has been a devaluation of the pound and euro against the U.S. dollar. For 2016 and 2017, the Company has
hedged against these foreign currency movements, however, the impact could be greater in future years.
Puerto Rico — Our subsidiaries in Puerto Rico have long term PPAs with state-owned PREPA. Due to the
ongoing economic situation in the territory, PREPA faces significant financial challenges. There have been no
significant adverse impacts to AES Puerto Rico due to PREPA’s financial challenges.
If PREPA continues to face challenges, or those challenges worsen, or otherwise impact PREPA’s ability to
make payments to AES Puerto Rico, there could be a material impact on the Company.
United States of America — The outcome of the 2016 U.S. elections could result in significant changes to U.S.
tax laws, and environmental and energy policies, the impact of which is uncertain.
Philippines — The outcome of the 2016 Philippines election could result in changes in policies towards the
U.S., China or other nations the impact of which on our business is uncertain.
Foreign Exchange and Commodities
Our businesses are exposed to and proactively manage market risk. Our primary market risk exposure is to
the price of commodities, particularly electricity, oil, natural gas, coal and environmental credits. In 2016, there were
more than 50% improvement in both oil and natural gas prices, which had a positive impact on our businesses in
the Dominican Republic, Ohio and Northern Ireland. Since we operate in multiple countries, we are subject to
volatility in exchange rates at varying degrees at the subsidiary level and between our functional currency, the U.S.
103
Dollar, and currencies of the countries in which we operate. In 2016, we had a significant devaluation in the
Argentine Peso. The Brazilian Real, Colombian Peso and Kazakhstani Tenge recovered during the year, but remain
devalued as compared to the beginning of 2015, which had an offsetting impact on our 2016 results. For additional
information, refer to Item 7A.—Quantitative and Qualitative Disclosures About Market Risk.
Alto Maipo
During 2016, the Alto Maipo project in Chile experienced technical difficulties in construction which resulted in
an increase in projected costs of up to 22% over the original $2 billion budget. These additional costs have led to a
series of negotiations with the main contractors, financiers and partners of the project, with the intention to
restructure the existing financing and obtain additional financing to guarantee project completion. On January 19,
2017, the parties agreed on the basis of the restructuring process, including new project milestones. These
agreements are subject to the negotiation and finalization of the specific restructuring terms and conditions; and the
negotiation and approval of the terms and conditions of each of the financing documents. Currently, the Company's
indirect equity interest in the project is 40%.
Impairments
Long-lived Assets — During the year ended December 31, 2016, the Company recognized asset impairment
expense of $1.1 billion. Due to decreased wind production and a decline in forward power curves in 2016, the
Company tested the recoverability of its long-lived assets at Buffalo Gap I, II, and III. After recognizing asset
impairment expense of $236 million at Buffalo Gap I and II, the carrying value of the long-lived asset groups at
Buffalo Gap I, II, and III totaled $242 million at December 31, 2016.
Additionally, the Company recognized an asset impairment expense of $859 million at DPL in 2016. After
recognizing asset impairment expense at DPL, the carrying value of the long-lived asset groups at DPL, including
those that were not impaired, totaled $498 million at December 31, 2016. See Note 20—Asset Impairment Expense
in Item 8.—Financial Statements and Supplementary Data for further information regarding the impairments at
Buffalo Gap and DPL.
Events or changes in circumstances that may necessitate further recoverability tests and potential
impairments of long-lived assets may include, but are not limited to, adverse changes in the regulatory environment,
unfavorable changes in power prices or fuel costs, increased competition due to additional capacity in the grid,
technological advancements, declining trends in demand, or an expectation that it is more likely than not that the
asset will be disposed of before the end of its previously estimated useful life.
Goodwill — The Company currently has no reporting units considered to be "at risk." A reporting unit is
considered "at risk" when its fair value is not higher than its carrying amount by more than 10%. The Company
monitors its reporting units at risk of Step 1 failure on an ongoing basis. It is possible that the Company may incur
goodwill impairment charges at any reporting units containing goodwill in future periods if adverse changes in their
business or operating environments occur. See Note 9—Goodwill and Other Intangible Assets in Item 8.—Financial
Statements and Supplementary Data for further information.
Capital Resources and Liquidity
Overview — As of December 31, 2016, the Company had unrestricted cash and cash equivalents of $1.3
billion, of which $100 million was held at the Parent Company and qualified holding companies. The Company also
had $798 million in short term investments, held primarily at subsidiaries. In addition, we had restricted cash and
debt service reserves of $871 million. The Company also had non-recourse and recourse aggregate principal
amounts of debt outstanding of $15.8 billion and $4.7 billion, respectively. Of the approximately $1.3 billion of our
current non-recourse debt, $1.2 billion was presented as such because it is due in the next twelve months and $128
million relates to debt considered in default due to covenant violations. The defaults are not payment defaults, but
are instead technical defaults triggered by failure to comply with other covenants and/or other conditions such as
(but not limited to) failure to meet information covenants, complete construction or other milestones in an allocated
time, meet certain minimum or maximum financial ratios, or other requirements contained in the non-recourse debt
documents of the Company.
104
We expect such current maturities will be repaid from net cash provided by operating activities of the
subsidiary to which the debt relates or through opportunistic refinancing activity or some combination thereof. None
of our recourse debt matures within the next twelve months. From time to time, we may elect to repurchase our
outstanding debt through cash purchases, privately negotiated transactions or otherwise when management
believes that such securities are attractively priced. Such repurchases, if any, will depend on prevailing market
conditions, our liquidity requirements and other factors. The amounts involved in any such repurchases may be
material.
We rely mainly on long-term debt obligations to fund our construction activities. We have, to the extent
available at acceptable terms, utilized non-recourse debt to fund a significant portion of the capital expenditures and
investments required to construct and acquire our electric power plants, distribution companies and related assets.
Our non-recourse financing is designed to limit cross default risk to the Parent Company or other subsidiaries and
affiliates. Our non-recourse long-term debt is a combination of fixed and variable interest rate instruments.
Generally, a portion or all of the variable rate debt is fixed through the use of interest rate swaps. In addition, the
debt is typically denominated in the currency that matches the currency of the revenue expected to be generated
from the benefiting project, thereby reducing currency risk. In certain cases, the currency is matched through the
use of derivative instruments. The majority of our non-recourse debt is funded by international commercial banks,
with debt capacity supplemented by multilaterals and local regional banks.
Given our long-term debt obligations, the Company is subject to interest rate risk on debt balances that accrue
interest at variable rates. When possible, the Company will borrow funds at fixed interest rates or hedge its variable
rate debt to fix its interest costs on such obligations. In addition, the Company has historically tried to maintain at
least 70% of its consolidated long-term obligations at fixed interest rates, including fixing the interest rate through
the use of interest rate swaps. These efforts apply to the notional amount of the swaps compared to the amount of
related underlying debt. Presently, the Parent Company's only material un-hedged exposure to variable interest rate
debt relates to indebtedness under its floating rate senior unsecured notes due 2019. On a consolidated basis, of
the Company's $20.5 billion of total debt outstanding as of December 31, 2016, approximately $3.5 billion bore
interest at variable rates that were not subject to a derivative instrument which fixed the interest rate. Brazil holds
$1.3 billion of our floating rate non-recourse exposure as we have no ability to fix local debt interest rates efficiently.
In addition to utilizing non-recourse debt at a subsidiary level when available, the Parent Company provides a
portion, or in certain instances all, of the remaining long-term financing or credit required to fund development,
construction or acquisition of a particular project. These investments have generally taken the form of equity
investments or intercompany loans, which are subordinated to the project's non-recourse loans. We generally
obtain the funds for these investments from our cash flows from operations, proceeds from the sales of assets and/
or the proceeds from our issuances of debt, common stock and other securities. Similarly, in certain of our
businesses, the Parent Company may provide financial guarantees or other credit support for the benefit of
counterparties who have entered into contracts for the purchase or sale of electricity, equipment or other services
with our subsidiaries or lenders. In such circumstances, if a business defaults on its payment or supply obligation,
the Parent Company will be responsible for the business' obligations up to the amount provided for in the relevant
guarantee or other credit support. At December 31, 2016, the Parent Company had provided outstanding financial
and performance-related guarantees or other credit support commitments to or for the benefit of our businesses,
which were limited by the terms of the agreements, of approximately $535 million in aggregate (excluding those
collateralized by letters of credit and other obligations discussed below).
As a result of the Parent Company's below investment grade rating, counterparties may be unwilling to accept
our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing
commitments, the Parent Company may be required to provide some other form of assurance, such as a letter of
credit, to backstop or replace our credit support. The Parent Company may not be able to provide adequate
assurances to such counterparties. To the extent we are required and able to provide letters of credit or other
collateral to such counterparties, this will reduce the amount of credit available to us to meet our other liquidity
needs. At December 31, 2016, we had $6 million in letters of credit outstanding, provided under our senior secured
credit facility, $245 million in letters of credit outstanding, provided under our un-senior secured credit facility and $3
million in cash collateralized letters of credit outstanding outside of our senior secured credit facility. These letters of
credit operate to guarantee performance relating to certain project development activities and business operations.
During the year ended December 31, 2016, the Company paid letter of credit fees ranging from 0.2% to 2.5% per
annum on the outstanding amounts.
We expect to continue to seek, where possible, non-recourse debt financing in connection with the assets or
businesses that we or our affiliates may develop, construct or acquire. However, depending on local and global
market conditions and the unique characteristics of individual businesses, non-recourse debt may not be available
105
on economically attractive terms or at all. If we decide not to provide any additional funding or credit support to a
subsidiary project that is under construction or has near-term debt payment obligations and that subsidiary is
unable to obtain additional non-recourse debt, such subsidiary may become insolvent, and we may lose our
investment in that subsidiary. Additionally, if any of our subsidiaries lose a significant customer, the subsidiary may
need to withdraw from a project or restructure the non-recourse debt financing. If we or the subsidiary choose not to
proceed with a project or are unable to successfully complete a restructuring of the non-recourse debt, we may lose
our investment in that subsidiary.
Many of our subsidiaries depend on timely and continued access to capital markets to manage their liquidity
needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and
other commitments during times of political or economic uncertainty may have material adverse effects on the
financial condition and results of operations of those subsidiaries. In addition, changes in the timing of tariff
increases or delays in the regulatory determinations under the relevant concessions could affect the cash flows and
results of operations of our businesses.
Long-Term Receivables — As of December 31, 2016, the Company had approximately $264 million of
accounts receivable classified as Noncurrent assets—other related to certain of its generation businesses in
Argentina and the U.S. and its utility business in Brazil. The noncurrent portion primarily consists of accounts
receivable in Argentina that, pursuant to amended agreements or government resolutions, have collection periods
that extend beyond December 31, 2017, or one year from the latest balance sheet date. The majority of Argentinian
receivables have been converted into long-term financing for the construction of power plants. See Note 6—
Financing Receivables included in Item 8.—Financial Statements and Supplementary Data and Item 1.—Business
—Regulatory Matters—Argentina of this Form 10-K for further information.
Consolidated Cash Flows
The following table reflects the changes in operating, investing, and financing cash flows for the comparative
twelve month periods (in millions):
Cash flows provided by (used in):
Operating activities
Investing activities
Financing activities
Operating Activities
2016
December 31,
2015
2014
2016 vs. 2015
2015 vs. 2014
$ Change
$
$
2,884
(2,108)
(747)
$
2,134
(2,366)
28
$
1,791
(656)
(1,262)
$
750
258
(775)
343
(1,710)
1,290
The following table summarizes the key components of our consolidated operating cash flows (in millions):
2016
December 31,
2015
2014
2016 vs. 2015
2015 vs. 2014
$ Change
Net Income (Loss)
Depreciation and amortization
Impairment expenses
Loss on the extinguishment of debt
Deferred Income Taxes
Other adjustments to net income
Non-cash adjustments to net income
Net income, adjusted for non-cash items
Net change in operating assets and liabilities (1)
Net cash provided by operating activities (2)
_____________________________
$
$
$
(777) $
1,176
2,481
20
(793)
225
3,109
2,332
552
2,884
$
$
762
1,144
602
186
(50)
(73)
1,809
2,571
(437)
2,134
$
$
$
1,147
1,245
433
261
47
(320)
1,666
2,813
(1,022)
1,791
$
$
$
(1,539) $
32
1,879
(166)
(743)
298
1,300
(239) $
989
750
$
(385)
(101)
169
(75)
(97)
247
143
(242)
585
343
(1) Refer to the table below for explanations of the variance in operating assets and liabilities.
(2)
Amounts included in the table above include the results of discontinued operations, where applicable.
106
Fiscal Year 2016 versus 2015
The variance of $989 million in changes in operating assets and liabilities for the year ended December 31,
2016 compared to the year ended December 31, 2015 was driven by (in millions):
Decreases in:
Other assets, primarily long-term regulatory assets at Eletropaulo and service concession assets at Vietnam
Accounts receivable, primarily at Maritza and Eletropaulo
Prepaid expenses and other current assets, primarily regulatory assets at Eletropaulo and Sul
Accounts payable and other current liabilities, primarily at Eletropaulo and Sul
Income taxes payable, net and other taxes payable, primarily at Tietê, Chivor and Gener
Other operating assets and liabilities
Total increase in cash from changes in operating assets and liabilities
$
$
1,054
615
215
(651)
(252)
8
989
Fiscal Year 2015 versus 2014
The variance of $585 million in changes in operating assets and liabilities for the year ended December 31,
2015 compared to the year ended December 31, 2014 was driven by (in millions):
Decreases in:
Prepaid expenses and other current assets, primarily at Eletropaulo, Gener and DPL
Accounts receivable, primarily at Andres and Itabo Opco
Other operating assets and liabilities
Increases in:
Income tax payables, net and other tax payables, primarily at Tietê and Gener
Accounts payable and other current liabilities, primarily at Eletropaulo, Sul and Tietê
Other assets, primarily long-term regulatory assets at Eletropaulo and Sul and service concession assets at Mong Duong
Total increase in cash from changes in operating assets and liabilities
$
$
728
142
39
142
116
(582)
585
Investing Activities
Fiscal Year 2016 versus 2015
Net cash used in investing activities decreased $258 million for the year ended December 31, 2016 compared
to December 31, 2015, which was primarily driven by (in millions):
Increases in:
Capital expenditures (1)
Acquisitions, net of cash acquired (primarily Distributed Energy)
Proceeds from the sales of businesses, net of cash sold (primarily related to sales of DPLER and Sul)
Net purchases of short-term investments
Decreases in:
Restricted cash, debt service and other assets
Other investing activities
Total decrease in net cash used in investing activities
_____________________________
(1) Refer to the tables below for a breakout of capital expenditure by type and by primary business driver.
Capital Expenditures
$
$
(37)
(38)
493
(297)
98
39
258
The following table summarizes the Company's capital expenditures for growth investments, maintenance and
environmental reported in investing cash activities for the periods indicated (in millions):
Growth Investments
Maintenance
Environmental (1)
Total capital expenditures
_____________________________
2016
(1,510) $
(617)
(218)
(2,345) $
$
$
2015
(1,401) $
(606)
(301)
(2,308) $
(109)
(11)
83
(37)
December 31,
$ Change
2016 vs. 2015
(1)
Includes both recoverable and non-recoverable environmental capital expenditures. See SBU Performance Analysis for more information.
107
Cash used for capital expenditures increased by $37 million for the year ended December 31, 2016 compared
to December 31, 2015, which was primarily driven by (in millions):
Increases in:
Growth expenditures at the Asia SBU, primarily due to investments at Masinloc related to the construction of a coal-fired plant, a
battery storage project, and retrofit related costs
Growth expenditures at the MCAC SBU, primarily due to the construction of a natural gas-fired generation plant in Panama and
construction of a combined cycle project at Los Mina in the Dominican Republic
Decreases in:
Growth expenditures at the Andes SBU, primarily due to lower spending related to Cochrane and the Andes Solar plant; partially
offset by higher investments in the Alto Maipo construction project
Growth expenditures at the US SBU, primarily due to lower spending related to the CCGT and Transmission & Distribution projects at
IPALCO
Maintenance and environmental expenditures at the US SBU, primarily due to lower spending related to MATS compliance and the
conversion of Harding Street Stations 5, 6 and 7 to natural gas upon being placed into service in late 2015 and early 2016; partially
offset by higher spending on CCR compliance
Other capital expenditures
Total increase in net cash used for capital expenditures
Fiscal Year 2015 versus 2014
$ (124)
(266)
280
20
63
(10)
$ (37)
Net cash used in investing activities increased $1.7 billion for the year ended December 31, 2015 compared to
December 31, 2014, which was primarily driven by (in millions):
Increases in:
Capital expenditures (1)
Restricted cash, debt service and other assets
Decreases in:
Proceeds from sales of businesses (primarily related to the Guacolda and Masinloc transactions in 2014)
Acqusitions, net of cash acquired (primarily related to the Guacolda transaction in 2014)
Net purchases of short-term investments
Other investing activities
Total increase in net cash used in investing activities
_____________________________
(1) Refer to the tables below for a breakout of capital expenditures by type and by primary business driver.
$
$
(292)
(578)
(1,669)
711
170
(52)
(1,710)
The following table summarizes the Company's capital expenditures for growth investments, maintenance and
environmental for the periods indicated (in millions):
December 31,
$ Change
2015 vs. 2014
Growth Investments
Maintenance
Environmental (1)
Total capital expenditures
_____________________________
2015
(1,401) $
(606)
(301)
(2,308) $
$
$
2014
(1,151) $
(645)
(220)
(2,016) $
(1)
Includes both recoverable and non-recoverable environmental capital expenditures. See SBU Performance Analysis for more information.
Cash used for capital expenditures increased by $292 million for the year ended December 31, 2015
compared to December 31, 2014, which was primarily driven by (in millions):
Increases in:
Growth expenditures at the Andes SBU, primarily due to higher spending on Cochrane projects
Growth expenditures at the US SBU, primarily due to higher spending on the CCGT, Transmission & Distribution projects and a
battery storage project at IPALCO
Maintenance and environmental expenditures at the US SBU, primarily due to higher spending on the NPDES compliance and
Harding Street refueling projects as they began in 2015; partially offset by lower spending on MATS compliance
Decreases In:
Growth expenditures at Mong Duong due to the adoption of service concession accounting in 2015
Growth expenditures at Jordan due to the completion of IPP4 plant construction
Other capital expenditures
Total increase in net cash used for capital expenditures
108
(250)
39
(81)
(292)
$
(271)
(192)
(98)
111
72
86
(292)
$
Financing Activities
Net cash used in financing activities increased $775 million for the year ended December 31, 2016 compared
to December 31, 2015, which was primarily driven by (in millions):
Increases in:
Distributions to noncontrolling interests, primarily at the Brazil SBU
Contributions from noncontrolling interests, primarily at the MCAC SBU
Decreases in:
Net issuance of non-recourse debt, primarily at the Andes and Brazil SBUs
Proceeds from the sale of redeemable stock of subsidiaries at IPALCO
Proceeds from sales to noncontrolling interests, net of transaction costs
Purchases of treasury stock by the Parent Company
Net repayments of recourse debt at the Parent Company (1)
Other financing activities
Total increase in net cash used in financing activities
_____________________________
$
$
(150)
64
(624)
(327)
(154)
403
32
(19)
(775)
(1)
See Note 11—Debt in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for more information regarding significant recourse debt
transactions.
Net cash provided by financing activities increased $1.3 billion for the year ended December 31, 2015
compared to the year ended December 31, 2014, which was primarily driven by (in millions):
Increases in:
Proceeds from the sale of redeemable stock of subsidiaries at IPALCO
Net issuance of non-recourse debt, primarily at the Andes and Brazil SBUs
Proceeds from sales to noncontrolling interests, net of transaction costs
Dividends paid on The AES Corporation common stock
Purchases of treasury stock by the Parent Company
Decreases in:
Net repayments of recourse debt at the Parent Company (1)
Payments for financed capital expenditures, primarily at the Andes and Asia SBUs
Other financing activities
Total increase in net cash provided by financing activities
_____________________________
$
$
461
238
71
(132)
(174)
252
378
196
1,290
(1)
See Note 11—Debt in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for more information regarding significant recourse debt
transactions.
109
Segment Operating Cash Flow Analysis
Operating Cash Flow (1)
US
Andes
Brazil
MCAC
Europe
Asia
Corporate
Total SBUs
2016
$
912
475
716
312
637
255
(423)
$ 2,884
Operating Cash Flow by SBU
2016/2015
Change
2014
2015
2015/2014
Change
$
845
462
136
705
339
15
(368)
$ 2,134
$
830
359
316
370
292
105
(481)
$ 1,791
$
$
67
13
580
(393)
298
240
(55)
750
$
$
15
103
(180)
335
47
(90)
113
343
_____________________________
(1) Operating cash flow as presented above include the effect of intercompany transactions with other segments except for interest, tax sharing, charges for
management fees and transfer pricing.
US SBU
Fiscal Year 2016 versus 2015
The increase in Operating Cash Flow of $67 million was driven primarily by the following (in millions):
US SBU 2016 vs. 2015
Timing of payments for accounts payable and consumption of inventory, primarily due to lower inventory purchases from
inventory optimization efforts
Net impact of receivable settlements related to the 2016 sale of DPLER and the 2015 sale of MC2
Lower payments for interest expense, primarily due to debt repayments at DPL, and lower interest rates
Timing of receivables collections, primarily due to higher rates at IPL, favorable weather in Q4 2016, and the impact of
DPLER's declining customer base in 2015
Lower operating margin, net of non-cash items (primarily depreciation of $28 and an $18 accrual impact from IPL's new rates)
Other
Total US SBU Operating Cash Increase
$
$
142
17
16
(97)
(21)
10
67
110
Fiscal Year 2015 versus 2014
The increase in Operating Cash Flow of $15 million was driven primarily by the following (in millions):
US SBU 2015 vs. 2014
Decrease in Operating Margin, net of non-cash items (primarily depreciation of $6)
Collection of previously deferred storm costs at DPL
One-time payment occurring in 2014 at DPL to terminate an unfavorable coal contract
Settlement of receivables related to the sale of MC2
Favorable timing of inventory purchases and power purchase payments
Increased A/R collections at IPL
Other
Total US SBU Operating Cash Increase
ANDES SBU
$
$
(84)
22
19
16
25
12
5
15
Fiscal Year 2016 versus 2015
The increase in Operating Cash Flow of $13 million was driven primarily by the following (in millions):
Andes SBU 2016 vs. 2015
Higher operating margin, net of non-cash items (primarily depreciation of $44)
Higher collections at Chivor, primarily due to increased sales in Q4 2015
Collections of FONINVEMEM III receivables in Argentina, primarily as result of the commencement of operations at Termoelectrica
Guillermo Brown in 2016
Impact from a prior year payment to unwind an interest rate swap as part of the Ventanas refinancing in July 2015
Lower VAT refunds due to projects entering COD at Cochrane and the timing of VAT Refunds at Alto Maipo
Higher interest payments due primarily to new unsecured notes issued by Gener in July 2015 as part of the Ventanas refinancing
Higher tax payments in Chile, primarily due to withholding taxes paid on Chilean distributions to AES affiliates
Increase in income tax payments due to higher taxable income at Chivor
Timing of collections at Gener
Other
Total Andes SBU Operating Cash Increase
Fiscal Year 2015 versus 2014
The increase in Operating Cash Flow of $103 million was driven primarily by the following (in millions):
Andes SBU 2015 vs. 2014
Higher VAT refunds due to the construction of the Cochrane and Alto Maipo plants
Timing of non-recurring maintenance collections in Argentina
Lower interest payments at Chivor
Higher income tax payments at Chivor due to an increase in the tax rate and advance payments made in 2015
Lower collections on contract sales at Chivor
Impact from payments to unwind an interest rate swap as part of the Ventanas refinancing in July 2015
Other
Total Andes SBU Operating Cash Increase
$
$
$
$
58
83
57
38
(107)
(29)
(29)
(28)
(22)
(8)
13
153
27
15
(37)
(36)
(38)
19
103
111
BRAZIL SBU
Fiscal Year 2016 versus 2015
The increase in Operating Cash Flow of $580 million was driven primarily by the following (in millions):
Brazil SBU 2016 vs. 2015
Lower operating margin (1), net of non-cash items (primarily a net $45 impact from contingency items at Eletropaulo)
Timing of payments at Eletropaulo and Sul related to regulatory charges and tariff flags due to improved hydrology in 2016
Collections of higher costs deferred in net regulatory assets at Eletropaulo and Sul as result of unfavorable hydrology in prior
periods
Timing of collections on energy sales in the current year
Lower energy purchases at Tietê in the current year as result of favorable hydrology
Timing of non-income tax payments
Other
Total Brazil SBU Operating Cash Increase
____________________________
$ (308)
(581)
974
416
93
28
(42)
580
$
(1)
Includes the results of AES Sul, which is excluded from continuing operations in the Condensed Consolidated Statements of Operations but is included within
operating cash flow on the Condensed Consolidated Statements of Cash Flows. See Note 22 of Item 8.—Notes to Condensed Consolidated Financial
Statements within this Form 10-K for further information.
Fiscal Year 2015 versus 2014
The decrease in Operating Cash Flow of $180 million was driven primarily by the following (in millions):
Brazil SBU 2015 vs. 2014
Lower operating margin (1), net of non-cash items (primarily a net $38 impact from contingency items at Eletropaulo)
Timing of energy purchases in the spot market at Tietê at higher prices
Timing of collections at Eletropaulo due to higher tarriffs
Higher interest payments at Sul due to higher debt and a higher interest rate
Timing of payments at Eletropaulo and Sul related to regulatory charges and tariff flags due to unfavorable hydrology
Lower income tax payments at Tietê due to lower taxable income in 2014
Collections of higher costs deferred in net regulatory assets at Eletropaulo and Sul as result of unfavorable hydrology in prior
periods
Other
Total Brazil SBU Operating Cash Decrease
____________________________
$ (179)
(241)
(41)
(17)
181
127
53
(63)
$ (180)
(1)
Includes the results of AES Sul, which is excluded from continuing operations in the Condensed Consolidated Statements of Operations but is included within
operating cash flow on the Condensed Consolidated Statements of Cash Flows. See Note 22 of Item 8.—Notes to Condensed Consolidated Financial
Statements within this Form 10-K for further information
112
MCAC SBU
Fiscal Year 2016 versus 2015
The decrease in Operating Cash Flow of $393 million was driven primarily by the following (in millions):
MCAC SBU 2016 vs. 2015
Collection of overdue receivables in September 2015 from distribution companies in the Dominican Republic
Lower operating margin, net of non-cash items (primarily depreciation of $10)
Lower collections from the off-taker in Puerto Rico, primarily due to lower sales from Q4 2015
Compensation received in the prior year due to an early termination of the barge PPA by the off-taker in Panama
Higher withholding taxes paid on dividend distributions to AES affiliates in the Dominican Republic
Higher tax payments due to higher taxable income in El Salvador
Other
Total MCAC SBU Operating Cash Decrease
Fiscal Year 2015 versus 2014
The increase in Operating Cash Flow of $335 million was driven primarily by the following (in millions):
MCAC SBU 2015 vs. 2014
Higher collections on contract sales in Panama
Collection of overdue receivables in September 2015 from distribution companies in the Dominican Republic
Lower energy purchases due to a decrease in fuel prices in El Salvador
Timing of collections from the off-taker in Puerto Rico
Compensation received due to an early termination of the barge PPA by the off-taker in Panama
Other
Total MCAC SBU Operating Cash Increase
EUROPE SBU
$ (243)
(55)
(47)
(20)
(16)
(17)
5
$ (393)
$
$
27
243
22
45
20
(22)
335
113
Fiscal Year 2016 versus 2015
The increase in Operating Cash Flow of $298 million was driven primarily by the following (in millions):
Europe SBU 2016 vs. 2015
Increase in collections at Maritza from NEK (off-taker), net of payments to MMI (fuel supplier)
Timing of vendor payments
Lower operating margin, net of non cash items (primarily lower depreciation of $18)
Decrease in CO2 allowances due to a price decrease
Other
Total Europe SBU Operating Cash Increase
Fiscal Year 2015 versus 2014
The increase in Operating Cash Flow of $47 million was driven primarily by the following (in millions):
Europe SBU 2015 vs. 2014
Increase in collections at Maritza from NEK (off-taker), net of payments to MMI (fuel supplier)
Favorable timing of collections at IPP4
Lower operating margin
Lower payments for interest expense
Other
Total Europe SBU Operating Cash Increase
ASIA SBU
Fiscal Year 2016 versus 2015
The increase in Operating Cash Flow of $240 million was driven primarily by the following (in millions):
Asia SBU 2016 vs. 2015
Reduction in service concession asset expenditures, net of previously capitalized interest payments
Higher operating margin, net of an increase of $48 in non-cash service concession amortization
Decrease in working capital requirements at Mong Duong as the plant was fully operational in 2016
Higher interest income as a result of the financing component under service concession accounting
Other
Total Asia SBU Operating Cash Increase
Fiscal Year 2015 versus 2014
The decrease in Operating Cash Flow of $90 million was driven primarily by the following (in millions):
Asia SBU 2015 vs. 2014
Service concession asset expenditures at Mong Duong
Increase in interest payments at Mong Duong
Higher working capital at Mong Duong, due to a build-up in preparation for commencement of plant operations
Higher working capital at Masinloc, due primarily to the timing of coal purchases
Higher tax payments at Masinloc
Higher interest income as a result of the financing component under service concession accounting
Higher operating margin, net of non-cash items (primarily $33 in service concession amortization and a $15 retrospective
adjustment to energy prices in 2014)
Other
Total Asia SBU Operating Cash Decrease
114
$
$
$
$
360
47
(92)
(24)
7
298
69
34
(102)
42
4
47
$
$
98
69
58
34
(19)
240
$ (165)
(44)
(50)
(17)
(21)
115
91
1
(90)
$
CORPORATE AND OTHER
Fiscal Year 2016 versus 2015
The decrease in Operating Cash Flow of $55 million was driven primarily by the following (in millions):
Corporate and Other 2016 vs. 2015
Lower interest payments due principal repayments on debt
Decrease in cash from net settlements of FX and oil derivatives
Higher payments for people-related costs, primarily due to health benefit costs and severance
Other
Total Corporate and Other Operating Cash Decrease
Fiscal Year 2015 versus 2014
The increase in Operating Cash Flow of $113 million was driven primarily by the following (in millions):
Corporate and Other 2015 vs. 2014
Lower interest payments due primarily to corporate debt refinancing
Impact of swap termination payments occurring in the prior year related to corporate debt refinancing
Reduction in people-related costs, primarily due to benefit costs
Increase in collections from realized gains resulting from the settlement of foreign currency derivatives
Total Corporate and Other Operating Cash Increase
Parent Company Liquidity
$
$
$
$
18
(40)
(25)
(8)
(55)
60
22
16
15
113
The following discussion of Parent Company Liquidity has been included because we believe it is a useful
measure of the liquidity available to The AES Corporation, or the Parent Company, given the non-recourse nature of
most of our indebtedness. Parent Company Liquidity as outlined below is a non-GAAP measure and should not be
construed as an alternative to cash and cash equivalents which are determined in accordance with GAAP, as a
measure of liquidity. Cash and cash equivalents are disclosed in the consolidated statements of cash flows. Parent
Company Liquidity may differ from similarly titled measures used by other companies. The principal sources of
liquidity at the Parent Company level are dividends and other distributions from our subsidiaries, including
refinancing proceeds; proceeds from debt and equity financings at the Parent Company level, including availability
under our credit facility; and proceeds from asset sales. Cash requirements at the Parent Company level are
primarily to fund interest; principal repayments of debt; construction commitments; other equity commitments;
common stock repurchases; acquisitions; taxes; Parent Company overhead and development costs; and dividends
on common stock.
The Company defines Parent Company Liquidity as cash available to the Parent Company plus available
borrowings under existing credit facility. The cash held at qualified holding companies represents cash sent to
subsidiaries of the Company domiciled outside of the U.S.. Such subsidiaries have no contractual restrictions on
their ability to send cash to the Parent Company. Parent Company Liquidity is reconciled to its most directly
comparable U.S. GAAP financial measure, Cash and cash equivalents, at December 31, 2016 and 2015 as follows:
115
Parent Company Liquidity (in millions)
Consolidated cash and cash equivalents
Less: Cash and cash equivalents at subsidiaries
Parent and qualified holding companies' cash and cash equivalents
Commitments under Parent credit facility
Less: Letters of credit under the credit facilities
Borrowings available under Parent credit facilities
Total Parent Company Liquidity
2016
2015
$
$
1,305
1,205
100
800
(6)
794
894
$
$
1,257
857
400
800
(62)
738
1,138
The Company paid dividends of $0.44 per share to its common stockholders during the year ended
December 31, 2016. While we intend to continue payment of dividends and believe we will have sufficient liquidity
to do so, we can provide no assurance that we will continue to pay dividends, or if continued, the amount of such
dividends.
Recourse Debt — Our recourse debt at year-end was approximately $4.7 billion and $5.0 billion in 2016 and
2015, respectively. See Note 11—Debt in Item 8.—Financial Statements and Supplementary Data of this Form 10-K
for additional detail.
While we believe that our sources of liquidity will be adequate to meet our needs for the foreseeable future,
this belief is based on a number of material assumptions, including, without limitation, assumptions about our ability
to access the capital markets (see Key Trends and Uncertainties—Global Economic Conditions), the operating and
financial performance of our subsidiaries, currency exchange rates, power market pool prices, and the ability of our
subsidiaries to pay dividends. In addition, our subsidiaries' ability to declare and pay cash dividends to us (at the
Parent Company level) is subject to certain limitations contained in loans, governmental provisions and other
agreements. We can provide no assurance that these sources will be available when needed or that the actual cash
requirements will not be greater than anticipated. See Item 1A.—Risk Factors—The AES Corporation is a holding
company and its ability to make payments on its outstanding indebtedness, including its public debt securities, is
dependent upon the receipt of funds from its subsidiaries by way of dividends, fees, interest, loans or otherwise, of
this Form 10-K.
Various debt instruments at the Parent Company level, including our senior secured credit facility, contain
certain restrictive covenants. The covenants provide for — among other items — limitations on other indebtedness,
liens, investments and guarantees; limitations on dividends, stock repurchases and other equity transactions;
restrictions and limitations on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-
balance sheet and derivative arrangements; maintenance of certain financial ratios; and financial and other
reporting requirements.
As of December 31, 2016, we were in compliance with these covenants at the Parent Company level.
Non-Recourse Debt — While the lenders under our non-recourse debt financings generally do not have direct
recourse to the Parent Company, defaults thereunder can still have important consequences for our results of
operations and liquidity, including, without limitation:
•
•
•
•
reducing our cash flows as the subsidiary will typically be prohibited from distributing cash to the Parent
Company during the time period of any default;
triggering our obligation to make payments under any financial guarantee, letter of credit or other credit
support we have provided to or on behalf of such subsidiary;
causing us to record a loss in the event the lender forecloses on the assets; and
triggering defaults in our outstanding debt at the Parent Company.
For example, our senior secured credit facility and outstanding debt securities at the Parent Company include
events of default for certain bankruptcy related events involving material subsidiaries. In addition, our revolving
credit agreement at the Parent Company includes events of default related to payment defaults and accelerations of
outstanding debt of material subsidiaries.
Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding
indebtedness. The total non-recourse debt classified as current in the accompanying Consolidated Balance Sheets
amounts to $1.3 billion. The portion of current debt related to such defaults was $128 million at December 31, 2016,
all of which was non-recourse debt related to two subsidiaries — Kavarna, and Sogrinsk. See Note 11—Debt in
Item 8.—Financial Statements and Supplementary Data of this Form 10-K for additional detail.
None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of
materiality under AES' corporate debt agreements as of December 31, 2016 in order for such defaults to trigger an
event of default or permit acceleration under AES' indebtedness. However, as a result of additional dispositions of
116
assets, other significant reductions in asset carrying values or other matters in the future that may impact our
financial position and results of operations or the financial position of the individual subsidiary, it is possible that one
or more of these subsidiaries could fall within the definition of a "material subsidiary" and thereby upon an
acceleration trigger an event of default and possible acceleration of the indebtedness under the Parent Company's
outstanding debt securities. A material subsidiary is defined in the Company's senior secured revolving credit facility
as any business that contributed 20% or more of the Parent Company's total cash distributions from businesses for
the four most recently completed fiscal quarters. As of December 31, 2016, none of the defaults listed above
individually or in the aggregate results in or is at risk of triggering a cross-default under the recourse debt of the
Company.
Contractual Obligations and Parent Company Contingent Contractual Obligations
A summary of our contractual obligations, commitments and other liabilities as of December 31, 2016 is
presented below and excludes any businesses classified as discontinued operations or held-for-sale (in millions):
Contractual Obligations
Debt Obligations (1)
Interest Payments on Long-Term Debt (2)
Capital Lease Obligations
Operating Lease Obligations
Electricity Obligations
Fuel Obligations
Other Purchase Obligations
Other Long-Term Liabilities Reflected on AES' Consolidated
Balance Sheet under GAAP (3)
Total
_____________________________
Total
$20,949
7,945
165
1,374
33,106
5,163
14,009
Less than
1 year
$ 1,339
1,160
25
84
2,513
1,609
2,966
1-3
years
$ 2,897
1,962
32
181
4,874
1,213
3,260
3-5
years
$ 5,115
1,511
19
183
5,454
916
1,771
More than
5 years
$ 11,598
3,312
89
926
20,265
1,425
6,012
Other
$ —
—
—
—
—
—
—
783
—
264
41
430
$83,494
$ 9,696
$14,683
$15,010
$ 44,057
$
48
48
Footnote
Reference(4)
11
n/a
12
12
12
12
12
n/a
(1)
(2)
(3)
(4)
Includes recourse and non-recourse debt presented on the Consolidated Balance Sheet. These amounts exclude capital lease obligations which are included
in the capital lease category.
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2016 and do not reflect anticipated future
refinancing, early redemptions or new debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2016.
These amounts do not include current liabilities on the Consolidated Balance Sheet except for the current portion of uncertain tax obligations. Noncurrent
uncertain tax obligations are reflected in the "Other" column of the table above as the Company is not able to reasonably estimate the timing of the future
payments. In addition, these amounts do not include: (1) regulatory liabilities (See Note 10—Regulatory Assets and Liabilities), (2) contingencies (See
Note 13—Contingencies), (3) pension and other post retirement employee benefit liabilities (see Note 14—Benefit Plans), (4) derivatives and incentive
compensation (See Note 5—Derivative Instruments and Hedging Activities) or (5) any taxes (See Note 21—Income Taxes) except for uncertain tax
obligations, as the Company is not able to reasonably estimate the timing of future payments. See the indicated notes to the Consolidated Financial
Statements included in Item 8 of this Form 10-K for additional information on the items excluded.
For further information see the note referenced below in Item 8.—Financial Statements and Supplementary Data of this Form 10-K.
The following table presents our Parent Company's contingent contractual obligations as of December 31,
2016:
Contingent contractual obligations ($ in millions)
Guarantees and commitments
Letters of Credit under the unsecured credit facility
Asset sale related indemnities (1)
Letters of Credit under the senior secured credit facility
Cash collateralized letters of credit
Total
_____________________________
$
$
Amount
508
245
27
6
3
789
Number of Agreements
18
8
1
15
1
43
Maximum Exposure Range for Each Agreement
$8 - 58
$2 - 73
27
<$1 - 1
3
(1) Excludes normal and customary representations and warranties in agreements for the sale of assets (including ownership in associated legal entities) where
the associated risk is considered to be nominal.
As of December 31, 2016, the Company had no commitments to invest in subsidiaries under construction and
to purchase related equipment that were not included in the letters of credit disclosed above.
We have a diverse portfolio of performance-related contingent contractual obligations. These obligations are
designed to cover potential risks and only require payment if certain targets are not met or certain contingencies
occur. The risks associated with these obligations include change of control, construction cost overruns, subsidiary
default, political risk, tax indemnities, spot market power prices, sponsor support and liquidated damages under
power sales agreements for projects in development, in operation and under construction. In addition, we have an
asset sale program through which we may have customary indemnity obligations under certain assets sale
agreements. While we do not expect that we will be required to fund any material amounts under these contingent
contractual obligations beyond 2016, many of the events which would give rise to such obligations are beyond our
control. We can provide no assurance that we will be able to fund our obligations under these contingent
contractual obligations if we are required to make substantial payments thereunder.
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Critical Accounting Policies and Estimates
The Consolidated Financial Statements of AES are prepared in conformity with U.S. GAAP, which requires the
use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of
the financial statements and the reported amounts of revenue and expenses during the periods presented. AES'
significant accounting policies are described in Note 1—General and Summary of Significant Accounting Policies to
the Consolidated Financial Statements included in Item 8 of this Form 10-K.
An accounting estimate is considered critical if the estimate requires management to make assumptions about
matters that were highly uncertain at the time the estimate was made; different estimates reasonably could have
been used; or the impact of the estimates and assumptions on financial condition or operating performance is
material.
Management believes that the accounting estimates employed are appropriate and the resulting balances are
reasonable; however, actual results could materially differ from the original estimates, requiring adjustments to
these balances in future periods. Management has discussed these critical accounting policies with the Audit
Committee, as appropriate. Listed below are the Company's most significant critical accounting estimates and
assumptions used in the preparation of the Consolidated Financial Statements.
Income Taxes — We are subject to income taxes in both the U.S. and numerous foreign jurisdictions. Our
worldwide income tax provision requires significant judgment and is based on calculations and assumptions that are
subject to examination by the Internal Revenue Service and other taxing authorities. The Company and certain of
its subsidiaries are under examination by relevant taxing authorities for various tax years. The Company regularly
assesses the potential outcome of these examinations in each tax jurisdiction when determining the adequacy of
the provision for income taxes. Accounting guidance for uncertainty in income taxes prescribes a more likely than
not recognition threshold. Tax reserves have been established, which the Company believes to be adequate in
relation to the potential for additional assessments. Once established, reserves are adjusted only when there is
more information available or when an event occurs necessitating a change to the reserves. While the Company
believes that the amounts of the tax estimates are reasonable, it is possible that the ultimate outcome of current or
future examinations may be materially different than the reserve amounts.
Because we have a wide range of statutory tax rates in the multiple jurisdictions in which we operate, any
changes in our geographical earnings mix could materially impact our effective tax rate. Furthermore, our tax
position could be adversely impacted by changes in tax laws, tax treaties or tax regulations or the interpretation or
enforcement thereof and such changes may be more likely or become more likely in view of recent economic trends
in certain of the jurisdictions in which we operate. As an example, new tax laws were enacted in February 2016 in
Chile which increased the statutory income tax rate for most of our Chilean businesses from 25% to 25.5% in 2017
and to 27% for 2018 and future years. Accordingly, in 2016 our net Chilean deferred tax liabilities were remeasured
to the new rates. The remeasurement amount and other potential future impacts of the changes in tax law may be
material to continuing operations. See Note 21—Income Taxes to the Consolidated Financial Statements included
in Item 8 of this Form 10-K for additional information.
The Company's provision for income taxes could be adversely impacted by changes to the U.S. taxation of
earnings of our foreign subsidiaries. Since 2006, the Company has benefited from the Controlled Foreign
Corporation look-through rule, originally enacted in the TIPRA of 2005, subject to five temporary extensions,
including the most recent five year retroactive extension enacted on December 18, 2015 in the H.R.2029 -
Consolidated Appropriations Act, 2016. There can be no assurance that this provision will continue to be extended
beyond December 31, 2019. Further, the U.S. is considering corporate tax reform that may significantly change
corporate tax rates, business rules such as interest deductibility and capital expenditure cost recovery, and U.S.
international tax rules. Our expected effective tax rate could increase by amounts that may be material to the
Company should such reforms be enacted.
In addition, U.S. income taxes and foreign withholding taxes have not been provided on undistributed earnings
for certain of our non-U.S. subsidiaries to the extent such earnings are considered to be indefinitely reinvested in
the operations of those subsidiaries.
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences
between the financial statement carrying amounts of the existing assets and liabilities, and their respective income
tax bases. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a
deferred tax asset will not be realized.
Sales of Noncontrolling Interests — The accounting for a sale of noncontrolling interests under the
accounting standards depends on whether the sale is considered to be a sale of in-substance real estate (as
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opposed to an equity transaction), where the gain (loss) on sale would be recognized in earnings rather than within
stockholders' equity. If management's estimation process determines that there is no significant value beyond the
in-substance real estate, the gain (loss) on the sale of the noncontrolling interest is recognized in earnings.
However, if it is determined that significant value likely exists beyond the in-substance real estate, the gain (loss) on
the sale of the noncontrolling interest would be recognized within stockholders' equity. In-substance real estate is
comprised of land plus improvements and integral equipment. The determination of whether property, plant and
equipment is integral equipment is based on the significance of the costs to remove the equipment from its existing
location (including the cost of repairing damage resulting from the removal), combined with the decrease in the fair
value of the equipment as a result of those removal activities. When the combined total of removal costs and the
decrease in fair value of the equipment exceeds 10% of the fair value of the equipment, the equipment is
considered integral equipment. The accounting standards specifically identify power plants as an example of in-
substance real estate. Where the consolidated entity in which noncontrolling interests have been sold contains in-
substance real estate, management estimates the extent to which the total fair value of the assets of the entity is
represented by the in-substance real estate and whether significant value exists beyond the in-substance real
estate. This estimation considers all qualitative and quantitative factors relevant for each sale and, where
appropriate, includes making quantitative estimates about the fair value of the entity and its identifiable assets and
liabilities (including any favorable or unfavorable contracts) by analogy to the accounting standards on business
combinations. As such, these estimates may require significant judgment and assumptions, similar to the critical
accounting estimates discussed below for impairments and fair value.
Impairments — Our accounting policies on goodwill and long-lived assets are described in detail in Note 1—
General and Summary of Significant Accounting Policies, included in Item 8 of this Form 10-K. The Company
makes considerable judgments in its impairment evaluations of goodwill and long-lived assets; however, the fair
value determination is typically the most judgmental part in an impairment evaluation.
The Company determines the fair value of a reporting unit or a long-lived asset (asset group) by applying the
approaches prescribed under the fair value measurement accounting framework. Generally, the market approach
and income approach are most relevant in the fair value measurement of our reporting units and long-lived assets;
however, due to the lack of available relevant observable market information in many circumstances, the Company
often relies on the income approach. The Company may engage an independent valuation firm to assist
management with the valuation. The decision to engage an independent valuation firm considers all relevant facts
and circumstances, including a cost-benefit analysis and the Company's internal valuation knowledge of the long-
lived asset (asset group) or business. The Company develops the underlying assumptions consistent with its
internal budgets and forecasts for such valuations. Additionally, the Company uses an internal discounted cash flow
valuation model (the "DCF model"), based on the principles of present value techniques, to estimate the fair value
of its reporting units or long-lived assets under the income approach. The DCF model estimates fair value by
discounting our internal budgets and cash flow forecasts, adjusted to reflect market participant assumptions, to the
extent necessary, at an appropriate discount rate.
Management applies considerable judgment in selecting several input assumptions during the development of
our internal budgets and cash flow forecasts. Examples of the input assumptions that our budgets and forecasts are
sensitive to include macroeconomic factors such as growth rates, industry demand, inflation, exchange rates, power
prices and commodity prices. Whenever appropriate, management obtains these input assumptions from
observable market data sources (e.g., Economic Intelligence Unit) and extrapolates the market information if an
input assumption is not observable for the entire forecast period. Many of these input assumptions are dependent
on other economic assumptions, which are often derived from statistical economic models with inherent limitations
such as estimation differences. Further, several input assumptions are based on historical trends which often do not
recur. The input assumptions most significant to our budgets and cash flows are based on expectations of
macroeconomic factors which have been volatile recently. It is not uncommon that different market data sources
have different views of the macroeconomic factor expectations and related assumptions. As a result,
macroeconomic factors and related assumptions are often available in a narrow range; however, in some situations
these ranges become wide and the use of a different set of input assumptions could produce significantly different
budgets and cash flow forecasts.
A considerable amount of judgment is also applied in the estimation of the discount rate used in the DCF
model. To the extent practical, inputs to the discount rate are obtained from market data sources (e.g., Bloomberg,
Capital IQ, etc.). The Company selects and uses a set of publicly traded companies from the relevant industry to
estimate the discount rate inputs. Management applies judgment in the selection of such companies based on its
view of the most likely market participants. It is reasonably possible that the selection of a different set of likely
market participants could produce different input assumptions and result in the use of a different discount rate.
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Fair value of a reporting unit or a long-lived asset (asset group) is sensitive to both input assumptions to our
budgets and cash flow forecasts and the discount rate. Further, estimates of long-term growth and terminal value
are often critical to the fair value determination. As part of the impairment evaluation process, management
analyzes the sensitivity of fair value to various underlying assumptions. The level of scrutiny increases as the gap
between fair value and carrying amount decreases. Changes in any of these assumptions could result in
management reaching a different conclusion regarding the potential impairment, which could be material. Our
impairment evaluations inherently involve uncertainties from uncontrollable events that could positively or negatively
impact the anticipated future economic and operating conditions.
Further discussion of the impairment charges recognized by the Company can be found within Note 9—
Goodwill and Other Intangible Assets, Note 20—Asset Impairment Expense and Note 8—Other Non-Operating
Expense to the Consolidated Financial Statements included in Item 8 of this Form 10-K.
Fair Value
Fair Value Hierarchy — The Company uses valuation techniques and methodologies that maximize the use
of observable inputs and minimize the use of unobservable inputs. Where available, fair value is based on
observable market prices or parameters or derived from such prices or parameters. Where observable prices are
not available, valuation models are applied to estimate the fair value using the available observable inputs. The
valuation techniques involve some level of management estimation and judgment, the degree of which is
dependent on the price transparency for the instruments or market and the instruments' complexity.
To increase consistency and enhance disclosure of the fair value of financial instruments, the fair value
measurement standard includes a fair value hierarchy to prioritize the inputs used to measure fair value into three
categories. An asset or liability's level within the fair value hierarchy is based on the lowest level of input significant
to the fair value measurement, where Level 1 is the highest and Level 3 is the lowest. For more information
regarding the fair value hierarchy, see Note 1—General and Summary of Significant Accounting Policies included in
Item 8 of this Form 10-K.
Fair Value of Financial Instruments — A significant number of the Company's financial instruments are
carried at fair value with changes in fair value recognized in earnings or other comprehensive income each period.
The Company makes estimates regarding the valuation of assets and liabilities measured at fair value in preparing
the Consolidated Financial Statements. These assets and liabilities include short and long-term investments in debt
and equity securities, included in the balance sheet line items Short-term investments and Other assets
(Noncurrent), derivative assets, included in Other current assets and Other assets (Noncurrent) and derivative
liabilities, included in Accrued and other liabilities (current) and Other long-term liabilities. Investments are generally
fair valued based on quoted market prices or other observable market data such as interest rate indices. The
Company's investments are primarily certificates of deposit, government debt securities and money market funds.
Derivatives are valued using observable data as inputs into internal valuation models. The Company's derivatives
primarily consist of interest rate swaps, foreign currency instruments, and commodity and embedded derivatives.
Additional discussion regarding the nature of these financial instruments and valuation techniques can be found in
Note 4—Fair Value included in Item 8 of this Form 10-K.
Fair Value of Nonfinancial Assets and Liabilities — Significant estimates are made in determining the fair
value of long-lived tangible and intangible assets (i.e., property, plant and equipment, intangible assets and
goodwill) during the impairment evaluation process. In addition, the majority of assets acquired and liabilities
assumed in a business combination are required to be recognized at fair value under the relevant accounting
guidance. In determining the fair value of these items, management makes several assumptions as discussed in
the Impairments section above.
Accounting for Derivative Instruments and Hedging Activities — We enter into various derivative
transactions in order to hedge our exposure to certain market risks. We primarily use derivative instruments to
manage our interest rate, commodity and foreign currency exposures. We do not enter into derivative transactions
for trading purposes.
In accordance with the accounting standards for derivatives and hedging, we recognize all derivatives as
either assets or liabilities in the balance sheet and measure those instruments at fair value except where derivatives
qualify and are designated as "normal purchase/normal sale" transactions. Changes in fair value of derivatives are
recognized in earnings unless specific hedge criteria are met. Income and expense related to derivative instruments
are recognized in the same category as that generated by the underlying asset or liability. See Note 5—Derivative
Instruments and Hedging Activities included in Item 8 of this Form 10-K for further information on the classification.
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The accounting standards for derivatives and hedging enable companies to designate qualifying derivatives
as hedging instruments based on the exposure being hedged. These hedge designations include fair value hedges
and cash flow hedges. Changes in the fair value of a derivative that is highly effective and is designated and
qualifies as a fair value hedge, are recognized in earnings as offsets to the changes in fair value of the exposure
being hedged. The Company has no fair value hedges at this time. Changes in the fair value of a derivative that is
highly effective and is designated as and qualifies as a cash flow hedge, are deferred in accumulated other
comprehensive income and are recognized into earnings as the hedged transactions occur. Any ineffectiveness is
recognized in earnings immediately. For all hedge contracts, the Company provides formal documentation of the
hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging.
The fair value measurement accounting standard provides additional guidance on the definition of fair value
and defines fair value as 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, or exit price. The fair value measurement
standard requires the Company to consider and reflect the assumptions of market participants in the fair value
calculation. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit
risk, both of the reporting entity (for liabilities) and of the counterparty (for assets). Due to the nature of the
Company's interest rate swaps, which are typically associated with non-recourse debt, credit risk for AES is
evaluated at the subsidiary level rather than at the Parent Company level. Nonperformance risk on the Company's
derivative instruments is an adjustment to the initial asset/liability fair value position that is derived from internally
developed valuation models that utilize observable market inputs.
As a result of uncertainty, complexity and judgment, accounting estimates related to derivative accounting
could result in material changes to our financial statements under different conditions or utilizing different
assumptions. As a part of accounting for these derivatives, we make estimates concerning nonperformance,
volatilities, market liquidity, future commodity prices, interest rates, credit ratings (both ours and our counterparty's),
and future exchange rates. Refer to Note 4—Fair Value included in Item 8 of this Form 10-K for additional details.
The fair value of our derivative portfolio is generally determined using internal and third party valuation
models, most of which are based on observable market inputs including interest rate curves and forward and spot
prices for currencies and commodities. The Company derives most of its financial instrument market assumptions
from market efficient data sources (e.g., Bloomberg, Reuters and Platt's). In some cases, where market data is not
readily available, management uses comparable market sources and empirical evidence to derive market
assumptions to determine a financial instrument's fair value. In certain instances, the published curve may not
extend through the remaining term of the contract and management must make assumptions to extrapolate the
curve. Specifically, where there is limited forward curve data with respect to foreign exchange contracts, beyond the
traded points the Company utilizes the purchasing power parity approach to construct the remaining portion of the
forward curve using relative inflation rates. Additionally, in the absence of quoted prices, we may rely on "indicative
pricing" quotes from financial institutions to input into our valuation model for certain of our foreign currency swaps.
These indicative pricing quotes do not constitute either a bid or ask price and therefore are not considered
observable market data. For individual contracts, the use of different valuation models or assumptions could have a
material effect on the calculated fair value.
Regulatory Assets — Management continually assesses whether the regulatory assets are probable of future
recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other
regulated entities and the status of any pending or potential deregulation legislation. If future recovery of costs
ceases to be probable, any asset write-offs would be required to be recognized in operating income.
Consolidation — The Company has recently entered into several transactions whereby the Company sells an
interest in its controlled subsidiaries and/or equity method investments. In connection with each transaction, the
Company must determine whether the sale of the interest impacts the Company's consolidation conclusion by first
determining whether the transaction should be evaluated under the variable interest model or the voting model. In
determining which consolidation model applies to the transaction, the Company is required to make judgments
about how the entity operates, the most significant of which are whether (i) the entity has sufficient equity to finance
its activities, (ii) the equity holders, as a group, have the characteristics of a controlling financial interest, and (iii)
whether the entity has non-substantive voting rights.
If the entity is determined to be a variable interest entity, the most significant judgment in determining whether
the Company must consolidate the entity is whether the Company, including its related parties and de facto agents,
collectively have power and benefits. If AES is determined to have power and benefits, the entity will be
consolidated by AES.
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Alternatively, if the entity is determined to be a voting model entity, the most significant judgments involve
determining whether the non-AES shareholders have substantive participating rights. The assessment of
shareholder rights and whether they are substantive participating rights requires significant judgment since the
rights provided under shareholders' agreements may include selecting, terminating, and setting the compensation
of management responsible for implementing the subsidiary's policies and procedures, establishing operating and
capital decisions of the entity, including budgets, in the ordinary course of business. On the other hand, if
shareholder rights are only protective in nature (referred to as protective rights) then such rights would not
overcome the presumption that the owner of a majority voting interest shall consolidate its investee. Significant
judgment is required to determine whether minority rights represent substantive participating rights or protective
rights that do not affect the evaluation of control. While both represent an approval or veto right, a distinguishing
factor is the underlying activity or action to which the right relates.
Pension and Other Postretirement Plans — Effective January 1, 2016 the Company applied a
disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension
plans and post-retirement plans in the U.S. and U.K. Refer to Note 1—General and Summary of Significant
Accounting Policies included in Item 8 of this Form 10-K for further information.
New Accounting Pronouncements — See Note 1—General and Summary of Significant Accounting Policies
included in Item 8 of this Form 10-K for further information about new accounting pronouncements adopted during
2016 and accounting pronouncements issued but not yet effective.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Overview Regarding Market Risks — Our businesses are exposed to and proactively manage market risk.
Our primary market risk exposure is to the price of commodities, particularly electricity, oil, natural gas, coal and
environmental credits. In addition, our businesses are also exposed to lower electricity prices due to increased
competition, including from renewable sources such as wind and solar, as a result of lower costs of entry and lower
variable costs. We operate in multiple countries and as such are subject to volatility in exchange rates at varying
degrees at the subsidiary level and between our functional currency, the U.S. Dollar, and currencies of the countries
in which we operate. We are also exposed to interest rate fluctuations due to our issuance of debt and related
financial instruments.
The disclosures presented in this Item 7A are based upon a number of assumptions; actual effects may differ.
The safe harbor provided in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange
Act of 1934 shall apply to the disclosures contained in this Item 7A. For further information regarding market risk,
see Item 1A.—Risk Factors, Our financial position and results of operations may fluctuate significantly due to
fluctuations in currency exchange rates experienced at our foreign operations, Our businesses may incur
substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the electricity
markets, which could have a material adverse effect on our financial performance, and We may not be adequately
hedged against our exposure to changes in commodity prices or interest rates of this 2016 Form 10-K.
Commodity Price Risk — Although we prefer to hedge our exposure to the impact of market fluctuations in
the price of electricity, fuels and environmental credits, some of our generation businesses operate under short-term
sales or under contract sales that leave an unhedged exposure on some of our capacity or through imperfect fuel
pass-throughs. In our utility businesses, we may be exposed to commodity price movements depending on our
excess or shortfall of generation relative to load obligations and sharing or pass-through mechanisms. These
businesses subject our operational results to the volatility of prices for electricity, fuels and environmental credits in
competitive markets. We employ risk management strategies to hedge our financial performance against the effects
of fluctuations in energy commodity prices. The implementation of these strategies can involve the use of physical
and financial commodity contracts, futures, swaps and options. At our generation businesses for 2017-2019, 75% to
80% of our variable margin is hedged against changes in commodity prices. At our utility businesses for 2017-2019,
85% to 90% of our variable margin is insulated from changes in commodity prices.
The portion of our sales and purchases that are not subject to such agreements or contracted businesses
where indexation is not perfectly matched to business drivers will be exposed to commodity price risk. When
hedging the output of our generation assets, we utilize contract sales that lock in the spread per MWh between
variable costs and the price at which the electricity can be sold.
AES businesses will see changes in variable margin performance as global commodity prices shift. For 2017,
we project pretax earnings exposure on a 10% move in commodity prices would be approximately $15 million for
U.S. power (DPL), $5 million for natural gas, $5 million for oil and $10 million for coal. Our estimates exclude
correlation of oil with coal or natural gas. For example, a decline in oil or natural gas prices can be accompanied by
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a decline in coal price if commodity prices are correlated. In aggregate, the Company's downside exposure occurs
with lower oil, lower natural gas, and higher coal prices. Exposures at individual businesses will change as new
contracts or financial hedges are executed, and our sensitivity to changes in commodity prices generally increases
in later years with reduced hedge levels at some of our businesses.
Commodity prices affect our businesses differently depending on the local market characteristics and risk
management strategies. Spot power prices, contract indexation provisions and generation costs can be directly or
indirectly affected by movements in the price of natural gas, oil and coal. We have some natural offsets across our
businesses such that low commodity prices may benefit certain businesses and be a cost to others. Exposures are
not perfectly linear or symmetric. The sensitivities are affected by a number of local or indirect market factors.
Examples of these factors include hydrology, local energy market supply/demand balances, regional fuel supply
issues, regional competition, bidding strategies and regulatory interventions such as price caps. Operational
flexibility changes the shape of our sensitivities. For instance, certain power plants may limit downside exposure by
reducing dispatch in low market environments. Volume variation also affects our commodity exposure. The volume
sold under contracts or retail concessions can vary based on weather and economic conditions resulting in a higher
or lower volume of sales in spot markets. Thermal unit availability and hydrology can affect the generation output
available for sale and can affect the marginal unit setting power prices.
In the US SBU, the generation businesses are largely contracted but may have residual risk to the extent
contracts are not perfectly indexed to the business drivers. IPL primarily generates energy to meet its retail
customer demand however it opportunistically sells surplus economic energy into wholesale markets at market
prices. Additionally, at DPL, competitive retail markets permit our customers to select alternative energy suppliers or
elect to remain in aggregated customer pools for which energy is supplied by third party suppliers through a
competitive auction process. DPL participates in these auctions held by other utilities and sells the remainder of its
economic energy into the wholesale market. Given that natural gas-fired generators generally get energy prices for
many markets, higher natural gas prices tend to expand our coal fixed margins. Our non-contracted generation
margins are impacted by many factors including the growth in natural gas-fired generation plants, new energy
supply from renewable sources, and increasing energy efficiency.
In the Andes SBU, our business in Chile owns assets in the central and northern regions of the country and
has a portfolio of contract sales in both. In the central region, the contract sales generally cover the efficient
generation from our coal-fired and hydroelectric assets. Any residual spot price risk will primarily be driven by the
amount of hydrological inflows. In the case of low hydroelectric generation, spot price exposure is capped by the
ability to dispatch our natural gas/diesel assets the price of which depends on fuel pricing at the time required.
There is a small amount of coal generation in the northern region that is not covered by the portfolio of contract
sales and therefore subject to spot price risk. In both regions, generators with oil or oil-linked fuel generally set
power prices. In Colombia, we operate under a short-term sales strategy and have commodity exposure to
unhedged volumes. Because we own hydroelectric assets there, contracts are not indexed to fuel.
In the Brazil SBU, the hydroelectric generating facility is covered by contract sales. Under normal hydrological
volatility, spot price risk is mitigated through a regulated sharing mechanism across all hydroelectric generators in
the country. Under drier conditions, the sharing mechanism may not be sufficient to cover the business' contract
position, and therefore it may have to purchase power at spot prices driven by the cost of thermal generation.
In the MCAC SBU, our businesses have commodity exposure on unhedged volumes. Panama is highly
contracted under a portfolio of fixed volume contract sales. To the extent hydrological inflows are greater than or
less than the contract sales volume, the business will be sensitive to changes in spot power prices which may be
driven by oil prices in some time periods. In the Dominican Republic, we own natural gas-fired assets contracted
under a portfolio of contract sales and a coal-fired asset contracted with a single contract, and both contract and
spot prices may move with commodity prices. Additionally, the contract levels do not always match our generation
availability and our assets may be sellers of spot prices in excess of contract levels or a net buyer in the spot
market to satisfy contract obligations.
In the Europe SBU, our Kilroot facility operates on a short-term sales strategy. To the extent that sales are
unhedged, the commodity risk at our Kilroot business is to the clean dark spread, which is the difference between
electricity price and our coal-based variable dispatch cost including emissions. Natural gas-fired generators set
power prices for many periods, so higher natural gas prices generally expand margins and higher coal or emissions
prices reduce them. Similarly, increased wind generators displaces higher cost generation, reducing Kilroot's
margins, and vice versa.
In the Asia SBU, our Masinloc business is a coal-fired generation facility which hedges its output under a
portfolio of contract sales that are indexed to fuel prices, with generation in excess of contract volume or shortfalls
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of generation relative to contract volumes settled in the spot market. Low oil prices may be a driver of margin
compression since oil affects spot power sale prices sold in the spot market. Our Mong Duong business has
minimal exposure to commodity price risk as it has no merchant exposure and fuel is subject to a pass-through
mechanism.
Foreign Exchange Rate Risk — In the normal course of business, we are exposed to foreign currency risk
and other foreign operations risks that arise from investments in foreign subsidiaries and affiliates. A key component
of these risks stems from the fact that some of our foreign subsidiaries and affiliates utilize currencies other than our
consolidated reporting currency, the U.S. Dollar ("USD"). Additionally, certain of our foreign subsidiaries and
affiliates have entered into monetary obligations in the USD or currencies other than their own functional currencies.
We have varying degrees of exposure to changes in the exchange rate between the USD and the following
currencies: Argentine Peso, British Pound, Brazilian Real, Chilean Peso, Colombian Peso, Dominican Peso, Euro,
Indian Rupee, Kazakhstan Tenge, Mexican Peso and Philippine Peso. These subsidiaries and affiliates have
attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in
foreign exchange rates. We also use foreign currency forwards, swaps and options, where possible, to manage our
risk related to certain foreign currency fluctuations.
AES enters into cash flow hedges to protect economic value of the business and minimize impact of foreign
exchange rate fluctuations to AES portfolio. While protecting cash flows, the hedging strategy is also designed to
reduce forward looking earnings foreign exchange volatility. Due to variation of timing and amount between cash
distribution and earnings exposure, the hedge impact may not fully cover the earnings exposure on a realized basis
which could result in greater volatility in earnings. The largest foreign exchange risks over a 12-month forward-
looking period stem from the following currencies: Brazilian Real, Euro, Colombian Peso, British Pound, and
Kazakhstan Tenge. As of December 31, 2016, assuming a 10% USD appreciation, cash distributions attributable to
foreign subsidiaries exposed to movement in the exchange rate of the Brazilian Real and Euro each is projected to
be reduced by $5 million. Colombian Peso, Kazakhstan Tenge and British Pound - less than $5 million for 2017.
These numbers have been produced by applying a one-time 10% USD appreciation to forecasted exposed cash
distributions for 2017 coming from the respective subsidiaries exposed to the currencies listed above, net of the
impact of outstanding hedges and holding all other variables constant. The numbers presented above are net of
any transactional gains/losses. These sensitivities may change in the future as new hedges are executed or
existing hedges are unwound. Additionally, updates to the forecasted cash distributions exposed to foreign
exchange risk may result in further modification. The sensitivities presented do not capture the impacts of any
administrative market restrictions or currency inconvertibility.
The foreign exchange sensitivities included above have been calculated based on the underlying cash
distribution exposures. This is different than the prior period’s disclosure, which was based on earnings, as a result
of a change in AES’ foreign exchange hedging strategy in 2016. The table below provides a comparison of the
earnings based sensitivity approached used in the 2015 Form 10-K for both FY2016 and FY2017.
ARS
BRL
COP
EUR
KZT
Earnings Exposure
2016
2017
5
—
5
10
5
5
5
—
5
5
Interest Rate Risks — We are exposed to risk resulting from changes in interest rates as a result of our
issuance of variable and fixed-rate debt, as well as interest rate swap, cap, floor and option agreements.
Decisions on the fixed-floating debt mix are made to be consistent with the risk factors faced by individual
businesses or plants. Depending on whether a plant's capacity payments or revenue stream is fixed or varies with
inflation, we partially hedge against interest rate fluctuations by arranging fixed-rate or variable-rate financing. In
certain cases, particularly for non-recourse financing, we execute interest rate swap, cap and floor agreements to
effectively fix or limit the interest rate exposure on the underlying financing. Most of our interest rate risk is related to
non-recourse financings at our businesses.
As of December 31, 2016, the portfolio's pretax earnings exposure for 2017 to a one time 100-basis-point
increase in interest rates for our Argentine Peso, Brazilian Real, Colombian Peso, Euro, Kazakhstani Tenge and
USD denominated debt would be approximately $25 million on interest expense for the debt denominated in these
currencies. These amounts do not take into account the historical correlation between these interest rates.
124
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of The AES Corporation:
We have audited the accompanying consolidated balance sheets of The AES Corporation as of December 31,
2016 and 2015, and the related consolidated statements of operations, comprehensive income, changes in equity,
and cash flows for each of the three years in the period ended December 31, 2016. Our audits also included the
financial statement schedules listed in the Index at Item 15(a). These financial statements and schedules are the
responsibility of the Company’s management. Our responsibility is to express an opinion on these financial
statements and schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the
consolidated financial position of The AES Corporation at December 31, 2016 and 2015, and the consolidated
results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in
conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement
schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all
material respects the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, the Company changed its requirements for
reporting discontinued operations as a result of the adoption of the amendments to the FASB Accounting Standards
Codification resulting from Accounting Standards Update No. 2014-08, “Reporting Discontinued Operations and
Disclosures of Disposals of Components of an Entity,” effective July 1, 2014. Also, the Company changed its
classification of debt issuance costs as a result of the adoption of the amendments to the FASB Accounting
Standards Codification resulting from Accounting Standards Update No. 2015-03 and No. 2015-15, “Interest -
Imputation of Interest (Subtopic 835-30),” effective January 1, 2016.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States), The AES Corporation’s internal control over financial reporting as of December 31, 2016, based on
criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission (2013 framework) and our report dated February 24, 2017 expressed an unqualified
opinion thereon.
/s/ Ernst & Young LLP
McLean, Virginia
February 24, 2017
125
THE AES CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2016 AND 2015
2016
2015
(in millions, except share and per share
data)
$
$
$
ASSETS
CURRENT ASSETS
Cash and cash equivalents
Restricted cash
Short-term investments
Accounts receivable, net of allowance for doubtful accounts of $111 and $87, respectively
Inventory
Prepaid expenses
Other current assets
Current assets of discontinued operations and held-for-sale businesses
Total current assets
NONCURRENT ASSETS
Property, Plant and Equipment:
Land
Electric generation, distribution assets and other
Accumulated depreciation
Construction in progress
Property, plant and equipment, net
Other Assets:
Investments in and advances to affiliates
Debt service reserves and other deposits
Goodwill
Other intangible assets, net of accumulated amortization of $519 and $481, respectively
Deferred income taxes
Service concession assets, net of accumulated amortization of $114 and $34, respectively
Other noncurrent assets
Noncurrent assets of discontinued operations and held-for-sale businesses
Total other assets
TOTAL ASSETS
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable
Accrued interest
Accrued and other liabilities
Non-recourse debt, including $273 and $258, respectively, related to variable interest entities
Current liabilities of discontinued operations and held-for-sale businesses
Total current liabilities
NONCURRENT LIABILITIES
Recourse debt
Non-recourse debt, including $1,502 and $1,531, respectively, related to variable interest entities
Deferred income taxes
Pension and other postretirement liabilities
Other noncurrent liabilities
Noncurrent liabilities of discontinued operations and held-for-sale businesses
Total noncurrent liabilities
Commitments and Contingencies (see Notes 12 and 13)
Redeemable stock of subsidiaries
EQUITY
THE AES CORPORATION STOCKHOLDERS’ EQUITY
Common stock ($0.01 par value, 1,200,000,000 shares authorized; 816,061,123 issued and
659,182,232 outstanding at December 31, 2016 and 815,846,621 issued and 666,808,790 outstanding
at December 31, 2015)
Additional paid-in capital
Retained earnings (accumulated deficit)
Accumulated other comprehensive loss
Treasury stock, at cost (156,878,891 shares at December 31, 2016 and 149,037,831 shares at
December 31, 2015)
Total AES Corporation stockholders’ equity
NONCONTROLLING INTERESTS
Total equity
TOTAL LIABILITIES AND EQUITY
$
See Accompanying Notes to Consolidated Financial Statements.
126
1,305
278
798
2,166
630
83
1,151
—
6,411
779
28,539
(9,528)
3,057
22,847
621
593
1,157
359
781
1,445
1,905
—
6,861
36,119
1,656
247
2,066
1,303
—
5,272
4,671
14,489
804
1,396
3,005
—
24,365
782
8
8,592
(1,146)
(2,756)
(1,904)
2,794
2,906
5,700
36,119
$
$
$
$
1,257
295
469
2,302
671
106
1,318
424
6,842
702
27,282
(8,939)
2,977
22,022
610
555
1,157
340
410
1,543
2,109
882
7,606
36,470
1,571
236
2,286
2,172
661
6,926
4,966
12,943
1,090
919
2,794
123
22,835
538
8
8,718
143
(3,883)
(1,837)
3,149
3,022
6,171
36,470
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014
2016
2014
2015
(in millions, except per share amounts)
$
6,629
6,957
13,586
$
6,852
7,303
14,155
$
7,852
8,272
16,124
Revenue:
Regulated
Non-Regulated
Total revenue
Cost of Sales:
Regulated
Non-Regulated
Total cost of sales
Operating margin
General and administrative expenses
Interest expense
Interest income
Loss on extinguishment of debt
Other expense
Other income
Gain on disposal and sale of businesses
Goodwill impairment expense
Asset impairment expense
Foreign currency transaction gains (losses)
Other non-operating expense
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES AND EQUITY IN EARNINGS OF
AFFILIATES
Income tax benefit (expense)
Net equity in earnings of affiliates
INCOME FROM CONTINUING OPERATIONS
Income (loss) from operations of discontinued businesses, net of income tax benefit (expense) of $9, $7,
and $(71), respectively
Net loss from disposal and impairments of discontinued businesses, net of income tax benefit (expense)
of $266, $0, and $(4), respectively
NET INCOME (LOSS)
Noncontrolling interests:
Less: Net (income) attributable to noncontrolling interests
Less: Net loss attributable to redeemable stocks of subsidiaries
Plus: Loss from discontinued operations attributable to noncontrolling interests
Total net income attributable to noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income from continuing operations, net of tax
Income (loss) from discontinued operations, net of tax
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION
BASIC EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax
Income (loss) from discontinued operations attributable to The AES Corporation common stockholders,
net of tax
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS
DILUTED EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax
Income (loss) from discontinued operations attributable to The AES Corporation common stockholders,
net of tax
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS
DIVIDENDS DECLARED PER COMMON SHARE
$
$
$
$
$
— $
0.48
(1.72)
(0.03)
(1.72) $
0.45
— $
0.48
(1.71)
(0.04)
(1.71) $
0.45
$
0.44
0.41
See Accompanying Notes to Consolidated Financial Statements.
127
(6,078)
(5,075)
(11,153)
2,433
(194)
(1,431)
464
(13)
(103)
65
29
—
(1,096)
(15)
(2)
137
188
36
361
(19)
(1,119)
(777)
(364)
11
—
(353)
$ (1,130) $
$
$
8
(1,138)
$ (1,130) $
(5,764)
(5,533)
(11,297)
2,858
(196)
(1,344)
460
(182)
(58)
82
29
(317)
(285)
107
—
1,154
(472)
105
787
(25)
—
762
(456)
—
—
(456)
306
331
(25)
306
(6,615)
(6,529)
(13,144)
2,980
(187)
(1,451)
320
(261)
(65)
121
358
(164)
(91)
11
(128)
1,443
(371)
19
1,091
111
(55)
1,147
(386)
—
8
(378)
769
705
64
769
0.98
0.09
1.07
0.97
0.09
1.06
0.25
$
$
$
$
$
$
$
$
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014
2016
2015
(in millions)
762
2014
$
1,147
(777) $
NET INCOME (LOSS)
Foreign currency translation activity:
$
Foreign currency translation adjustments, net of income tax benefit (expense) of $1, $1, and $(7),
respectively
Reclassification to earnings, net of $0 income tax for all periods
Total foreign currency translation adjustments
Derivative activity:
Change in derivative fair value, net of income tax benefit (expense) of $(7), $16 and $72, respectively
Reclassification to earnings, net of income tax expense of $8, $11 and $26, respectively
Total change in fair value of derivatives
Pension activity:
Change in pension adjustments due to prior service cost, net of income tax expense of $6, $0, and $0
respectively
Change in pension adjustments due to net actuarial gain (loss) for the period, net of income tax
benefit (expense) of $106, $(29), and $27, respectively
Reclassification to earnings due to amortization of net actuarial loss, net of income tax expense of $3,
$9, and $7, respectively
Total pension adjustments
OTHER COMPREHENSIVE INCOME (LOSS)
COMPREHENSIVE INCOME (LOSS)
Less: Comprehensive (income) loss attributable to noncontrolling interests
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION
189
992
1,181
(1,019)
—
(1,019)
5
37
42
11
(208)
10
(187)
1,036
259
(262)
$
(3) $
(57)
66
9
1
60
16
77
(933)
(171)
(133)
(304) $
(491)
(3)
(494)
(358)
99
(259)
—
(49)
29
(20)
(773)
374
(49)
325
See Accompanying Notes to Consolidated Financial Statements.
128
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014
(in millions)
Shares
Amount
Shares
Amount
Common Stock
Treasury Stock
Additional
Paid-In
Capital
Retained
Earnings
(Accumulated
Deficit)
Accumulated
Other
Comprehensive
Loss
Noncontrolling
Interests
THE AES CORPORATION STOCKHOLDERS
90.8
$ (1,089) $
8,443
$
(150) $
(2,882) $
3,321
Balance at December 31, 2013
813.3
$
Net income
Total foreign currency translation adjustment, net of income tax
Total change in derivative fair value, net of income tax
Total pension adjustments, net of income tax
Total other comprehensive loss
Balance Sheet reclassification related to an equity method
investment (1)
Disposition of businesses
Distributions to noncontrolling interests
Contributions from noncontrolling interests
Dividends declared on common stock
Purchase of treasury stock
Issuance and exercise of stock-based compensation benefit
plans, net of income tax
Sale of subsidiary shares to noncontrolling interests
Acquisition of subsidiary shares from noncontrolling interests
—
—
—
—
—
—
—
—
—
—
1.2
—
—
Balance at December 31, 2014
814.5
$
Net income
Total foreign currency translation adjustment, net of income tax
Total change in derivative fair value, net of income tax
Total pension adjustments, net of income tax
Total other comprehensive loss
Cumulative effect of a change in accounting principle
Acquisition of a business (2)
Disposition of businesses
Distributions to noncontrolling interests
Contributions from noncontrolling interests
Dividends declared on common stock
Purchase of treasury stock
Issuance and exercise of stock-based compensation benefit
plans, net of income tax
Sale of subsidiary shares to noncontrolling interests
—
—
—
—
—
—
—
—
—
—
—
1.3
—
Balance at December 31, 2015
815.8
$
Net income
Total foreign currency translation adjustment, net of income tax
Total change in derivative fair value, net of income tax
Total pension adjustments, net of income tax
Total other comprehensive loss
Fair value adjustment (3)
Disposition of businesses
Distributions to noncontrolling interests
Contributions from noncontrolling interests
Dividends declared on common stock
Purchase of treasury stock
Issuance and exercise of stock-based compensation benefit
plans, net of income tax
Sale of subsidiary shares to noncontrolling interests
Acquisition and reclassification of subsidiary shares from
noncontrolling interests
—
—
—
—
—
—
—
—
—
—
0.3
—
—
Balance at December 31, 2016
816.1
$
8
—
—
—
—
—
—
—
—
—
—
—
—
—
8
—
—
—
—
—
—
—
—
—
—
—
—
—
8
—
—
—
—
—
—
—
—
—
—
—
—
—
8
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
769
—
—
—
—
—
—
—
(73)
(107)
21.9
(308)
(2.0)
—
—
26
—
—
—
3
29
7
110.7
$ (1,371) $
8,409
$
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
39.7
(482)
(1.4)
—
16
—
—
—
—
—
—
—
—
(27)
—
—
—
13
323
—
—
—
—
512
306
—
—
—
(18)
—
—
—
—
(280)
—
—
(377)
—
(332)
(108)
(4)
(444)
40
—
—
—
—
—
—
—
—
378
(162)
(151)
(16)
(329)
—
(153)
(466)
147
—
—
—
173
(18)
$
(3,286) $
3,053
—
(674)
43
21
(610)
13
—
—
—
—
—
—
—
—
149.0
$ (1,837) $
8,718
$
143
$
(3,883) $
—
—
—
—
—
—
—
—
—
8.7
(0.8)
—
—
—
—
—
—
—
—
—
—
—
(79)
12
—
—
—
—
—
—
17
—
(10)
—
(226)
—
11
84
(2)
(1,130)
—
—
—
(4)
—
—
—
(71)
—
—
(84)
—
—
1,109
30
(12)
1,127
—
—
—
—
—
—
—
—
—
456
(345)
(34)
56
(323)
—
15
(41)
(383)
126
—
—
—
119
3,022
364
72
12
(175)
(91)
(17)
(2)
(430)
60
—
—
—
17
(17)
156.9
$ (1,904) $
8,592
$
(1,146) $
(2,756) $
2,906
(1) Reclassification resulting from SRP transaction during the third quarter of 2014. See Note 7—Investments In and Advances to Affiliates for further information.
(2) Fair value of a tax equity partner's right to preferential returns recognized as a result of the acquisition of Solar Power PR, LLC, which was previously accounted for as an equity method investment.
(3) Adjustment to the carrying amount of non-controlling interest and redeemable stock of subsidiaries to fair value.
See Accompanying Notes to Consolidated Financial Statements
129
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014
OPERATING ACTIVITIES:
Net income (loss)
Adjustments to net income:
Depreciation and amortization
Gain on sales and disposals of businesses
Impairment expenses
Deferred income taxes
Provisions for (reversals of) contingencies
Loss on extinguishment of debt
Loss (Gain) on sale and disposal of assets
Impairments of discontinued operations and held-for-sale businesses
Other
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable
(Increase) decrease in inventory
(Increase) decrease in prepaid expenses and other current assets
(Increase) decrease in other assets
Increase (decrease) in accounts payable and other current liabilities
Increase (decrease) in income tax payables, net and other tax payables
Increase (decrease) in other liabilities
Net cash provided by operating activities
INVESTING ACTIVITIES:
Capital expenditures
Acquisitions, net of cash acquired
Proceeds from the sale of businesses, net of cash sold, and equity method investments
Sale of short-term investments
Purchase of short-term investments
(Increase) decrease in restricted cash, debt service reserves and other assets
Other investing
Net cash used in investing activities
FINANCING ACTIVITIES:
Borrowings under the revolving credit facilities
Repayments under the revolving credit facilities
Issuance of recourse debt
Repayments of recourse debt
Issuance of non-recourse debt
Repayments of non-recourse debt
Payments for financing fees
Distributions to noncontrolling interests
Contributions from noncontrolling interests and redeemable security holders
Proceeds from the sale of redeemable stock of subsidiaries
Dividends paid on AES common stock
Payments for financed capital expenditures
Purchase of treasury stock
Proceeds from sales to noncontrolling interests, net of transaction costs
Other financing
Net cash (used in) provided by financing activities
Effect of exchange rate changes on cash
Decrease (Increase) in cash of discontinued operations and held-for-sale businesses
Total Increase (decrease) in cash and cash equivalents
Cash and cash equivalents, beginning
Cash and cash equivalents, ending
SUPPLEMENTAL DISCLOSURES:
Cash payments for interest, net of amounts capitalized
Cash payments for income taxes, net of refunds
SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Assets received upon sale of subsidiaries
Assets acquired through capital lease and other liabilities
Dividends declared but not yet paid
2016
2015
(in millions)
2014
$
(777) $
762
$
1,147
1,176
(29)
1,098
(793)
48
20
38
1,383
168
237
42
870
(251)
(620)
(199)
473
2,884
(2,345)
(55)
631
4,904
(5,151)
(61)
(31)
(2,108)
1,465
(1,433)
500
(808)
2,978
(2,666)
(105)
(476)
190
134
(290)
(113)
(79)
—
(44)
(747)
9
10
48
1,257
1,305
1,273
487
$
$
$
1,144
(29)
602
(50)
(72)
186
20
—
8
(378)
(26)
655
(1,305)
31
53
533
2,134
(2,308)
(17)
138
4,851
(4,801)
(159)
(70)
(2,366)
959
(937)
575
(915)
4,248
(3,312)
(90)
(326)
126
461
(276)
(150)
(482)
154
(7)
28
(52)
(4)
(260)
1,517
1,257
1,265
388
$
$
$
1,245
(358)
383
47
(34)
261
(20)
50
92
(520)
(48)
(73)
(723)
(85)
(89)
516
1,791
(2,016)
(728)
1,807
4,503
(4,623)
419
(18)
(656)
836
(834)
1,525
(2,117)
4,179
(3,481)
(158)
(485)
143
—
(144)
(528)
(308)
83
27
(1,262)
(51)
59
(119)
1,636
1,517
1,351
480
— $
5
$
$
174
— $
$
18
$
135
44
49
72
$
$
$
$
$
$
See Accompanying Notes to Consolidated Financial Statements.
130
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2016, 2015, AND 2014
1. GENERAL AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The AES Corporation is a holding company (the "Parent Company") that through its subsidiaries and affiliates,
(collectively, "AES" or "the Company") operates a geographically diversified portfolio of electricity generation and
distribution businesses. Generally, given this holding company structure, the liabilities of the individual operating
entities are non-recourse to the parent and are isolated to the operating entities. Most of our operating entities are
structured as limited liability entities, which limit the liability of shareholders. The structure is generally the same
regardless of whether a subsidiary is consolidated under a voting or variable interest model.
PRINCIPLES OF CONSOLIDATION — The Consolidated Financial Statements of the Company include the
accounts of The AES Corporation and its subsidiaries, which are the entities that it controls. Furthermore, variable
interest entities ("VIEs") in which the Company has a variable interest have been consolidated when the Company
is the primary beneficiary and thus controls the VIE. Intercompany transactions and balances are eliminated in
consolidation. Investments in entities where the Company has the ability to exercise significant influence, but not
control, are accounted for using the equity method of accounting.
DP&L, our utility in Ohio, has undivided interests in five generation facilities and numerous transmission
facilities. These undivided interests in jointly-owned facilities are accounted for on a pro-rata basis in our
consolidated financial statements. Certain expenses, primarily fuel costs for the generating units, are allocated to
the joint owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant
materials and operating supplies and capital additions are allocated to the joint owners in accordance with their
respective ownership interests. See Note 3—Property, Plant and Equipment for additional details.
USE OF ESTIMATES — The preparation of these consolidated financial statements in conformity with
accounting principles generally accepted in the United States of America ("GAAP") requires the Company to make
estimates and assumptions that affect reported amounts of assets and liabilities and disclosures of contingent
assets and liabilities at the date of the consolidated financial statements, as well as the reported amounts of
revenue and expenses during the reporting period. Actual results could differ from those estimates. Items subject to
such estimates and assumptions include: the carrying amount and estimated useful lives of long-lived assets; asset
retirement obligations; impairment of goodwill, long-lived assets and equity method investments; valuation
allowances for receivables and deferred tax assets; the recoverability of regulatory assets; the estimation of
regulatory liabilities; the fair value of financial instruments; the fair value of assets and liabilities acquired in a
business combination; the measurement of noncontrolling interest using the hypothetical liquidation at book value
("HLBV") method for certain renewable generation partnerships; the determination of whether a sale of
noncontrolling interests is considered to be a sale of in-substance real estate (as opposed to an equity transaction);
pension liabilities; environmental liabilities; and potential litigation claims and settlements.
DISCONTINUED OPERATIONS — Effective July 1, 2014, the Company prospectively adopted Accounting
Standards Update ("ASU") No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and
Equipment (Topic 360): Reporting discontinued Operations and Disclosures of Disposals of Components of an
Entity, which significantly changed the prior accounting guidance on discontinued operations. Under ASU No.
2014-08, only those disposals of components of an entity that represent a strategic shift that has (or a held-for-sale
business that will have) a major effect on an entity's operations and financial results are reported as discontinued
operations. Amongst other changes: equity method investments that were previously scoped-out of the discontinued
operations accounting guidance are now included in the scope; a business can meet the criteria to be classified as
held-for-sale upon acquisition and be reported in discontinued operations; and components where an entity retains
significant continuing involvement or where operations and cash flows will not be eliminated from ongoing
operations as a result of a disposal transaction can meet the definition of discontinued operations. Additionally,
where summarized amounts are presented on the face of the financial statements, reconciliations of those amounts
to major classes of line items are also required. ASU No. 2014-08 requires additional disclosures for individually
material components that do not meet the definition of discontinued operations. Prior to the adoption of ASU
2014-08 we had classified certain business as discontinued operations that would not meet the criteria under the
current standard. See Note 23—Dispositions for further information.
Prior to July 1, 2014, a discontinued operation was a component of the Company that either had been
disposed of or was classified as held-for-sale and where the Company did not expect to have significant cash flows
from or significant continuing involvement with the component as of one year after its disposal or sale. A component
131
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
was comprised of operations and cash flows that could be clearly distinguished, operationally and for financial
reporting purposes, from the rest of the Company.
Prior period amounts in the statement of operations are retrospectively revised to reflect the businesses
determined to be discontinued operations. The cash flows of businesses that are determined to be discontinued
operations or held-for-sale are included within the relevant categories within operating, investing and financing
activities. The aggregate amount of cash flows is offset by the net increase or decrease in cash of discontinued and
held-for-sale businesses, which is presented as a separate line item in the Consolidated Statements of Cash Flows.
When an operation is classified as held-for-sale, the Company recognizes any impairment expense on the
entire operation, which will include an amount allocable to noncontrolling interests, at the level of the held-for-sale
operation and/or at a parent entity as applicable. However, any gain or loss on the completion of a disposal
transaction is fully allocated to AES and to its noncontrolling interests at a parent entity level, given that the
operational level noncontrolling interests have been removed with deconsolidation of the disposed entity. Assets
and liabilities of held-for-sale businesses are classified as current when they are expected to be disposed of within
twelve months.
RECLASSIFICATIONS — To comply with newly adopted accounting standards, certain prior period amounts
in the consolidated financial statements have been reclassified to conform to the current presentation. Deferred
financing costs were reclassified from the Other current assets and Other noncurrent assets lines to the current and
noncurrent Non-recourse debt lines, respectively, in the Consolidated Balance Sheet for the year ended December
31, 2015. Additionally, amounts relating to capitalized software were reclassified from Electric generation,
distribution assets and other line to Other intangible assets, net of amortization line on the Consolidated Balance
sheet for the year ended December 31, 2015. See further detail in the new accounting pronouncements discussion.
FAIR VALUE — Fair value is the price that would be received to sell an asset or paid to transfer a liability in an
orderly, hypothetical transaction between market participants at the measurement date, or exit price. The Company
applies the fair value measurement accounting guidance to financial assets and liabilities in determining the fair
value of investments in marketable debt and equity securities, included in the Consolidated Balance Sheet line
items Short-term investments and Other assets (noncurrent); derivative assets, included in Other current assets and
Other assets (noncurrent); and, derivative liabilities, included in Accrued and other liabilities (current) and Other
long-term liabilities. The Company applies the fair value measurement guidance to nonfinancial assets and liabilities
upon the acquisition of a business or in conjunction with the measurement of an asset retirement obligation or a
potential impairment loss on an asset group or goodwill under the accounting guidance for the impairment of long-
lived assets or goodwill.
The Company makes assumptions about what market participants would assume in valuing an asset or
liability based on the best information available. These factors include nonperformance risk (the risk that the
obligation will not be fulfilled) and credit risk of the subsidiary (for liabilities) and of the counterparty (for assets). The
Company is prohibited from including transaction costs and any adjustments for blockage factors in determining fair
value. The principal or most advantageous market is considered from the perspective of the subsidiary owning the
asset or with the liability.
Fair value is based on observable market prices where available. Where they are not available, specific
valuation models and techniques are applied depending on what is being fair valued. These models and techniques
maximize the use of observable inputs and minimize the use of unobservable inputs. The process involves varying
levels of management judgment, the degree of which is dependent on price transparency and complexity. An
asset's or liability's level within the fair value hierarchy is based on the lowest level of input significant to the fair
value measurement, where Level 1 is the highest and Level 3 is the lowest. The three levels are defined as follows:
• Level 1 — unadjusted quoted prices in active markets accessible by the Company for identical assets or
liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency
and volume to provide pricing information on an ongoing basis.
• Level 2 — pricing inputs other than quoted market prices included in Level 1 which are based on observable
market data, that are directly or indirectly observable for substantially the full term of the asset or liability. These
include quoted market prices for similar assets or liabilities, quoted market prices for identical or similar assets in
markets that are not active, adjusted quoted market prices, inputs from observable data such as interest rate and
yield curves, volatilities or default rates observable at commonly quoted intervals or inputs derived from
observable market data by correlation or other means.
132
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
• Level 3 — pricing inputs that are unobservable from objective sources. Unobservable inputs are only used to the
extent observable inputs aren't available. These inputs maintain the concept of an exit price from the perspective
of a market participant and reflect assumptions of other market participants. The Company considers all market
participant assumptions that are available without unreasonable cost and effort. These are given the lowest
priority and are generally used in internally developed methodologies to generate management's best estimate of
the fair value when no observable market data is available.
Any transfers between all levels within the fair value hierarchy levels are recognized at the end of the reporting
period.
CASH AND CASH EQUIVALENTS — The Company considers unrestricted cash on hand, deposits in banks,
certificates of deposit and short-term marketable securities with original maturities of three months or less to be
cash and cash equivalents. The carrying amounts of such balances approximate fair value.
RESTRICTED CASH AND DEBT SERVICE RESERVES — These include cash balances which are restricted
as to withdrawal or usage by the subsidiary that owns the cash. The nature of restrictions includes restrictions
imposed by financing agreements such as security deposits kept as collateral, debt service reserves, maintenance
reserves, contractual terms and others, as well as restrictions imposed by agreements related to the sales of
businesses or long-term PPAs.
INVESTMENTS IN MARKETABLE SECURITIES — The Company's marketable investments are primarily
unsecured debentures, certificates of deposit, government debt securities and money market funds. Short-term
investments consist of marketable equity securities and debt securities with original maturities in excess of three
months with remaining maturities of less than one year.
Marketable debt securities that the Company has both the positive intent and ability to hold to maturity are
classified as held-to-maturity and are carried at amortized cost. Other marketable securities that the Company does
not intend to hold to maturity are classified as available-for-sale or trading and are carried at fair value. Available-for-
sale investments are fair valued at the end of each reporting period where the unrealized gains or losses are
reflected in AOCL, a separate component of equity.
Investments classified as trading are fair valued at the end of each reporting period through the Consolidated
Statements of Operations. Interest and dividends on investments are reported in interest income and other income,
respectively. Gains and losses on sales of investments are determined using the specific identification method.
ACCOUNTS AND NOTES RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS — Accounts
and notes receivable are carried at amortized cost. The Company periodically assesses the collectability of
accounts receivable, considering factors such as specific evaluation of collectability, historical collection experience,
the age of accounts receivable and other currently available evidence of the collectability, and records an allowance
for doubtful accounts for the estimated uncollectible amount as appropriate. Certain of our businesses charge
interest on accounts receivable either under contractual terms or where charging interest is a customary business
practice. In such cases, interest income is recognized on an accrual basis. When the collection of such interest is
not reasonably assured, interest income is recognized as cash is received. Individual accounts and notes receivable
are written off when they are no longer deemed collectible.
INVENTORY — Inventory primarily consists of fuel and other raw materials used to generate power, and spare
parts and supplies used to maintain power generation and distribution facilities. Inventory is carried at lower of cost
or market. Cost is the sum of the purchase price and incidental expenditures and charges incurred to bring the
inventory to its existing condition or location. Costs of inventory are valued primarily using the average cost method.
Generally, the carrying amount of fuel inventory is reduced to market value if the market value of inventory has
declined and it is expected that the carrying amount of inventory, in its use in the ordinary course of business, will
not be recovered through revenue earned from the generation of power. The carrying amount of spare parts and
supplies is typically reduced only in instances where the items are considered obsolete.
LONG-LIVED ASSETS — Long-lived assets include property, plant and equipment, assets under capital
leases and intangible assets subject to amortization (i.e., finite-lived intangible assets).
Property, plant and equipment — Property, plant and equipment are stated at cost, net of accumulated
depreciation. The cost of renewals and improvements that extend the useful life of property, plant and equipment
are capitalized.
133
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
Construction progress payments, engineering costs, insurance costs, salaries, interest and other costs directly
relating to construction in progress are capitalized during the construction period, provided the completion of the
project is deemed probable, or expensed at the time the Company determines that development of a particular
project is no longer probable. The continued capitalization of such costs is subject to ongoing risks related to
successful completion, including those related to government approvals, site identification, financing, construction
permitting and contract compliance. Construction-in-progress balances are transferred to electric generation and
distribution assets when an asset group is ready for its intended use. Government subsidies, liquidated damages
recovered for construction delays and income tax credits are recorded as a reduction to property, plant and
equipment and reflected in cash flows from investing activities.
Depreciation, after consideration of salvage value and asset retirement obligations, is computed primarily
using the straight-line method over the estimated useful lives of the assets, which are determined on a composite or
component basis. Maintenance and repairs are charged to expense as incurred. Capital spare parts, including
rotable spare parts, are included in electric generation and distribution assets. If the spare part is considered a
component, it is depreciated over its useful life after the part is placed in service. If the spare part is deemed part of
a composite asset, the part is depreciated over the composite useful life even when being held as a spare part.
The Company's Brazilian subsidiaries, which include both generation and distribution companies, operate
under concession contracts. Certain estimates are utilized to determine depreciation expense for the Brazilian
subsidiaries, including the useful lives of the property, plant and equipment and the amounts to be recovered at the
end of the concession contract. The amounts to be recovered under these concession contracts are based on
estimates that are inherently uncertain and actual amounts recovered may differ from those estimates. These
concession contracts are not within the scope of ASC 853—Service Concession Arrangements.
Intangible Assets Subject to Amortization — Finite-lived intangible assets are amortized over their useful lives
which range from 3 – 50 years. The Company accounts for purchased emission allowances as intangible assets
and records an expense when utilized or sold. Granted emission allowances are valued at zero.
Impairment of Long-lived Assets — When circumstances indicate that the carrying amount of long-lived assets
in a held-for-use asset group may not be recoverable, the Company evaluates the assets for potential impairment
using internal projections of undiscounted cash flows expected to result from the use and eventual disposal of the
assets. Events or changes in circumstances that may necessitate a recoverability evaluation may include, but are
not limited to, adverse changes in the regulatory environment, unfavorable changes in power prices or fuel costs,
increased competition due to additional capacity in the grid, technological advancements, declining trends in
demand, or an expectation that it is more likely than not that the asset will be disposed of before the end of its
previously estimated useful life. If the carrying amount of the assets exceeds the undiscounted cash flows expected
to result from its use, an impairment expense is recognized for the amount by which the carrying amount of the
asset group exceeds its fair value. The impairment expense cannot exceed the carrying amount of the long-lived
assets (but subject to the carrying amount not being reduced below fair value for any individual long-lived asset that
is determinable without undue cost and effort). For regulated assets where recovery through approved rates is
probable, an impairment expense could be reduced by the establishment of a regulatory asset. For other regulated
assets and for non-regulated assets, impairment is recognized as an expense. When long-lived assets meet the
criteria to be classified as held-for-sale and the carrying amount of the disposal group exceeds its fair value less
costs to sell, an impairment expense is recognized for the excess up to the carrying amount of the long-lived assets;
if the fair value of the disposal group subsequently exceeds the carrying amount while the disposal group is still
held-for-sale, any impairment expense previously recognized will be reversed up to the lower of the prior expense
or the subsequent excess.
SERVICE CONCESSION ASSETS — Service concession assets are stated at cost, net of accumulated
amortization, in accordance with ASC 853. Service concession assets represent the cost of all infrastructure to be
transferred to the public-sector entity grantors at the end of the concession. These costs primarily represent
construction progress payments, engineering costs, insurance costs, salaries, interest and other costs directly
relating to construction of the service concession infrastructure. Government subsidies, liquidated damages
recovered for construction delays and income tax credits are recorded as a reduction to Service Concession Assets.
Service concession assets are amortized and recognized in earnings as a cost of goods sold as infrastructure
construction revenue is recognized. Services provided under concession arrangements are recognized on a straight
line basis.
134
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
DEBT ISSUANCE COSTS — Costs incurred in connection with the issuance of long-term debt are deferred
and presented as a direct reduction from the face amount of that debt and amortized over the related financing
period using the effective interest method. Debt issuance costs related to a line-of-credit are deferred and presented
as an asset and amortized over the related financing period. Make-whole payments in connection with early debt
retirements are classified as cash flows used in financing activities.
EQUITY METHOD INVESTMENTS — Investments in entities over which the Company has the ability to
exercise significant influence, but not control, are accounted for using the equity method of accounting and reported
in Investments in and advances to affiliates on the Consolidated Balance Sheets. The Company periodically
assesses if there is an indication that the fair value of an equity method investment is less than its carrying amount.
When an indicator exists, any excess of the carrying amount over its estimated fair value is recognized as
impairment expense when the loss in value is deemed other-than-temporary and included in Other non-operating
expense in the Consolidated Statements of Operations. The difference between the carrying amount and our
underlying equity in the net assets of the investee are accounted for as if the investee were a consolidated
subsidiary, except that the portion that represents equity method goodwill is not reviewed for impairment like
consolidated goodwill. Upon acquiring the investment, we determine the fair value of the identifiable assets and
assumed liabilities and the AES share of the amortization of the basis difference between each fair value and the
carrying amount of the corresponding asset or liability in the financial statements of the investee. The amortization
of the basis difference is recognized in our net equity in earnings of affiliates over the life of the asset or liability.
The Company discontinues the application of the equity method when an investment is reduced to zero and
the Company is not otherwise committed to provide further financial support to the investee. The Company resumes
the application of the equity method accounting to the extent that net income is greater than the share of net losses
not previously recorded.
GOODWILL AND INDEFINITE-LIVED INTANGIBLE ASSETS — The Company evaluates goodwill and
indefinite-lived intangible assets for impairment on an annual basis and whenever events or changes in
circumstances necessitate an evaluation for impairment. The Company's annual impairment testing date is
October first.
Goodwill — The Company evaluates goodwill impairment at the reporting unit level, which is an SBU (i.e. an
operating segment as defined in the segment reporting accounting guidance), or a component (i.e., one level below
an operating segment). In determining its reporting units, the Company starts with its management reporting
structure. Operating segments are identified and then analyzed to identify components which make up these
operating segments. Two or more components are combined into a single reporting unit if they are economically
similar. Assets and liabilities are allocated to a reporting unit if the assets will be employed by or a liability relates to
the operations of the reporting unit or would be considered by a market participant in determining its fair value.
Goodwill resulting from an acquisition is assigned to the reporting units that are expected to benefit from the
synergies of the acquisition. Generally, each AES business with a goodwill balance constitutes a reporting unit as
they are not reported to segment management together with other businesses and are not similar to other
businesses in a segment.
Goodwill is evaluated for impairment either under the qualitative assessment option or the two-step test. If the
Company qualitatively determines it is more likely than not that the fair value of a reporting unit is greater than its
carrying amount, the two-step impairment test is unnecessary. Otherwise, goodwill is evaluated for impairment
using the two-step test, where the carrying amount of a reporting unit is compared to its fair value in Step 1; if the
fair value exceeds the carrying amount, Step 2 is unnecessary. If the carrying amount exceeds the reporting unit's
fair value, this could indicate potential impairment and Step 2 of the goodwill evaluation process is required to
determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any. When Step 2 is
necessary, the fair value of individual assets and liabilities is determined using valuations (which in some cases may
be based in part on third party valuation reports) or other observable sources of fair value, as appropriate. If the
carrying amount of goodwill exceeds its implied fair value, the excess is recognized as an impairment loss up to the
carrying amount of the goodwill.
Most of the Company's reporting units are not publicly traded. Therefore, the Company estimates the fair value
of its reporting units using internal budgets and forecasts, adjusted for any market participants' assumptions and
discounted at the rate of return required by a market participant. The Company generally considers both market and
income-based approaches to determine a range of fair value, but typically concludes that the value derived using an
income-based approach is more representative of fair value due to the lack of direct market comparables. The
135
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
Company utilizes market data, when available, to corroborate and determine the reasonableness of the fair value
derived from the income-based discounted cash flow analysis.
Indefinite-Lived Intangible Assets — The Company's indefinite-lived intangible assets primarily include land-
use rights and water rights. These are tested for impairment on an annual basis or whenever events or changes in
circumstances necessitate an evaluation for impairment. If the carrying amount of an intangible asset exceeds its
fair value, the excess is recognized as impairment expense. When deemed appropriate, the Company uses the
qualitative assessment option under the accounting guidance on goodwill and intangible assets to determine
whether the existence of events or circumstances indicate that it is more likely than not that an intangible asset is
impaired. If, after assessing the totality of events and circumstances, the Company determines that it is not more
likely than not that an intangible asset is impaired, no further action is taken. The accounting guidance provides the
option to bypass the qualitative assessment for any intangible asset in any period and proceed directly to
performing the quantitative impairment test.
ACCOUNTS PAYABLE AND OTHER ACCRUED LIABILITIES — Accounts payable consists of amounts due
to trade creditors related to the Company's core business operations. These payables include amounts owed to
vendors and suppliers for items such as energy purchased for resale, fuel, maintenance, inventory and other raw
materials. Other accrued liabilities include items such as income taxes, regulatory liabilities, legal contingencies and
employee-related costs including payroll, benefits and related taxes.
REGULATORY ASSETS AND LIABILITIES — The Company records assets and liabilities that result from the
regulated ratemaking process that are not recognized under GAAP for non-regulated entities. Regulatory assets
generally represent incurred costs that have been deferred due to the future recovery in customer rates being
probable. Generally, returns earned on regulatory assets are reflected on the Consolidated Statement of Operations
within Interest Income. Regulatory liabilities generally represent obligations to make refunds to customers.
Management continually assesses whether the regulatory assets are probable of future recovery and regulatory of
liabilities are probable of future payment by considering factors such as applicable regulatory changes, recent rate
orders applicable to other regulated entities and the status of any pending or potential deregulation legislation. If
future recovery of costs previously deferred ceases to be probable, the related regulatory assets are written off and
recognized in income from continuing operations.
PENSION AND OTHER POSTRETIREMENT PLANS — The Company recognizes in its Consolidated
Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with
current-year changes in actuarial gains or losses recognized in AOCL, except for those plans at certain of the
Company's regulated utilities that can recover portions of their pension and postretirement obligations through
future rates. All plan assets are recorded at fair value. AES follows the measurement date provisions of the
accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined
benefit plans.
Effective January 1, 2016, the Company applied a disaggregated discount rate approach for determining
service cost and interest cost for its defined benefit pension plans and postretirement plans in the U.S. and U.K.
This approach is consistent with the requirements of ASC 715—Compensation—Retirement Benefits and is
considered to be more precise compared to the aggregated single rate discount approach, which has historically
been used in the U.S. and U.K., because it is more consistent with the philosophy of a full yield curve valuation. The
disaggregated rate approach can be applied only in countries with a sufficiently robust yield curve. For countries
other than the U.S. and U.K., the Company will continue to apply a local government bond yield approach.
The change in discount rate approach in the U.S. and U.K. did not have an impact on the measurement of the
benefit obligations as of December 31, 2015. The 2016 service costs and interest costs included in Note 14—
Benefit Plans reflect the change in estimate described above. The impact of the change in approach on service
costs for the U.S. and U.K. plans in 2016 is shown below (in millions):
U.S.
U.K.
Total
Disaggregated
rate approach
2016 Service Cost
Aggregate rate
approach
Impact of
change
Disaggregated
rate approach
2016 Interest Cost
Aggregate rate
approach
Impact of
change
$
$
13
3
16
$
$
14
4
18
$
$
(1) $
(1)
(2) $
42
7
49
$
$
51
9
60
$
$
(9)
(2)
(11)
INCOME TAXES — Deferred tax assets and liabilities are recognized for the future tax consequences
attributable to differences between the financial statement carrying amounts of the existing assets and liabilities,
136
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
and their respective income tax bases. The Company establishes a valuation allowance when it is more likely than
not that all or a portion of a deferred tax asset will not be realized. The Company's tax positions are evaluated under
a more likely than not recognition threshold and measurement analysis before they are recognized for financial
statement reporting.
Uncertain tax positions have been classified as noncurrent income tax liabilities unless expected to be paid
within one year. The Company's policy for interest and penalties related to income tax exposures is to recognize
interest and penalties as a component of the provision for income taxes in the Consolidated Statements of
Operations.
ASSET RETIREMENT OBLIGATIONS — The Company records the fair value of the liability for a legal
obligation to retire an asset in the period in which the obligation is incurred. When a new liability is recognized, the
Company capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The
liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the
related asset. Upon settlement of the obligation, the Company eliminates the liability and, based on the actual cost
to retire, may incur a gain or loss.
NONCONTROLLING INTERESTS — Noncontrolling interests are classified as a separate component of
equity in the Consolidated Balance Sheets and Consolidated Statements of Changes in Equity. Additionally, net
income and comprehensive income attributable to noncontrolling interests are reflected separately from
consolidated net income and comprehensive income on the Consolidated Statements of Operations and
Consolidated Statements of Changes in Equity. Any change in ownership of a subsidiary while the controlling
financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling
interests (unless the transaction qualifies as a sale of in-substance real estate). Losses continue to be attributed to
the noncontrolling interests, even when the noncontrolling interests' basis has been reduced to zero.
Although, in general, the noncontrolling ownership interest in earnings is calculated based on ownership
percentage, certain of the Company's businesses are subject to profit-sharing arrangements. These agreements
exist for certain renewable generation partnerships to designate different allocations of value among investors,
where the allocations change in form or percentage over the life of the partnership. For these businesses, the
Company uses the HLBV method when it is a reasonable approximation of the profit-sharing arrangement. HLBV
uses a balance sheet approach, which measures the Company's share of income or loss by calculating the change
in the amount of net worth the partners are legally able to claim based on a hypothetical liquidation of the entity at
the beginning of a reporting period compared to the end of that period.
Equity securities with redemption features that are not solely within the control of the issuer are classified
outside of permanent equity. Generally, initial measurement will be at fair value. Subsequent measurement and
classification vary depending on whether the instrument is probable of becoming redeemable. Where the equity
instrument is not probable of becoming redeemable subsequent allocation of income and dividends is classified in
permanent equity. For those securities where it is probable that the instrument will become redeemable or that are
currently redeemable, AES recognizes changes in the fair value at each accounting period against retained
earnings subject to the floor of the initial fair value. Further, the allocation of income and dividends, as well as the
adjustment to fair value, is classified outside permanent equity. Amounts that are mandatory redeemable are
classified as a liability.
FOREIGN CURRENCY TRANSLATION — A business's functional currency is the currency of the primary
economic environment in which the business operates and is generally the currency in which the business
generates and expends cash. Subsidiaries and affiliates whose functional currency is a currency other than the
U.S. dollar translate their assets and liabilities into U.S. dollars at the current exchange rates in effect at the end of
the fiscal period. Translation adjustments arising from the translation of the balance sheet of such subsidiaries are
included in AOCL. The revenue and expense accounts of such subsidiaries and affiliates are translated into
U.S. dollars at the average exchange rates that prevailed during the period. Gains and losses on intercompany
foreign currency transactions that are long-term in nature and which the Company does not intend to settle in the
foreseeable future, are also recognized in AOCL. Gains and losses that arise from exchange rate fluctuations on
transactions denominated in a currency other than the functional currency are included in determining net income.
Accumulated foreign currency translation adjustments are reclassified from AOCL to net income only when realized
upon sale or upon complete or substantially complete liquidation of the investment in a foreign entity. The
accumulated adjustments are included in carrying amounts in impairment assessments where the Company has
committed to a plan that will cause the accumulated adjustments to be reclassified to earnings.
137
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
REVENUE RECOGNITION — Revenue from utilities is classified as regulated in the Consolidated Statements
of Operations. Revenue from the sale of energy is recognized in the period during which the sale occurs. The
calculation of revenue earned but not yet billed is based on the number of days not billed in the month, the
estimated amount of energy delivered during those days and the estimated average price per customer class for
that month. Differences between actual and estimated unbilled revenue are usually immaterial. The Company has
businesses where it sells and purchases power to and from ISOs and RTOs. In those instances, the Company
accounts for these transactions on a net hourly basis because the transactions are settled on a net hourly basis.
Revenue from generation businesses is classified as non-regulated and is recognized based upon output delivered
and capacity provided, at rates as specified under contract terms or prevailing market rates. Certain of the
Company PPAs meet the definition of an operating lease or contain similar arrangements. Typically, minimum lease
payments from such PPAs are recognized as revenue on a straight-line basis over the lease term whereas
contingent rentals are recognized when earned. Revenue is recorded net of any taxes assessed on and collected
from customers, which are remitted to the governmental authorities.
SHARE-BASED COMPENSATION — The Company grants share-based compensation in the form of stock
options, restricted stock units, and performance stock units. The expense is based on the grant-date fair value of
the equity or liability instrument issued and is recognized on a straight-line basis over the requisite service period,
net of estimated forfeitures. The Company uses a Black-Scholes option pricing model to estimate the fair value of
stock options granted to its employees.
GENERAL AND ADMINISTRATIVE EXPENSES — General and administrative expenses include corporate
and other expenses related to corporate staff functions and initiatives, primarily executive management, finance,
legal, human resources and information systems, which are not directly allocable to our business segments.
Additionally, all costs associated with corporate business development efforts are classified as general and
administrative expenses.
DERIVATIVES AND HEDGING ACTIVITIES — Under the accounting standards for derivatives and hedging,
the Company recognizes all contracts that meet the definition of a derivative, except those designated as normal
purchase or normal sale at inception, as either assets or liabilities in the Consolidated Balance Sheets and
measures those instruments at fair value. See the Company's fair value policy and Note 4—Fair Value for additional
discussion regarding the determination of the fair value. The PPAs and fuel supply agreements entered into by the
Company are evaluated to determine if they meet the definition of a derivative or contain embedded derivatives,
either of which require separate valuation and accounting. To be a derivative under the accounting standards for
derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial
net investment and could be net settled. Generally, these agreements do not meet the definition of a derivative,
often due to the inability to be net settled. On a quarterly basis, we evaluate the markets for the commodities to be
delivered under these agreements to determine if facts and circumstances have changed such that the agreements
could then be net settled and meet the definition of a derivative.
Derivatives primarily consist of interest rate swaps, cross-currency swaps, foreign currency instruments, and
commodity derivatives. The Company enters into various derivative transactions in order to hedge its exposure to
certain market risks, primarily interest rate, foreign currency and commodity price risks. Regarding interest rate risk,
the Company and our subsidiaries generally utilize variable rate debt financing for construction projects and
operations so interest rate swap, lock, cap, and floor agreements are entered into to manage interest rate risk by
effectively fixing or limiting the interest rate exposure on the underlying financing and are typically designated as
cash flow hedges. Regarding foreign currency risk, we are exposed to it as a result of our investments in foreign
subsidiaries and affiliates that may be impacted by significant fluctuations in foreign currency exchange rates so
foreign currency options and forwards are utilized, where deemed appropriate, to manage the risk related to these
fluctuations. Cross-currency swaps are utilized in certain instances to manage the risk related to certain foreign
currencies and the associated impact on interest and loan principal payments. In addition, certain of our
subsidiaries have entered into contracts which contain embedded foreign currency derivatives as a result of the
contracts being denominated in a currency other than the functional or local currency of the parties to the contract.
Regarding commodity price risk, we are exposed to the impact of market fluctuations in the price of electricity, fuel
and environmental credits. Although we primarily consist of businesses with long-term contracts or retail sales
concessions (which provide our distribution businesses with a franchise to serve a specific geographic region), a
portion of our current and expected future revenues are derived from businesses without significant long-term
purchase or sales contracts. We use an overall hedging strategy, not just derivatives, to hedge our financial
performance against the effects of fluctuations in commodity prices.
138
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
The accounting standards for derivatives and hedging enable companies to designate qualifying derivatives as
hedging instruments based on the exposure being hedged. The Company only has cash flow hedges at this time.
Changes in the fair value of a derivative that is highly effective, designated and qualifies as a cash flow hedge are
deferred in AOCL and are recognized into earnings as the hedged transactions affect earnings. Any ineffectiveness
is recognized in earnings immediately. For all designated and qualifying hedges, the Company maintains formal
documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives
and hedging. If AES determines that the derivative is no longer highly effective as a hedge, hedge accounting will be
discontinued prospectively. For cash flow hedges of forecasted transactions, AES estimates the future cash flows of
the forecasted transactions and evaluates the probability of the occurrence and timing of such transactions.
Changes in conditions or the occurrence of unforeseen events could require discontinuance of hedge accounting or
could affect the timing of the reclassification of gains or losses on cash flow hedges from AOCL into earnings.
While derivative transactions are not entered into for trading purposes, some contracts are either not eligible
or not designated for hedge accounting. Changes in the fair value of derivatives not designated and qualifying as
cash flow hedges are immediately recognized in earnings. Regardless of when gains or losses on derivatives
(including all those where the fair value measurement is classified as Level 3) are recognized in earnings, they are
generally classified as follows: interest expense for interest rate and cross-currency derivatives, foreign currency
transaction gains or losses for foreign currency derivatives, and non-regulated revenue or non-regulated cost of
sales for commodity and other derivatives. However, gains and losses on interest rate and cross-currency
derivatives are classified as foreign currency transaction gains and losses if they offset the remeasurement of the
foreign currency-denominated debt being hedged by the cross-currency swaps. If the underlying hedged item is
construction debt, the effective portion of the realized swap payment related to capitalized interest is deferred in
AOCL, then reclassified to cost of sales to offset depreciation expense over the useful life of the associated asset.
Any foreign currency remeasurement effects in earnings of the foreign currency denominated debt is offset by a
reclassification from AOCL. Cash flows arising from derivatives are included in the Consolidated Statements of
Cash Flows as an operating activity given the nature of the underlying risk being economically hedged and the lack
of significant financing elements, except that cash flows on designated and qualifying hedges of variable-rate
interest during construction are classified as an investing activity.
The Company has elected not to offset net derivative positions in the financial statements. Accordingly, the
Company does not offset such derivative positions against the fair value of amounts (or amounts that approximate
fair value) recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral
(a payable) under master netting arrangements.
NEW ACCOUNTING PRONOUNCEMENTS — The following table provides a brief description of recent
accounting pronouncements that had and/or could have a material impact on the Company’s consolidated financial
statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable
or are expected to have no material impact on the Company’s consolidated financial statements.
139
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
New Accounting Standards Adopted
ASU Number and Name
Description
2016-19 — Technical
Corrections and
Improvements
This standard clarifies that the license of internal-use software shall
be accounted for as the acquisition of an intangible asset. Transition
Method: retrospective.
The adoption of the new guidance did not have an impact on net
income, net assets or net equity.
2015-03, 2015-15,
Interest — Imputation of
Interest (Subtopic
835-30)
2015-02, Consolidation
— Amendments to the
Consolidation Analysis
(Topic 810)
These standards simplify the presentation of debt issuance costs by
requiring that debt issuance costs related to a tranche of debt be
presented on the balance sheet as a direct deduction from the
carrying amount of that debt, consistent with debt discounts. Debt
issuance costs related to a line-of-credit can still be presented as an
asset and subsequently amortized over the term of the line-of-credit,
regardless of whether there are any outstanding borrowings on the
line-of-credit arrangement. The recognition and measurement
guidance for debt issuance costs are not affected by the standard.
Transition method: retrospective.
The standard makes targeted amendments to the current
consolidation guidance and ends the deferral granted to investment
companies from applying the VIE guidance. The standard amends the
evaluation of whether (1) fees paid to a decision-maker or service
providers represent a variable interest, (2) a limited partnership or
similar entity has the characteristics of a VIE and (3) a reporting entity
is the primary beneficiary of a VIE. Transition method: retrospective.
New Accounting Standards Issued But Not Yet Effective
ASU Number and Name
Description
2017-04, Intangibles -
Goodwill and Other
(Topic 350): Simplifying
the Test for Goodwill
Impairment
This standard simplifies the accounting for goodwill impairment by
removing the requirement to calculate the implied fair value. Instead,
it requires that an entity records an impairment charge based on the
excess of a reporting unit's carrying amount over its fair value.
Transition method: retrospective.
2017-01, Business
Combinations (Topic
805): Clarifying the
Definition of a Business
2016-18, Statement of
Cash Flows (Topic 320):
Restricted Cash (a
consensus of the FASB
Emerging Issues Task
Force)
This standard provides guidance to assist the entities with evaluating
when a set of transferred assets and activities is a business.
Transition method: prospective.
This standard requires that a statement of cash flows explain the
change during the period in the total of cash, cash equivalents, and
amounts generally described as restricted cash or restricted cash
equivalents. Therefore, amounts generally described as restricted
cash and restricted cash equivalents should be included with cash
and cash equivalents when reconciling the beginning-of-period and
end-of-period total amounts shown on the statement of cash flows.
Transition method: retrospective.
2016-16, Income Taxes
(Topic 740): Intra-Entity
Transfers of Assets
Other Than Inventory
This standard requires that an entity recognizes the income tax
consequences of an intra-entity transfer of an asset other than
inventory when the transfer occurs. Transition method: modified
retrospective.
2016-15, Statement of
Cash Flows (Topic 230):
Classification of Certain
Receipts and Cash
Payments (a consensus
of the Emerging Issues
Task Force)
2016-13, Financial
Instruments-Credit
Losses (Topic 326):
Measurement of Credit
Losses on Financial
Instruments
This standard provides specific guidance on how certain cash
transactions are presented and classified in the statement of cash
flows. Transition method: retrospective.
The standard updates the impairment model for financial assets
measured at amortized cost to an expected loss model rather than an
incurred loss model. It also allows for the presentation of credit losses
on available-for-sale debt securities as an allowance rather than a
write down. Transition method: various.
Date of
Adoption
December
31, 2016
January 1,
2016
Effect on the financial statements
upon adoption
The license fees and
capitalized costs of internal-use
software previously classified
as property plant and
equipment of $469 million, the
corresponding accumulated
amortization of $388 million,
and construction in progress of
$52 million were reclassified to
intangible assets as of
December 31, 2015.
Deferred financing costs of $24
million previously classified
within other current assets and
$357 million previously
classified within other
noncurrent assets were
reclassified to reduce the
related debt liabilities as of
December 31, 2015.
January 1,
2016
None, other than that some
entities previously consolidated
under the voting model are
now consolidated under the
VIE model.
Effect on the financial statements
upon adoption
The Company is currently
evaluating the impact of
adopting the standard on its
consolidated financial
statements.
The Company is currently
evaluating the impact of
adopting the standard on its
consolidated financial
statements.
The Company is currently
evaluating the impact of
adopting the standard on its
consolidated financial
statements.
The Company is currently
evaluating the impact of
adopting the standard on its
consolidated financial
statements.
The Company is currently
evaluating the impact of
adopting the standard, but
does not anticipate a material
impact on its consolidated
financial statements.
The Company is currently
evaluating the impact of
adopting the standard on its
consolidated financial
statements.
Date of
Adoption
January 1,
2020. Early
adoption is
permitted
as of
January 1,
2017.
January 1,
2018. Early
adoption is
permitted
January 1,
2018. Early
adoption is
permitted.
January 1,
2018. Early
adoption is
permitted.
January 1,
2018. Early
adoption is
permitted.
January 1,
2020. Early
adoption is
permitted
only as of
January 1,
2019.
140
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
2016-09, Compensation
— Stock Compensation
(Topic 718):
Improvements to
Employee Share-Based
Payment Accounting
The standard simplifies the following aspects of accounting for share-
based payments awards: accounting for income taxes, classification
of excess tax benefits on the statement of cash flows, forfeitures,
statutory tax withholding requirements, classification of awards as
either equity or liabilities and classification of employee taxes paid on
statement of cash flows when an employer withholds shares for tax-
withholding purposes. Transition method: The recording of excess tax
benefits and tax deficiencies arising from vesting or settlement will be
applied prospectively. The elimination of the requirement that excess
tax benefits be realized before they are recognized will be adopted on
a modified retrospective basis with a cumulative adjustment to the
opening balance sheet.
January 1,
2017.
The standard creates Topic 842, Leases, which supersedes Topic
840, Leases. It introduces a lessee model that brings substantially all
leases onto the balance sheet while retaining most of the principles of
the existing lessor model in U.S. GAAP and aligning many of those
principles with ASC 606, Revenue from Contracts with Customers.
Transition method: modified retrospective approach with certain
practical expedients.
See discussion of the ASU below:
2016-02, Leases (Topic
842)
2014-09, 2015-14,
2016-08, 2016-10,
2016-12, 2016-20,
Revenue from Contracts
with Customers (Topic
606)
January 1,
2019. Early
adoption is
permitted.
January 1,
2018.
Earlier
application
is permitted
only as of
January 1,
2017.
The primary effect of adoption
will be the recognition of
excess tax benefits in our
provision for income taxes in
the period when the awards
vest or are settled, rather than
in paid-in-capital in the period
when the excess tax benefits
are realized. Upon adoption,
the change will result in a
decrease of approximately $30
million to net deferred tax
liabilities, offset by an increase
to retained earnings. We will
continue to estimate the
number of awards that are
expected to vest in our
determination of the related
periodic compensation cost.
The Company is currently
evaluating the impact of
adopting the standard on its
consolidated financial
statements. The Company
intends to adopt the standard
as of January 1, 2019.
The Company will adopt the
standard on January 1, 2018;
see below for the evaluation of
the impact of its adoption on
the consolidated financial
statements.
ASU 2014-09 and its subsequent corresponding updates provides the principles an entity must apply to
measure and recognize revenue. The core principle is that an entity shall recognize revenue to depict the transfer of
promised goods or services to customers in an amount that reflects the consideration to which the entity expects to
be entitled in exchange for those goods or services. Amendments to the standard were issued that provide further
clarification of the principle and to provide certain transition expedients. The standard will replace most existing
revenue recognition guidance in GAAP, including the guidance on recognizing other income upon the sale or
transfer of nonfinancial assets (including in-substance real estate).
The standard requires retrospective application and allows either a full retrospective adoption in which all of
the periods are presented under the new standard or a modified retrospective approach in which the cumulative
effect of initially applying the guidance is recognized at the date of initial application. We are currently working
towards adopting the standard using the full retrospective method. However, the company will continue to assess
this conclusion which is dependent on the final impact to the financial statements.
In 2016, the company established a cross-functional implementation team and is in the process of evaluating
changes to our business processes, systems and controls to support recognition and disclosure under the new
standard. At this time, we do not expect any significant impact on our financial systems as a result of the
implementation of the new revenue recognition standard.
Given the complexity and diversity of our non-regulated arrangements, the Company is assessing the standard
on a contract by contract basis and has completed more than half of the total expected effort. Through this
assessment, the Company has identified certain key issues that we are continuing to evaluate in order to complete
our assessment of the full population of contracts and be able to assess the overall impact to the financial
statements. These issues include: the application of the practical expedient for measuring progress toward
satisfaction of a performance obligation, when variable quantities would be considered variable consideration
versus an option to acquire additional goods and services, how to measure progress toward completion for a
performance obligation that is a bundle and application of the standard to contracts that are under the scope of
Service Concession Arrangements (Topic 853). We are continuing to work with various non-authoritative industry
groups, and monitoring the FASB and Transition Resource Group (TRG) activity, as we finalize our accounting
policy on these and other industry specific interpretative issues which is expected in 2017.
141
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
2. INVENTORY
Inventory is valued primarily using the average-cost method. The following table summarizes the Company's
inventory balances as of the dates indicated (in millions):
December 31,
Fuel and other raw materials
Spare parts and supplies
Total
3. PROPERTY, PLANT AND EQUIPMENT
2016
2015
302
328
630
$
$
343
328
671
$
$
The following table summarizes the components of the electric generation and distribution assets and other
property, plant and equipment (in millions) with their estimated useful lives (in years). The amounts are stated net of
all prior asset impairment losses recognized.
Electric generation and distribution facilities
Other buildings
Furniture, fixtures and equipment
Other
Total electric generation and distribution assets and other
Accumulated depreciation
Net electric generation and distribution assets and other
Estimated Useful Life
4 - 68
3 - 63
3 - 31
2 - 50
December 31,
2016
2015
$
$
25,773
2,034
309
423
28,539
(9,528)
19,011
$
$
24,740
1,856
288
398
27,282
(8,939)
18,343
The following table summarizes depreciation expense (including the amortization of assets recorded under
capital leases and the amortization of asset retirement obligations) and interest capitalized during development and
construction on qualifying assets for the periods indicated (in millions):
Years Ended December 31,
Depreciation expense
Interest capitalized during development and construction
2016
$ 1,105
125
2015
$ 1,064
89
2014
$ 1,154
118
Property, plant and equipment, net of accumulated depreciation, of $10 billion and $11 billion was mortgaged,
pledged or subject to liens as of December 31, 2016 and 2015, respectively.
The following table summarizes regulated and non-regulated generation and distribution property, plant and
equipment and accumulated depreciation as of the dates indicated (in millions):
December 31,
Regulated generation, distribution assets and other, gross
Regulated accumulated depreciation
Regulated generation, distribution assets and other, net
Non-regulated generation, distribution assets and other, gross
Non-regulated accumulated depreciation
Non-regulated generation, distribution assets and other, net
Net electric generation, distribution assets and other
2016
2015
$
$
11,021
(4,194)
6,827
17,518
(5,334)
12,184
19,011
$
$
10,789
(3,984)
6,805
16,493
(4,955)
11,538
18,343
The following table presents amounts recognized related to asset retirement obligations for the periods
indicated (in millions):
Balance at January 1
Additional liabilities incurred
Liabilities settled
Accretion expense
Change in estimated cash flows
Other
Balance at December 31
2016
2015
$
$
247
12
(4)
15
86
1
357
$
$
209
43
(6)
13
(7)
(5)
247
The Company's asset retirement obligations primarily include active ash landfills, water treatment basins and
the removal or dismantlement of certain plants and equipment. The $86 million increase in estimated cash flows for
2016 is primarily relates to revised estimated closure expenditures and earlier plant closure dates than previously
forecast at DPL. There were $1 million of legally restricted assets for the year ended December 31, 2016 and $2
million for the year ended December 31, 2015 for purposes of settling asset retirement obligations.
142
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
Ownership of Certain Coal-Fired Facilities — DP&L has undivided ownership interests in five coal-fired
generation facilities jointly owned with other utilities. DP&L's share of the operating costs of the facilities is included
in Cost of Sales in the Consolidated Statements of Operations and its share of investment in the facilities is included
in Property, Plant and Equipment in the Consolidated Balance Sheets. DP&L's undivided ownership interest in the
facilities as of December 31, 2016 is as follows ($ in millions):
Production units:
Conesville Unit 4
Killen Station
Miami Fort Units 7 and 8
Stuart Station
Zimmer Station
Transmission
Total
4. FAIR VALUE
DP&L Share
Ownership
17%
67%
36%
35%
28%
Various
$
$
Gross Plant In Service
Accumulated Depreciation
DP&L Investment
— $
34
27
24
7
99
191
$
Construction Work In Process
—
2
7
23
9
—
41
— $
—
—
—
—
66
66
$
The fair value of current financial assets and liabilities, debt service reserves and other deposits approximate
their reported carrying amounts. The estimated fair values of the Company's assets and liabilities have been
determined using available market information. By virtue of these amounts being estimates and based on
hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or
estimation methodologies may have a material effect on the estimated fair value amounts.
Valuation Techniques — The fair value measurement accounting guidance describes three main approaches
to measuring the fair value of assets and liabilities: (1) market approach, (2) income approach and (3) cost
approach. The market approach uses prices and other relevant information generated from market transactions
involving identical or comparable assets or liabilities. The income approach uses valuation techniques to convert
future amounts to a single present value amount. The measurement is based on current market expectations of the
return on those future amounts. The cost approach is based on the amount that would currently be required to
replace an asset. The Company measures its investments and derivatives at fair value on a recurring basis.
Additionally, in connection with annual or event-driven impairment evaluations, certain nonfinancial assets and
liabilities are measured at fair value on a nonrecurring basis. These include long-lived tangible assets (i.e., property,
plant and equipment), goodwill and intangible assets (e.g., sales concessions, land use rights and water rights,
etc.). In general, the Company determines the fair value of investments and derivatives using the market approach
and the income approach, respectively. In the nonrecurring measurements of nonfinancial assets and liabilities, all
three approaches are considered; however, the value estimated under the income approach is often the most
representative of fair value.
Investments — The Company's investments measured at fair value generally consist of marketable debt and
equity securities. Equity securities are either measured at fair value using quoted market prices, which are
considered Level 1 measurements in the fair value hierarchy, or measured at fair value based on comparisons to
market data obtained for similar assets, which are considered Level 2 measurements in the fair value hierarchy.
Debt securities primarily consist of unsecured debentures, certificates of deposit and government debt securities
held by our Brazilian subsidiaries. Returns and pricing on these instruments are generally indexed to the CDI rates
in Brazil. Debt securities are measured at fair value based on comparisons to market data obtained for similar
assets and are considered Level 2 measurements in the fair value hierarchy.
Derivatives — Any Level 1 derivative instruments are exchange-traded commodity futures for which the pricing is
observable in active markets, and as such, these are not expected to transfer to other levels. There have been no
transfers between Level 1 and Level 2.
For all derivatives, with the exception of any classified as Level 1, the income approach is used, which consists
of forecasting future cash flows based on contractual notional amounts and applicable and available market data as
of the valuation date. The most common market data inputs used in the income approach include volatilities, spot
and forward benchmark interest rates (such as LIBOR and EURIBOR), foreign exchange rates and commodity
prices. Forward rates with the same tenor as the derivative instrument being valued are generally obtained from
published sources, with these forward rates being assessed quarterly at a portfolio-level for reasonableness versus
comparable published information provided from another source. When significant inputs are not observable, the
Company uses relevant techniques to determine the inputs, such as regression analysis or prices for similarly
traded instruments available in the market.
143
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
For derivatives for which there is a standard industry valuation model, the Company uses a third-party
derivative accounting and valuation service provider that uses a standard model and observable inputs to estimate
the fair value. For these derivatives, the Company performs analytical procedures and makes comparisons to other
third-party information in order to assess the reasonableness of the fair value. For derivatives for which there is not
a standard industry valuation model (such as PPAs and fuel supply agreements that are derivatives or include
embedded derivatives), the Company has created internal valuation models to estimate the fair value, using
observable data to the extent available. At each quarter-end, the models for the commodity and foreign currency-
based derivatives are generally prepared and reviewed by employees who globally manage the respective
commodity and foreign currency risks and are analytically reviewed independent of those employees.
Those cash flows are then discounted using the relevant spot benchmark interest rate (such as LIBOR or
EURIBOR). The Company then makes a credit valuation adjustment ("CVA") by further discounting the cash flows
for nonperformance or credit risk based on the observable or estimated debt spread of the Company's subsidiary or
its counterparty and the tenor of the respective derivative instrument. The CVA for potential future scenarios in
which the derivative is in an asset is based on the counterparty's credit ratings, credit default swap spreads, and
debt spreads, as available. The CVA for potential future scenarios in which the derivative is a liability is based on the
Parent Company's or the subsidiary's current debt spread. In the absence of readily obtainable credit information,
the Parent Company's or the subsidiary's estimated credit rating (based on applying a standard industry model to
historical financial information and then considering other relevant information) and spreads of comparably rated
entities or the respective country's debt spreads are used as a proxy. All derivative instruments are analyzed
individually and are subject to unique risk exposures.
The Company's methodology to fair value its derivatives is to start with any observable inputs; however, in
certain instances the published forward rates or prices may not extend through the remaining term of the contract
and management must make assumptions to extrapolate the curve, which necessitates the use of unobservable
inputs, such as proxy commodity prices or historical settlements to forecast forward prices. Specifically, where there
is limited forward curve data with respect to foreign exchange contracts, beyond the traded points the Company
utilizes the purchasing power parity approach to construct the remaining portion of the forward curve using relative
inflation rates. In addition, in certain instances, there may not be market or market-corroborated data readily
available, requiring the use of unobservable inputs. Similarly, in certain instances, the spread that reflects the credit
or nonperformance risk is unobservable requiring us to utilize proxy yield curves of similar credit quality. The fair
value hierarchy of an asset or a liability is based on the level of significance of the input assumptions. An input
assumption is considered significant if it affects the fair value by at least 10%. Assets and liabilities are classified as
Level 3 when the use of unobservable inputs is significant. When the use of unobservable inputs is insignificant,
assets and liabilities are classified as Level 2. Transfers between Level 3 and Level 2 are determined as of the end
of the reporting period and result from changes in significance of unobservable inputs used to calculate the CVA.
Debt — Recourse and non-recourse debt are carried at amortized cost. The fair value of recourse debt is
estimated based on quoted market prices. The fair value of non-recourse debt is estimated differently based upon
the type of loan. In general, the carrying amount of variable rate debt is a close approximation of its fair value. For
fixed rate loans, the fair value is estimated using quoted market prices or discounted cash flow ("DCF") analyses. In
the DCF analysis, the discount rate is based on the credit rating of the individual debt instruments, if available, or
the credit rating of the subsidiary. If the subsidiary's credit rating is not available, a synthetic credit rating is
determined using certain key metrics, including cash flow ratios and interest coverage, as well as other industry-
specific factors. For subsidiaries located outside the U.S., in the event that the country rating is lower than the credit
rating previously determined, the country rating is used for purposes of the DCF analysis. The fair value of recourse
and non-recourse debt excludes accrued interest at the valuation date. The fair value was determined using
available market information as of December 31, 2016. The Company is not aware of any factors that would
significantly affect the fair value amounts subsequent to December 31, 2016.
Nonrecurring Measurements — For nonrecurring measurements derived using the income approach, fair value
is determined using valuation models based on the principles of DCF. The income approach is most often used in
the impairment evaluation of long-lived tangible assets, equity method investments, goodwill, and intangible assets.
The Company uses its internally developed DCF valuation models as the primary means to determine nonrecurring
fair value measurements though other valuation approaches prescribed under the fair value measurement
accounting guidance are also considered. Depending on the complexity of a valuation, an independent valuation
firm may be engaged to assist management in the valuation process. A few examples of input assumptions to such
valuations include macroeconomic factors such as growth rates, industry demand, inflation, exchange rates and
144
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
power and commodity prices. Whenever possible, the Company attempts to obtain market observable data to
develop input assumptions. Where the use of market observable data is limited or not available for certain input
assumptions, the Company develops its own estimates using a variety of techniques such as regression analysis
and extrapolations.
For nonrecurring measurements derived using the market approach, recent market transactions involving the
sale of identical or similar assets are considered. The use of this approach is limited because it is often difficult to
identify sale transactions of identical or similar assets. This approach is used in impairment evaluations of certain
intangible assets. Otherwise, it is used to corroborate the fair value determined under the income approach.
For nonrecurring measurements derived using the cost approach, fair value is typically based upon a
replacement cost approach. Under this approach, the depreciated replacement cost of assets is derived by first
estimating the current replacement cost of assets and then applying the remaining useful life percentages to such
costs. Further adjustments for economic and functional obsolescence are made to the depreciated replacement
cost. This approach involves a considerable amount of judgment, which is why its use is limited to the measurement
of long-lived tangible assets. Like the market approach, this approach is also used to corroborate the fair value
determined under the income approach.
Fair Value Considerations — In determining fair value, the Company considers the source of observable
market data inputs, liquidity of the instrument, the credit risk of the counterparty and the risk of the Company's or its
counterparty's nonperformance. The conditions and criteria used to assess these factors are:
Sources of market assumptions — The Company derives most of its market assumptions from market efficient
data sources (e.g., Bloomberg and Reuters). To determine fair value, where market data is not readily available,
management uses comparable market sources and empirical evidence to develop its own estimates of market
assumptions.
Market liquidity — The Company evaluates market liquidity based on whether the financial or physical
instrument, or the underlying asset, is traded in an active or inactive market. An active market exists if the prices are
fully transparent to market participants, can be measured by market bid and ask quotes, the market has a relatively
large proportion of trading volume as compared to the Company's current trading volume and the market has a
significant number of market participants that will allow the market to rapidly absorb the quantity of assets traded
without significantly affecting the market price. Another factor the Company considers when determining whether a
market is active or inactive is the presence of government or regulatory controls over pricing that could make it
difficult to establish a market-based price when entering into a transaction.
Nonperformance risk — Nonperformance risk refers to the risk that an obligation will not be fulfilled and affects
the value at which a liability is transferred or an asset is sold. Nonperformance risk includes, but may not be limited
to, the Company or its counterparty's credit and settlement risk. Nonperformance risk adjustments are dependent
on credit spreads, letters of credit, collateral, other arrangements available and the nature of master netting
arrangements. The Company and its subsidiaries are parties to various interest rate swaps and options; foreign
currency options and forwards; and derivatives and embedded derivatives, which subject the Company to
nonperformance risk. The financial and physical instruments held at the subsidiary level are generally non-recourse
to the Parent Company.
Nonperformance risk on the investments held by the Company is incorporated in the fair value derived from
quoted market data to mark the investments to fair value.
Recurring Measurements — The following table presents, by level within the fair value hierarchy, as described
in Note 1—General and Summary of Significant Accounting Policies, the Company's financial assets and liabilities
that were measured at fair value on a recurring basis as of the dates indicated (in millions). For the Company's
investments in marketable debt and equity securities, the security classes presented are determined based on the
nature and risk of the security and are consistent with how the Company manages, monitors and measures its
marketable securities:
145
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
Level 1
December 31, 2016
Level 3
Level 2
Total
Level 1
December 31, 2015
Level 3
Level 2
Total
Assets
AVAILABLE FOR SALE:
Debt securities:
Unsecured debentures
Certificates of deposit
Government debt securities
Subtotal
Equity securities:
Mutual funds
Subtotal
Total available for sale
TRADING:
Equity securities:
Mutual funds
Total trading
DERIVATIVES:
Interest rate derivatives
Cross currency derivatives
Foreign currency derivatives
Commodity derivatives
Total derivatives — assets
TOTAL ASSETS
Liabilities
DERIVATIVES:
Interest rate derivatives
Cross currency derivatives
Foreign currency derivatives
Commodity derivatives
Total derivatives — liabilities
TOTAL LIABILITIES
$
— $
—
—
—
—
—
—
16
16
—
—
—
—
—
16
$
— $
—
—
—
—
— $
$
$
$
360
372
9
741
49
49
790
—
—
18
4
54
38
114
904
121
18
64
40
243
243
$
— $
—
—
—
—
—
—
—
—
—
—
255
7
262
262
179
—
—
2
181
181
$
$
$
360
372
9
741
49
49
790
16
16
18
4
309
45
376
$ 1,182
$
$
300
18
64
42
424
424
$
$
$
$
— $
—
—
—
—
—
—
15
15
—
—
—
—
—
15
$
— $
—
—
—
—
— $
318
129
28
475
15
15
490
—
—
—
—
35
41
76
566
54
43
41
29
167
167
$
$
$
$
— $
—
—
—
—
—
—
—
—
—
—
292
7
299
299
304
—
15
4
323
323
$
$
$
318
129
28
475
15
15
490
15
15
—
—
327
48
375
880
358
43
56
33
490
490
As of December 31, 2016, all AFS debt securities had stated maturities within one year. For the years ended
December 31, 2016, 2015, and 2014, no other-than-temporary impairment of marketable securities were
recognized in earnings or Other Comprehensive Income (Loss). Gains and losses on the sale of investments are
determined using the specific-identification method. The following table presents gross proceeds from sale of AFS
securities for the periods indicated (in millions):
Year Ended December 31,
Gross proceeds from sales of AFS securities
2016
2015
2014
$
4,335
$
4,177
$
3,829
The following tables present a reconciliation of net derivative assets and liabilities measured at fair value on a
recurring basis using significant unobservable inputs (Level 3) for the years ended December 31, 2016 and 2015
(presented net by type of derivative in millions). Transfers between Level 3 and Level 2 are determined as of the
end of the reporting period and principally result from changes in the significance of unobservable inputs used to
calculate the credit valuation adjustment.
Year Ended December 31, 2016
Balance at January 1
Total realized and unrealized gains (losses):
Included in earnings
Included in other comprehensive income — derivative activity
Included in other comprehensive income — foreign currency translation activity
Included in regulatory (assets) liabilities
Settlements
Transfers of liabilities into Level 3
Transfers of liabilities out of Level 3
Balance at December 31
Total gains for the period included in earnings attributable to the change in unrealized
gains (losses) relating to assets and liabilities held at the end of the period
$
$
146
Interest Rate
$
(304) $
Foreign Currency
277
Commodity
3
$
Total
$
(24)
—
(36)
3
—
72
(32)
118
(179) $
6
$
31
6
(52)
—
(22)
—
15
255
16
$
$
2
—
—
11
(11)
—
—
5
2
$
$
33
(30)
(49)
11
39
(32)
133
81
24
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
Year Ended December 31, 2015
Balance at January 1
Total realized and unrealized gains (losses):
Included in earnings
Included in other comprehensive income — derivative activity
Included in other comprehensive income — foreign currency translation activity
Included in regulatory (assets) liabilities
Settlements
Transfers of liabilities into Level 3
Transfers of assets out of Level 3
Balance at December 31
Total gains (losses) for the period included in earnings attributable to the change in
unrealized gains (losses) relating to assets and liabilities held at the end of the period $
$
Interest Rate
Foreign Currency
Commodity
Total
$
(210) $
209
$
6
$
5
(1)
(31)
9
—
24
(95)
—
(304) $
— $
198
—
(103)
—
(7)
(1)
(19)
277
187
$
$
(1)
—
—
(18)
16
—
—
3
$
196
(31)
(94)
(18)
33
(96)
(19)
(24)
(1) $
186
The following table summarizes the significant unobservable inputs used for the Level 3 derivative assets
(liabilities) as of December 31, 2016 (in millions, except range amounts):
Type of Derivative
Interest rate
Foreign currency:
Argentine Peso
Commodity:
Other
Total
Fair Value
Unobservable Input
$
(179) Subsidiaries’ credit spreads
Amount or Range
(Weighted Average)
2.1% - 4.4% (4.3%)
255 Argentine Peso to U.S. Dollar currency exchange rate after one year
19.9 - 33.4 (26.4)
$
5
81
Changes in the above significant unobservable inputs that lead to a significant and unusual impact to current-
period earnings are disclosed to the Financial Audit Committee. For interest rate derivatives, and foreign currency
derivatives, increases (decreases) in the estimates of the Company's own credit spreads would decrease (increase)
the value of the derivatives in a liability position. For foreign currency derivatives, increases (decreases) in the
estimate of the above exchange rate would increase (decrease) the value of the derivative.
Nonrecurring Measurements
When evaluating impairment of goodwill, long-lived assets, discontinued operations, and equity method
investments, the Company measures fair value using the applicable fair value measurement guidance. Impairment
expense is measured by comparing the fair value at the evaluation date to their then-latest available carrying
amount. The following table summarizes major categories of assets and liabilities measured at fair value on a
nonrecurring basis during the period and their level within the fair value hierarchy (in millions):
Year Ended December 31, 2016
Assets
Long-lived assets held and used: (2)
DPL
Buffalo Gap I
DPL
Buffalo Gap II
Discontinued operations: (3)
Sul
Year Ended December 31, 2015
Assets
Long-lived assets held and used: (2)
Buffalo Gap III
Kilroot
UK Wind
Other
Equity method investments: (4)
Solar Spain
Goodwill: (5)
DP&L
_____________________________
Measurement
Date
Carrying
Amount (1)
Level 1
Fair Value
Level 2
Level 3
Pretax
Loss
$
12/31/2016
08/31/2016
06/30/2016
03/31/2016
$
787
113
324
251
— $
—
—
—
$
60
—
—
—
06/30/2016
1,581
—
470
103
36
89
92
—
Measurement
Date
Carrying
Amount (1)
Level 1
Fair Value
Level 2
Level 3
$
09/30/2015
08/28/2015
06/30/2015
Various
02/09/2015
10/01/2015
$
234
191
38
32
29
317
— $
—
—
—
—
—
— $
—
1
21
—
—
118
70
—
—
29
—
$
$
624
77
235
159
783
Pretax
Loss
116
121
37
11
—
317
(1)
(2)
(3)
(4)
(5)
Represents the carrying values at the dates of measurement, before fair value adjustment.
See Note 20—Asset Impairment Expense for further information.
Per the Company's policy, pre-tax loss was limited to the impairment of long-lived assets. Upon disposal of AES Sul, we incurred an additional pre-tax loss on
sale of $602 million. See Note 22—Discontinued Operations for further information.
See Note 7—Investments In and Advances to Affiliates for further information.
See Note 9—Goodwill and Other Intangible Assets for further information.
147
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
The following table summarizes the significant unobservable inputs used in the Level 3 measurement of long-
lived assets held and used measured on a nonrecurring basis during the year ended December 31, 2016 (in
millions, except range amounts):
December 31, 2016
Fair Value
Valuation Technique
Unobservable Input
Range (Weighted Average)
Long-lived assets held and used:
DPL (1)
$
103 Discounted cash flow
Buffalo Gap I
36 Discounted cash flow
DPL (1)
89 Discounted cash flow
Buffalo Gap II
92 Discounted cash flow
Annual revenue growth
Annual pretax operating margin
Weighted-average cost of capital
Annual revenue growth
Annual pretax operating margin
Weighted-average cost of capital
Annual revenue growth
Annual pretax operating margin
Weighted-average cost of capital
Annual revenue growth
Annual pretax operating margin
Weighted-average cost of capital
-13% to -1% (-6%)
-42% to 3% (-16%)
7% to 10%
-20% to 9% (-14%)
-40% to 42% (29%)
9%
-11% to 13% (1%)
-50% to 60% (5%)
7% to 12%
-17% to 21% (20%)
-166% to 48% (18%)
9%
Total
_____________________________
$
320
(1)
See Note 20—Asset Impairment Expense for further discussion of each DPL impairment.
Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets
The following table presents (in millions) the carrying amount, fair value and fair value hierarchy of the
Company's financial assets and liabilities that are not measured at fair value in the Consolidated Balance Sheets as
of the periods indicated, but for which fair value is disclosed.
Assets:
Liabilities: Non-recourse debt
Accounts receivable — noncurrent (1)
Recourse debt
Assets:
Liabilities: Non-recourse debt
Accounts receivable — noncurrent (1)
Recourse debt
_____________________________
$
$
Carrying
Amount
264
15,792
4,671
Carrying
Amount
238
15,115
4,966
$
$
December 31, 2016
Fair Value
Total
Level 1
Level 2
Level 3
$
350
16,188
4,899
— $
—
—
20
15,120
4,899
$
330
1,068
—
December 31, 2015
Fair Value
Total
Level 1
Level 2
Level 3
$
310
15,592
4,696
— $
—
—
20
13,325
4,696
$
290
2,267
—
(1)
These accounts receivable principally relate to amounts due from CAMMESA, the administrator of the wholesale electricity market in Argentina, and are
included in Other noncurrent assets in the accompanying Consolidated Balance Sheets. The fair value and carrying amount of these receivables exclude VAT
of $24 million and $27 million as of December 31, 2016 and 2015, respectively.
5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Volume of Activity — The following table presents the Company's significant outstanding notional (in millions)
by type of derivative as of December 31, 2016, regardless of whether they are in qualifying cash flow hedging
relationships, and the dates through which the maturities for each type of derivative range:
Derivatives
Interest Rate (LIBOR and EURIBOR)
Cross Currency Swaps (Chilean Unidad de Fomento and Chilean Peso)
Foreign Currency:
Argentine Peso
Chilean Unidad de Fomento
Euro
Others, primarily with weighted average remaining maturities of a year or less
Current Notional
Translated to USD
3,581
$
374
171
151
226
749
Latest Maturity
2034
2029
2026
2019
2019
2018
148
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
Accounting and Reporting — Assets and Liabilities — The following tables present the fair value of assets and
liabilities related to the Company's derivative instruments as of the periods indicated (in millions):
Designated
December 31, 2016
Not Designated
Total
Designated
December 31, 2015
Not Designated
Total
Fair Value
Assets
Interest rate derivatives
Cross currency derivatives
Foreign currency derivatives
Commodity derivatives
Total assets
Liabilities
Interest rate derivatives
Cross currency derivatives
Foreign currency derivatives
Commodity derivatives
Total liabilities
$
$
$
$
18
4
9
20
51
295
18
19
26
358
$
$
$
$
Fair Value
Current
Noncurrent
Total
Credit Risk-Related Contingent Features (1)
Present value of liabilities subject to collateralization
Cash collateral held by third parties or in escrow
_____________________________
(1) Based on the credit rating of certain subsidiaries
— $
—
300
25
325
$
$
$
5
—
45
16
66
$
$
18
4
309
45
376
300
18
64
42
424
$
$
$
$
— $
—
8
30
38
$
358
43
35
12
448
$
$
— $
—
319
18
337
$
— $
—
21
21
42
$
—
—
327
48
375
358
43
56
33
490
December 31, 2016
December 31, 2015
Assets
Liabilities
Assets
Liabilities
99
277
376
$
$
155
269
424
$
86
289
$
375
December 31, 2016
$
144
346
$
490
December 31, 2015
$
$
41
18
58
38
Earnings and other Comprehensive (Loss) Income — The following table presents (in millions) the pretax gains
(losses) recognized in AOCL and earnings related to all derivative instruments for the periods indicated:
Cash flow hedges
Effective portion gain (losses) recognized in AOCL
Interest rate derivatives
Cross-currency derivatives
Foreign currency derivatives
Commodity derivatives
Total
Effective portion gain (losses) reclassified from AOCL into earnings
Interest rate derivatives
Cross-currency derivatives
Foreign currency deriviatives
Commodity derivatives
Total
Gain (losses) recognized in earnings related to
Ineffective portion of cash flow hedges
Not designated as hedging instruments:
Foreign currency derivatives
Commodity derivatives and Other
Total
Years Ended December 31,
2015
2014
2016
$
$
$
$
$
$
(35) $
21
(4)
30
12
$
(101) $
8
(8)
56
(45) $
(103) $
(20)
10
40
(73) $
(116) $
(24)
32
31
(77) $
(421)
(25)
(28)
44
(430)
(144)
(23)
14
28
(125)
(1) $
(6) $
(4)
19
(16)
2
$
211
(29)
176
$
144
58
198
The AOCL expected to decrease pretax income from continuing operations, primarily due to interest rate
derivatives, for the twelve months ended December 31, 2017 is $90 million.
6. FINANCING RECEIVABLES
The Company's financing receivables are defined as receivables with contractual maturities of greater than
one year. They are primarily related to amended agreements or government resolutions that are due from
CAMMESA. The following table presents financing receivables by country as of the dates indicated (in millions):
December 31,
Argentina
United States
Brazil
Total long-term financing receivables
2016
2015
$
$
236
20
8
264
$
$
237
20
7
264
149
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
Argentina — Collection of the principal and interest on these receivables is subject to various business risks
and uncertainties including, but not limited to, the operation of power plants which generate cash for payments of
these receivables, regulatory changes that could impact the timing and amount of collections, and economic
conditions in Argentina. The Company monitors these risks, including the credit ratings of the Argentine
government, on a quarterly basis to assess the collectability of these receivables. The Company accrues interest on
these receivables once the recognition criteria have been met. The Company's collection estimates are based on
assumptions that it believes to be reasonable, but are inherently uncertain. Actual future cash flows could differ from
these estimates.
FONINVEMEM Agreements
As a result of energy market reforms in 2004 and 2010, AES Argentina entered into three agreements with the
Argentine government, referred to as the FONINVEMEM Agreements, to contribute a portion of their accounts
receivable into a fund for financing the construction of combined cycle and gas-fired plants. These receivables
accrue interest and are collected in monthly installments over 10 years once the related plant begins operations. In
addition, AES Argentina receives an ownership interest in these newly built plants once the receivables have been
fully repaid.
FONINVEMEM I and II — The receivables under the first two FONINVEMEM Agreements have been actively
collected since the related plants commenced operations in 2010. In assessing the collectability of the receivables
under these agreements, the Company also considers how timely the collections have historically been made in
accordance with the agreements.
FONINVEMEM III — The receivables related to the third FONINVEMEM Agreement have been actively
collected since the related plants commenced operations in 2016. In assessing the collectability of the receivables
under this agreement, the Company also considers how timely the collections have historically been made in
accordance with the agreements.
The FONINVEMEM receivables are denominated in Argentine pesos, but indexed to U.S. dollars, which
represents a foreign currency derivative. As of December 31, 2016 and 2015, the amount of the foreign currency-
related derivative assets associated with the FONINVEMEM financing receivables that were excluded from the
table above had a fair value of $255 million and $292 million, respectively.
Other Agreements
In 2013, Resolution No. 95/2013 ("Resolution 95") which developed a new energy regulatory framework that
applies to all generation companies with certain exceptions became effective. The new regulatory framework
reimburses fixed and variable costs plus a margin that will depend on the technology and fuel used to generate the
electricity and the installed capacity of each plant.
In the fourth quarter of 2014, the Argentine government passed a resolution to contribute outstanding
Resolution 95 receivables into a trust whereby AES Argentina has committed to install additional capacity into the
system. CAMMESA will finance the investment utilizing the outstanding receivables as a guarantee.
On July 10, 2015, the Argentine government passed Resolution No. 482/2015 ("Resolution 482") which
updated the prices of Resolution 529/2014 retroactively to February 1, 2015, and created a new trust called
FONINVEMEM 2015-2018 in order to invest in new generation plants. AES Argentina and certain Termoandes units
will receive compensation under this program.
150
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
7. INVESTMENTS IN AND ADVANCES TO AFFILIATES
The following table summarizes the relevant effective equity ownership interest and carrying values for the
Company's investments accounted for under the equity method as of the periods indicated:
December 31,
Affiliate
Barry (1)
Elsta (1)
Distributed Energy (1)
Guacolda (2)
OPGC (3)
Other affiliates
Country
Carrying Value (in millions)
2016
2015
2016
2015
Ownership Interest %
United Kingdom
Netherlands
United States
Chile
India
Various
—
41
22
362
195
1
621
$
—
53
17
344
195
1
610
100%
50%
95%
33%
49%
100%
50%
94%
33%
49%
Total investments in and advances to affiliates
$
_____________________________
(1)
(2)
(3)
Represent VIEs in which the Company holds a variable interest but is not the primary beneficiary.
The Company's ownership in Guacolda is held through AES Gener, a 67%-owned consolidated subsidiary. AES Gener owns 50% of Guacolda, resulting in an
AES effective ownership in Guacolda of 33%.
OPGC has one coal-fired project under development which is an expansion of our existing OPGC business. The project started construction in April 2014 and
is expected to begin operations in 2018.
Guacolda — On September 1, 2015, AES Gener and Global Infrastructure Partners ("GIP") executed a
restructuring of Guacolda that increased Guacolda's tax basis in certain long-term assets and AES Gener's equity
investment. As a result, AES Gener recorded $66 million in net equity in earnings of affiliates for the year ended
December 31, 2015, of which $46 million is attributable to The AES Corporation.
On April 11, 2014, AES Gener undertook a series of transactions, pursuant to which AES Gener acquired the
interests that it did not previously own in Guacolda for $728 million and simultaneously sold the ownership interest
to GIP for $730 million. The transaction provided GIP with substantive participating rights in Guacolda and, as a
result, the Company continues to account for its investment in Guacolda using the equity method of accounting. At
no time during this transaction did the Company acquire a non-controlling interest. The cash paid for the acquisition
is reflected in Acquisitions, net of cash acquired and the cash proceeds from the sale of these ownership interests
to GIP is reflected in Proceeds from the sale of businesses, net of cash sold, and equity method investments on the
Consolidated Statement of Cash Flows for the period ended December 31, 2014.
Silver Ridge Power — On July 2, 2014, the Company closed the sale of its 50% ownership interest in Silver
Ridge Power, LLC ("SRP") for a purchase price of $179 million, excluding the Company's indirect ownership
interests in SRP's solar generation businesses in Italy and Spain ("Solar Italy" and "Solar Spain," respectively). As
part of the sale, the buyer had an option to purchase Solar Italy for additional consideration of $42 million by August
2015. The buyer exercised its option to purchase Solar Italy on August 31, 2015, and the sale was completed on
October 1, 2015. On September 24, 2015, the Company completed the sale of Solar Spain. Net proceeds from the
sale transaction were $31 million and the Company recognized a pretax gain on sale of less than $1 million. Upon
the completion of the Solar Spain and Solar Italy sale transactions noted above, the Company ceased its
involvement in SRP's business operations and accounted for these transactions as sales of real estate.
AES Barry Ltd. — The Company holds a 100% ownership interest in AES Barry Ltd. ("Barry"), a dormant entity
in the U.K. that disposed of its generation and other operating assets. Due to a debt agreement, no material
financial or operating decisions can be made without the banks' consent, and the Company does not control Barry.
As of December 31, 2016 and 2015, other long-term liabilities included $41 million and $49 million related to this
debt agreement.
Elsta — In 2014, long lived assets within Elsta were determined to not be recoverable and an impairment
charge of approximately $82 million was recognized. The Company recognized its 50% share, or $41 million,
through its proportion of the equity earnings in Elsta.
151
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
Summarized Financial Information — The following tables summarize financial information of the
Company's 50%-or-less-owned affiliates and majority-owned unconsolidated subsidiaries that are accounted for
using the equity method in millions:
Years ended December 31,
Revenue
Operating margin
Net income
December 31,
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
Stockholders' equity
50%-or-less Owned Affiliates
2015
2014
2016
Majority-Owned Unconsolidated Subsidiaries
2015
2016
2014
$
$
$
$
586
145
64
2016
308
2,577
626
1,209
1,048
$
641
152
210
2015
376
2,132
435
1,044
1,029
928
206
59
$
$
2016
$
$
23
9
(2)
16
181
10
122
65
2015
24
11
6
20
211
21
153
57
$
2
—
—
At December 31, 2016, retained earnings included $246 million related to the undistributed earnings of the
Company's 50%-or-less owned affiliates. Distributions received from these affiliates were $24 million, $18 million,
and $28 million for the years ended December 31, 2016, 2015, and 2014, respectively. As of December 31, 2016,
the aggregate carrying amount of our investments in equity affiliates exceeded the underlying equity in their net
assets by $162 million.
8. OTHER NON-OPERATING EXPENSE
There were no significant non-operating expenses for the years ended December 31, 2016 or 2015.
Entek — During 2014, the Company executed an agreement to sell its 49.62% interest in Entek, an investment
accounted for under the equity method, for $125 million. Entek consists of natural gas and hydroelectric generation
facilities, plus a coal-fired development project. The Company determined that there was an other-than-temporary
decline in the fair value of its equity method investment in Entek and recognized pretax impairment expense of $86
million. The sale of the Company's interest in Entek closed on December 18, 2014.
Silver Ridge — During 2014, the Company determined that there was a decline in the fair value of its equity
method investment in Silver Ridge Power, LLC ("SRP") that was other-than-temporary based on indications about
the fair value of the projects in Italy and Spain that resulted from actual and proposed changes to tariffs.
Accordingly, the Company recognized pretax impairment expense of $42 million. The transaction related to our 50%
ownership interest in SRP closed on July 2, 2014 for $179 million. See Note 7—Investments in and Advances to
Affiliates of this Form 10-K for further information.
9. GOODWILL AND OTHER INTANGIBLE ASSETS
Goodwill — The following table summarizes the changes in the carrying amount of goodwill, by reportable
segment for the years ended December 31, 2016 and 2015 in millions:
Balance as of December 31, 2014
Goodwill
Accumulated impairment losses
Net balance
Impairment losses
Goodwill acquired during the year
Balance as of December 31, 2015
Goodwill
Accumulated impairment losses
Net balance
Balance as of December 31, 2016
Goodwill
Accumulated impairment losses
Net balance
US
Andes
MCAC
Europe
Asia
Total
$
$
2,658
(2,316)
342
(317)
16
2,674
(2,633)
41
2,674
(2,633)
41
$
$
899
—
899
—
—
899
—
899
899
—
899
$
$
149
—
149
—
—
149
—
149
149
—
149
$
$
122
(122)
—
—
—
122
(122)
—
122
(122)
$
— $
68
—
68
—
—
68
—
68
68
—
68
$
$
3,896
(2,438)
1,458
(317)
16
3,912
(2,755)
1,157
3,912
(2,755)
1,157
DP&L — During the fourth quarter of 2015, the Company performed the annual goodwill impairment test at its
DP&L reporting unit and recognized a goodwill impairment expense of $317 million. The reporting unit failed Step 1
as its fair value was less than its carrying amount, which was primarily due to a decrease in forecasted dark
spreads that were driven by decreases in projected forward power prices, and lower than expected revenues from a
152
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
new CP product. The fair value of the reporting unit was determined under the income approach using a discounted
cash flow valuation model. The significant assumptions included within the discounted cash flow valuation model
were forward commodity price curves, the amount of non-bypassable charges from the pending ESP, expected
revenues from the new CP product, and planned environmental expenditures. In Step 2, goodwill was determined to
have an implied negative fair value after the hypothetical purchase price allocation under the accounting guidance
for business combinations; therefore, a full impairment of the remaining goodwill balance of $317 million was
recognized. DP&L is reported in the US SBU reportable segment.
Distributed Energy — During the first quarter of 2015, the Company completed the acquisition of 100% of the
common stock of Main Street Power Company, Inc (subsequently renamed Distributed Energy). The transaction
included recognition of $16 million of goodwill and is reported in the US SBU reportable segment. See Note 24—
Acquisitions for additional information.
Other Intangible Assets — The following table summarizes the balances comprising Other intangible assets in
the accompanying Consolidated Balance Sheets (in millions) as of the periods indicated:
Gross
Balance
December 31, 2016
Accumulated
Amortization
Net Balance
Gross
Balance
December 31, 2015
Accumulated
Amortization
Net Balance
Subject to Amortization
Internal-use software
Sales concessions
Contractual payment rights (1)
Management rights
Land use rights
Contracts
Other (2)
Subtotal
Indefinite-Lived Intangible Assets
Land use rights
Water rights
Other
Subtotal
Total
_____________________________
$
$
567
63
56
28
25
53
12
804
47
17
10
74
878
$
$
(424) $
(22)
(42)
(13)
(1)
(15)
(2)
(519)
—
—
—
—
(519) $
143
41
14
15
24
38
10
285
47
17
10
74
359
$
$
521
63
66
24
25
29
25
753
38
17
13
68
821
$
$
(388) $
(15)
(46)
(10)
—
(12)
(10)
(481)
—
—
—
—
(481) $
133
48
20
14
25
17
15
272
38
17
13
68
340
(1)
(2)
Represent legal rights to receive system reliability payments from the regulator.
Includes renewable energy credits, organization costs, project development rights, and other individually insignificant intangible assets.
The following tables summarize other intangible assets acquired during the periods indicated (in millions):
December 31, 2016
Internal-use software
Contracts
Other
Total
December 31, 2015
Internal-use software
Contracts
Land-use rights (1)
Other
Total
_____________________________
Amount
Subject to Amortization/
Indefinite-Lived
Weighted Average Amortization
Period (in years)
51 Subject to Amortization
24 Subject to Amortization
5 Subject to Amortization
80
4
26
13
Amount
Subject to Amortization/
Indefinite-Lived
Weighted Average
Amortization Period (in years)
29 Subject to Amortization
22 Subject to Amortization
13 Subject to Amortization
5 Various
69
5
5
N/A
N/A
$
$
$
$
Amortization
Method
Straight-line
Straight-line
Straight-line
Amortization
Method
Straight-line
Straight-line
N/A
N/A
(1)
The carrying value of these definite-lived intangible assets equals their salvage value
The following table summarizes the estimated amortization expense by intangible asset category for 2017
through 2021:
(in millions)
Internal-use software
Sales concessions
All other
Total
2017
2018
2019
2020
2021
34
6
5
45
$
21
6
5
32
$
14
4
5
23
$
10
2
5
17
$
38
6
6
50
$
153
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
Intangible asset amortization expense was $46 million, $52 million and $57 million for the years ended
December 31, 2016, 2015 and 2014, respectively.
10. REGULATORY ASSETS AND LIABILITIES
The Company has recorded regulatory assets and liabilities (in millions) that it expects to pass through to its
customers in accordance with, and subject to, regulatory provisions as follows:
December 31,
REGULATORY ASSETS
Current regulatory assets:
Brazil tariff recoveries: (1)
Energy purchases/sales
Transmission costs, regulatory fees and other
El Salvador tariff recoveries (1)
Other
Total current regulatory assets
Noncurrent regulatory assets:
IPL and DPL defined benefit pension obligations
DPL and IPL income taxes recoverable from customers
Brazil tariff recoveries: (1)
Energy purchases/sales
Transmission costs, regulatory fees and other
IPL deferred Midwest ISO costs (1)
Other
Total noncurrent regulatory assets
TOTAL REGULATORY ASSETS
REGULATORY LIABILITIES
Current regulatory liabilities:
Brazil efficiency program costs
Brazil tariff refunds:
Energy purchases/sales
Transmission costs, regulatory fees and other
Other
Total current regulatory liabilities
Noncurrent regulatory liabilities:
IPL and DPL asset retirement obligations
Brazil special obligations
Brazil efficiency program costs
Brazil tariff refunds:
Energy purchases/sales
Transmission costs, regulatory fees and other
Other
Total noncurrent regulatory liabilities
TOTAL REGULATORY LIABILITIES
_____________________________
$
$
$
$
2016
2015
Recovery/Refund Period
319
139
54
34
546
316
87
63
18
114
143
741
1,287
$
$
349 Annually as part of the tariff adjustment
212 Annually as part of the tariff adjustment
43 Quarterly as part of the tariff adjustment
23 Various
627
227 Various
36 Various
10 years
132 Annually as part of the tariff adjustment
124 Annually as part of the tariff adjustment
129
239 Various
887
1,514
36
$
9 Annually as part of the tariff adjustment
211
249
42
538
795
362
24
7
170
5
1,363
1,901
105 Annually as part of the tariff adjustment
235 Annually as part of the tariff adjustment
59 Various
408
759 Over life of assets
313 To be determined
14 Annually as part of the tariff adjustment
30 Annually as part of the tariff adjustment
86 Annually as part of the tariff adjustment
7 Various
$
1,209
1,617
(1)
Past expenditures on which the Company does not earn a rate of return.
Our regulatory assets primarily consist of costs that are generally non-controllable, such as purchased
electricity, energy transmission, the difference between actual fuel costs and the fuel costs recovered in the tariffs,
and other sector costs. These costs are recoverable or refundable as defined by the laws and regulations in our
various markets. Our regulatory assets also include defined pension and postretirement benefit obligations equal to
the previously unrecognized actuarial gains and losses and prior services costs that are expected to be recovered
through future rates. Other current and noncurrent regulatory assets primarily consist of:
• Unamortized carrying charges, certain environmental costs, and demand charges at IPL and DPL.
• Unamortized premiums reacquired or redeemed on long term debt at IPL and DPL, which are amortized over the
lives of the original issuances.
• Unrecovered fuel and purchased power costs at IPL and DPL.
Other current regulatory assets that did not earn a rate of return were $34 million and $8 million, as of
December 31, 2016 and 2015, respectively. Other noncurrent regulatory assets that did not earn a rate of return
were $138 million and $237 million, as of December 31, 2016 and 2015, respectively.
Our regulatory liabilities primarily consist of obligations for removal costs which do not have an associated
154
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
legal retirement obligation, as well as obligations established by ANEEL in Brazil associated with electric utility
concessions and represent amounts received from customers or donations not subject to return. These donations
are allocated to support energy network expansion and to improve utility operations to meet customers' needs. The
term of the obligation is established by ANEEL and settlement will occur when the electric utility concessions end.
Other current and noncurrent regulatory liabilities primarily consist of amounts related to rider over collection at
DPL and liabilities owed to electricity generators due to variance in energy prices during rationing periods known as
"Free Energy" at Eletropaulo. Our Brazilian subsidiaries are authorized to refund this cost associated with monthly
energy price variances between the wholesale energy market prices owed to the power generation plants producing
Free Energy and the capped price reimbursed by the local distribution companies which are passed through to the
final customers through energy tariffs.
In the accompanying Consolidated Balance Sheets the current regulatory assets and liabilities are recorded in
Other current assets and Accrued and other liabilities, respectively, and the noncurrent regulatory assets and
liabilities are recorded in Other noncurrent assets and Other noncurrent liabilities, respectively. The following table
summarizes regulatory assets and liabilities by reportable segment in millions as of the periods indicated:
Brazil SBU
US SBU
MCAC SBU
Total
11. DEBT
December 31, 2016
December 31, 2015
Regulatory Assets
$
$
544
689
54
1,287
Regulatory Liabilities
1,059
$
842
—
1,901
$
$
$
Regulatory Assets
821
650
43
1,514
Regulatory Liabilities
798
$
819
—
1,617
$
NON-RECOURSE DEBT — The following table summarizes the carrying amount and terms of non-recourse
debt at our subsidiaries as of the periods indicated (in millions):
NON-RECOURSE DEBT
Variable Rate: (1)
Bank loans
Notes and bonds
Debt to (or guaranteed by) multilateral, export credit agencies or development banks (2)
Other
Fixed Rate:
Bank loans
Notes and bonds
Debt to (or guaranteed by) multilateral, export credit agencies or development banks (2)
Other
Unamortized (discount)/premium & debt issuance (costs), net
Subtotal
Less: Current maturities
Noncurrent maturities
_____________________________
Weighted
Average
Interest Rate
December 31,
Maturity
2016
2015
4.61%
13.65%
2.99%
14.19%
5.43%
5.69%
5.85%
5.77%
2017 – 2035
2017 – 2023
2021 – 2034
2018 – 2043
$ 2,807
1,204
3,189
56
$ 2,275
1,169
3,089
39
2017 – 2032
2017 – 2073
2023 – 2034
2018 – 2061
791
7,822
328
36
(441)
15,792
(1,303)
$ 14,489
557
7,987
309
13
(323)
15,115
(2,172)
$ 12,943
(1)
The interest rate on variable rate debt represents the total of a variable component that is based on changes in an interest rate index and of a fixed
component. The Company has interest rate swaps and option agreements in an aggregate notional principal amount of approximately $3.6 billion on non-
recourse debt outstanding at December 31, 2016. These agreements economically fix the variable component of the interest rates on the portion of the
variable-rate debt being hedged so that the total interest rate on that debt has been fixed at rates ranging from approximately 1.99% to 8.25%. The debt
agreements expire at various dates from 2017 through 2073.
(2) Multilateral loans include loans funded and guaranteed by bilaterals, multilaterals, development banks and other similar institutions.
Non-recourse debt as of December 31, 2016 is scheduled to reach maturity as shown below (in millions):
December 31,
2017
2018
2019
2020
2021
Thereafter
Unamortized (discount)/premium & debt issuance (costs), net
Total non-recourse debt
Annual Maturities
$
$
1,339
1,443
1,214
1,645
2,035
8,557
(441)
15,792
As of December 31, 2016, AES subsidiaries with facilities under construction had a total of approximately $1.9
155
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
billion of committed but unused credit facilities available to fund construction and other related costs. Excluding
these facilities under construction, AES subsidiaries had approximately $2.3 billion in a number of available but
unused committed credit lines to support their working capital, debt service reserves and other business needs.
These credit lines can be used for borrowings, letters of credit, or a combination of these uses.
Significant transactions — During the year ended December 31, 2016, the Company's subsidiaries had the
following significant debt transactions:
Subsidiary
IPALCO
Gener
DPL
Andres
Los Mina
Wind Generation Holdings
Eletropaulo
Maritza
Other
Issuances
Repayments
$
$
688 $
633
460
243
172
130
73
18
611
3,028
$
Gain (Loss) on
Extinguishment of Debt
—
7
(3)
(2)
—
—
—
—
(2)
—
(455) $
(314)
(593)
(180)
—
(65)
(202)
(153)
(664)
(2,626) $
Non-Recourse Debt Covenants, Restrictions and Defaults — The terms of the Company's non-recourse debt
include certain financial and non-financial covenants. These covenants are limited to subsidiary activity and vary
among the subsidiaries. These covenants may include, but are not limited to, maintenance of certain reserves and
financial ratios, minimum levels of working capital and limitations on incurring additional indebtedness.
As of December 31, 2016 and 2015, approximately $535 million and $513 million, respectively, of restricted
cash was maintained in accordance with certain covenants of the non-recourse debt agreements, and these
amounts were included within Restricted cash and Debt service reserves and other deposits in the accompanying
Consolidated Balance Sheets.
Various lender and governmental provisions restrict the ability of certain of the Company's subsidiaries to
transfer their net assets to the Parent Company. Such restricted net assets of subsidiaries amounted to
approximately $2.5 billion at December 31, 2016.
The following table summarizes the Company's subsidiary non-recourse debt in default (in millions) as of
December 31, 2016. Due to the defaults, these amounts are included in the current portion of non-recourse debt:
Subsidiary
Kavarna (Bulgaria)
Sogrinsk (Kazakhstan)
Total
Primary Nature
of Default
Covenant
Covenant
December 31, 2016
Default
Net Assets
$
$
$
123
5
128
78
9
As of December 31, 2016, none of the defaults are payment defaults. All of the subsidiary non-recourse
defaults were triggered by failure to comply with other covenants and/or conditions such as (but not limited to)
failure to meet information covenants, complete construction or other milestones in an allocated time, meet certain
minimum or maximum financial ratios, or other requirements contained in the non-recourse debt documents of the
applicable subsidiary.
In the event that there is a default, bankruptcy or maturity acceleration at a subsidiary or group of subsidiaries
that meets the applicable definition of materiality under the corporate debt agreements of The AES Corporation,
there could be a cross-default to the Company's recourse debt. Materiality is defined in the Parent's senior secured
credit facility as having provided 20% or more of the Parent Company's total cash distributions from businesses for
the four most recently completed fiscal quarters. As of December 31, 2016, none of the defaults listed above
individually or in the aggregate result in or are at risk of triggering a cross-default under the recourse debt of the
Parent Company. In the event the Parent Company is not in compliance with the financial covenants of its senior
secured revolving credit facility, restricted payments will be limited to regular quarterly shareholder dividends at the
then-prevailing rate. Payment defaults and bankruptcy defaults would preclude the making of any restricted
payments.
156
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
RECOURSE DEBT — The following table summarizes the carrying amount and terms of recourse debt of the
Company as of the periods indicated (in millions):
Senior Unsecured Note
Senior Unsecured Note
Senior Unsecured Note
Senior Unsecured Note
Senior Unsecured Note
Senior Unsecured Note
Senior Unsecured Note
Senior Unsecured Note
Term Convertible Trust Securities
Interest Rate
8.00%
LIBOR + 3%
8.00%
7.38%
4.88%
5.50%
5.50%
6.00%
6.75%
Final Maturity
2017
2019
2020
2021
2023
2024
2025
2026
2029
Unamortized (discounts)/premiums & debt issuance (costs), net
Subtotal
Less: Current maturities
Noncurrent maturities
$
$
December 31, 2016
$
— $
December 31, 2015
181
775
469
1,000
750
750
575
—
517
(51)
4,966
—
4,966
$
$
240
469
966
713
738
573
500
517
(45)
4,671
—
4,671
The following table summarizes the principal amounts due under our recourse debt for the next five years and
thereafter (in millions):
December 31,
2017
2018
2019
2020
2021
Thereafter
Unamortized (discount)/premium & debt issuance (costs), net
Total recourse debt
Net Principal Amounts Due
—
$
—
240
469
966
3,041
(45)
4,671
$
In July 2016, the Company redeemed in full the $181 million balance of its 8.0% outstanding senior unsecured
notes due 2017. As a result, the Company recognized a loss on extinguishment of debt of $16 million that is
included in the Consolidated Statement of Operations.
In May 2016, the Company issued $500 million aggregate principal amount of 6.0% senior notes due 2026.
The Company used these proceeds to redeem, at par, $495 million aggregate principal of its existing LIBOR +
3.00% senior unsecured notes due 2019. As a result of the latter transaction, the Company recognized a net loss on
extinguishment of debt of $4 million that is included in the Consolidated Statement of Operations.
In January 2016, the Company redeemed $125 million of its senior unsecured notes outstanding. The
repayment included a portion of the 7.375% senior notes due in 2021, the 4.875% senior notes due in 2023, the
5.5% senior notes due in 2024, the 5.5% senior notes due in 2025 and the floating rate senior notes due in 2019. As
a result of these transactions, the Company recognized a net gain on extinguishment of debt of $7 million that is
included in the Consolidated Statement of Operations.
In April 2015, the Company issued $575 million aggregate principal amount of 5.50% senior notes due 2025.
Concurrent with this offering, the Company redeemed via tender offers $344 million aggregate principal of its
existing 8.00% senior unsecured notes due 2017, and $156 million of its existing 8.00% senior unsecured notes due
2020. As a result of the latter transaction, the Company recognized a loss on extinguishment of debt of $82 million
that is included in the Consolidated Statement of Operations.
In March 2015, the Company redeemed in full the $151 million balance of its 7.75% senior unsecured notes
due October 2015 and the $164 million balance of its 9.75% senior unsecured notes due April 2016. As a result of
these transactions, the Company recognized a loss on extinguishment of debt of $23 million that is included in the
Consolidated Statement of Operations.
Recourse Debt Covenants and Guarantees — The Company's obligations under the senior secured credit
facility are subject to certain exceptions, secured by (i) all of the capital stock of domestic subsidiaries owned
directly by the Company and 65% of the capital stock of certain foreign subsidiaries owned directly or indirectly by
the Company; and (ii) certain intercompany receivables, certain intercompany notes and certain intercompany tax
sharing agreements.
The senior secured credit facility is subject to mandatory prepayment under certain circumstances, including
the sale of certain assets. In such a situation, the net cash proceeds from the sale must be applied pro rata to repay
157
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
the term loan, if any, using 60% of net cash proceeds, reduced to 50% when and if the parent's recourse debt to
cash flow ratio is less than 5:1. The lenders have the option to waive their pro rata redemption.
The senior secured credit facility contains customary covenants and restrictions on the Company's ability to
engage in certain activities, including, but not limited to, limitations on other indebtedness, liens, investments and
guarantees; limitations on restricted payments such as shareholder dividends and equity repurchases; restrictions
on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet or derivative
arrangements; and other financial reporting requirements.
The senior secured credit facility also contains financial covenants requiring the Company to maintain certain
financial ratios including a cash flow to interest coverage ratio, calculated quarterly, which provides that a minimum
ratio of the Company's adjusted operating cash flow to the Company's interest charges related to recourse debt of
1.3 times must be maintained at all times and a recourse debt to cash flow ratio, calculated quarterly, which
provides that the ratio of the Company's total recourse debt to the Company's adjusted operating cash flow must not
exceed a maximum of 7.5 times.
The terms of the Company's senior unsecured notes and senior secured credit facility contain certain
covenants including, without limitation, limitation on the Company's ability to incur liens or enter into sale and
leaseback transactions.
TERM CONVERTIBLE TRUST SECURITIES — In 1999, AES Trust III, a wholly-owned special purpose
business trust and a VIE, issued approximately 10.35 million of $50 par value TECONS with a quarterly coupon
payment of $0.844 for total proceeds of $517 million and concurrently purchased $517 million of 6.75% Junior
Subordinated Convertible Debentures due 2029 (the "6.75% Debentures") issued by AES. The Company
consolidates AES Trust III in its consolidated financial statements and classifies the TECONS as recourse debt on
its Consolidated Balance Sheet. The Company's obligations under the 6.75% Debentures and other relevant trust
agreements, in aggregate, constitute a full and unconditional guarantee by the Company of the TECON Trusts'
obligations. As of December 31, 2016 and 2015, the sole assets of AES Trust III are the 6.75% Debentures.
AES, at its option, can redeem the 6.75% Debentures which would result in the required redemption of the
TECONS issued by AES Trust III, currently for $50 per TECON. The TECONS must be redeemed upon maturity of
the 6.75% Debentures. The TECONS are convertible into the common stock of AES at each holder's option prior to
October 15, 2029 at the rate of 1.4216, representing a conversion price of $35.17 per share. The maximum number
of shares of common stock AES would be required to issue should all holders decide to convert their securities
would be 14.7 million shares.
Dividends on the TECONS are payable quarterly at an annual rate of 6.75%. The Trust is permitted to defer
payment of dividends for up to 20 consecutive quarters, provided that the Company has exercised its right to defer
interest payments under the corresponding debentures or notes. During such deferral periods, dividends on the
TECONS would accumulate quarterly and accrue interest, and the Company may not declare or pay dividends on
its common stock. AES has not exercised the option to defer any dividends at this time and all dividends due under
the Trust have been paid.
12. COMMITMENTS
LEASES — The Company and its subsidiaries enter into long-term non-cancelable lease arrangements which,
for accounting purposes, are classified as either an operating lease or capital lease. Operating leases primarily
include certain transmission lines, office rental and site leases. Operating lease rental expense for the years ended
December 31, 2016, 2015, and 2014 was $80 million, $59 million and $48 million, respectively. Capital leases
primarily include transmission lines at our subsidiaries in Brazil, vehicles, and office and other operating equipment.
Capital leases are recognized in Property, Plant and Equipment within Electric generation, distribution assets and
other. The gross value of the capital lease assets as of December 31, 2016 and 2015 was $91 million and $67
million, respectively. The following table shows the future minimum lease payments under operating and capital
leases for continuing operations together with the present value of the net minimum lease payments under capital
leases as of December 31, 2016 for 2017 through 2021 and thereafter (in millions):
158
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
December 31,
2017
2018
2019
2020
2021
Thereafter
Total
Less: Imputed interest
Present value of total minimum lease payments
Future Commitments for
Capital Leases
Operating Leases
$
$
25
18
14
11
8
89
165
(96)
69
84
90
91
92
91
926
1,374
$
$
$
CONTRACTS — The Company's operating subsidiaries enter into long-term contracts for construction
projects, maintenance and service, transmission of electricity, operations services and purchase of electricity and
fuel. In general, these contracts are subject to variable quantities or prices and are terminable only in limited
circumstances. Electricity purchase contracts primarily include energy auction agreements at our Brazil subsidiaries
with extended terms through 2028. The following table shows the future minimum commitments for continuing
operations under these contracts as of December 31, 2016 for 2017 through 2021 and thereafter as well as actual
purchases under these contracts for the years ended December 31, 2016, 2015, and 2014 (in millions):
Actual purchases during the year ended December 31,
2014
2015
2016
Future commitments for the year ending December 31,
2017
2018
2019
2020
2021
Thereafter
Total
13. CONTINGENCIES
Electricity Purchase Contracts
2,475
$
2,120
2,447
Fuel Purchase Contracts
1,521
$
1,262
1,790
Other Purchase Contracts
1,367
$
2,110
1,093
$
$
2,513
2,507
2,367
2,704
2,750
20,265
33,106
$
$
1,609
724
489
451
465
1,425
5,163
$
$
2,966
1,865
1,395
956
815
6,012
14,009
Guarantees, Letters of Credit — In connection with certain project financings, acquisitions and dispositions,
power purchases and other agreements, the Parent Company has expressly undertaken limited obligations and
commitments, most of which will only be effective or will be terminated upon the occurrence of future events. In the
normal course of business, the Parent Company has entered into various agreements, mainly guarantees and
letters of credit, to provide financial or performance assurance to third parties on behalf of AES businesses. These
agreements are entered into primarily to support or enhance the creditworthiness otherwise achieved by a business
on a stand-alone basis, thereby facilitating the availability of sufficient credit to accomplish their intended business
purposes. Most of the contingent obligations relate to future performance commitments which the Company or its
businesses expect to fulfill within the normal course of business. The expiration dates of these guarantees vary from
less than one year to more than 18 years.
The following table summarizes the Parent Company's contingent contractual obligations as of December 31,
2016. Amounts presented in the following table represent the Parent Company's current undiscounted exposure to
guarantees and the range of maximum undiscounted potential exposure. The maximum exposure is not reduced by
the amounts, if any, that could be recovered under the recourse or collateralization provisions in the guarantees.
The were no obligations made by the Parent Company for the direct benefit of the lenders associated with the non-
recourse debt of its businesses.
159
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
Contingent Contractual Obligations
Amount (in millions)
Number of
Agreements
Guarantees and commitments
Letters of Credit under the unsecured credit facility
Asset sale related indemnities (1)
Letters of Credit under the senior secured credit facility
Cash collateralized letters of credit
Total
_____________________________
$
$
508
245
27
6
3
789
Maximum Exposure Range for
Each Agreement (in millions)
$8 - 58
$2 - 73
27
<$1 - 1
3
18
8
1
15
1
43
(1)
Excludes normal and customary representations and warranties in agreements for the sale of assets (including ownership in associated legal entities) where
the associated risk is considered to be nominal.
As of December 31, 2016, the Parent Company had no commitments to invest in subsidiaries under
construction and to purchase related equipment that were not included in the letters of credit discussed above.
During the year ended December 31, 2016, the Company paid letter of credit fees ranging from 0.2% to 2.5% per
annum on the outstanding amounts of letters of credit.
Environmental — The Company periodically reviews its obligations as they relate to compliance with
environmental laws, including site restoration and remediation. As of December 31, 2016 and 2015 the Company
had recognized liabilities of $12 million and $10 million, respectively, for projected environmental remediation costs.
Due to the uncertainties associated with environmental assessment and remediation activities, future costs of
compliance or remediation could be higher or lower than the amount currently accrued. Moreover, where no liability
has been recognized, it is reasonably possible that the Company may be required to incur remediation costs or
make expenditures in amounts that could be material but could not be estimated as of December 31, 2016. In
aggregate, the Company estimates that the range of potential losses related to environmental matters, where
estimable, to be up to $19 million. The amounts considered reasonably possible do not include amounts accrued as
discussed above.
Litigation — The Company is involved in certain claims, suits and legal proceedings in the normal course of
business. The Company accrues for litigation and claims when it is probable that a liability has been incurred and
the amount of loss can be reasonably estimated. The Company has evaluated claims in accordance with the
accounting guidance for contingencies that it deems both probable and reasonably estimable and, accordingly, has
recorded aggregate liabilities for all claims of approximately $179 million as of December 31, 2016 and 2015. These
amounts are reported on the Consolidated Balance Sheets within Accrued and other liabilities and Other noncurrent
liabilities. A significant portion of these accrued liabilities relate to employment, non-income tax and customer
disputes in international jurisdictions (principally Brazil). Certain of the Company's subsidiaries, principally in Brazil,
are defendants in a number of labor and employment lawsuits. The complaints generally seek unspecified monetary
damages, injunctive relief, or other relief. The subsidiaries have denied any liability and intend to vigorously defend
themselves in all of these proceedings. There can be no assurance that these accrued liabilities will be adequate to
cover all existing and future claims or that we will have the liquidity to pay such claims as they arise.
Where no accrued liability has been recognized, it is reasonably possible that some matters could be decided
unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that
could be material but could not be estimated as of December 31, 2016. The material contingencies where a loss is
reasonably possible primarily include claims under financing agreements; disputes with offtakers, suppliers and
EPC contractors; alleged violation of monopoly laws and regulations; income tax and non-income tax matters with
tax authorities; and regulatory matters. In aggregate, the Company estimates that the range of potential losses,
where estimable, related to these reasonably possible material contingencies to be between $1.5 billion and $1.8
billion. The amounts considered reasonably possible do not include amounts accrued, as discussed above. These
material contingencies do not include income tax-related contingencies which are considered part of our uncertain
tax positions.
Regulatory — During 2013, the Company recognized a regulatory liability of $269 million for a contingency
related to an administrative ruling which required Eletropaulo to refund customers' amounts related to the regulatory
asset base. In 2014, Eletropaulo started refunding customers as part of the tariff. In January 2015, ANEEL updated
the tariff to exclude any further customer refunds. On June 30, 2015, ANEEL included in the tariff reset the
reimbursement to Eletropaulo of these amounts previously refunded to customers to begin in July 2015. During
2015, as a result of favorable events, management reassessed the contingency and determined that it no longer
meets the recognition criteria under ASC 450 — Contingencies. Management believes that it is now only reasonably
possible that Eletropaulo will have to refund these amounts to customers. Accordingly, the Company reversed the
160
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
remaining regulatory liability for this contingency of $161 million in 2015, which increased Regulated Revenue by
$97 million and reduced Interest Expense by $64 million. Amounts related to this case are now included as part of
our reasonably possible contingent range mentioned in the preceding paragraph.
14. BENEFIT PLANS
Defined Contribution Plan — The Company sponsors four defined contribution plans ("the Plans"). Two are for
U.S. non-union employees, of which one is for employees of the Parent Company and certain U.S. SBU businesses
and one is for DPL employees. One plan includes both union and non-union employees at IPL. One defined
contribution plan is for union employees at DPL. The Plans are qualified under section 401 of the Internal Revenue
Code. All U.S. employees of the Company are eligible to participate in the appropriate Plan except for those
employees who are covered by a collective bargaining agreement, unless such agreement specifically provides that
the employee is considered an eligible employee under a Plan. The Plans provide matching contributions in AES
common stock or cash, other contributions at the discretion of the Compensation Committee of the Board of
Directors in AES common stock or cash and discretionary tax deferred contributions from the participants.
Participants are fully vested in their own contributions and the Company's matching contributions. Participants vest
in other company contributions ratably over a five-year period ending on the fifth anniversary of their hire date. For
the year ended December 31, 2016, the Company's contributions to the defined contribution plans were
approximately $15 million, and for the years ended December 31, 2015 and 2014, contributions were $18 million
and $22 million per year, respectively.
Defined Benefit Plans — Certain of the Company's subsidiaries have defined benefit pension plans covering
substantially all of their respective employees. Pension benefits are based on years of credited service, age of the
participant and average earnings. Of the 33 active defined benefit plans as of December 31, 2016, 5 are at
U.S. subsidiaries and the remaining plans are at foreign subsidiaries .
The following table reconciles the Company's funded status, both domestic and foreign, as of the periods
indicated (in millions):
December 31,
CHANGE IN PROJECTED BENEFIT OBLIGATION:
Benefit obligation as of January 1
Service cost
Interest cost
Employee contributions
Plan amendments
Plan curtailments
Plan settlements
Benefits paid
Actuarial (gain) loss
Effect of foreign currency exchange rate changes
Benefit obligation as of December 31
CHANGE IN PLAN ASSETS:
Fair value of plan assets as of January 1
Actual return on plan assets
Employer contributions
Employee contributions
Plan settlements
Benefits paid
Effect of foreign currency exchange rate changes
Fair value of plan assets as of December 31
RECONCILIATION OF FUNDED STATUS
Funded status as of December 31
2016
2015
U.S.
Foreign
U.S.
Foreign
$
$
$
$
$
1,172
13
42
—
—
2
—
(60)
19
—
1,188
1,021
61
22
—
—
(60)
—
1,044
$
$
$
$
2,876
13
344
3
(4)
—
—
(303)
558
505
3,992
2,195
451
138
3
—
(303)
340
2,824
$
$
$
$
1,235
16
48
—
5
—
(3)
(61)
(68)
—
1,172
1,061
(7)
31
—
(3)
(61)
—
1,021
$
$
$
$
4,222
15
340
3
2
—
—
(292)
(158)
(1,256)
2,876
3,144
175
86
3
—
(292)
(921)
2,195
(144) $
(1,168) $
(151) $
(681)
The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to the
funded status of the plans, both domestic and foreign, as of the periods indicated (in millions):
December 31,
Amounts Recognized on the Consolidated Balance Sheets
Noncurrent assets
Accrued benefit liability—current
Accrued benefit liability—noncurrent
Net amount recognized at end of year
2016
2015
U.S.
Foreign
U.S.
Foreign
$
$
— $
—
(144)
(144) $
$
60
(5)
(1,223)
(1,168) $
— $
—
(151)
(151) $
67
(5)
(743)
(681)
161
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
The following table summarizes the Company's U.S. and foreign accumulated benefit obligation as of the
periods indicated (in millions):
December 31,
Accumulated Benefit Obligation
Information for pension plans with an accumulated benefit obligation in excess of plan assets:
Projected benefit obligation
Accumulated benefit obligation
Fair value of plan assets
Information for pension plans with a projected benefit obligation in excess of plan assets:
Projected benefit obligation
Fair value of plan assets
_____________________________
2016
2015
U.S.
$ 1,167
Foreign
$ 3,942
U.S.
$ 1,150
Foreign
$ 2,836
$ 1,188
1,167
1,044
$ 3,671
3,638
2,448
$ 1,172
1,150
1,021
$ 2,585
2,561
1,842
$ 1,188
1,044
$ 3,793
2,565
(1)
(1)
$ 1,172
1,021
$ 2,600
1,853
(1)
(1)
(1)
$1.2 billion and $686 million of the total net unfunded projected benefit obligation is due to Eletropaulo in Brazil as of December 31, 2016 and 2015,
respectively.
The following table summarizes the significant weighted average assumptions used in the calculation of
benefit obligation and net periodic benefit cost, both domestic and foreign, as of the periods indicated:
December 31,
Benefit Obligation —
Discount rate
Rate of compensation increase
Periodic Benefit Cost — Discount rate
Expected long-term rate of return on plan assets
Rate of compensation increase
_____________________________
2016
2015
U.S.
4.28%
3.34%
4.44%
6.67%
3.34%
(1)
Foreign
10.08%
6.41%
11.37%
9.54%
6.40%
U.S.
4.44%
3.34%
4.04%
6.67%
3.94%
(1)
Foreign
11.35%
6.31%
10.47%
9.77%
6.33%
(1)
Includes an inflation factor that is used to calculate future periodic benefit cost, but is not used to calculate the benefit obligation.
The Company establishes its estimated long-term return on plan assets considering various factors, which
include the targeted asset allocation percentages, historic returns and expected future returns.
The measurement of pension obligations, costs and liabilities is dependent on a variety of assumptions. These
assumptions include estimates of the present value of projected future pension payments to all plan participants,
taking into consideration the likelihood of potential future events such as salary increases and demographic
experience. These assumptions may have an effect on the amount and timing of future contributions.
The assumptions used in developing the required estimates include the following key factors: discount rates;
salary growth; retirement rates; inflation; expected return on plan assets; and mortality rates.
The effects of actual results differing from the Company's assumptions are accumulated and amortized over
future periods and, therefore, generally affect the Company's recognized expense in such future periods.
Effective January 1, 2016, the Company applied a disaggregated discount rate approach for determining
service cost and interest cost for its defined benefit pension plans and postretirement plans in the U.S. and U.K.
Refer to Note 1—General and Summary of Significant Accounting Policies for further information relating to this
change in estimate.
Sensitivity of the Company's pension funded status to the indicated increase or decrease in the discount rate
and long-term rate of return on plan assets assumptions is shown below. Note that these sensitivities may be
asymmetric and are specific to the base conditions at year-end 2016. They also may not be additive, so the impact
of changing multiple factors simultaneously cannot be calculated by combining the individual sensitivities shown.
The funded status as of December 31, 2016 is affected by the assumptions as of that date. Pension expense for
2016 is affected by the December 31, 2015 assumptions. The impact on pension expense from a one percentage
point change in these assumptions is shown in the following table (in millions):
Increase of 1% in the discount rate
Decrease of 1% in the discount rate
Increase of 1% in the long-term rate of return on plan assets
Decrease of 1% in the long-term rate of return on plan assets
$
(37)
32
(35)
35
The following table summarizes the components of the net periodic benefit cost, both domestic and foreign, for
the years indicated (in millions):
162
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
December 31,
Components of Net Periodic Benefit Cost:
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service cost
Amortization of net loss
Curtailment loss recognized
Settlement gain recognized
Total pension cost
2016
2015
2014
U.S.
Foreign
U.S.
Foreign
U.S.
Foreign
$
$
13
42
(68)
7
18
4
—
16
$
$
13
344
(221)
(1)
19
—
—
154
$
$
16
48
(70)
7
20
—
—
21
$
$
15
340
(236)
—
25
—
—
144
$
$
14
50
(67)
6
13
—
—
16
$
$
16
473
(348)
(1)
35
—
1
176
The following table summarizes in millions the amounts reflected in AOCL, including AOCL attributable to
noncontrolling interests, on the Consolidated Balance Sheet as of December 31, 2016, that have not yet been
recognized as components of net periodic benefit cost and amounts expected to be reclassified to earnings in the
next fiscal year (in millions):
December 31, 2016
Accumulated Other Comprehensive Income (Loss)
Amounts expected to be
reclassified to earnings in next fiscal year
Prior service cost
Unrecognized net actuarial gain (loss)
Total
$
$
U.S.
Foreign
U.S.
Foreign
— $
(16)
(16) $
(1) $
(1,370)
(1,371) $
— $
—
— $
—
(41)
(41)
The following table summarizes the Company's target allocation for 2016 and pension plan asset allocation,
both domestic and foreign, as of the periods indicated:
Asset Category
Equity securities
Debt securities
Real estate
Other
Total pension assets
Target Allocations
2016
2015
Percentage of Plan Assets as of December 31,
U.S.
53%
45%
2%
—%
Foreign
15% -28%
62% - 85%
0% - 4%
0% - 5%
U.S.
50.96%
45.88%
3.16%
—%
100.00%
Foreign
9.42%
78.29%
3.15%
9.14%
100.00%
U.S.
44.76%
50.05%
2.94%
2.25%
100.00%
Foreign
12.76%
81.41%
3.33%
2.50%
100.00%
The U.S. plans seek to achieve the following long-term investment objectives:
• maintenance of sufficient income and liquidity to pay retirement benefits and other lump sum payments;
•
•
•
long-term rate of return in excess of the annualized inflation rate;
long-term rate of return, net of relevant fees, that meets or exceeds the assumed actuarial rate; and
long-term competitive rate of return on investments, net of expenses, that equals or exceeds various benchmark
rates.
The asset allocation is reviewed periodically to determine a suitable asset allocation which seeks to manage
risk through portfolio diversification and takes into account, among other possible factors, the above-stated
objectives, in conjunction with current funding levels, cash flow conditions and economic and industry trends. The
following table summarizes the Company's U.S. plan assets by category of investment and level within the fair value
hierarchy as of the periods indicated (in millions):
U.S. Plans
Equity securities:
Debt securities:
Real Estate:
Other:
Mutual funds
Government debt securities
Mutual funds (1)
Real Estate
Other investments
Total plan assets
Level 1
532
86
393
—
—
$ 1,011
_____________________________
Total
December 31, 2016
Level 3
Level 2
532
—
—
86
—
—
393
—
—
33
—
33
—
—
—
— $ 1,044
33
$
$
Level 1
457
53
458
—
—
968
$
Total
December 31, 2015
Level 3
Level 2
457
—
—
53
—
—
458
—
—
30
—
30
—
23
23
— $ 1,021
53
$
$
(1) Mutual funds categorized as debt securities consist of mutual funds for which debt securities are the primary underlying investment.
The investment strategy of the foreign plans seeks to maximize return on investment while minimizing risk.
The assumed asset allocation has less exposure to equities in order to closely match market conditions and near
term forecasts. The following table summarizes the Company's foreign plan assets by category of investment and
level within the fair value hierarchy as of the periods indicated (in millions):
163
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
Foreign Plans
Equity securities — Mutual funds
Debt securities —
Real estate —
Other —
Private equity (1)
Government debt securities
Corporate debt securities
Mutual funds (2)
Real estate (1)
Participant loans (3)
Other assets
Total plan assets
_____________________________
Level 1
175
$
—
10
—
215
—
—
24
424
$
December 31, 2016
Level 2
Level 3
$
— $
— $
—
—
67
2,049
—
—
—
$ 2,116
$
150
—
—
—
89
42
3
284
Total
175
150
10
67
2,264
89
42
27
$ 2,824
Level 1
156
$
—
11
—
217
—
—
16
400
$
December 31, 2015
Level 2
Level 3
$
— $
— $
—
29
—
1,530
—
—
—
$ 1,559
$
124
—
—
—
73
37
2
236
Total
156
124
40
—
1,747
73
37
18
$ 2,195
(1)
Plan assets of our Brazilian subsidiaries are invested in private equities and commercial real estate through the plan administrator in Brazil. The fair value of
these assets is determined using the income approach through annual appraisals based on a discounted cash flow analysis.
(2) Mutual funds categorized as debt securities consist of mutual funds for which debt securities are the primary underlying investment.
(3)
Loans to participants are stated at cost, which approximates fair value.
The following table presents a reconciliation of all plan assets measured at fair value using significant
unobservable inputs (Level 3) for the periods indicated (in millions):
December 31,
Balance at January 1
Actual return on plan assets:
Returns relating to assets still held at reporting date
Change due to exchange rate changes
Balance at December 31
2016
2015
236
$
389
3
45
284
$
(35)
(118)
236
$
$
The following table summarizes the estimated cash flows for U.S. and foreign expected employer contributions
and expected future benefit payments, both domestic and foreign (in millions):
Expected employer contribution in 2017
Expected benefit payments for fiscal year ending:
2017
2018
2019
2020
2021
2022 - 2026
15. EQUITY
U.S.
Foreign
$
14
$
159
67
69
71
72
74
387
334
346
358
370
381
2,057
Equity Transactions with Noncontrolling Interests
Jordan — In February 2016, the Company completed the sale of 40% of its interest in a wholly-owned
subsidiary in Jordan that owns a controlling interest in the Jordan IPP4 gas-fired plant for $21 million. The
transaction was accounted for as a sale of in-substance real estate and a pretax gain of $4 million, net of
transaction costs, was recognized in net income. The cash proceeds from the sale are reflected in Proceeds from
the sale of businesses, net of cash sold on the Consolidated Statement of Cash Flows for the period ended
December 31, 2016. After completion of the sale, the Company has a 36% economic interest in Jordan IPP4 and
will continue to manage and operate the plant, with 40% owned by Mitsui Ltd. and 24% owned by Nebras Power
Q.S.C. As the Company maintained control after the sale, Jordan IPP4 continues to be consolidated by the
Company within the Europe SBU reportable segment.
Brazil Reorganization — In 2015, the Company completed a restructuring of Tietê. This transaction resulted in
no change of ownership or control. The $27 million impact of this equity transaction was recognized in additional
paid-in capital.
Gener — In November 2015, the Company sold a 4% stake in AES Gener S.A. ("Gener") through its 99.9%
owned subsidiary Inversiones Cachagua S.p.A ("Cachagua") for $145 million, net of transaction costs. The sale was
of previously issued common shares of Gener to certain institutional investors and is not a sale of in-substance real
estate. While the sale decreased Parent ownership interest from 70.7% to 66.7%, the Parent continues to retain its
controlling financial interest in the subsidiary. The difference of $24 million between the fair value of the
consideration received, net of taxes and transaction costs, and the amount by which the NCI is adjusted was
164
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
recognized in additional paid-in capital. No pretax gain or loss was recognized in net income as a result of this
transaction.
Dominican Republic — In December 2014 Estrella and Linda Groups, an investor-based group in the
Dominican Republic acquired 8% noncontrolling interest in our businesses in the Dominican Republic for $83
million, net of transaction costs, with options to acquire an additional 2% for $24 million at any time between the
closing date and December 31, 2015, and an additional 10% for $125 million at any time between the closing date
and December 31, 2017. In December 2015, Estrella and Linda Groups exercised its first call option of additional
2% for $18 million, net of discount and transaction costs. This resulted in Estrella and Linda Groups having a total of
10% noncontrolling interest in our businesses in the Dominican Republic.
As a result of these transaction, $7 million, net of taxes and transaction costs, was recognized in additional
paid-in capital at December 31, 2015. No gain or loss was recognized in net income as the sale was not considered
to be a sale of in-substance real estate. As the Company maintained control after the sale, our businesses in the
Dominican Republic continue to be consolidated by the Company within the MCAC SBU reportable segment.
Masinloc — On June 25, 2014, the Company executed an agreement to sell approximately 45% of its interest
in Masin-AES Pte Ltd., a wholly-owned subsidiary that owns the Company's business interests in the Philippines,
for $453 million, subject to certain purchase price adjustments. On July 15, 2014, the Company completed the
Masinloc sale transaction and received cumulative net proceeds of $436 million, including $23 million contingent
upon the achievement of certain restructuring efficiencies. The transaction was accounted for as a sale of in-
substance real estate. Noncontrolling interest of $130 million and a pretax gain on sale of investment of
approximately $283 million, net of transaction costs, were recognized during the third quarter of 2014. The portion of
the proceeds related to the contingency has been deferred.
After completion of the sale, the Company owns a 51% net ownership interest in Masinloc and will continue to
manage and operate the plant. As the Company maintained control after the sale, Masinloc continues to be
accounted for as a consolidated subsidiary within the Asia SBU reportable segment.
The following table summarizes the net income attributable to The AES Corporation and all transfers (to) from
noncontrolling interests for the periods indicated (in millions):
Net income attributable to The AES Corporation
Transfers from the noncontrolling interest:
December 31,
2015
2016
2014
$ (1,130) $
306
$
769
Net increase in The AES Corporation's paid-in capital for sale of subsidiary shares
Additional paid-in capital, IPALCO shares, transferred to redeemable stock of subsidiaries (1)
Increase (decrease) in The AES Corporation's paid-in capital for purchase of subsidiary shares
Net transfers (to) from noncontrolling interest
84
(84)
(2)
(2)
Change from net income attributable to The AES Corporation and transfers (to) from noncontrolling interests
_____________________________
$ (1,132) $
323
(377)
—
(54)
252
$
29
—
7
36
805
(1)
See Note 18—Redeemable stock of subsidiaries for further information on increase in paid-in capital transferred to redeemable stock of subsidiaries.
Deconsolidations
UK Wind — During 2016, the Company determined it no longer had control of its wind development projects in
the United Kingdom (“UK Wind”) as the Company no longer held seats on the board of directors. In accordance with
the accounting guidance, UK Wind was deconsolidated and a loss on deconsolidation of $20 million was recorded
to Gain (loss) on disposal and sale of businesses in the Consolidated Statement of Operations to write off the
Company’s non-controlling interest in the project. The UK Wind projects were reported in the Europe SBU
reportable segment.
165
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
Accumulated Other Comprehensive Loss — The changes in AOCL by component, net of tax and
noncontrolling interests, for the periods indicated were as follows (in millions):
Balance at December 31,2014
Other comprehensive (loss) income before reclassifications
Amount reclassified to earnings
Other comprehensive (loss) income
Cumulative effect of a change in accounting principle
Balance at December 31, 2015
$
$
$
Other comprehensive (loss) income before reclassifications $
Amount reclassified to earnings
Other comprehensive (loss) income
Balance at December 31, 2016
$
$
Foreign currency
translation adjustment, net
$
$
Unrealized derivative
losses, net
Unfunded pension
obligations, net
Total
(2,595) $
(674) $
—
(674) $
$
13
(3,256) $
117
$
992
1,109
$
(2,147) $
(396) $
(5) $
48
43
$
— $
(353) $
2
$
28
30
$
(323) $
19
2
21
$
— $
(295) $ (3,286)
(660)
$
50
(610)
13
(274) $ (3,883)
106
1,021
(12) $ 1,127
(286) $ (2,756)
(13) $
1
Reclassifications out of AOCL are presented in the following table. Amounts for the periods indicated are in
millions and those in parenthesis indicate debits to the Condensed Consolidated Statements of Operations:
Details About
AOCL Components
Foreign currency translation adjustment, net
Affected Line Item in the Consolidated Statements of Operations
2016
December 31,
2015
2014
Gain on sale of businesses
Net loss from disposal and impairments of discontinued operations
Net income attributable to The AES Corporation
Unrealized derivative gains (losses), net
Non-regulated revenue
Non-regulated cost of sales
Interest expense
Gain on sale of businesses
Foreign currency transaction gains (losses)
Income from continuing operations before taxes and equity in earnings of affiliates
Income tax expense
Net equity in earnings of affiliates
Income from continuing operations
Less: (Income) from continuing operations attributable to noncontrolling interests
Net income attributable to The AES Corporation
Amortization of defined benefit pension actuarial loss, net
Regulated cost of sales
Non-regulated cost of sales
General and administrative expenses
Other Expense
Income from continuing operations before taxes and equity in earnings of affiliates
Income tax expense
Income from continuing operations
Net loss from disposal and impairments of discontinued operations
Net Income
Less: (Income) from continuing operations attributable to noncontrolling interests
Net income attributable to The AES Corporation
Total reclassifications for the period, net of income tax and noncontrolling interests
$
$
$
$
$
$
$
— $
(992)
(992) $
$
111
(57)
(107)
—
8
(45)
8
—
(37)
9
(28) $
(17) $
—
(1)
(1)
(19)
3
(16)
6
(10)
9
(1) $
(1,021) $
— $
—
— $
$
43
(14)
(112)
(4)
12
(75)
11
(2)
(66)
18
(48) $
(24) $
2
(2)
—
(24)
9
(15)
(1)
(16)
14
(2) $
(50) $
4
(38)
(34)
30
(4)
(139)
—
(9)
(122)
26
(3)
(99)
27
(72)
(32)
(5)
—
—
(37)
7
(30)
1
(29)
19
(10)
(116)
Common Stock Dividends — The Company paid dividends of $0.11 per outstanding share to its common
stockholders during the first, second, third and fourth quarters of 2016 for dividends declared in December 2015,
February, July, and October 2016.
On December 9, 2016, the Board of Directors declared a quarterly common stock dividend of $0.12 per share
payable on February 15, 2017 to shareholders of record at the close of business on February 1, 2017.
Stock Repurchase Program — During the year ended December 31, 2016, the Company repurchased 8.7
million shares of its common stock under the Program at a total cost of $79 million under the existing stock
repurchase program. The cumulative repurchase from the commencement of the Program in July 2010 through
December 31, 2016 totaled 154.3 million shares for a total cost of $1.9 billion, at an average price per share of
$12.12 (including a nominal amount of commissions). As of December 31, 2016, $246 million remained available for
repurchase under the Program.
166
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
The common stock repurchased has been classified as treasury stock and accounted for using the cost
method. A total of 156,878,891 and 149,037,831 shares were held as treasury stock at December 31, 2016 and
2015, respectively. Restricted stock units under the Company's employee benefit plans are issued from treasury
stock. The Company has not retired any common stock repurchased since it began the Program in July 2010.
16. SEGMENTS AND GEOGRAPHIC INFORMATION
The segment reporting structure uses the Company's organizational structure as its foundation to reflect how
the Company manages the businesses internally and is organized by geographic regions which provides a socio-
political-economic understanding of our business. The management reporting structure is organized by six SBUs
led by our President and Chief Executive Officer: US, Andes, Brazil, MCAC, Europe, and Asia SBUs. Using the
accounting guidance on segment reporting, the Company determined that it has six operating and six reportable
segments corresponding to its SBUs.
Corporate and Other — Corporate overhead costs which are not directly associated with the operations of our
six reportable segments are included in "Corporate and Other." Also included are certain intercompany charges
such as self-insurance premiums which are fully eliminated in consolidation.
The Company uses Adjusted PTC as its primary segment performance measure. Adjusted PTC, a non-GAAP
measure, is defined by the Company as pretax income from continuing operations attributable to AES excluding (1)
unrealized gains or losses related to derivative transactions, (2) unrealized foreign currency gains or losses, (3)
gains or losses due to dispositions and acquisitions of business interests, (4) losses due to impairments, and (5)
costs due to the early retirement of debt. The Company has concluded that Adjusted PTC best reflects the
underlying business performance of the Company and is the most relevant measure considered in the Company's
internal evaluation of the financial performance of its segments. Additionally, given its large number of businesses
and complexity, the Company concluded that Adjusted PTC is a more transparent measure that better assists
investors in determining which businesses have the greatest impact on the Company's results.
Revenue and Adjusted PTC are presented before inter-segment eliminations, which includes the effect of
intercompany transactions with other segments except for interest, charges for certain management fees, and the
write-off of intercompany balances, as applicable. All intra-segment activity has been eliminated within the segment.
Inter-segment activity has been eliminated within the total consolidated results.
The following tables present financial information by segment for the periods indicated (in millions):
Year Ended December 31,
US SBU
Andes SBU
Brazil SBU
MCAC SBU
Europe SBU
Asia SBU
Corporate and Other
Eliminations
Total Revenue
2016
$ 3,429
2,506
3,755
2,172
918
752
77
(23)
$ 13,586
Total Revenue
2015
$ 3,593
2,489
3,858
2,353
1,191
684
31
(44)
$ 14,155
2014
$ 3,826
2,642
4,987
2,682
1,439
558
15
(25)
$ 16,124
Reconciliation from Income from Continuing Operations before Taxes and Equity In Earnings of Affiliates:
Year Ended December 31,
Income from continuing operations before taxes and equity in earnings of affiliates
Add: Net equity earnings in affiliates
Less: Income from continuing operations before taxes, attributable to noncontrolling interests
Pretax contribution
Unrealized derivative (gains) losses
Unrealized foreign currency losses
Disposition/acquisition (gains) losses
Impairment losses
Loss on extinguishment of debt
Total Adjusted PTC
$
$
167
2016
Total Adjusted PTC
2015
$ 1,154
105
653
606
(166)
96
(42)
504
179
$ 1,177
137
36
313
(140)
(9)
23
6
933
29
842
2014
$ 1,443
19
578
884
(135)
110
(361)
415
274
$ 1,187
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
Year Ended December 31,
US SBU
Andes SBU
Brazil SBU
MCAC SBU
Europe SBU
Asia SBU
Corporate and Other
Total Adjusted PTC
Year Ended December 31,
US SBU
Andes SBU
Brazil SBU
MCAC SBU
Europe SBU
Asia SBU
Assets of discontinued operations and
held-for-sale businesses
Corporate and Other
Total
Year Ended December 31,
US SBU
Andes SBU
Brazil SBU
MCAC SBU
Europe SBU
Asia SBU
Corporate and Other
Total
Year Ended December 31,
US SBU
Andes SBU
Brazil SBU
MCAC SBU
Europe SBU
Asia SBU
Corporate and Other
Total
Total Adjusted PTC
2015
2014
2016
$
$
347
390
29
267
187
96
(474)
842
$
360
482
118
327
235
96
(441)
$ 1,177
$
445
421
108
352
348
46
(533)
$ 1,187
2016
$ 9,333
8,971
6,448
5,162
2,664
3,113
Total Assets
2015
$ 9,800
8,594
5,209
4,820
3,101
3,099
2014
$ 10,019
7,741
6,830
4,924
3,491
2,883
—
1,306
1,603
Depreciation and Amortization
2014
2015
2016
Capital Expenditures
2015
2016
2014
$
$
471
218
145
165
116
33
16
$
443
175
145
155
134
32
40
$
450
182
210
144
154
32
49
$
809
538
264
480
143
136
70
$
861
949
224
201
118
13
75
534
702
317
192
228
429
112
428
$ 36,119
541
$ 36,470
1,071
$ 38,562
12
$ 1,176
20
$ 1,144
24
$ 1,245
18
$ 2,458
17
$ 2,458
30
$ 2,544
Interest Income
2015
2016
2014
2016
Interest Expense
2015
2014
$
$
— $
57
257
11
5
134
—
464
$
— $
77
235
30
1
115
2
460
$
— $
87
204
26
1
2
—
320
236
178
365
163
68
111
310
$ 1,431
$
262
154
257
179
73
85
334
$ 1,344
$
285
160
311
178
98
25
394
$ 1,451
Investments in and Advances to Affiliates
2015
2014
2016
Net Equity in Earnings of Affiliates
2015
2016
2014
$
$
23
363
—
(1)
41
195
—
621
$
$
1
345
—
—
53
195
16
610
$
$
1
287
—
—
54
194
1
537
$
$
9
15
—
(2)
10
3
1
36
$
$
— $
83
—
—
10
8
4
105
$
—
42
—
—
(25)
10
(8)
19
168
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
The following table presents information, by country, about the Company's consolidated operations for each of
the three years ended December 31, 2016, 2015, and 2014, and as of December 31, 2016 and 2015 (in millions).
Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are
located.
Year Ended December 31,
United States
Non-U.S.:
Brazil
Chile
Dominican Republic
El Salvador
Colombia
Philippines
Argentina
Mexico
Vietnam
United Kingdom
Bulgaria
Panama
Puerto Rico
Jordan
Kazakhstan
Sri Lanka
Other Non-U.S.
Total Non-U.S.
Total
Total Revenue
Property, Plant & Equipment, net
2016
2015
2014
2016
2015
$
3,489
$
3,597
$
3,828
$
7,397
$
7,957
3,755
1,707
614
601
437
401
359
342
340
337
334
312
301
136
103
10
8
10,097
$ 13,586
3,858
1,523
632
736
557
406
399
383
233
396
382
297
302
248
155
45
6
10,558
$ 14,155
4,987
1,624
802
832
552
451
463
434
—
533
410
263
348
262
161
107
67
12,296
$ 16,124
$
3,221
4,995
914
327
451
866
195
699
1
151
1,174
1,233
583
452
178
—
10
15,450
22,847
$
2,582
4,591
781
313
445
735
193
716
2
190
1,259
1,027
599
469
146
—
17
14,065
22,022
17. SHARE-BASED COMPENSATION
STOCK OPTIONS — AES grants options to purchase shares of common stock under stock option plans to
employees and non-employee directors. Under the terms of the plans, the Company may issue options to purchase
shares of the Company's common stock at a price equal to 100% of the market price at the date the option is
granted. Stock options are generally granted based upon a percentage of an employee's base salary. Stock options
issued in 2015 and 2014 have a three-year vesting schedule and vest in one-third increments over the three-year
period. The stock options have a contractual term of ten years. The Company did not issue stock options in 2016. At
December 31, 2016, approximately 16 million shares were remaining for award under the plans. In all
circumstances, stock options granted by AES do not entitle the holder the right, or obligate AES, to settle the stock
option in cash or other assets of AES.
The following table presents the weighted average fair value of each option grant and the underlying weighted
average assumptions, as of the grant date, using the Black-Scholes option-pricing model:
December 31,
Expected volatility
Expected annual dividend yield
Expected option term (years)
Risk-free interest rate
Fair value at grant date
2015
2014
25%
3%
7
1.86%
2.07
$
24%
1%
6
1.86%
3.26
$
The Company does not discount the grant date fair values to estimate post-vesting restrictions. Post-vesting
restrictions include black-out periods when the employee is not able to exercise stock options based on their
potential knowledge of information prior to the release of that information to the public.
169
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
The Company initially recognizes compensation cost on the estimated number of instruments for which the
requisite service is expected to be rendered. The following table summarizes the components of stock-based
compensation related to employee stock options recognized in the Company's consolidated financial statements (in
millions):
December 31,
Pretax compensation expense
Tax benefit
Stock options expense, net of tax
Total intrinsic value of options exercised
Total fair value of options vested
Cash received from the exercise of stock options
$
$
$
2016
2015
2014
$
2
(1)
1
$
— $
3
1
$
$
$
3
(1)
2
1
3
5
3
(1)
2
1
2
3
No cash was used to settle stock options or compensation cost capitalized as part of the cost of an asset for
the years ended December 31, 2016, 2015 and 2014. As of December 31, 2016, total unrecognized compensation
cost related to stock options of $1 million is expected to be recognized over a weighted average period of 1 year.
A summary of the option activity for the year ended December 31, 2016 follows (number of options in
thousands, dollars in millions except per option amounts):
Options
Weighted Average
Exercise Price
Weighted Average Remaining
Contractual Term (in years)
Aggregate
Intrinsic Value
Outstanding at December 31, 2015
Exercised
Forfeited and expired
Outstanding at December 31, 2016
Vested and expected to vest at December 31, 2016
Eligible for exercise at December 31, 2016
7,155
(127)
(700)
6,328
6,200
4,810
$
$
$
$
13.81
11.00
17.70
13.43
13.46
13.72
5.5
5.5
4.8
$
$
$
2
2
2
The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the difference
between the Company's closing stock price on the last trading day of 2016 and the exercise price, multiplied by the
number of in-the-money options) that would have been received by the option holders had all option holders
exercised their options on December 31, 2016. The amount of the aggregate intrinsic value will change based on
the fair market value of the Company's stock.
RESTRICTED STOCK
Restricted Stock Units — The Company issues restricted stock units ("RSUs") under its long-term
compensation plan. The RSUs are generally granted based upon a percentage of the participant's base salary. The
units have a three-year vesting schedule and vest in one-third increments over the three-year period. Units granted
prior to 2011 are required to be held for an additional two years before they can be converted into shares, and thus
become transferable. There is no such requirement for units granted in 2011 and afterwards. In all circumstances,
restricted stock units granted by AES do not entitle the holder the right, or obligate AES, to settle the restricted stock
unit in cash or other assets of AES.
For the years ended December 31, 2016, 2015, and 2014, RSUs issued had a grant date fair value equal to
the closing price of the Company's stock on the grant date. The Company does not discount the grant date fair
values to reflect any post-vesting restrictions. RSUs granted to employees during the years ended December 31,
2016, 2015, and 2014 had grant date fair values per RSU of $9.42, $12.03 and $14.60, respectively.
The following table summarizes the components of the Company's stock-based compensation related to its
employee RSUs recognized in the Company's consolidated financial statements (in millions):
December 31,
RSU expense before income tax
Tax benefit
RSU expense, net of tax
Total value of RSUs converted (1)
Total fair value of RSUs vested
_____________________________
(1)
Amount represents fair market value on the date of conversion.
2016
2015
2014
$
$
$
$
14
(4)
10
7
13
$
$
$
$
13
(3)
10
16
12
$
$
$
$
12
(3)
9
25
13
There was no cash used to settle RSUs or compensation cost capitalized as part of the cost of an asset for the
years ended December 31, 2016, 2015, and 2014. As of December 31, 2016, total unrecognized compensation cost
related to RSUs of $17 million is expected to be recognized over a weighted average period of approximately
1.8 years. There were no modifications to RSU awards during the year ended December 31, 2016.
170
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
A summary of the activity of RSUs for the year ended December 31, 2016 follows (RSUs in thousands):
Nonvested at December 31, 2015
Vested
Forfeited and expired
Granted
Nonvested at December 31, 2016
Vested and expected to vest at December 31, 2016
RSUs
2,392
(1,063)
(256)
1,964
3,037
2,716
Weighted Average
Grant Date Fair Values
12.55
$
12.43
10.91
9.42
10.70
10.76
$
$
Weighted Average
Remaining Vesting Term
1.7
The Company initially recognizes compensation cost on the estimated number of instruments for which the
requisite service is expected to be rendered. In 2016, AES has estimated a weighted average forfeiture rate of
11.54% for RSUs granted in 2016. This estimate will be revised if subsequent information indicates that the actual
number of instruments forfeited is likely to differ from previous estimates. Based on the estimated forfeiture rate, the
Company expects to expense $16 million on a straight-line basis over a three year period related to RSUs granted
during the year ended December 31, 2016.
The following table summarizes the RSUs that vested and were converted during the periods indicated (RSUs
in thousands):
Years Ended December 31,
RSUs vested during the year
RSUs converted during the year, net of shares withheld for taxes
Shares withheld for taxes
2016
2015
2014
1,063
705
358
954
1,238
549
1,037
1,734
796
Performance Stock Units — In 2015 and 2014, the Company issued performance stock units ("PSUs") to
officers under its long-term compensation plan. PSUs are restricted stock units of which 50% of the units awarded
include a market condition and the remaining 50% include a performance condition. Vesting will occur if the
applicable continued employment conditions are satisfied and (a) for the units subject to the market condition the
total stockholder return on AES common stock exceeds the total stockholder return of the Standard and Poor's 500
Utilities Sector Index over the three-year measurement period beginning on January 1 of the grant year and ending
on December 31 of the third year and (b) for the units subject to the performance condition if the Company's actual
Adjusted EBITDA meets the performance target over the three-year measurement period beginning on January 1 of
the grant year and ending on December 31 of the third year. The market and performance conditions determine the
vesting and final share equivalent per PSU and can result in earning an award payout range of 0% to 200%,
depending on the achievement. PSUs that included a market condition granted during the year ended
December 31, 2015, and 2014 had a grant date fair value per PSU of $8.22 and $15.19, respectively.
In 2016, the Company issued PSUs to officers under its long-term compensation plan. Vesting will occur if the
Company achieves its Proportional Free Cash Flow target over the three-year performance period beginning on
January 1 of the grant year and ending on December 31 of the third year. The PSUs issued to officers in 2016 had a
grant date fair value of $9.41 equal to the closing price of the Company's stock on the grant date. The grant date fair
value is estimated at 100% of the company's closing stock price. The company believes that it's probable that the
performance condition will be met and will continue to be evaluated throughout the performance period.
In all circumstances, PSUs granted by AES do not entitle the holder the right, or obligate AES, to settle the
restricted stock unit in cash or other assets of AES.
The following table summarizes the components of the Company's stock-based compensation related to its
PSUs recognized in the Company's consolidated financial statements (in millions):
December 31,
PSU expense before income tax
Tax benefit
PSU expense, net of tax
Total value of PSUs converted(1)
Total fair value of PSUs vested
_____________________________
(1)
Amount represents fair market value on the date of conversion.
2016
2015
2014
$
$
$
$
6
(2)
4
1
3
$
$
$
$
5
(1)
4
1
3
$
$
$
$
6
(2)
4
4
1
There was no cash used to settle PSUs or compensation cost capitalized as part of the cost of an asset for the
years ended December 31, 2016, 2015, and 2014. As of December 31, 2016 total unrecognized compensation cost
171
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
related to PSUs of $7 million is expected to be recognized over a weighted average period of approximately
1.8 years. There were no modifications to PSU awards during the year ended December 31, 2016.
A summary of the activity of PSUs for the year ended December 31, 2016 follows (PSUs in thousands):
Nonvested at December 31, 2015
Vested
Forfeited and expired
Granted
Nonvested at December 31, 2016
Vested and expected to vest at December 31, 2016
PSUs
1,551
(231)
(308)
697
1,709
1,449
Weighted Average
Grant Date Fair Values
12.16
$
12.23
12.28
9.41
11.01
10.39
$
$
Weighted Average
Remaining Vesting Term
1.3
The Company initially recognizes compensation cost on the estimated number of instruments for which the
requisite service is expected to be rendered. In 2016, AES has estimated a forfeiture rate of 12.28% for PSUs
granted in 2016. This estimate will be revised if subsequent information indicates that the actual number of
instruments forfeited is likely to differ from previous estimates. Based on the estimated forfeiture rate, the Company
expects to expense $6 million on a straight-line basis over a three year period (approximately $2 million per year)
related to PSUs granted during the year ended December 31, 2016.
The following table summarizes the PSUs that vested and were converted during the periods indicated (PSUs
in thousands):
Years Ended December 31,
PSUs vested during the year
PSUs converted during the year, net of shares withheld for taxes
Shares withheld for taxes
OTHER SHARE-BASED AWARDS
2016
2015
2014
231
141
90
161
96
65
85
287
141
Performance Cash Units - In 2016, the Company issued Performance Cash Units ("PCUs") to its officers
under its long-term compensation plan. The value of these units depends on the total stockholder return on
AES common stock as compared to the total stockholder return of the Standard and Poor's 500 Utilities Sector
Index, Standard and Poor's 500 Index and MSCI Emerging Market Index over a three-year measurement period
beginning on January 1 of the grant year and ending on December 31 of the third year. Since PCUs are settled in
cash, they qualify for liability accounting and periodic measurement is required. As of December 31, 2016, each
PCU is valued at $1.04 per unit. The Company expects to expense $7 million on a straight-line basis over a three
year period (approximately $2 million per year) related to these PCUs.
18. REDEEMABLE STOCK OF SUBSIDIARIES
The following table is a reconciliation of changes in redeemable stock of subsidiaries (in millions):
December 31,
Balance at the beginning of the period
Sale of redeemable stock of subsidiaries
Contributions from holders of redeemable stock of subsidiaries
Net loss attributable to redeemable stock of subsidiaries
Fair value adjustment recorded to retained earnings (1)
Other comprehensive income attributable to redeemable stock of subsidiaries
Acquisition and reclassification of stock of subsidiaries
Balance at the end of the period
_____________________________
2016
2015
$
$
538
134
130
(11)
4
6
(19)
782
$
$
78
460
—
—
—
—
—
538
(1)
$5 million increase in fair value of DP&L preferred shares offset by $1 million decrease in fair value of Colon common stock.
172
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2016, 2015, AND 2014
The following table summarizes the Company's redeemable stock of subsidiaries balances as of the periods
indicated (in millions):
December 31,
IPALCO common stock
Colon quotas (1)
IPL preferred stock
Other common stock
DPL preferred stock
Total redeemable stock of subsidiaries
_____________________________
(1)
Characteristics of quotas are similar to common stock.
2016
2015
$
$
618
100
60
4
—
782
$
$
460
—
60
—
18
538
Colon — During the year ended December 31, 2016, our partner in Colon increased their ownership from 25%
to 49.9% and made capital contributions of $106 million. Any subsequent adjustments to allocate earnings and
dividends to our partner, or measure the investment at fair value, will be classified as temporary equity each
reporting period as it is probable that the shares will become redeemable.
IPL — IPL had $60 million of cumulative preferred stock outstanding at December 31, 2016 and 2015, which
represented five series of preferred stock. The total annual dividend requirements were approximately $3 million at
December 31, 2016 and 2015. Certain series of the preferred stock were redeemable solely at the option of the
issuer at prices between $100 and $118 per share. Holders of the preferred stock are entitled to elect a majority of
IPL's board of directors if IPL has not paid dividends to its preferred stockholders for four consecutive quarters.
Based on the preferred stockholders' ability to elect a majority of IPL's board of directors in this circumstance, the
redemption of the preferred shares is considered to be not solely within the control of the issuer and the preferred
stock is considered temporary equity.
DPL — DPL had $18 million of cumulative preferred stock outstanding as of December 31, 2015, which
represented three series of preferred stock issued by DP&L, a wholly-owned subsidiary of DPL. The DP&L
preferred stock was redeemable at DP&L's option as determined by its board of directors at per-share redemption
prices between $101 and $103 per share, plus cumulative preferred dividends. In addition, DP&L's Amended
Articles of Incorporation contained provisions that permitted preferred stockholders to elect members of the DP&L
Board of Directors in the event that cumulative dividends on the preferred stock are in arrears in an aggregate
amount equivalent to at least four full quarterly dividends. Based on the preferred stockholders' ability to elect
members of DP&L's board of directors in this circumstance, the redemption of the preferred shares was considered
to be not solely within the control of the issuer and the preferred stock was considered temporary equity.
In September 2016, it became probable that the preferred shares would become redeemable. As such, the
Company recorded an adjustment of $5 million to retained earnings to adjust the preferred shares to their
redemption value of $23 million. In October 2016, DP&L redeemed all of its preferred shares. Upon redemption, the
preferred shares were no longer outstanding and all rights of the holders thereof as shareholders of DP&L ceased
to exist.
IPALCO — In February 2015, CDPQ purchased 15% of AES US Investment, Inc., a wholly-owned subsidiary
that owns 100% of IPALCO, for $247 million, with an option to invest an additional $349 million in IPALCO through
2016 in exchange for a 17.65% equity stake. In April 2015, CDPQ invested an additional $214 million in IPALCO,
which resulted in CDPQ's combined direct and indirect interest in IPALCO of 24.90%. As a result of these
transactions, $84 million in taxes and transaction costs were recognized as a net decrease to equity. The Company
also recognized an increase to additional paid-in capital and a reduction to retained earnings of 377 million for the
excess of the fair value of the shares over their book value. No gain or loss was recognized in net income as the
transaction was not considered to be a sale of in-substance real estate.
In March 2016, CDPQ exercised its remaining option by investing $134 million in IPALCO, which resulted in
CDPQ's combined direct and indirect interest in IPALCO of 30%. The Company also recognized an increase to
additional paid-in capital and a reduction to retained earnings of $84 million for the excess of the fair value of the
shares over their book value. In June 2016, CDPQ contributed an additional $24 million to IPALCO, with no impact
to the ownership structure of the investment. Any subsequent adjustments to allocate earnings and dividends to
CDPQ will be classified as NCI within permanent equity as it is not probable that the shares will become
redeemable.
173
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
19. OTHER INCOME AND EXPENSE
Other Income — Other income generally includes gains on asset sales and liability extinguishments, favorable
judgments on contingencies, gains on contract terminations, allowance for funds used during construction and other
income from miscellaneous transactions. The components are summarized as follows (in millions):
Years Ended December 31,
Allowance for Funds Used During Construction (US Utilities)
Gain on sale of assets
Contract termination
Contingency reversal
Other
Total other income
2016
2015
2014
29
5
—
—
31
65
$
$
17
19
20
—
26
82
$
$
9
66
—
18
28
121
$
$
Other Expense — Other expense generally includes losses on asset sales and dispositions, losses on legal
contingencies, and losses from other miscellaneous transactions. The components are summarized as follows (in
millions):
Years Ended December 31,
Allowance for other receivables (1)
Loss on sale and disposal of assets
Water rights write-off
Legal contingencies and settlements
Other
Total other expense
_____________________________
2016
2015
2014
$
$
52
38
6
3
4
103
$
$
— $
31
10
9
8
58
$
—
46
—
11
8
65
(1)
During the fourth quarter of 2016, we recognized a full allowance on a non-trade receivable in the MCAC SBU as a result of payment delays and discussions
with the counterparty. The allowance relates to certain reimbursements the Company was expecting in connection with a legal matter. Management believes
the counterparty is obligated to pay and plans to continue to attempt to fully collect the non-trade receivable.
20. ASSET IMPAIRMENT EXPENSE
Years ended December 31, (in millions)
DPL
Buffalo Gap II
Buffalo Gap I
Kilroot
Buffalo Gap III
U.K. Wind
Ebute
East Bend (DP&L)
Other
Total asset impairment expense
2016
2015
2014
$
$
859
159
77
—
—
—
—
—
1
1,096
$
$
— $
—
—
121
116
37
—
—
11
285
$
—
—
—
—
—
12
67
12
—
91
Buffalo Gap I — During 2016, the Company tested the recoverability of its long-lived assets at Buffalo Gap I.
Low wind production during 2016 resulted in management lowering future expectations of production and therefore
future forecasted revenues. As such this was determined to be an impairment indicator. The Company determined
that the carrying amount of the asset group was not recoverable. The Buffalo Gap I asset group was determined to
have a fair value of $36 million using the income approach. As a result, the Company recognized an asset
impairment expense of $77 million ($23 million attributable to AES). Buffalo Gap I is reported in the US SBU
reportable segment.
DPL — During the second quarter of 2016, the Company tested the recoverability of its long-lived generation
assets at DPL. Uncertainty created by the Supreme Court of Ohio’s June 20, 2016 opinion regarding ESP 2, lower
expectations of future revenue resulting from the most recent PJM capacity auction, and higher anticipated
environmental compliance costs resulting from third party studies were collectively determined to be an impairment
indicator for these assets. The Company performed a long-lived asset impairment analysis and determined that the
carrying amount of Killen, a coal-fired generation facility, and certain DPL peaking generation facilities were not
recoverable. The Killen and DPL peaking generation asset groups were determined to have a fair value of $84
million and $5 million, respectively, using the income approach. As a result, the Company recognized a total asset
impairment expense of $235 million. DPL is reported in the US SBU reportable segment.
During the fourth quarter of 2016, the Company tested the recoverability of its long-lived coal-fired generation
assets and one gas-fired peaking plant at DPL. Additional uncertainty around the useful life of Stuart and Killen
174
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
related to the Company’s ESP proceedings, along with lower expected forward dark spreads and capacity prices,
were collectively determined to be an impairment indicator for these assets. Market information indicating that there
was a significant decrease in the fair value of Zimmer and Miami Fort was determined to be an indicator of
impairment for these assets. The lower forward dark spreads and capacity prices, along with the indicators at the
other coal-fired facilities, collectively, resulted in an indicator of impairment for the Conesville asset group. For the
gas-fired peaking plant, significant incremental capital expenditures relative to its fair value, and an impairment
charge taken at this facility in Q2 2016, were collectively determined to be impairment indicators for this asset. The
Company performed a long-lived asset impairment analysis for each of these asset groups and determined that
their carrying amounts were not recoverable. The Stuart, Killen, Miami Fort, Zimmer, Conesville and the gas-fired
peaking plant asset groups were determined to have a fair value of $57 million, $43 million, $36 million, $24
million, $1 million and $2 million, respectively, using the market approach for Miami Fort and Zimmer and the
income approach for the remaining asset groups. As a result, the Company recognized a total pre-tax asset
impairment expense of $624 million. DPL is reported in the US SBU reportable segment.
Buffalo Gap II — During 2016, the Company tested the recoverability of its long-lived assets at Buffalo Gap II.
Impairment indicators were identified based on a decline in forward power curves. The Company determined that
the carrying amount was not recoverable. The Buffalo Gap II asset group was determined to have a fair value of
$92 million using the income approach. As a result, the Company recognized an asset impairment expense of $159
million ($49 million attributable to AES). Buffalo Gap II is reported in the US SBU reportable segment.
Kilroot — During 2015, the Company tested the recoverability of long-lived assets at Kilroot, a coal- and oil-
fired plant in the U.K., when the regulator established lower capacity prices for the Irish Single Electricity Market.
The Company determined that the carrying amount of the asset group was not recoverable. The Kilroot asset group
was determined to have a fair value of $70 million using the income approach. As a result, the Company recognized
asset impairment expense of $121 million. Kilroot is reported in the Europe SBU reportable segment.
Buffalo Gap III — During 2015, the Company tested the recoverability of its long-lived assets at Buffalo Gap III,
a wind farm in Texas. Impairment indicators were identified based on a decline in forward power curves coupled
with the near term expiration of favorable contracted cash flows. The Company determined that the carrying amount
was not recoverable. The Buffalo Gap III asset group was determined to have a fair value of $118 million using the
income approach. As a result, the Company recognized asset impairment expense of $116 million. Buffalo Gap III is
reported in the US SBU reportable segment.
U.K. Wind — During 2015, the Company decided to no longer pursue two wind projects in the U.K. based on
recent regulatory clarifications specific to these projects, resulting in a full impairment. Impairment indicators were
also identified at four other wind projects based on their current development status and a reassessment of the
likelihood that each project would be pursued given aviation concerns, regulatory changes, economic
considerations and other factors. The Company determined that the carrying amounts of each of these asset
groups, which totaled $38 million, were not recoverable. In aggregate, the asset groups were determined to have a
fair value of $1 million using the market approach and, as a result, the Company recognized asset impairment
expense of $37 million. The U.K. Wind Projects are reported in the Europe SBU reportable segment.
Ebute — During 2014, the Company identified impairment indicators at Ebute in Nigeria, resulting from the
continued lack of gas supply, the increased likelihood of selling the asset group before the end of its useful life, and
indications about the potential proceeds that could be received from a future sale. The Company determined that
the carrying amount of the asset group was not recoverable. The Company recognized asset impairment of $67
million, which represents the difference between the carrying amount of $103 million and fair value less cost to sell
of $36 million. In November 2014, the Company completed the sale of its interest in Ebute. See Note 23—
Dispositions for additional details. Prior to its sale, Ebute was reported in the Europe SBU reportable segment.
U.K. Wind (Newfield) — During 2014, the Company tested the recoverability of long-lived assets at its
Newfield wind development project in the U.K. after their government refused to grant a permit necessary for the
project to continue. The Company determined that the carrying amount of the asset group was not recoverable. The
Newfield asset group was determined to have no fair value using the income approach. As a result, the Company
recognized asset impairment expense of $12 million. U.K. Wind (Newfield) is reported in the Europe SBU reportable
segment.
East Bend (DP&L) — During 2014, the Company identified impairment indicators at East Bend, a coal-fired
plant in Ohio jointly owned by DP&L, resulting from the increased likelihood that the asset group would be disposed
175
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
prior to the end of its useful life. The Company determined that the carrying amount of the asset group was not
recoverable. The East Bend asset group was determined to have a fair value of $2 million using the market
approach, and the Company recognized asset impairment expense of $12 million. The Company's interest in East
Bend was sold in December 2014. Prior to its sale, East Bend was reported in the US SBU reportable segment.
21. INCOME TAXES
Income Tax Provision — The following table summarizes the expense for income taxes on continuing
operations for the periods indicated (in millions):
December 31,
Federal:
State:
Foreign:
Total
Current
Deferred
Current
Deferred
Current
Deferred
2016
2015
2014
$
$
$
2
(361)
1
(4)
326
(152)
(188) $
9
(59)
1
(5)
505
21
472
$
$
—
(127)
1
1
432
64
371
Effective and Statutory Rate Reconciliation — The following table summarizes a reconciliation of the
U.S. statutory federal income tax rate to the Company's effective tax rate as a percentage of income from
continuing operations before taxes for the periods indicated:
December 31,
Statutory Federal tax rate
State taxes, net of Federal tax benefit
Taxes on foreign earnings
Valuation allowance
Uncertain tax positions
Noncontrolling Interest on Buffalo Gap impairments
Change in tax law
Goodwill impairment
Other—net
Effective tax rate
2016
2015
2014
35 %
(24)%
(215)%
14 %
10 %
42 %
16 %
— %
(15)%
(137)%
35 %
(5)%
3 %
(4)%
(1)%
3 %
— %
10 %
— %
41 %
35 %
(1)%
(15)%
(1)%
— %
— %
4 %
4 %
— %
26 %
For 2016, included in the favorable 215% taxes on foreign earnings percentage above is approximately 151%
related to the current year benefit resulting from a restructuring of one of our Brazilian subsidiaries that increased
tax basis in long-term assets. The 42% Buffalo Gap impairments item relates to the amounts of impairment
allocated to noncontrolling interest which is nondeductible.
Included in the favorable 15% 2014 taxes on foreign earnings percentage above is approximately 9% related
to the sale of approximately 45% of the Company's interest in Masin AES Pte Ltd., which owns the Company's
interests in the Philippines, and the sale of the Company's interests in four U.K. wind projects. Neither of these
transactions gave rise to income tax expense.
Income Tax Receivables and Payables — The current income taxes receivable and payable are included in
Other Current Assets and Accrued and Other Liabilities, respectively, on the accompanying Consolidated Balance
Sheets. The noncurrent income taxes receivable and payable are included in Other Noncurrent Assets and Other
Noncurrent Liabilities, respectively, on the accompanying Consolidated Balance Sheets. The following table
summarizes the income taxes receivable and payable as of the periods indicated (in millions):
December 31,
Income taxes receivable—current
Total income taxes receivable
Income taxes payable—current
Income taxes payable—noncurrent
Total income taxes payable
2016
2015
145
145
149
22
171
$
$
$
$
166
166
264
35
299
$
$
$
$
Chilean Tax Reform — In February 2016, the Chilean government enacted further reforms to its income tax
laws that resulted in an increase to statutory income tax rates for most of our Chilean businesses from 25% to
25.5% in 2017 and to 27% for 2018 and future years. The impact of remeasuring deferred taxes to account for the
enacted change in future applicable income tax rates was recognized as discrete income tax expense in the first
quarter of 2016, resulting in an increase of $26 million to consolidated income tax expense.
176
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
Deferred Income Taxes — Deferred income taxes reflect the net tax effects of (a) temporary differences
between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for
income tax purposes and (b) operating loss and tax credit carryforwards. These items are stated at the enacted tax
rates that are expected to be in effect when taxes are actually paid or recovered.
As of December 31, 2016, the Company had federal net operating loss carryforwards for tax purposes of
approximately $3.5 billion expiring in years 2021 to 2036. Approximately $88 million of the net operating loss
carryforward related to stock option deductions will be recognized in additional paid-in capital when realized. The
Company also had federal general business tax credit carryforwards of approximately $20 million expiring primarily
from 2021 to 2036, and federal alternative minimum tax credits of approximately $5 million that carry forward
without expiration. The Company had state net operating loss carryforwards as of December 31, 2016 of
approximately $9.1 billion expiring in years 2017 to 2036. As of December 31, 2016, the Company had foreign net
operating loss carryforwards of approximately $3.1 billion that expire at various times beginning in 2017 and some
of which carry forward without expiration, and tax credits available in foreign jurisdictions of approximately $32
million, $22 million of which expire in 2021 and $8 million of which carryforward without expiration.
Valuation allowances decreased $18 million during 2016 to $876 million at December 31, 2016. This net
decrease was primarily the result of valuation allowance releases and foreign exchange gains at certain of our
Brazil subsidiaries.
Valuation allowances decreased $103 million during 2015 to $894 million at December 31, 2015. This net
decrease was primarily the result of foreign exchange losses and valuation allowance releases at certain of our
Brazil and Vietnam subsidiaries.
The Company believes that it is more likely than not that the net deferred tax assets as shown below will be
realized when future taxable income is generated through the reversal of existing taxable temporary differences and
income that is expected to be generated by businesses that have long-term contracts or a history of generating
taxable income. The Company continues to monitor the utilization of its deferred tax asset for its U.S. consolidated
net operating loss carryforward. Although management believes it is more likely than not that this deferred tax asset
will be realized through generation of sufficient taxable income or reversal of deferred tax liabilities prior to
expiration of the loss carryforwards, such realization is not assured.
The following table summarizes deferred tax assets and liabilities, as of the periods indicated (in millions):
December 31,
Differences between book and tax basis of property
Other taxable temporary differences
Total deferred tax liability
Operating loss carryforwards
Capital loss carryforwards
Bad debt and other book provisions
Retirement costs
Tax credit carryforwards
Other deductible temporary differences
Total gross deferred tax asset
Less: valuation allowance
Total net deferred tax asset
Net deferred tax (liability)
2016
2015
(2,071) $
(80)
(2,151)
2,116
59
182
306
54
287
3,004
(876)
2,128
(23) $
(2,199)
(328)
(2,527)
2,107
66
156
146
55
211
2,741
(894)
1,847
(680)
$
$
The Company considers undistributed earnings of certain foreign subsidiaries to be indefinitely reinvested
outside of the U.S. and, accordingly, no U.S. deferred taxes have been recorded with respect to such earnings in
accordance with the relevant accounting guidance for income taxes. Should the earnings be remitted as dividends,
the Company may be subject to additional U.S. taxes, net of allowable foreign tax credits. As of December 31,
2016, the cumulative amount of foreign un-remitted earnings upon which U.S. income taxes have not been provided
is approximately $4 billion. It is not practicable to estimate the amount of any additional taxes which may be payable
on the undistributed earnings.
Income from operations in certain countries is subject to reduced tax rates as a result of satisfying specific
commitments regarding employment and capital investment. The Company's income tax benefits related to the tax
status of these operations are estimated to be $20 million, $21 million and $38 million for the years ended
December 31, 2016, 2015 and 2014, respectively. The per share effect of these benefits after noncontrolling
interests was $0.02, $0.02 and $0.04 for the years ended December 31, 2016, 2015 and 2014, respectively.
177
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
Included in the Company's income tax benefits is the benefit related to our operations in Vietnam, which is
estimated to be $15 million and $8 million for the years ended December 31, 2016 and 2015, respectively. The per
share effect of these benefits related to our operations in Vietnam after noncontrolling interest was $0.01 and $0.01
for the years ended December 31, 2016 and 2015, respectively.
The following table shows the income (loss) from continuing operations, before income taxes, net equity in
earnings of affiliates and noncontrolling interests, for the periods indicated (in millions):
December 31,
U.S.
Non-U.S.
Total
2016
2015
2014
$
$
(1,305) $
1,442
137
$
(612) $
1,766
1,154
$
(560)
2,003
1,443
Uncertain Tax Positions — Uncertain tax positions have been classified as noncurrent income tax liabilities
unless they are expected to be paid in one year. The Company's policy for interest and penalties related to income
tax exposures is to recognize interest and penalties as a component of the provision for income taxes in the
Consolidated Statements of Operations. The following table shows the total amount of gross accrued income tax
included in the Consolidated Balance Sheets for the periods indicated (in millions):
December 31,
Interest related
Penalties related
2016
2015
$
$
10
1
8
—
The following table shows the total expense/(benefit) related to unrecognized tax benefits for the periods
indicated (in millions):
December 31,
Total expense for interest related to unrecognized tax benefits
Total benefit for penalties related to unrecognized tax benefits
2016
2015
2014
$
$
4
—
— $
—
2
(1)
We are potentially subject to income tax audits in numerous jurisdictions in the U.S. and internationally until
the applicable statute of limitations expires. Tax audits by their nature are often complex and can require several
years to complete. The following is a summary of tax years potentially subject to examination in the significant tax
and business jurisdictions in which we operate:
Jurisdiction
Argentina
Brazil
Chile
Colombia
Dominican Republic
El Salvador
Netherlands
Philippines
United Kingdom
United States (Federal)
Tax Years Subject to Examination
2010-2016
2011-2016
2013-2016
2014-2016
2013-2016
2014-2016
2014-2016
2013-2016
2010-2016
2013-2016
As of December 31, 2016, 2015 and 2014, the total amount of unrecognized tax benefits was $369 million,
$373 million and $394 million, respectively. The total amount of unrecognized tax benefits that would benefit the
effective tax rate as of December 31, 2016, 2015 and 2014 is $332 million, $343 million and $366 million,
respectively, of which $24 million, $24 million and $24 million, respectively, would be in the form of tax attributes that
would warrant a full valuation allowance.
The total amount of unrecognized tax benefits anticipated to result in a net decrease to unrecognized tax
benefits within 12 months of December 31, 2016 is estimated to be up to $10 million, primarily relating to statute of
limitation lapses and tax exam settlements.
178
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the
periods indicated (in millions):
December 31,
Balance at January 1
Additions for current year tax positions
Additions for tax positions of prior years
Reductions for tax positions of prior years
Effects of foreign currency translation
Settlements
Lapse of statute of limitations
Balance at December 31
2016
2015
2014
373
8
1
(1)
2
(13)
(1)
369
$
$
394
7
12
(7)
(7)
(19)
(7)
373
$
$
392
7
14
(2)
(3)
(2)
(12)
394
$
$
The Company and certain of its subsidiaries are currently under examination by the relevant taxing authorities
for various tax years. The Company regularly assesses the potential outcome of these examinations in each of the
taxing jurisdictions when determining the adequacy of the amount of unrecognized tax benefit recorded. While it is
often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, we
believe we have appropriately accrued for our uncertain tax benefits. However, audit outcomes and the timing of
audit settlements and future events that would impact our previously recorded unrecognized tax benefits and the
range of anticipated increases or decreases in unrecognized tax benefits are subject to significant uncertainty. It is
possible that the ultimate outcome of current or future examinations may exceed our provision for current
unrecognized tax benefits in amounts that could be material, but cannot be estimated as of December 31, 2016.
Our effective tax rate and net income in any given future period could therefore be materially impacted.
22. DISCONTINUED OPERATIONS
Brazil Distribution — Due to a portfolio evaluation in the first half of 2016, management has decided to pursue
a strategic shift of its distribution companies in Brazil, AES Sul and Eletropaulo. The disposal of Sul was completed
in October 2016. In December 2016, Eletropaulo underwent a corporate restructuring which is expected to, among
other things, provide more liquidity of its shares. AES is continuing to pursue strategic options for Eletropaulo in
order to complete its strategic shift to reduce AES’ exposure to the Brazilian distribution business, including
preparation for listing its shares into the Novo Mercado, which is a listing segment of the Brazilian stock exchange
with the highest standards of corporate governance.
The Company executed an agreement for the sale of its wholly-owned subsidiary AES Sul in June 2016. We
have reported the results of operations and financial position of AES Sul as discontinued operations in the
consolidated financial statements for all periods presented. Upon meeting the held-for-sale criteria, the Company
recognized an after tax loss of $382 million comprised of a pretax impairment charge of $783 million, offset by a tax
benefit of $266 million related to the impairment of the Sul long lived assets and a tax benefit of $135 million for
deferred taxes related to the investment in AES Sul. Prior to the impairment charge in the second quarter, the
carrying value of the AES Sul asset group of $1.6 billion was greater than its approximate fair value less costs to
sell. However, the impairment charge was limited to the carrying value of the long lived assets of the AES Sul
disposal group.
On October 31, 2016, the Company completed the sale of AES Sul and received final proceeds less costs to
sell of $484 million, excluding contingent consideration. Upon disposal of AES Sul, we incurred an additional after-
tax loss on sale of $737 million. The cumulative impact to earnings of the impairment and loss on sale was $1.1
billion. This includes the reclassification of approximately $1 billion of cumulative translation losses, resulting in a
net reduction to the Company’s stockholders’ equity of $92 million.
Sul’s pretax loss attributable to AES for the years ended December 31, 2016 and 2015 was $1.4 billion and
$32 million, respectively. Sul’s pretax gain attributable to AES for the year ended December 31, 2014 was $133
million. Prior to its classification as discontinued operations, Sul was reported in the Brazil SBU reportable segment.
As discussed in Note 1—General and Summary of Significant Accounting Policies, effective July 1, 2014, the
Company prospectively adopted ASU No. 2014-08. Discontinued operations prior to adoption of ASU No. 2014-08
include the results of Cameroon, Saurashtra and various U.S. wind projects which were each sold in the first half of
2014.
Cameroon — In September 2013, the Company executed agreements for the sale of its 56% equity interests
in businesses in Cameroon: Sonel, an integrated utility, Kribi, a gas and light fuel oil plant, and Dibamba, a heavy
179
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
fuel oil plant. The sale was completed in June 2014. Net proceeds from the sale transaction were $200 million, of
which $156 million was received in 2014. Of the remaining non-contingent consideration of $44 million, $40 million
was received in the second quarter of 2016. Between meeting the held-for-sale criteria in September 2013 and
completing the sale in June 2014, the Company recognized impairments of $101 million and an additional loss on
sale of $7 million. Prior to classification as discontinued operations, these businesses were reported in the Europe
SBU reportable segment.
Saurashtra — In October 2013, the Company executed an agreement for the sale of Saurashtra, a wind
project in India. The sale transaction was completed in February 2014 and net proceeds of $8 million were received.
Prior to its classification as discontinued operations, Saurashtra was reported in the Asia SBU reportable segment.
U.S. Wind Projects — In November 2013, the Company executed an agreement for the sale of its 100%
membership interests in three wind projects: Condon in California, Lake Benton I in Minnesota and Storm Lake II in
Iowa. Upon meeting the held-for-sale criteria for these three projects, the Company recognized impairment expense
of $47 million (of which $7 million was attributable to noncontrolling interests held by tax equity partners)
representing the difference between their aggregate carrying amount of $77 million and the fair value less costs to
sell of $30 million. The sale was completed in January 2014 and net proceeds of $27 million were received. Prior to
classification as discontinued operations, these businesses were reported in the US SBU reportable segment.
As the sale of AES Sul closed October 31, 2016, there were no assets or liabilities of discontinued operations
and held-for-sale businesses at December 31, 2016. The following table summarizes the carrying amounts of the
major classes of assets and liabilities of discontinued operations and held-for-sale businesses at December 31,
2015:
(in millions)
Assets of discontinued operations and held-for-sale businesses:
Cash and cash equivalents
Accounts receivable, net of allowance for doubtful accounts of $8
Property, plant and equipment and intangibles, net
Deferred income taxes
Other classes of assets that are not major
Total assets of discontinued operations
Other assets of businesses classified as held-for-sale (1)
Total assets of discontinued operations and held-for-sale businesses (2)
Liabilities of discontinued operations and held-for-sale businesses:
Accounts payable
Accrued and other liabilities
Non-recourse debt
Other classes of liabilities that are not major
Total liabilities of discontinued operations
Other liabilities of businesses classified as held-for-sale (1)
Total liabilities of discontinued operations and held-for-sale businesses (2)
_____________________________
(1)
(2)
DPLER and Kelanitissa were classified as held-for-sale as of December 31, 2015. See Note 23—Dispositions for further information.
Amounts were classified as both current and long-term on the Consolidated Balance Sheet as of December 31, 2015.
December 31, 2015
$
$
$
$
5
171
668
133
233
1,210
96
1,306
150
150
346
125
771
13
784
The following table summarizes the major line items constituting income (losses) from discontinued operations
for the periods indicated (in millions):
December 31,
Income (loss) from discontinued operations, net of tax:
Revenue — regulated
Cost of sales
Other income and expense items that are not major
Pretax income (loss) from operations of discontinued businesses
Pretax gain (loss) from disposal and impairments of discontinued businesses
Pretax income (loss) from discontinued operations
Less: Net loss attributable to noncontrolling interests
Pretax income (loss) from discontinued operations attributable to The AES Corporation
Income tax benefit (expense)
Income (loss) from discontinued operations, net of tax
2016
2015
2014
$
$
$
701
(672)
(57)
(28)
(1,385)
(1,413)
—
(1,413)
275
(1,138) $
$
808
(800)
(40)
(32)
—
(32)
—
(32)
7
(25) $
1,255
(1,078)
5
182
(51)
131
8
139
(75)
64
180
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
The following table summarizes the operating and investing cash flows from discontinued operations
associated with Sul, the only business that qualifies for discontinued operations after the adoption of ASU No.
2014-08, for the periods indicated (in millions):
December 31,
Cash flows from operating activities of Sul discontinued operations
Cash flows from investing activities of Sul discontinued operations
2016
2015
2014
$
$
58
(54)
(15) $
(25)
15
(123)
23. DISPOSITIONS
U.K. Wind — During the second quarter of 2016, the Company deconsolidated UK Wind and recorded a loss
on deconsolidation of $20 million to Gain on disposal and sale of businesses in the Consolidated Statement of
Operations. Prior to deconsolidation, UK Wind was reported in the Europe SBU reportable segment. See Note 15—
Equity for additional information.
DPLER — In December 2015, the Company executed an agreement for the sale of its ownership interest in
DPLER, a competitive retail marketer selling electricity to customers in Ohio. Accordingly, DPLER was classified as
held-for-sale as of December 31, 2015, but did not meet the criteria to be reported as a discontinued operation.
DPLER's results were therefore reflected within continuing operations in the Consolidated Statements of
Operations.
On January 1, 2016, the Company completed the sale of its interest in DPLER and recognized a gain on sale
of $49 million. Proceeds of $76 million were received on December 31, 2015. The proceeds were classified as
restricted cash with a corresponding amount recorded in Accrued and other liabilities in the Consolidated Balance
Sheet as of December 31, 2015. DPLER's pretax income attributable to AES for the year ended December 31, 2015
was $11 million and pretax loss attributable to AES for the year ended December 31, 2014 was $129 million. Prior to
its sale, DPLER was reported in the US SBU reportable segment.
Kelanitissa — In August 2015, the Company executed an agreement for the sale of its 90% ownership interest
in Kelanitissa, a diesel-fired generation plant in Sri Lanka. Accordingly, Kelanitissa was classified as held-for-sale as
of December 31, 2015, but did not meet the criteria to be reported as a discontinued operation. Kelanitissa's results
were therefore reflected within continuing operations in the Consolidated Statements of Operations.
On January 27, 2016, the Company completed the sale of its interest in Kelanitissa. Upon completion,
proceeds of $18 million were received and a loss on sale of $5 million was recognized. Kelanitissa's pretax loss
attributable to AES for the year ended December 31, 2015 was $7 million and pretax income attributable to AES for
the year ended December 31, 2014 was $1 million. Prior to its sale, Kelanitissa was reported in the Asia SBU
reportable segment.
Armenia Mountain — Under the terms of the sale agreement for certain U.S. Wind Projects, the buyer was
provided an option to purchase the Company's 100% interest in Armenia Mountain, a wind project in Pennsylvania,
at a fixed price of $75 million. The buyer exercised the option on March 31, 2015 and completed the sale of its
interest in Armenia Mountain on July 1, 2015. The sale did not meet the criteria to be reported as a discontinued
operation. Upon completion, net proceeds of $64 million were received and a pretax gain on sale of $22 million was
recognized. Excluding the gain on sale, Armenia Mountain's pretax income attributable to AES was $6 million and
$7 million for the years ended December 31, 2015 and 2014, respectively. Prior to its sale, Armenia Mountain was
reported in the US SBU reportable segment.
Ebute — On November 20, 2014, the Company completed the sale of its interest in Ebute, which included its
95% interest in AES Nigeria Barge Limited and its 100% interest in AES Nigeria Barge Operations Limited.
Proceeds from the sale were $22 million and the Company recognized a loss on sale of $6 million. As Ebute did not
meet the criteria to be reported as a discontinued operation, its results were reflected within continuing operations in
the Consolidated Statements of Operations. Excluding the loss on sale, Ebute's pretax loss attributable to AES was
$27 million for the year ended December 31, 2014. Prior to its sale, Ebute was reported in the Europe SBU
reportable segment.
U.K. Wind (Operating Projects) — On August 22, 2014, the Company completed the sale of its interests in four
operating wind projects located in the U.K.. Total net proceeds from the sale were $158 million and the Company
recognized a pretax gain on sale of $78 million. As these wind projects did not meet the criteria to be reported as
discontinued operations, their results were reflected within continuing operations in the Consolidated Statements of
Operations. Excluding the gain on sale, the pretax loss attributable to AES for these disposed projects was $18
181
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
million for the year ended December 31, 2014. Prior to the sale, U.K. Wind (Operating Projects) were reported in
the Europe SBU reportable segment.
24. ACQUISITIONS
Distributed Energy — On February 18, 2015, the Company completed the acquisition of 100% of the common
stock of Main Street Power Company, Inc. for approximately $25 million. The purchase consideration was
composed of $20 million cash and the fair value of earn-out payments of $5 million. At December 31, 2015, the
assets acquired (including $4 million cash) and liabilities assumed at the acquisition date were recorded at fair
value based on the final purchase price allocation, which resulted in the recognition of $16 million of goodwill. After
the date of acquisition, Main Street Power Company, Inc. was renamed Distributed Energy, Inc.
On September 16, 2016, Distributed Energy acquired the equity interest of various projects held by multiple
partnerships for approximately $43 million. These partnerships were previously classified as equity method
investments. In accordance with the accounting guidance for business combinations, the Company has recorded
the opening balance sheets of the acquired businesses based on the purchase price allocation as of the acquisition
date.
25. EARNINGS PER SHARE
Basic and diluted earnings per share are based on the weighted-average number of shares of common stock
and potential common stock outstanding during the period. Potential common stock, for purposes of determining
diluted earnings per share, includes the effects of dilutive restricted stock units, stock options and convertible
securities. The effect of such potential common stock is computed using the treasury stock method or the if-
converted method, as applicable.
The following table is a reconciliation of the numerator and denominator of the basic and diluted earnings per
share computation for income from continuing operations for the years ended December 31, 2016, 2015 and 2014,
where income represents the numerator and weighted-average shares represent the denominator. Values are in
millions except per share data:
Year Ended December 31,
2016
2015
2014
Income
Shares
$ per Share
Income
Shares
$ per Share
Income
Shares
$ per Share
BASIC EARNINGS PER SHARE
Income from continuing operations attributable to
The AES Corporation common stockholders (1)
EFFECT OF DILUTIVE SECURITIES
Stock options
Restricted stock units
DILUTED EARNINGS PER SHARE
_____________________________
$
3
660
$
— $ 331
687
$
0.48
$ 705
720
$
0.98
—
—
3
$
—
2
662
$
—
—
—
—
— $ 331
—
2
689
$
—
—
0.48
—
—
$ 705
1
3
724
$
—
(0.01)
0.97
(1)
Income from continuing operations, net of tax, of $8 million less the $5 million adjustment to retained earnings to record the DP&L redeemable preferred stock
at its redemption value as of December 31, 2016.
The calculation of diluted earnings per share excluded 8 million, 8 million and 6 million stock awards
outstanding for the years ended December 31, 2016, 2015 and 2014, respectively, that could potentially dilute basic
earnings per share in the future. Additionally, for the years ended December 31, 2016, 2015 and 2014, all 15 million
convertible debentures were omitted from the earnings per share calculation. The stock awards and convertible
debentures were excluded from the calculation because they were anti-dilutive.
26. RISKS AND UNCERTAINTIES
AES is a diversified power generation and utility company organized into six market-oriented SBUs. See
additional discussion of the Company's principal markets in Note 16—Segment and Geographic Information. Within
our six SBUs, we have two primary lines of business: Generation and Utilities. The Generation line of business uses
a wide range of fuels and technologies to generate electricity such as coal, gas, hydro, wind, solar and biomass.
Our Utilities business is comprised of businesses that transmit, distribute, and in certain circumstances, generate
power. In addition, the Company has operations in the renewables area. These efforts include projects primarily in
wind and solar.
Operating and Economic Risks — The Company operates in several developing economies where
macroeconomic conditions are usually more volatile than developed economies. Deteriorating market conditions
often expose the Company to the risk of decreased earnings and cash flows due to, among other factors, adverse
182
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
fluctuations in the commodities and foreign currency spot markets. Additionally, credit markets around the globe
continue to tighten their standards, which could impact our ability to finance growth projects through access to
capital markets. Currently, the Company has a below-investment grade rating from Standard & Poor's of BB-. This
could affect the Company's ability to finance new and/or existing development projects at competitive interest rates.
As of December 31, 2016, the Company had $1.3 billion of unrestricted cash and cash equivalents.
During 2016, 74% of our revenue was generated outside the U.S. and a significant portion of our international
operations is conducted in developing countries. We continue to invest in several developing countries to expand
our existing platform and operations. International operations, particularly the operation, financing and development
of projects in developing countries, entail significant risks and uncertainties, including, without limitation:
• economic, social and political instability in any particular country or region;
•
inability to economically hedge energy prices;
• volatility in commodity prices;
• adverse changes in currency exchange rates;
• government restrictions on converting currencies or repatriating funds;
• unexpected changes in foreign laws, regulatory framework, or in trade, monetary or fiscal policies;
• high inflation and monetary fluctuations;
•
•
• unwillingness of governments, government agencies, similar organizations or other counterparties to honor
restrictions on imports of coal, oil, gas or other raw materials required by our generation businesses to operate;
threatened or consummated expropriation or nationalization of our assets by foreign governments;
their commitments;
• unwillingness of governments, government agencies, courts or similar bodies to enforce contracts that are
economically advantageous to subsidiaries of the Company and economically unfavorable to counterparties,
against such counterparties, whether such counterparties are governments or private parties;
inability to obtain access to fair and equitable political, regulatory, administrative and legal systems;
•
• adverse changes in government tax policy;
• difficulties in enforcing our contractual rights, enforcing judgments, or obtaining a just result in local
jurisdictions; and
• potentially adverse tax consequences of operating in multiple jurisdictions.
Any of these factors, individually or in combination with others, could materially and adversely affect our
business, results of operations and financial condition. In addition, our Latin American operations experience
volatility in revenue and earnings which have caused and are expected to cause significant volatility in our results of
operations and cash flows. The volatility is caused by regulatory and economic difficulties, political instability,
indexation of certain PPAs to fuel prices, and currency fluctuations being experienced in many of these countries.
This volatility reduces the predictability and enhances the uncertainty associated with cash flows from these
businesses.
Our inability to predict, influence or respond appropriately to changes in law or regulatory schemes, including
any inability to obtain reasonable increases in tariffs or tariff adjustments for increased expenses, could adversely
impact our results of operations or our ability to meet publicly announced projections or analysts' expectations.
Furthermore, changes in laws or regulations or changes in the application or interpretation of regulatory provisions
in jurisdictions where we operate, particularly our Utility businesses where electricity tariffs are subject to regulatory
review or approval, could adversely affect our business, including, but not limited to:
• changes in the determination, definition or classification of costs to be included as reimbursable or pass-
through costs;
• changes in the definition or determination of controllable or noncontrollable costs;
• adverse changes in tax law;
• changes in the definition of events which may or may not qualify as changes in economic equilibrium;
• changes in the timing of tariff increases;
• other changes in the regulatory determinations under the relevant concessions; or
183
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
• changes in environmental regulations, including regulations relating to GHG emissions in any of our
businesses.
Any of the above events may result in lower margins for the affected businesses, which can adversely affect
our results of operations.
Construction — As of December 31, 2016, the Company has 531 MW under construction at Alto Maipo.
Increased project costs, or delays in construction, could have an adverse impact on the Company.
Foreign Currency Risks — AES operates businesses in many foreign countries and such operations could
be impacted by significant fluctuations in foreign currency exchange rates. Fluctuations in currency exchange rate
between U.S. Dollar and the following currencies could create significant fluctuations to earnings and cash flows:
the Argentine peso, the Brazilian real, the Dominican Republic peso, the Euro, the Chilean peso, the Colombian
peso, the Philippine peso and the Kazakhstan tenge.
Concentrations — Due to the geographical diversity of its operations, the Company does not have any
significant concentration of customers or sources of fuel supply. Several of the Company's generation businesses
rely on PPAs with one or a limited number of customers for the majority of, and in some cases all of, the relevant
businesses' output over the term of the PPAs. However, no single customer accounted for 10% or more of total
revenue in 2016, 2015 or 2014.
The cash flows and results of operations of our businesses depend on the credit quality of our customers and
the continued ability of our customers and suppliers to meet their obligations under PPAs and fuel supply
agreements. If a substantial portion of the Company's long-term PPAs and/or fuel supply were modified or
terminated, the Company would be adversely affected to the extent that it would be unable to replace such
contracts at equally favorable terms.
27. RELATED PARTY TRANSACTIONS
Certain of our businesses in Panama and the Dominican Republic are partially owned by governments either
directly or through state-owned institutions. In the ordinary course of business, these businesses enter into energy
purchase and sale transactions, and transmission agreements with other state-owned institutions which are
controlled by such governments. At two of our generation businesses in Mexico, the offtakers exercise significant
influence, but not control, through representation on these businesses' Boards of Directors. These offtakers are also
required to hold a nominal ownership interest in such businesses. In Chile, we provide capacity and energy under
contractual arrangements to our investment which is accounted for under the equity method of accounting.
Additionally, the Company provides certain support and management services to several of its affiliates under
various agreements.
The Company's Consolidated Statements of Operations included the following transactions with related parties
for the periods indicated (in millions):
Years Ended December 31,
Revenue—Non-Regulated
Cost of Sales—Non-Regulated
Interest Income
Interest Expense
$
2016
2015
2014
$
1,100
210
4
39
$
1,099
330
25
33
1,188
331
17
9
The following table summarizes the balances receivable from and payable to related parties included in the
Company's Consolidated Balance Sheets as of the periods indicated (in millions):
December 31,
Receivables from related parties
Accounts and notes payable to related parties
2016
2015
$
$
218
498
181
524
28. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly Financial Data — The following tables summarize the unaudited quarterly Condensed Consolidated
Statements of Operations for the Company for 2016 and 2015 (amounts in millions, except per share data).
Amounts have been restated to reflect discontinued operations in all periods presented and reflect all adjustments
necessary in the opinion of management for a fair statement of the results for interim periods.
184
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2016, 2015, AND 2014
Mar 31
June 30
Sept 30
Dec 31
Quarter Ended 2016
Revenue
Operating margin
Income (loss) from continuing operations, net of tax (1)
(Loss) from discontinued operations, net of tax
Net income (loss)
Net income (loss) attributable to The AES Corporation
Basic income (loss) per share:
Income (loss) from continuing operations attributable to The AES Corporation, net of tax
Income (loss) from discontinued operations attributable to The AES Corporation, net of tax
Basic income (loss) per share attributable to The AES Corporation
Diluted income (loss) per share:
Income (loss) from continuing operations attributable to The AES Corporation, net of tax
Income (loss) from discontinued operations attributable to The AES Corporation, net of tax
Diluted income (loss) per share attributable to The AES Corporation
Dividends declared per common share
Quarter Ended 2015
Revenue
Operating margin
Income from continuing operations, net of tax (2)
Income (loss) from discontinued operations, net of tax
Net income
Net income (loss) attributable to The AES Corporation
Basic income (loss) per share:
Income (loss) from continuing operations attributable to The AES Corporation, net of tax
Income (loss) from discontinued operations attributable to The AES Corporation, net of tax
Basic income (loss) per share attributable to The AES Corporation
Diluted income (loss) per share:
Income (loss) from continuing operations attributable to The AES Corporation, net of tax
Income (loss) from discontinued operations attributable to The AES Corporation, net of tax
Diluted income (loss) per share attributable to The AES Corporation
Dividends declared per common share
_____________________________
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
3,271
509
83
(9)
74
126
0.20
(0.01)
0.19
0.20
(0.01)
0.19
0.11
Mar 31
3,758
721
261
(7)
254
142
0.21
(0.01)
0.20
0.21
(0.01)
0.20
$
— $
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
3,229
574
(8)
(379)
(387) $
(482) $
(0.16) $
(0.57)
(0.73) $
(0.16) $
(0.57)
(0.73) $
— $
3,542
688
230
(1)
229
175
0.26
—
0.26
0.26
—
0.26
0.11
June 30
Sept 30
3,656
755
274
(10)
264
69
0.11
(0.01)
0.10
0.11
(0.01)
0.10
0.10
$
$
$
$
$
$
$
$
3,522
665
198
5
203
180
0.26
0.01
0.27
0.26
—
0.26
0.10
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
3,544
662
56
(749)
(693)
(949)
(0.30)
(1.14)
(1.44)
(0.30)
(1.14)
(1.44)
0.23
Dec 31
3,219
717
54
(13)
41
(85)
(0.11)
(0.02)
(0.13)
(0.11)
(0.02)
(0.13)
0.21
(1)
(2)
Includes pretax impairment expense of $159 million, $235 million, $79 million and $625 million, for the first, second, third and fourth quarters of 2016,
respectively. See Note 20—Asset Impairment Expense for further discussion.
Includes pretax impairment expense of $8 million, $37 million, $231 million and $326 million, for the first, second, third and fourth quarters of 2015,
respectively. See Note 9—Goodwill and Other Intangible Assets and Note 20—Asset Impairment Expense for further discussion.
29. SUBSEQUENT EVENTS
Kazakhstan Sale - In January 2017, the Company entered into an agreement for the sale of Ust-Kamenogorsk
CHP and Sogrinsk CHP, its combined heating and power coal plants in Kazakhstan. The sale is expected to close in
the second quarter of 2017. The assets did not qualify as held-for-sale as of December 31, 2016. The Company
expects to recognize a combined impairment and loss on sale of approximately $125 million in the first half of 2017.
sPower Acquisition - On February 19, 2017, the Company and Alberta Investment Management Corporation
(“AIMCo”) entered into an agreement to acquire FTP Power LLC (“sPower”) for $853 million in cash, subject to
customary purchase price adjustments, plus the assumption of sPower’s non-recourse debt. Upon completion of the
transaction, AES and AIMCo will each own slightly below 50% of sPower. The sPower portfolio includes solar and
wind projects in operation, under construction, and in development located in the United States. The transaction is
expected to close by the third quarter of 2017. The Agreement contains certain termination rights for the parties,
including if the closing does not occur by December 31, 2017, which may be automatically extended under certain
circumstances. Additionally, the Company and AIMCo may be required to incur a reverse termination fee of up to
$75 million.
185
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
The Company maintains disclosure controls and procedures that are designed to ensure that information
required to be disclosed in the reports that the Company files or submits under the Securities Exchange Act of
1934, as amended (the "Exchange Act") is recorded, processed, summarized and reported within the time periods
specified in the SEC's rules and forms, and that such information is accumulated and communicated to the CEO
and CFO, as appropriate, to allow timely decisions regarding required disclosures.
The Company carried out the evaluation required by Rules 13a-15(b) and 15d-15(b), under the supervision
and with the participation of our management, including the CEO and CFO, of the effectiveness of our “disclosure
controls and procedures” (as defined in the Exchange Act Rules 13a-15(e) and 15d-15(e)). Based upon this
evaluation, the CEO and CFO concluded that as of December 31, 2016, our disclosure controls and procedures
were effective.
Management's Report on Internal Control over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over
financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. The 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 GAAP and includes
those policies and procedures that:
•
pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the Company;
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only
in accordance with authorizations of management and directors of the Company; and
provide reasonable assurance that unauthorized acquisition, use or disposition of the Company's assets that
could have a material effect on the financial statements are prevented or detected timely.
•
•
Management, including our CEO and CFO, does not expect that our internal controls will prevent or detect all
errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not
absolute, assurance that the objectives of the control system are met. Further, the design of a control system must
reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their
costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may
become inadequate in future periods because of changes in business conditions, or that the degree of compliance
with the policies or procedures deteriorates.
Management assessed the effectiveness of our internal control over financial reporting as of December 31,
2016. In making this assessment, management used the criteria established in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") in 2013.
Based on this assessment, management believes that the Company maintained effective internal control over
financial reporting as of December 31, 2016.
The effectiveness of the Company's internal control over financial reporting as of December 31, 2016, has
been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report,
which appears herein.
Changes in Internal Control Over Financial Reporting:
There were no changes that occurred during the quarter ended December 31, 2016 that have materially
affected, or are reasonably likely to materially affect, our internal control over financial reporting.
186
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of The AES Corporation:
We have audited The AES Corporation’s internal control over financial reporting as of December 31, 2016,
based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (2013 Framework) (the COSO criteria). The AES 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 Report
on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal
control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether effective internal control over financial reporting was maintained in all material respects. Our audit included
obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness
exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk,
and performing such other procedures as we considered necessary in the circumstances. We believe that our audit
provides a reasonable basis for our opinion.
A 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 generally accepted accounting principles. 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 company; (2) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company are being made
only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’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.
In our opinion, The AES Corporation maintained, in all material respects, effective internal control over
financial reporting as of December 31, 2016, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States), the consolidated balance sheets of The AES Corporation as of December 31, 2016 and 2015, and
the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for
each of the three years in the period ended December 31, 2016 of The AES Corporation and our report dated
February 24, 2017 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
McLean, Virginia
February 24, 2017
ITEM 9B. OTHER INFORMATION
None.
187
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The following information is incorporated by reference from the Registrant's Proxy Statement for the
Registrant's 2017 Annual Meeting of Stockholders which the Registrant expects will be filed on or around March 7,
2017 (the "2017 Proxy Statement"):
•
•
•
•
information regarding the directors required by this item found under the heading Board of Directors;
information regarding AES' Code of Ethics found under the heading Additional Governance Matters - AES
Code of Business Conduct and Corporate Governance Guidelines;
information regarding compliance with Section 16 of the Exchange Act required by this item found under the
heading Additional Governance Matters - Other Governance Information - Section 16(a) Beneficial
Ownership Reporting Compliance; and
information regarding AES' Financial Audit Committee found under the heading Board and Committee
Governance Matters - Financial Audit Committee (the “Audit Committee”).
Certain information regarding executive officers required by this Item is presented as a supplementary item in
Part I hereof (pursuant to Instruction 3 to Item 401(b) of Regulation S-K). The other information required by this
Item, to the extent not included above, will be contained in our 2017 Proxy Statement and is herein incorporated by
reference.
ITEM 11. EXECUTIVE COMPENSATION
The following information is contained in the 2017 Proxy Statement and is incorporated by reference: the
information regarding executive compensation contained under the heading Compensation Discussion and Analysis
and the Compensation Committee Report on Executive Compensation under the heading Report of the
Compensation Committee.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS
(a) Security Ownership of Certain Beneficial Owners.
See the information contained under the heading Security Ownership of Certain Beneficial Owners, Directors,
and Executive Officers of the 2017 Proxy Statement, which information is incorporated herein by reference.
(b) Security Ownership of Directors and Executive Officers.
See the information contained under the heading Security Ownership of Certain Beneficial Owners, Directors,
and Executive Officers of the 2017 Proxy Statement, which information is incorporated herein by reference.
(c) Changes in Control.
None.
(d) Securities Authorized for Issuance under Equity Compensation Plans.
The following table provides information about shares of AES common stock that may be issued under AES'
equity compensation plans, as of December 31, 2016:
Securities Authorized for Issuance under Equity Compensation Plans (As of December 31, 2016)
Plan category
Equity compensation plans approved by security holders (1)
Equity compensation plans not approved by security holders
Total
_____________________________
(a)
Number of securities
to be issued upon exercise
of outstanding options,
warrants and rights
(b)
Weighted average
exercise price of
outstanding options,
warrants and rights
(c)
Number of securities remaining available for
future issuance under
equity compensation plans (excluding
securities reflected in column (a))
12,630,620 (2) $
$
$
—
12,630,620
13.43
—
—
15,918,834
—
15,918,834
(1) The following equity compensation plans have been approved by the Company's Stockholders:
(A)
The AES Corporation 2003 Long Term Compensation Plan was adopted in 2003 and provided for 17,000,000 shares authorized for
issuance thereunder. In 2008, an amendment to the Plan to provide an additional 12,000,000 shares was approved by AES'
stockholders, bringing the total authorized shares to 29,000,000. In 2010, an additional amendment to the Plan to provide an
additional 9,000,000 shares was approved by AES' stockholders, bringing the total authorized shares to 38,000,000. In 2015, an
additional amendment to the Plan to provide an additional 7,750,000 shares was approved by AES' stockholders, bringing the total
188
(B)
(C)
authorized shares to 45,750,000. The weighted average exercise price of Options outstanding under this plan included in Column
(b) is $13.42 (excluding performance stock units, restricted stock units and director stock units), with 15,915,834 shares available
for future issuance).
The AES Corporation 2001 Plan for outside directors adopted in 2001 provided for 2,750,000 shares authorized for issuance. The
weighted average exercise price of Options outstanding under this plan included in Column (b) is $21.44. In conjunction with the
2010 amendment to the 2003 Long Term Compensation plan, ongoing award issuance from this plan was discontinued in 2010. Any
remaining shares under this plan, which are not reserved for issuance under outstanding awards, are not available for future
issuance and thus the amount of 2,078,579 shares is not included in Column (c) above.
The AES Corporation Second Amended and Restated Deferred Compensation Plan for directors provided for 2,000,000 shares
authorized for issuance. Column (b) excludes the Director stock units granted thereunder. In conjunction with the 2010 amendment
to the 2003 Long Term Compensation Plan, ongoing award issuance from this plan was discontinued in 2010 as Director stock units
will be issued from the 2003 Long Term Compensation Plan. Any remaining shares under this plan, which are not reserved for
issuance under outstanding awards, are not available for future issuance and thus the amount of 105,341 shares is not included in
Column (c) above.
(2)
Includes 4,745,968 (of which 427,520 are vested and 4,318,488 are unvested) shares underlying PSU and RSU awards (assuming
performance at a maximum level), 1,556,575 shares underlying Director stock unit awards, and 6,328,077 shares issuable upon the
exercise of Stock Option grants, for an aggregate number of 12,630,620 shares.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
The information regarding related party transactions required by this item is included in the 2017 Proxy
Statement found under the headings Transactions with Related Persons, Proposal I: Election of Directors and
Board Committees and are incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information concerning principal accountant fees and services included in the 2017 Proxy Statement
contained under the heading Information Regarding The Independent Registered Public Accounting Firm's Fees,
Services and Independence and is incorporated herein by reference.
189
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Financial Statements.
PART IV
Financial Statements and Schedules:
Consolidated Balance Sheets as of December 31, 2016 and 2015
Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014
Consolidated Statements of Comprehensive Income for the years ended December 31, 2016, 2015 and 2014
Consolidated Statements of Changes in Equity for the years ended December 31, 2016, 2015 and 2014
Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014
Notes to Consolidated Financial Statements
Schedules
(b) Exhibits.
Page
126
127
128
129
130
131
S-2-S-7
3.1
3.2
4
4.(a)
4.(b)
4.(c)
4.(d)
4.(e)
4.(f)
4.(g)
4.(h)
4.(i)
4.(j)
4.(k)
4.(l)
4.(m)
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.7A
10.8
10.9
Sixth Restated Certificate of Incorporation of The AES Corporation is incorporated herein by reference to Exhibit 3.1 of the
Company's Form 10-K for the year ended December 31, 2008.
By-Laws of The AES Corporation, as amended and incorporated herein by reference to Exhibit 3.1 of the Company's Form 8-K/A
filed on December 2, 2015.
There are numerous instruments defining the rights of holders of long-term indebtedness of the Registrant and its consolidated
subsidiaries, none of which exceeds ten percent of the total assets of the Registrant and its subsidiaries on a consolidated basis.
The Registrant hereby agrees to furnish a copy of any of such agreements to the Commission upon request. Since these
documents are not required filings under Item 601 of Regulation S-K, the Company has elected to file certain of these documents
as Exhibits 4.(a)—4.(r).
Junior Subordinated Indenture, dated as of March 1, 1997, between The AES Corporation and Wells Fargo Bank, National
Association, as successor to Bank One, National Association (formerly known as The First National Bank of Chicago) is
incorporated herein by reference to Exhibit 4.(a) of the Company's Form 10-K for the year ended December 31, 2008.
Third Supplemental Indenture, dated as of October 14, 1999, between The AES Corporation and Wells Fargo Bank, National
Association, as successor to Bank One, National Association is incorporated herein by reference to Exhibit 4.(b) of the Company's
Form 10-K for the year ended December 31, 2008.
Senior Indenture, dated as of December 8, 1998, between The AES Corporation and Wells Fargo Bank, National Association, as
successor to Bank One, National Association (formerly known as The First National Bank of Chicago) is incorporated herein by
reference to Exhibit 4.01 of the Company's Form 8-K filed on December 11, 1998 (SEC File No. 001-12291).
Ninth Supplemental Indenture, dated as of April 3, 2003, between The AES Corporation and Wells Fargo Bank, National
Association (as successor by consolidation to Wells Fargo Bank Minnesota, National Association) is incorporated herein by
reference to Exhibit 4.6 of the Company's Form S-4 filed on December 7, 2007.
Twelfth Supplemental Indenture, dated as of October 15, 2007, between The AES Corporation and Wells Fargo Bank, National
Association is incorporated herein by reference to Exhibit 4.8 of the Company's Form S-4 filed on December 7, 2007.
Thirteenth Supplemental Indenture, dated as of May 19, 2008, between The AES Corporation and Wells Fargo Bank, National
Association is incorporated herein by reference to Exhibit 4.(l) of the Company's Form 10-K for the year ended December 31,
2008.
Fifteenth Supplemental Indenture, dated as of June 15, 2011, between The AES Corporation and Wells Fargo Bank, National
Association is incorporated herein by reference to Exhibit 4.3 of the Company's Form 8-K filed on June 15, 2011.
Indenture, dated October 3, 2011, between Dolphin Subsidiary II, Inc. and Wells Fargo Bank, National Association is incorporated
herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on October 5, 2011.
Sixteenth Supplemental Indenture, dated April 30, 2013, between The AES Corporation and Wells Fargo Bank, N.A., as Trustee is
incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on April 30, 2013 (SEC File No. 001-12291).
Seventeenth Supplemental Indenture, dated March 7, 2014, between The AES Corporation and Wells Fargo Bank, N.A. as Trustee
is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on March 7, 2014.
Eighteenth Supplemental Indenture, dated May 20, 2014, between The AES Corporation and Wells Fargo Bank, N.A. as Trustee is
incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on May 20, 2014.
Nineteenth Supplemental Indenture, dated April 6, 2015, between The AES Corporation and Wells Fargo Bank, N.A. as Trustee is
incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on April 6, 2015.
Twentieth Supplemental Indenture, dated May 25, 2016, between The AES Corporation and Wells Fargo Bank, N.A. as Trustee is
incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on May 25, 2016.
The AES Corporation Profit Sharing and Stock Ownership Plan are incorporated herein by reference to Exhibit 4(c)(1) of the
Registration Statement on Form S-8 (Registration No. 33-49262) filed on July 2, 1992.
The AES Corporation Incentive Stock Option Plan of 1991, as amended, is incorporated herein by reference to Exhibit 10.30 of the
Company's Form 10-K for the year ended December 31, 1995 (SEC File No. 00019281).
Applied Energy Services, Inc. Incentive Stock Option Plan of 1982 is incorporated herein by reference to Exhibit 10.31 of the
Registration Statement on Form S-1 (Registration No. 33-40483).
Deferred Compensation Plan for Executive Officers, as amended, is incorporated herein by reference to Exhibit 10.32 of
Amendment No. 1 to the Registration Statement on Form S-1 (Registration No. 33-40483).
Deferred Compensation Plan for Directors, as amended and restated, on February 17, 2012 is incorporated herein by reference to
Exhibit 10.5 of the Company's Form 10-K for the year ended December 31, 2012.
The AES Corporation Stock Option Plan for Outside Directors, as amended and restated, on December 7, 2007 is incorporated
herein by reference to Exhibit 10.6 of the Company's Form 10-K for the year ended December 31, 2012.
The AES Corporation Supplemental Retirement Plan is incorporated herein by reference to Exhibit 10.63 of the Company's
Form 10-K for the year ended December 31, 1994 (SEC File No. 00019281).
Amendment to The AES Corporation Supplemental Retirement Plan, dated March 13, 2008 is incorporated herein by reference to
Exhibit 10.9.A of the Company's Form 10-K for the year ended December 31, 2007.
The AES Corporation 2001 Stock Option Plan is incorporated herein by reference to Exhibit 10.12 of the Company's Form 10-K for
the year ended December 31, 2000 (SEC File No. 001-12291).
Second Amended and Restated Deferred Compensation Plan for Directors is incorporated herein by reference to Exhibit 10.13 of
the Company's Form 10-K for the year ended December 31, 2000 (SEC File No. 001-12291).
190
10.10
10.10A
10.11
10.12
10.13
10.14
10.15
10.16
10.17
10.18
10.18A
10.19
10.19A
10.20
10.21
10.22
10.23
10.24
10.25
10.26
10.27
10.27A
10.27B
10.27C
10.28
10.29
10.30
10.31
The AES Corporation 2001 Non-Officer Stock Option Plan is incorporated herein by reference to Exhibit 10.12 of the Company's
Form 10-K for the year ended December 31, 2002 (SEC File No. 001-12291).
Amendment to the 2001 Stock Option Plan and 2001 Non-Officer Stock Option Plan, dated March 13, 2008 is incorporated herein
by reference to Exhibit 10.12.A of the Company's Form 10-K for the year ended December 31, 2007.
The AES Corporation 2003 Long Term Compensation Plan, as Amended and Restated, dated April 23, 2015, is incorporated
herein by reference to Exhibit 99.1 of the Company's Form 8-K filed on April 23, 2015.
Form of AES Nonqualified Stock Option Award Agreement under The AES Corporation 2003 Long Term Compensation Plan
(Outside Directors) is incorporated herein by reference to Exhibit 10.2 of the Company's Form 8-K filed on April 27, 2010.
Form of AES Performance Stock Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan is
incorporated herein by reference to Exhibit 10.13 of the Company's Form 10-K for the year ended December 31,2015.
Form of AES Restricted Stock Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan is
incorporated herein by reference to Exhibit 10.14 of the Company's Form 10-K for the year ended December 31, 2015.
Form of AES Performance Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan is incorporated
herein by reference to Exhibit 10.15 of the Company's Form 10-K for the year ended December 31,2015.
Form of AES Nonqualified Stock Option Award Agreement under The AES Corporation 2003 Long Term Compensation Plan is
incorporated herein by reference to Exhibit 10.4 of the Company's Form 10-Q for the quarter ended June 30, 2015.
Form of AES Performance Cash Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan is
incorporated herein by reference to Exhibit 10.17 of the Company's Form 10-K for the year ended December 31, 2015.
The AES Corporation Restoration Supplemental Retirement Plan, as amended and restated, dated December 29, 2008 is
incorporated herein by reference to Exhibit 10.15 of the Company's Form 10-K for the year ended December 31, 2008.
Amendment to The AES Corporation Restoration Supplemental Retirement Plan, dated December 9, 2011 is incorporated herein
by reference to Exhibit 10.17A of the Company's Form 10-K for the year ended December 31, 2012.
The AES Corporation International Retirement Plan, as amended and restated on December 29, 2008 is incorporated herein by
reference to Exhibit 10.16 of the Company's Form 10-K for the year ended December 31, 2008.
Amendment to The AES Corporation International Retirement Plan, dated December 9, 2011 is incorporated herein by reference to
Exhibit 10.18A of the Company's Form 10-K for the year ended December 31, 2012.
The AES Corporation Severance Plan, as amended and restated on April 23, 2015 is incorporated herein by reference to Exhibit
10.6 of the Company's Form 10-Q for the quarter ended June 30, 2015.
The AES Corporation Amended and Restated Executive Severance Plan dated April 23, 2015 is incorporated herein by reference
to Exhibit 10.5 of the Company's Form 10-Q for the period ended June 30, 2015.
The AES Corporation Performance Incentive Plan, as Amended and Restated on April 23, 2015 is incorporated herein by reference
to Exhibit 99.2 of the Company's Form 8-K filed on April 23, 2015.
The AES Corporation Deferred Compensation Program For Directors dated February 17, 2012 is incorporated herein by reference
to Exhibit 10.22 of the Company's Form 10-K filed on December 31, 2011.
The AES Corporation Employment Agreement with Andrés Gluski is incorporated herein by reference to Exhibit 99.3 of the
Company's Form 8-K filed on December 31, 2008.
Mutual Agreement, between Andrés Gluski and The AES Corporation dated October 7, 2011 is incorporated herein by reference to
Exhibit 10.2 of the Company's Form 10-Q for the period ended September 30, 2011.
Form of Retroactive Consent to Provide for Double-Trigger IN Change-In-Control Transactions is incorporated herein by reference
to Exhibit 10.7 of the Company's Form 10-Q for the period ended June 30, 2015.
Amendment No. 3, dated as of July 26, 2013 to the Fifth Amended and Restated Credit and Reimbursement Agreement, dated as
of July 29, 2010 is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on July 29, 2013.
Sixth Amended and Restated Credit and Reimbursement Agreement dated as of July 26, 2013 among The AES Corporation, a
Delaware corporation, the Banks listed on the signature pages thereof, Citibank, N.A., as Administrative Agent and Collateral
Agent, Citigroup Global Markets Inc., as Lead Arranger and Book Runner, Banc of America Securities LLC, as Lead Arranger and
Book Runner and Co-Syndication Agent, Barclays Capital, as Lead Arranger and Book Runner and Co-Syndication Agent, RBS
Securities Inc., as Lead Arranger and Book Runner and Co-Syndication Agent and Union Bank, N.A., as Lead Arranger and Book
Runner and Co-Syndication Agent is incorporated herein by reference to Exhibit 10.1.A of the Company's Form 8-K filed on July
29, 2013.
Appendices and Exhibits to the Sixth Amended and Restated Credit and Reimbursement Agreement, dated as of July 29, 2013 is
incorporated herein by reference to Exhibit 10.1.B of the Company's Form 8-K filed on July 29, 2013.
Amendment No. 1, dated as of May 6, 2016 to the Sixth Amended and Restated Credit and Reimbursement Agreement, dated as
of July 23, 2013 among The AES Corporation, a Delaware corporation, the Banks listed on the signature pages thereof and
Citibank, N.A. as Administrate Agent and Collateral Agent is incorporated herein by reference to Exhibit 10.1 of the Company's
Form 8-K filed on May 9, 2016.
Collateral Trust Agreement dated as of December 12, 2002 among The AES Corporation, AES International Holdings II, Ltd.,
Wilmington Trust Company, as corporate trustee and Bruce L. Bisson, an individual trustee is incorporated herein by reference to
Exhibit 4.2 of the Company's Form 8-K filed on December 17, 2002 (SEC File No. 001-12291).
Security Agreement dated as of December 12, 2002 made by The AES Corporation to Wilmington Trust Company, as corporate
trustee and Bruce L. Bisson, as individual trustee is incorporated herein by reference to Exhibit 4.3 of the Company's Form 8-K
filed on December 17, 2002 (SEC File No. 001-12291).
Charge Over Shares dated as of December 12, 2002 between AES International Holdings II, Ltd. and Wilmington Trust Company,
as corporate trustee and Bruce L. Bisson, as individual trustee is incorporated herein by reference to Exhibit 4.4 of the Company's
Form 8-K filed on December 17, 2002 (SEC File No. 001-12291).
Agreement and Plan of Merger, dated as of February 19, 2017, by and among AES Lumos Holdings, LLC, PIP5 Lumos LLC, AES
Lumos Merger Sub, LLC, PIP5 Lumos MS LLC, FTP Power LLC and Fir Tree Solar LLC (filed herewith).
Statement of computation of ratio of earnings to fixed charges (filed herewith).
Subsidiaries of The AES Corporation (filed herewith).
Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP (filed herewith).
Powers of Attorney (filed herewith).
Rule 13a-14(a)/15d-14(a) Certification of Andrés Gluski (filed herewith).
Rule 13a-14(a)/15d-14(a) Certification of Thomas M. O'Flynn (filed herewith).
Section 1350 Certification of Andrés Gluski (filed herewith).
Section 1350 Certification of Thomas M. O'Flynn (filed herewith).
XBRL Instance Document (filed herewith).
12
21.1
23.1
24
31.1
31.2
32.1
32.2
101.INS
101.SCH XBRL Taxonomy Extension Schema Document (filed herewith).
191
101.CAL
101.DEF
101.LAB
101.PRE
XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith).
XBRL Taxonomy Extension Definition Linkbase Document (filed herewith).
XBRL Taxonomy Extension Label Linkbase Document (filed herewith).
XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith).
(c) Schedules
Schedule I—Financial Information of Registrant
Schedule II—Valuation and Qualifying Accounts
192
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the
Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
Date: February 24, 2017
THE AES CORPORATION
(Company)
By:
Name:
/s/ ANDRÉS GLUSKI
Andrés Gluski
President, Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been
signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated.
Name
*
Andrés Gluski
President, Chief Executive Officer (Principal Executive Officer)
and Director
Title
Date
*
Director
Charles L. Harrington
*
Kristina M. Johnson
Director
*
Director
Tarun Khanna
*
Director
Holly K. Koeppel
*
Director
Philip Lader
*
Director
James H. Miller
*
Director
John B. Morse
*
Director
Moises Naim
*
Chairman of the Board and Lead Independent Director
Charles O. Rossotti
/s/ THOMAS M. O'FLYNN Executive Vice President and Chief Financial Officer (Principal
Thomas M. O'Flynn
Financial Officer)
/s/ FABIAN E. SOUZA
Vice President and Controller (Principal Accounting Officer)
Fabian E. Souza
*By:
/s/ BRIAN A. MILLER
Attorney-in-fact
193
February 24, 2017
February 24, 2017
February 24, 2017
February 24, 2017
February 24, 2017
February 24, 2017
February 24, 2017
February 24, 2017
February 24, 2017
February 24, 2017
February 24, 2017
February 24, 2017
February 24, 2017
THE AES CORPORATION AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule I—Condensed Financial Information of Registrant
Schedule II—Valuation and Qualifying Accounts
S-2
S-7
Schedules other than those listed above are omitted as the information is either not applicable, not required,
or has been furnished in the financial statements or notes thereto included in Item 8 hereof.
See Notes to Schedule I
S-1
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
BALANCE SHEETS
ASSETS
Current Assets:
Cash and cash equivalents
Restricted cash
Accounts and notes receivable from subsidiaries
Prepaid expenses and other current assets
Total current assets
Investment in and advances to subsidiaries and affiliates
Office Equipment:
Cost
Accumulated depreciation
Office equipment, net
Other Assets:
Other intangible assets, net of accumulated amortization
Deferred financing costs, net of accumulated amortization of $1
Deferred income taxes
Other assets
Total other assets
Total
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable
Accounts and notes payable to subsidiaries
Accrued and other liabilities
Total current liabilities
Long-term Liabilities:
Senior notes payable
Junior subordinated notes and debentures payable
Accounts and notes payable to subsidiaries
Other long-term liabilities
Total long-term liabilities
Stockholders' equity:
Common stock
Additional paid-in capital
Retained earnings (accumulated deficit)
Accumulated other comprehensive loss
Treasury stock
Total stockholders' equity
Total
December 31,
2016
2015
(in millions)
$
$
$
$
109
3
155
39
306
7,561
26
(16)
10
5
5
1,041
13
1,064
8,941
18
304
250
572
4,154
517
883
21
5,575
8
8,592
(1,146)
(2,756)
(1,904)
2,794
8,941
$
$
$
$
186
32
264
26
508
7,764
27
(15)
12
11
—
1,028
1
1,040
9,324
16
97
204
317
4,449
517
873
19
5,858
8
8,718
143
(3,883)
(1,837)
3,149
9,324
See Notes to Schedule I.
S-2
2015
(in millions)
24
$
859
24
(154)
24
(6)
(105)
(364)
302
4
306
14
(615)
19
(144)
7
(65)
(14)
(344)
(1,142)
12
(1,130) $
2014
29
1,313
59
(161)
8
(30)
(193)
(422)
603
166
769
$
$
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF OPERATIONS
For the Years Ended December 31,
2016
Revenue from subsidiaries and affiliates
Equity in earnings of subsidiaries and affiliates
Interest income
General and administrative expenses
Other income
Other expense
Loss on extinguishment of debt
Interest expense
Income (loss) before income taxes
Income tax benefit
Net income (loss)
$
$
See Notes to Schedule I.
S-3
2015
(in millions)
306
2014
$
769
$ (1,130) $
117
992
1,109
2
28
30
9
(22)
1
(12)
1,127
$
(3) $
(674)
—
(674)
(5)
48
43
1
18
2
21
(610)
(304) $
(366)
34
(332)
(180)
72
(108)
(1)
(13)
10
(4)
(444)
325
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014
2016
NET INCOME (LOSS)
Foreign currency translation activity:
Foreign currency translation adjustments, net of income tax benefit (expense) of $1, $1 and $(7),
respectively
Reclassification to earnings, net of $0 income tax for all periods
Total foreign currency translation adjustments, net of tax
Derivative activity:
Change in derivative fair value, net of income tax benefit (expense) of $(5), $4 and $51, respectively
Reclassification to earnings, net of income tax benefit (expense) of $1, $(12) and $(37), respectively
Total change in fair value of derivatives, net of tax
Pension activity:
Prior service cost for the period, net of income tax expense of $5, $0 and $0, respectively
Change in pension adjustments due to net actuarial gain (loss) for the period, net of income tax
benefit (expense) of $10, $(7) and $9, respectively
Reclassification of earnings due to amortization of net actuarial loss, net of income tax benefit
(expense) of $2, $(2) and $0, respectively
Total change in unfunded pension obligation
OTHER COMPREHENSIVE INCOME (LOSS)
COMPREHENSIVE INCOME (LOSS)
See Notes to Schedule I.
S-4
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF CASH FLOWS
For the Years Ended December 31,
Net cash provided by operating activities
Investing Activities:
Expenses related to asset sales
Investment in and net advances to subsidiaries
Return of capital
Decrease in restricted cash
Additions to property, plant and equipment
Purchase of short term investments, net
Net cash provided by (used in) investing activities
Financing Activities:
Borrowings of notes payable and other coupon bearing securities
Repayments of notes payable and other coupon bearing securities
Loans from subsidiaries
Purchase of treasury stock
Proceeds from issuance of common stock
Common stock dividends paid
Payments for deferred financing costs
Distributions to noncontrolling interests
Other financing
Net cash used in financing activities
Effect of exchange rate changes on cash
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents, beginning
Cash and cash equivalents, ending
Supplemental Disclosures:
Cash payments for interest, net of amounts capitalized
Cash payments for income taxes, net of refunds
2016
2015
(in millions)
2014
$
818
$
475
$
—
(650)
247
29
(12)
—
(386)
500
(808)
183
(79)
1
(290)
(12)
(2)
(3)
(510)
1
(77)
186
109
296
6
$
$
$
—
(221)
501
49
(11)
—
318
575
(915)
—
(482)
4
(276)
(6)
—
(18)
(1,118)
—
(325)
511
186
$
314
$
— $
$
$
$
449
(4)
(69)
740
96
(31)
(1)
731
1,525
(2,117)
263
(308)
1
(144)
(20)
—
—
(800)
—
380
131
511
373
(2)
See Notes to Schedule I.
S-5
THE AES CORPORATION
SCHEDULE I
NOTES TO SCHEDULE I
1. Application of Significant Accounting Principles
The Schedule I Condensed Financial Information of the Parent includes the accounts of The AES Corporation
(the “Parent Company”) and certain holding companies.
Accounting for Subsidiaries and Affiliates—The Parent Company has accounted for the earnings of its
subsidiaries on the equity method in the financial information.
Income Taxes—Positions taken on the Parent Company's income tax return which satisfy a more-likely-than-
not threshold will be recognized in the financial statements. The income tax expense or benefit computed for the
Parent Company reflects the tax assets and liabilities on a stand-alone basis and the effect of filing a consolidated
U.S. income tax return with certain other affiliated companies.
Accounts and Notes Receivable from Subsidiaries—Amounts have been shown in current or long-term
assets based on terms in agreements with subsidiaries, but payment is dependent upon meeting conditions
precedent in the subsidiary loan agreements.
2. Debt
Senior Notes and Loans Payable ($ in millions)
Senior Unsecured Note
Senior Unsecured Note
Senior Unsecured Note
Senior Unsecured Note
Senior Unsecured Note
Senior Unsecured Note
Senior Unsecured Note
Senior Unsecured Note
Unamortized (discounts)/premiums & debt issuance (costs)
SUBTOTAL
Less: Current maturities
Total
Junior Subordinated Notes Payable ($ in millions)
Interest Rate
8.00%
LIBOR + 3.00%
8.00%
7.38%
4.88%
5.50%
5.50%
6.00%
Maturity
2017
2019
2020
2021
2023
2024
2025
2026
Term Convertible Trust Securities
Interest Rate
6.75%
Maturity
2029
December 31,
2016
2015
— $
240
469
966
713
738
573
500
(45)
4,154
—
4,154
$
$
181
775
469
1,000
750
750
575
—
(51)
4,449
—
4,449
December 31,
2016
2015
517
$
517
$
$
$
$
Future Maturities of Recourse Debt — As of December 31, 2016 scheduled maturities are presented in the
following table (in millions):
December 31,
2017
2018
2019
2020
2021
Thereafter
Unamortized (discount)/premium & debt issuance (costs)
Total debt
3. Dividends from Subsidiaries and Affiliates
Annual Maturities
$
$
—
—
240
469
966
3,041
(45)
4,671
Cash dividends received from consolidated subsidiaries were $1 billion, $748 million, and $880 million for the
years ended December 31, 2016, 2015, and 2014, respectively. There were no cash dividends received from
affiliates accounted for by the equity method for the years ended December 31, 2016, 2015, and 2014.
4. Guarantees and Letters of Credit
GUARANTEES — In connection with certain of its project financing, acquisition, and power purchase
agreements, the Company has expressly undertaken limited obligations and commitments, most of which will only
be effective or will be terminated upon the occurrence of future events. These obligations and commitments,
excluding those collateralized by letter of credit and other obligations discussed below, were limited as of
December 31, 2016, by the terms of the agreements, to an aggregate of approximately $535 million representing 19
S-6
agreements with individual exposures ranging from $8 million up to $58 million. These amounts exclude normal and
customary representations and warranties in agreements for the sale of assets (including ownership in associated
legal entities) where the associated risk is considered to be nominal.
LETTERS OF CREDIT — At December 31, 2016, the Company had $6 million in letters of credit outstanding
under the senior secured credit facility, representing 15 agreements with individual exposures up to $1 million, and
$245 million in letters of credit outstanding under the senior unsecured credit facility, representing 8 agreements
with individual exposures of $2 million up to $73 million, and $3 million in cash collateralized letters of credit
outstanding representing 1 agreement with exposure of $3 million, which operate to guarantee performance relating
to certain project development and construction activities and subsidiary operations. During 2016, the Company
paid letter of credit fees ranging from 0.2% to 2.5% per annum on the outstanding amounts.
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
(in millions)
Balance at
Beginning of the Period
Charged to Cost
and Expense
Amounts
Written off
Translation
Adjustment
Balance at End of
the Period
Allowance for accounts receivables
(current and noncurrent)
Year Ended December 31, 2014
Year Ended December 31, 2015
Year Ended December 31, 2016
$
$
114
89
87
$
60
80
37
(75) $
(56)
(27)
(10) $
(26)
14
89
87
111
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AES EXECUTIVE LEADERSHIP TEAMAndrés GluskiPresident & Chief Executive OfficerMichael ChiltonSenior Vice President of Global Engineering & ConstructionBernerd Da SantosSenior Vice President and Chief Operating OfficerElizabeth HackensonSenior Vice President of Technology & Services and Chief Information OfficerTish Mendoza Senior Vice President of Global Human Resources & Internal Communications and Chief Human Resources OfficerBrian MillerExecutive Vice President, General Counsel & Corporate Secretary Thomas O’FlynnExecutive Vice President and Chief Financial OfficerAES BOARD OF DIRECTORS Charles Rossotti (Chairman)Senior Advisor, The Carlyle Group; former Commissioner, the IRS; former Founder and Chairman, American Management Systems, Inc.Andrés GluskiPresident and Chief Executive Officer, The AES CorporationCharles Harrington Chairman and CEO of Parsons CorporationKristina JohnsonCEO of Cube Hydro Partners; former Undersecretary for Energy at the Department of Energy; former Provost and Senior Vice President for Academic Affairs at the Johns Hopkins UniversityTarun KhannaJorge Paulo Lemann Professor at the Harvard Business SchoolHolly K. KoeppelManaging Partner and Co-Head of Corsair Infrastructure Management, L.P.Philip LaderFormer Chairman, WPP Group plc; Senior Advisor, Morgan Stanley; former U.S. Ambassador to the Court of St. James’sJames MillerFormer Chairman of PPL Corporation; former Executive Vice President of USEC Inc.; President for two ABB Group subsidiariesJohn MorseRetired Senior Vice President Finance and CFO Washington Post Company; former Partner Price Waterhouse (now PricewaterhouseCoopers); former Trustee and President Emeritus of the College Foundation of The University of VirginiaMoisés NaímDistinguished Fellow in the International Economics Program at the Carnegie Endowment for International Peace and international columnist and broadcaster; Former Editor in Chief for Foreign Policy magazine; Former Minister of Industry and Trade and the Central Bank for Venezuela; former Executive Director for the World BankCOMPANY INFORMATIONCorporate OfficeThe AES Corporation 4300 Wilson Boulevard Arlington, VA 22203 USA 703-522-1315Websitewww.aes.com @TheAESCorpStock InformationCommon stock of The AES Corporation trades under the symbol AES. The AES Corporation is proud to meet the listing requirements of the NYSE, the world’s leading equities market.Number of ShareholdersAs of December 31, 2016 there were approximately 4,384 AES shareholders of record and 659,182,232 shares of AES common stock outstanding. Transfer AgentThe AES Corporation has designated Computershare Investor Services (“Computershare”) to be its transfer agent for AES common stock.Please contact Computershare if you need assistance with lost or stolen AES stock certificates directly held by you, issues related to dividend checks, address changes, name changes and stock transfers.By mail: Computershare P.O. Box 30170 College Station, TX 77842-3170 Overnight: Computershare 211 Quality Circle, Suite 210 College Station, TX 77845 877-373-6374 www.computershare.comIndependent Auditors Ernst & Young LLPInvestors Please visit the Investors section of the AES website at www.aes.com, or you may contact a member of the AES Investor Relations team: General: invest@aes.com Ahmed Pasha, Vice President, Investor Relations: 703-682-6451Media InquiriesGeneral: mediainquiries@aes.com Amy Ackerman, Manager, External Communications: 703-682-6399AES Code of ConductAES is committed to demonstrating the highest standards of business ethics in all that we do. To that end, AES has adopted a Code of Conduct, which is available at our website.Note: Contains forward looking statements. Please see “Forward looking information” in AES’ 2016 Annual Report on Form 10-K.1 A non-GAAP financial measure. See Financial Notes on Page 7 for definition and reconciliation to the nearest GAAP number.80% 40%34%22%4%Capacity by Fuel TypeGW Capacity37of adjusted pre-tax contribution (ptc)¹ comes from 9 countries in the AmericasCoalGasRenewablesOil, Diesel, Pet CokeWe are the EnergyGWH Delivered in 201671Utilities79Million Distribution Customers A
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The AES Corporation
4300 Wilson Boulevard
Arlington, VA 22203
USA
703-522-1315
www.aes.com
2016
Annual Report