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The AES Corporation
4300 Wilson Boulevard
Arlington, VA 22203, USA
www.aes.com
703.522.1315
2018 Annual report cover_front and back_spine.275.indd 1
2018 ANNUAL
REPORT
About AES
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 15 countries. Our workforce of 9,000 people is
committed to operational excellence and meeting the world’s changing power needs.
ADJUSTED PTC1 BY SBU
Eurasia
$222M
US & Utilities
$511M
MCAC2
$300M
South America
$519M
32 GW
26,020 GWh
OF CAPACITY
DELIVERED IN 2018
6 UTILITIES
2.4 MILLION
DISTRIBUTION CUSTOMERS
1 A non-GAAP financial measure. See Financial Notes on page 8 for definition and reconciliation to the nearest GAAP number.
2 Mexico, Cnetral America and the Caribbean.
AES VALUES
SAFETY
INTEGRITY
AGILITY
FUN
EXCELLENCE
2
2018 ANNUAL REPORT
32018 ANNUAL REPORTStrategic OverviewREDUCING CARBON INTENSITY BY 50% BY 2022 AND 70% BY 2030STRONG BACKLOG DRIVES FUTURE GROWTHDELIVERING ON OUR COMMITMENTS2018Adjusted EPS1 of $1.24Guidance of$1.15-$1.25vs.2018Parent Free Cash3 Flow of$689Mexpectation of $600-$675Mvs.Achieved a key investment grade metric in 2018 and expect to attain ratings in 2020PARENT LEVERAGE RATIOS: 3.95x as of Dec. 31, 20184.9x as of Sep. 30, 2016vs.Carbon Intensity (Tons of CO2/MWh of Generation)3 Parent Free Cash Flow (a non-GAAP financial measure) should not be construed as an alternate to Net Cash Provided by Operating Activities which is determined in accordance with GAAP. Parent Free Cash Flow is equal to Subsidiary Distribution less cash used for interest costs, general and administrative activities, and tax payments by the parent company. Parent Free Cash Flow is used for dividends, share repurchases, growth investments, recourse debt repayments, and other uses by the parent company.2,722Backlog COD of Projected PPAs (2019-2022)2019 2020 2021 2022 2023-2024 TOTAL2019-2022: 12.0 GW of New Capacity2,6551,2503,9052,5002,6002,5002,7702,5003,75010,00015,7475,747Backlog = Under Construction + Signed PPAs Not Yet Under Construction
Chairman and CEO Letter to AES Shareholders2018 was a very good year for AES, demonstrated by our strong financial results and excellent progress toward achieving our strategic goals. 2018 was also a significant year in our overall transformation, which positions us well to continue to accomplish our mission to improve lives, while at the same time deliver attractive returns to our shareholders.42018 ANNUAL REPORT Delivering on Our CommitmentsIn 2018, we delivered on all of our commitments, including achieving our financial guidance, hitting key milestones on our strategy and positioning AES for long-term, sustainable growth. Some key accomplishments this year included: Adjusted EPS of $1.24, compared to guidance of $1.15 to $1.25; Parent Free Cash Flow of $689 million, compared to our expectation of $600 to $675 million; Total Shareholder Return (TSR) of 39%, outperforming the S&P 500 and S&P Utilities Indexes; Signed long-term Power Purchase Agreements (PPA) for approximately 2 GW of renewable capacity, increasing our backlog to almost 6 GW; Completed construction of 1.3 GW across our portfolio; Paid down $1 billion in Parent debt, enabling us to achieve a key investment grade financial metric of 3.95x Parent leverage one year early; and Expanded our world-leading battery-based energy storage business, including the launch of our joint venture with Siemens, Fluence, which was awarded 286 MW of new projects.Strong Backlog Drives Future GrowthOur strong backlog of 5,787 MW includes both our conventional and renewable capacity under construction, as well as our renewables under signed PPAs that are not yet under construction. During the year, we completed construction of an additional 1,278 MW, including several transformative projects. At our utility, Indianapolis Power and Light (IPL) in Indiana, we completed the 671 MW Eagle Valley combined cycle gas plant. The completion of Eagle Valley also represents the conclusion of a significant investment program at IPL, wherein we have replaced nearly half of IPL’s coal-fired generation with cleaner and more efficient natural gas.In Panama, we completed the 381 MW AES Colón combined cycle gas plant and regasification terminal, and made the first shipment of LNG in Central America’s history. The LNG storage tank is expected to come on-line in the middle of 2019, with approximately 60% of the terminal’s capacity still available to be contracted. We expect that the entry of low-cost U.S. LNG will transform the Central American energy sector, much as it has in the Dominican Republic.We believe the integration of renewables and energy storage is the key to accelerating a cleaner energy future. In Hawaii, we are delivering two solar plus storage facilities for a total of 34 MW of solar capacity and 170 MWh of five-hour energy storage on the island of Kaua’i. The first of these pioneering projects, Lāwa’i was completed in December 2018 and will satisfy energy demand during peak hours in the evening, as well as the rest of the day. The second, Kekaha, is under construction and expected to be on-line later in 2019. We have 4,440 MW of capacity under construction and expected to come on-line through 2021. Our primary projects under construction include: the 1,320 MW OPGC 2 project in India, the 1,384 MW Southland repowering in Southern California and the 531 MW Alto Maipo project in Chile. In 2018 we signed 1,946 MW of renewables under long-term PPAs and expect to sign an additional 2,000 to 3,000 MW per year through 2022. This capacity should be split equally between the U.S. and internationally, and similarly between solar and wind. In the U.S., the majority of our expected growth will come from our sPower and AES Distributed Energy (AES DE) businesses. We are also focusing on our “Green Blend and Extend” strategy, where we are enhancing some of our current contracts by blending and extending existing PPAs, by adding renewable energy. We see potential opportunities to execute this strategy across many of our markets, including Chile and Mexico. In fact, in 2018 we signed our first two “Green Blend and Extend” contracts, for 576 MW in Chile and Mexico. In the near-term, we see an addressable Figure 1. 2018 Total Shareholder ReturnAESS&P 500S&P Utility38.99%-4.39%4.11%Figure 2. 2016-2018 Adjusted EPS1 by year 201620172019$0.98$1.08$1.2452018 ANNUAL REPORT1 A non-GAAP financial measure. See Financial Notes on page 8 for definition and reconciliation to the nearest GAAP number
universe of 7 GW across our portfolio, which could substantially increase as our markets capitalize on the economic benefit of renewables. Our total backlog of 5,787 MW will be a key contributor for our expected earnings and cash flow growth of 7% to 9% per year through 2022.Reducing Carbon Intensity by 50% by 2022 and 70% by 2030We recently announced that based on our renewable growth plans, we expect to reduce our carbon intensity (tons of CO2/MWh of generation) by 70% from 2016 to 2030. This is an improvement from our prior goal of 50% over the same period. Furthermore, we also announced a near-term target of reducing our carbon intensity by 50% from 2016 to 2022, compared to our prior goal of 25% over the same period.In November 2018, we published the AES Climate Scenario Report, which includes an impact analysis of a 2° Celsius scenario on our strategy and business, fulfilling our April 2018 commitment to adopt the recommendations of the Task Force on Climate-related Financial Disclosures (TCFD). AES was the first publicly-traded owner of utilities and power companies based in the U.S. to disclose its portfolio’s resilience consistent with the TCFD recommendations and third-party scenarios. The report shows that AES’ portfolio is resilient against the assessed climate risks and demonstrates the significant upside for AES in a lower carbon future. In 2018, AES was named to the Dow Jones Sustainability Index (DJSI) for North America for the fifth year in a row by RobecoSAM. We were also named by Ethisphere as one of the World’s Most Ethical Companies for the fifth year in a row. These recognitions validate the degree to which every member of the AES team lives by our values.AES Values SAFETY: We will always put safety first–for our people, contractors and communities. INTEGRITY: We are honest, trustworthy and dependable. Integrity is at the core of all we do–how we conduct ourselves and interact with all of our stakeholders. AGILITY: We move with vision, speed and flexibility to adapt to our dynamic and rapidly changing world. FUN: We work because work can be fun, fulfilling and exciting. EXCELLENCE: We strive to be the best in all that we do and to perform at world-class levels.Investing in Innovative Technologies for Additional UpsideWe continue to invest in innovative technologies, such as battery-based energy storage, drone applications and digital customer interfaces. These initiatives have already allowed us to reduce O&M costs, improve customer experiences and deliver new solutions to the market. In January 2018, we formed Fluence, our energy storage joint venture with Siemens. During the year, Fluence delivered or was awarded 80 projects in 17 countries, with a total capacity of 766 MW. Notably, Fluence was also named the #1 utility energy storage integrator by Navigant. We are also implementing a corporate-wide digital transformation, including becoming a strategic investor in Simple Energy. 62018 ANNUAL REPORT1 | © 2018 The AES CorporationAES CLIMATE SCENARIO REPORTAES_Draft_57.indd 112/4/18 4:27 PM Simple Energy provides a digital platform that allows our IPL and DPL utilities to accelerate energy efficiency and demand response programs, while improving customer experience. Although not in our guidance, we expect our new digital initiatives to materially benefit both our top and bottom lines. Achieved a Key Investment Grade Financial Metric and Expect to Attain Ratings in 2020In the third quarter of 2016, we established a goal of reaching investment grade. At that time, we had $5 billion in Parent debt and a Parent Debt/EBITDA coverage ratio of 4.9x. Since then, we have reduced debt by $1.3 billion and ended this year with a Parent leverage ratio of 3.95x, achieving our goal a year ahead of our plan. We are now very well-positioned to attain investment grade ratings in 2020.Offering Double-Digit Total Return Annually Through 2022We continued to improve the returns from our existing portfolio and position AES for long-term, sustainable growth. We will achieve this objective as we continue to optimize our costs, strengthen our Balance Sheet, reduce our carbon intensity and deploy new technologies in our existing markets. Combining our current dividend yield of 3.2%, and our 7% to 9% average annual growth in Adjusted EPS and Parent Free Cash Flow, will yield a double-digit total return annually through 2022. Thank you for your continued support. 72018 ANNUAL REPORTFitch Moody’s S&P BB- Ba3 BB BB+ Ba1 BB+2016New2018Figure 3. Achieved a key Investment Grade Metric and Expect to Attain Ratings in 2020Andrés GluskiPresident and Chief Executive Officer March 1, 2019Jay MorseChairman and Lead Independent DirectorMarch 1, 20192019 EXPECTED2018 2017 2016 2015 20142013 2012 $0.546$0.52 $0.48 $0.44 $0.40$0.20 $0.16 $0.04Figure 4. 2012-2019 Shareholder Dividend by year Jay Morse and Andrés Gluski
Financial Measures: Non-GAAP Financial Measures Reconciliation (Unaudited)
($ in millions, except per share amounts)
Reconciliation of Adjusted Earnings Per Share (1)
Diluted Earnings (Loss) Per Share From Continuing Operations
Effect of anti-dilutive securities
Non-GAAP diluted earnings (loss) per share from continuing operations
Unrealized derivative and equity securities losses (gains)
Unrealized foreign currency losses (gains)
Disposition/acquisition losses (gains)
Impairment expense
Loss on extinguishment of debt
Restructuring costs
U.S. Tax Law Reform Impact
Less: Net income tax expense (benefit)
Adjusted Earnings Per Share (1)
Reconciliation of Adjusted Pre-Tax Contribution (16)
Income (Loss) From Continuing Operations Attributable to AES
Add: Income tax expense (benefit) attributable to AES
Pre-tax contribution
Unrealized derivative and equity securities losses (gains)
Unrealized foreign currency losses (gains)
Disposition/acquisition losses (gains)
Impairment expense
Loss on extinguishment of debt
Restructuring costs
Adjusted Pre-Tax Contribution (16)
Year Ended
December 31
2017
2016
$(0.77)
$(0.04)
0.01
(0.76)
—
(0.10)
0.19(4)
0.82(6)
0.09(9)
0.05
1.08(12)
(0.29)(14)
$1.08
—
(0.04)
(0.01)
0.03
0.01
1.41(7)
0.05(10)
—
—
(0.51)(15)
$ 0.94
$(507)
$(20)
828
321
(3)
(59)
123
542
62
31
(111)
(131)
(9)
22
6
933
29
—
2018
$1.48
—
1.48
0.05
0.09(2)
(1.41)(3)
0.46(5)
0.27(8)
—
0.18(11)
0.12(13)
$1.24
$985
563
1,548
33
51
(934)
307
180
—
$1,185
$1.017
$ 850
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 and equity securities; (b) unrealized foreign
currency gains or losses; (c) gains, losses, benefits and costs associated
with dispositions and acquisitions of business interests, including early
plant closures, and the tax impact from the repatriation of sales proceeds;
(d) losses due to impairments; (e) gains, losses and costs due to the early
retirement of debt; (f) costs directly associated with a major restructuring
program, including, but not limited to, workforce reduction efforts,
relocations and office consolidation; and (g) tax benefit or expense
related to the enactment effects of 2017 U.S. tax law reform and related
regulations and any subsequent period adjustments related to enactment
effects. 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 transactions or equity
securities remeasurement, unrealized foreign currency gains or losses,
losses due to impairments and strategic decisions to dispose of or acquire
business interests, retire debt or implement restructuring initiatives, 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 unrealized FX losses of $22 million, or $0.03
per share, associated with the devaluation of long-term receivables
8
2018 ANNUAL REPORT
15. Amount primarily relates to the income tax benefit associated with asset
impairments of $332 million, or $0.50 per share.
16. We define Adjusted Pre-Tax Contribution (“Adjusted PTC”), a non-GAAP
measure, as pre-tax income from continuing operations attributable to AES
excluding gains or losses of the consolidated entity due to (a) unrealized
gains or losses related to derivative transactions and equity securities; (b)
unrealized foreign currency gains or losses; (c) gains, losses, benefits and
costs associated with dispositions and acquisitions of business interests,
including early plant closures; (d) losses due to impairments; (e) gains,
losses and costs due to the early retirement of debt; and (f) costs directly
associated with a major restructuring program, including, but not limited
to, workforce reduction efforts, relocations and office consolidation.
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. The GAAP measure most comparable to Adjusted PTC is income
from continuing operations attributable to AES. AES believes 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 or equity
securities remeasurement, unrealized foreign currency gains or losses,
losses due to impairments and strategic decisions to dispose of or acquire
business interests, retire debt or implement restructuring initiatives, 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. 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. Adjusted PTC should not
be construed as an alternative to income from continuing operations
attributable to AES, which is determined in accordance with GAAP.
3.
4.
5.
6.
7.
8.
9.
denominated in Argentine pesos, and unrealized FX losses of $14 million,
or $0.02 per share, on intercompany receivables denominated in Euros and
British pounds at the Parent Company.
Amount primarily relates to gain on sale of Masinloc of $772 million, or
$1.16 per share, gain on sale of CTNG of $86 million, or $0.13 per share,
gain on sale of Electrica Santiago of $36 million, or $0.05 per share, gain on
remeasurement of contingent consideration at AES Oahu of $32 million,
or $0.05 per share, gain on sale related to the Company’s contribution of
AES Advancion energy storage to the Fluence joint venture of $23 million,
or $0.03 per share and realized derivative gains associated with the sale of
Eletropaulo of $21 million, or $0.03 per share; partially offset by loss on
disposal of the Beckjord facility and additional shutdown costs related to
Stuart and Killen at DPL of $21 million, or $0.03 per share.
Amount primarily relates to loss on sale of Kazakhstan CHPs of $49 million,
or $0.07 per share, realized derivative losses associated with the sale of Sul
of $38 million, or $0.06 per share, loss on sale of Kazakhstan HPPs of $33
million, or $0.05 per share, and costs associated with early plant closures at
DPL of $24 million, or $0.04 per share; partially offset by gain on Masinloc
contingent consideration of $23 million, or $0.03 per share and gain on sale
of Miami Fort and Zimmer of $13 million, or $0.02 per share.
Amount primarily relates to asset impairments at Shady Point of $157
million, or $0.24 per share, and Nejapa of $37 million, or $0.06 per share,
and other-than-temporary impairment of Guacolda of $96 million, or $0.14
per share.
Amount primarily relates to asset impairments at Kazakhstan CHPs of $94
million, or $0.14 per share, at Kazakhstan HPPs of $92 million, or $0.14 per
share, at Laurel Mountain of $121 million, or $0.18 per share, at DPL of $175
million, or $0.27 per share and at Kilroot of $37 million, or $0.05 per share.
Amount primarily relates to asset impairments at DPL of $859 million, or
$1.30 per share, at Buffalo Gap II of $159 million ($49 million, or $0.07 per
share, net of NCI) and at Buffalo Gap I of $77 million ($23 million, or $0.03
per share, net of NCI).
Amount primarily relates to loss on early retirement of debt at the Parent
Company of $171 million, or $0.26 per share.
Amount primarily relates to losses on early retirement of debt at the Parent
Company of $92 million, or $0.14 per share, at AES Gener of $20 million, or
$0.02 per share, and at IPALCO of $9 million or $0.01 per share; partially
offset by a gain on early retirement of debt at AES Argentina of $65 million,
or $0.10 per share.
10. Amount primarily relates to the loss on early retirement of debt at the
Parent Company of $19 million, or $0.03 per share.
11. Amount relates to a SAB 118 charge to finalize the provisional estimate
of one-time transition tax on foreign earnings of $194 million, or $0.29
per share, partially offset by a SAB 118 income tax benefit to finalize the
provisional estimate of remeasurement of deferred tax assets and liabilities
to the lower corporate tax rate of $77 million, or $0.11 per share.
12. Amount relates to a one-time transition tax on foreign earnings of $675
million, or $1.02 per share and the remeasurement of deferred tax assets
and liabilities to the lower corporate tax rate of $39 million, or $0.06 per
share.
13. Amount primarily relates to the income tax expense under the GILTI
provision associated with the gains on sales of business interests, primarily
Masinloc, of $97 million, or $0.15 per share, and income tax expense
associated with gains on sale of CTNG of $36 million, or $0.05 per share
and Electrica Santiago of $13 million, or $0.02 per share; partially offset by
income tax benefits associated with the loss on early retirement of debt
at the Parent Company of $36 million, or $0.05 per share, and income tax
benefits associated with the impairment at Shady Point of $33 million, or
$0.05 per share.
14. Amount primarily relates to the income tax benefit associated with asset
impairments of $148 million, or $0.22 per share.
THIS PAGE INTENTIONALLY LEFT BLANK
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, 2018
-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
Name of Each Exchange on Which Registered
New York Stock Exchange
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Securities registered pursuant to Section 12(g) of the Act: None
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 every Interactive Data File required to be submitted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit such files). Yes
No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) 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, a smaller
reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting
company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Accelerated filer
Smaller reporting company
Emerging growth company
Non-accelerated filer
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for
complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
The aggregate market value of the voting and non-voting common equity held by non-affiliates on June 29, 2018, the last business
No
day of the Registrant's most recently completed second fiscal quarter (based on the adjusted closing sale price of $13.05 of the
Registrant's Common Stock, as reported by the New York Stock Exchange on such date) was approximately $8.63 billion.
The number of shares outstanding of Registrant's Common Stock, par value $0.01 per share, on February 21, 2019 was
662,358,244.
Portions of Registrant's Proxy Statement for its 2019 annual meeting of stockholders are incorporated by reference in Parts II and
DOCUMENTS INCORPORATED BY REFERENCE
III
THE AES CORPORATION FISCAL YEAR 2018 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 2018 Results
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 (Loss)
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 - Goodwill and Other Intangible Assets
Note 9 - Regulatory Assets and Liabilities
Note 10 - Debt
Note 11 - Commitments
Note 12 - Contingencies
Note 13 - Benefit Plans
Note 14 - Equity
Note 15 - Segment and Geographic Information
Note 16 - Share-Based Compensation
Note 17 - Redeemable Stock of Subsidiaries
Note 18 - Revenue
Note 19 - Other Income and Expense
Note 20 - Asset Impairment Expense
Note 21 - Income Taxes
Note 22 - Discontinued Operations
Note 23 - Held-for-Sale and 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)
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 SCHEDULE
SIGNATURES
1
4
6
45
63
63
63
65
66
66
67
69
69
69
70
77
84
87
96
100
103
104
105
106
107
108
109
121
121
122
127
129
130
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173
GLOSSARY OF TERMS
The following terms and abbreviations appear in the text of this report and have the definitions indicated
below:
Adjusted EPS
Adjusted PTC
AES
AOCI
AOCL
ASC
ASEP
BACT
BART
BOT
BTA
CAA
CAMMESA
CCGT
CCR
Adjusted Earnings Per Share, a non-GAAP measure
Adjusted Pre-tax Contribution, a non-GAAP measure of operating performance
The Parent Company and its subsidiaries and affiliates
Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Loss
Accounting Standards Codification
National Authority of Public Services
Best Available Control Technology
Best Available Retrofit Technology
Build, Operate and Transfer
Best Technology Available
United States Clean Air Act
Wholesale Electric Market Administrator in Argentina
Combined Cycle Gas Turbine
Coal Combustion Residuals, which includes bottom ash, fly ash and air pollution control wastes generated at
coal-fired generation plant sites.
La Caisse de dépôt et placement du Quebéc
Coordinador Electrico Nacional
Chief Executive Officer
Federal Electricity Commission
Combined Heat and Power
Contribuição para o Financiamento da Seguridade Social
Carbon Dioxide
Committee of Sponsoring Organizations of the Treadway Commission
Capacity Performance
United States Consumer Price Index
Clean Power Plan
Competitive Retail Electric Service
Cross-State Air Pollution Rule
Compañia Transmisora del Norte Grande
U.S. Clean Water Act
Directorate-General for Competition of the European Commission
The Dayton Power & Light Company
DPL Inc.
DPL Energy Resources, Inc.
Dominican Power Partners
Earnings before Interest, Taxes, Depreciation & Amortization
United States Environmental Protection Agency
Engineering, Procurement, and Construction
Electric Reliability Council of Texas
Electric Security Plan
European Union
Euro Inter Bank Offered Rate
Electric Utility Steam Generating Unit
Electricity of Vietnam
Financial Accounting Standards Board
Federal Energy Regulatory Commission
CDPQ
CEN
CEO
CFE
CHP
COFINS
CO2
COSO
CP
CPI
CPP
CRES
CSAPR
CTNG
CWA
DG Comp
DP&L
DPL
DPLER
DPP
EBITDA
EPA
EPC
ERCOT
ESP
EU
EURIBOR
EUSGU
EVN
FASB
FERC
FONINVEMEM Fund for the Investment Needed to Increase the Supply of Electricity in the Wholesale Market
FPA
FX
GAAP
GDPR
GHG
GILTI
GRIDCO
GWh
HLBV
IDEM
ITC
IPALCO
Federal Power Act
Foreign Exchange
Generally Accepted Accounting Principles in the United States
General Data Protection Regulation
Greenhouse Gas
Global Intangible Low Taxed Income
Grid Corporation of Odisha Ltd.
Gigawatt Hours
Hypothetical Liquidation Book Value
Indiana Department of Environmental Management
Imputed Tax Credit
IPALCO Enterprises, Inc.
1
Indiana, Indianapolis Power & Light Company
Independent Power Producers
Integrated Single Electricity Market
Independent System Operator
Indiana Utility Regulatory Commission
London Inter Bank Offered Rate
Liquefied Natural Gas
Mercury and Air Toxics Standards
Midcontinent Independent System Operator, Inc.
Energy Reallocation Mechanism
Megawatts
Megawatt Hours
National Ambient Air Quality Standards
Noncontrolling Interest
Non-Conventional Renewable Energy
Natsionalna Elektricheska Kompania (state-owned electricity public supplier in Bulgaria)
National Electric Power Company
North American Electric Reliability Corporation
Not Meaningful
Notice of Violation
Nitrogen Dioxide
National Pollutant Discharge Elimination System
New Source Performance Standards
Operations and Maintenance
Orissa Electricity Regulatory Commission
National System Operator
Odisha Power Generation Corporation, Ltd.
Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling
IPL
IPP
I-SEM
ISO
IURC
LIBOR
LNG
MATS
MISO
MRE
MW
MWh
NAAQS
NCI
NCRE
NEK
NEPCO
NERC
NM
NOV
NOX
NPDES
NSPS
O&M
OERC
ONS
OPGC
OTC Policy
Parent Company The AES Corporation
PCU
Pet Coke
PIS
PJM
PM
PPA
PREPA
PSD
PSU
PUCO
PURPA
QF
RMRR
RSU
RTO
SADI
SBU
SCE
SEC
SEM
SEN
SIC
SIN
SING
SIP
SNE
SO2
SSO
SWRCB
TCJA
TECONS
U.S.
UK
USD
Performance Cash Units
Petroleum Coke
Partially Integrated System
PJM Interconnection, LLC
Particulate Matter
Power Purchase Agreement
Puerto Rico Electric Power Authority
Prevention of Significant Deterioration
Performance Stock Unit
The Public Utilities Commission of Ohio
Public Utility Regulatory Policies Act
Qualifying Facility
Routine Maintenance, Repair and Replacement
Restricted Stock Unit
Regional Transmission Organization
Argentine Interconnected System
Strategic Business Unit
Southern California Edison
United States Securities and Exchange Commission
Single Electricity Market
Sistema Electrico Nacional
Central Interconnected Electricity System
National Interconnected System
Northern Interconnected Electricity System
State Implementation Plan
National Secretary of Energy
Sulfur Dioxide
Standard Service Offer
California State Water Resources Board
Tax Cuts and Jobs Act
Term Convertible Preferred Securities
United States
United Kingdom
U.S. dollar
2
VAT
VIE
Vinacomin
YPF
Value Added Tax
Variable Interest Entity
Vietnam National Coal-Mineral Industries Holding Corporation Ltd.
Argentina state-owned gas company
3
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:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
the economic climate, particularly the state of the economy in the areas in which we operate and the state
of the economy in China, which impacts demand for electricity in many of our key markets, 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 fulfill our obligations, 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;
our ability to receive funds from our subsidiaries by way of dividends, fees, interest, loans or otherwise;
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 operate power generation, distribution and transmission facilities, including managing
availability, outages and equipment failures;
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 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, wildfires and low levels of wind or sunlight for our wind and solar facilities;
the performance of our contracts by our contract counterparties, including suppliers or customers;
severe weather and natural disasters;
our ability to raise sufficient capital to fund development projects or to successfully execute our
development projects;
the success of our initiatives in other renewable energy projects and energy storage projects;
4
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
the availability of government incentives or policies that support the development of renewable energy
generation projects;
our ability to keep up with advances in technology;
growth in number of customers or in customer usage;
the operations of our joint ventures that we do not control;
our ability to achieve reasonable rate treatment in our utility businesses;
changes in laws, rules and regulations affecting our international businesses, particularly in developing
countries;
changes in laws, rules and regulations affecting our utilities businesses, 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 government
policies or tax incentives;
changes in environmental laws, including requirements for reduced emissions, GHG legislation, regulation,
and/or treaties and CCR regulation and remediation;
changes in tax laws, including U.S. tax reform, and challenges to our tax positions;
the effects of litigation and government and regulatory investigations;
the performance of our acquisitions;
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
•
cyber-attacks 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.
5
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 power generation and utility company, providing affordable, sustainable energy
through our diverse portfolio of thermal and renewable generation facilities and distribution businesses. Our mission
is to improve lives by accelerating a safer and greener energy future. We do this by leveraging our unique electricity
platforms and the knowledge of our people to provide the energy and infrastructure solutions our customers 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 through the availability of reliable, affordable
electric power.
Overview of Our Strategy
Future growth across our company will be heavily weighted toward less carbon-intensive wind, solar and
natural gas generation and infrastructure. Our robust backlog of projects under construction or under signed PPAs
continues to increase, driven by our focus on select markets where we can take advantage of our global scale and
synergies with our existing businesses. In 2018, we signed long-term PPAs for 2 GW of capacity and we are on
pace to sign 2 to 3 GW of new PPAs annually through 2022.
We are also working on enhancing some of our current contracts by blending and extending existing PPAs and
by adding renewable energy. We call this approach Green Blend and Extend. With this strategy, we leverage our
existing platforms, contracts and relationships to negotiate new long-term renewable PPAs with higher returns than
we would otherwise achieve through a bidding process. We see potential opportunities to execute this strategy
across many of our markets, including Chile, Mexico and the United States.
In Hawaii, we are delivering pioneering solar plus storage facilities, which will serve baseload energy needs,
including satisfying demand with renewable power 24 hours a day, seven days a week.
We have two LNG regasification terminals in Central America and the Caribbean, with a total of 150 TBTU of
LNG storage capacity. These terminals were built to supply not only the gas for our co-located combined cycle
6
plants, but also to meet the growing demand for natural gas in the region.
In Panama, the storage tank at our recently inaugurated Colon power plant and regasification terminal is
expected to come on-line in mid-2019. We believe there is significant potential upside associated with increasing
utilization beyond the requirements of our co-located power plant.
As a result of our efforts to decrease our exposure to coal-fired generation and increase our portfolio of
renewables, energy storage and natural gas capacity, we are significantly reducing our carbon dioxide emissions
per MWh of generation. Under our current strategy, we anticipate a reduction of carbon intensity levels of 50% from
2016 to 2022 and of 70% from 2016 to 2030.
We are a leader in deploying new technologies, such as battery-based energy storage, drone applications and
digital customer interfaces. The Company's energy storage joint venture with Siemens, Fluence, has now delivered
or been awarded 80 projects in 18 countries, with a total capacity of 766 MW.
Strategic Highlights
We continue to improve the returns from our existing portfolio and position AES for long-term, sustainable
growth.
•
In 2018, the Company paid down $1 billion in Parent debt
Reduced Parent debt by 22%, to $3.7 billion, compared to December 31, 2017
In December 2018, the Company achieved a key investment grade financial metric of 3.95x Parent
leverage one year earlier than previously planned
• As of December 31, 2018, the Company's backlog of 5,787 MW includes:
3,841 MW under construction and coming on-line through 2021; and
1,946 MW of renewables signed under long-term PPAs
•
•
•
In 2018, the Company agreed to sell approximately 48% of its interest in sPower's operating portfolio
Once these sales close, AES' ownership in sPower's operating portfolio will decrease from 50% to
approximately 26%
In 2018, the Company signed long-term agreements to sell 25 TBTU of LNG annually in the Dominican
Republic, which will contribute to growth beyond 2020
In 2018, Fluence was awarded 286 MW of new projects
_____________________________
(1)
(2) Excludes working capital adjustments and growth activity prior to the close of the acquisition.
Investments in subsidiaries excludes $2.2 billion investment in DPL
7
Segments
We are organized into four market-oriented SBUs: US and Utilities (United States, Puerto Rico and El
Salvador); South America (Chile, Colombia, Argentina and Brazil); MCAC (Mexico, Central America and the
Caribbean); and Eurasia (Europe and Asia) — which are led by our SBU Presidents. During the first quarter of
2018, the Andes and Brazil SBUs were merged in order to leverage scale and are now reported together as part of
the South America SBU. Further, the Puerto Rico and El Salvador businesses, formerly part of the MCAC SBU,
were combined with the US SBU, which is now reported as the US and Utilities SBU. Within our four 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.
We measure the operating performance of our SBUs using Adjusted PTC, a non-GAAP measure. The
Adjusted PTC by SBU for the year ended December 31, 2018 is shown below. The percentages for Adjusted PTC
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 of Financial Condition and Results of Operations
—SBU Performance Analysis of this Form 10-K for reconciliation and definitions of Adjusted PTC.
The following summarizes our businesses within our four SBUs.
8
9
Overview
Generation
We currently own and/or operate a generation portfolio of 31,792 MW, including one integrated utility. 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, availability of generation capacity to meet contracted sales, fuel costs, seasonality, weather
variations and economic activity, fixed-cost management, and competition.
10
Contract Sales — Most of our generation businesses sell electricity under medium- or long-term contracts
("contract sales") or under short-term agreements in competitive markets ("short-term sales"). Our medium-term
contract sales have terms of two to five years, while our long-term contracts have terms of more than five 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 below under Fuel Costs). These contracts are intended to reduce exposure to the
volatility of fuel 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 in 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 Short-
Term Sales and Capacity Payments sections 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 average terms of less than two years, including spot sales, directly in the short-term market or 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.
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.
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.
11
37% 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.
31% 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.
29% of the capacity of our generation plants are fueled by renewables, including hydro, solar, wind, energy
storage, biomass and landfill gas, which do not have significant fuel costs.
3% of the capacity of our generation fleet utilizes pet coke, diesel or oil 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.
Seasonality, Weather Variations and Economic Activity — Our generation businesses are affected by seasonal
weather patterns and, therefore, operating margin is not generated evenly throughout 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' six utility businesses distribute power to 2.4 million people in two countries. AES' two utilities in the U.S.
also include generation capacity totaling 4,102 MW. Our utility businesses consist of IPL (an integrated utility) and
DP&L (transmission and distribution) in the U.S., and four utilities in El Salvador (distribution).
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
on the Consolidated Statements of Operations.
Regulated Rate of Return and Tariff — In exchange for the right to sell or distribute electricity in a service
territory, our utility businesses are subject to government regulation. This regulation sets the framework for the
prices ("tariffs") that our utilities are allowed to charge customers for electricity and establishes service standards
that we are required to meet.
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 usage level and may include a pass-
through 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, to the customer. 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 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 and, therefore, operating margin is not generated evenly throughout the year. Additionally, weather
12
variations may also have an impact based on the number of customers, temperature variances from normal
conditions, and customers' historic usage levels and patterns. Retail 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 explicit, with defined performance incentives or penalties, or
implicit, where the utility must operate to meet customer expectations.
Competition — Our fully integrated utility, IPL, and our transmission and distribution regulated utility, DP&L,
operate as the sole distributors of electricity within their respective jurisdictions. IPL owns and operates all of the
businesses and facilities necessary to generate, transmit and distribute electricity. DP&L owns and operates all of
the businesses and facilities necessary to transmit and distribute electricity. Competition in the regulated electricity
business is primarily from the on-site generation for industrial customers. IPL is 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. However, effective with the approval of the 2018 IPL rate order in December, annual
wholesale margins earned above or below a certain benchmark are shared with customers, thus mitigating this
volatility. See the full discussion under the US and Utilities SBU.
At our distribution business in El Salvador, we face limited competition due to significant barriers to enter the
market. According to El Salvador's regulation, large regulated customers have the option of becoming unregulated
users and requesting service directly by the generation or commercialization agents.
Development and Construction
We develop and construct new generation facilities. For our utility business, new plants may be built or
existing plants retrofitted in response to customer needs or to comply with regulatory developments. The projects
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. 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.
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 15—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.
13
US AND UTILITIES SBU
Our US and Utilities SBU has 29 generation facilities, two utilities in the United States, and four utilities in El
Salvador.
Generation — Operating installed capacity of our US and Utilities SBU totals 11,574 MW. IPALCO (IPL's
parent), DP&L, and DPL Inc. (DP&L's parent) are all SEC registrants, and as such, follow the public filing
requirements of the Securities Exchange Act of 1934. The following table lists our US and Utilities SBU generation
facilities:
Business
Location
Fuel
El Salvador
El Salvador
El Salvador
Solar
Landfill
Gas
Solar
Bosforo
AES Nejapa
Moncagua
El Salvador Subtotal
Southland—Alamitos
Southland—Redondo Beach
sPower (1)
AES Puerto Rico
Southland—Huntington Beach
Shady Point (2)
Buffalo Gap II (3)
Hawaii
US-CA
US-CA
US-Various
US-PR
US-CA
US-OK
US-TX
US-HI
Warrior Run
Buffalo Gap III (3)
sPower (1)
AES Distributed Energy (AES DE) (3) US-Various
US-MD
US-TX
US-Various Wind
Buffalo Gap I (3)
Laurel Mountain
Mountain View I & II
Mountain View IV
Lawa'i (AES DE) (3)
Ilumina
Laurel Mountain ES
AES Gilbert (Salt River)
Warrior Run ES
United States Subtotal
_____________________________
US-TX
US-WV
US-CA
US-CA
US-HI
US-PR
US-WV
US-AZ
US-MD
Gross
MW
43
6
3
52
2,075
1,392
AES
Equity
Interest
50%
100%
100%
100%
100%
Year Acquired
or Began
Operation
Contract
Expiration
Date
2018
2011
2015
2043
2035
2035
Customer(s)
EEO
CAESS
EEO
1998
2019-2020 Southern California Edison
1998
2020
EDF Energy, LLC, Clean
Power Alliance of
Southern California
1,081
50%
2017-2018
2028-2046
Various
524
100%
2002
2027 Puerto Rico Electric Power
Authority
1998
2019-2020 Southern California Edison
474
360
233
206
205
170
140
136
117
98
65
49
20
20
24
16
10
100%
100%
100%
100%
100%
100%
50%
1991
2007
1992
2000
2008
2017
2022
2030
2036
Hawaiian Electric Co.
First Energy
Various
Utility, Municipality,
Education, Non-Profit
100%
2015-2018
2029-2042
100%
100%
100%
100%
100%
100%
100%
100%
2006
2011
2008
2012
2018
2012
2011
2019
2021
Direct Energy
2021 Southern California Edison
2032 Southern California Edison
2043
Kaua'i Island Utility
Cooperative
2032 Puerto Rico Electric Power
Authority
2039
Salt River Project
Agricultural Improvement
and Power District
5
100%
2016
7,420
7,472
Gas
Gas
Solar
Coal
Gas
Coal
Wind
Coal
Coal
Wind
Solar
Wind
Wind
Wind
Wind
Solar
Energy
Storage
Solar
Energy
Storage
Energy
Storage
Energy
Storage
(1)
(2)
(3)
Unconsolidated entity, accounted for as an equity affiliate.
Announced the sale of this business in December 2018.
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.
14
Under construction — The following table lists our plants under construction in the US and Utilities SBU:
Business
AES Distributed Energy (AES
DE)
Riverhead (sPower)
Bosforo
Basin Electric (sPower)
San Pablo (sPower)
Antelope DSR3 (sPower)
Kekaha (AES DE)
Southland Repowering
Na Pua Makani
Alamitos Energy Center
Location
US-Various
US-NY
El Salvador
US-SD
US-CA
US-CA
US-HI
US-CA
US-HI
US-CA
Fuel
Gross
AES Equity
Expected Date of Commercial
Solar
Energy Storage
Solar
Solar
Wind
Solar
Solar
Solar
Energy Storage
Gas
Wind
Energy Storage
47
3
20
57
220
100
20
14
14
1,284
28
100
1,907
100%
100%
50%
50%
50%
50%
50%
100%
100%
100%
100%
100%
1H-2H 2019
2H 2019
1H 2019
1H 2019
2H 2019
2H 2019
2H 2019
2H 2019
1H 2020
1H 2020
1H 2021
Utilities — The following table lists our utilities and their generation facilities.
Business
Location
El Salvador
CAESS
CLESA
El Salvador
DEUSEM El Salvador
El Salvador
EEO
El Salvador Subtotal
DPL (1)
IPL (2)
US-OH
US-IN
United States
Subtotal
Approximate Number of Customers
Served as of 12/31/2018
GWh Sold in
2018
Fuel
Gross
MW
AES Equity
Interest
Year Acquired or
Began Operation
602,000
404,000
81,000
310,000
1,397,000
525,000
498,000
1,023,000
2,420,000
2,122
931
138
598
3,789
7,139
15,092
22,231
26,020
Coal
Coal/Gas/Oil
129
3,973
4,102
75%
80%
74%
89%
100%
70%
2000
1998
2000
2000
2011
2001
_____________________________
(1)
(2)
DPL's subsidiary, AES Ohio Generation, LLC, owned an undivided interest in Conesville Unit 4. In October 2018, the co-owner of Conesville Unit 4 announced
that the plant will be retired by May 2020. DPL's subsidiary, DP&L, also owns a 4.9% equity ownership in OVEC, an electric generating company. OVEC has
two plants in Cheshire, Ohio and Madison, Indiana with a combined generation capacity of approximately 2,109 MW. DP&L’s share of this generation is
approximately 103 MW. DPL's GWh sold in 2018 represent DPL's wholesale revenues and DP&L's Standard Service Offer (SSO) utility revenues, which are
sales to utility customers who use DP&L to source their electricity through the competitive bid process. Total transmission sales were 14,439 GWh.
CDPQ owns direct and indirect interests in IPALCO which total approximately 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. 20 MW of IPL total is considered a transmission asset.
15
The following map illustrates the locations of our US and Utilities facilities:
US and Utilities Businesses
U.S. Businesses
IPL
Regulatory Framework and Market Structure — IPL is subject to comprehensive regulation by the IURC with
respect to its services and facilities, retail rates and charges, the issuance of long-term securities, and certain other
matters. The regulatory authority of the IURC over IPL's business is typical of regulation generally imposed by state
public utility commissions. The IURC sets tariff rates for electric service provided by IPL. The IURC considers all
allowable costs for ratemaking purposes, including a fair return on assets used and useful to providing service to
customers.
IPL's tariff rates consist of basic rates and approved charges. 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 and (ii) a rider for the timely recovery of costs incurred to comply with
environmental laws and regulations. These components function somewhat independently of one another, and are
subject to review at the same time as any review of IPL's basic rates and charges.
IPL is one of many transmission system owner members in MISO, an 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. MISO operates on a merit order dispatch, considering transmission constraints and
other reliability issues to meet the total demand in the MISO region. IPL offers electricity in the MISO day-ahead
and real-time markets.
16
Business Description — IPL is engaged primarily in generating, transmitting, distributing and selling electric
energy to 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 950,000. IPL owns and operates four generating stations, all within the
state of Indiana. IPL’s largest generating station, Petersburg, is coal-fired. The second largest station, Harding
Street, uses natural gas and fuel oil to power combustion turbines. In addition, IPL operates a 20 MW battery-based
energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a newly
constructed 671 MW CCGT natural gas plant. IPL took operational control and commenced commercial operations
of this CCGT plant in April 2018. The fourth station, Georgetown, is a small peaking station that uses natural gas to
power combustion turbines.
On October 31, 2018, the IURC issued an order approving an uncontested settlement agreement to increase
IPL's annual revenues by $44 million, or 3% (the "2018 Rate Order"). The 2018 Rate Order primarily includes
recovery through rates of costs associated with the CCGT at Eagle Valley, completed in the first half of 2018, and
other construction projects. New base rates and charges became effective on December 5, 2018. The order also
provides customers with approximately $50 million in benefits, including tax reform benefits associated with the
TCJA, over a two-year period through a rate adjustment mechanism beginning in March 2019.
Environmental Regulation — For information on compliance with environmental regulations see Item 1.—
United States Environmental and Land-Use Legislation and Regulations.
Key Financial Drivers — IPL's financial results are driven primarily by retail demand, weather, and outage
costs. In addition, IPL's financial results are likely to be driven by many factors, including, but not limited to:
•
•
•
•
regulatory outcomes;
the passage of new legislation, implementation of regulations or other changes in regulation;
timely recovery of capital expenditures; and
to a lesser extent, wholesale and capacity prices.
Construction and Development — IPL's construction program is composed of capital expenditures necessary
for prudent utility operations and compliance with environmental regulations, along with discretionary investments
designed to replace aging equipment or improve overall performance. Additionally, IPL is currently evaluating future
investments under the Transmission, Distribution, and Storage System Improvement Charge, for which electric
utilities in Indiana can recover costs (including a return) for IURC approved infrastructure improvement plans.
DPL
Regulatory Framework and Market Structure — DPL is an energy holding company whose principal
subsidiaries include DP&L and AES Ohio Generation, LLC, both of which operate in Ohio. Electric customers within
Ohio are permitted to purchase power under contract from a CRES provider or from their local utility under SSO
rates. The SSO generation supply is provided by third parties through a competitive bid process. Ohio utilities have
the exclusive right to provide transmission and distribution services in their state-certified territories.
DP&L is regulated by the PUCO for its distribution services and facilities, retail rates and charges, reliability of
service, compliance with renewable energy portfolio requirements, energy efficiency program requirements, and
certain other matters. The PUCO maintains jurisdiction over the delivery of electricity, SSO, and other retail electric
services.
While Ohio 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. SSO rates
are subject to rules and regulations of the PUCO and are established through a competitive bid process for the
supply of power to SSO customers. 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 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. DP&L's wholesale transmission rates are
regulated by FERC.
DP&L is a member of PJM, an RTO that 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
17
Carolina, Tennessee, Indiana and Illinois. PJM also runs the day-ahead and real-time energy markets, ancillary
services market and forward capacity market for its members.
Business Description — DP&L transmits, distributes and sells electricity to retail customers in a 6,000 square
mile area of West Central Ohio. Ohio consumers have the right to choose the electric generation supplier from
whom they purchase retail generation service; however, retail transmission and distribution services are still
regulated. DP&L has the exclusive right to provide such transmission and distribution services to those customers.
Additionally, DP&L procures retail SSO electric service on behalf of residential, commercial, industrial and
governmental customers.
In September 2018, DP&L received an order from the PUCO establishing new base distribution rates for DP&L
(“the order”), which became effective October 1, 2018. The order approved, without modification, a stipulation and
recommendation previously filed by DP&L, along with various intervening parties, with the PUCO staff. The order
established a revenue requirement of $248 million for DP&L's electric service base distribution rates, which reflects
an increase to distribution revenues of $30 million per year. In addition, the order authorizes DP&L to collect from
customers costs related to qualified investments through a Distribution Investment Rider, changes the Decoupling
Rider to reduce variability from the impact of weather and demand, partially resolves regulatory issues related to the
TCJA, and authorizes DP&L to defer certain vegetation management costs for future collection.
In January 2019, DP&L filed a request with the PUCO for a two-year extension of its Distribution Modernization
Rider ("DMR") through October 2022, in the proposed amount of $199 million for each of the two additional years.
The request was made pursuant to the PUCO’s October 2017 ESP order, which approved the DMR and the option
for DP&L to file for a two-year extension. The extension request is set at a level expected to reduce debt obligations
at both DP&L and DPL and to position DP&L to make capital expenditures to maintain and modernize its electric
grid.
Environmental Regulation — For information on compliance with environmental regulations see Item 1.—
United States Environmental and Land-Use Legislation and Regulations.
Key Financial Drivers — DPL's financial results are primarily driven by customer growth. Following the
issuance of the distribution rate order in September 2018 and the resulting changes to the decoupling rider, DPL's
financial results are no longer driven by retail demand and weather, but will be impacted by customer growth within
our service territory.
In addition, DPL's financial results are likely to be driven by many factors, including, but not limited to:
•
•
•
the passage of new legislation, new regulations or other changes in regulation;
timely recovery of transmission and distribution expenditures; and
exiting generation assets currently owned by AES Ohio Generation.
Construction and Development — Planned construction additions primarily relate to new investments in and
upgrades to DPL's 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.
DP&L is projecting to spend an estimated $628 million on capital projects for the period 2019 through 2021.
We expect to finance this construction with a combination of cash on hand, short-term financing, long-term debt and
cash flows from operations.
In December 2018, DP&L filed a Distribution Modernization Plan with the PUCO proposing to invest $576
million in capital projects over the next 20 years. The principal components of the Distribution Modernization Plan
includes leveraging technologies to modernize and improve the sustainability of the grid, and enhancing customer
experience and security. These initiatives will allow DP&L to leverage and integrate distributed energy resources
into its grid, including community solar, energy storage, microgrids and electric vehicle charging infrastructure.
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.
18
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.
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.
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 in Southern California Edison's territory. 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.
All of AES Southland's capacity was previously contracted through a 20 year agreement (the “Tolling
Agreement”), that expired on May 31, 2018. Currently, AES Huntington Beach, LLC and AES Alamitos, LLC are
contracted though Resource Adequacy Purchase Agreements (the “RAPAs”), approved by the California Public
Utilities Commission in 2017. AES Redondo Beach, LLC has also entered into various RAPAs for the period of June
1, 2018 through December 31, 2020.
Under the RAPAs, the generating stations provide resource adequacy capacity, and have no obligation to
produce or sell any energy to the RAPA counterparty. However, the generating stations are required to bid energy
into the California ISO markets. Compensation under these RAPAs is dependent on the availability of the AES
Southland units in the California ISO market. Failure to achieve the minimum availability target will result in an
assessed penalty.
Re-powering — In November 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. The
contracts are resource adequacy agreements with annual energy put options. If the put option is exercised, all
capacity will be sold to SCE in exchange for a fixed monthly capacity fee that covers fixed operating cost, debt
service, and return on capital. In addition, SCE will reimburse variable costs and provide the natural gas and
charging electricity. If the annual put option is not exercised, SCE only has rights to the resource adequacy capacity
for that contract year and AES Southland can sell the energy and ancillary services to other counterparties.
In April 2017, the California Energy Commission unanimously approved the licenses for the new combined
cycle projects at AES Alamitos and AES Huntington Beach. In June 2017, AES closed the financing of $2.0 billion,
funded with a combination of non-recourse debt and AES equity. The construction of this new capacity started in
2017 and commercial operation of the gas-fired capacity is expected to commence in 2020 and the energy storage
capacity is expected to commence in 2021.
Key Financial Drivers — AES Southland's availability is one of the most important drivers of operations along
with market prices for gas and electricity.
Additional U.S. Generation Facilities
Regulatory Framework and Market Structure — For the non-renewable businesses, coal and natural gas are
used as the primary fuels. Coal prices are set by market factors internationally, while natural gas prices are
generally set domestically. Price variations for these fuels can change the composition of generation costs and
energy prices in our generation businesses.
Many of these generation businesses have entered into long-term PPAs with utilities or other offtakers. Some
businesses with PPAs have mechanisms to recover fuel costs from the offtaker, including an energy payment
partially based on the market price of fuel. When market price fluctuations in fuel are borne by the offtaker, revenue
may change as fuel prices fluctuate, but the variable margin or profitability should remain consistent. 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.
Several of our generation businesses in the U.S. currently operate as QFs, including Hawaii, Shady Point and
Warrior Run, as defined under the PURPA. These businesses entered into long-term contracts with electric utilities
that had a mandatory obligation 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
19
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 the 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 Federal Power Act 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.
The U.S. wholesale electricity market consists of multiple distinct regional markets that are subject to both
federal regulation, as implemented by 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.
Business Description — Additional businesses include thermal, wind, and solar generating facilities, of which
our U.S. Renewables businesses and AES Hawaii are the most significant.
U.S. Renewables
sPower owns and/or operates 153 utility and distributed electrical generation systems with a capacity of 1,221
MWh currently in operation across the U.S. sPower is also actively buying, developing and constructing renewable
assets in the U.S.
AES Distributed Energy develops, constructs and sells electricity generated by photovoltaic solar energy
systems and energy storage systems to public sector, utility, and non-profit entities through PPAs.
Excluding sPower wind plants, AES has 732 MW of wind capacity in the U.S., located in California, Texas and
West Virginia. Mountain View I & II, Mountain View IV and Buffalo Gap I sell under long-term PPAs through which
the energy price on the entire production of these facilities is guaranteed. Laurel Mountain, Buffalo Gap II and
Buffalo Gap III are exposed to the volatility of energy prices and their revenue may change materially as energy
prices fluctuate in their respective markets of operations.
AES manages the U.S. Renewables portfolio as part of its broader investments in the U.S.. A portion of U.S.
Solar projects and the majority of wind projects have 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 variability to earnings attributable to AES compared to the earnings reported at the facilities.
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. AES
Hawaii has entered into fixed-price coal purchase commitments through December 2019 and plans to seek
additional fuel purchase commitments to manage fuel price risk after December 2019.
Key Financial Drivers — U.S. thermal 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
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. The financial results
of U.S. Solar are primarily driven by the amount of sunshine hours available at the facilities, cell maintenance and
growth in projects. For additional details see Key Trends and Uncertainties in Item 7.— Management’s Discussion
and Analysis of Financial Condition and Results of Operations.
Construction and Development — Planned capital projects include the AES Southland re-powering described
above. In addition to the new construction project, U.S. Generation performs capital projects related to major plant
20
maintenance, repairs and upgrades to be compliant with new environmental laws and regulations. sPower has 360
MW of projects under construction and a development pipeline that includes 938 MW of projects for which long-
term PPAs have been signed. The budget for construction of the projects currently under construction and the
contracted projects is over $1.8 billion. AES Distributed Energy has 78 MW of projects under construction and a
development pipeline that includes 332 MW of projects for which long-term PPAs have been signed or, as
applicable, tariffs have been assigned through a regulatory process. The budget for construction of the projects
currently under construction and the contracted projects is over $1 billion.
Puerto Rico
Regulatory Framework and Market Structure — Puerto Rico has a single electric grid managed by 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. The Puerto Rico Energy Bureau is the main regulatory body. The
bureau approves wholesale and retail rates, sets efficiency and interconnection standards, and oversees PREPA's
compliance with Puerto Rico's renewable portfolio standard.
Puerto Rico's electricity is 98% produced by thermal plants (47% from petroleum, 34% from natural gas, 17%
from coal).
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. See Item 7.—Management's
Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties—
Macroeconomic and Political—Puerto Rico for further discussion of the long-term PPA with PREPA.
El Salvador
Regulatory Framework and Market Structure — El Salvador's national electric market is composed of
generation, distribution, transmission and marketing businesses, as well as a market and system operator and
regulatory agencies. The operation of the transmission system and the wholesale market is based on production
costs with a marginal economic model that rewards efficiency and allows investors to have guaranteed profits, while
end users receive affordable rates. The energy sector is governed by the General Electricity Law, which establishes
two regulatory entities responsible for monitoring its compliance:
• The National Energy Council is the highest authority on energy policy and strategy, and the coordinating
body for the different energy sectors. One of its main objectives is to promote investment in non-
conventional renewable sources to diversify the energy matrix.
• The General Superintendence of Electricity and Telecommunications regulates the market and sets
consumer prices, and, jointly with the distribution companies in El Salvador, developed the tariff calculation
applicable from 2018 until 2022.
El Salvador has a national electric grid that interconnects with Guatemala and Honduras. The sector has
approximately 1,659 MW of installed capacity, composed primarily of thermal (43%), hydroelectric (34%),
geothermal (10%), biomass (9%) and solar (4%) generation plants.
Business Description — AES El Salvador is the majority owner of four of the five distribution companies
operating in El Salvador (CAESS, CLESA, EEO and DEUSEM). AES El Salvador's territory covers 79% of the
country and accounted for 4,040 GWh of the wholesale market energy purchases during 2018, or about 63%
market share.
Construction and Development — As part of the initiative to pursue opportunities in renewable generation,
AES El Salvador has entered into a joint venture with Corporacion Multi-Inversiones, a Guatemalan investment
group, to develop, construct and operate Bosforo, a 142 MW solar farm. 43 MW of the project were completed in
2018 and are fully operational. 57 MW are under construction and expected to become operational during the first
half of 2019 and the remaining 42 MW will start construction in 2019 and are expected to be completed in the
second half of 2019. The energy produced by this project will be contracted directly by AES' utilities in El Salvador.
21
South America SBU
Our South America SBU has generation facilities in four countries — Chile, Colombia, Argentina and Brazil.
AES Gener, which owns all of our assets in Chile, Chivor in Colombia and TermoAndes in Argentina, as detailed
below, is a publicly traded company in Chile. AES has a 66.7% ownership interest in AES Gener and this business
is consolidated in our financial statements. Tietê is a publicly traded company in Brazil. AES controls and
consolidates Tietê through its 24% economic interest.
Operating installed capacity of our South America SBU totals 12,435 MW, of which 33%, 28%, 8%, and 31%
are located in Argentina, Chile, Colombia and Brazil, respectively. The following table lists our South America SBU
generation facilities:
AES
Equity
Interest
67%
67%
Year Acquired
or Began
Operation
2000
2016
Contract
Expiration
Date
2019-2026
Customer(s)
Various
67%
2000
2019-2040
Various
Business
Location
Fuel
Chivor
Tunjita
Colombia Subtotal
Gener - Chile (1)
Guacolda (2)
Electrica Angamos
Cochrane
Cochrane ES
Electrica Angamos ES
Norgener ES (Los Andes)
Chile Subtotal
TermoAndes (3)
AES Gener Subtotal
Alicura
Paraná-GT
San Nicolás
Guillermo Brown (4)
Los Caracoles (4)
Cabra Corral
Ullum
Sarmiento
El Tunal
Argentina Subtotal
Tietê (5)
Alto Sertão II
Guaimbe
Tietê Subtotal
Uruguaiana
Brazil Subtotal
Colombia Hydro
Colombia Hydro
Chile
Chile
Chile
Chile
Chile
Chile
Chile
Coal/Hydro/
Diesel/Solar/
Biomass
Coal
Coal
Coal
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
Brazil
Brazil
Brazil
Hydro
Wind
Solar
Brazil
Gas
Gross
MW
1,000
20
1,020
1,532
760
558
550
20
20
12
3,452
643
5,115
1,050
870
675
576
125
102
45
33
10
3,486
2,658
386
150
3,194
640
3,834
12,435
33%
67%
40%
40%
67%
67%
67%
100%
100%
100%
—%
—%
100%
100%
100%
100%
24%
24%
24%
46%
2000
2019-2032
Various
2011
2026-2037
2016
2030-2037
Minera Escondida, Minera
Spence, Quebrada Blanca
SQM, Sierra Gorda,
Quebrada Blanca
2016
2011
2009
2000
2019-2020
Various
Various
2019
Energia Provincial Sociedad
del Estado (EPSE)
Various
Various
2029
2033-2035
2037
Various
Various
Various
CCEE
2000
2001
1993
2016
2009
1995
1996
1996
1995
1999
2017
2018
2000
_____________________________
(1)
(2)
(3)
(4)
(5)
Gener - Chile plants: Alfalfal, Andes Solar, Laguna Verde, Laguna Verde Turbogas, Laja, Maitenes, Norgener 1, Norgener 2, Queltehues, Ventanas 1,
Ventanas 2, Ventanas 3, Ventanas 4 and Volcán.
Guacolda is comprised of five coal-fired units under Guacolda Energia S.A., an unconsolidated entity for which the results of operations are reflected in Net
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%.
TermoAndes is located in Argentina, but is connected to both the SEN in Chile and the SADI in Argentina.
AES operates these facilities through management or O&M agreements and owns no equity interest in these businesses.
Tietê plants: Água Vermelha, Bariri, Barra Bonita, Caconde, Euclides da Cunha, Ibitinga, Limoeiro, Mog-Guaçu, Nova Avanhandava, Promissão, Sao Joaquim
and Sao Jose.
22
Under construction — The following table lists our plants under construction in the South America SBU:
Business
Boa Hora
AGV Solar
Energetica
Vientos Nequinos
Alto Maipo
Fuel
Location
Brazil
Solar
Solar
Brazil
Argentina Wind
Argentina Wind
Hydro
Chile
Gross MW AES Equity Interest
24%
24%
100%
100%
62%
69
75
100
80
531
855
Expected Date of Commercial Operations
1H 2019
1H 2019
1H 2020
1H 2020
2H 2020
In June 2018, the Company completed the sale of its entire 17% ownership interest in Eletropaulo, a
distribution business in Brazil. Prior to its sale, Eletropaulo was accounted for as an equity method investment and
its results of operations and financial position were reported as discontinued operations in the consolidated financial
statements for all periods presented.
The following map illustrates the location of our South America facilities:
South America Businesses
Chile
Market Structure and Regulatory Framework — The Chilean electricity industry is divided into three business
segments: generation, transmission and distribution. Private companies operate in all three segments, and
generators can enter into PPAs to sell energy to regulated and unregulated customers, as well as to other
generators in the spot market.
Chile has operated a single power market, referred to as the SEN, which has been managed by the grid
operator CEN since November 2017. Previously, Chile had two main power systems, the SIC and SING, largely as
a result of its geographic shape and size, which were merged to form the SEN. The SEN has an installed capacity
23
of approximately 24,586 MW. SEN represents 99% of the installed generation capacity of the country.
CEN coordinates all generation and transmission companies in the SEN. CEN minimizes the operating costs
of the electricity system, while maximizing service quality and reliability requirements. CEN dispatches plants in
merit order based on their variable cost of production, allowing for electricity to be supplied at the lowest available
cost. In the south-central region of the SEN (former SIC), thermoelectric generation is required to fulfill demand not
satisfied by hydroelectric, solar and wind output and is critical to provide reliable and dependable electricity supply
under dry hydrological conditions. In the northern region of the SEN (former SING), which includes the Atacama
Desert, thermoelectric capacity represents the majority of installed capacity as hydroelectric generation is not
feasible. The fuels used for thermoelectric generation, mainly coal, diesel and LNG, are indexed to international
prices. In 2018, the generation installed capacity in the Chilean market was composed of the following:
Installed Capacity
Thermoelectric
Hydroelectric
Solar
Wind
Other
SEN
54%
27%
10%
7%
2%
Hydroelectric plants represent a significant portion of the system's installed capacity. Hydrological conditions
influence reservoir water levels, which in turn affects dispatch of the system's hydroelectric and thermoelectric
generation plants, thereby influencing spot market prices. Precipitation and snow melt impact hydrological
conditions in Chile. Rains occurs principally between June and August and are scarce during the remainder of the
year. Snow melt occurs between September and November.
The Ministry of Energy has primary responsibility for the Chilean electricity system directly or through the
National Energy Commission and the Superintendency of Electricity and Fuels.
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 2019
through 2034.
All generators can sell energy through contracts with regulated distribution companies or directly to
unregulated customers. Unregulated customers are customers whose connected capacity is higher than 5 MW.
Customers with connected capacity between 0.5 MW and 5.0 MW can opt for regulated or unregulated contracts for
a minimum period of four years. By law, both regulated and unregulated customers are required to purchase all
electricity under contracts. Generators may also sell energy to other power generation companies on a short-term
basis at negotiated prices outside the spot market. Electricity prices in Chile are denominated in U.S. dollars,
although payments are made in Chilean pesos.
Business Description — In Chile, through AES Gener, we are engaged in the generation and supply of
electricity (energy and capacity) in the SEN. AES Gener is the second largest generation operator in Chile in terms
of installed capacity with 3,400 MW, excluding energy storage , and has a market share of approximately 14% as of
December 31, 2018.
AES Gener owns a diversified generation portfolio in Chile in terms of geography, technology, customers and
fuel source. AES Gener's plants are located near the principal electricity consumption centers, including Santiago,
Valparaiso and Antofagasta. AES Gener's diverse generation portfolio provides flexibility for the management of
contractual obligations with regulated and unregulated customers, provides backup energy to the spot market and
facilitates operations under a variety of market and hydrological conditions.
Our commercial strategy in Chile aims to maximize margin while reducing cash flow volatility. To achieve this,
we contract a significant portion of our coal and hydroelectric baseload capacity under long-term agreements with a
diversified customer base. Power plants not considered within our baseload capacity (higher variable cost units,
mainly diesel) sell energy on the spot market when operating during scarce system supply conditions, such as low
hydrology and/or plant outages. In Chile, sales on the spot market are made only to other generation companies
who are members of the SEN at the system marginal cost.
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 pass-through mechanisms for fuel costs along with price indexations to US CPI.
In addition to energy payments, AES Gener also receives capacity payments to compensate for availability
during periods of peak demand. CEN annually determines the capacity requirements for each power plant. The
24
capacity price is fixed semiannually by the National Energy Commission and indexed to the CPI and other relevant
indices.
Environmental Regulation — During 2017 and 2016, the Ministry of Environment under the previous
administration updated the Atmospheric Decontamination Plan for the Ventanas and Huasco regions. Under that
proposed plan, no significant investments were needed to comply with new requirements at our plants Ventanas
and Guacolda. However, the authority under the current administration rejected that proposed plan on December
30, 2017. In December 2018, a new decontamination plan for the Ventanas and Huasco regions was proposed by
the authority under the current administration. Currently, the Environmental Ministry expects approval of the new
decontamination plan in early March 2019 and we are currently assessing the impact of the new proposed
decontamination plan.
Chilean law requires all electricity generators to supply a certain portion of their total contractual obligations
with NCREs. Generation companies are able to meet this requirement by building NCRE generation capacity (wind,
solar, biomass, geothermal and small hydroelectric technology) or purchasing NCREs from qualified generators.
Non-compliance with the NCRE requirements will result in fines. AES Gener currently fulfills the NCRE
requirements by utilizing AES Gener's solar and biomass power plants and by purchasing NCREs from other
generation companies. At present, AES Gener is in the process of negotiating additional NCRE supply contracts to
meet the future requirements.
In September 2014, a new emission tax, or green tax, was enacted effective January 2017. Emissions of PM,
SO2, NOx and CO2 are monitored for plants with an installed capacity over 50 MW; these emissions are taxed. In
the case of CO2, the tax will be equivalent to $5 per ton emitted. PPAs originating from the SING have clauses
allowing the Company to pass the green tax costs to unregulated customers. Distribution PPAs originating from the
SIC do not allow for the pass through of these costs.
Key Financial Drivers — Hedge levels at AES Gener limit volatility to the underlying financial drivers. In
addition, financial results are likely to be driven by many factors, including, but not limited to:
•
•
•
•
•
•
dry hydrology scenarios;
forced outages;
changes in current regulatory rulings altering the ability to pass through or recover certain costs;
fluctuations of the Chilean peso (our hedging strategy reduces this risk, but some residual risk remains);
tax policy changes;
legislation promoting renewable energy and/or more restrictive regulations on thermal generation assets;
and
• market price risk when re-contracting.
Construction and Development — AES Gener continues to advance the construction of the 531 MW Alto
Maipo run-of-the-river hydroelectric plant. Alto Maipo is the largest project in construction in the SEN market. When
completed, it will include 75 km of tunnels, two power houses and 17 km of transmission lines. See Item 7.—
Management's Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and
Uncertainties—Alto Maipo.
Colombia
Regulatory Framework and Market Structure — Electricity supply in Colombia is concentrated in one main
system, the SIN, which encompasses one-third of Colombia's territory, providing electricity to 97% of the country's
population. The SIN's installed capacity, primarily hydroelectric (68%) and thermal (31%), totaled 17,392 MW as of
December 31, 2018. The marked seasonal variations in Colombia's hydrology result in price volatility in the short-
term market. In 2018, 84% of total energy demand was supplied by hydroelectric plants.
The electricity sector in Colombia operates under a competitive market framework for the generation and sale
of electricity, and a regulated framework for transmission and distribution of electricity. The distinct activities of the
electricity sector are governed by Colombian laws and the CREG, regulating entity for energy and gas. Other
government entities have a role in the electricity industry, including 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 utility companies; and the Mining and Energetic Planning Unit, which is in charge of 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
25
companies, generators and traders, and unregulated customers at freely negotiated prices. 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.
In 2018, the Ministry of Mines and Energy published the final resolution for renewable energy auctions in
Colombia. The auction allocates 12-year energy contracts for 1.1 TW/h of energy demand under which renewable
generators commit to be in commercial operation by December 2021. The auction is scheduled for February 2019
and the regulator expects to adopt the current regulation for the entry of renewable generation to the market during
2019.
Business Description — We operate in Colombia through AES Chivor, a subsidiary of AES Gener, which owns
a hydroelectric plant with an installed capacity of 1,000 MW, and Tunjita, a 20 MW run-of-river hydroelectric plant,
both located approximately 160 km east of Bogota. AES Chivor’s installed capacity accounted for approximately 6%
of system capacity at the end of 2018. AES Chivor is dependent on hydrological conditions, which influence
generation and spot prices of non-contracted generation in Colombia.
AES Chivor's commercial strategy aims to execute contracts with commercial and industrial customers, and
bid in public tenders for one to four year contracts, mainly with distribution companies to reduce margin volatility
with proper portfolio risk management. The remaining energy generated by our portfolio is sold to the spot market,
including ancillary services. Additionally, AES Chivor receives reliability payments for maintaining the plant available
during periods of power scarcity, such as adverse hydrological conditions, in order to prevent power shortages.
Key Financial Drivers — Hydrological conditions largely influence Chivor's power generation. Maintaining the
appropriate contract level, while maximizing revenue through the sale of excess generation, is key to Chivor's
results of operations. Hedge levels at Chivor limit volatility in the underlying financial drivers. In addition to
hydrology, financial results are driven by many factors, including, but not limited to:
•
•
•
forced outages;
fluctuations of the Colombian peso; and
spot market prices.
Argentina
Regulatory Framework and Market Structure — Argentina has one main power system, the SADI, which
serves 96% of the country. As of December 31, 2018, the installed capacity of the SADI totaled 38,538 MW. The
SADI's installed capacity is composed primarily of thermoelectric generation (64%) and hydroelectric generation
(28%).
Thermoelectric generation in the SADI is primarily natural gas. However, scarcity of natural gas during winter
periods (June to August), result in the use of alternative fuels, such as oil and coal. The SADI is also highly reliant
on hydroelectric plants. Hydrological conditions impact reservoir water levels and largely influence the dispatch of
the system's hydroelectric and thermoelectric generation plants and, therefore, influence market costs. Precipitation
in Argentina occurs principally between June and August.
Regulatory Framework — The Argentine regulatory framework divides the electricity sector into generation,
transmission and distribution. The wholesale electric market is comprised of generation companies, transmission
companies, distribution companies and large customers who are permitted to trade electricity. Generation
companies can sell their output in the spot market or under PPAs. CAMMESA manages the electricity market and is
responsible for dispatch coordination. The Electricity National Regulatory Agency is in charge of regulating public
service activities and the Secretariat of Energy regulates system framework and grants concessions or
authorizations for sector activities. In Argentina, the regulator establishes the prices for electricity and fuel and
adjusts them periodically for inflation, changes in fuel prices and other factors. As a result, our businesses are
particularly sensitive to changes in regulation.
The Argentine electric market is an "average cost" system, with generators being compensated for fixed costs
and non-fuel variable costs plus a rate of return. All fuel, except coal, can be provided by CAMMESA. In December
2018, Resolution 70/2018 was enacted. This allows generation companies to buy fuel directly from producers or
from CAMMESA.
Argentina’s administration continues introducing regulatory improvements aiming to normalize the energy
sector. Among others, Resolution 19/2017 was enacted in 2017 to set higher tariffs, denominated in USD, for
energy and capacity prices. The enactment of resolution 19/2017 ceased the remuneration intended to fund
increased capacity projects . Likewise, long term USD-denominated PPAs have been awarded to develop 9.4 GW
26
of new capacity (thermal and renewable) through the execution of competitive auctions. During 2018, the
government has continued to increase end user prices to reduce subsidies and decrease system deficit.
AES Argentina has contributed certain accounts receivable 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 to operate. AES Argentina has three FONINVEMEM funds related to
operational plants under which payments are being received. AES Argentina will receive a pro rata ownership
interest in these plants once the accounts receivables have been fully repaid. See Item 7.—Management's
Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Long-
Term Receivables and Note 6.—Financing Receivables in Item 8.—Financial Statements and Supplementary Data
of this Form 10-K for further discussion of receivables in Argentina.
Business Description — As of December 31, 2018, AES operates plants totaling 4,129 MW, representing 11%
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 SEN markets. AES Argentina has a
diversified generation portfolio.
AES primarily sells its energy in the wholesale electricity market where prices are largely regulated. In 2018,
approximately 93% of the energy was sold in the wholesale electricity market and 7% was sold under contract, as a
result of contract sales made by TermoAndes.
Foreign currency controls were lifted in December 2015, allowing the Argentine peso to float under the
administration of the Argentinian Central Bank. In 2018, the Argentine peso devalued by approximately 102% and
Argentina’s economy was determined to be highly inflationary. See Item 7.—Management's Discussion and
Analysis Key Trends and Uncertainties of this Form 10-K for further discussion.
Tax Regulation — On December 29, 2017, Law 27430 was enacted in Argentina, which introduced a tax
reform with several changes in the Argentine tax system, effective on January 1, 2018. This tax reform reduced the
statutory corporate tax rate of companies from 35% to 30% in 2018 and 2019, and will reduce the rate to 25% from
2020 onward. The law also eliminated the Equalization Tax on the distribution of earnings generated after January
1, 2018. The Equalization Tax was replaced with a withholding tax on dividends at the rate of 7% for 2018 and
2019, and 13% from 2020 onward.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
•
•
•
•
forced outages;
exposure to fluctuations of the Argentine peso;
changes in hydrology;
timely collection of FONINVEMEM installment and outstanding receivables (See Note 6.—Financing
Receivables in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further
discussion); and
•
natural gas prices and availability for contracted generation.
Brazil
Regulatory Framework and Market Structure — In Brazil, the Ministry of Mines and Energy determines the
maximum amount of energy a generation plant can sell, called physical guarantee, representing the long-term
average expected energy production of the plant. Under current rules, physical guarantee energy can be sold to
distribution companies through long-term regulated auctions or under unregulated bilateral contracts with large
consumers or energy trading companies.
Brazil has installed capacity of 162,932 MW, which is primarily hydroelectric (64%) and renewables (19%).
Operation is centralized and controlled by the national operator, ONS, and regulated by ANEEL. The ONS
dispatches generators based on their marginal cost of production and on the risk of system rationing. Key variables
for the dispatch decision are forecasted hydrological conditions, reservoir levels, electricity demand, fuel prices and
thermal generation availability.
In case of unfavorable hydrology, the ONS will reduce hydroelectric dispatch to preserve reservoir levels and
increase dispatch of thermal plants to meet demand. The consequences of unfavorable hydrology are (i) higher
energy spot prices due to higher energy production costs by thermal plants and (ii) the need for hydro plants to
purchase energy in the spot market to fulfill their contractual obligations.
A mechanism known as the MRE was created under ONS to share hydrological risk across MRE hydro
generators. If the hydro plants generate less than the total MRE physical guarantee, the hydro generators may
27
need to purchase energy in the short-term market. When total hydro generation is higher than the total MRE
physical guarantee, the surplus is proportionally shared among its participants and they may sell the excess energy
on the spot market.
Business Description — Tietê has a portfolio of 12 hydroelectric power plants in the state of São Paulo with
total installed capacity of 2,658 MW. Tietê represents approximately 10% of the total generation capacity in the
state of São Paulo. Tietê hydroelectric plants operate under a 30-year concession expiring in 2029. AES owns 24%
of Tietê and is the controlling shareholder and manages and consolidates this business. Tietê aims to contract most
of its physical guarantee requirements and sell the remaining portion in the spot market. The commercial strategy is
reassessed periodically according to changes in market conditions, hydrology and other factors. Tietê generally
sells available energy through medium-term bilateral contracts.
Tietê's strategy is to grow by adding renewable capacity to its generation platform. In 2017, Tietê acquired Alto
Sertão II Wind Complex (“Alto Sertão II”) located in the state of Bahia, with an installed capacity of 386 MW and subject
to 20-year PPAs expiring between 2033 and 2035. Furthermore, in 2017 Tiete acquired Boa Hora Solar, a solar
development project and won a bid to develop a second solar project, AGV Solar, in the state of São Paulo. In 2018,
Tietê acquired Guaimbê, a solar power complex. All the solar assets are fully contracted with 20 year PPAs. Through
its ownership of Tietê, AES owns a 24% economic interest in those entities. These assets are not subject to return at
the end of the concession.
Under the concession agreement, Tietê is required to increase its capacity in the state of São Paulo by 15%
(or 398 MW). The above mentioned investments in new solar generation capacity in the state of São Paulo allowed
Tietê to sign a legal agreement in October 2018 with the state government in which it was agreed that: (i) 80% of
the expansion obligation (317 MW) was delivered or is in performance stage; and (ii) the Company will have up to
six years from the agreement's approval date to meet the remaining balance (81 MW).
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. AES manages and has a 46% economic interest in the plant. The plant's operations have
been largely suspended due to the unavailability of gas. The plant operated for short periods of time in 2013, 2014
and 2015 when short-term supply of LNG was sourced for the facility. The plant did not operate in 2016, 2017 or
2018. AES has evaluated several alternatives to bring gas supply on a competitive basis to Uruguaiana. Capacity
restrictions on the Argentinean pipeline are a challenge, especially during the winter season when gas demand in
Argentina is very high. Uruguaiana continues to work toward securing gas on a long-term basis.
Key Financial Drivers — As the system is highly dependent on hydroelectric generation, electricity pricing is
driven by hydrology in Brazil. Plant availability is also a significant financial driver as in times of high hydrology AES
is more exposed to the spot market. The availability of gas is also a driver for continued operations at Uruguaiana.
Tietê's financial results are 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; and
ability to execute on its growth strategy.
Construction and Development — As part of the initiative to pursue opportunities in renewable generation
discussed above, Tietê is currently constructing photovoltaic power plants with a total projected capacity of 144
MW, subject to 20 year PPAs. Commercial operation of first phase, Boa Hora Solar, and of the second phase, AGV
Solar, is expected in the first half of 2019.
28
MCAC SBU
Our MCAC SBU has a portfolio of generation facilities, including renewable energy, in three countries, with a
total capacity of 3,205 MW as of December 31, 2018.
Generation — The following table lists our MCAC SBU generation facilities:
Fuel
Gross
MW
Business
DPP (Los Mina)
Andres
Itabo (1)
Andres ES
Los Mina DPP ES
Location
Dominican
Republic
Dominican
Republic
Dominican
Republic
Dominican
Republic
Dominican
Republic
Gas
Gas
Coal
Energy
Storage
Energy
Storage
Dominican Republic Subtotal
Merida III
Mexico
Gas
Termoelectrica del Golfo (TEG)
Mexico
Termoelectrica del Penoles (TEP) Mexico
Pet Coke
Pet Coke
Mexico Subtotal
Colon (2)
Bayano
Changuinola
Chiriqui-Esti
Estrella del Mar I
Chiriqui-Los Valles
Panama
Gas
Panama
Hydro
Panama
Panama
Panama
Panama
Hydro
Hydro
Heavy Fuel
Oil
Hydro
Chiriqui-La Estrella
Panama
Hydro
Panama Subtotal
_____________________________
358
319
295
10
10
992
505
275
275
1,055
381
260
223
120
72
54
48
1,158
3,205
AES
Equity
Interest
85 %
85 %
43 %
85 %
85 %
75 %
99 %
99 %
50 %
49 %
90 %
49 %
49 %
49 %
49 %
Year Acquired
or Began
Operation
Contract
Expiration
Date
1996
2003
2000
2017
2017
2000
2007
2007
2018
1999
2011
2003
2015
1999
1999
2022
2022
2022
2025
2027
2027
2028
2030
2030
2030
2020
2030
2030
Customer(s)
CDEEE
Ede Norte/Ede Este/Ede
Sur/Non-Regulated Users
Ede Norte/Ede Este/Ede
Sur
Comision Federal de
Electricidad
CEMEX
Penoles
Electra Noreste/Edemet/
Edechi
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
(1)
(2)
Itabo plants: Itabo complex (two coal-fired steam turbines and one gas-fired steam turbine).
Plant also includes an adjacent regasification facility, as well as a 180,000 m3 LNG storage tank, which is expected to come on-line in 2019.
Under construction — The following table lists our plants under construction in the MCAC SBU:
Business
Location
Fuel
Mesa La Paz
Mexico
Wind
Gross
MW
306
AES Equity Interest
50%
Expected Date of Commercial
Operations
1H 2020
29
The following map illustrates the location of our MCAC facilities:
MCAC Businesses
Dominican Republic
Regulatory Framework and Market Structure — The Dominican Republic energy market is a decentralized
industry consisting of generation, transmission and distribution businesses. Generation companies can earn
revenue through short- and long-term PPAs, ancillary services, and a competitive wholesale generation market. All
generation, transmission and distribution companies are subject to and regulated by the General Electricity Law.
Two main agencies are responsible for monitoring compliance with the General Electricity Law:
• The National Energy Commission drafts and coordinates the legal framework and regulatory legislation.
They propose and adopt policies and procedures to implement best practices, support the proper
functioning and development of the energy sector, and promote investment.
• The Superintendence of Electricity's main responsibilities include monitoring compliance with legal
provisions, rules, and technical procedures governing generation, transmission, distribution and
commercialization of electricity. They monitor behavior in the electricity market in order to avoid
monopolistic practices. In addition to the two agencies responsible for monitoring compliance with the
General Electricity Law, the Industrial and Commerce Ministry supervises commercial and industrial
activities in the Dominican Republic as well as the fuels and natural gas commercialization to the end
users.
The Dominican Republic has one main interconnected system with approximately 3,800 MW of installed
capacity, composed primarily of thermal (78%), hydroelectric (16%), wind (4%) and solar (2%) generation plants/
farms.
30
Business Description — AES Dominicana consists of three operating subsidiaries, Itabo, Andres and Los
Mina. With a total of 992 MW of installed capacity, AES has 26% of the system capacity and supplies approximately
40% of energy demand via these generation facilities. 821 MW is mostly contracted until 2022 with government-
owned distribution companies and large customers.
AES has a strategic partnership with the Estrella and Linda Groups ("Estrella-Linda"), a consortium of two
leading Dominican industrial groups that manage a diversified business portfolio.
Itabo is 42.5% owned by AES. Itabo owns and operates two thermal power generation units with a total of 295
MW of installed capacity.
Andres and Los Mina are owned 85% by AES. Andres has a combined cycle natural gas turbine, an energy
storage solution and generation capacity of 329 MW as well as the only LNG import facility in the country, with
160,000 cubic meters of storage capacity. Los Mina has a combined cycle with two natural gas turbines, an energy
storage solution and generation capacity of 368 MW.
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 delivery 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.
Key Financial Drivers — Financial results are 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 2019; and
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.
Panama
Regulatory Framework and Market Structure — The Panamanian power sector is composed of three distinct
operating business units: generation, distribution and transmission. 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. Generators can
only contract up to their firm capacity.
Three main agencies are responsible for monitoring compliance with the General Electricity Law:
• 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
regulate the procurement of energy and hydrocarbons 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, the transmission and
distribution of natural gas utilities, and the companies that provide such services.
• 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. Short-term power prices are determined on an hourly basis by
the last dispatched generating unit. Physical generation of energy is determined by the National Dispatch
Center regardless of contractual arrangements.
Panama's current total installed capacity is 3,501 MW, composed primarily of hydroelectric (49%) and thermal
(40%) generation.
Business Description — AES owns and operates five hydroelectric plants and two thermoelectric power
plants, Estrella del Mar I and Colon, representing 705 MW and 453 MW of hydro and thermal capacity, respectively
and 33% of the total installed capacity in Panama.
The majority of hydroelectric plants in Panama are based on run-of-river technology, with the exception of the
260 MW Bayano plant. Hydrological conditions have an important influence on profitability. Variations in hydrology
31
can result in excess or a shortfall in energy production relative to our contract obligations. Hydro generation is
generally in a shortfall position during the dry season from January through May, while thermal assets are expected
to be in a long position as their behavior is opposite and complimentary to hydro generation.
Both hydro and thermal assets are mainly contracted through medium- to long-term PPAs with distribution
companies. A small volume of contracts are with unregulated users.
Hydro assets in Panama have PPAs with distribution companies up to December 2030 for a total contracted
capacity of 350 MW. Thermal assets in Panama have PPAs with distribution companies for a total contracted
capacity of 430 MW, of which 80 MW will expire in June 2020 and 350 MW will expire in December 2028.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
•
•
•
•
changes in hydrology which impacts commodity prices and exposes the business to variability in the cost of
replacement power;
fluctuations in commodity prices, mainly oil and natural gas, affect the cost of thermal generation and spot
prices;
constraints imposed by the capacity of the transmission lines connecting the west side of the country with
the load, keeping surplus power trapped during the wet season; and
country demand as GDP growth is expected to remain strong over the short and medium term.
Construction and Development — In August 2015, AES executed a partnership agreement with Deeplight
Corporation, a minority partner, 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. The combined cycle natural gas power generation plant
initiated operations in September 2018 and the liquefied natural gas storage and regasification facility is scheduled
for completion in the second half of 2019.
Mexico
Regulatory Framework and Market Structure — Mexico has a single electric grid, the National Electricity
System, covering all of Mexico's territory through the Interconnected National Electricity, Baja California and
Southern Baja California Systems. The market comprises generation, transmission, distribution and
commercialization segments.
Three main agencies, in addition to the Ministry of Energy, are responsible for monitoring compliance with the
Electric Industry Law:
• The Energy Regulatory Commission is responsible for the establishment of directives, orders,
methodologies and standards oriented to regulate the electric and fuel markets.
• The National Center for Energy Control, 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.
• The CFE owns the transmission and distribution grids and it is also the country's basic supplier. CFE is the
offtaker for IPP generators, and together with its own power units has more than 50% of the current
generation market share.
Mexico has an installed capacity totaling 74 GW with a generation mix primarily comprising of thermal (71%)
and hydroelectric (17%) plants.
Business Description — AES has 1,055 MW of installed capacity in Mexico. The TEG and TEP pet coke-fired
plants, located in Tamuin, 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 CFE under a
capacity and energy based long-term PPA through 2025. Additionally, the plant purchases natural gas and diesel
under a long-term contract with one of the CFE’s subsidiaries, the cost of which is then passed through to CFE
under the terms of the PPA.
32
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
•
•
as the companies are fully contracted, improved operational performance provides additional benefits,
including performance incentives and/or excess energy sales; and
changes in the methodology to calculate spot energy prices, which impacts the excess energy sales to
CFE.
Construction and Development — AES has partnered in a joint venture with Grupo BAL to co-invest in power
and related infrastructure projects in Mexico, focusing on renewable and natural gas generation. The first
development, a 306 MW wind project, began construction in 2018 and is expected to be completed in 2020.
Eurasia SBU
Generation — Our Eurasia SBU has generation facilities in six countries. Operating installed capacity totaled
4,578 MW. The following table lists our Eurasia SBU generation facilities:
Business
Location
Fuel
Gross
MW
AES
Equity
Interest
100%
89%
49%
60%
37%
36%
Year Acquired
or Began
Operation
Contract
Expiration
Date
Customer(s)
2011
2010
1998
2019
2009
2014
2026
2025
Natsionalna Elektricheska
Natsionalna Elektricheska
2026
GRID Corporation Ltd.
2033
2039
National Electric Power
Company
National Electric Power
Company
100%
2015
Bulgaria
Bulgaria
India
India
Jordan
Jordan
Netherlands
Coal
Wind
Coal
Energy
Storage
Gas
Heavy
Fuel Oil
Energy
Storage
United Kingdom Gas
United Kingdom Coal/Oil
690
156
846
420
10
430
381
250
631
10
10
708
701
Maritza
St. Nikola
Bulgaria Subtotal
OPGC (1)
Delhi ES
India Subtotal
Amman East
IPP4
Jordan Subtotal
Netherlands ES
Netherlands Subtotal
Ballylumford (2)
Kilroot (3)
Kilroot ES
United Kingdom
Subtotal
Mong Duong 2
Vietnam Subtotal
100%
99%
2023
Power NI/I-SEM
I-SEM
2010
1992
2015
United Kingdom Energy
Storage
10
100%
Vietnam
Coal
1,419
1,242
1,242
4,578
51%
2015
2040
EVN
_____________________________
(1)
(2)
(3)
Unconsolidated entity, the results of operations of which are reflected in Equity in Earnings of Affiliates.
The Ballylumford B Station began the process for a safe shutdown in December 2018.
Includes Kilroot Open Cycle Gas Turbine.
Under construction — The following table lists our plants under construction in the Eurasia SBU:
Business
Location
Fuel
OPGC 2 (1)
AM Solar
India
Jordan
Coal
Solar
_____________________________
(1)
Unconsolidated entity, accounted for as an equity affiliate.
Gross MW AES Equity Interest
49 %
1,320
52
1,372
36 %
Expected Date of Commercial Operations
1H 2019
2H 2019
In March 2018, the Company completed the sale of its entire 51% ownership interest in Masinloc, a 630 MW
coal-fired plant located in the Philippines. Prior to its sale, Masinloc was accounted for as a consolidated entity and
its results were included in our operations as we had a controlling interest in the business.
33
The following map illustrates the location of our Eurasia facilities:
Eurasia Businesses
Bulgaria
Regulatory Framework and Market Structure — The electricity sector in Bulgaria allows both regulated and
competitive segments. NEK, the state-owned electricity public supplier and energy trading company, acts as a
single buyer and seller for all regulated transactions on the market. Electricity outside the regulated market trades
on one of the platforms of the Independent Bulgarian Electricity Exchange day-ahead market, intra-day market or
bilateral contracts market. Bulgaria is working with the European Commission on a model that will allow the gradual
phase-out of regulated energy prices.
Bulgaria’s power sector is supported by a diverse generation mix, universal access to the grid, and numerous
cross-border connections in neighboring countries. In addition, it plays an important role in the energy balance in
the Balkan region.
Bulgaria has 12 GW of installed capacity enabling the country to meet and exceed domestic demand and
export energy. Installed capacity is 37% coal-fired and 17% nuclear.
Business Description — Our Maritza plant is a 690 MW lignite fuel thermal power plant. Maritza's entire power
output is contracted with NEK under a 15-year PPA, expiring in May 2026. Since the renegotiation of the PPA in
April 2016, Maritza has been collecting receivables from NEK in a timely manner. However, NEK's liquidity position
remains subject to political conditions and regulatory changes in Bulgaria.
The DG Comp is reviewing NEK’s PPA with Maritza pursuant to the European Commission’s state aid rules.
Maritza believes that its PPA is legal and in compliance with all applicable laws. See Item 7. —Management's
34
Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties—
Regulatory.
AES also owns an 89% economic interest in the St. Nikola wind farm with 156 MW of installed capacity.
Through December 31, 2018, the entire power output of the St. Nikola wind farm was contracted under a 15-year
PPA with NEK. Starting January 1, 2019, the power output of St. Nikola is sold on the Independent Bulgarian
Electricity Exchange and the plant receives additional revenue per the terms of an October 2018 Contract for
Premium with the state-owned Electricity Security Fund.
Environmental Regulation — Best Available Techniques Reference Document for Large Combustion Plants
(BREF LCP), the new EU environmental standards regulating emissions from the combustion of solid fuels for large
combustion plants, was enacted in August 2017 and applies to Maritza. Impacted power plants are required to
either meet the new standards or be granted a derogation by August 2021. Maritza requested such derogation from
the Bulgarian environmental authorities in 2018, and expects to receive a response in 2019. If derogation is not
received Maritza would seek to pass through the compliance costs to the off-taker pursuant to the PPA.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
•
•
•
•
•
regulatory changes to the Bulgaria power market;
results of the DG Comp review;
the availability of the operating units;
the level of wind resources for St. Nikola;
spot market price volatility beyond the level of compensation through the Contract for Premium for St.
Nikola; and
• NEK's ability to meet the payment terms of the PPA contract.
United Kingdom
Regulatory Framework and Market Structure — AES UK operates in the Integrated Single Electricity Market
("I-SEM") in Northern Ireland. The I-SEM is the wholesale electricity market arrangement operating in the Republic
of Ireland and Northern Ireland starting October 1, 2018, replacing the previously existing SEM. The I-SEM market
arrangements are designed to integrate the Irish All Island electricity market with European electricity markets
enabling the free flow of energy across borders, creating increased levels of competition and increased security of
supply.
The Single Electricity Market Operator facilitates the continuous operation and administration of the I-SEM.
The organization is managed as a contractual joint venture between EirGrid, the transmission system operator for
the Republic of Ireland, and the System Operator for Northern Ireland. The Single Electricity Market Operator is
licensed and regulated cooperatively by the Commission for Energy Regulation in the Republic of Ireland and the
Northern Ireland Authority for Utility Regulation.
In addition, the I-SEM has a competitive capacity payment mechanism to ensure that sufficient generating
capacity is offered to the market. The first competitive capacity auction for the capacity year May 2018 to
September 2019 was completed in January 2018. The second capacity auction for the capacity year October 2019
to September 2020 was completed on February 1, 2019.
Since the introduction of I-SEM in October 2018, new instruments such as day-ahead, intra-day and
balancing markets were introduced to reflect integration with EU energy markets. The system support services
market was also reformed in May 2018 through the introduction of DS3, a competitive services market where
participants are required to complete a separate qualification process.
Northern Ireland's power sector is supported by a diverse generation mix, a stable regulatory environment,
universal access to the grid, and connections between the Republic of Ireland, Northern Ireland and the remainder
of the UK. Installed capacity in the I-SEM is 41% gas fired and 38% from renewable sources, resulting in sensitivity
to gas prices relative to order of merit. I-SEM has also set a target of 40% renewable generation by 2020.
Business Description — AES has two generation plants in the UK, Kilroot and Ballylumford, both of which are
located in Northern Ireland within the Greater Belfast region.
Kilroot is a 701 MW coal-fired merchant plant, with an additional 10 MW of energy storage, that bids into the I-
SEM. Kilroot's coal fired units failed to clear in the first I-SEM capacity auction process finalized in January 2018.
Consequently, AES announced its intent to shut down the coal units, pending the results of an assessment by the
35
regulator to determine the long term needs of the Northern Ireland power grid. In November 2018, Kilroot's Unit 1
was awarded the 12 month System Support Service Agreement for the period October 2018 to September 2019. In
addition, the Company also decided to transfer the capacity contract awarded to Ballylumford Unit 4 to Kilroot Unit
2. As a result, the decision to shut down both Kilroot coal units was reversed.
Ballylumford is a 708 MW gas-fired plant, of which 592 MW is contracted under a PPA with Power NI Power
Procurement Business expiring in 2023. The 116 MW remaining capacity is bid into the I-SEM market.
Ballylumford's B station Unit 5 failed to clear the aforementioned I-SEM capacity auction while Unit 4’s capacity
contract was transferred to Kilroot. As a result, AES stopped generation at Ballylumford's B station in late 2018, and
ongoing work to safely shut down the station is expected to be completed in early 2019.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
•
•
regulatory changes to the market structure and payment mechanisms;
investments to maintain compliance with EU environmental legislation;
• weather conditions impacting availability of growing renewables generation;
•
•
availability of the operating units and trading strategy;
commodity and FX prices (gas, coal, CO2) and sufficient market liquidity to hedge prices in the short-term;
and
•
electricity demand in the I-SEM (including impact of wind generation).
Jordan
Regulatory Framework and Market Structure — The Jordan electricity transmission market is a single-buyer
model with the state owned NEPCO responsible for transmission. NEPCO generally enters into long-term power
purchase agreements with IPP's to fulfill energy procurement requests from distribution utilities. The sector is
prioritizing renewable energy development, with 2,200 MW of renewable energy installed capacity expected by
2020, 940 MW of which is already connected to the grid.
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 expiring in 2033, and a 36% controlling interest in
the IPP4 plant, a 250 MW oil/gas-fired peaker plant, fully contracted with the national utility until 2039. We
consolidate the results in our operations as we have controlling interest in these businesses.
Construction and Development — AES, in conjunction with Mitsui & Co of Japan and NEBRAS Power of
Qatar, have signed an agreement to construct a 52 MW solar project in Jordan. The plant is currently under
construction, and is expected to be completed by mid 2019 to coincide with the start of a PPA to provide energy to
NEPCO through 2038.
India
Regulatory Framework and Market Structure — The power sector is comprised of state and central
government-owned and privately-owned generation and distribution utilities. Electricity is sold to state utilities mostly
under long-term PPAs and about 10% of electricity is sold in the short-term market, for example, traded on an
energy exchange or through competitively bid bilateral contracts. The tariffs are fixed on yearly basis by the
Electricity Regulatory Commissions Central / State(s) for the long-term PPAs or determined through a competitive
bidding process. OERC regulates the electricity purchase process for the distribution licensees, including the price
at which the electricity from generating companies shall be procured for supply within the state of Orissa. OERC
also facilitates intrastate transmission and wheeling of electricity. The electricity regulatory commissions are guided
by the Electricity Act, National Electricity Policy, National Electricity Plan and Tariff Policy issued by the Government
of India.
The power sector in India is composed of coal, gas, hydroelectric, renewable and nuclear energy. Total
installed capacity as of December 31, 2018 was 349 GW, of which 64% is thermal generation. Renewable energy is
adding capacity at a rapid pace and currently represents 21% of the total installed capacity. The remaining capacity
is nuclear (2%) and hydro (13%).
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. OPGC is an unconsolidated entity and
results are reported as Net equity in earnings of affiliates on our Consolidated Statements of Operations.
36
Construction and Development — AES has one 1,320 MW coal-fired project under construction, which is
expected to begin operations in the first half of 2019. As of December 31, 2018, total capitalized costs at the project
level were $1.3 billion. Once becoming operational, 75% of the expansion installed capacity is contracted with
GRIDCO for a period of four years through 2023 and 100% for the next 25 years through 2048. A separate trading
agreement is being negotiated for the remaining 25% of capacity to be sold in the trading market by GRIDCO on
behalf of OPGC during the first four years following commencement of operations.
Environmental Regulation — The Ministry of Environment, Forest and Climate Change in India amended the
Environment (Protection) Rules with stricter emission limits for thermal power plants through 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 onwards are
required to operate within the revised emission limits. As a result of this amendment, Selective Catalytic Rectifier
and Flue Gas Desulphurisation systems are to be installed in the existing OPGC units to comply with the new NOX
and SO2 emissions limits. The hardware to be installed to meet the tightened emission requirements will require
substantial investment by OPGC. We believe the cost of complying with the new environmental regulations for
particulate matters, water consumption, SOx and NOx limits will be a pass-through in the OERC prescribed tariff
regulations for both the existing and expansion units.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to:
•
•
•
operating performance of the facility;
regulatory and environmental policy changes;
tariff determination by the OERC; and
• PPA provisions and energy trading.
Vietnam
Regulatory Framework and Market Structure — The Ministry of Industry and Trade in Vietnam is primarily
responsible for formulating a program to restructure the power industry, developing the electricity market, and
promulgating electricity market regulations. The fuel supply is owned by the government through Vinacomin, a
state-owned entity, and Petro Vietnam.
The Vietnam power market is divided into three regions (North, Central and South), with total installed capacity
of approximately 47 GW. The fuel mix in Vietnam is composed primarily of hydropower at 42% and coal at 37%.
EVN, the national utility, owns 60% of installed generation capacity.
The government is in the process of realigning EVN-owned companies into three different independent
operations in order to create a competitive power market. A competitive electricity market has already been
established. A pilot competitive wholesale electricity market has been developed, and will be implemented over the
next five years. The retail market will undergo similar reforms after 2022. BOT power plants will not directly
participate in the power market; however, their dispatch will be impacted by the merit order
Business Description — Mong Duong II is a 1,242 MW gross coal-fired plant located in Quang Ninh Province
of Vietnam and was constructed under a BOT service concession agreement expiring in 2040. This is the first and
largest coal-fired BOT plant using pulverized coal-fired boiler technology in Vietnam. The BOT company has a PPA
with EVN and a Coal Supply Agreement with Vinacomin both expiring in 2040.
Key Financial Drivers — Financial results are driven by many factors, including, but not limited to, the
operating performance and availability of the facility.
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 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; Several of our businesses are subject to potentially significant remediation expenses,
enforcement initiatives, private party lawsuits and reputational risk associated with CCR; Our businesses are
subject to stringent environmental laws, rules and regulations; and Concerns about GHG emissions and the
37
potential risks associated with climate change have led to increased regulation and other actions that could impact
our businesses 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 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 combined fluidized bed 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. The Company 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 United States, 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 required significant reductions in SO2
and NOX emissions from power plants in many states in which subsidiaries of the Company operate. The Company
is required to comply with the CSAPR in several states, including Ohio, Indiana, Oklahoma and Maryland. 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 Company complies with CSAPR
through operation of existing controls and purchases of allowances on the open market, as needed.
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 started in the 2017 ozone
season (May-September 2017). Affected facilities began to receive fewer ozone season NOx allowances in 2017,
resulting in the need to purchase additional allowances. While the Company's 2017 and 2018 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, but it could be material if certain facilities will need to purchase additional
allowances based on reduced allocations.
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. Over the past several years, the EPA has filed
suits against coal-fired power plant owners and issued 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
38
and regulatory action, including a NOV issued by the EPA against IPL concerning NSR and prevention of significant
deterioration issues under the CAA.
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.
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" toward 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 would require 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. In September 2017, the EPA published a final rule affirming the continued validity of the
EPA's previous determination allowing states to rely on the CSAPR to satisfy BART requirements. All of the
Company’s facilities that are subject to BART comply by meeting the requirements of CSAPR.
The second phase of the Regional Haze Rule begins in 2019. States must submit regional haze plans for this
second implementation period in 2021 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 air 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 attain or maintain 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.
Beginning January 1, 2017, IPL Petersburg has been required to meet reduced SO2 limits established in a final
rule published by IDEM in 2015 in accordance with a new one-hour SO2 NAAQS of 75 parts per billion.
Improvements to the existing FGD systems at IPL’s Petersburg station were required to meet the emission limits
imposed by the rule. The IURC approved IPL’s request for NAAQS SO2 compliance at its Petersburg generation
station with 80% of qualifying costs recovered through a rate adjustment mechanism and the remainder recorded
as a regulatory asset for recovery in a subsequent rate case. The approved capital cost of the NAAQS SO2
compliance plan is approximately $29 million. On August 15, 2018, EPA proposed to approve Indiana’s State
Implementation Plan addressing attainment of the 2010 SO2 standard for certain locations including those of IPL's
Petersburg Generating Stations.
Greenhouse Gas Emissions — In January 2011, the EPA began regulating GHG emissions from certain
stationary sources, including pre-construction permitting program for certain new construction or major
modifications, known as the PSD. If future modifications to our U.S.-based businesses' sources become subject to
PSD for other pollutants, it may trigger GHG BACT requirements and the cost of compliance with such
requirements may be material.
On October 23, 2015, the EPA's rule establishing NSPS for new electric generating units became effective
establishing CO2 emissions standards for newly constructed coal-fueled electric generating plants, which reflects
the partial capture and storage of CO2 emissions from the plants. 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 could have an impact on the Company's plans to construct and/or modify or reconstruct
electric generating units in some locations. On December 20, 2018, EPA published proposed revisions to the final
NSPS for new, modified and reconstructed coal-fired electric utility steam generating units proposing that the Best
System of Emissions Reduction for these units is highly efficient generation that would be equivalent to supercritical
39
steam conditions for larger units and sub-critical steam conditions for smaller units, and not partial carbon capture
and sequestration, as was finalized in the 2015 final NSPS. EPA did not include revisions for natural-gas combined
cycle or simple cycle units in the December 20, 2018 proposal.
On December 22, 2015, the EPA finalized CO2 emission rules for existing power plants under Clean Air Act
Section 111(d) (called the CPP). 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. The full impact of
the CPP would 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. Pursuant to a court order
issued in August 2017, the litigation is being held in indefinite abeyance pending further court order.
In addition, on February 9, 2016, the U.S. Supreme Court issued orders staying implementation of the CPP
pending resolution of challenges to the rule. Challenges to both the CPP and the GHG NSPS are being held in
abeyance at this time. On October 16, 2017, the EPA published in the Federal Register a proposed rule that would
rescind the CPP. On December 28, 2017, the EPA published an Advance Notice of Proposed Rulemaking to solicit
comments as EPA considers a potential rule to establish emission guidelines to replace the CPP and limit GHG
emissions from existing electric generating units under Section 111(d) of the CAA.
On August 31, 2018, the EPA published in the Federal Register proposed Emission Guidelines for Greenhouse
Gas Emissions from Existing Electric Utility Generating Units, known as the Affordable Clean Energy (ACE) Rule. In
addition, the EPA proposed associated revisions to implementing regulations and the New Source Review program.
The proposed ACE Rule would replace the EPA’s 2015 Clean Power Plan and proposes to determine that heat rate
improvement measures are the best system of emission reduction for existing coal-fired electric generating units.
Due to the future uncertainty of the CPP or potential replacement rule, we cannot at this time determine the
impact on our operations or consolidated financial results, but we believe the cost to comply with the CPP, should it
be upheld and implemented in its current or a substantially similar form, could be material. The GHG NSPS remains
in effect at this time, and, absent further action from the EPA that rescinds or substantively revises the NSPS, it
could impact any Company plans to construct and/or modify or reconstruct electric generating units in some
locations, which may have a material impact on our business, financial condition or results of operations.
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. These standards
require certain subject facilities 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 which site-specific controls, if any, are required to reduce entrainment. It is
possible that this decision-making process, which includes permitting and public input, 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. 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 is to comply with the SWRCB OTC Policy by shutting down and permanently
retiring all existing generating units at AES Alamitos, AES Huntington Beach and AES Redondo Beach that utilize
OTC by December 31, 2020, the compliance date included in the OTC Policy. 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 there is currently no plan to replace the OTC generating units at the AES Redondo
Beach generating station. 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 information on OTC generating unit retirement dates and
40
new generation availability 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. Construction of new generating capacity began in June 2017 at AES Huntington Beach and July 2017
at AES Alamitos. Construction at both sites is on schedule and will require the following existing OTC units to retire
earlier than December 31, 2020 to provide interconnection capacity and/or emissions credits prior to startup of the
new generating units:
• Redondo Beach Unit 7 - September 30, 2019
• Huntington Beach Unit 1 - December 31, 2019
• Alamitos Units 1, 2, and 6 - December 31, 2019
The remaining AES OTC generating units in California will be shutdown and permanently retired by December 31,
2020.
Power plants are 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 were filed and consolidated in the U.S. Court of Appeals for the Second
Circuit, although implementation of the rule was not stayed while the challenges proceeded. On July 23, 2018, the
U.S. Court of Appeals for the Second Circuit upheld the rule. The Second Circuit later denied a petition by
environmental groups for rehearing. The Company anticipates that compliance with CWA Section 316(b)
regulations and associated costs could have a material impact on our consolidated financial condition or results of
operations.
Water Discharges — 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 United States. This rule, which initially became effective on August
28, 2015, may expand or otherwise change the number and types of waters or features subject to federal
permitting. On June 27, 2017, the EPA proposed a rule that would rescind the “Waters of the United States” rule
and re-codify the definition of “Waters of the United States” that existed prior to the 2015 rule. However, on
February 6, 2018, the EPA published a final rule to delay the original effective date of the 2015 “Waters of the
United States” to February 6, 2020, which allows the EPA to create a new rule in the interim period without the 2015
rule taking effect. On June 29, 2018, the agencies signed a supplemental notice of proposed rulemaking clarifying
that the proposal is to permanently repeal the 2015 Rule. We cannot predict the outcome of the judicial challenges
to the rule or the regulatory process to rescind the rule, but if the “Waters of the United Sates” rule is ultimately
implemented in its current or substantially similar form and survives legal challenges, it could have a material
impact on our business, financial condition or results of operations. On February 14, 2019, the agencies published a
proposed rule to revise the definition of the “Waters of the United States.” We are reviewing the December 11, 2018
proposed rule and it is too early to determine whether this might have a material impact on our business, financial
condition or results of operations.
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 United
States under the CWA.
On August 28, 2012, the IDEM issued NPDES permits that set new water quality-based effluent discharge
limits for the IPL Harding Street and Petersburg facilities with full compliance ultimately required by September 29,
2017. The deadline for Petersburg to commission a portion of the treatment system was subsequently extended to
April 11, 2018.
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. The required compliance time lines for existing sources was to be established between November 1,
2018 and December 31, 2023. On September 18, 2017, the EPA published a final rule delaying certain compliance
dates of the ELG rule for two years while it administratively reconsiders the rule. IPL Petersburg has installed a dry
bottom ash handling system in response to the CCR rule described below and wastewater treatment systems in
response to the NPDES permits described above in advance of the ELG compliance date. As a result of the
decision to retire Stuart and Killen generating stations, we do not expect the ELG rule to have a material impact on
these two stations. While we are still evaluating the effects of the rule on our other U.S. businesses, we anticipate
41
that the implementation of its current requirements could have a material adverse effect on our results of
operations, financial condition and cash flows, and a postponement or reconsideration of the rule that leads to less
stringent requirements would likely offset some or all of the adverse effects of the rule.
Selenium Rule — In June 2016, the EPA published the final national chronic aquatic life criterion for the
pollutant Selenium in fresh water. 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 polychlorinated biphenyl
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, including location restrictions, design and operating criteria,
groundwater monitoring, corrective action and closure requirements and post-closure care. The primary
enforcement mechanisms under this regulation would be actions commenced by the states and private lawsuits. On
December 16, 2016, the Water Infrastructure Improvements for the Nation Act ("WIN Act") was signed into law. This
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 EPA has indicated that it will implement a phased approach to
amending the CCR Rule. It is too early to determine whether the results of the groundwater monitoring data or the
outcome of CCR litigation or a potential CCR Remand Rule may have a material impact on our business, financial
condition or results of operations.
The existing ash ponds at the Petersburg Station did not meet certain structural stability requirements set forth
in the CCR rule. As such, the Company was ultimately required to cease use of all ash ponds at Petersburg by
November 11, 2018.
Comprehensive Environmental Response, Compensation and Liability Act of 1980 — This act, also know as
"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. The 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.
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 2018 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.
42
Executive Officers
The following individuals are our executive officers:
Sanjeev Addala, 53 years old, was appointed Chief Information and Digital officer in October 2018. Prior to
joining AES, Mr. Addala was Chief Digital Officer at GE from 2016 to September 2018, Chief Digital Officer at
Caterpillar from 2013 to 2015, and Chief Information Officer, Americas, Climate Control Technologies at Ingersoll-
Rand from 2008 to 2013. He also previously held business and technology leadership roles at General Motors from
1994 to 2008. He served on Energize Ventures and AppLariat advisory Boards. Mr. Addala is a member of the
Board of AES Distributed Energy. Mr. Addala holds a Master of Science degree in Mechanical Engineering from
South Dakota School of Mines and Tech. and a Master of Business Administration degree from the Kellogg School
of Management at Northwestern University. Mr. Addala has also completed an Executive Leadership program at
Duke University.
Bernerd Da Santos, 55 years old, has been Chief Operating Officer and Executive Vice President since
December 2017. Previously, Mr. Da Santos held several positions at the Company, including Chief Operating
Officer and Senior Vice President from 2014 to 2017, Chief Financial Officer, Global Finance Operations from 2012
to 2014, Chief Financial Officer of Global Utilities from 2011 to 2012, Chief Financial Officer of Latin America and
Africa from 2009 to 2011, Chief Financial Officer of Latin America from 2007 to 2009, Managing Director of Finance
for Latin America from 2005 to 2007 and VP and Controller of La Electricidad de Caracas ("EDC") (Venezuela).
Prior to joining AES in 2000, Mr. Da Santos held a number of financial leadership positions at EDC. Mr. Da Santos
is the chairman of AES Gener in Chile and a member of the Board of Companhia Brasiliana de Energia, AES Tietê,
Compañia de Alumbrado Electrico de San Salvador, Empresa Electrica de Oriente, Compañia 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.
Manuel Pérez Dubuc, 55 years old, has served as Senior Vice President, Global New Energy Solutions since
October 2018. Previously Mr. Pérez Dubuc served as the President of the South America SBU from March 2018 to
October 2018 and President of the MCAC SBU from November 2012 to March 2018. He also served as Vice
President and General Manager AES North Asia, President of AES Dominicana and Chief Financial Officer of EDC.
Mr. Pérez Dubuc is a member of the Boards of SPower, AES Gener, AES Tiete, Fluence and EnerAB, Ron Santa
Teresa SACA and GFR Group Advisory board. Prior to joining AES, Mr. Pérez Dubuc served as a Chairman and
CEO of Meiya Power Company based in Hong Kong. Mr. Pérez Dubuc studied electrical engineering at the
Universidad Simon Bolivar and with a master’s degree in business administration from IESA (Instituto de Estudios
Superiores de Administración) of Caracas, Venezuela. He attended the Executive Leadership Program at the
University of Virginia’s Darden School of Business and the Global Executive Leadership Program at Georgetown
University’s McDonough School of Business in 2015.
Paul L. Freedman, 48 years old, has been Senior Vice President and General Counsel since February 2018
and was appointed Corporate Secretary in October 2018. Prior to assuming his current position, Mr. Freedman
served as Chief of Staff to the Chief Executive Officer from April 2016 to February 2018, Assistant General Counsel
from 2014 to 2016, General Counsel, North America Generation, from 2011 to 2014, Senior Corporate Counsel
from 2010 to 2011 and Counsel 2007 to 2010. Mr. Freedman is a member of the Boards of IPALCO, AES U.S.
Investments, DP&L, Fluence and the Business Council for International Understanding. Prior to joining AES, Mr.
Freedman was Chief Counsel for credit programs at the U.S. Agency for International Development and he
previously worked as an associate at the law firms of White & Case, LLP and Freshfields. Mr. Freedman received a
B.A. from Columbia University and a J.D. from the Georgetown University Law Center.
Andrés R. Gluski, 61 years old, has been President, Chief Executive Officer and a member of our Board of
Directors since September 2011 and is a member of the Innovation and Technology Committee. Prior to assuming
his current position, Mr. Gluski served as Executive Vice President and Chief Operating Officer of the Company
since March 2007. Prior to becoming the Chief Operating Officer of AES, Mr. Gluski was Executive Vice President
and the Regional President of Latin America from 2006 to 2007. Mr. Gluski was Senior Vice President for the
Caribbean and Central America from 2003 to 2006, Chief Executive Officer of EDC from 2002 to 2003 and Chief
Executive Officer of AES Gener (Chile) in 2001. Prior to joining AES in 2000, Mr. Gluski was Executive Vice
President and Chief Financial Officer of EDC, Executive Vice President of Banco de Venezuela (Grupo Santander),
Vice President for Santander Investment, and Executive Vice President and Chief Financial Officer 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 to 2016,
Mr. Gluski served on President Obama's Export Council. Mr. Gluski is a member of the Board of Waste
43
Management and AES Gener in Chile. Mr. Gluski is also Chairman of the Americas Society/Council of the Americas,
and Director of the Edison Electric Institute. 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.
Lisa Krueger, 55 years old, has served, as Senior Vice President and President of the US SBU since
September 2018. Prior to joining AES, Ms. Krueger served as an energy consultant from July 2017 to August 2018,
Chief Commercial Officer of Cogentrix Energy Power Management, LLC, the portfolio management company of
Carlyle Power Partners, from January 2017 to June 2017, and President and Chief Executive Officer of Essential
Power, LLC from March 2014 to June 2017. Ms. Krueger also served as Vice President - Sustainable Development
of First Solar, one of the world’s largest photovoltaic manufacturers and system integrators, where she led the
development and implementation of various domestic and internal strategic plans focused on market and business
development and served as the President of First Solar Electric. Prior to First Solar, Ms. Krueger held a variety of
executive level positions with Dynegy, Inc., including Vice President - Enterprise Risk Control, Vice President -
Northeast Commercial Operations, Vice President - Origination and Retail Operations, and Vice President,
Environmental, Health & Safety. She also held a variety of leadership roles at Illinois Power, including positions in
transmission planning and system operations, generation planning and system operations, and environmental,
health & safety. Ms. Krueger has a Bachelor of Science degree in Chemical Engineering from the Missouri
University of Science and Technology and a Master of Business Administration degree from the Jones Graduate
School of Business at Rice University.
Tish Mendoza, 43 years old, is Chief Human Resources Officer and Senior Vice President, Global Human
Resources and Internal Communications since 2015. 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, D.C. Prior to
joining AES, Ms. Mendoza was Vice President of Human Resources for a product company in the Treasury
Services division of JP 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.
Leonardo Moreno, 39 years old, has served as Senior Vice President, Corporate Strategy and Investments
and Chief Risk Officer since May 2017. Previously Mr. Moreno served as the Chief Financial Officer, Europe SBU
from May 2015 to April 2017 and as a Managing Director on AES’ Mergers & Acquisitions team from January 2012
to April 2015. Since joining AES in 2006, Mr. Moreno has served in various positions throughout the Company. Mr.
Moreno serves as a member of the Board of DP&L and AES Tiete. Prior to joining AES Mr. Moreno worked for Ernst
& Young. Mr. Moreno has a degree in Business Administration from Universidade Federal de Minas Gerais, Brazil
and has completed executive business and leadership programs at the London Business School, Georgetown
University and the University of Virginia.
Julian Nebreda, 52 years old, has served as Senior Vice President and President of the South America SBU
since October 2018. Prior to assuming his current position Mr. Nebreda served as the President of the AES Brazil
SBU from April 2016 to October 2018, and President of the Europe SBU from June 2009 to April 2016. Prior to June
2009, Mr. Nebreda held several senior positions, such as Vice President for Central America and Caribbean, Chief
Executive Officer of EDC and President of AES Dominicana, in Santo Domingo, Dominican Republic. Mr. Nebreda
serves as Chairman of the Board of AES Gener and AES Tiete. Before joining AES, Mr. Nebreda has held positions
in the public and private sectors, namely he served as Counsellor to the Executive Director from Panama and
Venezuela at the Inter-American Development Bank. Mr. Nebreda earned a law degree from Universidad Católica
Andrés Bello in Caracas, Venezuela. He also earned a Master of Laws in Common Law with a Fulbright Fellowship
and a Master of Laws in Securities and Financial Regulations, both from Georgetown University.
Gustavo Pimenta, 40 years old, was appointed Executive Vice President and Chief Financial Officer effective
January 1, 2019. Prior to assuming his current position, Mr. Pimenta served as Deputy Chief Financial Officer from
February 2018 to December 2018, Chief Financial Officer for the Company’s MCAC SBU from December 2014 to
February 2018 and as Chief Financial Officer of AES Brazil from 2013 to December 2014. Prior to joining AES in
2009, Mr. Pimenta held various positions at Citigroup, including Vice President of Strategy and M&A in London and
New York City. Mr. Pimenta received a Bachelor’s degree in Economics from Universidade Federal de Minas Gerais
and a Master’s degree in Economics and Finance from Fundação Getulio Vargas. He also participated in
development programs in Finance, Strategy and Risk Management at New York University, University of Virginia’s
Darden School of Business and Georgetown University.
44
Juan Ignacio Rubiolo, 42 years old, has served Senior Vice President and President of the MCAC SBU
since March 2018. Previously Mr. Rubiolo served as the Chief Executive Officer of AES Mexico from 2014 to March
2018 and as a Vice President on the Commercial team of the MCAC SBU from 2013 to 2014. Mr. Rubiolo joined
AES in 2001 and has worked in AES businesses in the Philippines, Argentina, Mexico, Panama and the Dominican
Republic. Mr. Rubiolo serves on the Boards of AES Gener, Itabo, AES Andres, and AES Panama. Mr. Rubiolo has a
Science Degree in Business from the Universidad Austral of Argentina, a Master of Project Management from the
Quebec University in Canada and has completed the executive business and leadership program at the University
of Virginia.
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. 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 8, 2018.
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
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 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 indebtedness and financial condition;
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 Indebtedness and Financial Condition
We have a significant amount of debt, a large percentage of which is secured, that could adversely
affect our business and our ability to fulfill our obligations.
45
As of December 31, 2018, we had approximately $19 billion of outstanding indebtedness on a consolidated
basis. All outstanding borrowings, if any, under The AES Corporation's senior secured credit facility and secured
term loan 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 available for future
secured debt or credit support and reduces our flexibility in operating 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 our vulnerability to general adverse industry and economic conditions, including but not limited to
adverse changes in foreign exchange rates, interest rates and commodity prices;
reducing available 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. If we were to become more leveraged, the risks described 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. In addition, our ability to refinance existing or future indebtedness
will depend on the capital markets and our financial condition at such time. Any refinancing of our debt could come
at higher interest rates or may require us to comply with onerous covenants, which could restrict our business
operations. See Note 10.—Debt included in Item 8.—Financial Statements and Supplementary Data 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.
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. Business performance and local accounting and tax rules may also limit
dividend distributions. 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.
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.
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 that, 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
46
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, 2018, we had approximately $19.3 billion of outstanding indebtedness on a consolidated
basis, of which approximately $3.7 billion was recourse debt of The AES Corporation and approximately $15.6
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
$351 million as of December 31, 2018. 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:
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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 may have provided to
or on behalf of such subsidiary;
triggering defaults in The AES Corporation's outstanding debt. For example, The AES Corporation's senior
secured credit facility, secured term loan, 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; or
foreclosure on the assets that are pledged under the non-recourse loans, resulting in write-downs of assets
and 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.
The AES Corporation, or the Parent Company, has significant cash requirements and limited sources
of liquidity.
The AES Corporation requires cash primarily to fund:
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principal repayments of debt;
interest;
acquisitions;
construction and other project commitments;
other equity commitments, including business development investments;
equity repurchases and/or cash dividends on our common stock;
taxes; and
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The AES Corporation's principal sources of liquidity are:
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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, which could prove incorrect,
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. 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. In addition, our cash
flow may not be sufficient to repay at maturity the entire principal outstanding under our credit facility, term loan, 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 depends on our ability 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:
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general economic and capital market conditions;
the availability of bank credit;
the financial condition, performance and prospects of The AES Corporation in general and/or that of any
subsidiary requiring the financing;
the financial condition, performance and prospects of other companies in our industry or with similar
financial circumstances; and
changes in tax and securities laws which are conducive to raising capital.
Should 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 access to the capital markets, increase our interest costs and/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 development projects in certain less developed
economies, which could 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 may 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,
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and if they are not, we may have to abandon the relevant 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.
Some of our businesses sell electricity in the spot markets when they operate at levels in excess of their
power sales agreements or retail load obligations or when they do not have any powers sales agreements. 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 generally
reflect the variable cost of the source generation which could include renewable sources at near zero pricing or
thermal sources subject to fluctuating cost of fuels such as coal, natural gas or oil derivative fuels in addition to
other factors described below. Consequently, any changes in the generation supply stack 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:
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plant availability in the markets generally;
availability and effectiveness of transmission facilities owned and operated by third parties;
competition;
seasonality;
hydrology and other weather conditions;
illiquid markets;
transmission,transportation constraints, inefficiencies and/or availability;
renewables source contribution to the supply stack;
new entrants;
increased adoption of distributed generation;
energy efficiency and demand side resources;
available supplies of coal, natural gas, and crude oil and refined products;
generating unit performance;
natural disasters, terrorism, wars, embargoes, and other catastrophic events;
energy, market and environmental regulation, legislation and policies;
general economic conditions globally as well as in areas where we operate that impact demand and energy
consumption; and
bidding behavior and market bidding rules.
Adverse economic developments in China could have a negative impact on demand for electricity in
many of our markets.
The Chinese market has been driving global materials demand and pricing for commodities over the past
decade. Many of these commodities are produced in areas that are also our key markets for the sale of electricity.
After experiencing rapid growth for more than a decade, China’s economy has experienced decreasing foreign and
domestic demand, weak investment, factory overcapacity and oversupply in the property market, and has
experienced a significant slowdown in recent years. U.S. tariffs are also expected to have a negative impact on
China's economic growth. Continued slowing in China’s economic growth, demand for commodities and/or material
changes in policy could result in lower economic growth and lower demand for electricity in our key markets, which
could have a material adverse effect on our results of operations, financial condition and prospects.
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 several of our subsidiaries outside the United States 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
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where our subsidiaries outside the United States 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.
Wholesale power prices are declining in many markets and this could have a material adverse effect
on our operations and opportunities for future growth.
The wholesale prices offered for electricity have declined significantly in recent years in many markets in which
the Company has businesses. This price decline is due to a variety of factors, including the increased penetration of
renewable generation resources, low-priced natural gas and demand side management. The levelized cost of
electricity from new solar and wind generation sources has dropped substantially in recent years as solar panel
costs and wind turbine costs have declined, while wind and solar capacity factors have increased. These renewable
resources have no fuel costs and very low operational costs. In many instances, energy from these facilities are bid
into the wholesale spot market at a price of zero or close to zero during certain times of the day, driving down the
clearing price for all generators selling power in the relevant spot market. Also, in many markets new PPAs have
been awarded for renewable generation at prices significantly lower than the prices being awarded just a few years
ago.
This trend of declining wholesale prices could continue and could have a material adverse impact on the
financial performance of our existing generation assets to the extent they currently sell power into the spot market
or will seek to sell power into the spot market once their PPAs expire. The trend of declining prices can also make it
more difficult for us to obtain attractive prices under new long-term PPAs for any new generation facilities we may
seek to develop. As a result, the trend can have an adverse impact on our opportunities for new investments.
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
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 underlying exposure (usually the pricing node of the
generation facility). 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, while we seek to protect against that by
utilizing strong credit requirements and exchange trades, these protections may not fully cover the exposure in the
event of a counterparty default.
For our businesses with PPA pricing that does not completely 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 some 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.
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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. Counterparties to these agreements may breach or may be unable to perform their
obligations, due to bankruptcy, insolvency, financial distress or other factors. Furthermore, in the event of a
bankruptcy or similar insolvency-type proceeding, our counterparty can seek to reject our existing PPA under the
U.S. Bankruptcy Code or similar bankruptcy laws, including those in Puerto Rico. 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 financial performance of our facilities is dependent on the credit quality of, and continued performance by,
suppliers and customers. Any failure of a 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.
The market price of our common stock may be volatile.
The market price and trading volumes of our common stock could fluctuate substantially in the future. Factors
that could affect the price of our common stock include, among other factors, general conditions in our industry and
the power markets in which we participate, environmental and economic developments, and general credit and
capital markets conditions, as well as developments specific to us, including risks that could result in revenue and
earnings volatility, failing to meet our publicly announced guidance or other risk factors described in Item 1A.—Risk
Factors and key trends and other 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 United States, including in developing countries,
which presents significant risks.
A significant amount of our revenue is generated outside the United States 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. We believe these countries may have higher
growth rates and offer greater opportunities, 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:
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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, fiscal or environmental policies;
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;
unexpected delays in permitting and governmental approvals;
unexpected changes or instability affecting our strategic partners in developing countries;
risks relating to the failure to comply with the U.S. Foreign Corrupt Practices Act, UK Bribery Act or other
anti-bribery laws applicable to our operations, including, among other things, cost and disruption in
responding to allegations or investigations (regardless of ultimate finding), civil and/or criminal fines,
criminal prosecution of individuals, revocation or suspension of permits and/or licenses, civil litigation,
reputational damage, loss in share price, and loss of business;
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 less beneficial to counterparties, against
such counterparties, whether such counterparties are governments or private parties;
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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 are in the business of generating and distributing electricity, which involves certain risks that can adversely
affect financial and operating performance, including:
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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,
tsunamis, 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
liquidated damages and/or other penalties.
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.
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We and/or our subsidiaries may not have adequate risk mitigation and/or insurance coverage for
liabilities.
Power generation, distribution and transmission involves hazardous activities. We may from time to time
become exposed to significant liabilities for which we may not have adequate risk mitigation and/or insurance
coverage. 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. Our insurance does not cover every potential risk associated with our
operations. Adequate coverage at reasonable rates is not always obtainable and 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. 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 our business, results or operations, financial condition, and prospects.
We may not be able to enter into long-term contracts that reduce volatility in our results of operations.
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
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 more than 20 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 and renewables such as wind and
solar have also caused, and could continue to cause, price pressure in certain power markets where we sell or
intend to sell power. In addition, the introduction of low-cost disruptive technologies or the entry of non-traditional
competitors into our sector and markets could adversely affect our ability to compete, which could have a material
adverse effect on our businesses, operating results and financial condition.
Our businesses will need to continue to adapt to technological change and we may incur significant
expenditures to adapt to these changes.
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Emerging technologies may be superior to, or may not be compatible with, some of our existing technologies,
investments and infrastructure, and may require us to make significant expenditures to remain competitive, or may
result in the obsolescence of certain of our operating assets. Our future success will depend, in part, on our ability
to anticipate and successfully adapt to technological changes, to offer services and products that meet customer
demands and evolving industry standards.
Technological changes that could impact our businesses include:
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technologies that change the utilization of electric generation, transmission and distribution assets,
including the expanded cost-effective utilization of distributed generation (e.g., rooftop solar and community
solar projects), and energy storage technology;
advances in distributed and local power generation and energy storage that reduce the demand for large-
scale renewable electricity generation and/or impact our customers’ ability to perform under long-term
agreements; and
• more cost-effective batteries for energy storage, advances in solar or wind technology, and advances in
alternative fuels and other alternative energy sources.
Emerging technologies may also allow new competitors to more effectively compete in our markets or
disintermediate the services we provide our customers, including traditional utility and centralized generation
services. If we incur significant expenditures in adapting to technological changes, fail to adapt to significant
technological changes, fail to obtain access to important new technologies, fail to recover a significant portion of
any remaining investment in obsolete assets, or if implemented technology fails to operate as intended, our
businesses, operating results and financial condition could be materially adversely affected.
Certain of our businesses are sensitive to variations in weather and hydrology.
Our businesses are affected by variations in general weather patterns and unusually severe weather. Our
businesses forecast electric sales based on best available information and expectations for 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.
Changes in weather can also affect the production of electricity at power generation facilities, including, but not
limited to, our wind and solar facilities. For example, the level of wind resource affects the revenue produced by
wind generation facilities. Because the levels of wind and solar resources are variable and difficult to predict, our
results of operations for individual wind and solar facilities specifically, and our results of operations generally, may
vary significantly from period to period, depending on the level of available resources. To the extent that resources
are not available at planned levels, the financial results from these facilities may be less than expected.
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. Changes in temperature, precipitation and snow
pack conditions also could affect the amount and timing of hydroelectric generation.
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. Additionally, our contracts in
certain markets where hydroelectric facilities are prevalent may require us to purchase power in the spot markets
when our facilities are unable to operate (or operate at lower than anticipated levels) and the price of such spot
power may increase substantially in times of low hydrology.
Severe weather and natural disasters may present significant risks to our business and adversely
affect our financial results.
Weather conditions directly influence the demand for electricity and natural gas and other fuels and affect the
price of energy and energy-related commodities. In addition, severe weather and natural disasters, such as hurricanes,
floods, tornadoes, icing events, earthquakes, dam failures and tsunamis can be destructive and could prevent us from
operating our business in the normal course by causing power outages and property damage, reducing revenue,
affecting the availability of fuel and water, causing injuries and loss of life, and requiring us to incur additional costs,
for example, to restore service and repair damaged facilities, to obtain replacement power and to access available
financing sources. Our power plants could be placed at greater risk of damage should changes in the global climate
produce unusual variations in temperature and weather patterns, resulting in more intense, frequent and extreme
weather events, including heatwaves, fewer cold temperature extremes, abnormal levels of precipitation resulting in
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river and coastal urban floods in North America or reduced water availability and increased flooding across Central
and South America, and changes in coast lines due to sea level change.
Depending on the nature and location of the facilities and infrastructure affected, any such incident also could
cause catastrophic fires; releases of natural gas, natural gas odorant, or other greenhouse gases; explosions, spills
or other significant damage to natural resources or property belonging to third parties; personal injuries, health impacts
or fatalities; or present a nuisance to impacted communities. Such incidents that do not directly affect our facilities may
impact our business partners, supply chains and transportation, which could negatively impact construction projects
and our ability to provide electricity and natural gas to our customers.
A disruption or failure of electric generation, transmission or distribution systems or natural gas production,
transmission, storage or distribution systems in the event of a hurricane, tornado or other severe weather event, or
otherwise, could prevent us from operating our business in the normal course and could result in any of the adverse
consequences described above. At our businesses where cost recovery is available, recovery of costs to restore
service and repair damaged facilities is or may be subject to regulatory approval, and any determination by the regulator
not to permit timely and full recovery of the costs incurred.
Any of the foregoing could have a material adverse effect on our business, financial condition, results of operations,
reputation and prospects.
Our development projects are subject to substantial uncertainties.
Certain of our subsidiaries and affiliates are in various stages of developing and constructing power plants.
Some but not all of these power plant projects have signed long-term contracts or made similar arrangements for
the sale of electricity. Successful completion of the development of these projects 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 important elements for a
successful project. For example, our subsidiaries may instruct contractors to begin the construction process or seek
to procure equipment even where they do not have financing, a PPA or critical permits in place (or conversely, to
enter into a PPA, procurement agreement 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.
We do not control certain aspects of our joint ventures.
We have invested in some joint ventures in which 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 in which we do have majority control of the
voting securities, we have entered into shareholder agreements granting 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 that 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
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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, which means that we may be responsible for meeting
certain obligations of the joint ventures, should our joint venture partner be unable to do so, 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, solar, and energy storage projects are subject to substantial risks. 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. These wind resource estimates are not expected to reflect actual wind energy production in
any given year, but long-term averages of a resource.
As a result, these types of renewable energy projects face considerable risk, 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 our
more 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. 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.
Government incentives and policies that support the development of renewable energy generation
projects could change at any time.
AES’ U.S. renewable energy generation growth strategy depends in part on federal, state and local
government policies and incentives that support the development, financing, ownership and operation of renewable
energy generation projects. These policies and incentives include investment tax credits, production tax credits,
accelerated depreciation, renewable portfolio standards, feed-in-tariffs and similar programs, renewable energy
credit mechanisms, and tax exemptions. If these policies and incentives are changed or eliminated, or AES is
unable to use them, it could result in a material adverse impact on AES’ U.S. renewable growth opportunities,
including fewer future PPAs or lower prices for the sale of power in future PPAs, decreased revenues, reduced
economic returns on certain project company investments, increased financing costs, and/or difficulty obtaining
financing.
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 assess the financial impacts of complicated
business transactions that 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.
Cyber-attacks and data security breaches could harm our business.
Our business is heavily reliant on electronic systems and network technologies to operate our generation,
transmission and distribution infrastructure. We also use various financial, accounting and other infrastructure
systems. Our infrastructure may be targeted by nation states, hacktivists, criminals, insiders or terrorist groups.
Such an attack, by hacking, malware or other means, may interrupt our operations, cause property damage, affect
our ability to control our infrastructure assets, cause the release of sensitive customer information or limit
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communications with third parties. Any loss or corruption of confidential or proprietary data through such breach
may:
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impair our reputation;
impact our operations and strategic objectives;
impact our customer and vendor relationships;
result in substantial revenue loss;
expose us to legal claims and/or regulatory investigations and proceedings; and
require extensive repair and restoration costs for additional security measures to avert future cyber-attacks.
In addition, a breach of our financial and accounting systems could impact our ability to correctly record,
process and report financial information.
In addition, in the ordinary course of business, we collect and retain sensitive information, including personal
identification information about customers and employees, customer energy usage and other information. The theft,
damage or improper disclosure of sensitive electronic data can subject us to penalties for violation of applicable
privacy laws, subject us to claims from third parties, require compliance with notification and monitoring regulations,
and harm our reputation. The EU GDPR recently came into force and applies to the processing of personal
information collected from individuals located in the EU. The GDPR creates new compliance obligations and
significantly increases fines for noncompliance.
We have implemented measures to help prevent unauthorized access to our systems and facilities, including
certain measures to comply with mandatory regulatory reliability standards. To date, cyber-attacks on our business
and operations have not had a material impact on our operations or financial results. We continue to assess
potential threats and vulnerabilities and make investments to address them, including global monitoring of networks
and systems, identifying and implementing new technology, improving user awareness through employee security
training, and updating our security policies as well as those for third-party providers. We cannot guarantee the
extent to which our security measures will prevent future cyber-attacks and security breaches or that our insurance
coverage will adequately cover any losses we may experience.
Our utilities businesses may be negatively affected by a lack of growth or slower growth in the
number of customers or in customer usage.
Customer growth and customer usage in our utilities businesses are affected by a number of factors outside
our control, such as mandated energy efficiency measures, demand side management requirements, and economic
and demographic conditions, such as population changes, job and income growth, housing starts, new business
formation and the overall level of economic activity. A lack of growth, or a decline, in the number of customers or in
customer demand for electricity may cause us to fail to fully realize the anticipated benefits from significant
investments and expenditures and could have a material adverse effect on our growth, business, financial
condition, results of operations and prospects.
Some of our subsidiaries participate in defined benefit pension plans and their net pension plan
obligations may require additional significant contributions.
We have 30 defined benefit plans, five at U.S. subsidiaries and the remaining plans at foreign subsidiaries,
which cover substantially all of the employees at these 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 incorrect, resulting in a shortfall of pension plan assets
compared to pension obligations under the pension plan. We periodically evaluate the value of the pension plan
assets to ensure that they will be sufficient to fund the respective pension obligations. Our 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 generally 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 that participate in these
plans are responsible for satisfying the funding requirements required by law in their respective jurisdictions for any
shortfall of pension plan assets as compared to pension obligations under the pension plan. Satisfying such funding
requirements 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
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of Operations—Critical Accounting Policies and Estimates—Pension and Other Postretirement Plans and Note 13.
—Benefit Plans included in Item 8.—Financial Statements and Supplementary Data included in this Form 10-K.
Impairment of goodwill or long-lived assets would negatively impact our consolidated results of
operations and net worth.
As of December 31, 2018, the Company had approximately $1.1 billion of goodwill, which represented
approximately 3% 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; lower forecasted revenue; increase in fuel costs,
particularly when we are unable to pass through the impact to customers; increase in environmental compliance
costs; negative or declining cash flows; loss of a key contract or customer, particularly when we are unable to
replace it on equally favorable terms; developments in our strategy; divestiture of a significant component of our
business; or adverse actions or assessments by a regulator. For example, during the annual goodwill impairment
test performed as of October 1, 2018, the Company determined that the fair value of its Gener reporting unit
exceeded its carrying value by 7%. Therefore, Gener's $868 million goodwill balance was considered to be "at risk"
for impairment as of December 31, 2018 largely due to the fact that a market participant would no longer assume
perpetual cash flows from coal-fired power plants due to the increased penetration of renewable energy in Chile.
See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Key
Trends and Uncertainties—Impairments. 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.
Any of the foregoing could have a material adverse effect on our business, financial condition, results of
operations, and prospects.
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;
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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;
•
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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:
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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 operating 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. The impacts described above could also
result from our (or our subsidiaries') efforts to comply with European Market Infrastructure Regulation, which
includes regulations related to the trading, reporting and clearing of derivatives. 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.
Several of our businesses are subject to potentially significant remediation expenses, enforcement
initiatives, private party lawsuits and reputational risk associated with CCR.
CCR, which consists of bottom ash, fly ash and air pollution control wastes generated at our current and
former coal-fired generation plant sites, is currently handled and/or has been handled in the past in the following
ways: placement in onsite CCR ponds; disposal and beneficial use in onsite and offsite permitted, engineered
landfills; use in various beneficial use applications, including encapsulated uses and structural fill; and used in
permitted offsite mine reclamation. CCR currently remains onsite at several of our facilities, including in CCR ponds.
The U.S. EPA's final CCR rule, which became effective in October 2015, regulates CCR as nonhazardous solid
waste and establishes national minimum criteria for existing and new CCR landfills and existing and new CCR
ponds, including location restrictions, design and operating criteria, groundwater monitoring, corrective action and
closure requirements and post-closure care. On December 16, 2016, President Obama signed the WIN Act into law,
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 primary enforcement mechanisms under this regulation could
be actions commenced by U.S. EPA, states, or territories, and private lawsuits. Compliance with the U.S. federal
CCR rule; amendments to the federal CCR rule; or federal, state, territory, or foreign rules or programs addressing
CCR may require us to incur substantial costs. In addition, the Company and our businesses may face CCR-related
lawsuits in the United States and/or internationally that may expose us to unexpected potential liabilities.
Furthermore, CCR-related litigation may also expose us to unexpected costs. In addition, CCR, and its production
at several of our facilities, have been the subject of significant interest from environmental non-governmental
organizations and have received national and local media attention. The direct and indirect effects of such media
attention, and the demands of responding to and addressing it, may divert management time and attention. Any of
the foregoing could have a material adverse effect on our business, financial condition, results of operations,
reputation and prospects.
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Our business in the United States is subject to the provisions of various laws and regulations
administered in whole or in part by FERC and NERC, including PURPA, the Federal Power Act, and the
EPAct 2005. Actions by FERC, NERC and by state utility commissions can have a material effect on our
operations.
The AES Corporation is a registered electric holding company under the 2005 PUHCA as enacted as part of
the EPAct 2005. PUHCA 2005 eliminated many of the restrictions that had been in place under the 1935 PUCHA,
while continuing to provide FERC and state utility commissions with enhanced access to the books and records of
certain utility holding companies. PUHCA 2005 also creates additional potential challenges and opportunities. By
removing some barriers to mergers and other potential combinations, the creation of large, geographically
dispersed utility holding companies is more likely. These entities may have enhanced financial strength and
therefore an increased ability to compete with us in the U.S. market.
Other parts of the EPAct 2005 allow FERC to remove the PURPA purchase/sale obligations from utilities if
there are adequate opportunities to sell into competitive markets. FERC has exercised this power with a rebuttable
presumption that utilities located within the control areas of MISO, PJM, ISO New England, Inc., the New York
Independent System Operator, Inc., and ERCOT are not required to purchase or sell power from or to QFs above a
certain size. Additionally, FERC has the power to remove the purchase/sale obligations of individual utilities on a
case-by-case basis. While these changes do not affect existing contracts, certain of our QFs that have had sales
contracts expire are now facing a more difficult market environment and that is likely to continue for other AES QFs
with existing contracts that will expire over time.
In accordance with Congressional mandates in the EPAct 1992 and the EPAct 2005, FERC has strongly
encouraged competition in wholesale electric markets. Increased competition may have the effect of lowering our
operating margins. Among other steps, 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 generation assets. Similarly, 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.
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. 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. As a result, FERC is authorized to assess a maximum penalty authority established by statute and
such penalty authority has been and will continue to be adjusted periodically to account for inflation. 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.
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. Violations of NERC reliability standards are subject to FERC's
penalty authority under the FPA and EPAct 2005.
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, rules 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. Failure to comply with such laws and
regulations or to obtain or comply with any associated environmental permits could result in fines or other
sanctions. For example, in recent years, the EPA has issued notices of violation (NOVs) to a number of coal-fired
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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 and obtained settlements with many
companies for allegedly making major modifications to a coal-fired generating units without proper permit approvals
and without installing best available control technology. The primary focus of these NOVs has been emissions of
SO2 and NOx and the EPA has imposed fines and required companies to install improved pollution control
technologies to reduce such emissions. In addition, state regulatory agencies and non-governmental environmental
organizations have pursued civil lawsuits against power plants in situations that have resulted in judgments and/or
settlements requiring the installation of expensive pollution controls or the accelerated retirement of certain electric
generating units.
Furthermore,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. 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. See the various descriptions of
these laws and regulations contained in Item 1.—Business—Environmental and Land-Use Regulations of this
Form 10-K.
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
us 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.
Concerns about GHG emissions and the potential risks associated with climate change have led to
increased regulation and other actions that could impact our businesses.
International, federal and various regional and state authorities regulate GHG emissions and have created
financial incentives to reduce them. In 2018, the Company's subsidiaries operated businesses that had total CO2
emissions of approximately 55 million metric tonnes, approximately 23 million of which were emitted by our U.S.
businesses (both figures are 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-fired electric power generation facilities of the Company's subsidiaries that are in construction or
development and have received the necessary air permits for commercial operations are approximately 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.
There currently is no U.S. federal legislation imposing mandatory GHG emission reductions (including for CO2)
that affects our electric power generation facilities; however, in 2015, the EPA promulgated a rule establishing New
Source Performance Standards for CO2 emissions for newly constructed and modified/reconstructed fossil-fueled
EUSGUs larger than 25 MW. Also in 2015, the EPA promulgated the Clean Power Plan (CPP), which requires
interim reductions by preexisting EUSGUs beginning in 2022, with full compliance achieved by 2030. These actions
have been challenged in court and the current Administration has announced plans to significantly amend or
rescind the rules. In 2016, the EPA adopted regulations pertaining to GHG emissions that require new and existing
sources of GHG emissions to potentially obtain new source review permits from the EPA prior to construction or
modification, but only if such sources also must obtain a new source review permit for increases in other regulated
pollutants.
For further discussion of the regulation of GHG emissions, including the U.S. Supreme Court's issued order
staying implementation of the CPP, and the EPA's proposal to rescind the CPP, see Item 1.—Business—
Environmental and Land-Use Regulations—United States Environmental and Land-Use Legislation and
Regulations—Greenhouse Gas Emissions above.
In December 2015, the Parties to the United Nations Framework Convention on Climate Change convened for
the 21st Conference of the Parties and the resulting Paris Agreement established a long-term goal of keeping the
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increase in global average temperature well below 2°C above pre-industrial levels. We anticipate that the Paris
Agreement will continue the trend toward efforts to de-carbonize the global economy and to further limit GHG
emissions.
The impact of GHG regulation on our operations 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. The
costs of compliance could be substantial.
Our non-utility, generation subsidiaries seek to pass on any costs arising from CO2 emissions to contract
counterparties. Likewise, our utility subsidiaries seek to pass on any costs arising from CO2 emissions to
customers. However, there can be no assurance that we will effectively pass such costs onto the contract
counterparties or customers, respectively, or that the cost and burden associated with any dispute over which party
bears such costs would not be burdensome and costly.
In addition to government regulators, many groups , including politicians, environmentalists, the investor
community and other private parties have expressed increasing concern about GHG emissions. Negative public
perception of our GHG emissions could have an adverse effect on our relationships with third parties, our ability to
attract additional customers or our business development opportunities. In addition, plaintiffs previously brought tort
lawsuits against the Company because of its subsidiaries' GHG emissions. While these lawsuits were dismissed,
future similar lawsuits may prevail or result in damages awards or other relief. We may also be subject to risks
associated with the impact on weather conditions. See Item 1A.—Risk Factors—Certain of our businesses are
sensitive to variations in weather and hydrology and Severe weather and natural disasters may present significant
risks to our business and adversely affect our financial results for more information.
If any of the foregoing risks materialize, costs may increase or revenues may decrease and there could be a
material adverse effect on our electric power generation businesses and on our consolidated results of operations,
financial condition,cash flows and reputation.
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.
The TCJA enacted December 22, 2017 introduced significant changes to current U.S. federal tax law,
including but not limited to lowering the corporate income tax rate, introducing new limits on interest expense
deductibility, and changing the way in which foreign earnings are taxed. These changes are complex and are
subject to additional guidance to be issued by the U.S. Treasury and the Internal Revenue Service. In addition, the
reaction to the federal tax changes by the individual states is evolving. Our interpretations and assumptions around
U.S. tax reform may evolve in future periods as further administrative guidance and regulations are issued, which
may materially affect our effective tax rate or tax payments. For further details, please see Item 7.—Management's
Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties in this
Form 10-K.
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, in
coordination with the G8 and G20, through its Base Erosion and Profit Shifting project 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.
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.
62
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 when 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
consolidated 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 that cannot be estimated as of December 31, 2018.
In December 2001, Grid Corporation of Odisha (“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. A hearing on
the liability award has not taken place to date. 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.
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 mitigate the contaminated area located
on the grounds of the pole factory and an indemnity payment of approximately R$6 million ($2 million). In October
2011, the State Attorney 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 that only
CEEE was required to perform the removal work. In May 2012, CEEE began the removal work in compliance with
the injunction. The case is now awaiting judgment. The removal costs are estimated to be approximately R$29
million ($8 million), and there could be additional remediation costs which cannot be estimated at this time. In June
2016 the Company sold AES Sul to CPFL Energia S.A. and as part of the sale, AES Guaiba, a holding Company of
AES Sul, retained the potential liability relating to this matter. The Company believes that there are meritorious
63
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 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$1.21 billion ($312 million) as estimated by AES
Tietê. AES Tietê appealed to the SIAC. In January 2015, the Second Instance Administrative Court ("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 (“Special Appeal”), which was rejected as untimely in October 2016. The Tax Authority thereafter filed an
interlocutory appeal with the Superior Administrative Court (“SAC”). In March 2017, the President of the SAC
determined that the SAC would analyze the Special Appeal. AES Tietê challenged the Special Appeal. In May 2018,
the SAC rejected the Special Appeal on the merits. In August 2018, the Tax Authority filed a motion for clarification.
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 2017, the
EPA issued a second NOV for DPL Stuart Station, alleging violations of opacity in 2016. Moreover, in February
2016, IPL received an NOV from the EPA alleging violations of 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. GG has refiled its lawsuit.
Also, there are ongoing administrative proceedings concerning whether AES Panama is entitled to 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.
In January 2017, the Superintendencia del Medio Ambiente (“SMA”) issued a Formulation of Charges
asserting that Alto Maipo is in violation of certain conditions of the Environmental Approval Resolution (“RCA”)
governing the construction of Alto Maipo’s hydropower project, for, among other things, operating vehicles at
unauthorized times and failing to mitigate the impact of water infiltration during tunnel construction (“Infiltration
Water”). In February 2017, Alto Maipo submitted a compliance plan (“Compliance Plan”) to the SMA which, if
approved by the agency, would resolve the matter without materially impacting construction of the project.
Thereafter, the SMA made three separate requests for information about the Compliance Plan, to which Alto Maipo
duly responded. In April 2018, the SMA approved the Compliance Plan (“April 2018 Approval”). Among other things
the Compliance Plan as approved by the SMA requires Alto Maipo to obtain from the Environmental Evaluation
Service (“SEA”) an acceptable interpretation of the RCA’s provisions concerning the authorized times to operate
certain vehicles. In addition, Alto Maipo must obtain the SEA’s approval concerning the control, discharge, and
treatment of Infiltration Water. Alto Maipo continues to seek the relevant final approvals from the SEA. Furthermore,
64
in May 2018, three lawsuits were filed with the Environmental Court of Santiago (“ECS”) challenging the April 2018
Approval. Alto Maipo does not believe that there are grounds to challenge the April 2018 Approval. The ECS has
not decided the lawsuits to date. If Alto Maipo complies with the requirements of the Compliance Plan, and if the
above-referenced lawsuits are dismissed, the Formulation of Charges will be discharged without penalty.
Otherwise, Alto Maipo could be subject to penalties, and the construction of the project could be negatively
impacted. Alto Maipo will pursue its interests vigorously in these matters; however, there can be no assurances that
it will be successful in its efforts.
In June 2017, Alto Maipo terminated one of its contractors, Constructora Nuevo Maipo S.A. (“CNM”), given
CNM’s stoppage of tunneling works, its failure to produce a completion plan, and its other breaches of contract.
Also, Alto Maipo drew $73 million under letters of credit (“LC Funds”) in connection with its termination of CNM. Alto
Maipo is pursuing arbitration against CNM to recover excess completion costs and other damages totaling over
$230 million (net of the LC Funds) relating to CNM’s breaches (“First Arbitration”). CNM denies liability and seeks a
declaration that its termination was wrongful, damages, and other relief. CNM has made submissions alleging that it
is entitled to damages ranging from $90 million to $150 million (which include the LC Funds) plus interest and costs.
Alto Maipo has contested these submissions. There will be another round of briefing. The evidentiary hearing is
scheduled for May 20-31, 2019. Also, in August 2018, CNM purported to initiate a separate arbitration against AES
Gener and the Company (“Second Arbitration”). In the Second Arbitration, CNM seeks to pierce Alto Maipo’s
corporate veil and appears to seek an award requiring AES Gener and the Company to pay any amounts that are
found to be due to CNM in the First Arbitration or otherwise. Alto Maipo requested in the First Arbitration an interim
order restraining CNM from proceeding with the Second Arbitration until the conclusion of the First Arbitration. That
request was denied. Separately, AES Gener and the Company requested that the relevant arbitral institution decide
that the Second Arbitration shall not proceed, given that (among other reasons) there is no arbitration agreement
between AES Gener and the Company and CNM. That request was not granted. Subsequently, AES Gener and the
Company requested that the Second Arbitration be consolidated into the First Arbitration. That request was granted.
The schedule has not yet been established on CNM’s claims against AES Gener and the Company. Each of the
above-referenced AES companies believes it has meritorious claims and/or defenses and will pursue its interests
vigorously; however, there can be no assurances that each of the AES companies will be successful in its efforts.
In February 2018, Tau Power B.V. and Altai Power LLP (collectively, “AES Claimants”) initiated arbitration
against the Republic of Kazakhstan (“ROK”) for the ROK’s failure to pay approximately $75 million (“Return Transfer
Payment”) for the return of two hydropower plants (“HPPs”) pursuant to a concession agreement. In April 2018, the
ROK responded by denying liability and asserting purported counterclaims concerning the annual payment
provisions in the concession agreement, a bonus allegedly due for the 1997 takeover of the HPPs, and dividends
paid by the HPPs. The ROK seeks to recover the Return Transfer Payment (which is in an escrow account
maintained by a third party) and appears to be seeking over $480 million on its counterclaims. The AES Claimants
believe that the ROK’s defenses and counterclaims are without merit. An arbitrator has been appointed to decide
the case. The final evidentiary hearing is scheduled for July 22 to 26, 2019. The AES Claimants will pursue their
case and assert their defenses vigorously; however, there can be no assurances that they will be successful in their
efforts.
In December 2018, a lawsuit was filed in Dominican Republic civil court against the Company, AES Puerto Rico,
and three other AES affiliates. The lawsuit purports to be brought on behalf of over 100 Dominican claimants, living
and deceased, and appears to seek relief relating to CCRs that were delivered to the Dominican Republic in 2004.
The lawsuit generally alleges that the CCRs caused personal injuries and deaths and demands $476 million in alleged
damages. The lawsuit does not identify, or provide any supporting information concerning, the alleged injuries of the
claimants individually. Nor does the lawsuit provide any information supporting the demand for damages or explaining
how the quantum was derived. The relevant AES companies believe that they have meritorious defenses to the claims
asserted against them and will defend themselves vigorously in this proceeding; however, there can be no assurances
that they will be successful in their efforts.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
65
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 Parent 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 Stock Repurchase Program does not have an expiration date and can be modified
or terminated by the Board of Directors at any time. The cumulative repurchase from the commencement of the
Stock Repurchase Program in July 2010 through December 31, 2018 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,
2018, $264 million remained available for repurchase under the Stock Repurchase Program. No repurchases were
made by The AES Corporation of its common stock in 2018 and 2017, respectively. The Parent Company
repurchased 8,686,983 shares of its common stock in 2016.
Market Information
Our common stock is traded on the New York Stock Exchange under the symbol "AES."
Dividends
The Parent Company commenced a quarterly cash dividend in the fourth quarter of 2012. The Parent
Company has increased this dividend annually and the quarterly cash dividend for the last three years are
displayed below.
Commencing the fourth quarter of
Cash dividend
2018
$0.1365
2017
$0.13
2016
$0.12
The fourth quarter 2018 cash dividend is to be paid in the first quarter of 2019. There can be no assurance 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 21, 2019, there were approximately 3,875 record holders of our common stock.
66
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 27 electric and gas utilities included in the S&P 500.
The five year total return chart assumes $100 invested on December 31, 2013 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. This data
should be read 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, 2018 have been derived from our audited Consolidated Financial Statements.
Prior period amounts have been restated to reflect discontinued operations in all periods presented. 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 or significant
continuing involvement with the component as of one year after its disposal or sale. Effective July 1, 2014, the
Company adopted new accounting guidance under which the Company reports a business as discontinued
operations if the disposal represents a strategic shift that has (or will have) a major effect on the Company’s
operations and financial results when the business is sold or classified as held-for-sale. Please refer to Note 1—
General and Summary of Significant Accounting Policies 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
67
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.
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 (2)
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
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 (loss) per share:
Income (loss) 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
Cash Flow Data for the Years Ended December 31:
2018
$ 10,736
1,349
2017
2015
2016
(in millions, except per share amounts)
$ 10,281
191
$ 10,530
(148)
$ 11,260
682
2014
$ 12,604
941
985
218
(507)
(20)
(654)
(1,110)
318
(12)
678
91
$ 1,203
$ (1,161) $ (1,130) $
306
$
769
$
1.49
$
(0.77) $
(0.04) $
0.46
$
0.94
0.33
1.82
1.48
0.33
1.81
0.53
$
$
$
$
$
$
$
$
(0.99)
(1.68)
(0.01)
(1.76) $
(1.72) $
0.45
(0.77) $
(0.04) $
0.46
(0.99)
(1.68)
(0.02)
(1.76) $
$
0.49
(1.72) $
$
0.45
0.44
0.41
0.13
1.07
0.94
0.12
1.06
0.25
$
$
$
$
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by (used in) financing activities
Total increase (decrease) in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash, ending
$ 2,343
(505)
(1,643)
215
2,003
$ 2,504
(2,599)
43
(172)
1,788
$ 2,897
(2,136)
(747)
9
1,960
$ 2,136
(2,128)
28
(10)
1,951
$ 1,800
(1,075)
(1,262)
(529)
1,961
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
_____________________________
$ 32,521
13,986
—
3,650
879
(1,005)
3,208
$ 33,112
13,176
—
4,625
837
(2,276)
2,465
$ 36,124
13,731
758
4,671
782
(1,146)
2,794
$ 36,545
12,184
772
4,966
538
143
3,149
$ 38,676
12,077
1,226
5,047
78
512
4,272
(1)
(2)
Includes pre-tax gains on sales of business interests of $984 million, $29 million, $29 million and $358 million for the years ended December 31, 2018, 2016,
2015 and 2014, respectively, and pre-tax losses of $52 million for the year ended December 31, 2017; pre-tax impairment expense of $208 million, $537
million, $1.1 billion, $602 million and $383 million for the years ended December 31, 2018, 2017, 2016, 2015 and 2014, respectively; other-than-temporary
impairments of equity method investments of $147 million and $128 million for the years ended December 31, 2018 and 2014, respectively; income tax
expense of $194 million and $675 million related to the one-time transition tax on foreign earnings, and income tax benefit of $77 million and expense of $39
million related to the remeasurement of deferred tax assets and liabilities to the lower corporate tax rate for the years ended December 31, 2018 and 2017,
respectively. See Note 23—Held-for-Sale and Dispositions, Note 8—Goodwill and Other Intangible Assets, Note 20—Asset Impairment Expense, Note 7—
Investments in and Advances to Affiliates and Note 21—Income Taxes included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K
for further information.
Includes gain on sale of $199 million and loss on deconsolidation of $611 million related to Eletropaulo for the years ended December 31, 2018 and 2017,
respectively, and impairment expense of $382 million and loss on sale of $737 million related to Sul for the year ended December 31, 2016. See Note 22—
Discontinued Operations included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
68
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Executive Summary
In 2018, AES delivered strong financial results and achieved significant milestones on its strategic goals,
including continuing to enhance the resilience of the portfolio and growing the backlog of renewable projects. The
Company achieved a key investment grade metric, completed construction of 1.3 GW of new projects and signed
long-term PPAs for 2 GW of renewable capacity. See Overview of our Strategy included in Item 1.—Business of this
Form 10-K for further information.
During 2018, the Company saw increased margins at its South America, MCAC and US and Utilities SBUs.
These increases were primarily due to higher tariffs and rates in Argentina and the U.S., higher contract prices in
Colombia, new PPAs in Chile, and increased sales due to the commencement of operations at the Colon combined
cycle facility in Panama and Eagle Valley CCGT in the U.S. The Company also experienced decreased margins in
the Eurasia SBU due to completed sales of Masinloc in 2018 and the Kazakhstan facilities in 2017. In addition, the
Company reduced its recourse debt by approximately $1 billion in 2018, resulting in a decrease in Parent Company
interest.
Overview of 2018 Results
Earnings Per Share Results in 2018 (in millions, except per share amounts)
Years Ended December 31,
Diluted earnings (loss) per share from continuing operations
Adjusted EPS (a non-GAAP measure) (1)
_____________________________
(1)
See reconciliation and definition under SBU Performance Analysis—Non-GAAP Measures.
2018
2017
2016
$
$
1.48
1.24
(0.77) $
1.08
(0.04)
0.94
Diluted earnings per share from continuing operations increased $2.25 to $1.48 for the year ended
December 31, 2018, as compared to a loss of $0.77 for the year ended December 31, 2017. This increase was
primarily due to the current year gains on sales of Masinloc, CTNG and Electrica Santiago, prior year loss on sale
of the Kazakhstan CHPs and HPPs, prior year impairments at DPL, Laurel Mountain and in Kazakhstan, lower
interest expense at the Parent Company and Gener, a one-time transition tax on foreign earnings following the
enactment of the TCJA in the prior year, and higher margins. These increases were partially offset by higher current
year tax expense due to the new GILTI rules in the U.S. in large part due to the sale of our interest in Masinloc, the
current year impairment at Shady Point, other-than-temporary impairment of the Guacolda equity method
investment in Chile, foreign exchange losses mainly due to the devaluation of the Argentine peso and foreign
currency gains in the prior year, higher current year losses on extinguishment of debt, and a favorable legal
settlement at Uruguaiana in the prior year.
Adjusted EPS, a non-GAAP measure, increased $0.16, or 15%, to $1.24, reflecting higher margins at the
South America, US and Utilities and MCAC SBUs and lower interest on Parent Company debt. These increases
were partially offset by lower margin at the Eurasia SBU mainly driven by the sales of Masinloc and Kazakhstan.
69
Review of Consolidated Results of Operations
Years Ended December 31,
(in millions, except per share amounts)
Revenue:
US and Utilities SBU
South America SBU
MCAC SBU
Eurasia SBU
Corporate and Other
Eliminations
Total Revenue
Operating Margin:
US and Utilities SBU
South America SBU
MCAC SBU
Eurasia SBU
Corporate and Other
Eliminations
Total Operating Margin
General and administrative expenses
Interest expense
Interest income
Loss on extinguishment of debt
Other expense
Other income
Gain (loss) on disposal and sale of business interests
Asset impairment expense
Foreign currency transaction gains (losses)
Other non-operating expense
Income tax expense
Net equity in earnings of affiliates
INCOME (LOSS) FROM CONTINUING OPERATIONS
Income (loss) from operations of discontinued businesses, net of income
tax benefit (expense) of $(2), $(21), and $229, respectively
Gain (loss) from disposal and impairments of discontinued businesses, net
of income tax benefit (expense) of $(44), $0, and $266, respectively
NET INCOME (LOSS)
Noncontrolling interests:
Less: Income from continuing operations attributable to noncontrolling
interests and redeemable stock of subsidiaries
Less: Loss (income) from discontinued operations attributable to
noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON
STOCKHOLDERS:
Income (loss) 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
2018
2017
2016
% Change 2018
vs. 2017
% Change 2017
vs. 2016
$
4,230
3,533
1,728
1,255
41
(51)
10,736
$
4,162
3,252
1,519
1,590
35
(28)
10,530
$
4,330
2,956
1,274
1,670
77
(26)
10,281
733
1,017
534
227
58
4
2,573
(192)
(1,056)
310
(188)
(58)
72
984
(208)
(72)
(147)
(708)
39
1,349
693
862
465
422
23
—
2,465
(215)
(1,170)
244
(68)
(58)
120
(52)
(537)
42
—
(990)
71
(148)
719
823
390
427
14
10
2,383
(194)
(1,134)
245
(13)
(80)
64
29
(1,096)
(15)
(2)
(32)
36
191
(9)
(18)
151
225
1,565
(611)
(777)
(1,119)
(777)
(364)
(359)
(211)
2
(25)
(142)
$
1,203
$ (1,161) $ (1,130)
$
$
$
$
985
218
1,203
2,343
$
(507) $
(654)
(20)
(1,110)
$ (1,161) $ (1,130)
2,897
2,504
$
$
0.53
$
0.49
$
0.45
2%
9%
14%
-21%
17%
-82%
2%
6%
18%
15%
-46%
NM
NM
4%
-11%
-10%
27%
NM
—%
-40%
NM
-61%
NM
NM
-28%
-45%
NM
-50%
NM
NM
1%
NM
NM
NM
NM
NM
-6%
8%
-4%
10%
19%
-5%
-55%
-8%
2%
-4%
5%
19%
-1%
64%
-100%
3%
11%
3%
—%
NM
-28%
88%
NM
-51%
NM
-100%
NM
97%
NM
NM
-45%
—%
70%
-82%
3%
NM
-41%
3%
-14%
9%
Components of Revenue, Cost of Sales and Operating Margin — Revenue includes revenue earned from the
sale of energy from our utilities and the capacity and 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 and 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.
70
Operating margin is defined as revenue less cost of sales.
Consolidated Revenue and Operating Margin
Year Ended December 31, 2018
Revenue
(in millions)
Consolidated Revenue — Revenue increased $206 million, or 2%, in 2018 compared to 2017. Excluding the
unfavorable FX impact of $52 million, primarily in South America partially offset by Eurasia, this increase was driven
by:
• $357 million in South America primarily due to higher contract sales and prices in Colombia and the
commencement of new PPAs at Angamos and Cochrane in Chile, as well as higher capacity prices in
Argentina resulting from market reforms enacted in 2017;
• $215 million in MCAC primarily due to to the commencement of operations at the Colon combined cycle
facility as well as improved hydrology at Panama, higher pass-through fuel prices in Mexico, higher
contracted energy sales due to commencement of operations at the Los Mina combined cycle facility in
June 2017, and higher spot prices in the Dominican Republic; and
• $68 million in US and Utilities driven primarily by higher market energy sales at Southland, higher regulated
rates commencing in November 2017 at DPL, higher wholesale volume due to the new CCGT coming
online as well as higher retail demand at IPL, and higher prices due to tariff reset and higher energy prices
in El Salvador, partially offset by the sale and closure of several generation facilities at DPL.
These favorable impacts were partially offset by decreases of $366 million in Eurasia due to the sale of the
Masinloc power plant in March 2018, as well as the sale of the Kazakhstan CHPs and expiration of the Kazakhstan
HPP concession agreement in 2017.
Operating Margin
(in millions)
Consolidated Operating Margin — Operating margin increased $108 million, or 4%, in 2018 compared to
2017. Excluding the favorable impact of FX of $8 million, primarily driven by Eurasia, this increase was driven by:
• $154 million in South America primarily due to the drivers discussed above and the absence of
maintenance costs for planned outages in 2018 versus maintenance performed in Q3 2017 at Gener Chile;
71
• $70 million in MCAC primarily due to drivers discussed above; and
• $40 million in US and Utilities mostly due to the drivers discussed above and the favorable impact of a one
time reduction in the ARO liability at DPL's closed plants, Stuart and KIllen.
These favorable impacts were partially offset by a decrease of $204 million in Eurasia due to the drivers
discussed above.
Year Ended December 31, 2017
Revenue
(in millions)
Consolidated Revenue — Revenue increased $249 million, or 2%, in 2017 compared to 2016. Excluding the
net favorable FX impact of $38 million, primarily in South America, the increase was driven by:
• $249 million in South America primarily due to the start of commercial operations at Cochrane as well as
higher availability at Argentina, partially offset by lower spot sales at Chivor; and
• $248 million in MCAC primarily due to the commencement of the combined cycle operations at Los Mina in
June 2017 as well as higher rates in the Dominican Republic.
These favorable impacts were partially offset by decreases of $168 million in US & Utilities mainly due to lower
retail tariffs, lower wholesale volume and price at DPL as well as hurricane impacts at Puerto Rico, partially offset by
higher pass through costs in El Salvador.
Operating Margin
(in millions)
Consolidated Operating Margin — Operating margin increased $82 million, or 3%, in 2017 compared to 2016.
Excluding the favorable impact of FX of $39 million, primarily in Brazil, Argentina, and Colombia, the increase was
primarily driven by:
• $73 million in MCAC due to the commencement of the Los Mina combined cycle operations in June 2017 in
the Dominican Republic as well as higher availability due to forced outages in 2016 at Mexico.
These positive impacts were partially offset by a decreases of $26 million in US and Utilities driven by lower
retain margin, lower volumes, and lower commercial availability at DPL as well as a negative impact at IPL mainly
due to one-off accruals due to the implementation of new base rates in Q2 2016.
72
See Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations—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 initiatives,
executive management, finance, legal, human resources and information systems, as well as global development
costs.
General and administrative expenses decreased $23 million, or 11%, to $192 million for 2018, compared to
$215 million for 2017 primarily due to reduced people costs, professional fees and business development activity.
General and administrative expenses increased $21 million, or 11%, to $215 million for 2017, compared to
$194 million for 2016 primarily due to severance costs related to workforce reductions associated with a major
restructuring program, increased professional fees and increased business development activity.
Interest expense
Interest expense decreased $114 million, or 10%, to $1,056 million for 2018, compared to $1,170 million for
2017 primarily due to the reduction of debt at the Parent Company, favorable impacts from interest rate swaps in
Chile and increased capitalized interest at Alto Maipo.
Interest expense increased $36 million, or 3%, to $1,170 million for 2017, compared to $1,134 million for 2016
primarily due to an increase at the South America SBU, driven by lower capitalized interest in 2017 due to the
Cochrane plant starting commercial operations in the second half of 2016.
Interest income
Interest income increased $66 million, or 27%, to $310 million for 2018, compared to $244 million for 2017
primarily due to higher interest rates and increased long term receivables as a result of the adoption of the new
revenue recognition standard. See Note 1—General and Summary of Significant Accounting Policies included in
Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
Interest income decreased $1 million in 2017 from 2016 with no material drivers.
Loss on extinguishment of debt
Loss on extinguishment of debt increased $120 million to $188 million for 2018, compared to $68 million for
2017. This increase was primarily due to higher losses at the Parent Company of $79 million from the redemption of
senior notes and a prior year gain on early retirement of debt at AES Argentina of $65 million; partially offset by
lower losses at other subsidiaries of $24 million in 2018.
Loss on extinguishment of debt increased $55 million to $68 million for 2017, compared to $13 million for 2016
primarily related to losses of $92 million, $20 million, and $9 million on debt extinguishments at the Parent
Company, AES Gener, and IPALCO, respectively. The loss was partially offset by a gain on early retirement of debt
at AES Argentina of $65 million.
Other income
Other income decreased $48 million, or 40%, to $72 million for 2018, compared to $120 million for 2017
primarily due to the 2017 favorable settlement of legal proceedings at Uruguaiana related to YPF's breach of the
parties’ gas supply agreement and a decrease in allowance for funds used during construction in the US and
Utilities SBU. These decreases were partially offset by a gain on remeasurement of contingent liabilities for projects
in Hawaii in 2018.
Other income increased $56 million, or 88%, to $120 million for 2017, compared to $64 million for 2016
primarily due to the 2017 favorable legal settlement mentioned above.
Other expense
Other expense remained flat at $58 million for 2018, compared to 2017 primarily due to a loss resulting from
damage associated with a lightning incident at the Andres facility in the Dominican Republic in 2018 and higher non-
service pension and other postretirement costs in 2018. This was offset by the 2017 write-off of water rights for
projects that were no longer being pursued in the South America SBU and a loss on disposal of assets at DPL as a
result of the decision to close the coal-fired and diesel-fired generating units at Stuart and Killen.
73
Other expense decreased $22 million, or 28%, to $58 million for 2017, compared to $80 million for 2016
primarily due to the 2016 recognition of a full allowance on a non-trade receivable in the MCAC SBU as a result of
payment delays. This decrease was partially offset by the 2017 loss on disposal of assets at DPL as a result of the
decision to close the coal-fired and diesel-fired generating units at Stuart and Killen and the write-off of water rights
in the South America SBU for projects that are no longer being pursued.
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 (loss) on disposal and sale of business interests
Gain on disposal and sale of business interests was $984 million for 2018 primarily due to the $772 million
gain on sale of Masinloc and the $129 million and $69 million gains on sales of CTNG and Electrica Santiago,
respectively, in Chile.
Loss on disposal and sale of business interests was $52 million for 2017 primarily due to the $49 million and
$33 million losses on sale of Kazakhstan CHPs and HPPs, respectively, partially offset by the recognition of a $23
million gain related to the expiration of a contingency at Masinloc.
Gain on disposal and sale of business interests was $29 million for 2016 primarily due to the $49 million gain
on sale of DPLER, partially offset by the $20 million loss on the deconsolidation of U.K. Wind.
See Note 23—Held-For-Sale and Dispositions included in Item 8.—Financial Statements and Supplementary
Data of this Form 10-K for further information.
Goodwill impairment expense
There were no goodwill impairments for the years ended December 31, 2018, 2017, or 2016.
See Note 8—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 decreased $329 million, or 61%, to $208 million for 2018, compared to $537 million
for 2017 mainly driven by prior year impairments of $186 million recognized in Kazakhstan due to the classification
of the CHPs and HPPs as held-for-sale and $296 million in the U.S. as a result of the decision to sell the DPL
peaker assets and a decline in forward pricing at Laurel Mountain, partially offset by a current year impairment of
$157 million due to decreased future cash flows and the decision to sell Shady Point.
Asset impairment expense decreased $559 million, or 51%, to $537 million for 2017, compared to $1,096
million for 2016 mainly driven by the impairment of $859 million at DPL in 2016, partially offset by a $121 million
impairment at Laurel Mountain in 2017 as a result of a decline in forward pricing.
See Note 20—Asset Impairment Expense included in Item 8.—Financial Statements and Supplementary Data
of this Form 10-K for further information.
Foreign currency transaction gains (losses)
Foreign currency transaction gains (losses) in millions were as follows:
Years Ended December 31,
Argentina (1)
Chile
Bulgaria
United Kingdom
Philippines
Mexico
Colombia
Corporate
Other
Total (2)
_____________________________
2018
2017
2016
$
$
(71) $
(13)
(6)
(2)
(1)
—
6
11
4
(72) $
1
$
8
14
(3)
15
17
(23)
3
10
42
$
37
(9)
(8)
13
12
(8)
(8)
(50)
6
(15)
(1)
(2)
Primarily associated with the peso-denominated energy receivable indexed to the USD through the FONINVEMEM agreement which is considered a foreign
currency derivative. See Note 6—Financing Receivables included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further
information.
Includes gains of $23 million, losses of $21 million, and gains of $17 million on foreign currency derivative contracts for the years ended December 31,
2018, 2017 and 2016, respectively.
74
The Company recognized net foreign currency transaction losses of $72 million for the year ended
December 31, 2018 primarily due to the unrealized losses from the devaluation of receivables denominated in
Argentine pesos and realized losses from Chilean pesos. These losses were partially offset by foreign currency
derivative gains at the Parent Company.
The Company recognized net foreign currency transaction gains of $42 million for the year ended
December 31, 2017 primarily driven by transactions associated with VAT activity in Mexico, the amortization of
frozen embedded derivatives in the Philippines, and appreciation of the Euro in Bulgaria. These gains were partially
offset by foreign currency derivative losses in Colombia due to a change in functional currency.
The Company recognized net foreign currency transaction losses of $15 million for the year ended December
31, 2016 primarily due to remeasurement losses on intercompany notes, and losses on swaps and options at the
Parent Company. These losses were partially offset by foreign currency derivative gains related to government
receivables in Argentina.
Other non-operating expense
Other non-operating expense was $147 million in 2018 primarily due to the $144 million other-than-temporary
impairment of the Guacolda equity method investment as a result of increased renewable generation in Chile
lowering energy prices and impacting the ability of Guacolda to re-contract its existing PPAs after they expire.
There were no significant other non-operating expenses in 2017 and 2016.
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.
Income tax expense
Income tax expense decreased $282 million to $708 million in 2018 as compared to $990 million for 2017. The
Company's effective tax rates were 35% and 128% for the years ended December 31, 2018 and 2017, respectively.
The net decrease in the 2018 effective tax rate was primarily due to greater 2017 impacts related to U.S. tax
reform one-time transition tax and remeasurement of deferred tax assets, relative to the 2018 U.S. tax reform
impact to adjust the provisional estimate recorded under SAB 118, which provides SEC guidance on the application
of the accounting standards for the initial enactment impacts of the TCJA. This net decrease was also attributable to
the impact of the sale of the Company's entire 51% equity interest in Masinloc, offset by taxation of our foreign
subsidiaries under U.S. GILTI rules.
Income tax expense increased $958 million to $990 million in 2017 as compared to $32 million for 2016. The
Company's effective tax rates were 128% and 17% for the years ended December 31, 2017 and 2016, respectively.
The net increase in the 2017 effective tax rate was due primarily to the enactment of the TCJA in the U.S.,
partially offset by the impacts of the 2016 Chilean tax law reform and the 2016 devaluation of the Mexican peso.
See Note 21—Income Taxes included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K
for additional information regarding the 2016 Chilean income tax law reform.
Our effective tax rate reflects the tax effect of significant operations outside the U.S., which are generally taxed
at rates different than the U.S. statutory rate. Foreign earnings may be taxed at rates higher than the U.S. corporate
rate of 21% and are also subject to current U.S. taxation under the GILTI rules introduced by the TCJA. 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 included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K for additional
information regarding these reduced rates.
Net equity in earnings of affiliates
Net equity in earnings of affiliates decreased $32 million, or 45%, to $39 million for 2018, compared to $71
million for 2017 primarily due to losses at Fluence, which was formed in the first quarter of 2018, decreased income
at Guacolda, and larger gains on projects that achieved commercial operations in 2017 than in 2018 at sPower,
which was purchased in the third quarter of 2017.
Net equity in earnings of affiliates increased $35 million, or 97%, to $71 million in 2017, compared to $36
million for 2016 primarily due to earnings at the sPower equity method investment purchased in 2017, partially
offset by fixed asset impairments in 2017 at the Distributed Energy entities, accounted for as equity affiliates.
75
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.
Net income (loss) from discontinued operations
Net income from discontinued operations was $216 million for the year ended December 31, 2018 primarily
due to the after-tax gain on sale of Eletropaulo of $199 million recognized in the second quarter of 2018 and the
recognition of a $26 million deferred gain upon liquidation of Borsod in October 2018.
Net loss from discontinued operations was $629 million for the year ended December 31, 2017 primarily due
to the after-tax loss on deconsolidation of Eletropaulo of $611 million recognized in the fourth quarter of 2017. The
remaining loss was due to a loss contingency recognized by our equity affiliate, partially offset by the income from
operations of Eletropaulo prior to the date of deconsolidation.
Net loss from discontinued operations was $968 million for the year ended December 31, 2016 due to the sale
of Sul, partially offset by the income from operations of Eletropaulo. The loss includes an after-tax loss on the
impairment of Sul of $382 million recognized in the second quarter of 2016 and an additional after-tax loss on the
sale of Sul of $737 million recognized upon disposal in October 2016. There was no significant loss from operations
related to the Sul discontinued business.
See Note 22—Discontinued Operations included in Item 8.—Financial Statements and Supplementary Data of
this Form 10-K for further information.
Net income attributable to noncontrolling interests and redeemable stock of subsidiaries
Net income attributable to noncontrolling interests and redeemable stock of subsidiaries decreased $22
million, or 6%, to $362 million in 2018, compared to $384 million in 2017. This decrease was primarily due to:
• Current year other-than-temporary impairment of Guacolda;
• Prior year favorable impact of a legal settlement at Uruguaiana; and
• Lower earnings due to deconsolidation of Eletropaulo in November 2017 and the sale of Masinloc in March
2018.
These decreases were partially offset by:
• Current year gains on sales of Electrica Santiago and CTNG in Chile;
• Higher earnings in Colombia primarily due to higher contract sales and prices; and
• Higher earnings in Vietnam due to the adoption of the new revenue recognition standard (See Note 1—
General and Summary of Significant Accounting Policies included in Item 8.—Financial Statements and
Supplementary Data of this Form 10-K for further information).
Net income attributable to noncontrolling interests and redeemable stock of subsidiaries increased $31 million,
or 9%, to $384 million in 2017, compared to $353 million in 2016. This increase was primarily due to:
• Asset impairments at Buffalo Gap I and II in 2016.
These increases were partially offset by:
•
Income tax benefits at Eletropaulo in 2016 (reflected within discontinued operations).
Net income (loss) attributable to The AES Corporation
Net income attributable to The AES Corporation increased $2,364 million to $1,203 million in 2018, compared
to a loss of $1,161 million in 2017. This increase was primarily due to:
• Gains on the sales of Masinloc, Eletropaulo (reflected within discontinued operations), CTNG, and Electrica
Santiago, and prior year losses on the sales of Kazakhstan CHPs and HPPs;
• Prior year loss on deconsolidation of Eletropaulo (reflected within discontinued operations);
• Prior year impact of U.S. tax reform enacted in December 2017;
• Prior year asset impairments at DPL, Laurel Mountain and in Kazakhstan;
• Lower interest expense at the Parent Company and Gener; and
• Higher margins at our South America, MCAC and US and Utilities SBUs.
These increases were partially offset by:
• Higher current year tax expense due to the new GILTI rules in the U.S.;
• Current year impairment at Shady Point;
76
• Current year other-than-temporary impairment of Guacolda;
• Higher losses on extinguishment of debt in the current year;
• Current year foreign exchange losses primarily due to the devaluation of the Argentine peso and foreign
currency gains in the prior year;
• Prior year favorable impact of a legal settlement at Uruguaiana; and
• Lower margins in the current year at our Eurasia SBU as a result of the sales of Masinloc and Kazakhstan.
Net loss attributable to The AES Corporation increased $31 million, or 3%, to $1,161 million in 2017, compared
to $1,130 million in 2016. This increase was primarily due to:
•
Impact of U.S. tax reform enacted in December 2017;
• Losses on the sales of Kazakhstan CHPs and HPPs;
• Loss on deconsolidation of Eletropaulo (reflected within discontinued operations);
•
Impairments at Laurel Mountain, Kilroot and in Kazakhstan; and
• Higher loss on extinguishment of debt.
These increases were partially offset by:
•
Impairments at DPL in 2016;
• Loss on sale of Sul in 2016 (reflected within discontinued operations);
• Favorable impact of a legal settlement at Uruguaiana;
• Higher gains on foreign currency transactions; and
• Higher margins at our MCAC SBU.
SBU Performance Analysis
Segments
We are organized into four market-oriented SBUs: US and Utilities (United States, Puerto Rico and El
Salvador); South America (Chile, Colombia, Argentina and Brazil); MCAC (Mexico, Central America and the
Caribbean); and Eurasia (Europe and Asia). During the first quarter of 2018, the Andes and Brazil SBUs were
merged in order to leverage scale and are now reported together as part of the South America SBU. Further, the
Puerto Rico and El Salvador businesses, formerly part of the MCAC SBU, were combined with the US SBU, which
is now reported as the US and Utilities SBU.
Non-GAAP Measures
Adjusted Operating Margin, Adjusted PTC and Adjusted EPS 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.
Effective January 1, 2018, the Company changed the definitions of Adjusted PTC and Adjusted EPS to
exclude unrealized gains or losses from equity securities resulting from a newly effective accounting standard. We
believe excluding these gains or losses provides a more accurate picture of continuing operations. Factors in this
determination include the variability due to unrealized gains or losses related to equity securities remeasurement.
Adjusted Operating Margin
We define Adjusted Operating Margin as Operating Margin, adjusted for the impact of NCI, excluding (a)
unrealized gains or losses related to derivative transactions; (b) benefits and costs associated with dispositions and
acquisitions of business interests, including early plant closures; and (c) costs directly associated with a major
restructuring program, including, but not limited to, workforce reduction efforts, relocations and office consolidation.
The allocation of HLBV earnings to noncontrolling interests is not adjusted out of Adjusted Operating Margin. 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 gains or losses related to derivative transactions
and strategic decisions to dispose of or acquire business interests. Adjusted Operating Margin should not be
construed as an alternative to Operating Margin, which is determined in accordance with GAAP.
77
Reconciliation of Adjusted Operating Margin (in millions)
Operating Margin
Noncontrolling interests adjustment (1)
Unrealized derivative losses (gains)
Disposition/acquisition losses
Restructuring costs (2)
Total Adjusted Operating Margin
_____________________________
Years Ended December 31,
2017
2016
2018
$
$
2,573
(686)
19
21
1
1,928
$
$
2,465
(689)
(5)
22
22
1,815
$
$
2,383
(645)
9
—
—
1,747
(1)
(2)
The allocation of HLBV earnings to noncontrolling interests is not adjusted out of Adjusted Operating Margin.
In February 2018, the Company announced a reorganization as a part of its ongoing strategy to simplify its portfolio, optimize its cost structure and reduce its
carbon intensity.
Adjusted PTC
We define Adjusted PTC as pre-tax income from continuing operations attributable to The AES Corporation
excluding gains or losses of the consolidated entity due to (a) unrealized gains or losses related to derivative
transactions and equity securities; (b) unrealized foreign currency gains or losses; (c) gains, losses, benefits and
costs associated with dispositions and acquisitions of business interests, including early plant closures; (d) losses
due to impairments; (e) gains, losses and costs due to the early retirement of debt; and (f) costs directly associated
with a major restructuring program, including, but not limited to, workforce reduction efforts, relocations and office
consolidation. 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
Consolidated Statement of Operations, such as general and administrative expenses 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 the most relevant measure considered in the Company's internal evaluation of the financial
performance of its segments. Factors in this determination include the variability due to unrealized gains or losses
related to derivative transactions or equity securities remeasurement, unrealized foreign currency gains or losses,
losses due to impairments and strategic decisions to dispose of or acquire business interests, retire debt or
implement restructuring initiatives, 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. 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.
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.
78
Reconciliation of Adjusted PTC (in millions)
Income (loss) from continuing operations, net of tax, attributable to The AES Corporation
$
Income tax expense (benefit) attributable to The AES Corporation
Pre-tax contribution
Unrealized derivative and equity securities losses (gains)
Unrealized foreign currency losses (gains)
Disposition/acquisition losses (gains)
Impairment expense
Loss on extinguishment of debt
Restructuring costs (1)
Total Adjusted PTC
_____________________________
$
Years Ended December 31,
2017
2016
2018
985
563
1,548
33
51
(934)
307
180
—
1,185
$
$
(507) $
828
321
(3)
(59)
123
542
62
31
1,017
$
(20)
(111)
(131)
(9)
22
6
933
29
—
850
(1)
In February 2018, the Company announced a reorganization as a part of its ongoing strategy to simplify its portfolio, optimize its cost structure and reduce its
carbon intensity.
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 and equity securities; (b) unrealized foreign currency gains or losses; (c) gains,
losses, benefits and costs associated with dispositions and acquisitions of business interests, including early plant
closures, and the tax impact from the repatriation of sales proceeds; (d) losses due to impairments; (e) gains,
losses and costs due to the early retirement of debt; (f) costs directly associated with a major restructuring program,
including, but not limited to, workforce reduction efforts, relocations and office consolidation; and (g) tax benefit or
expense related to the enactment effects of 2017 U.S. tax law reform and related regulations and any subsequent
period adjustments related to enactment effects.
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 or equity securities
remeasurement, unrealized foreign currency gains or losses, losses due to impairments and strategic decisions to
dispose of or acquire business interests, retire debt or implement restructuring initiatives, 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.
The Company reported a loss from continuing operations of $0.77 and $0.04 per share for the years ended
December 31, 2017 and 2016, respectively. For purposes of measuring diluted loss per share under GAAP,
common stock equivalents were excluded from weighted average shares as their inclusion would be anti-dilutive.
However, for purposes of computing Adjusted EPS, the Company has included the impact of anti-dilutive common
stock equivalents. The table below reconciles the weighted average shares used in GAAP diluted loss per share to
79
the weighted average shares used in calculating the non-GAAP measure of Adjusted EPS. No reconciliation is
necessary for the year ended December 31, 2018 as the Company reported income from continuing operations.
Reconciliation of Denominator Used For Adjusted Earnings Per Share
(in millions, except per share data)
GAAP DILUTED LOSS PER SHARE
Loss from continuing operations attributable to The AES
Corporation common stockholders
EFFECT OF ANTI-DILUTIVE SECURITIES
Restricted stock units
NON-GAAP DILUTED LOSS PER SHARE
Reconciliation of Adjusted EPS
Diluted earnings (loss) per share from continuing operations
Unrealized derivative and equity securities losses (gains)
Unrealized foreign currency losses (gains)
Disposition/acquisition losses (gains)
Impairment expense
Loss on extinguishment of debt
Restructuring costs
U.S. Tax Law Reform Impact
Less: Net income tax expense (benefit)
Adjusted EPS
_____________________________
Year Ended December 31, 2017
$ per
share
Shares
Loss
Year Ended December 31, 2016
$ per
share
Shares
Loss
$
(507)
660
$
(0.77) $
(25)
660
$
(0.04)
—
(507)
$
2
662
$
0.01
(0.76) $
—
(25)
2
662
$
—
(0.04)
Years Ended December 31,
2017
2016
2018
$
$
1.48
0.05
0.09
(1.41)
0.46
0.27
—
0.18
0.12
1.24
(1)
(2)
(4)
(7)
(10)
(12)
$
$
(5)
(3)
(0.76)
—
(0.10)
0.19
0.82
0.09
0.05
1.08 (11)
(0.29)
1.08
(13)
(8)
$
$
(0.04)
(0.01)
0.03
0.01
1.41
0.05
—
—
(0.51)
0.94
(6)
(9)
(14)
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
Amount primarily relates to unrealized FX losses of $22 million, or $0.03 per share, associated with the devaluation of long-term receivables denominated in
Argentine pesos, and unrealized FX losses of $14 million, or $0.02 per share, on intercompany receivables denominated in Euros and British pounds at the
Parent Company.
Amount primarily relates to gain on sale of Masinloc of $772 million, or $1.16 per share, gain on sale of CTNG of $86 million, or $0.13 per share, gain on sale
of Electrica Santiago of $36 million, or $0.05 per share, gain on remeasurement of contingent consideration at AES Oahu of $32 million, or $0.05 per share,
gain on sale related to the Company's contribution of AES Advancion energy storage to the Fluence joint venture of $23 million, or $0.03 per share and
realized derivative gains associated with the sale of Eletropaulo of $21 million, or $0.03 per share; partially offset by loss on disposal of the Beckjord facility
and additional shutdown costs related to Stuart and Killen at DPL of $21 million, or $0.03 per share.
Amount primarily relates to loss on sale of Kazakhstan CHPs of $49 million, or $0.07 per share, realized derivative losses associated with the sale of Sul of
$38 million, or $0.06 per share, loss on sale of Kazakhstan HPPs of $33 million, or $0.05 per share, and costs associated with early plant closures at DPL of
$24 million, or $0.04 per share; partially offset by gain on Masinloc contingent consideration of $23 million, or $0.03 per share and gain on sale of Miami Fort
and Zimmer of $13 million, or $0.02 per share.
Amount primarily relates to asset impairments at Shady Point of $157 million, or $0.24 per share, and Nejapa of $37 million, or $0.06 per share, and other-
than-temporary impairment of Guacolda of $96 million, or $0.14 per share.
Amount primarily relates to asset impairments at Kazakhstan CHPs of $94 million, or $0.14 per share, at Kazakhstan HPPs of $92 million, or $0.14 per share,
at Laurel Mountain of $121 million, or $0.18 per share, at DPL of $175 million, or $0.27 per share and at Kilroot of $37 million, or $0.05 per share.
Amount primarily relates to asset impairments at DPL of $859 million, or $1.30 per share, at Buffalo Gap II of $159 million ($49 million, or $0.07 per share, net
of NCI) and at Buffalo Gap I of $77 million ($23 million, or $0.03 per share, net of NCI).
Amount primarily relates to loss on early retirement of debt at the Parent Company of $171 million, or $0.26 per share.
Amount primarily relates to losses on early retirement of debt at the Parent Company of $92 million, or $0.14 per share, at AES Gener of $20 million, or $0.02
per share, and at IPALCO of $9 million or $0.01 per share; partially offset by a gain on early retirement of debt at AES Argentina of $65 million, or $0.10 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.
(10) Amount relates to a SAB 118 charge to finalize the provisional estimate of one-time transition tax on foreign earnings of $194 million, or $0.29 per share,
partially offset by a SAB 118 income tax benefit to finalize the provisional estimate of remeasurement of deferred tax assets and liabilities to the lower
corporate tax rate of $77 million, or $0.11 per share.
(11) Amount relates to a one-time transition tax on foreign earnings of $675 million, or $1.02 per share and the remeasurement of deferred tax assets and liabilities
to the lower corporate tax rate of $39 million, or $0.06 per share.
(12) Amount primarily relates to the income tax expense under the GILTI provision associated with the gains on sales of business interests, primarily Masinloc, of
$97 million, or $0.15 per share, and income tax expense associated with gains on sale of CTNG of $36 million, or $0.05 per share and Electrica Santiago of
$13 million, or $0.02 per share; partially offset by income tax benefits associated with the loss on early retirement of debt at the Parent Company of $36
million, or $0.05 per share, and income tax benefits associated with the impairment at Shady Point of $33 million, or $0.05 per share.
(13) Amount primarily relates to the income tax benefit associated with asset impairments of $148 million, or $0.22 per share.
(14) Amount primarily relates to the income tax benefit associated with asset impairments of $332 million, or $0.50 per share.
US AND UTILITIES SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC (in millions)
for the periods indicated:
80
For the Years Ended December 31,
2018
2017
2016
Operating Margin
Adjusted Operating Margin (1)
Adjusted PTC (1)
_____________________________
$
$
733
678
511
$
693
623
424
719
637
392
$ Change
2018 vs. 2017
40
$
55
87
% Change
2018 vs. 2017
$ Change
2017 vs. 2016
(26)
(14)
32
6% $
9%
21%
% Change
2017 vs. 2016
-4%
-2%
8%
(1)
A non-GAAP financial measure, adjusted for the impact of NCI. See SBU Performance Analysis—Non-GAAP Measures for definition and Item 1.—Business
for the respective ownership interest for key businesses.
Fiscal year 2018 versus 2017
Operating Margin increased $40 million, or 6%, which was driven primarily by the following (in millions):
Increase at DPL primarily due to higher regulated rates following the approval of the 2017 ESP and the 2018 distribution rate
order and favorable weather
Increase at DPL driven by a one-time credit to depreciation expense, primarily as a result of a reduction in the ARO liability at
DPL's closed plants, Stuart and Killen
Increase at IPL due to higher wholesale margins driven by Eagle Valley coming online and higher retail margins due to favorable
weather
Increase at Southland driven by higher market energy sales, partially offset by a decrease in capacity sales and lower ancillary
services due to the expiration of long-term agreements
Decrease at Hawaii primarily due to higher coal prices and lower gain on valuation of MTM commodity swaps
Impact of the sale and closure of generation plants at DPL
Decrease at IPL due to higher maintenance expense due to increased current year outages
Other
Total US and Utilities SBU Operating Margin Increase
$
$
35
32
23
12
(24)
(12)
(21)
(5)
40
Adjusted Operating Margin increased $55 million primarily due to the drivers above, adjusted for a $24 million
unrealized loss on coal derivatives in Hawaii partially offset by restructuring charges in the prior year.
Adjusted PTC increased $87 million, primarily driven by the increase in Adjusted Operating Margin described
above, as well as an increase in the Company's share of earnings at Distributed Energy due to new solar project
growth, lower interest expense and the HLBV allocation of noncontrolling interest earnings at Buffalo Gap, partially
offset by lower allowance for equity funds used during construction at IPALCO.
Fiscal year 2017 versus 2016
Operating Margin decreased $26 million, or 4%, which was driven primarily by the following (in millions):
Decrease at DPL driven by lower retail margins due to lower regulated rates
Decrease at DPL primarily due to lower volumes due to the shutdown of Stuart Unit 1 and lower commercial availability
Decrease at IPL due to implementation of new base rates in Q2 2016 which resulted in a favorable change in accrual
Increase at DPL as a result of lower depreciation expense due to lower PP&E carrying values from impairments in 2016 and
2017
Other
Total US and Utilities SBU Operating Margin Decrease
$
$
(22)
(21)
(18)
26
9
(26)
Adjusted Operating Margin decreased $14 million primarily due to the drivers above, excluding unrealized
gains and losses on derivatives, restructuring charges and costs associated with early plant closures.
Adjusted PTC increased $32 million, driven by earnings from equity affiliates due to the 2017 acquisition of
sPower, the Company's share of earnings at Distributed Energy due to new solar project growth and an increase in
insurance recoveries at DPL. The increase in Adjusted PTC was partially offset by the decrease of $14 million in
Adjusted Operating Margin described above and a 2016 gain on contract termination at DP&L.
SOUTH AMERICA SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC (in millions)
for the periods indicated:
For the Years Ended December 31,
2018
2017
2016
Operating Margin
Adjusted Operating Margin (1)
Adjusted PTC (1)
_____________________________
$
$
1,017
612
519
$
862
500
446
823
486
428
$ Change
2018 vs. 2017
155
$
112
73
% Change
2018 vs. 2017
$ Change
2017 vs. 2016
39
14
18
18% $
22%
16%
% Change
2017 vs. 2016
5%
3%
4%
(1)
A non-GAAP financial measure, adjusted for the impact of NCI. See SBU Performance Analysis—Non-GAAP Measures for definition and Item 1.—Business
for the respective ownership interest for key businesses.
81
Fiscal year 2018 versus 2017
Operating Margin increased $155 million, or 18%, which was driven primarily by the following (in millions):
Increase in Argentina mainly related to higher capacity prices resulting from market reforms enacted in 2017 and lower fixed
costs primarily due to the devaluation of the Argentine peso
Increase in Colombia mainly related to higher contract pricing in 2018 and higher generation
Margin on new PPAs in Chile at Gener, Angamos and Cochrane
Impact of the sale of Electrica Santiago
Lower fixed costs at Gener associated with planned maintenance performed in Q3 2017
Lower contract sales to distribution companies in Chile net of higher revenue associated with a contract termination
Other
Total South America SBU Operating Margin Increase
$
$
71
64
50
(38)
21
(24)
11
155
Adjusted Operating Margin increased $112 million primarily due to the drivers above, adjusted for NCI.
Adjusted PTC increased $73 million, mainly due to the increase in Adjusted Operating Margin described above
and lower interest in Chile, partially offset by a $28 million decrease associated with a gain recognized in the prior
year from the settlement of a legal dispute with YPF at Uruguaiana, higher interest expense in Brazil, lower equity
earnings in Chile and higher realized foreign currency losses in Argentina.
Fiscal year 2017 versus 2016
Including the favorable impact of foreign currency translation and remeasurement of $38 million, Operating
Margin increased $39 million, or 5%, which was driven primarily by the following (in millions):
Start of operations at Cochrane Units I and II in July and October 2016, respectively
Higher capacity payments in Argentina primarily due to changes in regulation in 2017
Net impact of volume and prices of lower energy purchased in spot market at Tietê
Higher contract sales at Chivor primarily due to an increase in contracted capacity at higher prices
Higher volume due to acquisition of new wind entities - Alto Sertão II
Favorable FX impacts at Tietê
Net impact of volume and prices of bilateral contracts due to higher energy purchased at Tietê
Negative impact in Gener due to new regulation on emissions (Green Taxes)
Lower spot sales at Chivor mainly due to lower generation and lower spot prices
Lower availability of efficient generation resulting in higher replacement energy and fixed costs, mainly associated with major
maintenance at Ventanas Complex in Chile
Lower margin at the SING market primarily due to lower contract sales and increase in coal prices at Norgener partially offset by
higher spot sales
Lower generation at CTSN mainly due to lower demand
Other
Total South America SBU Operating Margin Increase
$
$
72
64
71
35
23
21
(100)
(41)
(37)
(29)
(21)
(26)
7
39
Adjusted Operating Margin increased $14 million primarily due to the drivers above, adjusted for NCI.
Adjusted PTC increased $18 million, driven by a $28 million increase from the settlement of a legal dispute
with YPF at Uruguaiana in 2017 and the $14 million increase in Adjusted Operating Margin described above, as
well as foreign currency gains in Argentina associated with the collection of financing receivables, prepayment of
financial debt denominated in U.S. dollars in 2017 and lower foreign currency losses associated with the sale of
Argentina’s sovereign bonds at Termoandes. These positive impacts were partially offset by higher interest
expense, mainly due to the acquisition of Alto Sertão II debt, issuance of debt at Argentina and lower interest
capitalization in Cochrane and Chivor, and the write-off of water rights at Gener resulting from a business
development project that is no longer pursued.
MCAC SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC (in millions)
for the periods indicated:
For the Years Ended December 31,
2018
2017
2016
Operating Margin
Adjusted Operating Margin (1)
Adjusted PTC (1)
$
$
534
391
300
$
465
358
277
390
292
222
$ Change
2018 vs. 2017
69
$
33
23
82
% Change
2018 vs. 2017
$ Change
2017 vs. 2016
75
66
55
15% $
9%
8%
% Change
2017 vs. 2016
19%
23%
25%
_____________________________
(1)
A non-GAAP financial measure, adjusted for the impact of NCI. See SBU Performance Analysis—Non-GAAP Measures for definition and Item 1.—Business
for the respective ownership interest for key businesses.
Fiscal year 2018 versus 2017
Operating Margin increased $69 million, or 15%, which was driven primarily by the following (in millions):
Increase in Dominican Republic due to higher spot prices
Higher contracted energy sales in Panama mainly driven by the commencement of operations at the Colon combined cycle
facility in September 2018
Higher availability driven by improved hydrology in Panama
Higher contracted energy sales in Dominican Republic mainly driven by the commencement of operations at the Los Mina
combined cycle facility in June 2017 and lower forced maintenance outages
Decrease in Mexico due to pension plan pass-through adjustments and higher fuel costs
Other
Total MCAC SBU Operating Margin Increase
$
$
32
21
17
12
(8)
(5)
69
Adjusted Operating Margin increased $33 million primarily due to the drivers above, adjusted for NCI.
Adjusted PTC increased $23 million, mainly driven by the increase in Adjusted Operating Margin as described
above, partially offset by lower capitalized interest due to project completions in Panama and Dominican Republic
and lower foreign currency gains in Mexico.
Fiscal year 2017 versus 2016
Operating Margin increased $75 million, or 19%, which was driven primarily by the following (in millions):
Higher contracted energy sales in Dominican Republic net of LNG fuel consumption, mainly driven by Los Mina combined cycle
commencement of operations in June 2017
Higher availability driven by improved hydrology in Panama
Higher availability in Mexico mainly driven by unplanned maintenance in 2016
Other
Total MCAC SBU Operating Margin Increase
$
$
34
26
13
2
75
Adjusted Operating Margin increased $66 million primarily due to the drivers above, adjusted for NCI.
Adjusted PTC increased $55 million, driven by the increase in Adjusted Operating Margin of $66 million as
described above.
EURASIA SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC (in millions)
for the periods indicated:
For the Years Ended December 31,
2018
2017
2016
Operating Margin
Adjusted Operating Margin (1)
Adjusted PTC (1)
_____________________________
$
$
227
194
222
$
422
306
290
427
303
283
$ Change
2018 vs. 2017
(195)
$
(112)
(68)
% Change
2018 vs. 2017
$ Change
2017 vs. 2016
(5)
3
7
-46% $
-37%
-23%
% Change
2017 vs. 2016
-1%
1%
2%
(1)
A non-GAAP financial measure, adjusted for the impact of NCI. See SBU Performance Analysis—Non-GAAP Measures for definition and Item 1.—Business
for the respective ownership interest for key businesses.
Fiscal year 2018 versus 2017
Including favorable FX impacts of $8 million, Operating Margin decreased $195 million, or 46%, which was
driven primarily by the following (in millions):
Impact of the sale of Masinloc power plant in March 2018
Impact of the sale of the Kazakhstan CHPs and the expiration of HPP concession in 2017
Decrease in Vietnam due to adoption of the new revenue recognition standard in 2018 and higher maintenance costs
Other
Total Eurasia SBU Operating Margin Decrease
$
$
(122)
(36)
(33)
(4)
(195)
Adjusted Operating Margin decreased $112 million, or 37%, primarily due to the drivers above, adjusted for
NCI.
Adjusted PTC decreased $68 million, primarily driven by the decrease in Adjusted Operating Margin discussed
above, partially offset by the positive impact in Vietnam due to increased interest income from the higher financing
83
component of contract consideration as a result of adoption of the new revenue recognition standard in 2018. See
Note 1—General and Summary of Significant Accounting Policies—New Accounting Standards Adopted included in
Item 8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
Fiscal year 2017 versus 2016
Operating Margin decreased $5 million, or 1%, and Adjusted Operating Margin increased $3 million, or 1%,
with no material drivers.
Adjusted PTC increased $7 million, primarily driven by the increase in Adjusted Operating Margin, adjusted for
NCI and excluding unrealized gains and losses on derivatives.
Key Trends and Uncertainties
During 2019 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
The macroeconomic and political environments in some countries where our subsidiaries conduct business
have changed during 2018. This 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.
United States Tax Law Reform
In December 2017, the United States enacted the TCJA. The legislation significantly revised the U.S.
corporate income tax system by, among other things, lowering the corporate income tax rate, introducing new
limitations on interest expense deductions, subjecting foreign earnings in excess of an allowable return to
current U.S. taxation, and adopting a semi-territorial corporate tax system. These changes impacted our 2018
effective tax rate and will materially impact our effective tax rate in future periods. Furthermore, we anticipate
that higher U.S. tax expense may fully utilize our remaining net operating loss carryforwards in the near term,
which could lead to material cash tax payments in the United States. Specific provisions of the TCJA and their
potential impacts on the Company are noted below. Our interpretation of the TCJA may change as the U.S.
Treasury and the Internal Revenue Service issue additional guidance. Such changes may be material.
Transition Tax — As further explained in Note 21—Income Taxes included in Item 8.—Financial Statements
and Supplementary Data of this Form 10-K we have concluded our analysis of the implementation impacts of
the TCJA and included adjustments to our previous estimates in accordance with the guidance of SAB 118. Our
revised estimates took into account interpretative guidance issued in 2018 by the U.S. Treasury in proposed
regulations. In the first quarter of 2019, the U.S. Treasury issued final regulations related to the one-time
transition tax which further amended the guidance of the proposed regulations. We are still evaluating the final
regulations which may have a material impact on our financial statements. The impacts of the final regulations
will be reflected in our financial statements during the quarter ended March 31, 2019.
Limitation on Interest Expense Deductions — The TCJA introduced a new limitation on the deductibility of
net interest expense beginning January 1, 2018. The deduction will be limited to interest income, plus 30 percent
of tax basis EBITDA through 2021 (30 percent of EBIT beginning January 1, 2022). This determination is made
at the consolidated group level, although it applies separately to partnerships. While interest expense of
regulated utilities may be exempt from the limitation, the proposed regulations issued by the U.S. Treasury in
2018 would effectively limit interest expense of our U.S. utilities. The proposed regulations may change before
they are fully enacted in final form and are not retroactive; we have not early adopted the proposed regulations.
Given typical project financing and current U.S. holding company debt levels, we anticipate that this limitation
will materially, negatively impact our effective tax rate.
Global Intangible Low Taxed Income (“GILTI”) — The TCJA subjects the earnings of foreign subsidiaries to
current U.S. taxation to the extent that those earnings exceed an allowable economic return on investment. The
foreign earnings subject to current taxation under the GILTI provision are not limited to those derived from
84
intangible property and may include gains derived from some future asset sales. The GILTI provision will subject
a significant portion of our foreign earnings to current U.S. taxation. In 2018, the GILTI provision materially,
negatively impacted our effective tax rate and we expect this to continue in future years. Prospectively, the
consequences of the new GILTI provision may be partially mitigated by foreign tax credits. Proposed regulations
were issued in 2018 by the U.S. Treasury which provided further guidance on GILTI and the related foreign tax
credit, however there are further regulations expected and they may change before enacted in final form.
State Taxes — The reactions of the individual states to federal tax reform are still evolving. Most states will
assess whether and how the federal changes will be incorporated into their state tax legislation. Some states
have already decided whether to conform to new provisions of the federal tax law, such as the one-time
transition tax and GILTI, while many other states have not yet enacted final legislation. As we expect higher
taxable income in the future due to the federal changes, this may also lead to higher state taxable income. Our
current state tax provisions predominantly have full valuation allowances against state net operating losses.
These positions will be re-assessed in the future as state tax law evolves and may result in material changes in
position.
Tax Equity Structures — Our U.S. renewable energy portfolio operates primarily through tax equity
partnerships. We cannot be certain of the impacts U.S. tax reform may have on availability or pricing of tax
equity for future growth opportunities. Impacts of provisions such as the lower tax rate and immediate expensing
may impact the amount and timing of returns allocable to our partners in our existing tax equity structures.
Puerto Rico — Our subsidiaries in Puerto Rico have a long-term PPA with state-owned PREPA, which has
been facing economic challenges that could result in a material adverse effect on our business in Puerto Rico.
The Puerto Rico Oversight, Management, and Economic Stability Act (“PROMESA”) was enacted to create a
structure for exercising federal oversight over the fiscal affairs of U.S. territories and created procedures for
adjusting debt accumulated by the Puerto Rico government and, potentially, other territories (“Title III”). Finally,
PROMESA expedites the approval of key energy projects and other critical projects in Puerto Rico.
PROMESA allowed for the establishment of an Oversight Board with broad powers of budgetary and financial
control over Puerto Rico. The Oversight Board filed for bankruptcy on behalf of PREPA under Title III in July 2017.
As a result of the bankruptcy filing, AES Puerto Rico and AES Ilumina’s non-recourse debt of $317 million and $34
million, respectively, continue to be in default and are classified as current as of December 31, 2018. The Company
is in compliance with its debt payment obligations as of December 31, 2018.
After the events of Hurricanes Irma and Maria in September 2017, Puerto Rico’s infrastructure was severely
damaged, including electric infrastructure and transmission lines. AES Puerto Rico resumed generation during the
first quarter of 2018 and continues to be the lowest cost and EPA compliant energy provider in Puerto Rico and a
critical supplier to PREPA. According to the US Federal Emergency Management Agency, as of January 2019
PREPA's recovery status is at 99%.
The Company's receivable balances in Puerto Rico as of December 31, 2018 totaled $68 million, of which $18
million was overdue. Despite the disruption caused by the hurricanes and the Title III protection, PREPA has been
making substantially all of its payments to the generators in line with historical payment patterns.
A proposed Energy Public Policy law was introduced in October 2018 which includes the elimination of coal as
a source for electricity generation by January 1, 2028 and the accelerated deployment of renewables (20% by 2025;
50% by 2040 and 100% by 2050). AES Puerto Rico's long-term PPA with PREPA expires December 31, 2027.
Puerto Rico's Senate and House of Representatives are still debating certain amendments.
Considering the information available as of the filing date, Management believes the carrying amount of our
assets in Puerto Rico of $598 million is recoverable as of December 31, 2018.
Argentina — During the second quarter of 2018, all of the three-year cumulative inflation rates commonly used
to evaluate Argentina’s inflation exceeded 100%. Therefore, Argentina’s economy was determined to be highly
inflationary. Since the tariffs and debt at our primary businesses in Argentina are denominated in USD, the
functional currency of those businesses is USD. As such, the determination that the Argentina economy is highly
inflationary is not expected to have a material impact on the Company’s financial statements.
United Kingdom — In June 2016, the UK held a referendum in which voters approved an exit from the EU,
commonly referred to as “Brexit.” In January 2019, the UK parliament rejected a proposed withdrawal agreement
that the EU had supported. The UK is expected to exit the EU on March 29, 2019. While the full impact of the Brexit
remains uncertain, these changes are not expected to have a material adverse effect on our operations and
consolidated financial results.
85
LIBOR Phase Out — In July 2017, the UK Financial Conduct Authority announced the phase out of LIBOR by
the end of 2021. The Alternative Reference Rate Committee at the Federal Reserve is working to establish a new
benchmark replacement rate. While AES maintains financial instruments that use LIBOR as an interest rate
benchmark, the full impact of the phase out is uncertain until a new replacement benchmark is determined and
implementation plans are more fully developed.
Regulatory
Maritza PPA Review — The DG Comp continues to review whether Maritza’s PPA with NEK is compliant with
the European Commission’s state aid rules. Although no formal investigation has been launched by DG Comp to
date, Maritza has engaged in discussions with the DG Comp case team and representatives of Bulgaria to discuss
the agency’s review. In the near term, Maritza expects that it will engage in discussions with Bulgaria to attempt to
reach a negotiated resolution concerning DG Comp’s review. The anticipated discussions could involve a range of
potential outcomes, including but not limited to termination of the PPA and payment of some level of compensation
to Maritza. Any negotiated resolution would be subject to mutually acceptable terms, lender consent, and DG Comp
approval. At this time, we cannot predict the outcome of the anticipated discussions between Maritza and Bulgaria,
nor can we predict how DG Comp might resolve its review if the 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.
Considering the information available as of the filing date, Management believes the carrying value of our
long-lived assets at Maritza of approximately $1.1 billion is recoverable as of December 31, 2018.
Foreign Exchange
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 USD, and currencies of the countries in which we
operate. In 2018, there was a significant devaluation in the Argentine peso against the USD, which had an impact
on our 2018 results. Continued material devaluation of the Argentine peso against the USD could have an impact
on our future results. For additional information, refer to Item 7A.—Quantitative and Qualitative Disclosures About
Market Risk.
Alto Maipo
Alto Maipo has experienced cost overruns which have resulted in increased projected costs over the original
$2 billion budget. Construction at the project is continuing, and the project is 75% complete.
In February 2018, Alto Maipo entered into a new construction contract with Strabag. The new contract is fixed-
price and lump sum, transfers geological and construction risk to Strabag and provides a date certain for completion
with strong performance and completion guarantees.
In May 2018, Alto Maipo and the project's senior lenders executed the financial restructuring of the project.
The restructuring, among other things, includes additional funding commitments of up to $400 million of which $200
million was already contributed by AES Gener. Any unused portion of AES Gener's commitment will be used to
prepay project debt.
If Alto Maipo is unable to meet certain construction milestones, there could be a material impact to the financing
and value of the project which could have a material impact on the Company. The carrying value of long-lived
assets and deferred tax assets of Alto Maipo as of December 31, 2018 was approximately $2 billion and $60
million, respectively. Management believes the carrying value of the long-lived asset group is recoverable as of
December 31, 2018. In addition, Management believes it is more likely than not the deferred tax assets will be
realized; however, the deferred tax assets could be reduced if estimates of future taxable income are decreased.
Andres
On September 3, 2018, lightning affected the Andres 319 MW combined cycle natural gas facility in the
Dominican Republic (“the Plant”) resulting in significant damage to its steam turbine and generator. The Company
has business interruption and property damage insurance coverage, subject to pre-defined deductibles, under its
existing programs.
On September 25, 2018, the Plant restarted operations running the gas turbine in simple cycle at partial load
of approximately 120 MW. Management estimates that the Plant will operate the gas turbine in simple cycle at full
86
load of approximately 185 MW starting in the second quarter of 2019, and in combined cycle at full capacity by the
fourth quarter of 2019.
To mitigate the impact of the reduced capacity in the local energy market, the Company installed 120 MW of
rental power (gas turbines) until the combined cycle facility is at full load. The rental units were fully operational
beginning in December 2018.
Considering the information available as of the filing date, Management believes the carrying amount of our
long-lived assets in Andres of $395 million is recoverable as of December 31, 2018.
Changuinola Tunnel Leak
Increased water levels were noted in a creek near the Changuinola power plant, a 223 MW hydroelectric
power facility in Panama. After the completion of an assessment, the Company has confirmed loss of water in
specific sections of the tunnel. The plant is in operation and can generate up to its maximum capacity. Repairs will
be needed to ensure the long term performance of the facility, during which time the affected units of the plant will
be out of service. Subject to final inspection, the repairs may take up to 10 months to complete and are expected to
commence during the first quarter of 2019. The Company has notified its insurers of a potential claim and has
asserted claims against its construction contractor. However, there can be no assurance of collection. The
Company continues to monitor the situation to identify any potential changes to the tunnel. The Company has not
identified any indicators of impairment and believes the carrying value of the long-lived asset group of $931 million
is recoverable as of December 31, 2018.
Impairments
Long-lived Assets and Equity Affiliates — During the year ended December 31, 2018, the Company
recognized asset and other-than-temporary impairment expense of $355 million. See Note 7—Investments In and
Advances To Affiliates and Note 20—Asset Impairment Expense included in Item 8.—Financial Statements and
Supplementary Data of this Form 10-K for further information. After recognizing this impairment expense, the
carrying value of the equity affiliates and the asset groups, including long-lived assets, and those asset groups that
were assessed and not impaired, totaled $661 million at December 31, 2018.
Events or changes in circumstances that may necessitate 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 it is more likely than not the asset will be disposed of
before the end of its estimated useful life.
Goodwill — The Company considers a reporting unit at risk of impairment when its fair value does not exceed
its carrying amount by more than 10%. During the annual goodwill impairment test performed as of October 1,
2018, the Company determined that the fair value of its Gener reporting unit exceeded its carrying value by 7%.
Therefore, Gener's $868 million goodwill balance was considered to be "at risk" as of December 31, 2018, largely
due to the fact that a market participant would no longer assume perpetual cash flows from coal-fired power plants
due to the increased penetration of renewable energy in Chile.
Through 2028, Gener’s plants remain largely contracted, with most of its PPAs expiring between 2029 and
2037. The Company utilized the income approach in deriving the fair value of the Gener reporting unit, which
included estimated cash flows assuming a 20-year annuity for thermal generation and longer term cash flows for
hydro generation. These cash flows were discounted using a weighted average cost of capital of 7%, which was
determined based on the Capital Asset Pricing Model. See Item 7.—Critical Accounting Policies and Estimates—
Fair Value of Nonfinancial Assets and Liabilities and Note 8—Goodwill and Other Intangible Assets included in Item
8.—Financial Statements and Supplementary Data of this Form 10-K for further information.
The Company monitors its reporting units at risk of Step 1 failure on an ongoing basis, and believes that the
estimates and assumptions used in the calculations are reasonable. Should the fair value of any of the Company’s
reporting units fall below its carrying amount because of reduced operating performance, market declines, changes
in the discount rate, regulatory changes, or other adverse conditions, goodwill impairment charges may be
necessary in future periods.
Capital Resources and Liquidity
Overview — As of December 31, 2018, the Company had unrestricted cash and cash equivalents of $1.2
billion, of which $24 million was held at the Parent Company and qualified holding companies. The Company also
had $313 million in short term investments, held primarily at subsidiaries. In addition, we had restricted cash and
87
debt service reserves of $837 million. The Company also had non-recourse and recourse aggregate principal
amounts of debt outstanding of $15.6 billion and $3.7 billion, respectively. Of the approximately $1.7 billion of our
current non-recourse debt, $825 million was presented as such because it is due in the next twelve months, $351
million relates to debt considered in default due to covenant violations, and $483 million relates to debt at Colon
which is in compliance with its covenants, but is presented as current since it is probable that the Company cannot
meet a technical covenant requirement by its deadline. None of the defaults are 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. The Company expects to modify the Colon loan agreement in 2019 to amend the
requirements of this technical covenant, after which the debt will be re-classified as noncurrent.
We expect such current maturities will be repaid from net cash provided by operating activities of the
subsidiary to which the debt relates, through opportunistic refinancing activity or some combination thereof. We
have $5 million of recourse debt which 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, export credit agencies 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 unhedged exposure to variable interest rate
debt relates to indebtedness under its $366 million outstanding secured term loan due 2022. On a consolidated
basis, of the Company's $19.7 billion of total gross debt outstanding as of December 31, 2018, approximately $3.2
billion bore interest at variable rates that were not subject to a derivative instrument which fixed the interest rate.
Brazil holds $1.1 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, 2018, 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 $712 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
88
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, 2018, we had $78 million in letters of credit outstanding, provided under our senior secured
credit facility, $368 million in letters of credit outstanding, provided under our unsecured senior credit facility. These
letters of credit operate to guarantee performance relating to certain project development and construction activities
and business operations. During the year ended December 31, 2018, the Company paid letter of credit fees ranging
from 1% to 3% 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
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, 2018, the Company had approximately $116 million of
accounts receivable classified as Other noncurrent assets primarily related to certain of its generation businesses in
Argentina. These noncurrent receivables mostly consist of accounts receivable in Argentina that, pursuant to
amended agreements or government resolutions, have collection periods that extend beyond December 31, 2019,
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.
As of December 31, 2018, the Company had approximately $1.4 billion of loans receivable primarily related to
the Mong Duong II facility constructed under a build, operate, and transfer contract in Vietnam. This loan receivable
represents contract consideration related to the construction of the facility, which was substantially completed in
2015, and will be collected over the 25 year term of the plant's PPA. See Note 18—Revenue included in Item 8.—
Financial Statements and Supplementary Data of this Form 10-K for further information.
Cash Sources and Uses
The primary sources of cash for the Company in the year ended December 31, 2018 were cash flows from
operating activities, proceeds from the sales of business interests, and debt financings. The primary uses of cash in
the year ended December 31, 2018 were repayments of debt, capital expenditures, and purchases of short-term
investments.
The primary sources of cash for the Company in the year ended December 31, 2017 were cash flows from
operating activities, debt financings, and sales of short-term investments. The primary uses of cash in the year
ended December 31, 2017 were repayments of debt, purchases of short-term investments, and capital
expenditures.
The primary sources of cash for the Company in the year ended December 31, 2016 were cash flows from
operating activities, debt financings, and sales of short-term investments. The primary uses of cash in the year
ended December 31, 2016 were repayments of debt, purchases of short-term investments, and capital
expenditures.
89
A summary of cash-based activities are as follows (in millions):
Cash Sources:
Net income, adjusted for non-cash items (1)
Proceeds from the sale of business interests, net of cash and restricted cash sold
Issuance of non-recourse debt
Borrowings under revolving credit facilities
Sale of short-term investments
Issuance of recourse debt
Contributions from noncontrolling interests and redeemable security holders
Release of working capital(2)
Other
Total Cash Sources
Cash Uses:
Repayments under revolving credit facilities
Capital expenditures
Repayments of recourse debt
Purchase of short-term investments
Repayments of non-recourse debt
Dividends paid on AES common stock
Distributions to noncontrolling interests
Payments for financed capital expenditures
Increase in working capital(2)
Contributions to equity affiliates
Acquisitions of businesses, net of cash acquired, and equity method investments
Payments for financing fees
Other
Total Cash Uses
Net increase (decrease) in Cash, Cash Equivalents, and Restricted Cash
_____________________________
Year Ended December 31,
2018
2017
2016
$
$
$
$
$
2,529
2,020
1,928
1,865
1,302
1,000
43
—
175
10,862
$
$
(2,238) $
(2,121)
(1,933)
(1,411)
(1,411)
(344)
(340)
(275)
(186)
(145)
(66)
(39)
(138)
(10,647) $
215
$
2,569
108
3,222
2,156
3,540
1,025
73
—
102
12,795
$
$
(1,742) $
(2,177)
(1,353)
(3,310)
(2,360)
(317)
(424)
(179)
(65)
(89)
(609)
(100)
(242)
(12,967) $
(172) $
2,344
538
2,978
1,465
4,904
500
190
553
171
13,643
(1,433)
(2,345)
(808)
(5,151)
(2,666)
(290)
(476)
(113)
—
(6)
(52)
(105)
(189)
(13,634)
9
(1)
(2)
Refer to the table within the Operating Activities section below for a reconciliation of non-cash items affecting net income during the applicable period.
Refer to the table within the Operating Activities section below for explanations of the variance in working capital requirements.
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
2018
December 31,
2017
2016
2018 vs. 2017
2017 vs. 2016
$ Change
$
$
2,343
(505)
(1,643)
$
2,504
(2,599)
43
$
2,897
(2,136)
(747)
(161) $
2,094
(1,686)
(393)
(463)
790
The following table summarizes the key components of our consolidated operating cash flows (in millions):
2018
December 31,
2017
2016
Net income (loss)
Depreciation and amortization
Loss (gain) on disposal and sale of business interests
Impairment expenses
Loss on extinguishment of debt
Deferred income taxes
Net loss (gain) from disposal and impairments of
discontinued businesses
Other adjustments to net income
Non-cash adjustments to net income (loss)
Net income, adjusted for non-cash items
Changes in working capital (1)
Net cash provided by operating activities (2)
_____________________________
$
$
$
1,565
1,003
(984)
355
188
313
(269)
358
964
2,529
(186)
2,343
$
$
$
(777) $
1,169
52
537
68
672
611
237
3,346
2,569
(65)
2,504
$
$
(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.
90
$ Change
(777) $
1,176
(29)
1,098
20
(793)
2018 vs. 2017
2,342
(166)
(1,036)
(182)
120
(359)
2017 vs. 2016
—
$
(7)
81
(561)
48
1,465
1,383
266
3,121
2,344
553
2,897
$
$
(880)
121
(2,382)
(40) $
(121)
(161) $
(772)
(29)
225
225
(618)
(393)
Fiscal Year 2018 versus 2017
Cash provided by operating activities decreased $161 million for the year ended December 31, 2018,
compared to December 31, 2017, primarily driven by a decrease in net income, adjusted for non-cash items of $40
million, and a $121 million increase in working capital requirements.
The increase in working capital requirements of $121 million for the year ended December 31, 2018,
compared to December 31, 2017, was primarily driven by (in millions):
Decreases in operating cash flow resulting from changes in:
Prepaid expenses and other current assets, primarily due to an insurance recovery receivable at Andres, advance payments to
gas suppliers at Colon, and prior year collections of net regulatory assets at Eletropaulo, which was deconsolidated in Q4 2017;
partially offset by the impact of the sales of Miami Fort and Zimmer and the retirement of the Stuart facility at DPL
$
(129)
Accounts payable and other current liabilities, primarily due to the deconsolidation of Eletropaulo in Q4 2017 and the timing of
payments on coal purchases at Gener; partially offset by the timing of payments on coal purchases at Puerto Rico
Other liabilities, primarily due to the deconsolidation of Eletropaulo in Q4 2017; partially offset by a prior year decrease in
deferred tax and derivative liabilities at the Parent Company
Accounts receivable, primarily due to lower collections at Los Mina and Itabo, and higher sales at Colon and Chivor; partially
offset by the deconsolidation of Eletropaulo in Q4 2017 and higher CAMMESA collections at Alicura
Increases in operating cash flow resulting from changes in:
Other assets, primarily related to the deconsolidation of Eletropaulo in Q4 2017 and collections on the construction performance
obligation from the offtaker at Vietnam
Other
Total decrease in operating cash flow from higher working capital requirements
(101)
(57)
(29)
263
(68)
(121)
$
Fiscal Year 2017 versus 2016
Cash provided by operating activities decreased $393 million for the year ended December 31, 2017,
compared to December 31, 2016, primarily driven by an increase in net income, adjusted for non-cash items of
$225 million and a $618 million increase in working capital requirements.
The increase in working capital requirements of $618 million for the year ended December 31, 2017,
compared to December 31, 2016, was primarily driven by (in millions):
Decreases in operating cash flow resulting from changes in:
Prepaid expenses and other current assets, primarily short-term regulatory assets at Eletropaulo and Sul
Accounts receivable, primarily at Maritza and Eletropaulo
Other liabilities, primarily due to higher deferrals into regulatory liabilities related to energy costs in 2016 compared to 2017
at Eletropaulo
Increases in operating cash flow resulting from changes in:
Accounts payable and other current liabilities, primarily at Eletropaulo, Tietê, Gener and Maritza; partially offset at the Parent
Company
Income taxes payable, net, and other taxes payable, primarily at Gener, Tietê and Eletropaulo
Other
Total decrease in operating cash flow from higher working capital requirements
$
$
(763)
(414)
(361)
782
252
(114)
(618)
Investing Activities
Fiscal Year 2018 versus 2017
Net cash used in investing activities decreased $2,094 million for the year ended December 31, 2018
compared to December 31, 2017, which was primarily driven by (in millions):
Increases in:
Proceeds from the sales of business interests, net of cash and restricted cash sold, primarily due to the current year sales of
Masinloc, Electrica Santiago, Eletropaulo, CTNG and the DPL Peaker assets, partially offset by the sale of the Kazakhstan CHPs
in 2017 and transaction costs incurred for the Beckjord sale
$
1,912
Decreases in:
Payments for the acquisitions of business interests, net of cash and restricted cash acquired, primarily due to the acquisitions of
sPower and Alto Sertão II in 2017
Capital expenditures (1)
Cash resulting from net purchases of short-term investments
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.
543
56
(339)
(78)
2,094
$
91
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
Total capital expenditures
2018
December 31,
2017
$ Change
$
$
1,663
423
35
2,121
$
$
1,549
552
76
2,177
$
$
114
(129)
(41)
(56)
Cash used for capital expenditures decreased $56 million for the year ended December 31, 2018 compared to
December 31, 2017, which was primarily driven by (in millions):
Decreases in:
Growth expenditures at the MCAC SBU, primarily related to the completion of the Colon project, and lower spending at Los Mina
due to the completion of the Combined Cycle project
Maintenance and environmental expenditures at the South America SBU, primarily due to the deconsolidation of Eletropaulo in
Q4 2017
Increases in:
Growth expenditures at the US and Utilities SBU, primarily due to increased spending for the Southland re-powering project
Other capital expenditures
Total decrease in capital expenditures
Fiscal Year 2017 versus 2016
$
(242)
(183)
373
(4)
(56)
$
Net cash used in investing activities increased $463 million for the year ended December 31, 2017 compared
to December 31, 2016, which was primarily driven by (in millions):
Increases in:
Payments for the acquisitions of businesses, net of cash and restricted cash acquired, and equity method investees (related to
the acquisitions of sPower and Alto Sertão II in 2017, partially offset by reduced acquisitions of Distributed Energy projects in
2016)
Contributions to equity investments at OPGC and sPower
Cash resulting from net sales of short-term investments
Decreases in:
Proceeds from the sale of business, net of cash and restricted cash sold, related to the sale of Sul in 2016, partially offset by the
sale of Zimmer and Miami Fort
Capital expenditures (1)
Other investing activities
Total increase in net cash used in investing activities
_____________________________
$
$
(557)
(83)
477
(430)
168
(38)
(463)
(1) Refer to the tables below for a breakout of capital expenditures by type and by primary business driver.
The following table summarizes the Company's capital expenditures for growth investments, maintenance and
environmental for the periods indicated (in millions):
Growth Investments
Maintenance
Environmental (1)
Total capital expenditures
_____________________________
(1)
Includes both recoverable and non-recoverable environmental capital expenditures.
2017
December 31,
2016
$ Change
$
$
1,549
552
76
2,177
$
$
1,510
617
218
2,345
$
$
39
(65)
(142)
(168)
92
Cash used for capital expenditures decreased by $168 million for the year ended December 31, 2017
compared to December 31, 2016, which was primarily driven by (in millions):
Decreases in:
Growth expenditures at the South America SBU, primarily due to the completion of the Cochrane project and slower than
anticipated productivity by construction contractors at Alto Maipo
Growth expenditures at the Eurasia SBU, primarily due to timing of payments resulting in more financed capex
Maintenance and environmental expenditures at the US and Utilities SBU, primarily due to lower spending at IPALCO on the
NPDES and MATS compliance and Harding Street refueling projects, decreased spending on CCR compliance, and decreased
spending at DPL on Stuart and Killen facilities due to planned plant closures
Increases in:
Growth expenditures at the US and Utilities SBU, primarily due to increased spending for the Southland re-powering project and
various Distributed Energy projects; partially offset by lower spending related to Eagle Valley at IPALCO
Other capital expenditures
Total decrease in capital expenditures
Financing Activities
Net cash used in financing activities increased $1,686 million for the year ended December 31, 2018
compared to December 31, 2017, which was primarily driven by (in millions):
Increases in:
Net repayments of recourse debt at the Parent Company (1)
Net repayments of non-recourse debt at Angamos, DPL, Chivor, and Maritza
Net repayments on revolving credit facilities at IPALCO and Gener
Net issuance of non-recourse debt at Southland
Decreases in:
Net issuance of non-recourse debt at AES Argentina, Tietê, Colon, Alto Maipo, US Generation, and Los Mina
Net borrowing on revolving credit facilities at the Parent Company
Net repayments of non-recourse debt at IPALCO and Gener
Other financing activities
Total increase in net cash used in financing activities
_____________________________
$
$
$
$
(114)
(73)
(180)
233
(34)
(168)
(605)
(372)
(370)
199
(614)
(413)
518
(29)
(1,686)
(1)
See Note 10—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 $790 million for the year ended December 31, 2017
compared to December 31, 2016, which was primarily driven by (in millions):
Increases in:
Net issuance of non-recourse debt at Southland, Tiete, Eletropaulo, AES Argentina, and Colon
Net repayments of non-recourse debt at Gener and IPALCO
Net borrowing on revolving credit facilities at the Parent Company and Gener
Decreases in:
Net repayments on revolving credit facilities at IPALCO
Net issuance of non-recourse debt at Cochrane
Proceeds from the sale of redeemable stock of subsidiaries at IPALCO
Contributions from noncontrolling interests and redeemable security holders at Colon, IPALCO, and Distributed Energy
Other financing activities
Total Increase in net cash provided by financing activities
Parent Company Liquidity
$
$
1,396
(628)
297
123
(170)
(134)
(117)
23
790
The following discussion of Parent Company Liquidity is included as 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 is determined in accordance with GAAP. 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 facilities, 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 facilities plus cash at qualified holding companies. 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
93
Liquidity is reconciled to its most directly comparable U.S. GAAP financial measure, Cash and cash equivalents, at
December 31, 2018 and 2017 as follows:
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 Company credit facilities
Less: Letters of credit under the credit facilities
Less: Borrowings under the credit facilities
Borrowings available under Parent Company credit facilities
Total Parent Company Liquidity
2018
2017
$
$
1,166
(1,142)
24
1,100
(78)
—
1,022
1,046
$
$
949
(938)
11
1,100
(35)
(207)
858
869
The Parent Company paid dividends of $0.52 per share to its common stockholders during the year ended
December 31, 2018. 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 total recourse debt was $3.7 billion and $4.6 billion at December 31, 2018 and 2017, respectively. See
Note 10—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, 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 facilities, 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, 2018, 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 facilities 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 $1.7 billion. As of December 31, 2018, $351 million of non-recourse debt was current related to such
defaults at two subsidiaries, AES Puerto Rico and AES Ilumina, and $483 million relates to debt at Colon which is in
94
compliance with its covenants, but is presented as current since it is probable that the Company cannot meet a
technical covenant requirement by its deadline. The Company expects to modify the Colon loan agreement in 2019
to amend the requirements of this technical covenant, after which the debt will be re-classified as noncurrent. See
Note 10—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, 2018 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
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
facilities 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, 2018, 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, 2018 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
$ 19,687
6,967
12
643
7,573
6,175
3,944
Less than
1 year
$ 1,701
846
1
74
786
1,494
1,375
1-3
years
$ 3,567
1,625
2
63
973
1,909
1,017
3-5
years
$ 4,407
1,194
2
51
627
1,038
774
More than
5 years
$ 10,012
3,302
7
455
5,187
1,734
778
$
809
—
263
207
326
$ 45,810
$ 6,277
$ 9,419
$ 8,300
$ 21,801
$
Footnote
Reference(4)
10
n/a
11
11
11
11
11
n/a
Other
—
—
—
—
—
—
—
13
13
(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, 2018 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, 2018.
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 9—Regulatory Assets and Liabilities), (2) contingencies (See Note 12
—Contingencies), (3) pension and other postretirement employee benefit liabilities (see Note 13—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,
2018:
Contingent contractual obligations
Amount (in millions)
Guarantees and commitments
Letters of credit under the unsecured credit facility
Letters of credit under the senior secured credit facility
Asset sale related indemnities (1)
Total
_____________________________
$
$
685
368
78
27
1,158
Number of
Agreements
Maximum Exposure Range for
Each Agreement (in millions)
$0 — 157
$1 — 247
$0 — 49
$27
33
10
23
1
67
(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.
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
95
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 2018, 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.
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. Certain of the Company's
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 December 2017 in
the U.S. which decreased the statutory income tax rate from 35% to 21%, required a one-time transition tax, and
introduced numerous other changes. As further outlined in Key Trends and Uncertainties, the Company anticipates
that the GILTI provisions of U.S. tax reform could materially impact the effective tax rate in future periods. See Note
21—Income Taxes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for additional
information.
In accordance with SAB 118, the Company made reasonable estimates of the impacts of U.S. tax reform on its
2017 financial results, and recorded adjustments to those estimates in 2018 as analysis was completed. As of
December 31, 2018, our analysis of the one-time impacts of the TCJA is complete under SAB 118. However, in the
first quarter of 2019, the U.S. Treasury Department issued final regulations on the one-time transition tax. The final
regulations include changes from the proposed regulations issued in 2018 and we expect to record the impacts of
the final regulations in the first quarter of 2019. We are still evaluating the final regulations which may have a
material impact on our financial statements.
In addition, no taxes have been recorded 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. Should
the earnings be remitted as dividends, the Company may be subject to additional foreign withholding and state
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, and their respective income
96
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 has elected to treat GILTI as an expense in the period in
which the tax is accrued. Accordingly, no deferred tax assets or liabilities are recorded related to GILTI.
Sales of Noncontrolling Interests — Sales of noncontrolling interests are recognized within stockholders'
equity. Effective January 1, 2018, the Company adopted ASU No. 2017-05, Other Income—Gains and Losses from
the Derecognition of Nonfinancial Assets, which clarified the accounting for the sale of business interests as either
the sale of nonfinancial assets or the sale of businesses. Among other things, under the newly adopted guidance
fewer transactions are expected to meet the definition of a business under the scope of ASC 810 and will fall under
the scope of the sale of nonfinancial assets.
Prior to January 1, 2018, the accounting for a sale of noncontrolling interests was dependent on whether the
sale was considered a sale of in-substance real estate, where the gain (loss) on sale would be recognized in
earnings rather than within stockholders' equity. In-substance real estate is composed 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, starting with
determining if an impairment indicator exists. Events that may result in an impairment analysis being performed
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 it is more likely than not that the asset will be disposed of before the end of its
previously estimated useful life. The Company exercises judgment in determining if these events represent an
impairment indicator requiring the computation of the fair value of goodwill and/or the recoverability of long-lived
assets. The fair value determination is typically the most judgmental part in an impairment evaluation. Please see
Fair Value below for further detail.
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 8—
Goodwill and Other Intangible Assets and Note 20—Asset Impairment Expense to the Consolidated Financial
Statements included in Item 8 of this Form 10-K.
Fair Value
Fair Value — For 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.
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 and mutual 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
97
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 and asset acquisitions by VIEs are required to be recognized at fair value
under the relevant accounting guidance.
The Company may engage an independent valuation firm to assist management with the valuation. The
Company generally utilizes the income approach to value nonfinancial assets and liabilities, specifically a
Discounted Cash Flow ("DCF") model to estimate fair value by discounting 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 cash flow forecasts. Examples of the input assumptions that our 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. 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).
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.
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. See Note 5—Derivative Instruments and Hedging Activities included in Item 8 of this Form 10-
K for further information on the classification.
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 interest rate differential approach to construct the remaining portion of the
98
forward curve. 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 enters into transactions impacting the Company's equity interests in its
affiliates. In connection with each transaction, the Company must determine whether the transaction 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.
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, and 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 — The Company recognizes a net 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. The valuation of the Company's benefit
obligation, fair value of plan assets, and net periodic benefit costs requires various estimates and assumptions, the
most significant of which include the discount rate and expected return on plan assets. These assumptions are
reviewed by the Company on an annual basis. Refer to Note 1—General and Summary of Significant Accounting
Policies included in Item 8 of this Form 10-K for further information.
Revenue Recognition — The Company recognizes revenue to depict the transfer of energy, capacity and
other services to customers in an amount that reflects the consideration to which we expect to be entitled. In
applying the revenue model, we determine whether the sale of energy, capacity and other services represent a
single performance obligation based on the individual market and terms of the contract. Generally, the promise to
transfer energy and capacity represent a performance obligation that is satisfied over time and meets the criteria to
be accounted for as a series of distinct goods or services. Progress toward satisfaction of a performance obligation
is measured using output methods, such as MWhs delivered or MWs made available, and when we are entitled to
consideration in an amount that corresponds directly to the value of our performance completed to date, we
recognize revenue in the amount to which we have the right to invoice. For further information regarding the nature
of our revenue streams and our critical accounting policies affecting revenue recognition, see Note 1—General and
Summary of Significant Accounting Policies included in Item 8 of this Form 10-K.
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
2018 and accounting pronouncements issued, but not yet effective.
99
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, Wholesale power prices are
declining in many markets and this could have a material adverse effect on our operations and opportunities for
future growth, and We may not be adequately hedged against our exposure to changes in commodity prices or
interest rates of this 2018 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.
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 2019,
we project pre-tax earnings exposure on a 10% move in commodity prices would be approximately less than $5
million for U.S. power, $(10) million for natural gas, less than $(5) million for oil and $(5) 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 a decline in coal price if commodity prices are correlated. In aggregate, the Company's
downside exposure occurs with lower power, higher oil, higher 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 and Utilities 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.
100
In the South America 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, under normal hydrology conditions, coal-firing
generation sets the price. However, when there are spikes in price due to lower hydrology and higher demand, gas
or oil-linked fuels 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. Additionally, in Brazil, 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 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 Eurasia SBU, our Kilroot facility operates on a short-term sales strategy. To the extent that variable
energy margin is 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 displace higher cost generation,
potentially reducing Kilroot's margins, and vice versa. Two steam gas generating units at Ballylumford were shut
down at the end of 2018 having reached the end of their economic lives. The open cycle gas turbines at both
Ballylumford and Kilroot will continue to operate as peaking units at times of high demand. 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 USD. Additionally, certain of our foreign subsidiaries and affiliates have entered
into monetary obligations in 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, and Mexican 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 foreign currency 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: Argentine peso, Brazilian real, Colombian peso,
Euro, British pound, and Indian Rupee. As of December 31, 2018, assuming a 10% USD appreciation, cash
distributions attributable to foreign subsidiaries exposed to movement in the exchange rate of the Argentine peso
and Euro each are projected to be reduced by $5 million, and the Colombian peso, Brazilian real, British pound and
Indian Rupee each are projected to be impacted by less than $5 million. These numbers have been produced by
applying a one-time 10% USD appreciation to forecasted exposed cash distributions for 2019 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,
101
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.
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, 2018, the portfolio's pre-tax earnings exposure for 2019 to a one-time 100-basis-point
increase in interest rates for our Argentine peso, Brazilian real, Chilean peso, Colombian peso, Euro and USD
denominated debt would be approximately $20 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.
102
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and the Board of Directors of The AES Corporation:
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of The AES Corporation (the Company) as of
December 31, 2018 and 2017, and the related consolidated statements of operations, comprehensive income
(loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2018, and
the related notes and the financial statement schedule listed in the Index at Item 15(a) (collectively referred to as
the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all
material respects, the financial position of the Company at December 31, 2018 and 2017, and the results of its
operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with
U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2018, based on
criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (2013 framework) and our report dated February 26, 2019, expressed
an unqualified opinion thereon.
Adoption of New Accounting Standards
As discussed in Note 1 to the consolidated financial statements, the Company changed its method of
accounting for revenue as a result of the adoption of Accounting Standards Update (ASU) No. 2014-09, Revenue
from Contracts with Customers (Topic 606), and the amendments in ASUs 2015-14, 2016-08, 2016-10, 2016-12,
2016-20, 2017-10 and 2017-13 effective January 1, 2018.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to
express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm
registered with the PCAOB and are required to be independent with respect to the Company in accordance with the
U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission
and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of
material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks
of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that
respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and
disclosures in the financial statements. Our audits also included evaluating the accounting principles used and
significant estimates made by management, as well as evaluating the overall presentation of the financial
statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Ernst & Young LLP
We have served as the Company's auditor since 2008.
Tysons, Virginia
February 26, 2019
103
THE AES CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2018 AND 2017
2018
2017
(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 $23 and $10, 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 $457 and $441, respectively
Deferred income taxes
Service concession assets, net of accumulated amortization of $0 and $206, respectively
Loan receivable
Other noncurrent assets
Total other assets
TOTAL ASSETS
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable
Accrued interest
Accrued non-income taxes
Accrued and other liabilities
Non-recourse debt, including $479 and $1,012, 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 $2,922 and $1,358 respectively, related to variable interest entities
Deferred income taxes
Other noncurrent liabilities
Total noncurrent liabilities
Commitments and Contingencies (see Notes 11 and 12)
Redeemable stock of subsidiaries
EQUITY
THE AES CORPORATION STOCKHOLDERS’ EQUITY
Common stock ($0.01 par value, 1,200,000,000 shares authorized; 817,203,691 issued and
662,298,096 outstanding at December 31, 2018 and 816,312,913 issued and 660,388,128 outstanding
at December 31, 2017)
Additional paid-in capital
Accumulated deficit
Accumulated other comprehensive loss
Treasury stock, at cost (154,905,595 and 155,924,785 shares at December 31, 2018 and 2017,
respectively)
Total AES Corporation stockholders’ equity
NONCONTROLLING INTERESTS
Total equity
TOTAL LIABILITIES AND EQUITY
$
See Accompanying Notes to Consolidated Financial Statements.
$
$
$
1,166
370
313
1,595
577
130
807
57
5,015
449
25,242
(8,227)
3,932
21,396
1,114
467
1,059
436
97
—
1,423
1,514
6,110
32,521
1,329
191
250
962
1,659
8
4,399
3,650
13,986
1,280
2,723
21,639
949
274
424
1,463
562
62
630
2,034
6,398
502
24,119
(7,942)
3,617
20,296
1,197
565
1,059
366
130
1,360
—
1,741
6,418
33,112
1,371
228
252
980
2,164
1,033
6,028
4,625
13,176
1,006
2,595
21,402
879
837
8
8,154
(1,005)
(2,071)
(1,878)
3,208
2,396
5,604
32,521
$
8
8,501
(2,276)
(1,876)
(1,892)
2,465
2,380
4,845
33,112
104
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2018, 2017, AND 2016
2018
2016
2017
(in millions, except per share amounts)
$
$
2,939
7,797
10,736
3,109
7,421
10,530
$
3,310
6,971
10,281
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 (loss) on disposal and sale of business interests
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 expense
Net equity in earnings of affiliates
INCOME (LOSS) FROM CONTINUING OPERATIONS
Income (loss) from operations of discontinued businesses, net of income tax benefit (expense) of
$(2), $(21), and $229, respectively
Gain (loss) from disposal and impairments of discontinued businesses, net of income tax benefit
(expense) of $(44), $0, and $266, respectively
NET INCOME (LOSS)
Noncontrolling interests:
Less: Income from continuing operations attributable to noncontrolling interests and redeemable
stock of subsidiaries
Less: Loss (income) from discontinued operations attributable to noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income (loss) 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 (loss) 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:
(2,473)
(5,690)
(8,163)
2,573
(192)
(1,056)
310
(188)
(58)
72
984
(208)
(72)
(147)
2,018
(708)
39
1,349
(9)
225
1,565
(364)
2
1,203
985
218
1,203
1.49
0.33
1.82
(2,650)
(5,415)
(8,065)
2,465
(215)
(1,170)
244
(68)
(58)
120
(52)
(537)
42
—
771
(990)
71
(148)
(18)
(611)
(777)
(2,839)
(5,059)
(7,898)
2,383
(194)
(1,134)
245
(13)
(80)
64
29
(1,096)
(15)
(2)
187
(32)
36
191
151
(1,119)
(777)
(359)
(25)
(1,161) $
(211)
(142)
(1,130)
(507) $
(654)
(1,161) $
(20)
(1,110)
(1,130)
(0.77) $
(0.04)
(0.99)
(1.76) $
(1.68)
(1.72)
$
$
$
$
$
Income (loss) from continuing operations attributable to The AES Corporation common stockholders,
net of tax
$
1.48
$
(0.77) $
(0.04)
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
$
0.33
1.81
0.53
$
$
(0.99)
(1.76) $
0.49
$
(1.68)
(1.72)
0.45
See Accompanying Notes to Consolidated Financial Statements.
105
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
YEARS ENDED DECEMBER 31, 2018, 2017, AND 2016
NET INCOME (LOSS)
Foreign currency translation activity:
Foreign currency translation adjustments, net of income tax benefit of $2, $17, and $1,
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 $27, $10 and $(7),
respectively
Reclassification to earnings, net of income tax expense of $24, $1 and $8, respectively
Total change in fair value of derivatives
Pension activity:
Change in pension adjustments due to prior service cost, net of income tax benefit (expense) of
$1, $(1), and $(6) respectively
Change in pension adjustments due to net actuarial gain (loss) for the period, net of income tax
benefit of $1, $6, and $106, respectively
Reclassification to earnings, net of income tax expense of $2, $135, and $3 respectively
Total pension adjustments
OTHER COMPREHENSIVE INCOME (LOSS)
COMPREHENSIVE INCOME
Less: Comprehensive income attributable to noncontrolling interests
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION
2018
$
1,565
2017
(in millions)
$
(777) $
(161)
(21)
(182)
(67)
93
26
(2)
(1)
(9)
643
634
(12)
50
38
2
(21)
8
5
(151)
1,414
(425)
989
$
$
266
247
919
142
(390)
(248) $
2016
(777)
189
992
1,181
5
37
42
11
(208)
10
(187)
1,036
259
(262)
(3)
See Accompanying Notes to Consolidated Financial Statements.
106
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
YEARS ENDED DECEMBER 31, 2018, 2017, AND 2016
THE AES CORPORATION STOCKHOLDERS
Common Stock
Treasury Stock
Shares
Amount
Shares
Amount
Additional
Paid-In
Capital
Retained
Earnings
(Accumulated
Deficit)
Accumulated
Other
Comprehensive
Loss
Noncontrolling
Interests
(in millions)
Balance at December 31, 2015
Net income (loss)
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 income (loss)
Fair value adjustment (1)
Disposition of business interests (2)
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
Less: Net loss attributable to redeemable stock of subsidiaries
Balance at December 31, 2016
Net income (loss)
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 income
Cumulative effect of a change in accounting principle (3)
Fair value adjustment (1)
Disposition of business interests (2)
Distributions to noncontrolling interests
Contributions from noncontrolling interests
Dividends declared on common 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
Less: Net loss attributable to redeemable stock of subsidiaries
815.8
$
—
—
—
—
—
—
—
—
—
—
—
0.3
—
—
—
816.1
$
—
—
—
—
—
—
—
—
—
—
—
0.2
—
—
—
Balance at December 31, 2017
816.3
$
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 income (loss)
Cumulative effect of a change in accounting principle (3)
Fair value adjustment (1)
Disposition of business interests (2)
Distributions to noncontrolling interests
Contributions from noncontrolling interests
Dividends declared on common stock
Issuance and exercise of stock-based compensation benefit
plans, net of income tax
Sale of subsidiary shares to noncontrolling interests
—
—
—
—
—
—
—
—
—
—
—
0.9
—
Balance at December 31, 2018
817.2
$
8
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
8
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
8
—
—
—
—
—
—
—
—
—
—
—
—
—
8
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
—
—
—
—
—
—
—
—
—
—
3,022
353
72
12
(175)
(91)
(17)
(2)
(430)
60
—
—
—
17
(17)
11
156.9
$ (1,904) $
8,592
$
(1,146) $
(2,756) $
2,906
—
—
—
—
—
—
—
—
—
—
—
(1.0)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
12
—
—
—
—
—
—
—
—
—
(25)
—
—
—
(324)
5
13
240
—
(1,161)
—
—
—
—
31
—
—
—
—
—
—
—
—
—
—
661
23
229
913
—
—
—
—
—
—
—
7
(40)
—
155.9
$ (1,892) $
8,501
$
(2,276) $
(1,876) $
—
—
—
—
—
—
—
—
—
—
—
(1.0)
—
—
—
—
—
—
—
—
—
—
—
—
14
—
—
—
—
—
—
—
(4)
—
—
—
(348)
8
(3)
1,203
—
—
—
—
68
—
—
—
—
—
—
—
—
(235)
14
7
(214)
19
—
—
—
—
—
—
—
384
(27)
15
18
6
—
—
(666)
(426)
11
—
—
83
68
14
2,380
360
53
10
(2)
61
81
—
(250)
(343)
9
—
—
98
154.9
$ (1,878) $
8,154
$
(1,005) $
(2,071) $
2,396
(1) Adjustment to the carrying amount of noncontrolling interest and redeemable stock of subsidiaries to fair value.
(2) See Note 23—Held-for-Sale and Dispositions for further information.
(3) See Note 1—General and Summary of Significant Accounting Policies for further information.
See Accompanying Notes to Consolidated Financial Statements
107
THE AES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2018, 2017, AND 2016
OPERATING ACTIVITIES:
Net income (loss)
Adjustments to net income (loss):
Depreciation and amortization
Loss (gain) on disposal and sale of business interests
Impairment expenses
Deferred income taxes
Provisions for contingencies
Loss on extinguishment of debt
Loss on sale and disposal of assets
Net loss (gain) from disposal and impairments of discontinued 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 of business interests, net of cash and restricted cash acquired
Proceeds from the sale of business interests, net of cash and restricted cash sold
Sale of short-term investments
Purchase of short-term investments
Contributions to equity investments
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 provided by (used in) financing activities
Effect of exchange rate changes on cash, cash equivalents and restricted cash
(Increase) decrease in cash, cash equivalents and restricted cash of discontinued operations and
held-for-sale businesses
Total increase (decrease) in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash, beginning
Cash, cash equivalents and restricted cash, 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:
Non-cash acquisition of intangible assets
Non-cash contributions of assets and liabilities for the Fluence transaction (see Note 7)
Non-cash exchange of debentures for the acquisition of the Guaimbê Solar Complex (see Note 24)
Non-cash acquisition of the remaining interest in a Distributed Energy equity affiliate (see Note 24)
Dividends declared but not yet paid
Conversion of Alto Maipo loans and accounts payable into equity (see Note 14)
Return Share Transfer Payment due (see Note 23)
$
$
See Accompanying Notes to Consolidated Financial Statements
108
2018
$
1,565
2017
(in millions)
$
(777) $
2016
(777)
1,176
(29)
1,098
(793)
48
20
38
1,383
180
237
42
870
(251)
(619)
(199)
473
2,897
(2,345)
(52)
538
4,904
(5,151)
(6)
(24)
(2,136)
1,465
(1,433)
500
(808)
2,978
(2,666)
(105)
(476)
190
134
(290)
(113)
(79)
—
(44)
(747)
37
(42)
9
1,951
1,960
1,273
487
—
—
—
—
174
—
—
1,003
(984)
355
313
14
188
27
(269)
317
(206)
(36)
(22)
(32)
62
(7)
55
2,343
(2,121)
(66)
2,020
1,302
(1,411)
(145)
(84)
(505)
1,865
(2,238)
1,000
(1,933)
1,928
(1,411)
(39)
(340)
43
—
(344)
(275)
—
—
101
(1,643)
(54)
74
215
1,788
2,003
1,003
370
16
20
119
23
90
—
—
$
$
1,169
52
537
672
34
68
43
611
160
(177)
(28)
107
(295)
163
53
112
2,504
(2,177)
(609)
108
3,540
(3,310)
(89)
(62)
(2,599)
2,156
(1,742)
1,025
(1,353)
3,222
(2,360)
(100)
(424)
73
—
(317)
(179)
—
94
(52)
43
8
(128)
(172)
1,960
1,788
1,196
377
—
—
—
—
86
279
75
$
$
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2018, 2017, AND 2016
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, the liabilities of individual operating entities are non-recourse to the Parent
Company 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. The preparation of these consolidated financial
statements is in conformity with accounting principles generally accepted in the United States of America ("US
GAAP").
PRINCIPLES OF CONSOLIDATION — The consolidated financial statements of the Company include the
accounts of The AES Corporation and its controlled subsidiaries. Furthermore, VIEs in which the Company has an
ownership interest and is the primary beneficiary, thus controlling the VIE, have been consolidated. 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.
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 qualified 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.
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. When 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 or additional paid-in-capital in the absence of 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. Instruments that are mandatorily redeemable are classified as a liability.
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’s proportionate
share of the net income or loss of these companies is included in our results of operations.
The Company utilizes the cumulative earning approach to determine whether distributions received from
equity method investees are returns on investment or returns of investment. 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.
Upon acquiring the investment, we determine the fair value of the identifiable assets and assumed liabilities
and 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 AES share of the amortization of the basis difference is recognized in
Net equity in earnings of affiliates in the Consolidated Statements of Operations over the life of the asset or liability.
The Company periodically assesses if impairment indicators exist at our equity method investments. When an
impairment is observed, 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.
BUSINESS INTERESTS — Acquisitions and disposals of business interests are generally transactions
pertaining to legal entities, which may be accounted for as a consolidated business, an asset, or an equity method
109
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
investment. Losses on sales of business interests are limited to the impairment of long-lived assets as of the date of
execution of the sales agreement. Any additional gains/(losses) on sales are recognized in Gain (loss) on disposal
and sale of business interests in the Consolidated Statement of Operations upon completion of the sale.
ALLOCATION OF EARNINGS — Certain of the Company's businesses are subject to profit-sharing
arrangements where the allocation of cash distributions and the sharing of tax benefits are not based on fixed
ownership percentages. These arrangements exist for certain U.S. 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 hypothetical liquidation at book value (“HLBV”)
method when it is a reasonable approximation of the profit-sharing arrangement. The HLBV method calculates the
proceeds that would be attributable to each partner based on the liquidation provisions of the respective operating
partnership agreement if the partnership was to be liquidated at book value at the balance sheet date. Each
partner’s share of income in the period is equal to the change in the amount of net equity they are legally able to
claim based on a hypothetical liquidation of the entity at the end of a reporting period compared to the beginning of
that period, adjusted for any capital transactions.
The HLBV method is used both to allocate the equity earnings attributable to AES when the Company
accounts for the renewable business as an equity method investment and to calculate the earnings attributable to
noncontrolling interest when the business is consolidated by AES. Where, prior to the commencement of operating
activities for a respective renewable energy facility, HLBV results in an immediate decrease in the hypothetical
liquidation proceeds attributable to the tax equity investor due to the recognition of ITCs or other adjustments as
required by the U.S. Internal Revenue Code, the Company records the impact (sometimes referred to as the ‘Day
one gain’) to income in the same period.
USE OF ESTIMATES — US GAAP requires the Company to make estimates and assumptions that affect the
asset and liability balances reported as of the date of the consolidated financial statements, as well as the revenues
and expenses recognized 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; regulatory liabilities; the
fair value of financial instruments; the fair value of assets and liabilities acquired as business combinations or as
asset acquisitions by variable interest entities; the measurement of equity method investments or noncontrolling
interest using the 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; the impact of U.S. tax reform; and potential litigation claims
and settlements.
HELD-FOR-SALE DISPOSAL GROUPS— A disposal group classified as held-for-sale is reflected on the
balance sheet at the lower of its carrying amount or estimated fair value less cost to sell. A loss is recognized if the
carrying amount of the disposal group exceeds its estimated fair value less cost to sell. This loss is limited to the
carrying value of long-lived assets until the completion of the sale, at which point, any additional loss is recognized.
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 lesser of the previously
recognized expense or the subsequent excess.
Assets and liabilities related to a disposal group classified as held-for-sale are segregated in the current
balance sheet in the period in which the disposal group is classified as held-for-sale. Assets and liabilities of held-
for-sale disposal groups are classified as current when they are expected to be disposed of within twelve months.
Transactions between the held-for-sale disposal group and businesses that are expected to continue to exist after
the disposal are not eliminated to appropriately reflect the continuing operations and balances held-for-sale. See
Note 23—Held-for-Sale and Dispositions for further information.
DISCONTINUED OPERATIONS — Discontinued operations reporting occurs only when the disposal of a
business or a group of businesses represents a strategic shift that has (or will have) a major effect on the
Company's operations and financial results. The Company reports financial results for discontinued operations
separately from continuing operations to distinguish the financial impact of disposal transactions from ongoing
operations. Prior period amounts in the Consolidated Statements of Operations and Consolidated Balance Sheets
are retrospectively revised to reflect the businesses determined to be discontinued operations. The cash flows of
110
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
businesses that are determined to be discontinued operations are included within the relevant categories within
operating, investing and financing activities on the face of the Consolidated Statements of Cash Flows.
Transactions between the businesses determined to be discontinued operations and businesses that are
expected to continue to exist after the disposal are not eliminated to appropriately reflect the continuing operations
and balances held-for-sale. The results of discontinued operations include any gain or loss recognized on closing or
adjustment of the carrying amount to fair value less cost to sell, including gains or losses associated with
noncontrolling interests upon completion of the disposal transaction. Adjustments related to components previously
reported as discontinued operations under prior accounting guidance are presented as discontinued operations in
the current period even if the disposed-of component to which the adjustments are related would not meet the
criteria for presentation as a discontinued operation under current guidance. See Note 22—Discontinued
Operations for further information.
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 noncurrent assets; derivative assets, included in Other current assets and
Other noncurrent assets; and, derivative liabilities, included in Accrued and other liabilities (current) and Other
noncurrent liabilities. The Company applies the fair value measurement guidance to nonfinancial assets and
liabilities upon the acquisition of a business or an asset acquisition by a variable interest entity, or in conjunction
with the measurement of an asset retirement obligation or a potential impairment loss on an asset group or
goodwill.
When determining the fair value measurements for assets and liabilities required to be reflected at their fair
values, the Company considers the principal or most advantageous market in which it would transact and considers
assumptions that market participants would use when pricing the assets or liabilities, such as inherent risk, transfer
restrictions and risk of nonperformance. The Company is prohibited from including transaction costs and any
adjustments for blockage factors in determining fair value.
In determining fair value measurements, the Company maximizes the use of observable inputs and minimizes
the use of unobservable inputs. Assets and liabilities are categorized within a fair value hierarchy based upon the
lowest level of input that is significant to the fair value measurement:
• Level 1: Quoted prices in active markets for identical assets or liabilities;
• Level 2: Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices in
active markets for similar assets or liabilities, quoted prices for identical or similar assets or liabilities in markets
that are not active or other inputs that are observable or can be corroborated by observable market data for
substantially the full term of the assets or liabilities; or
• Level 3: Unobservable inputs that are supported by little or no market activity and that are significant to the fair
values of the assets or liabilities.
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, cash balances not
restricted as to withdrawal or usage, 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.
RESTRICTED CASH AND DEBT SERVICE RESERVES — Cash balances restricted as to withdrawal or
usage, primarily via contract, are considered restricted cash.
The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported on
the Consolidated Balance Sheets that reconcile to the total of such amounts as shown on the Consolidated
Statements of Cash Flows (in millions):
Cash and cash equivalents
Restricted cash
Debt service reserves and other deposits
Cash, Cash Equivalents and Restricted Cash
111
December 31, 2018
December 31, 2017
$
$
1,166
370
467
2,003
$
$
949
274
565
1,788
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
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 where 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. Remaining marketable debt securities are classified as available-for-sale or trading and are
carried at fair value.
Unrealized gains or losses on available-for-sale debt securities are reflected in AOCL, a separate component
of equity, and the Consolidated Statements of Operations, respectively. Unrealized gains or losses on equity
investments are reported in Other income. 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 historical collection experience, the age of accounts receivable
and other currently available evidence supporting collectability, and records an allowance for doubtful accounts for
the estimated uncollectible amount as appropriate. Certain of our businesses charge interest on accounts
receivable. Interest income is recognized on an accrual basis. When 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
operational spare parts and supplies used to maintain power generation and distribution facilities. Inventory is
carried at lower of cost or net realizable value. Cost is the sum of the purchase price and expenditures incurred to
bring the inventory to its existing location. Inventory is primarily valued using the average cost method. Generally, if
it is expected fuel inventory will not be recovered through revenue earned from power generation, an impairment is
recognized to reflect the fuel at market value. 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.
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
construction project is deemed probable, or expensed at the time construction completion is determined to no
longer be probable. The continued capitalization of such costs is subject to 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. Maintenance and repairs are charged to expense as incurred.
Depreciation, after consideration of salvage value and asset retirement obligations, is computed using the
straight-line method over the estimated useful lives of the assets, which are determined on a composite or
component basis. 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.
Certain of the Company's subsidiaries operate under concession contracts. Certain estimates are utilized to
determine depreciation expense for the 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
112
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
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 1 – 50 years and are included in the Consolidated Balance Sheet line item Other intangible
assets. The Company accounts for purchased emission allowances as intangible assets and records an expense
when they are utilized or sold. Granted emission allowances are valued at zero.
Impairment of Long-lived Assets — When circumstances indicate 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 resulting from the use and eventual disposal of the assets. Events or
changes in circumstances that may necessitate a recoverability evaluation 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 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, an impairment expense is recognized for the
amount by which the carrying amount of the asset group exceeds its fair value (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).
An impairment expense for certain assets may be reduced by the establishment of a regulatory asset if recovery
through approved rates is probable.
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. Effective January 1, 2018, the Company derecognized the service concession assets and recognized a
loan receivable under ASC 606. See further detail in the new accounting pronouncements discussion below.
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 or revolving credit facility
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.
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
1.
Goodwill — Goodwill represents the excess of the purchase price of the business acquisition over the fair
value of identifiable net assets acquired. 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 similar to other businesses in a segment nor are they reported to
segment management together with other businesses.
Goodwill is evaluated for impairment either under the qualitative assessment option or the quantitative test
option to determine the fair value of the reporting unit. If goodwill is determined to be impaired, an impairment loss
measured at the amount by which the reporting unit’s carrying amount exceeds its fair value, not to exceed the
carrying amount of goodwill, is recorded.
Indefinite-Lived Intangible Assets — The Company's indefinite-lived intangible assets primarily include land-
use rights and water rights. Indefinite-lived intangible assets are evaluated for impairment either under the
qualitative assessment option or the two-step quantitative test. If the carrying amount of an intangible asset being
tested for impairment exceeds its fair value, the excess is recognized as impairment expense.
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
113
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
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, and benefits.
REGULATORY ASSETS AND LIABILITIES — The Company recognizes assets and liabilities that result from
regulated ratemaking processes. Regulatory assets generally represent incurred costs which have been deferred
due to the probable future recovery via customer rates. Generally, returns earned on regulatory assets are reflected
in the Consolidated Statement of Operations within Interest Income. Regulatory liabilities generally represent
obligations to refund customers. Management continually assesses whether regulatory assets are probable of
future recovery and regulatory 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.
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,
and their respective income tax basis. 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.
The Company has elected to treat GILTI as an expense in the period in which the tax is accrued. Accordingly,
no deferred tax assets or liabilities are recorded related to GILTI.
ASSET RETIREMENT OBLIGATIONS — The Company records the fair value of a 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.
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. 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 for 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.
114
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
REVENUE RECOGNITION — Revenue is earned from the sale of electricity from our utilities and the
production and sale of electricity and capacity from our generation facilities. Revenue is recognized upon the
transfer of control of promised goods or services to customers in an amount that reflects the consideration to which
we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed
on and collected from customers, which are remitted to the governmental authorities.
Utilities — Our utilities sell electricity directly to end-users, such as homes and businesses, and bill customers
directly. The majority of our utility contracts have a single performance obligation, as the promises to transfer
energy, capacity, and other distribution and/or transmission services are not distinct. Additionally, as the
performance obligation is satisfied over time as energy is delivered, and the same method is used to measure
progress, the performance obligation meets the criteria to be considered a series. Utility revenue is classified as
regulated on the Consolidated Statements of Operations.
In exchange for the right to sell or distribute electricity in a service territory, our utility businesses are subject to
government regulation. This regulation sets the framework for the prices (“tariffs”) that our utilities are allowed to
charge customers for electricity. Since tariffs are determined by the regulator, the price that our utilities have the
right to bill corresponds directly with the value to the customer of the utility's performance completed in each period.
The Company also has some month-to-month contracts. Revenue under these contracts is recognized using an
output method measured by the MWh delivered each month, which best depicts the transfer of goods or services to
the customer, at the approved tariff.
The Company has businesses where it sells and purchases power to and from ISOs and RTOs. Our utility
businesses generally purchase power to satisfy the demand of customers that is not contracted through separate
PPAs. In these instances, the Company accounts for these transactions on a net hourly basis because the
transactions are settled on a net hourly basis. In limited situations, a utility customer may choose to receive
generation services from a third-party provider, in which case the Company may serve as a billing agent for the
provider and recognize revenue on a net basis.
Generation — Most of our generation fleet sells electricity under contracts to customers such as utilities,
industrial users, and other intermediaries. Our generation contracts, based on specific facts and circumstances, can
have one or more performance obligations as the promise to transfer energy, capacity, and other services may or
may not be distinct depending on the nature of the market and terms of the contract. As the performance obligations
are generally satisfied over time and use the same method to measure progress, the performance obligations meet
the criteria to be considered a series. In measuring progress toward satisfaction of a performance obligation, the
Company applies the "right to invoice" practical expedient when available, and recognizes revenue in the amount to
which the Company has a right to consideration from a customer that corresponds directly with the value of the
performance completed to date. Revenue from generation businesses is classified as non-regulated on the
Consolidated Statements of Operations.
For contracts determined to have multiple performance obligations, we allocate revenue to each performance
obligation based on its relative standalone selling price using a market or expected cost plus margin approach.
Additionally, the Company allocates variable consideration to one or more, but not all, distinct goods or services that
form part of a single performance obligation when (1) the variable consideration relates specifically to the efforts to
transfer the distinct good or service and (2) the variable consideration depicts the amount to which the Company
expects to be entitled in exchange for transferring the promised good or service to the customer.
Revenue from generation contracts is recognized using an output method, as energy and capacity delivered
best depicts the transfer of goods or services to the customer. Performance obligations including energy or ancillary
services (such as operations and maintenance and dispatch services) are generally measured by the MWh
delivered. Capacity, which is a stand-ready obligation to deliver energy when required by the customer, is measured
using MWs. In certain contracts, if plant availability exceeds a contractual target, the Company may receive a
performance bonus payment, or if the plant availability falls below a guaranteed minimum target, we may incur a
non-availability penalty. Such bonuses or penalties represent a form of variable consideration and are estimated
and recognized when it is probable that there will not be a significant reversal.
In assessing whether variable quantities are considered variable consideration or an option to acquire
additional goods and services, the Company evaluates the nature of the promise and the legally enforceable rights
in the contract. In some contracts, such as requirement contracts, the legally enforceable rights merely give the
customer a right to purchase additional goods and services which are distinct. In these contracts, the customer's
action results in a new obligation, and the variable quantities are considered an option.
115
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
When energy or capacity is sold or purchased in the spot market or to ISOs, the Company assesses the facts
and circumstances to determine gross versus net presentation of spot revenues and purchases. Generally, the
nature of the performance obligation is to sell surplus energy or capacity above contractual commitments, or to
purchase energy or capacity to satisfy deficits. Generally, on an hourly basis, a generator is either a net seller or a
net buyer in terms of the amount of energy or capacity transacted with the ISO. In these situations, the Company
recognizes revenue for the hours where the generator is a net seller and cost of sales for the hours where the
generator is a net buyer.
Certain generation contracts contain operating leases where capacity payments are generally considered
lease elements. In such cases, the allocation between the lease and non-lease elements is made at the inception of
the lease following the guidance in ASC 840. Minimum lease payments from such contracts are recognized as
revenue on a straight-line basis over the lease term whereas contingent rentals are recognized when earned.
The transaction price allocated to a construction performance obligation is recognized as revenue over time as
construction activity occurs, with revenue being fully recognized upon completion of construction. These contracts
may include a difference in timing between revenue recognition and the collection of cash receipts, which may be
collected over the term of the entire arrangement. The timing difference could result in a significant financing
component for the construction performance obligation if determined to be a material component of the transaction
price. The Company accounts for a significant financing component under the effective interest rate method,
recognizing a long-term receivable for the expected future payments related to the construction performance
obligation in the Loan Receivable line item on the Consolidated Balance Sheets. As payments are collected from
the customer over the term of the contract, consideration related to the construction performance obligation is
bifurcated between the principal repayment of the long-term receivable and the related interest income, recognized
in the Consolidated Statements of Operations.
SHARE-BASED COMPENSATION — The Company grants share-based compensation in the form of stock
options, restricted stock units, performance stock units, and performance cash 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 Note 4—Fair Value and Fair value in this section for additional
discussion regarding the determination of fair value.
PPAs and fuel supply agreements are evaluated to assess if they contain either a derivative or an embedded
derivative requiring separate valuation and accounting. 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 commodities
to be delivered under these agreements to determine if facts and circumstances have changed such that the
agreements could be net settled and meet the definition of a derivative.
The Company typically designates its derivative instruments as cash flow hedges if they meet the criteria
specified in ASC 815, Derivatives and Hedging. The Company enters into interest rate swap agreements in order to
hedge the variability of expected future cash interest payments. Foreign currency contracts are used to reduce risks
arising from the change in fair value of certain foreign currency denominated assets and liabilities. The objective of
these practices is to minimize the impact of foreign currency fluctuations on operating results. The Company also
enters into commodity contracts to economically hedge price variability inherent in electricity sales arrangements.
The objectives of the commodity contracts are to minimize the impact of variability in spot electricity prices and
stabilize estimated revenue streams. The Company does not use derivative instruments for speculative purposes.
For our hedges, changes in fair value that are considered highly effective are deferred in AOCL and are
recognized into earnings as the hedged transactions affect earnings. Any ineffectiveness is recognized in earnings
116
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
immediately. If a derivative is no longer highly effective, 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 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 are recognized in earnings, they are
generally classified as 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. 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.
NEW ACCOUNTING PRONOUNCEMENTS — The following table provides a brief description of recent
accounting pronouncements that had an impact on the Company’s consolidated financial statements. Accounting
pronouncements not listed below were assessed and determined to be either not applicable or did not have a
material impact on the Company’s consolidated financial statements.
New Accounting Standards Adopted
ASU Number and Name
2018-15, Intangibles—
Goodwill and Other—
Internal-Use Software
(Subtopic 350-40):
Customer’s Accounting
for Implementation Costs
Incurred in a Cloud
Computing Arrangement
That Is a Service
Contract
2018-14, Compensation
— Retirement Benefits
— Defined Benefit Plans
— General (Subtopic
715-20): Disclosure
Framework
2017-07, Compensation
— Retirement Benefits
(Topic 715): Improving
the Presentation of Net
Periodic Pension Cost
and Net Periodic
Postretirement Benefit
Cost
Description
This standard aligns the accounting for implementation costs
incurred for a cloud computing arrangement that is a service with
the requirement for capitalizing implementation costs associated
with developing or obtaining internal-use software.
Transition method: retrospective or prospective.
Date of Adoption
October 1,
2018
This standard modifies the disclosure requirements for
employers that sponsor defined benefit pension or other
postretirement plans.
Transition method: retrospective.
This standard changes the presentation of non-service costs
associated with defined benefit and other postretirement plans
and updates the guidance so that only the service cost
component will be eligible for capitalization.
Transition method: retrospective for presentation of non-service
cost and prospective for the change in capitalization.
Early adoption
elected,
January 1,
2018
January 1,
2018
2017-05, Other Income
— Gains and Losses
from the Derecognition of
Nonfinancial Assets
(Topic 610-20): Clarifying
the Scope of Asset
Derecognition Guidance
and Accounting for
Partial Sales of
Nonfinancial Assets
This standard clarifies the scope and application of ASC 610-20
on the sale, transfer, and derecognition of nonfinancial assets
and in substance nonfinancial assets to non-customers, including
partial sales. It also provides guidance on how gains and losses
on transfers of nonfinancial assets and in substance nonfinancial
assets to non-customers are recognized. The standard also
clarifies that the derecognition of businesses is under the scope
of ASC 810. The standard must be adopted concurrently with
ASC 606, however an entity will not have to apply the same
transition method as ASC 606.
January 1,
2018
Transition method: modified retrospective.
Effect on the financial
statements upon adoption
The Company elected to
early-adopt this
standard on a
prospective basis,
effective for fiscal year
2018. The adoption of
this standard did not
have a material impact
on the financial
statements.
Impact limited to
changes in financial
statement disclosures.
For the year ended
December 31, 2017 and
2016, $1 million and $3
million of non-service
costs associated with
defined benefit and
other postretirement
plans were reclassified
from Costs of Sales to
Other Expense,
respectively.
Following adoption of
ASU 2017-01, fewer
transactions are
expected to meet the
definition of a business
under the scope of ASC
810 and will fall under
the scope under this
standard.
117
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
2017-04, Intangibles —
Goodwill and Other
(Topic 350): Simplifying
the Test for Goodwill
Impairment
This standard simplifies the accounting for goodwill impairments
by removing the requirement to calculate the implied fair value of
goodwill by assigning the fair value of a reporting unit to all of its
assets and liabilities as if it had been acquired in a business
combination. Instead, it requires that an entity record an
impairment charge based on the amount by which a reporting
unit's carrying amount exceeds its fair value, not to exceed the
total amount of goodwill allocated to that reporting unit.
Transition method: prospective.
October 1,
2018
2017-01, Business
Combinations (Topic
805): Clarifying the
Definition of a Business
The standard requires an entity to first evaluate whether
substantially all of the fair value of the gross assets acquired is
concentrated in a single identifiable asset or a group of similar
identifiable assets, and if that threshold is met, the set is not a
business. As a second step, at least one substantive process
should exist to be considered a business.
January 1,
2018
Transition method: prospective.
2016-18, Statement of
Cash Flows (Topic 230):
Restricted Cash (a
consensus of the FASB
Emerging Issues Task
Force)
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.
January 1,
2018
Transition method: retrospective.
In anticipation of our
annual goodwill process,
the Company early-
adopted this standard to
ease the administrative
burden for the
measurement of any
potential goodwill
impairment losses.
There was no impact to
the financial statements
upon adoption of the
standard.
Some acquisitions and
dispositions are
expected to now fall
under a different
accounting model. This
will reduce the number
of transactions that are
accounted for as
business combinations
and therefore future
acquired goodwill.
For the years ended
December 31, 2017 and
2016, cash provided by
operating activities
increased by $15 million
and $13 million,
respectively, cash used
in investing activities
decreased by $150
million and increased by
$28 million, respectively,
and cash provided by
financing activities was
unchanged.
No material impact upon
adoption of the
standard.
The standard significantly revises an entity’s accounting related
to (1) classification and measurement of investments in equity
securities and (2) the presentation of certain fair value changes
for financial liabilities measured at fair value. It also amends
certain disclosures of financial instruments.
January 1,
2018
Transition method: modified retrospective. Prospective for equity
investments without readily determinable fair value.
See discussion of the ASU below.
January 1,
2018
See impact upon
adoption of the standard
below.
2016-01, Financial
Instruments — Overall
(Subtopic 825-10):
Recognition and
Measurement of
Financial Assets and
Financial Liabilities
2014-09, 2015-14,
2016-08, 2016-10,
2016-12, 2016-20,
2017-10, 2017-13,
Revenue from Contracts
with Customers (Topic
606)
On January 1, 2018, the Company adopted ASU 2014-09, "Revenue from Contracts with Customers," and its
subsequent corresponding updates ("ASC 606"). Under this standard, 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. The Company applied the modified
retrospective method of adoption to the contracts that were not completed as of January 1, 2018. Results for
reporting periods beginning January 1, 2018 are presented under ASC 606, while prior period amounts were not
adjusted and continue to be reported in accordance with the previous revenue recognition standard. For contracts
that were modified before January 1, 2018, the Company reflected the aggregate effect of all modifications when
identifying the satisfied and unsatisfied performance obligations, determining the transaction price and allocating the
transaction price.
The cumulative effect to our January 1, 2018 Consolidated Balance Sheet resulting from the adoption of ASC
606 was as follows (in millions):
118
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
Consolidated Balance Sheet
Assets
Other current assets
Deferred income taxes
Service concession assets, net
Loan receivable
Equity
Accumulated deficit
Accumulated other comprehensive loss
Noncontrolling interest
Balance at
December 31, 2017
Adjustments Due to
ASC 606
Balance at
January 1, 2018
$
$
630
130
1,360
—
(2,276)
(1,876)
2,380
$
61
(24)
(1,360)
1,490
67
19
81
691
106
—
1,490
(2,209)
(1,857)
2,461
The Mong Duong II power plant in Vietnam is the primary driver of changes in revenue recognition under the
new standard. This plant is operated under a build, operate, and transfer contract and will be transferred to the
Vietnamese government after the completion of a 25-year PPA. Under the previous revenue recognition standard,
construction costs were deferred to a service concession asset, which was expensed in proportion to revenue
recognized for the construction element over the term of the PPA. Under ASC 606, construction revenue and
associated costs are recognized as construction activity occurs. As construction of the plant was substantially
completed in 2015, revenues and costs associated with the construction were recognized through retained
earnings, and the service concession asset was derecognized. A loan receivable was recognized for the future
expected payments for the construction performance obligation. As the payments for the construction performance
obligation occur over a 25-year term, a significant financing element was determined to exist which is accounted for
under the effective interest rate method. The other performance obligation to operate and maintain the facility is
measured based on the capacity made available.
The impact to our Consolidated Balance Sheet as of December 31, 2018 resulting from the adoption of ASC
606 as compared to the previous revenue recognition standard was as follows (in millions):
Consolidated Balance Sheet
Assets
Other current assets
Deferred income taxes
Service concession assets, net
Loan receivable
TOTAL ASSETS
Equity
Accumulated deficit
Accumulated other comprehensive loss
Noncontrolling interest
TOTAL LIABILITIES AND EQUITY
As Reported
December 31, 2018
Balances Without
Adoption of ASC 606
Adoption Impact
$
$
807
97
—
1,423
32,521
(1,005)
(2,071)
2,396
32,521
$
741
122
1,261
—
32,318
(1,112)
(2,088)
2,317
32,318
66
(25)
(1,261)
1,423
203
107
17
79
203
The impact to our Consolidated Statement of Operations for the year ended December 31, 2018 resulting from
the adoption of ASC 606 as compared to the previous revenue recognition standard was as follows (in millions):
Consolidated Statement of Operations
Total revenue
Total cost of sales
Operating margin
Interest income
Other Income
Income from continuing operations before taxes and equity in
earnings of affiliates
INCOME FROM CONTINUING OPERATIONS
NET INCOME
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION
$
Year Ended December 31, 2018
As Reported
Balances Without
Adoption of ASC 606
Adoption Impact
$
10,736
(8,163)
2,573
310
72
2,018
1,349
1,565
1,203
$
10,800
(8,207)
2,593
252
70
1,978
1,309
1,525
1,163
(64)
44
(20)
58
2
40
40
40
40
New Accounting Pronouncements Issued But Not Yet Effective — The following table provides a brief
description of recent accounting pronouncements that could have a material impact on the Company’s consolidated
financial statements once adopted. Accounting pronouncements not listed below were assessed and determined to
119
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
be either not applicable or are expected to have no material impact on the Company’s consolidated financial
statements.
New Accounting Standards Issued But Not Yet Effective
Description
Date of Adoption
ASU Number and Name
2018-02, Income
Statement — Reporting
Comprehensive Income
(Topic 220),
Reclassification of
Certain Tax Effects from
AOCI
2017-12, Derivatives and
Hedging (Topic 815):
Targeted improvements
to Accounting for
Hedging Activities
2016-13, Financial
Instruments — Credit
Losses (Topic 326):
Measurement of Credit
Losses on Financial
Instruments
2016-02, 2018-01,
2018-10, 2018-11,
2018-20 Leases (Topic
842)
This amendment allows a reclassification of the stranded tax
effects resulting from the implementation of the Tax Cuts and
Jobs Act from AOCI to retained earnings. Because this
amendment only relates to the reclassification of the income tax
effects of the Tax Cuts and Jobs Act, the underlying guidance
that requires that the effect of a change in tax laws or rates be
included in income from continuing operations is not affected.
The standard updates the hedge accounting model to expand
the ability to hedge nonfinancial and financial risk components,
reduce complexity, and ease certain documentation and
assessment requirements. When facts and circumstances are
the same as at the previous quantitative test, a subsequent
quantitative effectiveness test is not required. The standard also
eliminates the requirement to separately measure and report
hedge ineffectiveness. For cash flow hedges, this means that the
entire change in the fair value of a hedging instrument will be
recorded in other comprehensive income and amounts deferred
will be reclassified to earnings in the same income statement line
as the hedged item in the period in which it settles.
Transition method: modified retrospective with the cumulative
effect adjustment recorded to the opening balance of retained
earnings as of the initial application date. Prospective for
presentation and disclosures.
The standard updates the impairment model for financial assets
measured at amortized cost. For trade and other receivables,
held-to-maturity debt securities, loans and other instruments,
entities will be required to use a new forward-looking "expected
loss" model that generally will result in the earlier recognition of
allowance for losses. For available-for-sale debt securities with
unrealized losses, entities will measure credit losses as it is done
today, except that the losses will be recognized as an allowance
rather than a reduction in the amortized cost of the securities.
Transition method: various.
See discussion of the ASU below.
January 1,
2019. Early
adoption is
permitted.
January 1,
2019. Early
adoption is
permitted.
Effect on the financial
statements upon adoption
The Company does not
expect any impact on its
consolidated financial
statements upon
adoption of the standard
on January 1, 2019.
The Company is
currently evaluating the
impact of adopting the
standard on its
consolidated financial
statements.
January 1,
2020. Early
adoption is
permitted only
as of January 1,
2019.
The Company is
currently evaluating the
impact of adopting the
standard on its
consolidated financial
statements.
January 1,
2019. Early
adoption is
permitted.
The Company will adopt
the standard on January
1, 2019; see below for
the evaluation of the
impact of its adoption on
the consolidated
financial statements.
ASU 2016-02 and its subsequent corresponding updates require lessees to recognize assets and liabilities for
most leases, and recognize expenses in a manner similar to the current accounting method. For lessors, the
guidance modifies the lease classification criteria and the accounting for sales-type and direct financing leases. The
guidance also eliminates current real estate-specific provisions.
The standard must be adopted using a modified retrospective approach. The FASB has provided an optional
transition method, which the Company has elected, that allows entities to continue to apply the guidance in ASC
840 Leases to the comparative periods presented in the year of adoption. Under this transition method, the
Company will apply the transition provisions starting on January 1, 2019.
The Company has elected to apply a package of practical expedients that allow lessees and lessors not to
reassess: (1) whether any expired or existing contracts are or contain leases, (2) lease classification for any expired
or existing leases, and (3) whether initial direct costs for any expired or existing leases qualify for capitalization
under ASC 842. These three practical expedients must be elected as a package and must be consistently applied to
all leases. The Company has also elected to apply an optional transition practical expedient for land easements that
allows an entity to continue applying its current accounting policy for all land easements that exist before the
standard’s effective date that were not previously accounted for under ASC 840.
The Company established a task force focused on the identification of contracts that are under the scope of
the new standard and the assessment and measurement of their corresponding right-of-use assets and related
liabilities. Additionally, the implementation team has been working on the configuration of a lease accounting tool
that will support the implementation and the subsequent accounting. The implementation team has also evaluated
120
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
changes to our business processes, systems and controls to support recognition and disclosure under the new
standard.
Under ASC 842, it is expected that fewer contracts will contain a lease. However, due to the elimination of the
real estate-specific guidance and changes to certain lessor classification criteria, more leases will qualify as sales-
type leases and direct financing leases. Under these two models, a lessor will derecognize the asset and will
recognize a lease receivable. According to ASC 842, the lease receivable includes the fair value of the plant after
the contract period but does not include any variable payments such as margin on the sale of energy. Therefore, the
lease receivable could be significantly different than the carrying amount of the underlying asset at lease
commencement. In such circumstances, the difference between the initially recognized lease receivable and the
carrying amount of the underlying asset is recognized as a gain/loss at lease commencement.
The primary expected impact as of the effective date is the recognition of approximately $300 million of lease
liabilities and the corresponding right of use assets for all contracts that contain an operating lease and for which
the Company is the lessee. In addition, the Company expects to reclassify various account balances to different line
items on the Consolidated Balance Sheet to reflect the new presentation requirements. Consolidated Statement of
Operations presentation and the expense recognition pattern are not expected to change for lessees.
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
2018
2017
$
$
300
277
577
$
$
284
278
562
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
7-40
5-72
3-25
5-44
December 31,
2018
2017
$
$
22,875
1,651
310
406
25,242
(8,227)
17,015
$
$
21,529
1,971
284
335
24,119
(7,942)
16,177
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
2018
$
960
199
2017
$ 1,005
139
2016
$ 1,002
118
Property, plant and equipment, net of accumulated depreciation, of $11 billion and $10 billion was mortgaged,
pledged or subject to liens as of December 31, 2018 and 2017, respectively, including assets classified as held-for-
sale.
121
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
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
2018
2017
$
$
8,959
(3,504)
5,455
16,283
(4,723)
11,560
17,015
$
$
8,093
(3,357)
4,736
16,026
(4,585)
11,441
16,177
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
2018
2017
$
$
368
19
(14)
18
24
—
415
$
$
357
1
(21)
16
25
(10)
368
The Company's asset retirement obligations include active ash landfills, water treatment basins and the
removal or dismantlement of certain plants and equipment. The $24 million increase in estimated cash flows in 2018
is primarily due to an increase of $55 million in estimated ash pond closure costs and revised closure dates
associated with an EPA rule regulating CCR at IPL and an increase in coal pile remediation costs at DPL. These
were partially offset by a decrease of $32 million due to reductions in estimated closure costs associated with ash
ponds and landfills at DPL resulting in a reduction to Cost of Sales on the Consolidated Statements of Operations.
The Company used the cost approach to determine the fair value of the ARO liabilities, which was estimated
by discounting expected cash outflows to their present value using market based rates at the initial recording of the
liabilities. Cash outflows were based on the approximate future disposal costs as determined by market information,
historical information or other management estimates. These inputs to the fair value of the ARO liabilities are
considered Level 3 inputs under the fair value hierarchy.
4. FAIR VALUE
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. Because these amounts are 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.
122
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
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 or based on
comparisons to market data obtained for similar assets. Debt securities primarily consist of unsecured debentures
and certificates of deposit held by our Brazilian subsidiaries. Returns and pricing on these instruments are generally
indexed to the market interest rates in Brazil. Debt securities are measured at fair value based on comparisons to
market data obtained for similar assets.
Derivatives — Derivatives are measured at fair value using quoted market prices or the income approach
utilizing volatilities, spot and forward benchmark interest rates (such as LIBOR and EURIBOR), foreign exchange
rates, credit data, and commodity prices, as applicable. 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.
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 interest rate differential approach to construct the remaining portion of the forward curve. Similarly, in
certain instances, the spread that reflects the credit or nonperformance risk is unobservable requiring the use of
proxy yield curves of similar credit quality.
To determine the fair value of a derivative, cash flows are discounted using the relevant spot benchmark
interest rate. The Company then makes a credit valuation adjustment ("CVA"), as applicable, 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 position 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 in a liability position 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 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 based upon interest
rates and other features of the 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. 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, 2018. The Company is not
aware of any factors that would significantly affect the fair value amounts subsequent to December 31, 2018.
Nonrecurring measurements — For nonrecurring measurements derived using the income approach, fair value
is generally 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. 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.
Depending on the complexity of a valuation, an independent valuation firm may be engaged to assist management
in the valuation process.
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
123
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
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. 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 is party 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 were determined
based on the nature and risk of the security and are consistent with how the Company manages, monitors and
measures its marketable securities:
124
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
Assets
DEBT SECURITIES:
Available-for-sale:
Unsecured debentures
Certificates of deposit
Total debt securities
EQUITY SECURITIES:
Mutual funds
Total equity securities
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
Level 1
December 31, 2018
Level 3
Level 2
Total
Level 1
December 31, 2017
Level 3
Level 2
Total
$
$
$
$
— $
—
—
19
19
—
—
—
—
—
19
$
— $
—
—
—
—
— $
5
243
248
49
49
28
6
18
6
58
355
67
5
41
3
116
116
$
$
$
$
— $
—
—
—
—
1
—
199
4
204
204
141
—
—
—
141
141
$
$
$
5
243
248
68
68
29
6
217
10
262
578
208
5
41
3
257
257
$
$
$
$
— $
—
—
20
20
—
—
—
—
—
20
$
— $
—
—
—
—
— $
207
153
360
52
52
15
29
29
30
103
515
111
3
30
19
163
163
$
$
$
$
— $
—
—
—
—
—
—
240
5
245
245
151
—
—
1
152
152
$
$
$
207
153
360
72
72
15
29
269
35
348
780
262
3
30
20
315
315
As of December 31, 2018, all AFS debt securities had stated maturities within one year. For the years ended
December 31, 2018, 2017, and 2016, 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 sale of AFS securities (1)
_____________________________
2018
2017
2016
$
1,403
$
1,398
$
1,726
(1)
Proceeds include $119 million of non-cash proceeds from non-convertible debentures at Guaimbê Solar Complex. See Note 24—Acquisitions for further
information.
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.
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, 2018 and 2017
presented net by type of derivative. 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 (in millions).
Year Ended December 31, 2018
Balance at January 1
Total realized and unrealized gains (losses):
Included in earnings
Included in other comprehensive income — derivative activity
Included in regulatory (assets) liabilities
Settlements
Transfers of assets/(liabilities), net into Level 3
Transfers of (assets)/liabilities, net 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 $
$
125
Interest Rate
$
(151) $
Foreign Currency
240
Commodity
Total
$
4
$
93
22
(8)
—
14
(8)
(9)
(140) $
(14)
—
—
(27)
—
—
199
$
(1)
—
5
(4)
—
—
4
$
29
$
(41) $
(1) $
7
(8)
5
(17)
(8)
(9)
63
(13)
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
Year Ended December 31, 2017
Balance at January 1
Total realized and unrealized gains (losses):
Included in earnings
Included in other comprehensive income — derivative activity
Included in regulatory (assets) liabilities
Settlements
Transfers of assets/(liabilities), net into Level 3
Transfers of (assets)/liabilities, net 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
$
(179) $
255
$
5
$
81
(1)
(23)
—
36
(4)
20
(151) $
21
—
—
(36)
—
—
240
$
7
$
(15) $
1
—
10
(12)
—
—
4
1
$
$
21
(23)
10
(12)
(4)
20
93
(7)
The following table summarizes the significant unobservable inputs used for the Level 3 derivative assets
(liabilities) as of December 31, 2018 (in millions, except range amounts):
Type of Derivative
Interest rate
Foreign currency:
Argentine peso
Commodity:
Other
Total
Fair Value
Unobservable Input
$
(140) Subsidiaries’ credit spreads
Amount or Range
(Weighted Average)
1.8% - 5.3% (3.7%)
199 Argentine peso to U.S. dollar currency exchange rate after one year
52.7 - 142.6 (96.1)
4
63
$
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 long-lived assets 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, 2018
Assets
Dispositions and held-for-sale businesses:
Shady Point
Long-lived assets held and used: (2)
Nejapa
Equity method investments:
Guacolda
Elsta
Year Ended December 31, 2017
Assets
Long-lived assets held and used: (2)
Laurel Mountain
Kilroot
DPL
Other
Dispositions and held-for-sale businesses:
DPL Peaker Assets
Kazakhstan Hydroelectric (3)
Kazakhstan CHPs
_____________________________
Measurement
Date
Carrying
Amount (1)
Level 1
Fair Value
Level 2
Level 3
Pre-tax
Loss
12/31/2018
$
211
$
— $
— $
30
$
157
12/31/2018
10/01/2018
09/30/2018
42
354
19
—
—
—
—
—
16
5
209
—
37
144
3
Measurement
Date
Carrying
Amount (1)
Level 1
Fair Value
Level 2
Level 3
Pre-tax
Loss
$
12/31/2017
12/31/2017
02/28/2017
Various
12/31/2017
06/30/2017
03/31/2017
$
154
69
77
18
346
190
171
— $
—
—
—
—
—
—
— $
—
—
—
237
92
29
$
33
20
11
—
—
—
—
121
37
66
18
109
92
94
(1)
(2)
(3)
Represents the carrying values at the dates of initial measurement, before fair value adjustment.
See Note 20—Asset Impairment Expense for further information.
Per the Company's policy, pre-tax loss is limited to the impairment of long-lived assets. Any additional loss will be recognized on completion of the sale. Upon
disposal of Kazakhstan HPPs, the Company incurred an additional pre-tax loss on disposal of $33 million. See Note 20—Asset Impairment Expense and Note
23—Held-for-Sale and Dispositions for further information.
126
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
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, 2018 (in
millions, except range amounts):
December 31, 2018
Fair Value
Valuation Technique
Unobservable Input
Range (Weighted Average)
Long-lived assets held and used:
Nejapa
5 Discounted cash flow
Annual revenue growth
Pre-tax operating margin
Weighted-average cost of capital
-70% to -1% (-15%)
37% to 82% (59%)
12%
Equity method invesments:
Guacolda
209 Discounted cash flow
Annual dividend growth
Weighted-average cost of equity
-70% to 467% (48%)
10%
Total
$
214
When determining the fair value of the Shady Point held-for-sale asset group, the Company used the market
approach based on prices and unobservable inputs from transactions involving comparable assets as the inputs for
the Level 3 nonrecurring measurement.
Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets
The following table presents 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 (in millions).
Assets:
Liabilities: Non-recourse debt
Accounts receivable — noncurrent (1)
Recourse debt
Assets:
Liabilities: Non-recourse debt
Accounts receivable — noncurrent (1)
Recourse debt
_____________________________
$
$
Carrying
Amount
100
15,645
3,655
Carrying
Amount
163
15,340
4,630
$
$
December 31, 2018
Fair Value
Total
Level 1
Level 2
Level 3
$
209
16,225
3,621
— $
—
—
— $
13,524
3,621
209
2,701
—
December 31, 2017
Fair Value
Total
Level 1
Level 2
Level 3
$
217
15,890
4,920
— $
—
—
6
13,350
4,920
$
211
2,540
—
(1)
These amounts primarily 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 $16 million and
$31 million as of December 31, 2018 and 2017, respectively.
5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Volume of Activity — The following table presents the Company's maximum notional (in millions) over the
remaining contractual period by type of derivative as of December 31, 2018, 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 peso
Colombian peso
Brazilian real
Others, primarily with weighted average remaining maturities of a year or less
Maximum Notional
Translated to USD
4,584
$
344
68
270
117
23
112
Latest Maturity
2044
2029
2026
2021
2021
2019
2021
127
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
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, 2018
Not Designated
Total
Designated
December 31, 2017
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
$
$
$
$
Fair Value
Current
Noncurrent
Total
29
6
—
—
35
205
5
28
—
238
$
$
$
$
— $
—
217
10
227
$
$
$
3
—
13
3
19
$
$
29
6
217
10
262
208
5
41
3
257
$
$
$
$
15
29
8
5
57
125
3
1
9
138
$
$
$
$
— $
—
261
30
291
$
137
—
29
11
177
$
$
December 31, 2018
December 31, 2017
Assets
Liabilities
Assets
Liabilities
75
187
262
$
$
51
206
257
$
$
84
264
348
$
$
15
29
269
35
348
262
3
30
20
315
211
104
315
As of December 31, 2018, all derivative instruments subject to credit risk-related contingent features were in
an asset position.
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
December 31, 2017
$
15
9
Earnings and Other Comprehensive Income (Loss) — The following table presents the pre-tax gains (losses)
recognized in AOCL and earnings related to all derivative instruments for the periods indicated (in millions):
Effective portion of cash flow hedges
Gains (losses) recognized in AOCL
Interest rate derivatives
Cross-currency derivatives
Foreign currency derivatives
Commodity derivatives
Total
Gains (losses) reclassified from AOCL to earnings
Interest rate derivatives
Cross-currency derivatives
Foreign currency derivatives
Commodity derivatives
Total
Loss reclassified from AOCL to earnings due to discontinuance of hedge accounting (1)
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,
2017
2016
2018
$
$
$
$
$
$
$
(16) $
(26)
(52)
—
(94) $
(52) $
(43)
(16)
(6)
(117) $
— $
(66) $
31
(5)
18
(22) $
(82) $
34
(20)
17
(51) $
(13) $
(7) $
3
$
148
25
173
$
1
14
15
$
(35)
21
(4)
30
12
(101)
8
(8)
56
(45)
—
(1)
19
(16)
3
(1) Cash flow hedge was discontinued because it was probable the forecasted transaction will not occur.
AOCL is expected to decrease pre-tax income from continuing operations for the twelve months ended
December 31, 2019 by $59 million, primarily due to interest rate derivatives.
128
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
6. FINANCING RECEIVABLES
Receivables with contractual maturities of greater than one year are considered financing receivables,
primarily related to amended agreements or government resolutions due from CAMMESA. The following table
presents financing receivables by country as of the dates indicated (in millions):
December 31,
Argentina
Panama
Other
Total
Argentina
2018
2017
$
$
93
14
9
116
$
$
177
—
17
194
Collection of the principal and interest on these receivables is subject to various business risks and
uncertainties, including, but not limited to, the continued 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 if collectability is reasonably assured. The Company's collection estimates are based on
assumptions it believes to be reasonable, but are inherently uncertain. Actual future cash flows could differ from
these estimates. The decrease in Argentina financing receivables was primarily due to planned collections and
unfavorable FX impacts.
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.
The FONINVEMEM receivables are denominated in Argentine pesos, but indexed to U.S. dollars, which
represents a foreign currency derivative. Due to differences between spot rates, used to remeasure the receivables,
and discounted forward rates, used to value the foreign currency derivative, these two items will not perfectly offset
over the life of the receivable. Once settled, the foreign currency derivative will offset the accumulated unrealized
foreign currency losses resulting from the devaluation of the FONINVEMEM receivable. As of December 31, 2018
and 2017, 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 $199 million and $240 million, respectively.
The receivables under the FONINVEMEM Agreements have been actively collected since the related plants
commenced operations in 2010 and 2016. In assessing the collectability of the receivables under these
agreements, the Company also considers historic collection evidence in accordance with the agreements.
Other Agreements — Other agreements primarily consist of resolutions passed by the Argentine government
in which AES Argentina will receive compensation for investments in new generation plants and technologies. The
timing of collections depend on corresponding agreements and collectability of these receivables are assessed on
an ongoing basis.
129
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
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
sPower
OPGC (1)
Guacolda (2)
Other affiliates (3)
Total
_____________________________
Country
United States
India
Chile
Various
2018
2017
Carrying Value (in millions)
2018
2017
Ownership Interest %
$
$
515
293
209
97
1,114
$
$
508
269
357
63
1,197
50%
49%
33%
50%
49%
33%
(1)
(2)
(3)
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 2019.
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%.
Includes Fluence, Simple Energy, Bosforo, Elsta, Distributed Energy equity method investments, and others.
Guacolda — In October 2018, an other-than-temporary impairment was identified at Guacolda primarily as a
result of increased renewable generation in Chile lowering energy prices, impacting management's ability to re-
contract Guacolda's generation after expiration of existing PPAs. A calculation of the fair value of Gener's
investment in Guacolda was required to evaluate whether there was a loss in the carrying value of the investment.
Based on management's estimate of fair value of $209 million, the Company recognized an other-than-temporary
impairment of $144 million in Other non-operating expense. The Guacolda equity method investment is reported in
the South America SBU reportable segment.
Distributed Energy — In December 2018, Distributed Energy acquired the remaining equity interest in a
partnership holding various solar projects for consideration of $23 million. This transaction resulted in a loss of $5
million, reported in Other expense in the Consolidated Statement of Operations. The projects, previously recorded
as equity method investments, have been consolidated. See Note 24—Acquisitions for further discussion.
Simple Energy — In April 2018, the Company invested $35 million in Simple Energy, a provider of utility-
branded marketplaces and omni-channel instant rebates. As the Company does not control Simple Energy, the
investment is accounted for as an equity method investment and is reported as part of Corporate and Other.
Fluence — On January 1, 2018, Siemens and AES closed on the creation of the Fluence joint venture with
each party holding a 50% ownership interest. The Company contributed $7 million in cash and $20 million in non-
cash assets from the AES Advancion energy storage development business as consideration for the transaction,
and received an equity interest in Fluence with a fair value of $50 million. See Note 23—Held-for-Sale and
Dispositions for further discussion. Fluence is a global energy storage technology and services company. As the
Company does not control Fluence, the investment is accounted for as an equity method investment. The Fluence
equity method investment is reported as part of Corporate and Other.
sPower — In February 2017, the Company and Alberta Investment Management Corporation (“AIMCo”)
entered into an agreement to acquire FTP Power LLC (“sPower”). In July 2017, AES closed on the acquisition of its
48% ownership interest in sPower for $461 million. In November 2017, AES acquired an additional 2% ownership
interest in sPower for $19 million. As the Company does not control sPower, it is accounted for as an equity method
investment. The sPower portfolio includes solar and wind projects in operation, under construction, and in
development located in the United States. The sPower equity method investment is reported in the US and Utilities
SBU reportable segment.
130
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
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, 2018 and 2017, other long-term liabilities included $43 million and $45 million related to this
debt agreement.
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 (loss)
December 31,
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
Stockholders' equity
50%-or-less Owned Affiliates
2017
2016
2018
Majority-Owned Unconsolidated Subsidiaries
2017
2016
2018
$
$
$
$
962
135
14
2018
558
5,918
546
3,309
2,622
$
762
165
72
2017
418
5,372
633
2,629
2,527
586
145
64
$
$
2018
$
$
40
3
(3)
89
41
35
122
(27)
$
16
5
(15)
23
9
(2)
2017
70
102
10
147
15
At December 31, 2018, retained earnings included $236 million related to the undistributed earnings of the
Company's 50%-or-less owned affiliates. Distributions received from these affiliates were $42 million, $69 million,
and $24 million for the years ended December 31, 2018, 2017, and 2016, respectively. As of December 31, 2018,
the underlying equity in the net assets of our equity affiliates exceeded the aggregate carrying amount of our
investments in equity affiliates by $49 million.
8. GOODWILL AND OTHER INTANGIBLE ASSETS
Goodwill — The following table summarizes the carrying amount of goodwill by reportable segment for the years
ended December 31, 2018 and 2017 (in millions):
Balance as of December 31, 2017
Goodwill
Accumulated impairment losses
Net balance
Balance as of December 31, 2018
Goodwill
Accumulated impairment losses
Net balance
US and
Utilities
South
America
MCAC
Eurasia
Total
$
$
2,786
(2,611)
175
2,786
(2,611)
175
$
$
868
—
868
868
—
868
$
$
16
—
16
16
—
16
$
$
$
122
(122)
—
122
(122)
— $
3,792
(2,733)
1,059
3,792
(2,733)
1,059
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, 2018
Accumulated
Amortization
Net Balance
Gross
Balance
December 31, 2017
Accumulated
Amortization
Net Balance
Subject to Amortization
Internal-use software
Contracts
Project development rights
Contractual payment rights (1)
Emissions allowances (2)
Other (3)
Subtotal
Indefinite-Lived Intangible Assets
Land use rights
Water rights
Other
Subtotal
Total
_____________________________
$
$
467
137
93
57
15
78
847
21
20
5
46
893
$
$
123
113
92
13
15
34
390
21
20
5
46
436
$
$
416
92
57
65
—
98
728
45
20
14
79
807
$
$
(330) $
(21)
(1)
(47)
—
(42)
(441)
—
—
—
—
(441) $
86
71
56
18
—
56
287
45
20
14
79
366
(344) $
(24)
(1)
(44)
—
(44)
(457)
—
—
—
—
(457) $
131
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
(1)
(2)
(3)
Represent legal rights to receive system reliability payments from the regulator.
Acquired or purchased emissions allowances are finite-lived intangible assets that are expensed when utilized and included in net income for the year.
Includes management rights, sales concessions, renewable energy credits and incentives, and other individually insignificant intangible assets. During the
fourth quarter of 2018, the Company recognized an asset impairment of $23 million on gas extraction rights at Nejapa. See Note 20—Asset Impairment
Expense for further information.
The following tables summarize other intangible assets acquired during the periods indicated (in millions):
December 31, 2018
Amount
Internal-use software
Contracts
Project development rights
Emissions allowances
Other
Total
December 31, 2017
Project Development Rights
Contracts
Internal-use software
Other
Total
$
$
$
$
67
50
35
16
11
179
Amount
53
34
17
8
112
Subject to Amortization/
Indefinite-Lived
Subject to Amortization
Subject to Amortization
Subject to Amortization
Subject to Amortization
Various
Subject to Amortization/
Indefinite-Lived
Subject to Amortization
Subject to Amortization
Subject to Amortization
Various
Weighted Average Amortization
Period (in years)
6
24
23
Various
N/A
Weighted Average Amortization
Period (in years)
30
25
7
N/A
Amortization
Method
Straight-line
Straight-line
Straight-line
As utilized
N/A
Amortization
Method
Straight-line
Straight-line
Straight-line
N/A
The following table summarizes the estimated amortization expense by intangible asset category for 2019
through 2023:
(in millions)
Internal-use software
Contracts
Other
Total
2019
2020
2021
2022
2023
$
$
33
4
8
45
$
$
28
4
8
40
$
$
19
4
6
29
$
$
13
4
6
23
$
$
7
4
6
17
Intangible asset amortization expense was $47 million, $34 million and $37 million for the years ended
December 31, 2018, 2017 and 2016, respectively.
132
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
9. 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:
2018
2017
Recovery/Refund
Period
El Salvador energy pass through costs recovery
$
87
$
Other
Total current regulatory assets
Noncurrent regulatory assets:
IPL and DPL defined benefit pension obligations (1)
IPL deferred Midwest ISO costs
IPL environmental costs
Other
Total noncurrent regulatory assets
TOTAL REGULATORY ASSETS
REGULATORY LIABILITIES
Current regulatory liabilities:
Overcollection of costs to be passed back to customers
Other
Total current regulatory liabilities
Noncurrent regulatory liabilities:
IPL and DPL accrued costs of removal and ARO's
IPL and DPL income taxes payable to customers through rates
Other
Total noncurrent regulatory liabilities
TOTAL REGULATORY LIABILITIES
_____________________________
(1)
Past expenditures on which the Company earns a rate of return.
69
156
283
88
89
87
547
703
83
3
86
847
246
53
1,146
$
$
$
$
$
1,232
$
59 Quarterly
60 Various
119
298 Various
102
8 years
48 Various
94 Various
542
661
14
1 year
3 Various
17
830 Over life of assets
243 Various
6 Various
1,079
1,096
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
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:
• Demand charges at DPL;
• Unamortized premiums reacquired or redeemed on long-term debt at IPL and DPL, which are amortized
over the lives of the original issuances; and
• Costs to comply with environmental regulations.
Our regulatory liabilities primarily consist of obligations for removal costs which do not have an associated
legal retirement obligation. Our regulatory liabilities also include deferred income taxes associated with the
reduction of the U.S. federal income tax rate which will be passed through to our regulated customers via a
decrease in future retail rates, see Note 21—Income Taxes for further information.
In the accompanying Consolidated Balance Sheets the current regulatory assets and liabilities are reflected in
Other current assets and Accrued and other liabilities, respectively, and the noncurrent regulatory assets and
liabilities are reflected in Other noncurrent assets and Other noncurrent liabilities, respectively. The regulatory
assets and liabilities primarily related to the US and Utilities SBU as of December 31, 2018 and December 31,
2017.
133
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
10. DEBT
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:
Bank loans
Notes and bonds
Debt to (or guaranteed by) multilateral, export credit agencies or development banks (1)
Fixed Rate:
Bank loans
Notes and bonds
Debt to (or guaranteed by) multilateral, export credit agencies or development banks (1)
Other
Unamortized (discount) premium & debt issuance (costs), net
Subtotal
Less: Current maturities
Noncurrent maturities
_____________________________
Weighted
Average
Interest Rate
December 31,
Maturity
2018
2017
4.46%
3.89%
3.56%
4.62%
5.85%
5.45%
5.87%
2019 – 2050
2020 – 2030
2023 – 2034
$ 2,600
821
3,292
$ 2,488
900
3,668
2019 – 2040
2019 – 2073
2023 – 2034
2023 – 2061
1,684
7,346
246
24
(368)
$ 15,645
(1,659)
$ 13,986
993
7,388
271
26
(394)
$ 15,340
(2,164)
$ 13,176
(1) Multilateral loans include loans funded and guaranteed by bilaterals, multilaterals, development banks and other similar institutions.
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 $3.9 billion on non-recourse debt outstanding at
December 31, 2018. 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 2.24% to 8.00%.
Non-recourse debt as of December 31, 2018 is scheduled to reach maturity as shown below (in millions):
December 31,
2019
2020
2021
2022
2023
Thereafter
Unamortized (discount) premium & debt issuance (costs), net
Total
Annual Maturities
$
$
1,697
1,458
1,601
1,530
1,316
8,411
(368)
15,645
As of December 31, 2018, AES subsidiaries with facilities under construction had a total of approximately $811
million of committed but unused credit facilities available to fund construction and other related costs. Excluding
these facilities under construction, AES subsidiaries had approximately $1.8 billion in various 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, 2018, the Company's subsidiaries had the
following significant debt transactions:
Subsidiary
Southland (1)
Tietê
Alto Maipo
DPL
Gener
Angamos
IPALCO
Total
Transaction Period
Issuances
Repayments
Gain (Loss) on
Extinguishment of Debt
Q1, Q2, Q3, Q4
Q1
Q2
Q2
Q3
Q3
Q4
$
$
757
385
104
—
—
—
105
1,351
$
$
— $
(231)
—
(106)
(104)
(98)
(89)
(628) $
—
—
—
(6)
(7)
—
—
(13)
_____________________________
(1)
Issuances relate to the June 2017, long-term non-recourse debt financing to fund the Southland re-powering construction projects.
134
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
AES Argentina — In February 2017, AES Argentina issued $300 million aggregate principal of unsecured and
unsubordinated notes due in 2024. The net proceeds from this issuance were used for the prepayment of $75
million of non-recourse debt related to the construction of the San Nicolas Plant resulting in a gain on
extinguishment of debt of approximately $65 million.
Non-Recourse Debt Covenants, Restrictions and Defaults — The terms of the Company's non-recourse debt
include certain financial and nonfinancial 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, 2018 and 2017, approximately $627 million and $642 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 $2.9 billion at December 31, 2018.
The following table summarizes the Company's subsidiary non-recourse debt in default (in millions) as of
December 31, 2018. Due to the defaults, these amounts are included in the current portion of non-recourse debt:
Subsidiary
AES Puerto Rico
AES Ilumina (Puerto Rico)
Total
_____________________________
(1)
Primary Nature
of Default
Covenant
Covenant
$
$
December 31, 2018
Default
Net Assets
317
34
351
$
(1)
139
17
This does not include $483 million of non-recourse debt at Colon, one of the Company’s subsidiaries in Panama, that has been classified as current.
Colon is currently in compliance with all provisions of its financing agreements, but does not expect to complete a required contract assignment to the lenders by the
March 31, 2019 deadline. The Company is working with the lenders to modify the loan agreement to amend the requirement of this technical covenant in 2019. If this
amendment is executed, the debt will be re-classified as noncurrent.
The above defaults are not payment defaults. All of the subsidiary non-recourse defaults were triggered by
failure to comply with 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.
The AES Corporation's recourse debt agreements include cross-default clauses that will trigger if a subsidiary
or group of subsidiaries for which the non-recourse debt is in default provides more than 20% of the Parent
Company's total cash distributions from businesses for the four most recently completed fiscal quarters. As of
December 31, 2018, the Company has no defaults which 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.
135
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
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
Drawings on secured credit facility
Senior Secured Term Loan
Senior Unsecured Note
Senior Unsecured Note
Senior Unsecured Note
Senior Unsecured Note
Senior Unsecured Note
Senior Unsecured Note
Interest Rate
8.00%
4.00%
7.38%
LIBOR + 2.00%
LIBOR + 1.75%
4.88%
4.50%
5.50%
5.50%
6.00%
5.13%
Final Maturity
2020
2021
2021
2021
2022
2023
2023
2024
2025
2026
2027
Unamortized (discount) premium & debt issuance (costs), net
Subtotal
Less: Current maturities
Noncurrent maturities
$
$
December 31, 2018
$
— $
December 31, 2017
228
—
690
207
521
713
—
738
573
500
500
(40)
4,630
(5)
4,625
$
$
500
—
—
366
713
500
63
544
500
500
(31)
3,655
(5)
3,650
The following table summarizes the principal amounts due under our recourse debt for the next five years and
thereafter (in millions):
December 31,
2019
2020
2021
2022
2023
Thereafter
Unamortized (discount) premium & debt issuance (costs), net
Total recourse debt
Net Principal Amounts Due
5
$
5
505
350
1,213
1,608
(31)
3,655
$
In December 2018, the Company prepaid $150 million aggregate principal of its existing senior secured term
loan due in 2022. As a result of the transaction, the Company recognized a loss on extinguishment of debt of $1
million.
In March 2018, the Company purchased via tender offers $671 million aggregate principal of its existing 5.50%
senior unsecured notes due in 2024 and $29 million of its existing 5.50% senior unsecured notes due in 2025. As a
result of these transactions, the Company recognized a loss on extinguishment of debt of $44 million.
In March 2018, the Company issued $500 million aggregate principal of 4.00% senior notes due in 2021 and
$500 million of 4.50% senior notes due in 2023. The Company used the proceeds from these issuances to
purchase via tender offer in full the $228 million balance of its 8.00% senior notes due in 2020 and the $690 million
balance of its 7.375% senior notes due in 2021. As a result of these transactions, the Company recognized a loss
on extinguishment of debt of $125 million.
In August 2017, the Company issued $500 million aggregate principal amount of 5.125% senior notes due in
2027. The Company used these proceeds to redeem at par $240 million aggregate principal of its existing LIBOR +
3.00% senior unsecured notes due in 2019 and purchased $217 million of its existing 8.00% senior unsecured
notes due in 2020. As a result of the latter transactions, the Company recognized a loss on extinguishment of debt
of $36 million.
In May 2017, the Company closed on $525 million aggregate principal LIBOR + 2.00% secured term loan due
in 2022. In June 2017, the Company used these proceeds to redeem at par all $517 million aggregate principal of
its existing Term Convertible Securities. As a result of the latter transaction, the Company recognized a loss on
extinguishment of debt of $6 million.
In March 2017, the Company redeemed via tender offers $276 million aggregate principal of its existing
7.375% senior unsecured notes due in 2021 and $24 million of its existing 8.00% senior unsecured notes due in
2020. As a result of these transactions, the Company recognized a loss on extinguishment of debt of $47 million.
Recourse Debt Covenants and Guarantees — The Company's obligations under the senior secured credit
facility and senior secured term loan are, subject to certain exceptions, secured by (i) all of the capital stock of
136
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
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 and senior secured term loan are 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 the term loan, if any, using 60% of net cash proceeds, reduced to 50% when and
if the Parent Company'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, evaluated quarterly, requiring the Company
to maintain a minimum ratio of adjusted operating cash flow to interest charges on recourse debt of 1.3 times and a
maximum ratio of recourse debt to adjusted operating cash flow of 7.5 times.
The terms of the Company's senior unsecured notes and senior secured term loan contain certain covenants
including limitations 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. AES, at its option, may
redeem the 6.75% Debentures which would result in the required redemption of the TECONS issued by
AES Trust III for $50 per TECON. As of December 31, 2016, the sole assets of AES Trust III were the
6.75% Debentures. In June 2017, the Company redeemed the 6.75% Debentures and redeemed at par all
remaining aggregate principal of its existing TECONs.
11. COMMITMENTS
LEASES — The Company enters into long-term non-cancelable lease arrangements which, for accounting
purposes, are classified as either operating or capital leases. Operating leases primarily include certain
transmission lines, office rental and site leases. Operating lease rental expense for the years ended December 31,
2018, 2017, and 2016 was $51 million, $61 million and $61 million, respectively. Capital leases primarily include
transmission lines, vehicles, offices, 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, 2018 and 2017 was $13 million and $27 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, 2018 for 2019 through
2023 and thereafter (in millions):
December 31,
2019
2020
2021
2022
2023
Thereafter
Total
Less: Imputed interest
Present value of total minimum lease payments
Future Commitments for
Capital Leases
Operating Leases
$
$
1
1
1
1
1
7
12
(6)
6
74
38
25
26
25
455
643
$
$
$
CONTRACTS — The Company enters into long-term contracts for construction projects, maintenance and
service, transmission of electricity, operations services and purchases of electricity and fuel. In general, these
contracts are subject to variable quantities or prices and are terminable only in limited circumstances. The following
table shows the future minimum commitments for continuing operations under these contracts as of December 31,
137
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
2018 for 2019 through 2023 and thereafter as well as actual purchases under these contracts for the years ended
December 31, 2018, 2017, and 2016 (in millions):
Actual purchases during the year ended December 31,
2016
2017
2018
Future commitments for the year ending December 31,
2019
2020
2021
2022
2023
Thereafter
Total
12. CONTINGENCIES
Electricity Purchase Contracts
420
$
747
827
Fuel Purchase Contracts
1,790
$
1,619
1,838
Other Purchase Contracts
817
$
1,945
1,671
$
$
786
602
371
234
393
5,187
7,573
$
$
1,494
1,027
882
575
463
1,734
6,175
$
$
1,375
681
336
561
213
778
3,944
Guarantees and 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 expects to fulfill within the normal course of business. The expiration dates of these guarantees
vary from less than one year to more than 16 years.
The following table summarizes the Parent Company's contingent contractual obligations as of December 31,
2018. 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.
There were no obligations made by the Parent Company for the direct benefit of the lenders associated with the
non-recourse debt of its businesses.
Contingent Contractual Obligations
Amount (in millions)
Guarantees and commitments
Letters of credit under the unsecured credit facility
Letters of credit under the senior secured credit facility
Asset sale related indemnities (1)
Total
_____________________________
$
$
685
368
78
27
1,158
Number of
Agreements
Maximum Exposure Range for
Each Agreement (in millions)
$0 — 157
$1 — 247
$0 — 49
$27
33
10
23
1
67
(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.
During the year ended December 31, 2018, the Company paid letter of credit fees ranging from 1% to 3% 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. For the periods ended December 31, 2018 and
2017, the Company had recognized liabilities of $5 million 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, 2018. In aggregate,
the Company estimates the range of potential losses related to environmental matters, where estimable, to be up to
$17 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 recognized aggregate liabilities for all claims of
138
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
approximately $53 million and $50 million as of December 31, 2018 and 2017, respectively. 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 regulatory matters and commercial disputes in international
jurisdictions. 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, 2018. The material contingencies where a loss is
reasonably possible primarily include disputes with offtakers, suppliers and EPC contractors; alleged breaches of
contract; alleged violation of laws and regulations; income tax and non-income tax matters with tax authorities; and
regulatory matters. In aggregate, the Company estimates the range of potential losses, where estimable, related to
these reasonably possible material contingencies to be between $79 million and $439 million. 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.
13. BENEFIT PLANS
Defined Contribution Plan — The Company sponsors four defined contribution plans ("the DC Plans"). Two
plans cover U.S. non-union employees; one for Parent Company and certain US and Utilities SBU business
employees, and one for DPL employees. The remaining two plans include union and non-union employees at IPL
and union employees at DPL. The DC Plans are qualified under section 401 of the Internal Revenue Code. Most
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. Within the DC Plans, the Company provides matching contributions
in addition to other non-matching contributions. Participants are fully vested in their own contributions. The
Company's contributions vest over various time periods ranging from immediate up to five years. For the years
ended December 31, 2018, 2017 and 2016, costs for defined contribution plans were approximately $21 million,
$23 million and $15 million, respectively.
Defined Benefit Plans — Certain of the Company's subsidiaries have defined benefit pension plans covering
substantially all of their respective employees ("the DB Plans"). Pension benefits are based on years of credited
service, age of the participant, and average earnings. Of the 30 active DB Plans as of December 31, 2018, five are
at U.S. subsidiaries and the remaining plans are at foreign subsidiaries.
139
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
The following table reconciles the Company's funded status, both domestic and foreign, as of the periods
indicated (in millions):
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
Plan combinations
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
2018
2017
U.S.
Foreign
U.S.
Foreign
$
$
$
$
$
1,257
15
40
—
10
—
—
(105)
—
(99)
—
1,118
1,127
(35)
39
—
—
(105)
—
1,026
$
$
$
$
470
12
22
1
—
—
(21)
(17)
(4)
(8)
(38)
417
455
6
21
1
(21)
(17)
(35)
410
$
$
$
$
1,188
13
41
—
1
3
—
(71)
—
82
—
1,257
1,044
141
13
—
—
(71)
—
1,127
$
$
$
$
(92) $
(7) $
(130) $
411
10
22
1
(1)
—
(2)
(22)
—
29
22
470
402
31
18
1
(2)
(22)
27
455
(15)
The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to the
funded status of the DB 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
2018
2017
U.S.
Foreign
U.S.
Foreign
$
$
— $
—
(92)
(92) $
$
64
(6)
(65)
(7) $
— $
—
(130)
(130) $
69
(6)
(78)
(15)
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
2018
2017
U.S.
$ 1,101
Foreign
376
$
U.S.
$ 1,236
Foreign
433
$
$ 1,118
1,101
1,026
$ 1,118
1,026
$
$
89
79
33
$ 1,257
1,236
1,127
220
150
$ 1,257
1,127
$
$
109
97
33
238
154
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:
Periodic Benefit Cost:
Discount rate
Rate of compensation increase
Discount rate
Expected long-term rate of return on plan assets
Rate of compensation increase
2018
2017
U.S.
4.35%
3.34%
3.67%
5.73%
3.34%
Foreign
5.63%
4.79%
5.23%
3.94%
4.65%
(1)
U.S.
3.67%
3.34%
4.28%
6.67%
3.34%
Foreign
5.23%
4.65%
5.83%
5.30%
4.86%
(1)
_____________________________
(1)
Includes an inflation factor that is used to calculate future periodic benefit cost, but is not used to calculate the benefit obligation.
140
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
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. Unrecognized gains or losses
are amortized using the “corridor approach,” under which the net gain or loss in excess of 10% of the greater of the
projected benefit obligation or the market-related value of the assets, if applicable, is amortized.
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 2018. 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, 2018 is affected by the assumptions as of that date. Pension expense for
2018 is affected by the December 31, 2017 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
$
(12)
12
(16)
16
The following table summarizes the components of the net periodic benefit cost, both domestic and foreign, for
the years indicated (in millions):
December 31,
Components of Net Periodic Benefit Cost:
2018
2017
2016
U.S.
Foreign
U.S.
Foreign
U.S.
Foreign
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service cost
Amortization of net loss
Curtailment loss recognized
Settlement loss recognized
Total pension cost
$
$
15
40
(64)
5
18
1
—
15
$
$
12
22
(17)
—
3
—
4
24
$
$
13
41
(69)
6
18
4
—
13
$
$
10
23
(21)
—
2
—
—
14
$
$
13
42
(68)
7
18
4
—
16
$
$
9
21
(19)
(1)
2
—
—
12
The following table summarizes the amounts reflected in AOCL, including AOCL attributable to noncontrolling
interests, on the Consolidated Balance Sheet as of December 31, 2018, that have not yet been recognized as
components of net periodic benefit cost (in millions):
December 31, 2018
Prior service cost
Unrecognized net actuarial loss
Total
Accumulated Other Comprehensive Income (Loss)
U.S.
Foreign
$
$
(4) $
(19)
(23) $
1
(76)
(75)
The following table summarizes the Company's target allocation for 2018 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
2018
2017
Percentage of Plan Assets as of December 31,
U.S.
20%
78%
2%
—%
Foreign
3%
94%
—%
3%
U.S.
16.85%
80.20%
2.35%
0.60%
100.00%
Foreign
3.75%
93.57%
0.44%
2.24%
100.00%
U.S.
31.90%
64.53%
3.20%
0.37%
100.00%
Foreign
4.61%
93.10%
0.44%
1.85%
100.00%
141
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
The U.S. DB 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 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. DB 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
Cash and cash equivalents
Total plan assets
Level 1
173
$
170
653
—
6
$ 1,002
_____________________________
December 31, 2018
Level 2
Level 3
$
— $
—
—
24
—
24
$
Total
173
— $
170
—
653
—
24
—
—
6
— $ 1,026
Level 1
359
$
135
593
—
4
$ 1,091
December 31, 2017
Level 2
Level 3
$
— $
—
—
36
—
36
$
Total
359
— $
135
—
593
—
36
—
—
4
— $ 1,127
(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 DB 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 DB plan assets by category of investment
and level within the fair value hierarchy as of the periods indicated (in millions):
Foreign Plans
Equity securities:
Debt securities:
Real estate:
Other:
Mutual funds
Private equity
Government debt securities
Mutual funds (1)
Real estate
Cash and cash equivalents
Other assets
Total plan assets
Level 1
14
$
—
13
287
—
2
1
317
$
_____________________________
December 31, 2018
Level 2
Level 3
$
— $
—
—
84
—
—
—
84
$
Total
14
1
13
371
2
2
7
410
Level 1
20
$
—
11
323
—
—
1
355
$
— $
1
—
—
2
—
6
9
$
December 31, 2017
Level 2
Level 3
$
— $
—
—
90
—
—
—
90
$
Total
20
1
11
413
2
—
8
455
— $
1
—
—
2
—
7
10
$
(1) Mutual funds categorized as debt securities consist of mutual funds for which debt securities are the primary underlying investment.
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 2019
Expected benefit payments for fiscal year ending:
2019
2020
2021
2022
2023
2024 - 2028
14. EQUITY
U.S.
Foreign
$
9
$
69
70
72
72
73
367
14
23
21
23
24
25
155
Equity Transactions with Noncontrolling Interests
Distributed Energy — In 2018, Distributed Energy, through multiple transactions, sold noncontrolling interests
in multiple project companies to tax equity partners. These transactions resulted in a $98 million increase to
noncontrolling interest. Distributed Energy is reported in the US and Utilities SBU reportable segment.
Alto Maipo — In March 2017, AES Gener completed the legal and financial restructuring of Alto Maipo. As part
of this restructuring, AES indirectly acquired the 40% ownership interest of the noncontrolling shareholder for a de
142
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
minimis payment, and sold a 6.7% interest in the project to the construction contractor. This transaction resulted in a
$196 million increase to the Parent Company’s Stockholders’ Equity due to an increase in additional paid-in-capital
of $229 million, offset by the reclassification of accumulated other comprehensive losses from NCI to the Parent
Company Stockholders’ Equity of $33 million. No gain or loss was recognized in net income as the sale was not
considered to be a sale of in-substance real estate. After completion of the sale, the Company has an effective 62%
economic interest in Alto Maipo. As the Company maintained control of the partnership after the sale, Alto Maipo
continues to be consolidated by the Company within the South America SBU reportable segment.
Dominican Republic — In September 2017, Linda Group acquired 5% of our Dominican Republic business for
$60 million, pre-tax. This transaction resulted in a net increase of $25 million to the Company’s additional paid-in-
capital and noncontrolling interest, respectively. No gain or loss was recognized in net income as the sale was not
considered 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.
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 (loss) attributable to The AES Corporation
Transfers from noncontrolling interest:
Increase (decrease) 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
Change from net income (loss) attributable to The AES Corporation and transfers (to) from noncontrolling
interests
_____________________________
2018
$ 1,203
December 31,
2017
2016
$ (1,161) $ (1,130)
(3)
—
—
(3)
13
—
240
253
84
(84)
(2)
(2)
$ 1,200
$
(908) $ (1,132)
(1)
See Note 17—Redeemable stock of subsidiaries for further information on increase in paid-in-capital transferred to redeemable stock of subsidiaries.
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):
Foreign currency
translation adjustment, net
$
Derivative gains
(losses), net
Unfunded pension
obligations, net
Total
$
(323) $
(14)
37
23
(33)
(333) $
(64) $
78
14
19
(300) $
$
$
(286) $ (2,756)
(15)
(19)
928
248
229
913
(33)
—
(57) $ (1,876)
(278)
— $
64
7
7
(214)
19
—
(50) $ (2,071)
$
$
(2,147) $
18
643
661
—
(1,486) $
(214) $
(21)
(235) $
—
(1,721) $
Balance at December 31, 2016
Other comprehensive income (loss) before reclassifications
Amount reclassified to earnings
Other comprehensive income
$
Reclassification from NCI due to Alto Maipo Restructuring
Balance at December 31, 2017
$
Other comprehensive income (loss) before reclassifications $
Amount reclassified to earnings
Other comprehensive income (loss)
$
Cumulative effect of a change in accounting principle
Balance at December 31, 2018
$
143
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
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 Consolidated Statements of Operations:
Details About
AOCL Components
Foreign currency translation adjustments, net
Affected Line Item in the Consolidated Statements of Operations
2018
December 31,
2017
2016
Gain (loss) on disposal and sale of business interests
Net loss from disposal and impairments of discontinued operations
Net income (loss) attributable to The AES Corporation
Derivative gains (losses), net
Non-regulated revenue
Non-regulated cost of sales
Interest expense
Foreign currency transaction gains
Income from continuing operations before taxes and equity in earnings of affiliates
Income tax expense
Income (loss) from continuing operations
Less: (Income) loss from continuing operations attributable to noncontrolling
interests
Net income (loss) attributable to The AES Corporation
Amortization of defined benefit pension actuarial losses, net
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 (loss)
Less: (Income) loss from continuing operations attributable to noncontrolling
interests
Add: Loss from discontinued operations attributable to noncontrolling interests
Net income (loss) attributable to The AES Corporation
Total reclassifications for the period, net of income tax and noncontrolling interests
$
$
$
19
2
21
$
$
(188) $
(455)
(643) $
(6) $
(3)
(49)
(59)
(117)
24
(93)
15
$
25
(12)
(79)
15
(51)
1
(50)
13
$
(78) $
(37) $
—
—
(6)
(6)
2
(4)
(2)
(6)
(1)
1
(1)
—
—
—
—
(266)
(266)
—
—
(992)
(992)
111
(57)
(107)
8
(45)
8
(37)
9
(28)
—
(1)
(1)
(2)
3
1
(11)
(10)
9
—
(7) $
(64) $
18
(248) $
(928) $
—
(1)
(1,021)
$
$
Common Stock Dividends — The Parent Company paid dividends of $0.13 per outstanding share to its
common stockholders during the first, second, third and fourth quarters of 2018 for dividends declared in December
2017, February, July and October 2018, respectively.
On December 7, 2018, the Board of Directors declared a quarterly common stock dividend of $0.1365 per
share payable on February 15, 2019 to shareholders of record at the close of business on February 1, 2019.
Stock Repurchase Program — No shares were repurchased in 2018. The cumulative repurchases from the
commencement of the Program in July 2010 through December 31, 2018 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, 2018, $264 million remained available for repurchase under the Program.
The common stock repurchased has been classified as treasury stock and accounted for using the cost
method. A total of 154,905,595 and 155,924,785 shares were held as treasury stock at December 31, 2018 and
2017, 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.
15. SEGMENTS AND GEOGRAPHIC INFORMATION
The segment reporting structure uses the Company's management reporting structure as its foundation to
reflect how the Company manages the businesses internally and is mainly organized by geographic regions which
provides a socio-political-economic understanding of our business. During the first quarter of 2018, the Andes and
Brazil SBUs were merged in order to leverage scale and are now reported together as part of the South America
SBU. Further, the Puerto Rico and El Salvador businesses, formerly part of the MCAC SBU, were combined with
the US SBU, which is now reported as the US and Utilities SBU. The management reporting structure is organized
by four SBUs led by our President and Chief Executive Officer: US and Utilities, South America, MCAC, and Eurasia
SBUs. Using the accounting guidance on segment reporting, the Company determined that its four operating
segments are aligned with its four reportable segments corresponding to its SBUs. All prior period results have been
retrospectively revised to reflect the new segment reporting structure.
144
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
Corporate and Other — The results of the Fluence and Simple Energy equity affiliates are included in
"Corporate and Other". Also included are the results of the AES self-insurance company and corporate overhead
costs which are not directly associated with the operations of our four reportable segments, and 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 pre-tax income from continuing operations attributable to The AES
Corporation excluding gains or losses of the consolidated entity due to (a) unrealized gains or losses related to
derivative transactions and equity securities; (b) unrealized foreign currency gains or losses; (c) gains, losses,
benefits and costs associated with dispositions and acquisitions of business interests, including early plant closures;
(d) losses due to impairments; (e) gains, losses and costs due to the early retirement of debt; and (f) costs directly
associated with a major restructuring program, including, but not limited to, workforce reduction efforts, relocations
and office consolidation. 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. The Company has concluded Adjusted
PTC better 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 and Utilities SBU
South America SBU
MCAC SBU
Eurasia SBU
Corporate and Other
Eliminations
Total Revenue
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
2018
$ 4,230
3,533
1,728
1,255
41
(51)
$ 10,736
Total Revenue
2017
$ 4,162
3,252
1,519
1,590
35
(28)
$ 10,530
2016
$ 4,330
2,956
1,274
1,670
77
(26)
$ 10,281
Total Adjusted PTC
2017
2018
$ 2,018
39
(509)
1,548
33
51
(934)
307
180
—
$ 1,185
$
771
71
(521)
321
(3)
(59)
123
542
62
31
$ 1,017
$
$
2016
187
36
(354)
(131)
(9)
22
6
933
29
—
850
Pre-tax contribution
Unrealized derivative losses (gains)
Unrealized foreign currency losses (gains)
Disposition/acquisition losses (gains)
Impairment expense
Loss on extinguishment of debt
Restructuring costs
Total Adjusted PTC
Year Ended December 31,
US and Utilities SBU
South America SBU
MCAC SBU
Eurasia SBU
Corporate, Other and Eliminations
Total Adjusted PTC
Total Adjusted PTC
2017
2016
2018
$
511
519
300
222
(367)
$ 1,185
$
424
446
277
290
(420)
$ 1,017
$
$
392
428
222
283
(475)
850
145
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
Year Ended December 31,
US and Utilities SBU
South America SBU
MCAC SBU
Eurasia SBU
Discontinued operations
Corporate, Other and Eliminations
Total
Year Ended December 31,
US and Utilities SBU
South America SBU
MCAC SBU
Eurasia SBU
Corporate, Other and Eliminations
Total
Year Ended December 31,
US and Utilities SBU
South America SBU
MCAC SBU
Eurasia SBU
Corporate, Other and Eliminations
Total
2018
$ 12,286
10,941
4,462
4,538
—
294
$ 32,521
Total Assets
2017
$ 11,548
11,126
4,087
6,002
86
263
$ 33,112
2016
$ 10,815
10,487
3,680
5,777
4,936
429
$ 36,124
Depreciation and Amortization
2016
2017
2018
$
449
300
141
99
—
14
$ 1,003
$
487
301
122
127
123
9
$ 1,169
$
519
251
117
149
128
12
$ 1,176
2018
$ 1,373
662
302
51
—
8
$ 2,396
Capital Expenditures
2017
2016
$
905
477
435
211
315
13
$ 2,356
$
858
569
431
279
303
18
$ 2,458
Interest Income
2017
2018
2016
2018
Interest Expense
2017
2016
$
$
10
92
20
186
2
310
$
$
5
95
13
130
1
244
$
$
4
95
7
139
—
245
$
287
283
124
145
217
$ 1,056
$
315
297
111
167
280
$ 1,170
$
299
247
100
179
309
$ 1,134
Investments in and Advances to Affiliates
2017
2018
2016
Net Equity in Earnings of Affiliates
2017
2016
2018
$
538
213
5
293
65
$ 1,114
$
535
358
(5)
307
2
$ 1,197
$
$
23
363
(1)
236
—
621
$
$
35
15
(7)
14
(18)
39
$
$
41
28
(4)
9
(3)
71
$
$
9
15
(2)
13
1
36
The following table presents information, by country, about the Company's consolidated operations for each of
the three years ended December 31, 2018, 2017, and 2016, and as of December 31, 2018 and 2017 (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 (1)
Non-U.S.:
Chile
Dominican Republic
El Salvador
Brazil
Argentina
Panama
Colombia
Bulgaria
Mexico
United Kingdom
Vietnam (2)
Jordan
Philippines (3)
Kazakhstan
Other Non-U.S.
Total Non-U.S.
Total
_____________________________
Total Revenue
Property, Plant & Equipment, net
2018
2017
2016
2018
2017
$
3,462
$
3,487
$
3,790
$
8,731
$
7,968
2,087
884
768
527
487
438
428
426
399
390
245
95
93
—
7
7,274
$ 10,736
1,944
826
686
541
435
338
332
367
352
328
278
95
449
67
5
7,043
$ 10,530
1,707
614
601
450
359
312
437
334
342
337
340
136
401
103
18
6,491
$ 10,281
$
5,453
903
334
1,287
234
1,777
302
1,183
666
90
2
418
—
—
16
12,665
21,396
$
5,066
935
340
1,286
223
1,615
332
1,290
687
108
2
431
—
—
13
12,328
20,296
(1)
(2)
(3)
Includes Puerto Rico revenues of $257 million, $247 million and $301 million for the years ended December 31, 2018, 2017 and 2016, respectively, and
property, plant & equipment of $553 million and $565 million as of December 31, 2018 and 2017, respectively.
The Mong Duong II power project is operated under a build, operate and transfer contract. Future expected payments for the construction performance
obligation are recognized in Loan receivable on the Consolidated Balance Sheets. See Note 18—Revenue for further information.
The Masinloc property, plant and equipment was classified as held-for-sale as of December 31, 2017, and deconsolidated upon completion of the sale in
March 2018. See Note 23—Held-For-Sale and Dispositions for further information.
146
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
16. SHARE-BASED COMPENSATION
RESTRICTED STOCK
Restricted Stock Units — The Company issues 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. In all circumstances, RSUs granted by AES
do not entitle the holder the right, or obligate AES, to settle the RSU in cash or other assets of AES.
For the years ended December 31, 2018, 2017, and 2016, 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,
2018, 2017, and 2016 had grant date fair values per RSU of $10.55, $11.93 and $9.42, 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
_____________________________
2018
2017
2016
$
$
$
$
11
(2)
9
10
16
$
$
$
$
17
(4)
13
10
15
$
$
$
$
14
(4)
10
7
13
(1)
Amount represents fair market value on the date of conversion.
Cash was not used to settle RSUs or compensation cost capitalized as part of the cost of an asset for the
years ended December 31, 2018, 2017, and 2016. As of December 31, 2018, total unrecognized compensation cost
related to RSUs of $10 million is expected to be recognized over a weighted average period of approximately 1.7
years. There were no modifications to RSU awards during the year ended December 31, 2018.
A summary of the activity of RSUs for the year ended December 31, 2018 follows (RSUs in thousands):
Nonvested at December 31, 2017
Vested
Forfeited and expired
Granted
Nonvested at December 31, 2018
Vested and expected to vest at December 31, 2018
RSUs
2,966
(1,428)
(528)
913
1,923
Weighted Average
Grant Date Fair Values
11.02
$
11.05
10.95
10.55
10.80
$
1,782
$
10.79
Weighted Average
Remaining Vesting Term
1.4
The Company initially recognizes compensation cost on the estimated number of instruments for which the
requisite service is expected to be rendered. In 2018, AES has estimated a weighted average forfeiture rate of
9.35% for RSUs granted in 2018. 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 $9 million on a straight-line basis over a three-year period.
The following table summarizes the RSUs that vested and were converted during the periods indicated (RSUs
in thousands):
Year Ended December 31,
RSUs vested during the year
RSUs converted during the year, net of shares withheld for taxes
Shares withheld for taxes
OTHER SHARE BASED COMPENSATION
2018
2017
2016
1,428
950
478
1,337
865
472
1,063
705
358
The Company has three other share-based award programs. The Company has recorded expenses of $20
million, $8 million and $10 million for 2018, 2017 and 2016, respectively, related to these programs.
Stock options — AES grants options to purchase shares of common stock under stock option plans to 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 issued in 2017 and 2018 have a three-year vesting schedule and vest in one-third increments over the
147
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
three-year period. The stock options have a contractual term of 10 years. 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.
Performance Stock Units — In 2016, 2017 and 2018, the Company issued PSUs to officers under its long-
term compensation plan. PSUs are stock units which include performance conditions. Performance conditions are
based on the Company's Proportional Free Cash Flow targets for 2016, 2017 and 2018. The 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. The Company believes that it is 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 stock units in
cash or other assets of AES.
Performance Cash Units — In 2016, 2017 and 2018, the Company issued PCUs to its officers under its long-
term compensation plan. The value of these units is dependent on the market condition of 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.
Since PCUs are settled in cash, they qualify for liability accounting and periodic measurement is required.
17. 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
Contributions from holders of redeemable stock of subsidiaries
Net income (loss) attributable to redeemable stock of subsidiaries
Fair value adjustment
Other comprehensive income (loss) attributable to redeemable stock of subsidiaries
Acquisition and reclassification of stock of subsidiaries
Balance at the end of the period
2018
2017
$
$
837
34
2
4
2
—
879
$
$
782
50
(14)
25
(2)
(4)
837
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
Total redeemable stock of subsidiaries
_____________________________
(1)
Characteristics of quotas are similar to common stock.
2018
2017
$
$
618
201
60
879
$
$
618
159
60
837
Colon — Our partner in Colon made capital contributions of $34 million and $50 million during the year ended
December 31, 2018 and 2017, respectively. 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, 2018 and 2017, which
represent five series of preferred stock. The total annual dividend requirements were approximately $3 million at
December 31, 2018 and 2017. 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.
IPALCO — As part of a purchase agreement executed in 2014, CDPQ had an option to invest $349 million in
IPALCO through 2016 in exchange for a 17.65% equity stake. In March 2016, CDPQ exercised the remaining option
by investing $134 million in IPALCO, which resulted in CDPQ's combined direct and indirect interest in IPALCO of
30%. The Company 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
148
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
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.
18. REVENUE
The following table presents our revenue from contracts with customers and other revenue for the year ended
December 31, 2018 (in millions):
Regulated Revenue
Revenue from contracts with customers
Other regulated revenue
Total regulated revenue
Non-Regulated Revenue
Revenue from contracts with customers
Other non-regulated revenue (1)
Total non-regulated revenue
Total revenue
_____________________________
Year Ended December 31, 2018
US and
Utilities SBU
South
America SBU
MCAC SBU
Eurasia SBU
Corporate,
Other and
Eliminations
Total
$
$
$
$
$
2,885
54
2,939
972
319
1,291
4,230
$
$
$
$
$
— $
—
— $
3,529
4
3,533
3,533
$
$
$
— $
—
— $
1,642
86
1,728
1,728
$
$
$
— $
—
— $
943
312
1,255
1,255
$
$
$
— $
—
— $
(11) $
1
(10) $
(10) $
2,885
54
2,939
7,075
722
7,797
10,736
(1)
Other non-regulated revenue primarily includes lease and derivative revenue not accounted for under ASC 606.
Contract Balances — The timing of revenue recognition, billings, and cash collections results in accounts
receivable and contract liabilities. Accounts receivable represent unconditional rights to consideration and consist of
both billed amounts and unbilled amounts typically resulting from sales under long-term contracts when revenue
recognized exceeds the amount billed to the customer. We bill both generation and utilities customers on a
contractually agreed-upon schedule, typically at periodic intervals (e.g., monthly). 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.
Our contract liabilities consist of deferred revenue which is classified as current or noncurrent based on the
timing of when we expect to recognize revenue. The current portion of our contract liabilities is reported in Accrued
and other liabilities and the noncurrent portion is reported in Other noncurrent liabilities on the Consolidated
Balance Sheets. The contract liabilities from contracts with customers were $109 million and $131 million as of
December 31, 2018 and January 1, 2018, respectively.
Of the $131 million of contract liabilities reported at January 1, 2018, $36 million was recognized as revenue
during the period ended December 31, 2018.
A significant financing arrangement exists for our Mong Duong plant in Vietnam. The plant was constructed
under a build, operate, and transfer contract and will be transferred to the Vietnamese government after the
completion of a 25 year PPA. The performance obligation to construct the facility was substantially completed in
2015. Approximately $1.4 billion of contract consideration related to the construction, but not yet collected through
the 25 year PPA, was reflected as a loan receivable as of December 31, 2018.
Remaining Performance Obligations — The transaction price allocated to remaining performance obligations
represents future consideration for unsatisfied (or partially unsatisfied) performance obligations at the end of the
reporting period. As of December 31, 2018, the aggregate amount of transaction price allocated to remaining
performance obligations was $15 million, primarily consisting of fixed consideration for the sale of renewable energy
credits (RECs) in long-term contracts in the U.S. We expect to recognize revenue on approximately one-fifth of the
remaining performance obligations in 2019, with the remainder recognized thereafter. The Company has elected to
apply the optional disclosure exemptions under ASC 606. Therefore, the amount above excludes contracts with an
original length of one year or less, contracts for which we recognize revenue based on the amount we have the right
to invoice for services performed, and variable consideration allocated entirely to a wholly unsatisfied performance
obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts
the amount to which we expect to be entitled. As such, consideration for energy is excluded from the amounts
above as the variable consideration relates to the amount of energy delivered and reflects the value the Company
expects to receive for the energy transferred. Estimates of revenue expected to be recognized in future periods also
exclude unexercised customer options to purchase additional goods or services that do not represent material rights
to the customer.
149
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
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):
Year Ended December 31,
Gain on remeasurement of contingent consideration (1)
Allowance for funds used during construction (US Utilities)
Gain on sale of assets
Legal settlements (2)
Other
Total other income
_____________________________
2018
2017
2016
32
8
4
—
28
72
$
$
— $
26
1
60
33
120
$
—
29
4
—
31
64
$
$
(1)
(2)
Related to the amendment of the Oahu purchase agreement. See Note 24 —Acquisitions for further information.
In December 2016, the Company and YPF entered into a settlement in which all parties agreed to give up any and all legal action related to gas supply
contracts that were terminated in 2008 and have been in dispute since 2009. In January 2017, the YPF board approved the agreement and paid the Company
$60 million, thereby resolving all uncertainties around the dispute.
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):
Year Ended December 31,
Loss on sale and disposal of assets (1)
Non-service pension and other postretirement costs
Allowance for other receivables (2)
Water rights write-off
Other
Total other expense
_____________________________
2018
2017
2016
30
10
7
—
11
58
$
$
28
1
—
19
10
58
$
$
12
3
52
6
7
80
$
$
(1)
(2)
In September 2018, the Company recorded a $20 million loss due to damage associated with a lightning incident at the Andres facility in the Dominican
Republic.
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 was related to certain reimbursements the Company was expecting in connection with a legal matter.
20. ASSET IMPAIRMENT EXPENSE
Year ended December 31, (in millions)
2018
2017
2016
Shady Point
Nejapa
DPL
Laurel Mountain
Kazakhstan Hydroelectric
Kazakhstan CHPs
Kilroot
Buffalo Gap II
Buffalo Gap I
Other
Total
$
$
157
37
—
—
—
—
—
—
—
14
208
$
$
— $
—
175
121
92
94
37
—
—
18
537
$
—
—
859
—
—
—
—
159
77
1
1,096
Shady Point — In December 2018, the Company entered into an agreement to sell Shady Point, a coal-fired
generation facility in the U.S. Due first to the uncertainty around future cash flows, and then upon meeting the held-
for-sale criteria, the Company performed an impairment analysis of the Shady Point asset group in the second, third
and fourth quarter of 2018, resulting in the recognition of total asset impairment expense of $157 million for the year
ended December 31, 2018. Using the market approach, the asset group was determined to have a fair value of $30
million as of December 31, 2018. The sale is subject to regulatory approval and is expected to close during the
second half of 2019. See Note 23—Held-for-Sale and Dispositions for further information. Shady Point is reported in
the US and Utilities SBU reportable segment.
Nejapa — During the fourth quarter of 2018, the Company tested the recoverability of its long-lived assets at
Nejapa, a landfill gas plant in El Salvador. Decreased production as a result of the landfill owner´s failure to perform
improvements necessary to continue extracting gas from the landfill was identified as an impairment indicator. The
Company determined that the carrying amount was not recoverable. The asset group, consisting of property, plant,
150
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
and equipment and intangible assets, was determined to have a fair value of $5 million using the income approach.
As a result, the Company recognized an asset impairment expense of $37 million as of December 31, 2018. Nejapa
is reported in the US and Utilities SBU reportable segment.
DPL — In March 2017, the Board of Directors of DPL approved the retirement of the DPL operated and co-
owned Stuart coal-fired and diesel-fired generating units, and the Killen coal-fired generating unit and combustion
turbine on or before June 1, 2018. The Company performed an impairment analysis and determined that the
carrying amounts of the facilities were not recoverable. The Stuart and Killen asset groups were determined to have
fair values of $3 million and $8 million, respectively, using the income approach. As a result, the Company
recognized total asset impairment expense of $66 million. The Stuart and Killen units were retired in May 2018.
Prior to their retirement, Stuart and Killen were reported in the US and Utilities SBU reportable segment.
In December 2017, DPL entered into an agreement for the sale of six of its combustion turbine and diesel-fired
generation facilities and related assets ("DPL peaker assets"). Upon meeting the held-for-sale criteria, the Company
performed an impairment analysis and determined that the carrying value of the asset group of $346 million was
greater than its fair value less costs to sell of $237 million. As a result, the Company recognized asset impairment
expense of $109 million. DPL completed the sale of the peaker assets in March 2018. Prior to their sale, the DPL
peaker assets were reported in the US and Utilities SBU reportable segment. See Note 23—Held-for-Sale and
Dispositions for further information.
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 an 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 total asset impairment
expense of $235 million. DPL is reported in the US and Utilities 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. Uncertainty around the useful life of Stuart and Killen related to the
Company’s ESP proceedings and lower forward dark spreads and capacity prices were collectively determined to
be an impairment indicator for these assets. Market information indicating 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 the second quarter of
2016, were collectively determined to be impairment indicators for this asset. The Company performed an
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 fair values 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 total asset impairment expense of $624 million. DPL is reported
in the US and Utilities SBU reportable segment.
Laurel Mountain — During the fourth quarter of 2017, the Company tested the recoverability of its long-lived
assets at Laurel Mountain, a wind farm in the U.S. Impairment indicators were identified based on a decline in
forward pricing. The Company determined that the carrying amount was not recoverable. The Laurel Mountain
asset group was determined to have a fair value of $33 million using the income approach. As a result, the
Company recognized an asset impairment expense of $121 million. Laurel Mountain is reported in the US and
Utilities SBU reportable segment.
Kilroot — During the fourth quarter of 2017, the Company tested the recoverability of its long-lived assets at
Kilroot, a coal and oil-fired plant in Northern Ireland, as Kilroot was not successful in bidding its coal units into the
December 2017 capacity auction for the newly implemented I-SEM 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 $20 million using the income approach. As a result, the Company recognized an asset impairment expense
151
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
of $37 million, which was limited to the carrying value of the coal units. Kilroot is reported in the Eurasia SBU
reportable segment.
Kazakhstan Hydroelectric — In April 2017, the Republic of Kazakhstan stated the concession agreements
would not be extended for Shulbinsk HPP and Ust-Kamenogorsk HPP, two hydroelectric plants in Kazakhstan, and
initiated the process to transfer these plants back to the government. Upon meeting the held-for-sale criteria in the
second quarter of 2017, the Company performed an impairment analysis and determined the carrying value of the
asset group of $190 million, which included cumulative translation losses of $100 million, was greater than its fair
value less costs to sell of $92 million. As a result, the Company recognized asset impairment expense of $92 million
limited to the carrying value of the long-lived assets. The Company completed the transfer of the plants in October
2017. Prior to their transfer, the Kazakhstan hydroelectric plants were reported in the Eurasia SBU reportable
segment. See Note 23—Held-for-Sale and Dispositions for further information.
Kazakhstan CHPs — 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. Upon meeting
the held-for-sale criteria in the first quarter of 2017, the Company performed an impairment analysis and determined
that the carrying value of the asset group of $171 million, which included cumulative translation losses of $92
million, was greater than its fair value less costs to sell of $29 million. As a result, the Company recognized asset
impairment expense of $94 million limited to the carrying value of the long-lived assets. The Company completed
the sale of its interest in the Kazakhstan CHP plants in April 2017. Prior to their sale, the plants were reported in the
Eurasia SBU reportable segment. See Note 23—Held-for-Sale and Dispositions for further information.
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 asset impairment
expense of $77 million ($23 million attributable to AES). Buffalo Gap I is reported in the US and Utilities 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 asset impairment expense of $159
million ($49 million attributable to AES). Buffalo Gap II is reported in the US and Utilities SBU reportable segment.
21. INCOME TAXES
U.S. Tax Reform — In 2017, the U.S. enacted the Tax Cuts and Jobs Act (the “TCJA”). The TCJA
significantly changed U.S. corporate income tax law. Among other changes effective in 2017, the TCJA
required companies to pay a one-time tax on certain unrepatriated earnings of foreign subsidiaries. Many other
changes took effect in 2018, including a limit on the deductibility of interest expense and a new regime for
taxing certain earnings of foreign subsidiaries.
The Company recognized the income tax effects of the TCJA in accordance with Staff Accounting Bulletin
No. 118 (“SAB 118”) which provides SEC guidance on the application of ASC 740, Income Taxes, in the
reporting period in which the TCJA was signed into law. Accordingly, the Company’s 2017 financial statements
reflected provisional amounts for those impacts for which the accounting under ASC 740 was incomplete, but a
reasonable estimate could be determined. As of December 31, 2018, the Company's accounting for the initial
impacts of the TCJA are complete under SAB 118.
For the year ended December 31, 2018 the Company increased its estimate of the one-time transition tax
by $194 million to $869 million. The estimated tax expense recognized for the year ended December 31, 2017
relating to the remeasurement of deferred tax assets and liabilities from an income tax rate of 35% to 21%,
decreased $77 million, resulting in a total remeasurement benefit of $38 million.
Argentine Tax Reform — In December 2017, the Argentine government enacted reforms to its income tax
laws that resulted in a decrease to statutory income tax rates for our Argentine businesses from 35% to 30% in
2018-2019 and to 25% for 2020 and future years. The impact of remeasuring deferred taxes to account for the
enacted change in future applicable income tax rates was recognized as income tax benefit in the fourth quarter
152
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
of 2017, resulting in a decrease of $21 million to consolidated income tax expense.
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 a discrete income tax expense in the first
quarter of 2016, resulting in an increase of $26 million to consolidated income tax expense.
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
2018
2017
2016
$
$
7
186
2
5
378
130
708
$
$
— $
545
—
1
335
109
990
$
2
(361)
1
(4)
318
76
32
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
Other—net
Effective tax rate
2018
2017
2016
21 %
2 %
9 %
(2)%
— %
— %
6 %
(1)%
35 %
35 %
(7)%
— %
10 %
— %
— %
90 %
— %
128 %
35 %
(18)%
(46)%
10 %
4 %
31 %
12 %
(11)%
17 %
For 2018, the 6% change in tax law item relates primarily to changes in estimate under SAB 118 of the impacts
of adoption of the TCJA. The Company recognized tax expense of $194 million related to revised estimates of the
one-time transition tax in accordance with proposed regulations issued by the U.S. Treasury in 2018. The
adjustment was due in large part to the approach the proposed regulations adopted to determine the fair value of
our interests in publicly traded subsidiaries. The Company also recognized tax benefit of $77 million related to
revised estimates of deferred tax remeasurement. Included in the 9% taxes on foreign earnings item is $124 million
of U.S. GILTI tax expense related to foreign subsidiaries, including the sale of our interest in Masinloc.
For 2017, the 90% change in tax law item relates primarily to the impact of U.S. and Argentina tax reform. The
impact of the U.S one-time transition tax and remeasurement of deferred taxes represents 88% and 5%,
respectively, which is partially offset by the tax benefit resulting from Argentina tax reform representing 3%.
For 2016, the 31% Buffalo Gap impairments item relates to the amounts of impairment allocated to
noncontrolling interest which is nondeductible.
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
Income taxes receivable—noncurrent
Total income taxes receivable
Income taxes payable—current
Income taxes payable—noncurrent
Total income taxes payable
153
2018
2017
$
$
$
$
163
8
171
210
7
217
$
$
$
$
147
—
147
129
17
146
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
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, 2018, the Company had federal net operating loss carryforwards for tax return purposes
of approximately $1.1 billion expiring in years 2033 to 2036. The Company also had federal general business tax
credit carryforwards of approximately $22 million expiring primarily from 2021 to 2038, and federal alternative
minimum tax credits of approximately $15 million that may be fully recovered by 2021 under the TCJA. Additionally,
the Company had state net operating loss carryforwards as of December 31, 2018 of approximately $8.5 billion
expiring in years 2019 to 2038. As of December 31, 2018, the Company had foreign net operating loss
carryforwards of approximately $2.4 billion that expire at various times beginning in 2019 and some of which carry
forward without expiration, and tax credits available in foreign jurisdictions of approximately $14 million, $13 million
of which expire in 2021 and $1 million of which expire in years 2024 to 2029.
Valuation allowances decreased $120 million during 2018 to $868 million at December 31, 2018. This net
decrease was primarily the result of valuation allowance activity at certain of our Brazil subsidiaries and U.S. states.
Valuation allowances increased $112 million during 2017 to $988 million at December 31, 2017. This net
increase was primarily the result of valuation allowance activity at certain of our Brazil 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 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
Tax credit carryforwards
Other deductible temporary differences
Total gross deferred tax asset
Less: valuation allowance
Total net deferred tax asset
Net deferred tax (liability)
2018
2017
$
$
(1,418) $
(243)
(1,661)
1,066
52
62
55
111
1,346
(868)
478
(1,183) $
(1,424)
(143)
(1,567)
1,439
63
66
51
60
1,679
(988)
691
(876)
The Company considers undistributed earnings of certain foreign subsidiaries to be indefinitely reinvested
outside of the U.S. Except for the one-time transition tax in the U.S., no taxes have been recorded with respect to
our indefinitely reinvested 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 foreign withholding and state
income taxes. Under the TCJA, future distributions from foreign subsidiaries will generally be subject to a federal
dividends received deduction in the U.S. As of December 31, 2018, the cumulative amount of U.S. GAAP foreign
un-remitted earnings upon which additional 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 $35 million, $26 million and $20 million for the years ended
December 31, 2018, 2017 and 2016, respectively. The per share effect of these benefits after noncontrolling
interests was $0.04, $0.03 and $0.02 for the years ended December 31, 2018, 2017 and 2016, respectively.
Included in the Company's income tax benefits is the benefit related to our operations in Vietnam, which is
estimated to be $19 million, $13 million and $15 million for the years ended December 31, 2018, 2017 and 2016,
respectively. The per share effect of these benefits related to our operations in Vietnam after noncontrolling interest
was $0.01, $0.01 and $0.01 for the years ended December 31, 2018, 2017 and 2016, respectively.
154
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
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
2018
2017
2016
$
$
(218) $
2,236
2,018
$
(511) $
1,282
771
$
(1,305)
1,492
187
Uncertain Tax Positions — Uncertain tax positions have been classified as noncurrent income tax liabilities
unless they are 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. The following table shows the total amount of gross accrued income taxes
related to interest and penalties included in the Consolidated Balance Sheets for the periods indicated (in millions):
December 31,
Interest related
Penalties related
2018
2017
$
$
4
—
7
—
The following table shows the expense/(benefit) related to interest and penalties on unrecognized tax benefits
for the periods indicated (in millions):
December 31,
Total expense (benefit) for interest related to unrecognized tax benefits
Total expense for penalties related to unrecognized tax benefits
2018
2017
2016
$
(3) $
—
$
1
—
2
—
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
Panama
United Kingdom
United States (Federal)
Tax Years Subject to Examination
2012-2018
2013-2018
2015-2018
2016-2018
2016-2018
2016-2018
2014-2018
2015-2018
2012-2018
2015-2018
As of December 31, 2018, 2017 and 2016, the total amount of unrecognized tax benefits was $463 million,
$348 million and $352 million, respectively. The total amount of unrecognized tax benefits that would benefit the
effective tax rate as of December 31, 2018, 2017 and 2016 is $446 million, $332 million and $332 million,
respectively, of which $33 million, $29 million and $24 million, respectively, would be in the form of tax attributes that
would warrant a full valuation allowance. Further, the total amount of unrecognized tax benefit that would benefit the
effective tax rate as of 2018 would be reduced by approximately $161 million of tax expense related to
remeasurement from 35% to 21%.
The total amount of unrecognized tax benefits anticipated to result in a net decrease to unrecognized tax
benefits within 12 months of December 31, 2018 is estimated to be between $0 million and $10 million, primarily
relating to statute of limitation lapses and tax exam settlements.
155
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the
periods indicated (in millions):
Balance at January 1
Additions for current year tax positions
Additions for tax positions of prior years
Reductions for tax positions of prior years
Settlements
Lapse of statute of limitations
Balance at December 31
2018
2017
2016
$
$
348
2
146
(26)
—
(7)
463
$
$
352
—
2
(5)
—
(1)
348
$
$
364
2
1
(1)
(13)
(1)
352
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, 2018.
Our effective tax rate and net income in any given future period could therefore be materially impacted.
22. DISCONTINUED OPERATIONS
Due to a portfolio evaluation in the first half of 2016, management decided to pursue a strategic shift of its
distribution companies in Brazil, Sul and Eletropaulo, to reduce the Company's exposure to the Brazilian distribution
market. The disposals of Sul and Eletropaulo were completed in October 2016 and June 2018, respectively.
Eletropaulo — In November 2017, Eletropaulo converted its preferred shares into ordinary shares and
transitioned the listing of those shares to the Novo Mercado, which is a listing segment of the Brazilian stock
exchange with the highest standards of corporate governance. Upon conversion of the preferred shares into
ordinary shares, AES no longer controlled Eletropaulo, but maintained significant influence over the business. As a
result, the Company deconsolidated Eletropaulo. After deconsolidation, the Company's 17% ownership interest was
reflected as an equity method investment. The Company recorded an after-tax loss on deconsolidation of $611
million, which primarily consisted of $455 million related to cumulative translation losses and $243 million related to
pension losses reclassified from AOCL.
In December 2017, all the remaining criteria were met for Eletropaulo to qualify as a discontinued operation.
Therefore, its results of operations and financial position were reported as such in the consolidated financial
statements for all periods presented.
In June 2018, the Company completed the sale of its entire 17% ownership interest in Eletropaulo through a
bidding process hosted by the Brazilian securities regulator, CVM. Gross proceeds of $340 million were received at
our subsidiary in Brazil, subject to the payment of taxes. Upon disposal of Eletropaulo, the Company recorded a
pre-tax gain on sale of $243 million (after-tax $199 million).
Excluding the gain on sale, Eletropaulo's pre-tax loss attributable to AES was immaterial for the year ended
December 31, 2018. Eletropaulo's pre-tax loss attributable to AES, including the loss on deconsolidation, for the
years ended December 31, 2017 and 2016 was $633 million and $192 million, respectively. Prior to its classification
as discontinued operations, Eletropaulo was reported in the South America SBU reportable segment.
Sul — The Company executed an agreement for the sale of Sul, a wholly-owned subsidiary, in June 2016. The
results of operations and financial position of Sul are reported 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 pre-tax 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 Sul. Prior to the impairment charge, the carrying value of the 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 Sul disposal group.
156
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
On October 31, 2016, the Company completed the sale of Sul and received final proceeds less costs to sell of
$484 million, excluding contingent consideration. Upon disposal of Sul, the Company 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 pre-tax loss attributable to AES for the year ended December 31, 2016 was $1.4 billion. Prior to its
classification as discontinued operations, Sul was reported in the South America SBU reportable segment.
Borsod — In 2011, Borsod, which held two coal and biomass-fired generation plants in Hungary, filed for
liquidation and was deconsolidated with its historical operating results reflected in discontinued operations under
prior accounting guidance. In October 2018, the liquidation was completed and the Company recognized a deferred
gain of $26 million, primarily comprised of a $20 million write-off of cumulative translation balances. Prior to its
liquidation, Borsod was reported in the Eurasia SBU reportable segment.
The following table summarizes the carrying amounts of the major classes of assets and liabilities of
discontinued operations at December 31, 2017:
(in millions)
Assets of discontinued operations and held-for-sale businesses:
Investments in and advances to affiliates (1)
Total assets of discontinued operations
Other assets of businesses classified as held-for-sale (2)
Total assets of discontinued operations and held-for-sale businesses
Liabilities of discontinued operations and held-for-sale businesses:
Other liabilities of businesses classified as held-for-sale (2)
Total liabilities of discontinued operations and held-for-sale businesses
_____________________________
December 31, 2017
$
$
$
86
86
1,948
2,034
1,033
1,033
Represents the Company's 17% ownership interest in Eletropaulo.
(1)
(2) Masinloc, Eletrica Santiago, and the DPL peaker assets were classified as held-for-sale as of December 31, 2017. See Note 23—Held-for-Sale and
Dispositions for further information.
Excluding the gain on sale of Eletropaulo and deferred gain on liquidation of Borsod, income from discontinued
operations and cash flows from operating and investing activities of discontinued operations were immaterial for the
year ended December 31, 2018.
The following table summarizes the major line items constituting 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 (1)
Income (loss) from operations of discontinued businesses
Loss from disposal and impairments of discontinued businesses
Income (loss) from discontinued operations
Less: Net income attributable to noncontrolling interests
Income (loss) from discontinued operations attributable to The AES Corporation
Income tax benefit (expense)
Loss from discontinued operations, net of tax
_____________________________
(1)
Includes a loss contingency recognized by our equity method investment in discontinued operations.
2017
2016
$
$
$
3,320
(3,151)
(166)
3
(611)
(608)
(25)
(633)
(21)
(654) $
4,036
(3,954)
(160)
(78)
(1,385)
(1,463)
(142)
(1,605)
495
(1,110)
The following table summarizes the operating and investing cash flows from discontinued operations for the
periods indicated (in millions):
December 31,
Cash flows provided by operating activities of discontinued operations
Cash flows used in investing activities of discontinued operations
2017
2016
$
$
164
(288)
529
(368)
23. HELD-FOR-SALE AND DISPOSITIONS
Held-for-Sale
157
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
Shady Point — In December 2018, the Company entered into an agreement to sell Shady Point, a U.S. coal-
fired generating facility, for $30 million, subject to customary purchase price adjustments. The sale is subject to
regulatory approval and is expected to close during the second half of 2019. As of December 31, 2018, Shady Point
was classified as held-for-sale, but did not meet the criteria to be reported as discontinued operations. Shady
Point's carrying value as of December 31, 2018 was $30 million. Excluding impairment charges, pre-tax income
attributable to AES was $19 million in each of the years ended December 31, 2018, 2017 and 2016. Shady Point is
reported in the US and Utilities SBU reportable segment. See Note 20—Asset Impairment Expense for further
information.
Redondo Beach — In October 2018, the Company entered into an agreement to sell land held by AES
Redondo Beach, a gas-fired generating facility in California. The sale is expected to close during the first half of
2019. As of December 31, 2018, the $24 million carrying value of the land held by Redondo Beach was classified as
held-for-sale. Redondo Beach is reported in the US and Utilities SBU reportable segment.
Dispositions
CTNG — In December 2018, AES Gener completed the sale of CTNG, an entity that holds transmission lines
in Chile, for $225 million, subject to customary post-closing adjustments, resulting in a pre-tax gain on sale of $129
million. The sale did not meet the criteria to be reported as discontinued operations. Prior to its sale, CTNG was
reported in the South America SBU reportable segment.
Electrica Santiago — In May 2018, AES Gener completed the sale of Electrica Santiago for total consideration
of $287 million, resulting in a pre-tax gain on sale of $69 million after post-closing adjustments. Electrica Santiago
consisted of four gas and diesel-fired generation plants in Chile. The sale did not meet the criteria to be reported as
discontinued operations. Prior to its sale, Electrica Santiago was reported in the South America SBU reportable
segment.
Stuart and Killen — In May 2018, DPL retired the co-owned Stuart coal-fired and diesel-fired generating units,
and the Killen coal-fired generating unit and combustion turbine. Prior to their retirement, Stuart and Killen were
reported in the US and Utilities SBU reportable segment. See Note 20—Asset Impairment Expense for further
information.
Masinloc — In March 2018, the Company completed the sale of its entire 51% equity interest in Masinloc for
cash proceeds of $1.05 billion, resulting in a pre-tax gain on sale of $772 million after post-closing adjustments,
subject to U.S. income tax. Masinloc consisted of a coal-fired generation plant in operation, a coal-fired generation
plant under construction and an energy storage facility all located in the Philippines. The sale did not meet the
criteria to be reported as discontinued operations. Prior to its sale, Masinloc was reported in the Eurasia SBU
reportable segment.
In 2014, the Company completed the sale of 45% of its ownership interest in Masinloc for $436 million,
including $23 million of consideration that was contingent upon the achievement of certain tax restructuring
efficiencies. In December 2017, the related contingency expired and the $23 million of contingent consideration was
recognized as a gain in Gain (loss) on disposal and sale of business interests in the Consolidated Statement of
Operations.
DPL peaker assets — In March 2018, DPL completed the sale of six of its combustion turbine and diesel-fired
generation facilities and related assets ("DPL peaker assets") for total proceeds of $239 million, inclusive of
estimated working capital and subject to customary post-closing adjustments, resulting in a loss on sale of $2
million. The sale did not meet the criteria to be reported as discontinued operations. Prior to their sale, the DPL
peaker assets were reported in the US and Utilities SBU reportable segment.
Beckjord facility — In February 2018, DPL transferred its interest in Beckjord, a coal-fired generation facility
retired in 2014, including its obligations to remediate the facility and its site. The transfer resulted in cash
expenditures of $15 million, inclusive of disposal charges, and a loss on disposal of $12 million. Prior to the transfer,
Beckjord was reported in the US and Utilities SBU reportable segment.
Advancion Energy Storage — In January 2018, the Company deconsolidated the AES Advancion energy
storage development business and contributed it to the Fluence joint venture, resulting in a gain on sale of $23
million. See Note 7—Investments in and Advances to Affiliates for further discussion. Prior to the transfer, the AES
Advancion energy storage development business was reported as part of Corporate and Other.
158
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
Zimmer and Miami Fort — In December 2017, DPL and AES Ohio Generation completed the sale of Zimmer
and Miami Fort, two coal-fired generating plants, for net proceeds of $70 million, resulting in a gain on sale of $13
million. The sale did not meet the criteria to be reported as discontinued operations. Prior to their sale, Zimmer and
Miami Fort were reported in the US and Utilities SBU reportable segment.
Kazakhstan Hydroelectric — Affiliates of the Company (the “Affiliates”) previously operated Shulbinsk HPP and
Ust-Kamenogorsk HPP (the “HPPs”), two hydroelectric plants in Kazakhstan, under a concession agreement with
the Republic of Kazakhstan (“RoK”). In April 2017, the RoK initiated the process to transfer these plants back to the
RoK. The RoK indicated that arbitration would be necessary to determine the correct Return Share Transfer
Payment ("RST") and, rather than paying the Affiliates, deposited the RST into an escrow account. In exchange, the
Affiliates transferred 100% of the shares in the HPPs to the RoK, under protest and with a full reservation of rights.
The Company recorded a loss on disposal of $33 million in the fourth quarter of 2017. In February 2018, the
Affiliates initiated the arbitration process in international court to recover at least $75 million of the RST placed in
escrow, based on the September 30, 2017 RST calculation. As of December 31, 2018, the arbitration proceedings
are ongoing, and additional losses are not considered probable at this time. However, additional losses may be
incurred if some or all of the disputed consideration is not paid by the RoK via a mutually acceptable settlement, or
upon any unfavorable decision rendered by the arbiter. The transfer did not meet the criteria to be reported as
discontinued operations. Prior to their transfer, the Kazakhstan HPPs were reported in the Eurasia SBU reportable
segment. See Note 20—Asset Impairment Expense for further information.
Kazakhstan CHPs — In April 2017, the Company completed the sale of Ust-Kamenogorsk CHP and Sogrinsk
CHP, its combined heating and power coal plants in Kazakhstan, for net proceeds of $24 million. The Company
recognized a pre-tax loss on sale of $49 million, primarily related to cumulative translation losses. The sale did not
meet the criteria to be reported as discontinued operations. Prior to their sale, the Kazakhstan CHP plants were
reported in the Eurasia SBU reportable segment. See Note 20—Asset Impairment Expense for further information.
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
accounting guidance, UK Wind was deconsolidated and a loss on deconsolidation of $20 million was recorded to
Gain (loss) on disposal and sale of business interests in the Consolidated Statement of Operations to write off the
Company’s noncontrolling interest in the project. The UK Wind projects were reported in the Eurasia SBU reportable
segment.
DPLER — In January 2016, the Company completed the sale of DPLER, a competitive retail marketer selling
electricity to customers in Ohio, and recognized a gain on sale of $49 million. Proceeds of $76 million were received
in December 2015. DPLER 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. Prior to its sale,
DPLER was reported in the US and Utilities SBU reportable segment.
Kelanitissa — In January 2016, the Company completed the sale of its interest in Kelanitissa, a diesel-fired
generation plant in Sri Lanka, for $18 million, resulting in a loss on sale of $5 million. The sale did not meet the
criteria to be reported as discontinued operations. Kelanitissa's results were therefore reflected within continuing
operations in the Consolidated Statements of Operations. Prior to its sale, Kelanitissa was reported in the Eurasia
SBU reportable segment.
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 pre-tax 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 business interests, net of cash and restricted 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 continues to manage and operate the plant. As the Company maintained control after the sale,
Jordan IPP4 continues to be consolidated by the Company within the Eurasia SBU reportable segment.
159
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
Excluding any impairment charge or gain/loss on sale, pre-tax income (loss) attributable to AES of disposed
businesses was as follows (in millions):
Year Ended December 31,
Masinloc
Stuart and Killen (1)(2)
DPL peaker assets
Zimmer and Miami Fort
Kazakhstan Hydroelectric
Kazakhstan CHPs
Other
Total
_____________________________
2018
2017
2016
$
$
9
77
7
—
—
—
14
107
$
$
103
17
17
26
33
13
9
218
$
$
103
—
20
(14)
34
12
11
166
(1)
(2)
The Company entered into contracts to buy back all open capacity years for Stuart and Killen at prices lower than the PJM capacity revenue prices. As such,
the Company continues to earn capacity margin.
Reductions in the asset retirement obligations for ash ponds and landfills at Stuart and Killen in 2018 resulted in a $32 million reduction to cost of sales. See
Note 3—Property, Plant and Equipment for further information.
24. ACQUISITIONS
Distributed Energy — In December 2018, Distributed Energy acquired the outstanding noncontrolling interest
in a partnership holding various solar projects from its tax equity partner for $23 million of consideration in a non-
cash transaction through the assumption of debt, increasing the Company's ownership to 100%. The partnership
was previously classified as an equity method investment. The transaction was accounted for as an asset
acquisition, therefore the Company remeasured the equity investment at fair value and recognized a loss of $5
million in Other expense in the Consolidated Statement of Operations. The fair value of the investment, along with
the consideration transferred, plus transaction costs, were allocated to the individual assets acquired and liabilities
assumed based on their relative fair values. Distributed Energy is reported in the US and Utilities SBU reportable
segment.
In September 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 recorded the
opening balance sheets of the acquired businesses based on the purchase price allocation as of the acquisition
date.
Oahu — In November 2018, AES Oahu amended a 2017 agreement to acquire 100% of Na Pua Makani
Power Partners, a partnership designed to develop and hold a wind project in Hawaii. The fair value of the initial
consideration was $53 million, of which $48 million was contingent on meeting predefined development milestones.
The transaction was accounted for as an acquisition of a variable interest entity that did not meet the definition of a
business, therefore the assets acquired and liabilities assumed were recorded at their fair values, which equaled the
fair value of the consideration. As a result of the amendment, the Company paid $11 million in 2018 and the
contingent consideration was reduced to $5 million, resulting in a $32 million gain on remeasurement of contingent
consideration recorded in Other income in the Consolidated Statement of Operations. AES Oahu is reported in the
US and Utilities SBU reportable segment.
Guaimbê Solar Complex — In September 2018, AES Tietê completed the acquisition of the Guaimbê Solar
Complex (“Guaimbê”) from Cobra do Brasil for $152 million, subject to post-closing adjustments, comprised of the
exchange of $119 million of non-convertible debentures in project financing and additional cash consideration of $33
million. The transaction was accounted for as an asset acquisition, therefore the consideration transferred, plus
transaction costs, were allocated to the individual assets acquired and liabilities assumed based on their relative fair
values. Any differences arising from post-closing adjustments will be allocated accordingly. Guaimbê is reported in
the South America SBU reportable segment.
Alto Sertão II — In August 2017, the Company completed the acquisition of the Alto Sertão II Wind Complex
(“Alto Sertão II”) from Renova Energia S.A. for $179 million, plus the assumption of $346 million of non-recourse
debt. At closing, the Company made a cash payment of $143 million, which excluded holdbacks related to
indemnifications. In September 2018, an additional $12 million was paid to settle a portion of the remaining
indemnification liability. In the first quarter of 2018, the Company finalized the purchase price allocation related to
the acquisition of Alto Sertão II. There were no significant adjustments made to the preliminary purchase price
160
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
allocation recorded in the third quarter of 2017 when the acquisition was completed. The assets acquired and
liabilities assumed at the acquisition date were recorded at fair value, including a contingent liability for earn-out
payments of $18 million, based on the final purchase price allocation at March 31, 2018. Subsequent changes to
the fair value of the earn-out payments will be reflected in earnings. Alto Sertão II is reported in the South America
SBU reportable segment.
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 RSUs, 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, 2018, 2017 and 2016,
where income represents the numerator and weighted-average shares represent the denominator.
Year Ended December 31,
(in millions, except per share data)
BASIC EARNINGS (LOSS) PER SHARE
Income (loss) from continuing operations
attributable to The AES Corporation common
stockholders (1)
EFFECT OF DILUTIVE SECURITIES
Restricted stock units
DILUTED EARNINGS (LOSS) PER SHARE
_____________________________
Income
2018
Shares
$ per Share
Loss
2017
Shares
$ per Share
Loss
2016
Shares
$ per Share
$ 985
662
$
1.49
$ (507)
660
$
(0.77) $
(25)
660
$
(0.04)
—
$ 985
3
665
$
(0.01)
1.48
—
$ (507)
—
660
$
—
(0.77) $
—
(25)
—
660
$
—
(0.04)
(1)
Loss from continuing operations, net of tax, of $20 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 stock awards and convertible debentures which would
be anti-dilutive. The calculation of diluted earnings per share excluded 2 million, 7 million and 8 million stock awards
outstanding for the years ended December 31, 2018, 2017 and 2016, respectively, that could potentially dilute basic
earnings per share in the future. Additionally, for the year ended December 31, 2016, all 15 million convertible
debentures were excluded from the earnings per share calculation. The Company redeemed all of its existing
convertible debentures in June 2017.
For the years ended December 31, 2017 and 2016, respectively, the calculation of diluted earnings per share
also excluded 4 million and 5 million outstanding restricted stock units that could potentially dilute earnings per
share in the future because their impact would be anti-dilutive given the loss from continuing operations. Had the
Company generated income, 2 million potential shares of common stock related to the restricted stock units would
have been included in diluted average shares outstanding for each period.
26. RISKS AND UNCERTAINTIES
AES is a diversified power generation and utility company organized into four market-oriented SBUs. See
additional discussion of the Company's principal markets in Note 15—Segment and Geographic Information. Within
our four 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 comprises 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
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+, Fitch
of BB+, and Moody's of Ba1. This could affect the Company's ability to finance new and/or existing development
161
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
projects at competitive interest rates. As of December 31, 2018, the Company had $1.2 billion of unrestricted cash
and cash equivalents.
During 2018, 68% 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;
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;
unwillingness of governments, government agencies, similar organizations or other counterparties to honor
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
162
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
•
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.
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 in earnings and cash flows: the
Argentine peso, the Brazilian real, the Dominican Republic peso, the Euro, the Chilean peso, the Colombian peso,
and the Philippine peso.
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 2018, 2017 or 2016.
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
$
2018
2017
2016
$
1,533
342
14
54
$
1,297
220
8
36
1,100
210
4
39
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
2018
2017
$
$
371
754
250
727
The Company entered into an equity transaction with our related party, Linda Group, see Note 14—Equity for
further information.
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 2018 and 2017 (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.
163
THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2018, 2017, AND 2016
Quarter Ended 2018
Revenue
Operating margin
Income from continuing operations, net of tax (1)
Income (loss) from discontinued operations, net of tax (2)
Net income
Net income attributable to The AES Corporation
Basic earnings per share:
Income from continuing operations attributable to The AES Corporation common
stockholders, net of tax
Income from discontinued operations attributable to The AES Corporation common
stockholders, net of tax
Net income 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 from discontinued operations attributable to The AES Corporation common
stockholders, net of tax
Net income attributable to The AES Corporation common stockholders
Dividends declared per common share
Quarter Ended 2017
Revenue
Operating margin
Income (loss) from continuing operations, net of tax (3)
Income (loss) from discontinued operations, net of tax (4)
Net income (loss)
Net income (loss) attributable to The AES Corporation
Basic earnings (loss) per share:
Income (loss) 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 (loss) 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
_____________________________
Mar 31
Jun 30
Sep 30
Dec 31
2,740
656
778
(1)
777
684
$
$
$
2,537
600
224
192
416
290
$
$
$
2,837
671
192
(1)
191
101
$
$
$
2,622
646
155
26
181
128
1.04
$
0.15
$
0.15
$
0.15
—
1.04
$
0.29
0.44
—
$
0.15
$
0.04
0.19
1.03
$
0.15
$
0.15
$
0.15
—
1.03
0.13
$
$
0.29
0.44
$
— $
—
0.15
0.13
Mar 31
Jun 30
Sep 30
$
2,581
557
97
1
$
98
(24) $
2,613
623
142
8
150
53
$
$
$
2,693
640
235
26
261
152
0.04
0.19
0.27
Dec 31
2,643
645
(622)
(664)
(1,286)
(1,342)
$
$
$
$
$
(0.04) $
0.08
$
0.22
$
(1.03)
—
—
(0.04) $
0.08
$
0.01
0.23
$
(1.00)
(2.03)
(0.04) $
0.08
$
0.22
$
(1.03)
—
(0.04) $
0.12
$
—
0.08
$
— $
0.01
0.23
0.12
$
$
(1.00)
(2.03)
0.25
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(1)
(2)
(3)
(4)
Includes pre-tax gains on sales of business interests of $788 million, $89 million and $128 million, in the first, second and fourth quarters of 2018,
respectively, and pre-tax losses of $21 million in the third quarter of 2018 (See Note 23—Held-for-Sale and Dispositions), pre-tax impairment expense of $92
million, $74 million and $42 million, in the second, third and fourth quarters of 2018, respectively (See Note 20—Asset Impairment Expense), other-than-
temporary impairment of Guacolda of $144 million in the fourth quarter of 2018 (See Note 7—Investments in and Advances to Affiliates), SAB 118 charges to
finalize the provisional estimate of one-time transition tax on foreign earnings of $33 million and $161 million in the third and fourth quarters of 2018,
respectively, and a SAB 118 income tax benefit to finalize the provisional estimate of remeasurement of deferred tax assets and liabilities to the lower
corporate tax rate of $77 million in the fourth quarter of 2018 (See Note 21—Income Taxes).
Includes gain on sale of Eletropaulo of $199 million in the second quarter of 2018 (See Note 22—Discontinued Operations).
Includes provisional tax expense related to a one-time transition tax on foreign earnings of $675 million and the remeasurement of deferred tax assets and
liabilities to the lower corporate tax rate of $39 million in the fourth quarter of 2017 (See Note 21—Income Taxes), pre-tax impairment expense of $168 million,
$90 million and $277 million, in the first, second and fourth quarters of 2017, respectively (See Note 20—Asset Impairment Expense), and pre-tax losses on
sales of business interests of $48 million in second quarter of 2017 (See Note 23—Held-for-Sale and Dispositions).
Includes loss on deconsolidation of Eletropaulo of $611 million in the fourth quarter of 2017 (See Note 22—Discontinued Operations).
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.
164
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, 2018, 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,
2018. 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, 2018.
The effectiveness of the Company's internal control over financial reporting as of December 31, 2018, 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, 2018 that have materially
affected, or are reasonably likely to materially affect, our internal control over financial reporting.
165
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and the Board of Directors of The AES Corporation:
Opinion on Internal Control over Financial Reporting
We have audited The AES Corporation’s internal control over financial reporting as of December 31, 2018,
based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, The AES
Corporation (the Company) maintained, in all material respects, effective internal control over financial reporting as
of December 31, 2018, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2018 and 2017,
the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows
for each of the three years in the period ended December 31, 2018, and the related notes and financial statement
schedule listed in the Index at Item 15(a) (collectively referred to as the “financial statements”), and our report dated
February 26, 2019, expressed an unqualified opinion thereon.
Basis for Opinion
The Company’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 are a public accounting firm
registered with the PCAOB and are required to be independent with respect to the Company in accordance with the
U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission
and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial
reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk
that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control
based on the assessed risk, and performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with 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.
/s/ Ernst & Young LLP
Tysons, Virginia
February 26, 2019
166
ITEM 9B. OTHER INFORMATION
None.
167
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 2019 Annual Meeting of Stockholders which the Registrant expects will be filed on or around March 6,
2019 (the "2019 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 2019 Proxy Statement and is herein incorporated by
reference.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 402 of Regulation S-K is contained in the 2019 Proxy Statement under
"Director Compensation" and "Executive Compensation" (excluding the information under the caption “Report of the
Compensation Committee”) and is incorporated herein by reference.
The information required by Item 407(e)(5) of Regulation S-K is contained under the caption “Report of the
Compensation Committee Report” of the Proxy Statement. Such information shall not be deemed to be “filed.”
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS
(a) Security Ownership of Certain Beneficial Owners and Management.
See the information contained under the heading Security Ownership of Certain Beneficial Owners, Directors,
and Executive Officers of the 2019 Proxy Statement, which information is incorporated herein by reference.
(b) 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, 2018:
Securities Authorized for Issuance under Equity Compensation Plans (As of December 31, 2018)
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))
9,794,600 (2) $
—
9,794,600
$
12.36
—
12.36
14,534,999
—
14,534,999
(1) The following equity compensation plans have been approved by The AES Corporation's Stockholders:
(A)
(B)
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
authorized shares to 45,750,000. The weighted average exercise price of Options outstanding under this plan included in Column
(b) is $12.36 (excluding performance stock units, restricted stock units and director stock units), with 14,534,999 shares available
for future issuance.
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
168
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 4,366,156 (of which 592,813 are vested and 3,773,343 are unvested) shares underlying PSU and RSU awards (assuming 2016
PSU median performance and 2017 and 2018 PSUs maximum performance), 1,646,376 shares underlying Director stock unit awards,
and 3,782,068 shares issuable upon the exercise of Stock Option grants, for an aggregate number of 9,794,600 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 2019 Proxy
Statement found under the headings Transactions with Related Persons and Board and Committee Governance
Matters and are incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this Item 14 is included in the 2019 Proxy Statement under the headings
Information Regarding The Independent Registered Public Accounting Firm, Audit Fees, Audit Related Fees, and
Pre-Approval Policies and Procedures and is incorporated herein by reference.
169
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULE
PART IV
(a) Financial Statements.
Financial Statements and Schedules:
Consolidated Balance Sheets as of December 31, 2018 and 2017
Consolidated Statements of Operations for the years ended December 31, 2018, 2017 and 2016
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2018, 2017 and 2016
Consolidated Statements of Changes in Equity for the years ended December 31, 2018, 2017 and 2016
Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016
Notes to Consolidated Financial Statements
Schedules
Page
104
105
106
107
108
109
S-2-S-7
(b) Exhibits.
3.1
3.2
4
4.(a)
4.(b)
4.(c)
4.(d)
4.(e)
4.(f)
4.(g)
4.(h)
4.(i)
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.7A
10.8
10.9
10.10
10.10A
10.11
10.12
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.(q).
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.
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.
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.
Twenty-First Supplemental Indenture, dated August 28, 2017, between The AES Corporation and Deutsche Bank Trust Company,
as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on August 28, 2017.
Twenty-Second Supplemental Indenture, dated March 15, 2018, between The AES Corporation and Deutsche Bank Trust
Company Americas, as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on March 15,
2018.
Twenty-Fourth Supplemental Indenture, dated March 15, 2018 between The AES Corporation and Deutsche Bank Trust Company
Americas, as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on March 21, 2018.
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. (P)
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). (P)
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). (P)
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). (P)
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). (P)
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).
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 10.12A 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.
170
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
10.27D
10.27E
10.28
10.29
10.30
10.31
10.32
10.33
21.1
23.1
24
31.1
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 August 4, 2017 is incorporated herein by reference to Exhibit
10.1 of the Company's Form 10-Q for the quarter ended June 30, 2017.
The AES Corporation Amended and Restated Executive Severance Plan dated October 5, 2018 is incorporated herein by
reference to Exhibit 10.1 of the Company's Form 10-Q for the quarter ended September 30, 2018.
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 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 Administrative 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.
Amendment No. 2, dated as of June 28, 2017, to the 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 and
Citibank, N.A. as Administrative Agent and Collateral Agent is incorporated herein by reference to Exhibit 10.1 of the Company's
Form 8-K filed on June 29, 2017.
Annex A. to Amendment No. 2, dated as of June 28, 2017, to the Sixth Amended and Restated Credit and Reimbursement
Agreement, dated as of July 26, 2013 is incorporated herein by reference to 10.1.A of the Company's Form 8-K filed on June 29,
2017.
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).
Credit Agreement dated as of May 24, 2017 among The AES Corporation, as borrower, the bank listed therein and Bank of
America, N.A., as administrative agent is incorporated herein by reference to Exhibit 10.1 of the Company's Form 8-K filed on May
24, 2017.
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 is incorporated herein by reference to
Exhibit 10.31 of the Company's Form 10-K for the year ending December 31, 2016.
Consulting Agreement by and between The AES Corporation and Brian A. Miller dated February 26, 2018 is incorporated herein by
reference to Exhibit 10.33 of the Company's Form 10-K for the year ending December 31, 2017.
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).
171
31.2
32.1
32.2
101.INS
Rule 13a-14(a)/15d-14(a) Certification of Gustavo Pimenta (filed herewith).
Section 1350 Certification of Andrés Gluski (filed herewith).
Section 1350 Certification of Gustavo Pimenta (filed herewith).
XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are
embedded within the Inline XBRL document.
101.SCH XBRL Taxonomy Extension Schema Document (filed herewith).
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) Schedule
Schedule I—Financial Information of Registrant
172
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 26, 2019
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
James H. Miller
*
Director
Alain Monié
*
Chairman of the Board and Lead Independent Director
John B. Morse
*
Director
Moises Naim
*
Director
Jeffrey W. Ubben
/s/ GUSTAVO PIMENTA
Gustavo Pimenta
Executive Vice President and Chief Financial Officer (Principal
Financial Officer)
/s/ SARAH R. BLAKE
Vice President and Controller (Principal Accounting Officer)
Sarah R. Blake
*By:
/s/ PAUL L. FREEDMAN
Attorney-in-fact
173
February 26, 2019
February 26, 2019
February 26, 2019
February 26, 2019
February 26, 2019
February 26, 2019
February 26, 2019
February 26, 2019
February 26, 2019
February 26, 2019
February 26, 2019
February 26, 2019
February 26, 2019
THE AES CORPORATION AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule I—Condensed Financial Information of Registrant
S-2
Schedules other than that listed above are omitted as the information is either not applicable, not required, or
has been furnished in the consolidated 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
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 $4 and $2, respectively
Deferred income taxes
Other assets
Total other assets
Total assets
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable
Accounts and notes payable to subsidiaries
Accrued and other liabilities
Senior notes payable—current portion
Total current liabilities
Long-term Liabilities:
Senior notes payable
Accounts and notes payable to subsidiaries
Other long-term liabilities
Total long-term liabilities
Stockholders' equity:
Common stock
Additional paid-in capital
Accumulated deficit
Accumulated other comprehensive loss
Treasury stock
Total stockholders' equity
Total liabilities and equity
December 31,
2018
2017
(in millions)
$
$
$
$
19
285
31
335
6,834
27
(19)
8
3
4
24
2
33
7,210
15
74
206
5
300
3,650
28
24
3,702
8
8,154
(1,005)
(2,071)
(1,878)
3,208
7,210
$
$
$
$
10
143
27
180
8,239
27
(18)
9
3
5
289
2
299
8,727
18
381
246
5
650
4,625
967
20
5,612
8
8,501
(2,276)
(1,876)
(1,892)
2,465
8,727
See Notes to Schedule I.
S-2
$
2017
(in millions)
28
$
630
49
(158)
5
(554)
(92)
(317)
(409)
(752)
(1,161) $
$
2016
14
(615)
19
(144)
7
(65)
(14)
(344)
(1,142)
12
(1,130)
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF OPERATIONS
For the Years Ended December 31,
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 (expense)
Net income (loss)
See Notes to Schedule I.
2018
36
1,909
39
(142)
25
—
(171)
(220)
1,476
(273)
1,203
$
$
S-3
THE AES CORPORATION
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
YEARS ENDED DECEMBER 31, 2018, 2017, AND 2016
NET INCOME (LOSS)
Foreign currency translation activity:
Foreign currency translation adjustments, net of income tax benefit of $2, $11 and $1, 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 $16, $13 and $(5), respectively
Reclassification to earnings, net of income tax benefit (expense) of $(13), $1 and $1, 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 $1, $1 and $5, respectively
Change in pension adjustments due to net actuarial gain (loss) for the period, net of income tax
benefit (expense) of $(1), $6 and $10, respectively
Reclassification of earnings, net of income tax benefit (expense) of $(2), $(126) and $2, respectively
Total change in unfunded pension obligation
OTHER COMPREHENSIVE INCOME (LOSS)
COMPREHENSIVE INCOME (LOSS)
See Notes to Schedule I.
2018
$
1,203
2016
2017
(in millions)
$ (1,161) $ (1,130)
(214)
(21)
(235)
(64)
78
14
(2)
2
7
7
(214)
989
$
18
643
661
(14)
37
23
1
(20)
248
229
913
(248) $
$
117
992
1,109
2
28
30
9
(22)
1
(12)
1,127
(3)
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:
Proceeds from the sale of business interests, net of expenses
Investment in and net advances to subsidiaries
Return of capital
Additions to property, plant and equipment
Net cash provided by (used in) investing activities
Financing Activities:
(Repayments) Borrowings under the revolver, net
Borrowings of notes payable and other coupon bearing securities
Repayments of notes payable and other coupon bearing securities
Loans from (Repayments to) 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
2018
2017
(in millions)
2016
$
409
$
148
$
1,222
(216)
242
(13)
1,235
(207)
1,000
(1,933)
(143)
—
7
(344)
(11)
—
(5)
(1,636)
1
9
10
19
232
10
$
$
$
—
(339)
243
(13)
(109)
207
1,025
(1,353)
309
—
1
(317)
(12)
—
(7)
(147)
6
(102)
112
10
282
2
$
$
$
$
$
$
818
—
(650)
247
(12)
(415)
—
500
(808)
183
(79)
1
(290)
(12)
(2)
(3)
(510)
1
(106)
218
112
296
6
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 as well as effects of U.S. tax law reform
enacted in 2017.
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 and Secured Notes and Loans Payable ($ in millions)
Senior Unsecured Note
Senior Unsecured Note
Drawings on secured credit facility
Senior Unsecured Note
Senior Secured Term Loan
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
Interest Rate
8.00%
7.38%
LIBOR + 2.00%
4.00%
LIBOR + 1.75%
4.50%
4.88%
5.50%
5.50%
6.00%
5.13%
Maturity
2020
2021
2021
2021
2022
2023
2023
2024
2025
2026
2027
$
$
$
December 31,
2018
2017
— $
—
—
500
366
500
713
63
544
500
500
(31)
3,655
(5)
3,650
$
$
228
690
207
—
521
—
713
738
573
500
500
(40)
4,630
(5)
4,625
FUTURE MATURITIES OF RECOURSE DEBT — As of December 31, 2018 scheduled maturities are
presented in the following table (in millions):
December 31,
2019
2020
2021
2022
2023
Thereafter
Unamortized (discount)/premium & debt issuance (costs)
Total debt
3. Dividends from Subsidiaries and Affiliates
Annual Maturities
$
$
5
5
505
350
1,213
1,608
(31)
3,655
Cash dividends received from consolidated subsidiaries were $1.9 billion, $1.2 billion and $1 billion for the
years ended December 31, 2018, 2017, and 2016, respectively. For the year ended December 31, 2018, $1.2
billion of the dividends paid to the Parent Company are derived from the sale of business interests and are
classified as an investing activity for cash flow purposes. All other dividends are classified as operating activities.
There were no cash dividends received from affiliates accounted for by the equity method for the years ended
December 31, 2018, 2017, and 2016.
S-6
4. Guarantees and Letters of Credit
GUARANTEES — In connection with certain of its project financing, acquisition and power purchase
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. These obligations and
commitments, excluding those collateralized by letter of credit and other obligations discussed below, were limited
as of December 31, 2018 by the terms of the agreements, to an aggregate of approximately $712 million,
representing 34 agreements with individual exposures ranging up to $157 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, 2018, the Parent Company had $78 million in letters of credit
outstanding under the senior secured credit facility, representing 23 agreements with individual exposures up to $49
million, and $368 million in letters of credit outstanding under the senior unsecured credit facility, representing 10
agreements with individual exposures ranging from $1 million to $247 million. During 2018, the Parent Company
paid letter of credit fees ranging from 1% to 3% per annum on the outstanding amounts.
S-7
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Julian Nebreda
Senior Vice President
& President, South America SBU
Leonardo Moreno
Senior Vice President,
Chief Strategy & Risk Officer
Lisa Krueger
Senior Vice President
& President, US and Utilities SBU
Alain Monie
CEO of Ingram Micro
Moisés NaÍm
Distinguished Fellow in the International Economics
Program at the Carnegie Endowment for International
Peace and international columnist and broadcaster;
Former Editor in Cheif for Foreign Policy magazine;
Former Minister of Industry and Trade and the Central
Bank for Venezuela; former Executive Director for the
World Bank
Jeffrey Ubben
Founder and former CEO and CIO of ValueAct Capital
AES EXECUTIVE LEADERSHIP TEAM
Andrés Gluski
President & Chief Executive Officer
Bernerd Da Santos
Executive Vice President
& Chief Operating Officer
Paul Freedman
Senior Vice President, General Counsel
& Corporate Secretary
Tish Mendoza
Senior Vice President of Global Human
Resources & Internal Communications
and Chief Human Resource Officer
Manuel Perez Dubuc
Senior Vice President,
Global New Energy Solutions
Gustavo Pimenta
Executive Vice President
& Chief Financial Officer
Sanjeev Addala
Chief Information Digital Officer
Juan Ignacio Rubiolo
Senior Vice President
& President, MCAC SBU
AES BOARD OF DIRECTORS
John B. Morse Jr. (Chairman)
Retired Senior Vice President Finance and CFO
Washington Post Company; former Partner
Waterhouse (now PricewaterhouseCoopers); former
Trustee and President Emeritus of the College
Foundation of the University of Virginia
Kristina Johnson
Chancellor, State of New York University System;
former CEO of Cube Hydro Partners; former
Undersecretary for energy at the Department of
Energy; former Provost and Senior Vice President for
Academic Affairs at the John Hopkins University
Janet Davidson
Former Executive Vice President; Quality Customer
Care Alcatel Lucent S.A.
Tarun Khanna
Jorge Paulo Lemann Professor at the Harvard Business
School
Holly K. Koeppel
Former Managing Partner and Co-Head of Corsair
Infrastructure Management, L.P.
James Miller
Former Chairman of PPL Corporation; former
Executive Vice President of USEC Inc.; President for
two ABB Group subsidiaries
Andrés Gulski
AES President & Chief Executive Officer
Charles Harrington
Chairman and CEO of Parsons Corporation
COMPANY INFORMATION
Corporate Office
The AES Corporation
4300 Wilson Boulevard
Arlington, VA 22203
USA
703.522.1315
Website
www.aes.com @TheAESCorp
Transfer Agent
The 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.
Independent Auditors
Ernst & Young LLP
Investors
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: 703.682.6451
Stock Information
Common 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 Shareholders
As of December 31, 2018 there were approximately
3,919 AES shareholders of record and 662,298,096
shares of AES common stock outstanding.
By mail:
Computershare
P.O. Box 505000
Lousiville, KY 40233
Overnight:
Computershare
462 South 4th Street, Suite 1600
Lousville, KY 40233-9814
877.373.6374
www.computershare.com
Media Inquiries
General: mediainquiries@aes.com
Amy Ackerman, Manager, External
Communications: 703.682.6399
AES Code of Conduct
AES 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 on our website.
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The AES Corporation
4300 Wilson Boulevard
Arlington, VA 22203, USA
www.aes.com
703.522.1315
2018 Annual report cover_front and back_spine.275.indd 1
2018 ANNUAL
REPORT