Attached files
| file | filename |
|---|---|
| EX-99.3 - EXHIBIT 99.3 - TerraForm Power NY Holdings, Inc. | exhibit993terpq120188-k.htm |
| EX-99.1 - EXHIBIT 99.1 - TerraForm Power NY Holdings, Inc. | exhibit991terpq120188-kpre.htm |
| 8-K - 8-K - TerraForm Power NY Holdings, Inc. | terp8-kq1201810xqmay12018.htm |
TERRAFORM POWER
Q1 2018 Supplemental
Three Months Ended March 31, 2018
Information
2
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This communication contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. Forward-looking statements can be identified by the fact that they do not relate strictly to historical or current facts. These statements
involve estimates, expectations, projections, goals, assumptions, known and unknown risks, and uncertainties and typically include words or variations of words
such as “expect,” “anticipate,” “believe,” “intend,” “plan,” “seek,” “estimate,” “predict,” “project,” “goal,” “guidance,” “outlook,” “objective,” “forecast,” “target,”
“potential,” “continue,” “would,” “will,” “should,” “could,” or “may” or other comparable terms and phrases. All statements that address operating performance,
events, or developments that the Company expects or anticipates will occur in the future are forward-looking statements. They may include estimates of expected
cash available for distribution, earnings, revenues, capital expenditures, liquidity, capital structure, future growth, financing arrangements and other financial
performance items (including future dividends per share), descriptions of management’s plans or objectives for future operations, products, or services, or
descriptions of assumptions underlying any of the above. Forward-looking statements provide the Company’s current expectations or predictions of future
conditions, events, or results and speak only as of the date they are made. Although the Company believes its expectations and assumptions are reasonable, it
can give no assurance that these expectations and assumptions will prove to have been correct and actual results may vary materially.
Important factors that could cause actual results to differ materially from our expectations, or cautionary statements, are listed below and further disclosed under
the section entitled Item 1A. Risk Factors: risks related to the transition to Brookfield Asset Management Inc. sponsorship, including our ability to realize the
expected benefits of the sponsorship; risks related to wind conditions at our wind assets or to weather conditions at our solar assets; risks related to the
effectiveness of our internal controls over financial reporting; pending and future litigation; the willingness and ability of counterparties to fulfill their obligations
under offtake agreements; price fluctuations, termination provisions and buyout provisions in offtake agreements; our ability to enter into contracts to sell power on
acceptable prices and terms, including as our offtake agreements expire; our ability to compete against traditional and renewable energy companies; government
regulation, including compliance with regulatory and permit requirements and changes in tax laws, market rules, rates, tariffs, environmental laws and policies
affecting renewable energy; risks related to the expected relocation of the Company’s headquarters; the condition of the debt and equity capital markets and our
ability to borrow additional funds and access capital markets, as well as our substantial indebtedness and the possibility that we may incur additional indebtedness
going forward; operating and financial restrictions placed on us and our subsidiaries related to agreements governing indebtedness; risks related to the expected
timing and likelihood of completion of the tender offer for the shares of Saeta Yield, S.A., including the timing or receipt of any governmental approvals; risks
related to our financing of the tender offer for the shares of Saeta Yield, S.A., including our ability to issue equity on terms that are accretive to our shareholders
and our ability to implement our permanent funding plan; our ability to successfully identify, evaluate and consummate acquisitions; and our ability to integrate the
projects we acquire from third parties, including Saeta Yield, S.A., or otherwise and our ability to realize the anticipated benefits from such acquisitions.
The Company disclaims any obligation to publicly update or revise any forward-looking statement to reflect changes in underlying assumptions, factors, or
expectations, new information, data, or methods, future events, or other changes, except as required by law. The foregoing list of factors that might cause results
to differ materially from those contemplated in the forward-looking statements should be considered in connection with information regarding risks and
uncertainties, which are described in our Annual Report on Form 10-K and any subsequent Quarterly Report on Form 10-Q, as well as additional factors we may
describe from time to time in other filings with the SEC. We operate in a competitive and rapidly changing environment. New risks and uncertainties emerge from
time to time, and you should understand that it is not possible to predict or identify all such factors and, consequently, you should not consider any such list to be a
complete set of all potential risks or uncertainties.
3
Q1 2018 HIGHLIGHTS
Activities Highlights
• Announced offer to acquire 100% of Saeta Yield, a leading, publicly-listed European owner and
operator of wind and solar assets, located primarily in Spain. Received Spanish regulatory approval
for the acquisition and for our offer price of €12.20 per share; launching tender offer in early May;
expecting to close the transaction in June or July
• We are in advanced negotiations with an original equipment manufacturer to provide a full-wrap long-
term service contract covering all our wind fleet, which features a fixed price that is consistent with our
business plan and attractive availability guarantees
• In late stage negotiations to acquire a fully contracted 6 MW DG solar portfolio; includes a ROFO on
an additional 15 MW with the same seller, which we may be able to exercise in phases over the next
9-18 months
• In January one of the towers at our Raleigh, Ontario facility collapsed due to a single faulty blade. In
order to determine the root cause of the blade failure, we removed from service all 70 turbines across
the fleet that utilize the same blades. After a thorough investigation to determine the root cause of the
blade failure and rigorous inspections of the blades, the turbines have been returned to normal service
• In early February 2018, we upsized our corporate revolving credit facility to $600 million, TERP now
has over $1 billion of liquidity under committed facilities
• Paid quarterly dividend of $0.19 per share, or $0.76 per share on an annualized basis – a 6% increase
over previous guidance
4
2018 2017
2,022 2,022
1,834 1,982
$ 139 $ 149
96 103
(76) (56)
23 19
$ 0.56 $ (0.37)
$ 0.16 $ 0.14
1,897 1,982
$ 102 $ 103
$ 29 $ 19
Adjusted for sale of our UK solar and Residential portfolios.
Total generation (GWh) (1)(5)
(5)
Adjusted EBITDA(3)(5)
CAFD(3)(5)
(4)
(1)
(2)
(3)
Earnings per share for the three months ended March 31, 2018 includes the impact of a $145.0 million net loss
allocated to non-controlling interests resulting from changes in tax rates effective January 1, 2018.
Loss per share calculated on weighted average basic and diluted Class A shares outstanding. CAFD per share
calculated on shares outstanding of Class A common stock and Class B common stock on March 31. For three
months ended March 31, 2018, Class A common stock shares outstanding totaled 148.1 million (three months
ended March 31, 2017: 92.2 million). For three months ended March 31, 2018, there is no Class B common stock
shares outstanding (three months ended March 31, 2017: 48.2 million).
Excluding impact of Raleigh outages in 2018.
Non-GAAP measures. See “Calculation and Use of Non-GAAP Measures” and “Reconciliation of Non-GAAP
Measures” sections. Amounts in 2017 adjusted for sale of our UK and Residential portfolios.
Three months ended
(MILLIONS, EXCEPT AS NOTED)
Total generation (GWh)(1)
Mar 31
LTA generation (GWh)
Adjusted EBITDA(3)
Adjusted Revenue(3)
CAFD(3)
Excluding impact of Raleigh outages
Earnings (loss) per share(2)
CAFD per share(3)(4)
Net loss
• Our portfolio performed broadly in-line with expectations,
excluding the impact of the Raleigh outages, delivering
Adjusted EBITDA and CAFD of $102 million and $29
million
• Adjusted EBITDA $1 million down mainly due to
congestion in Texas Wind, partially offset by stronger
resource in Utility Solar
• CAFD $10 million higher due to lower debt service
driven by refinancing executed in Q4 2017, and lower
distributions to non-controlling interests, partially
offset by lower Adjusted EBITDA
• Including the nonrecurring lost revenue related to the
Raleigh outages, Adjusted EBITDA and CAFD were $96
million and $23 million
• Excluding the impact of the Raleigh outages, total
generation in Q1 2018 of 1,897 GWh, ~4% lower than Q1
2017, primarily due to curtailment in our Wind segment.
We experienced fleet availability of 95%
• Net loss of ($76) million was $20 million greater than Q1
2017 primarily due to lower Adjusted EBITDA and asset
impairment in DG Solar of $15 million due to FirstEnergy
Solutions bankruptcy
• Robust liquidity with over $1 billion of corporate liquidity
available to fund growth
Q1 2018 HIGHLIGHTS (continued)
Key Performance Metrics
Key Balance Sheet Metrics
Performance Highlights
1,834 GWh
Generation
~$1,037 million
Corporate Liquidity
$23 million
CAFD
Mar 31 Dec 31
2018 2017
1,037 855
3,637 3,643
5,966 6,071
(1)
(IN $ MILLIONS)
Corporate liquidity
Total long-term debt
Total capitalization(1)
Total capitalization is comprised of total stockholders ’ equity, redeemable non-controlling interests ,
and Total long-term debt.
5
Our Business
TerraForm Power’s goal is to own and operate high-quality solar and wind
generation assets in North America and Western Europe
Performance Targets and Key Measures
• Our objective is to deliver an attractive total return in the low teens per annum to
our shareholders
• Expect to generate return from a dividend backed by stable cashflow from our
assets and 5-8% annual dividend per share increase that we believe is
sustainable over the long term
• We target a dividend payout of 80-85% of CAFD
• Over the next five years, expect growth to be driven primarily by cost
savings, accretion from Saeta acquisition, and organic investments
• Opportunistic, value-oriented acquisitions expected to provide upside to our
business plan
• Growth in CAFD per share is a key performance metric as it is a proxy for our
ability to increase distributions
6
20+ years
15%
15-20 years
28%
10-15 years
39%
<10 years
18%
Our Operations
Owner and operator of a 2,606 MW diversified portfolio of high-quality solar and
wind assets, primarily in the US, underpinned by long-term contracts
Solar Wind Total
US 894 MW 1,453 MW 2,347 MW
International 181 MW 78 MW 259 MW
Total 1,075 MW 1,531 MW 2,606 MW
Solar
67%
Wind
33%
2.6 GW
Fleet
Large Scale Portfolio with Cash
Flow Diversified by Technology1
Long-Term Offtake Contract1
1. Weighted on 2017 project CAFD.
Average
~14 Years
Remaining
7
Generation and Revenue
• Long term average annual generation (LTA) is energy at the point of delivery net of all recurring losses and
constraints. Our LTA represents the level of production that we expect to achieve starting in 2019 as we improve the
performance of our fleet
• We compare actual generation levels against the long-term average to highlight the impact of an important factor that
affects the variability of our business results. In the short-term, we recognize that wind and irradiance conditions will
vary from one period to the next; however, we expect our facilities will produce electricity in-line with their long-term
averages over time
(GWh) (MILLIONS)
Actual Generation LTA Generation Operating Revenue, Net Adjusted Revenue(1)
Q1 2018 Q1 2017 Q1 Q1 2018 Q1 2017 Q1 2018 Q1 2017
Wind
Central Wind 669 778 779 32$ 40$ 40$ 49$
Texas Wind 430 479 454 6$ 13$ 6$ 10$
Hawaii Wind 41 39 66 8$ 7$ 8$ 7$
Northeast Wind 325 330 324 22$ 25$ 24$ 25$
1,465 1,626 1,623 68$ 85$ 78$ 91$
Solar
NA Utility Solar 204 189 219 23$ 21$ 24$ 22$
International Utility Solar 62 64 66 8$ 8$ 7$ 9$
DG 103 103 114 29$ 30$ 30$ 27$
369 356 399 60 59 61 58
Total adjusted for Asset Sales 1,834 1,982 2,022 128$ 144$ 139$ 149$
Asset Sold 50 - 7 - 7
Total 1,834 2,032 2,022 128$ 151$ 139$ 156$
(1) Non-GAAP measures. See "Calculation and Use of Non-GAAP Measures" and "Reconciliation of Non-GAAP Measures” sections. Adjusted for unrealized (gain) loss on commodity
contract derivatives, amortization of favorable and unfavorable rate revenue contracts, other non-cash items, and sale of our UK solar and Residential portfolios.
8
Selected Income Statement and Balance Sheet Information
The following tables present selected income statement and balance sheet information by operating
segment:
Income Statement Balance Sheet
2018 2017
(12) 6
(7) 5
(57) (67)
$ (76) $ (56)
49 47
54 65
(7) (9)
$ 96 $ 103
23 21
35 33
(35) (35)
$ 23 $ 19
Three months ended
Mar 31
(MILLIONS, UNLESS NOTED)
Net loss
Solar
Wind
Corporate
Total
Adjusted EBITDA
Solar
Wind
Corporate
Total
Total
CAFD
Solar
Wind
Corporate
2,814 2,897
3,342 3,401
103 89
$ 6,259 $ 6,387
1,101 1,145
882 884
1,946 1,929
$ 3,929 $ 3,958
1,713 1,752
2,460 2,517-
(1,843) (1,840)
$ 2,330 $ 2,429
Solar
Wind
Corporate
Total
Total
Total Equity and NCI
Solar
Wind
Corporate
Total
Total Liabilities
Solar
Wind
Corporate
As of
(MILLIONS) Mar 31, 2018 Dec 31, 2017
Total Assets
9
Operating Segments
10
Solar
The following table presents selected key performance metrics for our Solar segment:
Overview
• 1,075 MW of net capacity
• 515 Sites in diverse geographies
• Average remaining PPA life of 17 years
• Average offtaker credit rating of Aa3
• Diverse mix of high quality modules
Contracted cash flows
• Utility scale – generation contracted by
investment grade counterparties (such
as state utilities)
• Distributed generation – mostly behind
the meter generation contracted by
investment grade public offtakers
(municipalities, universities, schools,
hospitals), and commercial and
industrial offtakers
2018 2017
1,075 1,075
399 399
93% 93%
369 356
$ 61 $ 58
$ 166 $ 162
(1) Adjusted for sale of our UK solar and Residential portfolios.
(MILLIONS, UNLESS NOTED)
Average Adj. Revenue per MWh(1)
Adjusted Revenue (1)
Generation (GWh) (1)
LTA Generation (GWh)
Availability (%)
Capacity (MW)
Three months ended
Mar 31
11
Solar (continued)
• Adjusted EBITDA and CAFD were $49 million
and $23 million, respectively, versus $47
million and $21 million, respectively, in Q1
2017
• Adjusted EBITDA increased $2 million due
to higher average realized prices in DG
solar driven by greater SREC subscriptions
at strong prices in 2018, and higher
volumes in Utility Solar. These were
partially offset by an increase in costs
related to SunEdison sponsor subsidies,
which benefited 2017
• CAFD increased $2 million due to greater
Adjusted EBITDA, and lower distributions to
non-controlling interests than Q1 2017.
Project defaults in 2016 caused cash traps,
which increased distributions to non-
controlling interests in Q1 2017 as cash
was released
• Net loss of ($12 million) was $18 million lower
than Q1 2017 primarily due to an asset
impairment in DG Solar
• Availability was adversely impact in Q1 2018
primarily due to switch gear outages in Chile
Performance Highlights
2018 2017
61 58
(12) (11)
$ 49 $ 47
(14) (14)
(12) (12)
(3) (4)
3 4
$ 23 $ 21
49 47
(15) (20)
(30) (29)
(16) 8
$ (12) $ 6
(1 ) Adjusted for sale of our UK solar and Residential portfolios in 2017.
Depreciation and amortization
Other
Net (loss) income
(MILLIONS, UNLESS NOTED)
Adjusted revenue (1)
Direct operating costs (1)
Adjusted EBITDA (1)
Adjusted interest expense (1)
Levelized principal repayments
Distributions to NCI
Other
CAFD (1)
Adjusted EBITDA
Interest expense
Mar 31
Three months ended
Actual Generation (GWh) Average Adj. Revenue per MWh
(MILLIONS, EXCEPT AS NOTED) Q1 2018 Q1 2017 Q1 2018 Q1 2017
NA Utility Solar 204 189 118$ 116$
International Utility Solar 62 64 120 132
DG 103 103 289 266
Total 369 356 166$ 162$
12
Wind
Overview
• 1,531 MW of net capacity
• 18 Sites in diverse geographies
• Average remaining PPA life of 12 years
• Average offtaker credit rating of A1
• Recently constructed assets (average 5
years old) with primarily top tier turbines
Contracted cash flows
• Substantially all generation is contracted
with investment grade counterparties,
such as state utilities or financial
institutions
The following table presents selected key performance metrics for our Wind segment:
2018 2017
1,531 1,531
1,623 1,623
95% 95%
1,528 1,626
$ 84 $ 91
$ 53 $ 56
Capacity (MW)
(1) Excluding impact related to Raleigh outages in 2018.
Three months ended
Mar 31
(MILLIONS, UNLESS NOTED)
Adjusted Revenue (1)
Average Adj. Revenue per MWh
LTA Generation
Adjusted Availability (%)(1)
Generation (GWh) (1)
13
Wind (continued)
Performance Highlights
• Excluding the impact of the Raleigh outages,
Adjusted EBITDA and CAFD were $60 million and
$41 million, respectively, versus $65 million and
$33 million, respectively, in Q1 2017
• Adjusted EBITDA decreased $5 million versus
Q1 2017, primarily due to scheduled grid
outage at Bishop Hill in January, partially
offset by lower major maintenance versus Q1
2017
• CAFD was $8 million higher than Q1 2017
due to refinancing of the MidCo term loan with
corporate level debt, partially offset by the
impacts to Adjusted EBITDA
• Including the nonrecurring lost revenue related to
the Raleigh outages, Adjusted EBITDA and CAFD
were $54 million and $35 million, respectively,
versus $65 million and $33 million, respectively, in
Q1 2017
• Net loss was ($7) million, $12 million lower than Q1
2017, due to lower Adjusted EBITDA, higher
depreciation, partially offset by repayment of the
MidCo term loan
• Sustaining capital expenditures are reported based
on long term averages starting in 2018. The wind
fleet will record $7 million annually ($2 million per
quarter), substantially higher than the $2 million
recorded in FY 2017
Actual Generation (GWh) Average Adj. Revenue per MWh
(MILLIONS, EXCEPT AS NOTED) Q1 2018 Q1 2017 Q1 2018 Q1 2017
Central Wind 669 778 60$ 62$
Texas Wind 430 479 14 20
Hawaii Wind 41 39 190 190
Northeast Wind 325 330 73 77
Total 1,465 1,626 53$ 56$
2018 2017
78 91
(24) (26)
$ 54 $ 65
(11) (20)
(12) (13)
(2) (6)
Sustaining capital expenditures (2) -
8 7
$ 35 $ 33
54 65
(11) (20)
(46) (41)
(4) 1
$ (7) ` 5
$ 60 $ 65
$ 41 $ 33
Adjusted EBITDA
CAFD
Excluding impact of Raleigh outages
Other
Net (loss) income
CAFD
Adjusted EBITDA
Interest expense
Depreciation and amortization
Adjusted EBITDA
Adjusted interest expense
Levelized principal repayments
Distributions to NCI
Other
(MILLIONS, UNLESS NOTED)
Adjusted revenue
Direct operating costs
Three months ended
Mar 31
14
Corporate
The following table presents our Corporate segment’s
financial results:
Performance Highlights
• Direct operating costs decreased by $2
million compared to Q1 2017 primarily
due to lower compensation
• Interest expense was broadly in line with
Q1 2017, primarily driven by refinancing
of our high yield bonds with interest
saving of ~200 bps, and lower interest
expense on our revolver due to a
significant lower balances, partially offset
by interest expense on the $350 million
Term Loan B issued in Q4 2017
• Non-operating general and administrative
expenses decreased by $7 million
primarily driven by higher legal fees and
consulting fees related to litigation and
transactions in Q1 2017
• Net loss of ($57) million was $10 million
lower than Q1 2017, primarily due to
reduction in non-operating costs
2018 2017
(7) (9)
$ (7) $ (9)
(3) -
(25) (26)-
$ (35) $ (35)
(7) (9)
(28) (28)-
1 1- -
(4) -- -
(18) (25)- -
(1) (6)
$ (57) $ (67)
Three months ended
Mar 31
(MILLIONS, UNLESS NOTED)
Direct operating costs
Adjusted EBITDA
Management fees
Income tax benefit
Acquisition and related costs
Other
Net loss
Adjusted interest expense
CAFD
Adjusted EBITDA
Interest expense
Non-operating general and administrative expens
15
Progress Versus Cost Savings Objectives
• On an annualized basis,
Q1 operating costs plus
base management fee of
$181 million, compared to
operating costs of $191
million on a same store
basis in 2017, illustrating
cost savings of $10 million
• Q1 Corporate operating
costs include $0.9 million
of audit fees, which were
concentrated in Q1 and
not reflective of the normal
quarterly run rate
Three months ended March 31
2018
(MILLIONS, UNLESS NOTED) Solar Wind Corp Total
Operating costs ($12) ($24) ($7) ($43)
Base management fee - - (2) (2)
Total operating costs ($12) ($24) ($9) ($45)
Annualized
2018
Solar Wind Corp Total
Operating costs ($48) ($97) ($25) ($171)
Base management fee - - (10) (10)
Total operating costs ($48) ($97) ($35) ($181)
Tw elve months ended December 31
2017
Solar Wind Corp Total
Operating costs (1) ($52) ($106) ($31) ($189)
Base management fee - - (2) (2)
Total operating costs ($52) ($106) ($33) ($191)
2018 vs 2017 total operating costs ($10)
(1) Operating costs in 2017 include $5.8 million of costs previously reported as
sustaining capex related to our w ind assets. These costs w ill largely be covered by
our recently signed FSA contracts and so are being reported for all periods as
operating costs.
16
We operate with sufficient liquidity to enable us to fund expected growth initiatives, capital expenditures, and distributions,
and to provide protection against any sudden adverse changes in economic circumstances or short-term fluctuations in
generation.
Principal sources of liquidity are cash flows from operations, our credit facilities, up-financings of subsidiary borrowings
and proceeds from the issuance of securities.
Corporate liquidity and available capital were $1,037 million and $1,210 million, respectively, as of March 31, 2018:
Liquidity
$ 73 $ 47
12 21
Cash available to corporate 85 68
Authorized credit facilities 600 450
Draws on credit facilities (70) (60)
Commitments under revolver (78) (103)
Undrawn Sponsor Line 500 500
952 787
$ 1,037 $ 855
73 60
95 97
5 3
$ 1,210 $ 1,015
Other project-level unrestricted cash
Project-level restricted cash
Project-level credit commitments, unissued
Available capital
(MILLIONS)
Unrestricted corporate cash
Project-level distributable cash
Credit facilities
Available portion of credit facilities
Mar 31
2018
Dec 31
2017
Corporate liquidity
17
Maturity Profile
We finance our assets primarily with project level debt that generally has long-term maturities that amortize
over the contract life, few restrictive covenants and no recourse to either TerraForm Power or other projects.
We have long-dated, staggered debt maturities. We have no meaningful maturities over next four years.
The following table summarizes our scheduled principal repayments, overall maturity profile and average
interest rates associated with our borrowings over the next five years:
Notes 7.6 $ - $ - $ - $ - $ - $ 1,500 $ 1,500 5.1%
Term Loan 4.6 3 4 4 4 336 - 350 4.6%
Revolver (1) 3.5 70 - - - - - 70 4.9%
Total corporate 6.9 73 4 4 4 336 1,500 1,920 5.0%
Utility scale 15.1 34 37 41 44 46 677 879 5.7%
Distributed generation 8.5 9 20 10 10 6 43 98 6.8%
Solar 14.4 44 57 51 53 53 720 977 5.9%
Wind 8.9 46 50 50 51 208 334 740 5.5%
Total non-recourse 12.0 90 107 101 104 261 1,054 1,717 5.7%
Total borrrowings 9.4 $ 163 $ 111 $ 105 $ 108 $ 597 $ 2,554 $ 3,637 5.3%
4% 3% 3% 3% 16% 70%
Revolver is classified as current in 2018 because the majority has been paid off in Q2 2018. The remaining balance and future borrowings are eligible to be rolled over for the duration of facilities’ term
Principal Repayments
Corporate borrowings
Non-recourse debt
2021 2022 Thereafter Total
Weighted
Average
Interest
Rate(MILLIONS)
Weighted
Average
Life
Remainder
of 2018 2019 2020
(1)
18
Our portfolio has a weighted-average remaining contract duration of ~14 years. Over the next five years, contracts
accounting for 10% of our expected generation expire. We are focused on securing long-term contracts to the extent
these contracts expire.
The majority of our long-term power purchase agreements are with investment-grade counterparties. The composition of
our counterparties under power purchase agreements is as follows:
• Public utilities: 70%
• Financial institutions: 21%
• Commercial and industrial customers: 5%
• Government institutions: 4%
The following table sets out our contracted generation over the next five years as a percentage of expected generation.
We currently have a contracted profile of approximately 95% of future generation and our goal is to maintain this profile
going forward.
Contract Profile
For the Year ended December 31 2018 2019 2020 2021 2022
Contracted
Solar 100% 100% 100% 100% 100%
Wind 93% 91% 86% 82% 80%
TERP 95% 93% 90% 86% 85%
Uncontracted
Wind 7% 9% 14% 18% 20%
TERP 5% 7% 10% 14% 15%
19
Appendix 1 - Reconciliation of Non-GAAP Measures
20
Reconciliation of Non-GAAP Measures
for the Three Months Ended March 31
(MILLIONS, EXCEPT AS NOTED) Solar Wind Corp Total Solar Wind Corp Total
Revenue $60 $68 $0 $128 $66 $85 $0 $151
Unrealized (gain) loss on commodity contract derivatives, net (a) - 2 - 2 - (2) - (2)
Amortization of favorable and unfavorable rate revenue contracts, net (b) 1 8 - 9 2 8 - 10
Other non-cash items (c) - - - - (3) - - (3)
Adjustment for asset sales - - - - (7) - - (7)
Adjusted revenues $61 $78 $0 $139 $58 $91 $0 $149
Direct operating costs (d) (12) (24) (7) (43) (11) (26) (9) (46)
Adjusted EBITDA $49 $54 ($7) $96 $47 $65 ($9) $103
Non-operating general and administrative expenses (e) - - (18) (18) - - (25) (25)
Stock-based compensation expense - - - - - - (3) (3)
Acquisition and related costs - - (4) (4) - - - -
Depreciation, accretion and amortization expense (f) (30) (46) - (76) (29) (41) (1) (71)
Impairment charges (15) - - (15) - - - -
Interest expense, net (15) (11) (28) (54) (20) (20) (28) (68)
Income tax benefit - - 1 1 - - 1 1
Adjustment for asset sales - - - - 3 - - 3
Other non-cash or non-operating items (g) (1) (4) (1) (6) 5 1 (2) 4
Net (loss) income ($12) ($7) ($57) ($76) $6 $5 ($67) ($56)
(MILLIONS, EXCEPT AS NOTED) Solar Wind Corp Total Solar Wind Corp Total
Adjusted EBITDA $49 $54 ($7) $96 $47 $65 ($9) $103
Fixed management fee - - (2) (2) - - - -
Variable management fee - - (1) (1) - - - -
Adjusted interest expense (h) (14) (11) (25) (50) (14) (20) (26) (60)
Levelized principal payments (i) (12) (12) - (24) (12) (13) - (25)
Cash distributions to non-controlling interests (j) (3) (2) - (5) (4) (6) - (10)
Sustaining capital expenditures (k) - (2) - (2) - - - -
Other (l) 3 8 - 11 4 7 - 11
Cash available for distribution (CAFD) (m) $23 $35 ($35) $23 $21 $33 ($35) $19
Three Months Ended Three Months Ended
March 31, 2018 March 31, 2017
Three Months Ended Three Months Ended
March 31, 2018 March 31, 2017
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Reconciliation of Non-GAAP Measures
for the Three Months Ended March 31
a) Represents unrealized loss (gain) on commodity contracts associated with energy derivative contracts that are accounted for at fair value with the changes recorded in operating
revenues, net. The amounts added back represent changes in the value of the energy derivative related to future operating periods, and are expected to have little or no net economic
impact since the change in value is expected to be largely offset by changes in value of the underlying energy sale in the spot or day-ahead market.
b) Represents net amortization of purchase accounting related to intangibles arising from past business combinations related to favorable and unfavorable rate revenue contracts.
c) Primarily represents recognized deferred revenue related to the upfront sale of investment tax credits.
d) In the three months ended March 31, 2017, reclassifies $2.3 million wind sustaining capital expenditure into direct operating costs, which will now be covered under new Full Service
Agreement.
e) Pursuant to the management services agreement, SunEdison agreed to provide or arrange for other service providers to provide management and administrative services to us. In the
three months ended March 31, 2017, we accrued $0.4 million of costs incurred for management and administrative services that were provided by SunEdison under the Management
Services Agreement that were not reimbursed by TerraForm Power and were treated as an addback in the reconciliation of net income (loss) to Adjusted EBITDA. In addition, non-
operating items and other items incurred directly by TerraForm Power that we do not consider indicative of our core business operations are treated as an addback in the reconciliation
of net income (loss) to Adjusted EBITDA. These items include extraordinary costs and expenses related primarily to restructuring, legal, advisory and contractor fees associated with the
bankruptcy of SunEdison and certain of its affiliates (the “SunEdison bankruptcy”) and investment banking, legal, third party diligence and advisory fees associated with the Brookfield
transaction, dispositions and financings. The Company’s normal general and administrative expenses, paid by Terraform Power, are the amounts shown below and were not added back
in the reconciliation of net income (loss) to Adjusted EBITDA ($ in millions):
f) Includes reductions (increases) within operating revenues due to net amortization of favorable and unfavorable rate revenue contracts as detailed in the reconciliation of Adjusted
Revenue.
g) Represents other non-cash items as detailed in the reconciliation of Adjusted Revenue and associated footnote and certain other items that we believe are not representative of our core
business or future operating performance, including but not limited to: loss (gain) on foreign exchange (“FX”), unrealized loss on commodity contracts, loss on investments and
receivables with affiliate, loss on disposal of renewable energy facilities, and wind sustaining capital expenditure previously reclassified.
h) Represents project-level and other interest expense and interest income attributed to normal operations. The reconciliation from Interest expense, net as shown on the Unaudited
Condensed Consolidated Statement of Operations to adjusted interest expense applicable to CAFD is as follows:
Q1 2018 Q1 2017
$7 M $9 M
$ in millions Q1 2018 Q1 2017
Interest expense, net ($54) ($68)
Amortization of deferred financing costs and debt discounts 3 5
Adjustment for asset sales - 4
Other 1 (1)
Adjusted interest expense ($50) ($60)
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i) Represents levelized project-level and other principal debt payments to the extent paid from operating cash.
j) Represents cash distributions paid to non-controlling interests in our renewable energy facilities. The reconciliation from Distributions to non-controlling interests as shown on the
Unaudited Condensed Consolidated Statement of Cash Flows to Cash distributions to non-controlling interests, net for the three months ended March 31, 2018 and 2017 is as follows:
k) Represents long-term average sustaining capex starting in 2018 to maintain reliability and efficiency of the assets.
l) Represents other cash flows as determined by management to be representative of normal operations including, but not limited to, wind plant “pay as you go” contributions received from
tax equity partners, interconnection upgrade reimbursements, major maintenance reserve releases or (additions), and releases or (postings) of collateral held by counterparties of energy
market hedges for certain wind plants.
m) CAFD in 2017 was recast as follows to present the levelized principal payments and adjusted interest expense in order to provide period to period comparisons that are consistent and
more easily understood. In the twelve months ended December 31, 2017, CAFD remained $88 million as reported previously.
Reconciliation of Non-GAAP Measures
for the Three Months Ended March 31 (Continued)
$ in millions Q1 2018 Q1 2017
Distributions to non-controlling interests ($6) ($10)
Adjustment for non-operating cash distributions 1 -
Cash distributions to non-controlling interests, net ($5) ($10)
$ in millions Q1 2017 Q2 2017 Q3 2017 Q4 2017 2017
Cash available for distribution (CAFD) before debt service reported $104 $120 $106 $91 $421
Levelized principal payments (25) (25) (25) (24) (99)
Adjusted interest expense (60) (61) (63) (50) (234)
Cash available for distribution (CAFD), recast $19 $34 $18 $17 $88
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Appendix 2 – Additional Information
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Annualized Long-term Average Generation
GENERATION (GWh) (1) Q1 Q2 Q3 Q4 Total
Wind (2)
Central Wind 779 664 445 762 2,650
Texas Wind 454 472 349 438 1,713
Hawaii Wind 66 80 87 74 307
Northeast Wind 324 227 175 297 1,023
1,623 1,443 1,056 1,571 5,693
Solar (3)
NA Utility Solar 219 343 319 193 1,074
International Utility Solar 66 49 52 73 240
DG 114 182 174 101 571
399 574 545 367 1,885
Total 2,022 2,017 1,601 1,938 7,578
(1)
(2)
(3)
LTA is calculated on an annualized basis from the beginning of the year, regardless of the acquisition or commercial operation date.
Wind Long Term Average Annual Generation is the expected average generation resulting from simulations using historical wind speed data normally
from 1997 to 2016 (20 years), adjusted to the specific location and performance of the different wind farms.
Solar Long Term Average Annual Generation is the expected average generation resulting from simulations using historical solar irradiance level data
normally from 1998 to 2016 (19 years), adjusted to the specific location and performance of the different sites.
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Calculation and Use of Non-GAAP Measures
Adjusted Revenue, Adjusted EBITDA and CAFD are supplemental non-GAAP measures that should not be viewed as alternatives to GAAP measures of performance, including
revenue, net income (loss), operating income or net cash provided by operating activities. Our definitions and calculation of these non-GAAP measures may not necessarily be the
same as those used by other companies. These non-GAAP measures have certain limitations, which are described below, and they should not be considered in isolation. We
encourage you to review, and evaluate the basis for, each of the adjustments made to arrive at Adjusted Revenue, Adjusted EBITDA and CAFD.
Calculation of Non-GAAP Measures
We define adjusted revenue as operating revenues, net, adjusted for non-cash items including unrealized gain/loss on derivatives, amortization of favorable and unfavorable rate
revenue contracts, net and other non-cash revenue items.
We define adjusted EBITDA as net income (loss) plus depreciation, accretion and amortization, non-cash general and administrative costs, interest expense, income tax (benefit)
expense, acquisition related expenses, and certain other non-cash charges, unusual or non-recurring items and other items that we believe are not representative of our core business
or future operating performance.
We define “cash available for distribution” or “CAFD” as adjusted EBITDA (i) minus cash distributions paid to non-controlling interests in our renewable energy facilities, if any, (ii) minus
annualized scheduled interest and project level amortization payments in accordance with the related borrowing arrangements, (iii) minus average annual sustaining capital
expenditures (based on the long-sustaining capital expenditure plans) which are recurring in nature and used to maintain the reliability and efficiency of our power generating assets
over our long-term investment horizon, (iv) plus or minus operating items as necessary to present the cash flows we deem representative of our core business operations.
As compared to the preceding period, we revised our definition of CAFD to (i) exclude adjustments related to deposits into and withdrawals from restricted cash accounts, required by
project financing arrangements, (ii) replace sustaining capital expenditures payment made in the year with the average annualized long-term sustaining capital expenditures to maintain
reliability and efficiency of our assets, and (iii) annualized debt service payments. We revised our definition as we believe it provides a more meaningful measure for investors to
evaluate our financial and operating performance and ability to pay dividends. For items presented on an annualized basis, we will present actual cash payments as a proxy for an
annualized number until the period commencing January 1, 2018.
Furthermore, to provide investors with the most appropriate measures to assess the financial and operating performance of our existing fleet and the ability to pay dividends in the
future, we have excluded results associated with our UK solar and Residential portfolios, which were sold in 2017, from adjusted revenue, EBITDA and CAFD reported for all periods.
Use of Non-GAAP Measures
We disclose Adjusted Revenue because it presents the component of operating revenue that relates to energy production from our plants, and is, therefore, useful to investors and
other stakeholders in evaluating performance of our renewable energy assets and comparing that performance across periods in each case without regard to non-cash revenue items.
We disclose Adjusted EBITDA because we believe it is useful to investors and other stakeholders as a measure of financial and operating performance and debt service capabilities.
We believe Adjusted EBITDA provides an additional tool to investors and securities analysts to compare our performance across periods and among us and our peer companies
without regard to interest expense, taxes and depreciation and amortization. Adjusted EBITDA has certain limitations, including that it: (i) does not reflect cash expenditures or future
requirements for capital expenditures or contractual liabilities or future working capital needs, (ii) does not reflect the significant interest expenses that we expect to incur or any income
tax payments that we may incur, and (iii) does not reflect depreciation and amortization and, although these charges are non-cash, the assets to which they relate may need to be
replaced in the future, and (iv) does not take into account any cash expenditures required to replace those assets. Adjusted EBITDA also includes adjustments for goodwill impairment
charges, gains and losses on derivatives and foreign currency swaps, acquisition related costs and items we believe are infrequent, unusual or non-recurring, including adjustments for
general and administrative expenses we have incurred as a result of the SunEdison bankruptcy.
We disclose CAFD because we believe cash available for distribution is useful to investors in evaluating our operating performance and because securities analysts and other
stakeholders analyze CAFD as a measure of our financial and operating performance and our ability to pay dividends. CAFD is not a measure of liquidity or profitability, nor is it
indicative of the funds needed by us to operate our business. CAFD has certain limitations, such as the fact that CAFD includes all of the adjustments and exclusions made to Adjusted
EBITDA described above.
The adjustments made to Adjusted EBITDA and CAFD for infrequent, unusual or non-recurring items and items that we do not believe are representative of our core business involve
the application of management judgment, and the presentation of Adjusted EBITDA and CAFD should not be construed to infer that our future results will be unaffected by infrequent,
non-operating, unusual or non-recurring items.
In addition, these measures are used by our management for internal planning purposes, including for certain aspects of our consolidated operating budget, as well as evaluating the
attractiveness of investments and acquisitions. We believe these Non-GAAP measures are useful as a planning tool because it allows our management to compare performance
across periods on a consistent basis in order to more easily view and evaluate operating and performance trends and as a means of forecasting operating and financial performance
and comparing actual performance to forecasted expectations. For these reasons, we also believe these Non-GAAP measures are also useful for communicating with investors and
other stakeholders.
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http://www.terraformpower.com
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