Attached files
| file | filename |
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| 8-K - 8-K - TerraForm Power NY Holdings, Inc. | terp8-kinvestorcalldeckdec.htm |
Investor Update and Results for 2015 / 1Q 2016
December 15, 2016
Exhibit 99.1
2
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 TerraForm Power expects or anticipates will occur in the future are forward-looking statements. They may include
estimates of expected adjusted EBITDA, cash available for distribution (CAFD), earnings, revenues, adjusted revenues, capital expenditures, liquidity, capital
structure, future growth, 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 TerraForm Power’s
current expectations or predictions of future conditions, events, or results and speak only as of the date they are made. Although TerraForm Power 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.
By their nature, forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those suggested by
the forward-looking statements. Factors that might cause such differences include, but are not limited to, risks related to the SunEdison Bankruptcy, including
our transition away from reliance on SunEdison for management, corporate and accounting services, employees, critical systems and information technology
infrastructure, and the operation, maintenance and asset management of our renewable energy facilities; risks related to events of default and potential
events of default arising under our revolving credit facility, the indentures governing our senior notes, and/or project-level financing; risks related to failure to
satisfy the requirements of Nasdaq, which could result in the delisting of our common stock; risks related to our exploration and potential execution of strategic
alternatives; pending and future litigation; our ability to integrate the projects we acquire from third parties or otherwise realize the anticipated benefits from
such acquisitions; 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 successfully identify, evaluate, and consummate acquisitions; government regulation, including
compliance with regulatory and permit requirements and changes in market rules, rates, tariffs, environmental laws and policies affecting renewable energy;
operating and financial restrictions under agreements governing indebtedness; 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; our ability to compete against traditional and renewable energy companies; potential conflicts of interests or distraction due to the fact that most of
our directors and executive officers are also directors and executive officers of TerraForm Global, Inc.; and hazards customary to the power production
industry and power generation operations, such as unusual weather conditions and outages. Furthermore, any dividends are subject to available capital,
market conditions, and compliance with associated laws and regulations. Many of these factors are beyond TerraForm Power’s control.
TerraForm Power 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 TerraForm Power’s Form 10-K for the fiscal year ended December 31, 2015, as well as additional factors it may describe
from time to time in other filings with the Securities and Exchange Commission. 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.
Forward-Looking Statements
Exhibit 99.1
3
This presentation provides certain financial and operating metrics of TerraForm Power, Inc. (“TerraForm
Power” or the “Company”) as of or for the fiscal years and quarter ended December 31, 2015 and 2014 and
the quarters ended March 31, 2016 and 2015 and estimates for certain financial and operating metrics of
TerraForm Power for 2016 and 2017.
Please review these results together with the risk factors detailed in our annual report on Form 10-K for the
fiscal year ended December 31, 2015 filed with the SEC.
The financial information for full year 2016 and 2017 is preliminary and unaudited and includes estimates
which are inherently uncertain. This financial information may change materially as a result of the completion
of the audits for fiscal year 2016 and 2017 and review procedures for 2Q 2016, 3Q 2016, 1Q 2017, 2Q 2017
and 3Q 2017. Our estimates are based on various assumptions and are subject to various risks which could
cause actual results to differ materially. The information presented on the following slides does not represent
a complete picture of the financial position, results of operation or cash flows of TerraForm Power, is not a
replacement for full financial statements prepared in accordance with U.S. GAAP and should not be viewed
as indicative of future results, which may differ materially.
The Company’s last annual or quarterly report was its Form 10-Q for the period ended March 31, 2016. The
Company has not filed its Forms 10-Q for the periods ended June 30, 2016 or September 30, 2016. You
should refer also to the unaudited financial information for the fiscal quarter 2Q 2016 and the other filings we
have made with the SEC.
Importance of our Risk Factors
Exhibit 99.1
TerraForm Power Remains Focused on Key Areas of Execution
2016 was a year of transition and immense change
TERP team is successfully navigating challenges and is preparing for
2017 as a well-functioning, independent company
TERP fleet continues to perform well
Solid progress on moving TERP to a stand-alone entity, expansion of
board to 10 members, including 6 independents
Recent Canada financing reduces Holdco debt and strengthens balance
sheet
10-K for 2015 and 10-Q for 1Q 2016 filed; working towards full compliance
with all periodic reporting requirements by Nasdaq deadline of March 2017
Collaborating with SunEdison on strategic review process with aim of
maximizing value for all shareholders
4
Exhibit 99.1
5
Estimates: 2016 and 2017 Key Metrics
Agenda
3
1 High-Quality, Diversified Renewable Power Fleet
2 Results: 4Q 2015, FY 2015, and 1Q 2016
Exhibit 99.1
6
3.0 GW Wind and Solar Portfolio …
Exclusively renewable assets
Portfolio as of October 31, 2016
With Estimated Average 27 Year
Remaining Useful Life …
Average asset age of 3 years
With High Credit-Quality Counterparties
High quality average credit rating of A-;
86% rated investment grade
1
Under Long-Term Contracts …
Average remaining PPA life of 15 years
11-15 years
46%
16-20 years
24%
20+ years
18%
6-10 years
2%
0-5 years
10%
2-7 Years
68%
<2 Years
32%
AAA
1%
AA+
14%
AA
8%
AA-
1%
A+
13%
A
4%
A-
15%
BBB+
23%
BBB
4%
BBB-
3%
< IG
4%
NR
10%
Solar
49%
Wind
51%
1. 10% not rated; 4% rated non-investment grade
(MW Weighted)
(MW Weighted)(MW Weighted)
Best-in-Class Contracted Renewable Generation Portfolio
Exhibit 99.1
7
Low Concentration RiskGeographically Diverse Fleet of 3.0 GW
Solar and Wind Portfolio as of October 31, 2016
Mt. Signal
9% South
Plains I
7%
California
Ridge
7%
Bishop Hill
6%
Rattlesnake
6%
Prairie
Breeze
6%Cohocton
4%
CAP
3%
Other
(all < 3%)
52%
1. TerraForm Power is considering a sale of certain of its UK assets
CAISO
17%
ISO-NE
13%
ERCOT
13%
PJM
10%
MISO
6%
SPP
6%
NYISO
6%
WECC
3%
SERC
2%
Other
24%
(MW Weighted)
Wind
1,532 MW
Solar
1,456 MW
Total U.S.: 2,364 MW U.S. Wind: 1,454 MW U.S. Solar: 910 MW
Canada
145 MW
78 MW
68 MW
Chile
102 MW
102 MW
UK 1
376 MW
376 MW
OR – 1 MW MN – 2 MW
NE – 181 MW
NV – 32 MW
UT – 42 MW
CO – 12 MW
CA – 501 MW
TX – 387 MW Wind
1 MW Solar
HI – 81 MW Wind
1 MW Solar
OH – 10 MW
ME – 219 MW
NH – 1 MW
VT – 40 MW Wind
8 MW Solar
MA – 123 MW
CT – 1 MW
NY – 160 MW Wind
16 MW Solar
NJ – 63 MW
PA – 8 MW
MD – 19 MW
NC – 36 MW
IL – 386 MW
GA – 5 MW
FL – 9 MW
PR – 5 MW
NM – 1 MW
AZ – 12 MW
Diverse Asset Portfolio in Attractive and Stable Markets
Exhibit 99.1
8
1. Revenue adjusted for PPA amortization, changes in fair value of commodity hedges and ITC revenue amortization
2. 4Q 2015 and FY 2015 CAFD figures reflect revised restricted cash accounting policy
From 2014 to 2015, TERP’s fleet size more than tripled
Over 75% of fleet additions in 2015 were wind plants (1,532 MW), resulting in higher portfolio capacity factors, lower
price per MWh contracts, and lower gross margins (due to higher cost of operations)
Balanced mix of wind and solar power plants provides diversification and results in more consistent revenue
quarter-to-quarter as wind plants deliver stronger results during the winter months when solar resource is lower
Metric 4Q 2015 4Q 2014
YoY change
(%)
2015 2014
YoY change
(%)
MW, Net in Operation
(Period End)
2,931 928 216% 2,931 928 216%
MWh (000s) 1,069 266 302% 3,462 722 379%
Capacity Factor 22.9% 14.3% +860 bps 22.3% 16.5% +580 bps
Adj. Revenue / MWh $100 $162 -38% $135 $181 -25%
Revenue, net ($M) $106 $43 147% $470 $127 269%
Adj. Revenue ($M) 1 $107 $43 149% $467 $131 257%
Net Income / (Loss) ($M) ($156) ($63) n/a ($208) ($82) n/a
Adj. EBITDA ($M) $72 $34 110% $358 $109 229%
Adj. EBITDA Margin 67.1% 79.6% (1,240) bps 76.6% 83.4% (670) bps
CAFD ($M) $23
2
$17 35% $228
2
$67 241%
4Q 2015 and FY 2015 Results
Exhibit 99.1
9
1. Revenue adjusted for PPA amortization, changes in fair value of commodity hedges and ITC revenue amortization
1Q 2016 operating fleet
performance ahead of
management expectations
driven by prudent project
cost management
Wind plants acquired from
Invenergy in the Midwest,
Texas and Canada have
higher capacity factor, lower
average price/MWh, and
higher margins vs. existing
TERP wind fleet in the
Northeast and Hawaii
CAFD increased less than
EBITDA primarily due to
impact of new debt incurred /
assumed
Metric 1Q 2016 1Q 2015
YoY
change
(%)
MW, Net in Operation (Period End) 2,977 1,675 78%
MWh (000s) 2,072 602 244%
Capacity Factor 30.9% 20.8% +1,010 bps
Adj. Revenue1 / MWh $78 $124 -37%
Revenue, net ($M) $154 $71 118%
Adj. Revenue ($M)1 $162 $75 116%
Net Income / (Loss) ($M) ($34) ($84) n/a
Adj. EBITDA ($M) $120 $52 130%
Adj. EBITDA Margin 74.5% 69.8% +460 bps
CAFD ($M) $61 $45 37%
1Q 2016 Results
Commentary
Exhibit 99.1
10
1. The figures provided are projections for year-end 2016 and 2017 and are based on various assumptions and estimates regarding the Company’s future operations and performance. These assumptions and estimates
may not prove to be correct and actual results could differ materially due to various factors, many of which are not within the control of the Company. In addition, estimated results should not be viewed as indicative of the
Company’s expectations for future periods. Please see “Importance of our Risk Factors” and “Forward-Looking Statements”.
2. Excludes approximately $64M of non-operating cash costs expected to be incurred in 2016 (costs that are not representative of our core operations)
3. If some existing defaults are not resolved by deadline for 2016 CAFD reporting, up to approximately $100M of project level cash, that is currently projected as 2016 CAFD, could be shifted to 2017 CAFD.
Metric
Estimate
20161
Estimate
2017
MW, Net in Operation (Period End) 2,987 ~2,700
MWh (000s) 7,670 - 7,830 7,200 - 8,400
Capacity Factor 28% - 29% 30% - 35%
Revenue, net ($M) $665 - $675 $570 - $670
Adj. Revenue ($M) $700 - $710 $600 - $700
Adj. Revenue / MWh $89 - $91 ~$83
Net Income ($M) ($145) - ($105) ($50) - $50
Adj. EBITDA ($M)2 $520 - $530 $430 - $510
Adj. EBITDA Margin 78% 72%
CAFD ($M) $165 - $1853 $120 - $160
2016 estimates of key
financial metrics substantially
in-line with management
expectations post-SunEdison
bankruptcy
2016 forecast assumes that all
project-level defaults are
resolved and resulting
reclassifications of project
cash from restricted to
unrestricted favorably impacts
2016 CAFD estimate
If some existing defaults are
not resolved by deadline for
2016 CAFD reporting, up to
approximately $100M of
project level cash, that is
currently projected as 2016
CAFD, could be shifted to
2017 CAFD
2016 and 2017 Estimates
Commentary
Exhibit 99.1
11
CAFD Walk from 2015 to 2016 Estimate
CAFD (Period Ending December 31)1
$M, unless otherwise noted
1. The figures provided include estimates for the year ended 2016 and are based on various assumptions and estimates regarding the Company’s future operations and performance. These assumptions and estimates may
not prove to be correct and actual results could differ materially due to various factors, many of which are not within the control of the Company. In addition, estimated results for year-end 2016 should not be viewed as
indicative of the Company’s expectations for future periods. Please see “Importance of our Risk Factors” and “Forward-Looking Statements”.
2. 2015 CAFD includes $22M from Invenergy after project-level debt payments
3. Includes loss of $22M of G&A support, loss of $4M of capex reimbursement, and loss of $3M of interest payment support
$175
Midpoint
$165 - $185
3
2
Exhibit 99.1
12
$705M
Midpoint
Adj. Revenue
2016 Revenue to CAFD Waterfall
$M, unless otherwise noted
2016 Estimates1
$525M
Midpoint
Adj.
EBITDA2
$175M
Midpoint
CAFD
1. The figures provided are projections for 2016 and are based on various assumptions and estimates regarding the Company’s future operations and performance. These assumptions and estimates may not prove to be
correct and actual results could differ materially due to various factors, many of which are not within the control of the Company. In addition, estimated results for 2016 should not be viewed as indicative of the Company’s
expectations for future periods. Please see “Importance of our Risk Factors” and “Forward-Looking Statements”.
2. Excludes approximately $64M of non-operating cash costs expected to be incurred in 2016 (costs that are not representative of our core operations)
3. Does not include special interest payment of $12M
$670M
Midpoint
Revenue
2
3
Exhibit 99.1
13
CAFD Walk from 2016 to 2017 Estimates
$3
$22
$17
$6
2016 Range SunEdison
support
UK debt
amortization &
other
Net impact
of potential
UK sale
Canada
financing
Impact of
potential 2017
actions
2017 Range
$120 - $160
CAFD (Period Ending December 31)
$140
Midpoint
$M, unless otherwise noted
Management is evaluating options for 2017 to optimize the portfolio and capital structure
Potential actions that may impact CAFD include:
– UK portfolio sale
– Upsize of Canada project financing
– Paydown or refinancing of various corporate or project-level credit facilities
– Opportunistic divestiture or acquisition opportunities
$175
Midpoint
$165 - $185
1. The figures provided include estimates for the years ended 2016 and 2017 and are based on various assumptions and estimates regarding the Company’s future operations and performance. These assumptions and
estimates may not prove to be correct and actual results could differ materially due to various factors, many of which are not within the control of the Company. In addition, estimated results for years ended 2016 and 2017
should not be viewed as indicative of the Company’s expectations for future periods. Please see “Importance of our Risk Factors” and “Forward-Looking Statements”.
2. Includes $14M of lost G&A support from SunEdison and $8M of lost interest payment support
3. Net impact of previously announced $90M Canada financing partially offset by a $70M revolver paydown using a portion of the resulting proceeds. Potential upsize of facility by up to C$123M under evaluation.
2
1
3
Exhibit 99.1
Appendix
14
Exhibit 99.1
15
Metric
Preliminary figures
As of Sept. 30, 2016
Holdco unrestricted cash $496
Project-level unrestricted cash $38
Project-level restricted cash3 $225
Total Cash $759
Drawn Revolver1 $6551
Sr. Notes $1,250
Non-recourse debt2 ~$2,600
Gross Holdco debt $1,905
Net Holdco debt $1,409
Gross consolidated debt $4,505
Net consolidated debt $3,971
Financial Metrics (midpoint of 2016 range)
Adj. EBITDA $525
CFADS $279
CAFD $175
Credit Metrics (midpoint of 2016 range)
Net Holdco debt / CFADS 5.0x
Net consolidated debt / Adj. EBITDA 7.6x
Capital Structure
$M, unless otherwise noted
Definitions and Calculations:
CFADS: CAFD before Holdco debt service payments
Net Holdco debt: Gross Holdco debt less Holdco unrestricted cash
Gross consolidated debt: Drawn Revolver plus Senior Notes and non-recourse debt
Net consolidated debt: Gross consolidated debt less Holdco and project-level unrestricted cash
1. Reduced to $555 million as of 12/1/2016
2. Estimate (excludes net unamortized discount and deferred financing costs)
3. $55 million of restricted cash was classified as held for sale as of September 30, 2016
Exhibit 99.1
16
Change to CAFD Reporting Methodology and Presentation of CAFD reg. G
Reconciliation
Effective December 31, 2015, we have changed our method of presenting the reconciliation of cash available for distribution (CAFD) to begin with
adjusted EBITDA (as presented in our reconciliation of net income (loss) to adjusted EBITDA), instead of from net cash provided by operating
activities. The new method produces materially the same result for CAFD, is consistent with our view that CAFD is primarily a business
performance metric, and presents the reconciliation of CAFD in a format we believe improves investor understanding of our performance. In
addition, at December 31, 2015 we adopted an updated policy for accounting for restricted cash. The impact of this change in accounting policy
is reflected in our final reconciliation of CAFD as presented below and impacts the timing of CAFD realization during the year. The annual impact
is generally immaterial. The presentation of CAFD using the Cash From Operations method is provided below to demonstrate the consistency of
outcome with the adjusted EBITDA method, and will be discontinued following this presentation.
Net Cash Provided by Operating Activities Method 1Q 2Q 3Q 4Q 2015
Net cash provided by operating activities ($11) $46 $70 $19 $124
Change in asset and liabilities 11 4 (5) (48) (38)
Deposits into/withdraws from restricted cash accounts 8 5 5 (0) 19
Cash distributions to non-controlling interests (9) (3) (5) (6) (23)
Scheduled project level and other debt service and repayments (1) (11) (7) (27) (46)
Contributions received pursuant to agreements with SunEdison (s) 6 3 6 – 15
Non-expansionary capital expenditures – (4) (1) (8) (13)
Other:
Acquisition and related costs, including affiliates (g) 14 7 11 23 56
Change in accrued interest 9 (8) 11 (6) 6
General & administrative expenses (e) 5 17 14 16 51
LAP settlement payment (l) – – – 10 10
Eastern Maine Electric Cooperative litigation reserve (m) – – – 14 14
Non-recurring facility-level non-controlling interest member transaction fees (n) 3 – – 1 4
Economic ownership adjustments (t) 7 6 – 40 53
Other items 3 0 (2) (5) (4)
Estimated cash available for distribution $45 $63 $97 $23 $228
Adjusted EBITDA Method 1Q 2Q 3Q 4Q 2015
Adjusted EBITDA $52 $107 $126 $72 $358
Interest payments on debt (20) (41) (24) (52) (138)
Principal payments on debt (1) (11) (7) (27) (46)
C sh i t i utions to non-controlling interests (9) (3) (5) (6) (23)
De its i t /withdraws from restricted cash accounts 8 5 5 (0) 19
Non-expansionary capital expenditures – (4) (1) (8) (13)
Other: – – – – –
Contributions received pursuant to agreements with SunEdison (s) 6 3 6 – 15
Economic ownership adjustments (t) 7 6 – 40 53
Other items 2 (0) (3) 5 4
Estimated cash available for distribution $45 $63 $97 $23 $228
Exhibit 99.1
17
Definitions: Adjusted Revenue and Adjusted EBITDA
Reconciliation of Operating Revenues, Net to Adjusted Revenue
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 believe adjusted revenue is useful to investors in evaluating our operating performance because securities analysts
and other interested parties use such calculations as a measure of financial performance. Adjusted revenue is a non-
GAAP measure used by our management for internal planning purposes, including for certain aspects of our
consolidated operating budget.
Reconciliation of Net Income (Loss) to Adjusted EBITDA
We define adjusted EBITDA as net income (loss) plus depreciation, accretion and amortization, non-cash affiliate
general and administrative costs, acquisition related expenses, interest expense, gains (losses) on interest rate swaps,
foreign currency gains (losses), income tax (benefit) expense and stock compensation expense, 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. Our definitions and calculations of these items may not necessarily be the
same as those used by other companies. Adjusted EBITDA is not a measure of liquidity or profitability and should not
be considered as an alternative to net income, operating income, net cash provided by operating activities or any other
measure determined in accordance with U.S. GAAP.
Note: As of December 31, 2015, TerraForm Power changed its policy regarding restricted cash to characterize the
following as restricted cash: (i) cash on deposit in collateral accounts, debt service reserve accounts, maintenance and
other reserve accounts, and (ii) cash on deposit in operating accounts but subject to distribution restrictions due to debt
defaults, or other causes. Previously, cash available for operating purposes, but subject to compliance procedures and
lender approvals prior to distribution from project level accounts, was also considered restricted. This cash is now
considered unrestricted but is designated as unavailable for immediate corporate purposes. The impact of the new
accounting policy on full year reported or forecasted CAFD is immaterial.
Exhibit 99.1
18
Definitions: Cash Available For Distribution (CAFD)
CAFD is not a measure of liquidity or profitability and should not be considered as an alternative to net income, operating income,
net cash provided by operating activities or any other measure determined in accordance with U.S. GAAP
Reconciliation of Cash Provided by Operating Activities to CAFD
We have historically defined “cash available for distribution” or “CAFD” as net cash provided by operating activities of Terra
LLC as adjusted for certain other cash flow items that we associate with our operations. It is a non-GAAP measure of our ability to
generate cash to service our dividends. Cash available for distribution represents net cash provided by (used in) operating
activities of Terra LLC (i) plus or minus changes in assets and liabilities as reflected on our statement of cash flows, (ii) minus
deposits into (or plus withdrawals from) restricted cash accounts required by project financing arrangements to the extent they
decrease (or increase) cash provided by operating activities, (iii) minus cash distributions paid to non-controlling interests in our
projects, if any, (iv) minus scheduled project-level and other debt service payments and repayments in accordance with the related
borrowing arrangements, to the extent they are paid from operating cash flows during a period, (v) minus non-expansionary capital
expenditures, if any, to the extent they are paid from operating cash flows during a period, (vi) plus cash contributions
from SunEdison pursuant to the Interest Payment Agreement, (vii) plus operating costs and expenses paid
by SunEdison pursuant to the Management Services Agreement to the extent such costs or expenses exceed the fee payable by
us pursuant to such agreement but otherwise reduce our net cash provided by operating activities and (viii) plus or minus
operating items as necessary to present the cash flows we deem representative of our core business operations, with the approval
of the audit committee.
Reconciliation of Adjusted EBITDA to CAFD
Effective December 31, 2015, we define “cash available for distribution” or “CAFD” as adjusted EBITDA of Terra LLC as adjusted
for certain cash flow items that we associate with our operations. Cash available for distribution represents adjusted EBITDA (i)
minus deposits into (or plus withdrawals from) restricted cash accounts required by project financing arrangements to the extent
they decrease (or increase) cash provided by operating activities, (ii) minus cash distributions paid to non-controlling interests in
our renewable energy facilities, if any, (iii) minus scheduled project-level and other debt service payments and repayments in
accordance with the related borrowing arrangements, to the extent they are paid from operating cash flows during a period, (iv)
minus non-expansionary capital expenditures, if any, to the extent they are paid from operating cash flows during a period, (v) plus
or minus operating items as necessary to present the cash flows we deem representative of our core business operations, with the
approval of the audit committee.
Exhibit 99.1
19
Reg G: Reconciliation of Net Operating Revenue to Adjusted Revenue,
Net Income / (Loss) to Adjusted EBITDA and Adjusted EBITDA to CAFD
$M, unless otherwise noted
Reconciliation of Revenue to Adjusted Revenue 2014 1Q 2015 2Q 2015 3Q 2015 4Q 2015 2015 1Q 2016
2016
Midpoint
2017
Midpoint
Operating revenues, net $127 $71 $130 $163 $106 $470 $154 $670 $620
Unrealized loss on derivatives, net (a) – 4 (2) (3) 2 1 (0) 7 –
Amortization of favorable and unfavorable rate revenue contracts, net (b) 4 (0) 5 (3) 4 5 11 42 40
Other non-cash items (c) (1) 0 (1) (4) (4) (9) (2) (14) (10)
Adjusted revenue $131 $75 $132 $153 $107 $467 $162 $705 $650
Reconciliation of Net Loss to Adjusted EBITDA
Net income (loss) ($82) ($84) $29 $2 ($156) ($208) ($34) ($125) $0
Interest expense, net 86 37 36 49 46 168 69 281 203
Income tax benefit (5) (0) 1 2 (16) (13) 0 3 –
Depreciation, accretion and amortization expense (d) 45 32 43 40 51 167 70 278 246
General and administrative expenses (e) 19 7 16 14 14 51 16 74 12
Stock-based compensation expense (f) 6 5 2 3 2 12 1 5 8
Acquisition and related costs, including affiliate (g) 15 14 7 11 23 56 3 4 –
Loss on prepaid warranty with affiliate (h) – – – – 45 45 – – –
Formation and offering related fees and expenses, including affiliate (i) 5 – – – – – – – –
Unrealized loss on derivatives, net (j) – 4 (2) (3) 2 1 (0) 5 –
Loss (gain) on extinguishment of debt, net (k) (8) 20 (11) – 8 16 – – –
LAP settlement payment (l) – – – – 10 10 – – –
Eastern Maine Electric Cooperative litigation reserve (m) – – – – 14 14 – – –
Non-recurring facility-level non-controlling interest member transaction fees (n) 12 3 – – 1 4 – – –
Loss (gain) on foreign currency exchange, net (o) 14 14 (14) 10 10 19 (3) – –
Loss on investments and receivables with affiliate (p) – – – – 16 16 1 – –
Other non-cash operating revenues (q) (1) – – (4) (5) (9) (2) – –
Other non-operating expenses (r) 1 – – 2 6 8 1 – –
Adjusted EBITDA $109 $52 $107 $126 $72 $358 $120 $525 $470
Reconciliation of Adjusted EBITDA to CAFD
Adjusted EBITDA $109 $52 $107 $126 $72 $358 $119 $525 $470
Interest payments (41) (20) (41) (24) (52) (138) (58) (249) (209)
Principal payments (24) (1) (11) (7) (27) (46) (8) (87) (98)
Cash distributions to non-controlling interests, net (2) (9) (3) (5) (6) (23) (3) (24) (18)
Non-expansionary capital expenditures – 8 5 5 (0) 19 (3) (14) (19)
Deposits into/withdraws from restricted cash accounts 20 – (4) (1) (8) (13) (8) (1) 0
Other: – – – – – – – – –
Contributions received pursuant to agreements with SunEdison (s) 5 6 3 6 – 15 8 8 –
Economic ownership adjustments (t) – 7 6 – 40 53 – – –
Other items 0 2 (0) (3) 5 4 15 16 14
Estimated cash available for distribution $67 $45 $63 $97 $23 $228 $61 $175 $140
Exhibit 99.1
20
(1/3) Footnotes to Reg. G
a) Represents the change in the fair value of commodity contracts not designated as hedges.
b) Represents net amortization of favorable and unfavorable rate revenue contracts included within operating revenues, net.
c) Primarily represents deferred revenue recognized related to the upfront sale of investment tax credits to non-controlling interest members.
d) Includes the following reductions, (increases) and forecasted reductions within operating revenues, due to net amortization of favorable and unfavorable rate revenue contracts for
the following periods:
e) Pursuant to the MSA, SunEdison agreed to provide or arrange for other service providers to provide management and administrative services to us. For the year ended December
31, 2015, cash considerations as detailed in the following table were paid to SunEdison for these services, and the amount of general and administrative expense - affiliate in excess
of the fees paid to SunEdison in each period will be 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 will be treated as an addback in the reconciliation of net income (loss)
to Adjusted EBITDA. The Company’s normal general administrative expenses, not paid by SunEdison, are not added back in the reconciliation of net income (loss) to Adjusted
EBITDA. For the quarter ended March 31, 2016, the year ending December 31, 2016, and the year ending December 31, 2017, Terraform Power directly paid to, or estimates direct
payments to, suppliers for normal operating general and administrative expenses of the amounts shown below.
f) Represents stock-based compensation expense recorded within general and administrative expenses in the consolidated statements of operations. Excludes $1.0 million of stock-
based compensation expense for both the three months and year ended December 31, 2015 related to equity awards in the stock of SunEdison that was allocated to the Company
and recorded within general and administrative expenses – affiliate in the consolidated statement of operations.
g) Represents transaction related costs, including affiliate acquisition costs, associated with acquisitions.
h) In conjunction with the First Wind Acquisition, SunEdison committed to reimburse us for capital expenditures not to exceed $50.0 million through 2019 for certain of our wind power
plants in the form of a prepaid warranty that was capitalized as PP&E in purchase accounting. Through the year ended December 31, 2015, the Company received contributions
pursuant to this agreement of $2.7 million and recorded depreciation on the related asset of $1.9 million. As a result of the SunEdison Bankruptcy, the Company recorded a loss of
$45.4 million related to the write-off of this prepaid warranty agreement, which is no longer considered collectible.
i) Represents Formation and offering related fees and expenses and Formation and offering related fees and expenses – affiliate reflected in the consolidated statement of operations.
These fees consist of professional fees for legal, tax, and accounting, and other services related to our IPO.
j) Represents the unrealized change in the fair value of commodity contracts not designated as hedges.
2014 1Q 2015 2Q 2015 3Q 2015 4Q 2015 2015 1Q 2016 2016 Forecast 2017 Forecast
$4.2M $336 $5.0M ($3.4M) $3.7M $5.3M $8.9M $40.0M $40.0M
2014 1Q 2015 2Q 2015 3Q 2015 4Q 2015 2015 1Q 2016 2016 Forecast 2017 Forecast
$0 $0.7M $1.3M $1.0M $1.0M $4.0M $2.3M $14.0M $27.0M
Exhibit 99.1
21
(2/3) Footnotes to Reg. G
k) We recognized net losses and (gains) on extinguishment of debt for the following credit facilities during the periods shown:
l) Pursuant to the Settlement Agreement, TERP made a one-time payment to LAP in the amount of $10.0 million in April 2016 in exchange for and contingent on the termination of the
Arbitration against TERP. The expense incurred as a result of the one-time payment was recorded to general and administrative expenses for the year ended December 31, 2015.
m) Represents a loss reserve related to the legal judgment awarded to the Eastern Maine Electric Cooperative against certain of our subsidiaries for breach of contract over the
proposed sale of a transmission line acquired from First Wind.
n) Represents professional fees for legal, tax, and accounting services related to entering into certain tax equity financing arrangements that were paid by SunEdison, and are not
representative of our core business operations.
o) Represents net losses and (gains) on foreign currency exchange, primarily due to unrealized gains/losses on the re-measurement of intercompany loans which are primarily
denominated in British pounds.
p) As a result of the SunEdison Bankruptcy, we recognized an $11.3 million loss on investment as a result of residential project cancellations during the three months and year
ended December 31, 2015. Further, we recognized an additional $4.8 million loss related to recording a bad debt reserve for outstanding receivables from debtors in
the SunEdison bankruptcy during the same periods.
q) Primarily represents deferred revenue recognized related to the upfront sale of investment tax credits to non-controlling interest members.
r) Represents certain other non-cash charges or non-operating items that we believe are not representative of our core business or future operating performance.
$M 2014
1Q
2015
2Q
2015
3Q
2015
4Q
2015 2015
1Q
2016
2016
Forecast
2017
Forecast
Term Loan /HY Note extinguishment and related fees -- $12.3 -- -- -- $12.3 $0 -- $12.0
Revolver -- 1.3 -- -- -- 1.3 -- -- --
First Wind -- 6.4 -- -- -- 6.4 -- -- --
Duke Energy operating facility -- -- (11.4) -- -- (11.4) -- -- --
U.K. refinancing -- -- -- -- 7.5 7.5 -- -- --
U.S. Projects 2009-2013 2.5 -- -- -- -- -- -- -- --
Alamosa 1.9 -- -- -- -- -- -- -- --
Stonehenge Operating 3.8 -- -- -- -- -- -- -- --
SunE Solar Fund X (15.8) -- -- -- -- -- -- -- --
Exhibit 99.1
22
(3/3) Footnotes to Reg. G
s) We received an equity contribution of $5.4M and $4.0 million from SunEdison pursuant to the Interest Payment Agreement for the years ended December 31,
2014 and December 31, 2015, respectively. We received an equity contribution from SunEdison of $6.6 million and $8.0 million pursuant to the Amended Interest
Payment Agreement during the year ended December 31, 2015 and the three months ended March 31, 2016, respectively. In addition, in conjunction with the First
Wind Acquisition, SunEdison committed to reimburse us for capital expenditures and operations and maintenance labor fees in excess of budgeted amounts (not
to exceed $50.0 million through 2019) for certain of our wind power plants. During the year ended December 31, 2015, the Company received contributions
pursuant to this agreement of $4.3 million. No contributions were received pursuant to these agreements during the three months ended June 30, 2016.
t) Represents economic ownership of certain acquired operating assets which accrued to us prior to the acquisition close date. The amount recognized for the year
ended December 31, 2015 primarily related to our acquisition of Invenergy Wind, First Wind, and Northern Lights. Per the terms of the Invenergy Wind acquisition,
we received economic ownership of the Invenergy Wind assets effective July 1, 2015 and $39.6 million of CAFD accrued to us from July 1, 2015 through the
December 15, 2015 closing date. Per the terms of the First Wind acquisition, we received economic ownership of the First Wind operating assets effective January
1, 2015 and $7.2 million of CAFD accrued to us from January 1, 2015 through the January 29, 2015 closing date. Per the terms of the Northern Lights acquisition,
we received economic ownership of the Northern Lights facilities effective January 1, 2015 and $3.7 million of CAFD accrued to us from January 1, 2015 through
the June 30, 2015 closing date. The remaining $2.7 million of economic ownership related to our acquisitions of Moose Power and Integrys, which both closed in
the second quarter of 2015.
Exhibit 99.1
23
Exhibit 99.1