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•	our electricity generation, our projections thereof and factors affecting production, including wind, solar and other conditions, other weather conditions, availability and curtailment;

•	our ability to manage exposure to project development risks;

•	our ability to complete acquisitions and dispositions of power projects;

•	our ability to complete construction of construction projects and transition them into financially successful operating projects;

•	fluctuations in supply, demand, prices and other conditions for electricity, other commodities and renewable energy credits (RECs);

•	changes in law, including applicable tax laws;

•	public response to and changes in the local, state, provincial and federal regulatory framework affecting renewable energy projects, including those related to taxation, the U.S. federal production tax credit (PTC), investment tax credit (ITC) and potential reductions in Renewable Portfolio Standards (RPS) requirements;

•	the ability of our counterparties to satisfy their financial commitments or business obligations;

•	the availability of financing, including tax equity financing, for our power projects;

•	an increase in interest rates and the discontinuation of LIBOR;

•	our substantial short-term and long-term indebtedness, including additional debt in the future;

•	competition from other power project developers;

•	development constraints, including the availability of interconnection and transmission;

•	potential environmental liabilities and the cost and conditions of compliance with applicable environmental laws and regulations;

•	our ability to operate our business efficiently, manage capital expenditures and costs effectively and generate cash flow;

•	our ability to retain and attract executive officers and key employees;

•	our ability to keep pace with and take advantage of new technologies;

•	the effects of litigation, including administrative and other proceedings or investigations, relating to power projects in development, under construction and those in operation;

•	conditions in energy markets as well as financial markets generally, which will be affected by interest rates, foreign currency exchange rate fluctuations and general economic conditions;

•	the effectiveness of our currency risk management program;

•	the effective life and cost of maintenance of our wind turbines, solar panels and other equipment;

•	the increased costs of, and tariffs on, spare parts;

•	scarcity of necessary equipment;

•	negative public or community response to power projects;

•	the value of collateral in the event of liquidation; and

•	other factors discussed under "Risk Factors."

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•	“Amazon Wind” refers to Fowler Ridge IV Wind Farm LLC, a wind project located in Benton County, Indiana;

•	“Armow” refers to SP Armow Wind Ontario LP, a wind project located in Kincardine, Ontario, Canada;

•	“Broadview” collectively refers to Broadview Finco Pledgor LLC (Broadview Project), consisting of Broadview Energy KW, LLC and Broadview Energy JN, LLC, a wind project located in Curry County, New Mexico, and Western Interconnect;

•	“El Arrayán” refers to Parque Eólico El Arrayán SpA, a wind farm located in Ovalle, Chile (we disposed of our interests in El Arrayán on August 20, 2018);

•	“ERCOT” refers to the Electric Reliability Council of Texas;

•	“FERC” refers to the U.S. Federal Energy Regulatory Commission;

•	“FIT” refers to feed-in-tariff regime;

•	“FPA” refers to the Federal Power Act;

•	“Futtsu” refers to GK Green Power Futtsu, a solar project located in Chiba Prefecture, Japan;

•	“GPG” refers to Green Power Generation GK which consists primarily of 100% ownership in Ohorayama, Otsuki and Kanagi, and a consolidated controlling interest in Futtsu;

•	“GPI” refers to Green Power Investment Corporation;

•	“Grand” refers to Grand Renewable Wind LP, a wind project located in Haldimand County, Ontario, Canada;

•	“Gulf Wind” refers to Pattern Gulf Wind LLC, a wind project located in Kenedy County, Texas;

•	“Hatchet Ridge” refers to Hatchet Ridge Wind, LLC, a wind project located in Shasta County, California;

•	“Identified ROFO Projects” refers to projects that we have identified as development projects, owned by either of the Pattern Development Companies and subject to our Project Purchase Rights. See Identified ROFO Projects list in Item 1. Business;

•	“IPPs” refers to independent power producers;

•	“ISOs” refers to independent system organizations, which are organizations that administer wholesale electricity markets;

•	“ITCs” refers to investment tax credits;

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•	“K2” refers to K2 Wind Ontario Limited Partnership, a wind project located in Ashfield-Colborne-Wawanosh, Ontario, Canada (we disposed of our interests in K2 on December 31, 2018);

•	“Kanagi” refers to GK Green Power Kanagi, a solar wind project located in Shimane Prefecture, Japan;

•	“kWh” refers to kilowatt hour;

•	“Logan's Gap” refers to Logan's Gap Wind LLC, a wind project located Comanche County, Texas;

•	“Lost Creek” refers to Lost Creek Wind, LLC, a wind project located in DeKalb County, Missouri;

•	“Meikle” refers to Meikle Wind Energy L.P., a wind project located in Peace Region, British Columbia, Canada;

•	“MSM” refers to Mont Sainte-Marguerite Wind Farm Limited Partnership, a wind project located in Chaudiére-Appalaches, Quebec, Canada;

•	“Multilateral Management Services Agreement” (MSA) refers to the amended and restated multilateral services agreement between us and each of the Pattern Development Companies;

•	“MW” refers to megawatts;

•	“MWh” refers to megawatt hours;

•	“Non-Competition Agreement” refers to the second amended and restated non-competition agreement between us and each of the Pattern Development Companies in which we and each of the Pattern Development Companies have agreed to various arrangements with respect to how we may and may not compete with each other;

•	“Ocotillo” refers to Ocotillo Express LLC, a wind project located in Imperial County, California;

•	“Ohorayama” refers to GK Green Power Otsuki, a wind project located in Kochi Prefecture, Japan;

•	“Otsuki” refers to GK Otsuki Wind Power (formerly known as Otsuki Wind Power Corporation), a wind project located in Kochi Prefecture, Japan;

•	“Panhandle 1” refers to Pattern Panhandle Wind LLC, a wind project located in Carson County, Texas;

•	“Panhandle 2” refers to Pattern Panhandle Wind 2 LLC, a wind project located in Carson County, Texas;

•	“Pattern Canada Operations Holdings ULC” consists primarily of 100% ownership of St. Joseph, a consolidated controlling interest in Meikle and MSM, and a noncontrolling interest in Armow, Grand, K2 (which we disposed of on December 31, 2018) and South Kent, each of which are accounted for as unconsolidated investments;

•	“Pattern Development” refers to Pattern Energy Group 2 LP, a Delaware limited partnership, and, where the context so requires, its subsidiaries. We hold an approximate 29% ownership interest in Pattern Development;

•	“Pattern Development Companies” refers collectively to Pattern Energy Group LP and Pattern Development and their respective subsidiaries;

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“Pattern Development Companies Purchase Rights” refer collectively to our right to acquire Pattern Energy Group LP or substantially all of its assets, as contemplated by the Amended and Restated Purchase Rights Agreement between us and Pattern Energy Group LP (Pattern Energy Group LP Purchase Right) and to our right to acquire Pattern Development or substantially all of its assets, as contemplated by the Amended and Restated Purchase Rights Agreement between us and Pattern Development (Pattern Development Purchase Right);

•	“Pattern Energy Group LP” refers to Pattern Energy Group LP, a Delaware limited partnership, and, where the context so requires, its subsidiaries;

•	“Pattern US Operations Holdings LLC” consists primarily of 100% ownership interest of Gulf Wind, Hatchet Ridge, Lost Creek, Ocotillo, Santa Isabel and Spring Valley, and a consolidated controlling interest in Amazon Wind, Broadview, Logan's Gap, Panhandle 1, Panhandle 2, Post Rock, Stillwater and Western Interconnect;

•	“Post Rock” refers to Post Rock Wind Power Project, LLC, a wind project located in Ellsworth and Lincoln counties, Kansas;

•	“PPAs” refer to power purchase agreements;

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“Project Purchase Rights” refers collectively to our right of first offer with respect to power projects that Pattern Energy Group LP decides to sell, as contemplated by the Amended and Restated Purchase Rights Agreement between us and Pattern Energy Group LP, and our right of first offer with respect to power projects that Pattern Development decides to sell, as contemplated by the Amended and Restated Purchase Rights Agreement between us and Pattern Development (in each case including any Identified ROFO Projects);

•	“PSAs” or “power sale agreements” refer to PPAs and/or hedging arrangements, as applicable;

•	“PSP Investments” refers to the Public Sector Pension Investment Board;

•	“Purchase Rights” refers collectively to the Project Purchase Rights, and the Pattern Development Companies Purchase Rights, as contemplated by the Amended and Restated Purchase Rights Agreement between us and Pattern Energy Group LP and the Amended and Restated Purchase Rights Agreement between us and Pattern Development;

•	“RECs” refers to renewable energy credits;

•	“Riverstone” refers to Riverstone Holdings LLC;

•	“ROFO” refers to right of first offer;

•	“RPS” refers to Renewable Portfolio Standards;

•	“Santa Isabel” refers to Pattern Santa Isabel LLC, a wind project located in Santa Isabel, Puerto Rico;

•	“Sarbanes-Oxley Act” refers to the Sarbanes-Oxley Act of 2002;

•	“South Kent” refers to South Kent Wind LP, a wind project located in Chatham-Kent, Ontario, Canada;

•	“Spring Valley” refers to Spring Valley Wind LLC, a wind project located in White Pine County, Nevada;

•	“St. Joseph” refers to St. Joseph Windfarm Inc., a wind project located in Montcalm, Manitoba, Canada;

•	“Stillwater” refers to Stillwater Wind, LLC, a wind project located in Stillwater County, Montana;

•	“Tsugaru” refers to Green Power Tsugaru GK, a wind project located in Aomori Prefecture, Japan;

•	“Tsugaru Holdings” refers to Green Power Tsugaru Holdings GK, which consists primarily of 100% ownership of Tsugaru; and

•	“Western Interconnect” refers to Western Interconnect LLC, a transmission line located in Curry County, New Mexico.

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•	creating a safe and high-integrity work environment for our employees;

•	applying rigorous analysis to all aspects of our business in a timely, disciplined and functionally integrated manner to understand patterns in wind and solar regimes, technology developments, market trends and regulatory, financial and legal constraints; and

•	working proactively with our stakeholders to address environmental and community concerns, which we believe is a socially responsible approach that also benefits our business by reducing operating risks at our projects.

•	produce stable and sustainable cash available for distribution;

•	selectively grow our project portfolio and our dividend per Class A share of common stock; and

•	maintain a strong balance sheet and flexible capital structure.

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•	an approximate 13 year weighted average remaining contract life under our PSAs;

•	92% of electricity to be generated by our projects will be sold under PSAs;

•	an ‘A-’ weighted average off-taker credit rating; and

•	4.9-year average age of fleet, primarily using GE and Siemens turbines.

•	multiple years of on-site wind and solar data tied to one or more long-term wind and solar energy reference sources;

•	long-term contractually secured real estate property and easement rights;

•	right to firm interconnection to the electricity grid;

•	all requisite construction and operating permits and regulatory approvals;

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•	fixed-price turbine supply and construction contracts with guaranteed completion dates;

•	an operations and maintenance service program based on on-site personnel and central operations management. See “- Management, Operations, Maintenance and Administration of Projects in which We Have an Owned Interest” below; and

•	safety, environmental and community programs that support the project.

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(1)	Represent wind projects unless otherwise noted.

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(2)	Rated capacity represents the maximum electricity generating capacity of a project in MW. As a result of weather and other conditions, a project will not operate at its rated capacity at all times and the amount of electricity generated may be less than its rated capacity. The amount of electricity generated may vary based on a variety of factors.

(3)	Owned capacity represents the maximum, or rated, electricity generating capacity of the project in MW multiplied by our percentage ownership interest in the distributable cash flow of the project.

(4)	Represents the approximate percentage of a project’s total estimated average annual MWh of electricity generation contracted under power purchase agreements or hedge arrangements.

(5)	Reflects the counterparty’s or counterparty guarantor's corporate credit ratings issued by either Standard and Poor's (S&P) or Moody’s, or both S&P and Moody's, as of December 31, 2018.

(6)	Independent Electricity System Operator (IESO) acts as the settlement agent under the respective PPA.

(7)	Projects that are maintained through self-performance of maintenance and service activities.

•	service arrangements with reputable external third-parties;

•	our self-performance of maintenance and service activities; or

•	a combination of both of the above.

•	Selecting good opportunities in which to invest;

•	Minimizing the capital at risk during the early development stages;

•	De-risking projects through long-term offtake contracts and other arrangements so that, during the construction phase, projects have the potential to be sold (if needed) for good development returns; and

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•	Minimizing the duration of the relatively higher capital outlays that are required once a project has achieved an advanced stage.

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Our investment in Pattern Development. We have the right, but not the obligation, to make capital commitments of up to $300 million to Pattern Development as a part of an approximately $1 billion of capital commitments which Pattern Development has secured from long-term focused investors. Through February 28, 2019, we have invested a total of $183 million into Pattern Development, representing an approximate 29% ownership interest.

•	Project Purchase Rights. Pursuant to contractual arrangements we have with Pattern Development, we have (among other things) a right of first offer with respect to power projects that Pattern Development decides to sell. See also “- Identified ROFO Projects” below.

•	Our Executive Officers Oversee the Business Operations of Pattern Development. Under the shared service arrangements discussed further below, our executive officers provide executive management services to Pattern Development. Such executive officers, who are employed and compensated by us, devote such of their time that is prudent to carry out those executive responsibilities.

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Shared Services Arrangements. Under the MSA, we have shared services arrangements with each of Pattern Development and Pattern Energy Group LP. Such arrangements are intended to allow each of us, Pattern Development, and Pattern Energy Group LP to make their respective personnel available to others in the group to provide certain shared services. Under these arrangements, Pattern Development makes available its personnel to assist us in managing, operating, maintaining, and administering our projects in Japan.

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(1)	Represents year of actual or anticipated commencement of construction.

(2)	Represents year of actual or anticipated commencement of commercial operations.

(3)	Rated capacity represents the maximum electricity generating capacity of a project in MW. As a result of weather and other conditions, a project will not operate at its rated capacity at all times and the amount of electricity generated may be less than its rated capacity. The amount of electricity generated may vary based on a variety of factors.

(4)	Pattern Development Companies-Owned capacity represents the maximum, or rated, electricity generating capacity of the project in MW multiplied by Pattern Energy Group LP's or Pattern Development's percentage ownership interest in the distributable cash flow of the project.

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Efficiency. We seek to improve our margins through the expansion of our self-perform maintenance initiative as service agreements expire at projects, applying technological advances which emerge to deliver incremental efficiencies for turbines or projects such as the retrofit of hardware onto turbines (for example, dinotails), and upgrading software to more efficiently manage high-speed flow through, each at a cost that delivers positive returns over the length of the project.

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Scale. We also intend to improve our existing assets and business processes to reduce the marginal cost of overhead. We can achieve this through areas such as system enhancements and increased automation. We have implemented new systems as a result of this review which we expect will deliver incremental efficiencies and margin expansion from overhead savings and improved workflow. We intend to continue to manage overhead costs though additional back office optimization.

•	match assets with liabilities based on a project’s off-take tenor and currency denomination;

•	fix or hedge project debt on a long-term basis;

•	amortize our third-party project finance capital within the tenor of the off-take arrangement; and

•	apply conservative debt service coverage or tax equity structuring standards.

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•	our projects’ failure to produce sufficient electricity to meet our commitments under our PPAs, hedge arrangements or contracts for sale of RECs, which could result in our having to purchase electricity or RECs on the open market to cover our obligations or result in the payment of damages or the termination of a PPA;

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our projects not generating sufficient cash flow to make payments of principal and interest as they become due on project-related debt, distributing sufficient cash flow to pay dividends to holders of our Class A shares, or service our corporate debt. For example, certain of our projects have experienced lower than expected production and merchant power prices, as well as congestion on transmission systems upon which such projects rely upon, resulting in those projects failing to pass financial tests that measure cumulative cash distributions to the members. This has in the past, and may in the future, result in a temporary change of the cash percentage to be directed to the tax equity members until the shortfall is remedied. See “-Risks Related to Ownership of our Class A Shares - Our cash available for distribution to holders of our Class A shares may be reduced as a result of restrictions on our subsidiaries’ cash distributions to us under the terms of their indebtedness, or in the event certain specified events occurred under our tax equity arrangements that change the percentage of cash distributions to be made to the tax equity investors;” and

•	our projects’ hedging arrangements being ineffective or more costly.

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•	inclement weather conditions;

•	failure to receive generating equipment or other critical components and equipment necessary to maintain the operating capacity of our projects, in a timely manner or at all;

•	failure to complete interconnection to transmission networks, which relies on several third parties, including interconnection facilities provided by local utilities;

•	failure to maintain all necessary rights to land access and use;

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•	failure to receive quality and timely performance of third-party services;

•	failure to maintain environmental and other permits or approvals;

•	failure to meet domestic content requirements;

•	appeals of environmental and other permits or approvals that are held;

•	lawful or unlawful protests by or work stoppages resulting from local community objections to a project;

•	shortage of skilled labor or key construction equipment on the part of contractors;

•	geopolitical risks including risk of tax and tariff law changes;

•	adverse environmental and geological conditions; and

•	force majeure or other events out of our control.

•	difficulty with staffing and managing overseas operations, which may be exacerbated as a result of distance, time zone, language, and cultural differences;

•	difficulties and costs relating to compliance with different commercial, legal and regulatory requirements;

•	failure to develop appropriate risk management and internal control structures tailored to overseas operations;

•	challenges in coordinating and integrating systems, policies, and procedures, such as operational, financial and accounting, and information technology;

•	the need to devote a significant amount of our management’s time and effort to integrate and coordinate the international operations with our other operations; and

•	fluctuations in currency exchange rates.

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•	competing bids for a project, including a project subject to our respective Purchase Rights, from other owners, including companies that may have substantially greater capital and other resources than we do;

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fewer acquisition opportunities than we expect from both third-parties and the Pattern Development Companies, which could result from, among other things, available projects having less desirable economic returns or higher risk profiles than we believe suitable for our business plan and investment strategy. After, in part, consideration of such factors, in 2018 we had waived our Purchase Rights with respect to various projects at each of the Pattern Development Companies;

•

failure by Pattern Development to complete the development of (i) an Identified ROFO Project, which could result from, among other things, permitting challenges, failure to procure the requisite financing, equipment or interconnection, local opposition to the project which may entail litigation, or an inability to satisfy the conditions to effectiveness of project agreements such as PPAs and (ii) any of the other projects in its respective development pipeline, in a timely manner, or at all, in either case, which could limit our acquisition opportunities under our respective Purchase Rights and/or the value of our investment in Pattern Development; and

•	our failure to exercise our respective Purchase Rights or acquire assets from Pattern Energy Group LP or Pattern Development.

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•	failure to comply with the covenants in the agreements governing these obligations could result in an event of default under those agreements, or, under certain circumstances, cross-default to other debt instruments, which could be difficult to cure, or result in our bankruptcy;

•	in the event a project is unable to meet its debt service obligations through its own project cash flows, excess cash flow from other projects may be required to help service such obligations, thereby reducing funds available to pay dividends;

•	in the event a project is unable to meet its debt service obligations, it may result in a foreclosure on the project collateral and loss of the project;

•	our limited financial flexibility could reduce our ability to plan for and react to unexpected opportunities;

•	our substantial debt service obligations make us vulnerable to adverse changes in general economic, credit and capital markets, industry and competitive conditions and adverse changes in government regulation, and place us at a disadvantage compared with competitors with less debt; and

•	the need to repay or otherwise refinance maturing indebtedness which we may not be able to do on favorable terms or at all. For example, we have issued $225 million of 4.0% convertible senior notes which mature on July 15, 2020 and we have issued $350 million of 5.875% unsecured senior notes which mature on February 1, 2024.

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•	requiring us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, dividend payments, development activity, acquisitions and other general corporate purposes;

•	increasing our vulnerability to adverse general economic or industry conditions;

•	limiting our flexibility in planning for, or reacting to, changes in our business or the industries in which we operate;

•	making us more vulnerable to increases in interest rates, as borrowings under our revolving credit facility are at variable rates;

•	limiting our ability to obtain additional financing in the future for working capital or other purposes; and

•	placing us at a competitive disadvantage compared to our competitors that have less indebtedness.

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•	the public’s reaction to our press releases, our other public announcements and our filings with the Canadian securities regulators and the SEC;

•	changes in, or failure to meet, earnings estimates or recommendations by research analysts who track our Class A shares or the stock of other companies in our industry;

•	the failure of research analysts to cover our Class A shares;

•	changes in accounting standards, policies, guidance, interpretations or principles;

•	sales of Class A shares by us or members of our management team;

•	the granting or exercise of employee stock options; and

•	volume of trading in our Class A shares.

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•	authorize the issuance of blank check preferred stock that our Board of Directors could issue to increase the number of outstanding shares and to discourage a takeover attempt;

•	prohibit our stockholders from calling a special meeting of stockholders;

•	prohibit stockholder action by written consent, which requires all stockholder actions to be taken at a meeting of our stockholders;

•	provide that the Board of Directors is expressly authorized to adopt, or to alter or repeal our bylaws; and

•	establish advance notice requirements for nominations for election to our Board of Directors or for proposing matters that can be acted upon by stockholders at stockholder meetings.

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•	2018 Significant Activity

•	Factors that Significantly Affect our Business

◦	Trends Affecting our Industry

◦	Factors Affecting our Operational Results

•	Key Performance Metrics

•	Results of Operations

•	Liquidity and Capital Resources

◦	Sources of Liquidity

◦	Uses of Liquidity

◦	Covenants, Distribution Conditions and Events of Default

•	Critical Accounting Policies and Estimates

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•	In December 2018, we sold our 33.3% owned interest in the 270 MW K2 project in Ontario, Canada, for cash proceeds of $158 million.

•	In November 2018, we acquired 35 MW of owned capacity as a Class B member in Stillwater, an 80 MW project in Stillwater County, Montana, for cash proceeds of $24 million.

•	In September 2018, we committed to a plan to repower the 283 MW Gulf Wind project starting in 2019. We entered into a turbine purchase agreement for a maximum purchase price of $151 million, depending upon the number of turbines purchased.

•	In August 2018, we sold our 74% owned interest in the 115 MW El Arrayán project in Chile, for a sale price of $70 million.

•	In August 2018, we acquired a 51% owned interest in the 143 MW Mont Sainte-Marguerite project in Québec, for cash proceeds of $39 million.

•	In 2018, we funded approximately $115 million into Pattern Development which increased our ownership interest to 29%.

•	In March 2018, we acquired 206 MW of owned capacity in five Japanese projects which represents our entry into Japan, for approximately $177 million of cash and post-closing contingent payments. The fair value of such contingent payments is approximately $106 million.

•	consistent multi-year trend of total global investment in new renewable electricity generation sources being twice that of investment in conventional fossil generation;

•	efficiency and capital cost improvements in wind, solar and other renewable energy technologies, enabling wind, solar and other forms of renewable energy to compete successfully in more markets;

•	improvements in wind, solar and other renewable energy technologies which, when paired with cheap natural gas, continues to drive down power prices;

•	significant ongoing demand created by corporate and industrial buyers directly procuring renewable electricity on a large scale;

•	increasing deployment of storage technologies resulting in enhanced reliability and provision of grid services by utility scale wind and solar providers;

•	increased demand for renewable energy resulting from regulatory or policy initiatives. Notable initiatives include country, state or provincial RPS programs;

•	governmental incentives for renewable energy including feed-in-tariff regimes, carbon credits and the U.S. federal based PTCs or ITCs, which are subject to phase down for wind projects that begin construction by 2019 and solar projects that begin construction by 2021, that improve the cost competitiveness of renewable energy compared to traditional sources;

•	environmental and social factors supporting increasing levels of wind, solar and other renewable technologies in the generation mix;

•	regulatory barriers, market pressure and public acceptance challenges increasing the time, cost and difficulty of permitting new fossil fuel-fired facilities, notably coal, and nuclear facilities;

•	decommissioning of aging coal-fired and nuclear facilities is expected to leave a gap in electricity supply to be filled by cost-effective renewable and natural gas generation;

•	policy initiatives at both the state and federal levels to include externalities, such as the cost of carbon pollution, methane leakage and water usage in conventional fossil fuel-fired electricity generation, over time will increase costs of conventional generation; and

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•	ongoing shift within the portfolios of U.S based investor-owned utilities toward lower carbon emitting sources of power.

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(1)	Represents year of actual or anticipated commencement of construction.

(2)	Represents year of actual or anticipated commencement of commercial operations.

(3)	Rated capacity represents the maximum electricity generating capacity of a project in MW. As a result of weather and other conditions, a project will not operate at its rated capacity at all times and the amount of electricity generated may be less than its rated capacity. The amount of electricity generated may vary based on a variety of factors.

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(4)	Pattern Development Companies-Owned capacity represents the maximum, or rated, electricity generating capacity of the project in MW multiplied by Pattern Energy Group LP's or Pattern Development's percentage ownership interest in the distributable cash flow of the project.

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•	Adjusted EBITDA

•	does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;

•	does not reflect changes in, or cash requirements for, our working capital needs;

•	does not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on our debt, or our proportional interest in the interest expense of our unconsolidated investments or the cash requirements necessary to service interest or principal payments on the debt borne by our unconsolidated investments;

•	does not reflect our income taxes or the cash requirement to pay our taxes; or our proportional interest in income taxes of our unconsolidated investments or the cash requirements necessary to pay the taxes of our unconsolidated investments;

•	does not reflect depreciation, amortization and accretion which are non-cash charges; or our proportional interest in depreciation, amortization and accretion of our unconsolidated investments. The assets being depreciated, amortized and accreted will often have to be replaced in the future, and Adjusted EBITDA does not reflect any cash requirements for such replacements; and

•	does not reflect the effect of certain mark-to-market adjustments and non-recurring items or our proportional interest in the mark-to-market adjustments at our unconsolidated investments.

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We do not have control, nor have any legal claim to the portion of the unconsolidated investees' revenues and expenses allocable to our joint venture partners. As we do not control, but do exercise significant influence, we account for the unconsolidated investments in accordance with the equity method of accounting. Net earnings from these investments are reflected within our consolidated statements of operations in "Earnings in unconsolidated investments, net." Adjustments related to our proportionate share from unconsolidated investments include only our proportionate amounts of interest expense, income taxes, depreciation, amortization and accretion, and mark-to-market adjustments included in "Earnings in unconsolidated investments, net;" and

•	Other companies in our industry may calculate Adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure.

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•	Cash available for distribution:

◦	excludes depreciation, amortization and accretion;

◦	does not capture the level of capital expenditures necessary to maintain the operating performance of our projects or complete the construction of acquired projects;

◦	is not reduced for principal payments on our project indebtedness except to the extent they are paid from operating cash flows during a period; and

◦	excludes the effect of certain other cash flow items, all of which could have a material effect on our financial condition and results from operations.

•	Other companies in our industry may calculate cash available for distribution differently than we do, limiting its usefulness as a comparative measure.

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•	a $33 million decrease in our proportionate share of Adjusted EBITDA from unconsolidated investments;

•	a $13 million increase in project expenses; and

•	a $7 million increase in transmission costs.

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•	a $49 million increase in revenues (excluding unrealized loss on energy derivative and amortization of PPAs) primarily attributable to projects which were acquired or commenced commercial operations in 2017; and

•	a $21 million increase in our proportionate share of Adjusted EBITDA from unconsolidated investments.

•	a $21 million increase in project expense and transmission cost;

•	a $7 million increase in operating expenses; and

•	a $1 million increase in transaction cost.

•	an $18 million increase in distributions to noncontrolling interests;

•	a $13 million increase in project expenses;

•	a $9 million decrease in total distributions from unconsolidated investments;

•	a $9 million increase in interest expense (excluding amortization of financing costs and debt discount/premium) primarily due to additional debt associated with our acquisitions;

•	an $8 million decrease in network upgrade reimbursement;

•	a $7 million increase in transmission costs; and

•	a $3 million decrease in release of restricted cash.

•	a $49 million increase in revenues (excluding unrealized loss on energy derivative and amortization of PPAs) driven by projects acquired during 2017;

•	a $11 million increase in total distribution from unconsolidated investments;

•	a $7 million increase in release of restricted cash to fund project costs; and

•	a $5 million increase in network upgrade reimbursement primarily related to Broadview.

•	a $23 million increase in interest expense (excluding amortization of financing costs and debt discount/premium) primarily due to the issuance of the unsecured senior notes in January 2017 and debt associated with our acquisitions;

•	a $21 million increase in transmission cost and project expense;

•	a $7 million increase in operating expenses;

•	a $4 million increase in principal payments of project-level debt; and

•	a $2 million increase in distributions to noncontrolling interests.

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•	Consolidated MWh sold for any period presented, represents 100% of MWh sold by wholly-owned and partially-owned subsidiaries in which we have a controlling interest and are consolidated in our consolidated financial statements;

•	Noncontrolling interest MWh represents that portion of partially-owned subsidiaries not attributable to us;

•	Controlling interest in consolidated MWh is the difference between the consolidated MWh sold and the noncontrolling interest MWh;

•	Unconsolidated investments proportional MWh is our proportion in MWh sold from our equity method investments;

•	Proportional MWh sold for any period presented, represents the sum of the controlling interest and our percentage interest in our unconsolidated investments; and

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Average realized electricity price for each of consolidated MWh sold, unconsolidated investments proportional MWh sold, and proportional MWh sold represents (i) total revenue from electricity sales for each of the respective MWh sold, discussed above, excluding unrealized gains and losses on our energy derivative and the amortization of long-lived intangible assets and liabilities, divided by (ii) the respective MWh sold.

•	a decrease in volume of 392,361 MWh due to a reduction in our proportional ownership interest at Panhandle 2 at the end of 2017 and the sale of El Arrayán in 2018;

•	a decrease in volume of 34,607 MWh in controlling interest in consolidated MWh primarily due to unfavorable wind; and

•	a decrease in volume of 35,020 MWh from unconsolidated investments primarily due to curtailment.

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•	an increase in volume of 917,166 MWh as a result of acquisitions in 2017; and

•	a 254,443 MWh increase in volume from projects that existed in 2016 primarily due to favorable wind conditions.

•	an increase in volume of 748,277 MWh from controlling interest in consolidated MWh primarily due to acquisitions in 2017 and favorable wind conditions partially offset by lower availability; and

•	an increase in volume of 239,576 MWh from unconsolidated investments due to the acquisition of Armow in the fourth quarter of 2016 and favorable wind conditions, partially offset by lower availability.

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•	an increase in electricity sales due to a $82 million increase in volume as a result of acquisitions in 2018 and 2017, partially offset by a $12 million decrease in electricity sales attributable to the sale of El Arrayán, and a $6 million increase in unrealized losses on our energy derivative; and

•	a $6 million increase in other revenue, primarily due to a settlement for business interruption insurance for Santa Isabel.

•	a $54 million increase in electricity sales driven by projects acquired in 2017;

•	an $18 million increase in electricity sales due to favorable wind availability and an increase in PPA contractual volumes for Amazon Wind; and

•	a $9 million decrease in unrealized loss on our energy derivative primarily due to lower forward natural gas price curves when compared to the prior period.

•	a $5 million decrease related to an interruption caused principally by a hurricane in Puerto Rico; and

•	a $16 million decrease driven by the presence of ERCOT market congestion.

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•	a $7 million and a $13 million increase in transmission costs and project expense, respectively, for costs associated with projects acquired in 2017 and 2018; and

•	a $51 million increase in depreciation, which is primarily attributable to $26 million of accelerated depreciation related to our repowering project and $23 million related to acquisitions completed in 2017 and 2018.

•	a $19 million and a $12 million increase in transmission costs and project expense, respectively, for costs associated with projects acquired in 2017; and

•	a $24 million increase in depreciation, primarily due to projects acquired in 2017.

•	a $5 million increase in employee related costs primarily to support growth in employee headcount;

•	a $5 million net increase in professional fees and other general administration expense; and

•	a $4 million increase in related party general and administrative expense.

•	a $70 million increase in net gain on transactions primarily as a result of the gain on sale of our minority interest in K2;

•	a $26 million increase in gain on derivatives primarily due to a $23 million favorable impact from foreign currency exchange rates and a $3 million favorable impact due to interest rate swaps; and

•	a $2 million decrease in the extinguishment of debt.

•	a $41 million decrease in equity in earnings of unconsolidated investments, net, which is primarily attributable to equity losses associated with our investment in Pattern Development;

•	a $11 million increase in other expense, net primarily related to a $9 million increase in contingent liability accretion associated with acquisitions and a $3 million sublease loss related to our former San Francisco office; and

•	a $7 million increase in interest expense primarily due to debt acquired in conjunction with acquisitions in 2017 and 2018.

•	a $24 million increase in interest expense primarily due to the issuance of unsecured senior notes in January 2017 and debt associated with our acquisitions in 2017;

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•	a $9 million increase in early extinguishment loss associated with Ocotillo debt;

•	a $7 million increase in loss on derivatives primarily as a result of an unfavorable impact from foreign currency exchange rates and a realized loss due to the termination of the interest rate swaps; and

•	a $3 million increase in net losses on transactions and accretion expense primarily related to the acquisition of the Broadview Project.

•	a $72 million increase in total revenue, as discussed above; and

•	a $41 million decrease in other expense primarily consisting of the gain on sale of our noncontrolling interest in K2, favorable foreign currency exchange rates, partially offset by increased contingent liability accretion, a decrease in equity in earnings of unconsolidated investments and an increase in interest expense.

•	a $71 million increase in cost of revenues primarily related to increased depreciation as a result of acquisitions and accelerated depreciation at our repowering project;

•	a $20 million increase in the tax provision; and

•	a $9 million increase in operating expenses primarily related to impairment expense at El Arrayán.

•	a $44 million increase in cost of revenues due primarily to acquisitions in 2017;

•	a $32 million increase in other expense primarily related to increases in interest expense, early extinguishment loss, losses on derivatives due to unfavorable impacts from foreign currency exchange rates and the termination of the interest rate swaps;

•	a $8 million increase in operating expense, as discussed above; and

•	a $3 million increase in the tax provision.

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•	match assets with liabilities based on a project’s off-take tenor and currency denomination;

•	fix or hedge project debt on a long-term basis;

•	amortize our third-party project finance capital within the tenor of the off-take arrangement; and

•	apply conservative debt service coverage or tax equity structuring standards.

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(1)	As of February 22, 2019, the amount available on the revolving credit facilities was $152 million.

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•	$788 million in proceeds from debt and revolving credit facilities; and

•	$98 million in contributions from noncontrolling interest.

•	$588 million in repayments of debt and revolving credit facilities;

•	$165 million of dividend payments;

•	$38 million in distributions to noncontrolling interests; and

•	$9 million in payments for deferred financing costs primarily associated with the issuance of debt associated with Tsugaru Holdings.

•	$694 million in net proceeds from the issuance of long-term debt;

•	$237 million in net proceeds from equity issuances, net of expenses;

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•	$333 million in draws on the corporate revolving credit facility; and

•	$58 million in proceeds from the partial sale of Panhandle 2.

•	$513 million in repayments of the corporate revolving credit facility;

•	$483 million in repayment of long-term debt;

•	$145 million in dividend payments;

•	$20 million in distributions to noncontrolling interests;

•	$16 million in financing fee payments; and

•	$14 million in termination of designated derivatives payment.

•	$350 million in repayments of the corporate revolving credit facility;

•	$120 million in dividend payments;

•	$48 million in repayment of long-term debt; and

•	$18 million in distributions to noncontrolling interests.

•	$286 million in net proceeds from equity issuances, net of expenses; and

•	$175 million in draws on the corporate revolving credit facility.

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•	to the extent the project has letter of credit facilities under the project debt, there are no letter of credit loans outstanding;

•	to the extent the project has reserve requirements, accounts are fully funded;

•	any mandatory prepayment required has been made;

•	no default has occurred and such distribution will not result in an event of default; and

•	the applicable project has met its debt service coverage ratio.

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•	The amount of purchase price allocated to the various tangible and intangible assets, liabilities and noncontrolling interests on our consolidated balance sheets;

•	The amounts of purchase price allocated to the value of above-market and below-market power purchase agreement, which is subsequently amortized to electricity sales over the remaining terms of each respective arrangement; and

•	The period of time over which tangible and intangible assets are depreciated or amortized varies, and thus, changes in the amounts allocated to these assets will have a direct impact on our results of operations.

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(1)	Mr. Michael J. Lyon who currently serves as the chief financial officer will transition to the role of president of the Company;

(2)	Mr. Esben W. Pedersen who currently serves as the chief investment officer (and is a named executive officer) will transition to the role of chief financial officer of the Company where, in such role, he would also continue to perform his current responsibilities as chief investment officer; and

(3)	Mr. Michael M. Garland who currently serves as both the chief executive officer and president will continue to serve in the role of chief executive officer of the Company.

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*	These certifications accompany this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed “filed” by the Company for purposes of Section 18 of the Exchange Act.

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(1)	The Company sold its interest in El Arrayán on August 20, 2018. See Note 4, Divested Operations.

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(1)	As noted above, prior period amounts have not been adjusted under the modified retrospective method.

(2)	Includes revenue from PSAs accounted for as leases and energy hedge contracts.

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(1)	Refer to Corporate Revolving Credit Facility for interest rate details.

(2)	The amortization for the St. Joseph term loan and the Meikle term loan are through September 2036 and December 2038, respectively, which differs from the stated maturity date of such loans due to prepayment requirements.

(3)	Includes impact of interest rate swaps. See Note 12, Derivative Instruments, for discussion of interest rate swaps.

(4)	The discount relates to the 2020 Notes and MSM term loans.

(5)	Refer to Japan Credit Facility for interest rate details.

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(6)	The El Arrayán EKF term loan and El Arrayán commercial term loan were included as part of the Chilean Sale on August 20, 2018. The Spring Valley term loan was prepaid in full on December 31, 2018.

(7)	Refer to "Project Debt - Western Interconnect" below for additional borrowing details.

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(1)	Included in the consolidated balance sheets as additional paid-in capital, net of $1 million in equity issuance costs.

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(1)	Reflects non-cash additions due to acquisitions and construction during the year ended December 31, 2018. See Note 5, Acquisitions, for discussion of acquisitions.

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(1)	Represents price per MWh

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(1)	Noncontrolling interest of El Arrayán was derecognized as a result of the sale of the Company's operation in Chile.

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(1)

On December 22, 2017, the Tax Act was signed into law, which enacted major changes to the U.S. federal income tax laws, including a permanent reduction in the U.S. federal corporate income tax rate from 35% to 21%, effective January 1, 2018. Reduction in the corporate income tax rate resulted in a one-time reduction in the noncontrolling interests attributable to partners in its tax equity partnerships. As part of the liquidation waterfall, the Company allocated significantly lower portions of the hypothetical liquidation proceeds to compensate certain noncontrolling interest investors for tax gains on the hypothetical sale calculated at the lowered rate of 21% as compared to the rate of 35% that was previously utilized. For the year ended December 31, 2018, included in net loss attributable to noncontrolling interests is a one-time adjustment of $150 million as a result of the decrease in the federal corporate income tax rate.

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(1)	The expected volatility was estimated using the historical volatility derived from the Company's Class A common stock.

(2)	The expected performance period was estimated based on the length of the remaining performance period from the grant date.

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(1)	Amounts represent the Company's proportionate share in Pattern Development.

(2)	The Company accounts for its investment in Pattern Development under the equity method. Therefore, the reconciling amounts are presented to eliminate Pattern Development and to reconcile to the consolidated totals.

(3)	Included in Corporate, Other and Eliminations is a $35 million loss related to the Company's portion of the loss of Pattern Development and the elimination of intra entity profits of approximately $5 million.

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(1)	As discussed in Note 16. Stockholders' Equity, for the three months ended March 31, 2018, included in net loss attributable to noncontrolling interests is a one-time adjustment of $150 million as a result of the decrease in the federal corporate income tax rate.

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1	General information

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3	Restricted cash

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4	Property, plant and equipment

5	Intangible assets

6	Long-term debt

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7	Asset retirement obligation

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8	Derivatives

9	Fair value measurement

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10	Commitments and contingencies

1)	Commitments

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2)	Contingencies

11	Related party transactions

a)	Management, Operation, and Maintenance Agreement (MOMA)

b)	Project Administration Agreement (PAA)

c)	The Partnership recorded the following balances with related parties:

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12	Subsequent events

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1	General information

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2	Summary of significant accounting policies

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3	Restricted cash

4	Property, plant and equipment

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5	Intangible assets

6	Long-term debt

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7	Asset retirement obligation

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8	Derivatives

9	Fair value measurement

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10	Commitments and contingencies

1)	Commitments

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11	Related party transactions

a)	Management, Operation, and Maintenance Agreement (MOMA)

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b)	Project Administration Agreement (PAA)

c)	Transmission Facilities Co-ownership Agreement (TFCA)

d)	The Partnership recorded the following balances with related parties:

12	Subsequent events

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1	General information

2	Summary of significant accounting policies

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3	Restricted cash

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4	Property, plant and equipment

5	Long-term debt

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6	Asset retirement obligation

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7	Derivatives

8	Fair value measurement

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9	Commitments and contingencies

1)	Commitments

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2)	Contingencies

10	Related party transactions

a)	Management, Operation, and Maintenance Agreement (MOMA)

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b)	Project Administration Agreement (PAA)

c)	The Partnership recorded the following balances with related parties:

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(1)	Included in the consolidated balance sheets as additional paid-in capital, net of $1 million in equity issuance costs.

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