|
|
|
Commission
File
Number
|
|
Exact name of registrant as specified in its
charter, address of principal executive office and
registrant's telephone number
|
|
IRS Employer
Identification
Number
|
1-36518
|
|
NEXTERA ENERGY PARTNERS, LP
|
|
30-0818558
|
|
|
700 Universe Boulevard
Juno Beach, Florida 33408
(561) 694-4000
|
|
|
|
Name of exchange on which registered
|
|
Securities registered pursuant to Section 12(b) of the Act:
|
|
|
|
Common Units
|
New York Stock Exchange
|
Large Accelerated Filer
þ
|
Accelerated Filer
o
|
Non-Accelerated Filer
o
|
Smaller Reporting Company
o
|
Emerging Growth Company
o
|
|
|
Page No.
|
|
||
|
PART I
|
|
Business
|
||
Risk Factors
|
||
Unresolved Staff Comments
|
||
Properties
|
||
Legal Proceedings
|
||
Mine Safety Disclosures
|
||
|
PART II
|
|
Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
|
||
Selected Financial Data
|
||
Management's Discussion and Analysis of Financial Condition and Results of Operations
|
||
Quantitative and Qualitative Disclosures About Market Risk
|
||
Financial Statements and Supplementary Data
|
||
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
|
||
Controls and Procedures
|
||
Other Information
|
||
|
PART III
|
|
Directors, Executive Officers and Corporate Governance
|
||
Executive Compensation
|
||
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
|
||
Certain Relationships and Related Transactions, and Director Independence
|
||
Principal Accounting Fees and Services
|
||
|
PART IV
|
|
Exhibits, Financial Statement Schedules
|
||
|
Project
|
|
Resource
|
|
MW
|
|
Contract
Expiration
|
|
NEP Acquisition / Investment Date
|
Genesis
(a)
|
|
Solar
|
|
250
|
|
2039
|
|
July 2014
|
Northern Colorado
(a)
|
|
Wind
|
|
174
|
|
2029 (22 MW)
2034 (152 MW)
|
|
July 2014
|
Summerhaven
(a)
|
|
Wind
|
|
124
|
|
2033
|
|
July 2014
|
Tuscola Bay
(a)
|
|
Wind
|
|
120
|
|
2032
|
|
July 2014
|
Elk City
(a)
|
|
Wind
|
|
99
|
|
2030
|
|
July 2014
|
Perrin Ranch
(a)
|
|
Wind
|
|
99
|
|
2037
|
|
July 2014
|
Bluewater
(a)
|
|
Wind
|
|
60
|
|
2034
|
|
July 2014
|
Conestogo
(a)
|
|
Wind
|
|
23
|
|
2032
|
|
July 2014
|
Moore
(a)
|
|
Solar
|
|
20
|
|
2032
|
|
July 2014
|
Sombra
(a)
|
|
Solar
|
|
20
|
|
2032
|
|
July 2014
|
Palo Duro
(b)
|
|
Wind
|
|
250
|
|
2034
|
|
January 2015
|
Shafter
(a)
|
|
Solar
|
|
20
|
|
2035
|
|
February 2015
|
Stateline
(a)
|
|
Wind
|
|
300
|
|
2026
|
|
May 2015
|
Mammoth Plains
(b)
|
|
Wind
|
|
199
|
|
2034
|
|
May 2015
|
Baldwin Wind
(a)
|
|
Wind
|
|
102
|
|
2041
|
|
May 2015
|
Ashtabula Wind III
(a)
|
|
Wind
|
|
62
|
|
2038
|
|
May 2015
|
Jericho
(a)
|
|
Wind
|
|
149
|
|
2034
|
|
October 2015
|
Seiling Wind
(b)
|
|
Wind
|
|
199
|
|
2035
|
|
March 2016
|
Seiling Wind II
(b)
|
|
Wind
|
|
100
|
|
2034
|
|
March 2016
|
Cedar Bluff Wind
(b)
|
|
Wind
|
|
199
|
|
2035
|
|
July 2016
|
Golden Hills Wind
(b)
|
|
Wind
|
|
86
|
|
2035
|
|
July 2016
|
Investment in Desert Sunlight
(a)(c)
|
|
Solar
|
|
275
|
|
2035 (125 MW) 2039 (150 MW)
|
|
October 2016 (132 MW) November 2017 (143 MW)
|
Golden West Wind
(b)
|
|
Wind
|
|
249
|
|
2040
|
|
May 2017
|
Brady Wind I
(b)
|
|
Wind
|
|
150
|
|
2046
|
|
November 2017
|
Brady Wind II
(b)
|
|
Wind
|
|
149
|
|
2046
|
|
November 2017
|
Javelina I
(b)
|
|
Wind
|
|
250
|
|
2030 (200 MW) 2035 (50 MW)
|
|
November 2017
|
|
|
|
|
3,728
|
|
|
|
|
Non-Economic Ownership Interests:
|
|
|
|
|
|
|
|
|
Adelanto I and II
(a)(d)
|
|
Solar
|
|
14
|
|
2035
|
|
April 2015
|
McCoy
(a)(d)
|
|
Solar
|
|
125
|
|
2036
|
|
April 2015
|
Total
|
|
|
|
3,867
|
|
|
|
|
(a)
|
These projects are encumbered by liens against their assets securing various financings.
|
(b)
|
NEP owns these wind projects together with third-party investors with differential membership interests. See Note 2 - Sale of Differential Membership Interests and Note 8.
|
(c)
|
NEP owned an indirect approximately 50% equity method investment in Desert Sunlight and the MWs reflect the net ownership interest in plant capacity. See Note 2 - Investments in Unconsolidated Entities.
|
(d)
|
NEP owned an approximately 50% non-economic ownership interest in each of these solar projects and the MWs reflect the net ownership interest in plant capacity. All equity in earnings of these non-economic ownership interests is allocated to net income attributable to noncontrolling interest. See Note 2 - Investments in Unconsolidated Entities.
|
Pipeline
(a)
|
|
Miles of
Pipeline
|
|
Diameter (inches)
|
|
Capacity per day
|
|
Contracted
Capacity per day
|
|
Contract
Expiration
|
|
In Service Date
|
|
NEP Acquisition Date
(b)
|
NET Mexico
(c)
|
|
120
|
|
42" / 48"
|
|
2.30 Bcf
|
|
2.15 Bcf
|
|
2034 - 2035
|
|
December 2014
|
|
October 2015
|
Eagle Ford
|
|
158
|
|
16" / 24" - 30"
|
|
1.10 Bcf
|
|
0.65 Bcf
|
|
2020 - 2027
|
|
September 2011 / June 2013
|
|
October 2015
|
Monument
|
|
156
|
|
16"
|
|
0.25 Bcf
|
|
0.11 Bcf
|
|
2019 - 2030
|
|
Built in the 1950s - 2000s
|
|
October 2015
|
Other
|
|
108
|
|
8" - 16"
|
|
0.40 Bcf
|
|
0.28 Bcf
|
|
2018 - 2035
|
|
Built in the 1960s - 1980s; upgraded in 2001 / others placed in service in 2002 - 2015
|
|
October 2015
|
(a)
|
All of the pipelines are encumbered by liens against their assets securing various financings.
|
(b)
|
See Note 3 for a description of the Texas pipelines acquisition.
|
(c)
|
A subsidiary of Pemex owned a 10% interest in the NET Mexico pipeline.
|
|
Year construction of project begins
|
||||||||||||||||||||||
|
2015
|
|
2016
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
||||||||
PTC
(a)
|
100
|
%
|
|
100
|
%
|
|
80
|
%
|
|
60
|
%
|
|
40
|
%
|
|
-
|
|
|
-
|
|
|
-
|
|
Wind ITC
|
30
|
%
|
|
30
|
%
|
|
24
|
%
|
|
18
|
%
|
|
12
|
%
|
|
-
|
|
|
-
|
|
|
-
|
|
Solar ITC
(b)
|
30
|
%
|
|
30
|
%
|
|
30
|
%
|
|
30
|
%
|
|
30
|
%
|
|
26
|
%
|
|
22
|
%
|
|
10
|
%
|
(a)
|
Percentage of the full PTC available for wind projects that begin construction during the applicable year.
|
(b)
|
ITC is limited to 10% for projects not placed in service before January 1, 2024.
|
•
|
Focus on contracted clean energy projects.
NEP intends to focus on long-term contracted clean energy projects with newer and more reliable technology, lower operating costs and relatively stable cash flows, subject to seasonal variances, consistent with the characteristics of its portfolio.
|
•
|
Focus on North America.
NEP intends to focus its investments in North America, where it believes industry trends present significant opportunities to acquire contracted clean energy projects in diverse regions and favorable locations. By focusing on North America, NEP believes it will be able to take advantage of NEE’s long-standing industry relationships, knowledge and experience.
|
•
|
Maintain a sound capital structure and financial flexibility.
NEP and its subsidiaries have various financing structures in place including limited-recourse project-level financings, the sale of differential membership interests, preferred units, convertible senior unsecured notes and senior unsecured notes, as well as revolving credit facilities and term loans. NEP believes its cash flow profile, its credit rating, the long-term nature of its contracts and its ability to raise capital provide flexibility for optimizing its capital structure and increasing distributions. NEP intends to continually evaluate opportunities to finance future acquisitions or refinance its existing debt and seeks to limit recourse, optimize leverage, hedge exposure, extend maturities and increase cash distributions to common unitholders over the long term.
|
•
|
Take advantage of NEER’s operational excellence to maintain the value of the projects in its portfolio.
At the direction of the board, NEER provides O&M, administrative and management services to NEP's projects pursuant to the MSA and other agreements. Through these agreements, NEP benefits from the operational expertise that NEER currently provides across its entire portfolio. NEP expects that these services will maximize the operational efficiencies of its portfolio.
|
•
|
Grow NEP's business and cash distributions through selective acquisitions of operating projects or projects under construction.
NEP intends to grow primarily through the acquisition of projects that have similar characteristics to the renewable energy projects and pipelines in its portfolio. NEER has granted NEP OpCo a right of first offer on any proposed sale of the NEER ROFO projects through mid-2020. NEP intends to focus on acquiring projects in operation, maintaining a disciplined investment approach and taking advantage of opportunities to acquire additional projects from NEER and third parties in the future, which it believes will allow it to increase cash distributions to its common unitholders over the
|
•
|
the FERC, which oversees the acquisition and disposition of generation, transmission and other facilities, transmission of electricity and natural gas in interstate commerce and wholesale purchases and sales of electric energy, among other things;
|
•
|
the NERC, which, through its regional entities, establishes and enforces mandatory reliability standards, subject to approval by the FERC, to ensure the reliability of the U.S. electric transmission and generation system and to prevent major system blackouts;
|
•
|
the EPA, which has the responsibility to maintain and enforce national standards under a variety of environmental laws. The EPA also works with industries and all levels of government, including federal and state governments, in a wide variety of voluntary pollution prevention programs and energy conservation efforts;
|
•
|
various agencies in Texas, which oversee safety, environmental and certain aspects of rates and transportation related to the pipeline projects; and
|
•
|
the Pipeline and Hazardous Materials Safety Administration and Texas Railroad Commission's Pipeline Safety Division, which, among other things, oversee the safety of natural gas pipelines.
|
•
|
breakdown or failure of, or damage to, turbines, blades, blade attachments, solar panels, mirrors and other equipment, which could reduce a project’s energy output or result in personal injury or loss of life;
|
•
|
catastrophic events, such as fires, earthquakes, severe weather, tornadoes, ice or hail storms, other meteorological conditions, landslides and other similar events beyond NEP's control, which could severely damage or destroy all or a part of a project, reduce its energy output or result in personal injury or loss of life;
|
•
|
technical performance below expected levels, including, but not limited to, the failure of wind turbines, solar panels, mirrors and other equipment to produce energy as expected due to incorrect measures of expected performance provided by equipment suppliers;
|
•
|
increases in the cost of operating the projects, including, but not limited to, costs relating to labor, equipment, insurance and real estate taxes;
|
•
|
operator or contractor error or failure to perform;
|
•
|
serial design or manufacturing defects, which may not be covered by warranty;
|
•
|
extended events, including, but not limited to, force majeure, under certain PPAs that may give rise to a termination right of the customer under such a PPA (renewable energy counterparty);
|
•
|
failure to comply with permits and the inability to renew or replace permits that have expired or terminated;
|
•
|
the inability to operate within limitations that may be imposed by current or future governmental permits;
|
•
|
replacements for failed equipment, which may need to meet new interconnection standards or require system impact studies and compliance that may be difficult or expensive to achieve;
|
•
|
land use, environmental or other regulatory requirements;
|
•
|
disputes with the BLM, other owners of land on which NEP's projects are located or adjacent landowners;
|
•
|
changes in law, including, but not limited to, changes in governmental permit requirements, corporate income tax laws, regulations and policies and international trade laws, regulations, agreements, treaties and policies of the U.S. or other countries;
|
•
|
government or utility exercise of eminent domain power or similar events; and
|
•
|
existence of liens, encumbrances and other imperfections in title affecting real estate interests.
|
•
|
the protection of wildlife, including, but not limited to, migratory birds, bats and threatened and endangered species, such as desert tortoises, or protected species, such as eagles, and other protected plants or animals whose presence or movements often cannot be anticipated or controlled;
|
•
|
the storage, handling, use and transportation of natural gas as well as other hazardous or toxic substances and other regulated substances, materials, and/or chemicals;
|
•
|
air emissions, water quality, releases of hazardous materials into the environment and the prevention of and responses to releases of hazardous materials into soil and groundwater;
|
•
|
federal, state, provincial or local land use, zoning, building and transportation laws and requirements, which may mandate conformance with sound levels, radar and communications interference, hazards to aviation or navigation, or other potential nuisances, such as the flickering effect, caused when rotating wind turbine blades periodically cast shadows through openings, such as the windows of neighboring properties, which is known as shadow flicker;
|
•
|
the presence or discovery of archaeological, religious or cultural resources at or near NEP's operations; and
|
•
|
the protection of workers’ health and safety.
|
•
|
perform ongoing assessments of pipeline integrity;
|
•
|
identify and characterize applicable threats to pipeline segments that could affect a high consequence area;
|
•
|
improve data collection, integration and analysis;
|
•
|
repair and remediate the pipeline as necessary; and
|
•
|
implement preventive and mitigating actions.
|
•
|
delays in obtaining, or the inability to obtain, necessary permits and licenses;
|
•
|
delays and increased costs related to the interconnection of new projects to the transmission system;
|
•
|
the inability to acquire or maintain land use and access rights;
|
•
|
the failure to receive contracted third-party services;
|
•
|
interruptions to dispatch at the projects;
|
•
|
supply interruptions, including as a result of changes in international trade laws, regulations, agreements, treaties or policies of the U.S. or other countries in which NEP's suppliers are located;
|
•
|
work stoppages;
|
•
|
labor disputes;
|
•
|
weather interferences;
|
•
|
unforeseen engineering, environmental and geological problems, including, but not limited to, discoveries of contamination, protected plant or animal species or habitat, archaeological or cultural resources or other environment-related factors;
|
•
|
unanticipated cost overruns in excess of budgeted contingencies; and
|
•
|
failure of contracting parties to perform under contracts.
|
•
|
Specified events beyond NEP's control or the control of a customer may temporarily or permanently excuse the customer from its obligation to accept and pay for delivery of energy generated by a project. These events could include, among other things, a system emergency, transmission failure or curtailment, adverse weather conditions or labor disputes.
|
•
|
Since a governmental entity makes payments with respect to the energy produced by some of NEP's projects under FIT contracts, RESOP contracts and natural gas transportation agreements, including, but not limited to, Pemex, NEP is subject to the risk that the governmental entity may attempt to unilaterally change or terminate its contract with NEP, whether as a result of legislative, regulatory, political or other activities, including changes in international trade laws, regulations, agreements, treaties or policies of the U.S. or other countries.
|
•
|
The ability of NEP's customers to fulfill their contractual obligations to NEP depends on their financial condition. NEP is exposed to the credit risk of its customers over an extended period of time due to the long-term nature of NEP's PPAs and natural gas transportation agreements with them. These customers could become subject to insolvency or liquidation proceedings or otherwise suffer a deterioration of their financial condition when they have not yet paid for services delivered, any of which could result in underpayment or nonpayment under such agreements.
|
•
|
A default or failure by NEP to satisfy minimum energy or natural gas delivery requirements or mechanical availability levels under NEP's agreements could result in damage payments to the applicable customer or termination of the applicable agreement.
|
•
|
whether the renewable energy contract counterparty has a continued need for energy at the time of the agreement’s expiration, which could be affected by, among other things, the presence or absence of governmental incentives or mandates, prevailing market prices, and the availability of other energy sources;
|
•
|
the amount of commercial natural gas supply available to the Texas pipelines' systems and changing natural gas supply flow patterns in North America;
|
•
|
the satisfactory performance of NEP's obligations under such PPAs and natural gas transportation agreements;
|
•
|
the regulatory environment applicable to NEP's contract counterparties at the time;
|
•
|
macroeconomic factors present at the time, such as population, business trends, international trade laws, regulations, agreements, treaties or policies of the U.S. or other countries and related energy demand; and
|
•
|
the effects of regulation on the contracting practices of NEP's contract counterparties.
|
•
|
competing bids for a project, including, but not limited to, the NEER ROFO projects, from companies that may have substantially greater purchasing power, capital or other resources or a greater willingness to accept lower returns or more risk than NEP does;
|
•
|
NEP's failure to agree to favorable financial or legal terms with sellers with respect to any proposed acquisitions;
|
•
|
fewer acquisition opportunities than NEP expects, which could result from, among other things, available projects having less desirable economic returns or higher risk profiles than NEP believes suitable for its acquisition strategy and future growth;
|
•
|
NEP's failure to successfully complete construction of and finance projects, to the extent that it decides to acquire projects that are not yet operational or to otherwise pursue construction activities with respect to new projects;
|
•
|
NEP's inability to obtain regulatory approvals or other necessary consents to consummate an acquisition; and
|
•
|
the presence or potential presence of:
|
•
|
pollution, contamination or other wastes at the project site;
|
•
|
protected plant or animal species;
|
•
|
archaeological or cultural resources;
|
•
|
wind waking or solar shadowing effects caused by neighboring activities, which reduce potential energy production by decreasing wind speeds or reducing available insolation;
|
•
|
land use restrictions and other environment-related siting factors; and
|
•
|
local opposition to wind and solar projects and pipeline projects in certain markets due to concerns about noise, health, environmental or other alleged impacts of such projects.
|
•
|
incur or guarantee additional debt;
|
•
|
make distributions on or redeem or repurchase common units;
|
•
|
make certain investments and acquisitions;
|
•
|
incur certain liens or permit them to exist;
|
•
|
enter into certain types of transactions with affiliates;
|
•
|
merge or consolidate with another company; and
|
•
|
transfer, sell or otherwise dispose of projects.
|
•
|
failure to comply with the covenants in the agreements governing these obligations could result in an event of default under those agreements, which could be difficult to cure, result in bankruptcy or, with respect to subsidiary debt, result in loss of NEP OpCo's ownership interest in one or more of its subsidiaries or in some or all of their assets as a result of foreclosure;
|
•
|
NEP's subsidiaries’ debt service obligations require them to dedicate a substantial portion of their cash flow to pay principal and interest on their debt, thereby reducing their cash available for distribution to NEP;
|
•
|
NEP's subsidiaries’ substantial indebtedness could limit NEP's ability to fund operations of any projects acquired in the future and NEP's financial flexibility, which could reduce its ability to plan for and react to unexpected opportunities;
|
•
|
NEP's subsidiaries’ substantial debt service obligations make NEP vulnerable to adverse changes in general economic, credit markets, capital markets, industry, competitive conditions and government regulation that could place NEP at a disadvantage compared to competitors with less debt; and
|
•
|
NEP's subsidiaries’ substantial indebtedness could limit NEP's ability to obtain financing for working capital, including, but not limited to, collateral postings, capital expenditures, debt service requirements, acquisitions and general partnership or other purposes.
|
•
|
NEP is able to identify attractive acquisition candidates;
|
•
|
NEP is able to negotiate acceptable purchase agreements;
|
•
|
NEP is able to obtain financing for these acquisitions on economically acceptable terms; and
|
•
|
NEP is outbid by competitors.
|
•
|
No agreement to which NEP is a party requires NEE or its affiliates to pursue a business strategy that favors NEP or uses NEP's projects or dictates what markets to pursue or grow.
|
•
|
NEE and its affiliates are not limited in their ability to compete with NEP, and neither NEP GP nor its affiliates have any obligation to present business opportunities to NEP except for the NEER ROFO projects.
|
•
|
So long as the officers of NEP are officers of NEE or its affiliates, they will also devote significant time to the business of NEE or its affiliates and will be compensated by NEE or its affiliates.
|
•
|
The board may cause NEP to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a payment of the IDR fee.
|
•
|
NEP's partnership agreement replaces the fiduciary duties that would otherwise be owed by NEP GP and the directors and officers of NEP with contractual standards governing their duties and limits NEP GP’s and such directors’ and officers' liabilities and the remedies available to NEP's unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty under applicable Delaware law.
|
•
|
Except in limited circumstances, the board has the power and authority to conduct NEP's business without the approval of NEP GP or NEP's unitholders.
|
•
|
Actions taken by the board may affect the amount of cash available to pay distributions to NEP's unitholders.
|
•
|
NEP GP has limited liability regarding NEP's contractual and other obligations.
|
•
|
The board controls the exercise of the rights of NEP against NEE and its affiliates, and the enforcement of the obligations that NEE and its affiliates owe to NEP, including, but not limited to, NEP's rights against and obligations to NEER under the ROFO agreement and its other commercial agreements with NEER.
|
•
|
NEP may choose not to retain counsel, independent accountants or other advisors separate from those retained by NEP GP or NEE to perform services for NEP or for the holders of common units.
|
•
|
NEE Management defaults in the performance or observance of any material term, condition or covenant contained therein in a manner that results in material harm to NEP or its affiliates and the default continues unremedied for a period of 90 days after written notice thereof is given to NEE Management;
|
•
|
NEE Management engages in any act of fraud, misappropriation of funds or embezzlement that results in material harm to NEP for its affiliates;
|
•
|
NEE Management is reckless in the performance of its duties under the agreement and such recklessness results in material harm to NEP or its affiliates;
|
•
|
upon the happening of certain events relating to the bankruptcy or insolvency of NEP or certain of its affiliates; or
|
•
|
NEE Management intentionally or willfully takes any action that materially conflicts with or directly contravenes any resolution or other determination of the board relating to certain significant activities of NEP, such action has caused, or would reasonably be expected to cause, material harm to NEP and its subsidiaries, and such action continues unremedied for a period of 90 days after written notice thereof is given to NEE Management.
|
•
|
the amount of power generated from its projects and the amount of natural gas transported in its pipelines, and the prices received therefor;
|
•
|
its operating costs;
|
•
|
payment of interest and principal amortization, which depends on the amount of its indebtedness and the interest payable thereon;
|
•
|
the ability of NEP OpCo’s subsidiaries to distribute cash under their respective financing agreements;
|
•
|
the completion of any ongoing construction activities on time and on budget;
|
•
|
its capital expenditures; and
|
•
|
if NEP OpCo acquires a project prior to its COD, timely completion of future construction projects.
|
•
|
availability of borrowings under its subsidiaries' credit facility to pay distributions;
|
•
|
the costs of acquisitions, if any;
|
•
|
fluctuations in its working capital needs;
|
•
|
timing and collectability of receivables;
|
•
|
restrictions on distributions contained in its credit facility and other financing documents;
|
•
|
prevailing economic conditions;
|
•
|
access to credit or capital markets; and
|
•
|
the amount of cash reserves established by NEP OpCo GP, NEP OpCo’s general partner, for the proper conduct of its business.
|
•
|
appointment of three directors of NEP;
|
•
|
how to exercise NEP GP’s voting rights with respect to the units it or its affiliates own in NEP OpCo and NEP;
|
•
|
whether to exchange NEE Equity’s NEP OpCo common units for NEP's common units or, with the approval of the conflicts committee, to have NEP OpCo redeem NEE Equity’s NEP OpCo common units for cash; and
|
•
|
whether to consent to, among other things, NEP’s participation in certain activities or lines of business, the sale of all or substantially all of the assets of NEP, any merger, consolidation or conversion of NEP, dissolution of NEP, or an amendment to NEP OpCo’s partnership agreement.
|
•
|
whenever NEP GP or the board, or any director or any committee of the board (including, but not limited to, the conflicts committee), makes a determination or takes, or declines to take, any other action in its respective capacity, they are required to act in good faith;
|
•
|
NEP GP will not have any liability to NEP or its unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;
|
•
|
NEP GP and its officers and directors and the officers and directors of NEP will not be liable for monetary damages to NEP or NEP's limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining such persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
|
•
|
NEP GP and its affiliates and NEP’s directors will not be in breach of their obligations under NEP’s partnership agreement (including, but not limited to, any duties to NEP or its unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:
|
•
|
approved by the conflicts committee of the board, although the board is not obligated to seek such approval;
|
•
|
approved by the vote of a majority of the outstanding common units, excluding any common units owned by NEP GP and its affiliates if the conflict involves NEP GP or any of its affiliates;
|
•
|
determined by the board to be on terms no less favorable to NEP than those generally being provided to or available from unrelated third parties; or
|
•
|
determined by the board to be fair and reasonable to NEP, taking into account the totality of the relationships among the parties involved, including, but not limited to, other transactions that may be particularly favorable or advantageous to NEP.
|
•
|
NEP's existing common unitholders’ proportionate ownership interest in NEP will decrease;
|
•
|
the amount of cash distributions per common unit may decrease;
|
•
|
because the IDR fee is based on a percentage of total available cash, the IDR fee will increase if total available cash increases even if the per unit distribution on common units remains the same;
|
•
|
the relative voting strength of each previously outstanding unit may be diminished; and
|
•
|
the market price of the common units may decline.
|
•
|
NEP's quarterly distributions;
|
•
|
NEP's quarterly or annual earnings or those of other companies in NEP's industry;
|
•
|
announcements by NEP or NEP's competitors of significant contracts or acquisitions;
|
•
|
changes in accounting standards, policies, guidance, interpretations or principles;
|
•
|
general economic conditions;
|
•
|
the failure of securities analysts to cover NEP's common units or changes in financial estimates by analysts;
|
•
|
future sales of NEP's common units;
|
•
|
insufficient investor interest in NEP's common units;
|
•
|
concentration of ownership of NEP's common units in a relatively small group of investors;
|
•
|
operating and unit price performance of companies that investors deem comparable to NEP;
|
•
|
any adverse change in the financial condition or results of operations of NEE; and
|
•
|
the other factors described in these Risk Factors.
|
•
|
NEP was conducting business in a state or province but had not complied with that particular state or province’s partnership statute; or
|
•
|
the unitholder’s right to act with other unitholders to remove or replace NEP GP, to approve some amendments to NEP's partnership agreement or to take other actions under NEP's partnership agreement constitute “control” of NEP's business.
|
•
|
an existing unitholder’s proportionate ownership interest in NEP will decrease;
|
•
|
the amount of cash available for distribution on each common unit may decrease;
|
•
|
the relative voting strength of each previously outstanding common unit will be diminished; and
|
•
|
the market price of NEP's common units may decline.
|
|
|
2017
|
|
2016
|
||||||||||||||||||||
Quarter
|
|
High
|
|
Low
|
|
Cash
Distributions
|
|
High
|
|
Low
|
|
Cash
Distributions
|
||||||||||||
First
|
|
$
|
33.90
|
|
|
$
|
25.32
|
|
|
$
|
0.35250
|
|
|
$
|
30.15
|
|
|
$
|
23.78
|
|
|
$
|
0.30750
|
|
Second
|
|
$
|
39.83
|
|
|
$
|
31.78
|
|
|
$
|
0.36500
|
|
|
$
|
30.59
|
|
|
$
|
25.86
|
|
|
$
|
0.31875
|
|
Third
|
|
$
|
43.68
|
|
|
$
|
36.37
|
|
|
$
|
0.38000
|
|
|
$
|
32.42
|
|
|
$
|
27.60
|
|
|
$
|
0.33000
|
|
Fourth
|
|
$
|
44.00
|
|
|
$
|
36.42
|
|
|
$
|
0.39250
|
|
|
$
|
28.93
|
|
|
$
|
23.90
|
|
|
$
|
0.34125
|
|
|
|
Total Quarterly Distribution
per NEP OpCo Common Unit Target Amount
|
|
Marginal Percentage Interest in Adjusted Available Cash
|
||
|
|
|
NEP OpCo Common Unitholders
|
|
NEE Management
|
|
Minimum Quarterly Distribution
|
|
$0.1875
|
|
100%
|
|
—%
|
First Target Quarterly Distribution
|
|
Above $0.1875 up to $0.215625
|
|
100%
|
|
—%
|
Second Target Quarterly Distribution
|
|
Above $0.215625 up to $0.234375
|
|
85%
|
|
15%
|
Third Target Quarterly Distribution
|
|
Above $0.234375 up to $0.281250
|
|
75%
|
|
25%
|
Thereafter
|
|
Above $0.281250
|
|
50%
|
|
50%
|
|
Years Ended December 31,
|
||||||||||||||||||
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
SELECTED DATA OF NEP (millions, except per unit and GWh amounts):
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating revenues
|
$
|
807
|
|
|
$
|
772
|
|
|
$
|
501
|
|
|
$
|
359
|
|
|
$
|
179
|
|
Net income
(a)
|
$
|
109
|
|
|
$
|
380
|
|
|
$
|
107
|
|
|
$
|
141
|
|
|
$
|
17
|
|
Net income (loss) attributable to NEP
(a)
|
$
|
(65
|
)
|
|
$
|
82
|
|
|
$
|
10
|
|
|
$
|
3
|
|
|
n/a
|
|
|
Earnings (loss) per common unit attributable to NEP - basic and assuming dilution
(a)
|
$
|
(1.20
|
)
|
|
$
|
1.88
|
|
|
$
|
0.46
|
|
|
$
|
0.16
|
|
|
n/a
|
|
|
Distributions paid per common unit
|
$
|
1.4900
|
|
|
$
|
1.2975
|
|
|
$
|
0.9050
|
|
|
$
|
0.1875
|
|
|
n/a
|
|
|
Total assets
|
$
|
8,395
|
|
|
$
|
8,661
|
|
|
$
|
8,237
|
|
|
$
|
5,260
|
|
|
$
|
3,359
|
|
Long-term debt, excluding current maturities
|
$
|
4,218
|
|
|
$
|
3,508
|
|
|
$
|
3,334
|
|
|
$
|
1,807
|
|
|
$
|
1,527
|
|
GWh generated
|
11,117
|
|
|
10,215
|
|
|
7,373
|
|
|
4,249
|
|
|
2,893
|
|
(a)
|
The year ended December 31, 2017 reflects an income tax charge of approximately $101 million, all of which was attributable to NEP, related to tax reform (see Note 4). The year ended December 31, 2016 reflects a favorable fair value adjustment of approximately $189 million (see Note 5 - Contingent Consideration).
|
•
|
overview, including a description of NEP's business;
|
•
|
results of operations, including an explanation of significant differences between the periods in the specific line items of the consolidated statements of income;
|
•
|
liquidity and capital resources, addressing NEP's liquidity position, financing arrangements, contractual obligations, capital expenditures, cash distributions to unitholders and cash flows;
|
•
|
new accounting rules and interpretations, addressing those which have impacted or may impact NEP's financial condition and results of operations or disclosures;
|
•
|
critical accounting policies and estimates, which are most important to both the portrayal of NEP's financial condition and results of operations, and which require management’s most difficult, subjective or complex judgments; and
|
•
|
quantitative and qualitative disclosures about market risk.
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
(a)
|
|
2015
(a)
|
||||||
|
(millions)
|
||||||||||
STATEMENT OF INCOME DATA:
|
|
|
|
||||||||
OPERATING REVENUES
|
|
|
|
|
|
||||||
Renewable energy sales
|
$
|
613
|
|
|
$
|
583
|
|
|
$
|
464
|
|
Texas pipelines service revenue
|
194
|
|
|
189
|
|
|
37
|
|
|||
Total operating revenues
|
807
|
|
|
772
|
|
|
501
|
|
|||
OPERATING EXPENSES
|
|
|
|
|
|
||||||
Operations and maintenance
|
253
|
|
|
218
|
|
|
113
|
|
|||
Depreciation and amortization
|
226
|
|
|
235
|
|
|
163
|
|
|||
Taxes other than income taxes and other
|
21
|
|
|
20
|
|
|
16
|
|
|||
Total operating expenses
|
500
|
|
|
473
|
|
|
292
|
|
|||
OPERATING INCOME
|
307
|
|
|
299
|
|
|
209
|
|
|||
OTHER INCOME (DEDUCTIONS)
|
|
|
|
|
|
||||||
Interest expense
|
(199
|
)
|
|
(152
|
)
|
|
(117
|
)
|
|||
Benefits associated with differential membership interests - net
|
119
|
|
|
67
|
|
|
24
|
|
|||
Equity in earnings of equity method investee
|
40
|
|
|
40
|
|
|
36
|
|
|||
Equity in earnings (losses) of non-economic ownership interests
|
11
|
|
|
(4
|
)
|
|
(2
|
)
|
|||
Revaluation of contingent consideration
|
—
|
|
|
189
|
|
|
—
|
|
|||
Other - net
|
(2
|
)
|
|
(2
|
)
|
|
(10
|
)
|
|||
Total other income (deductions) - net
|
(31
|
)
|
|
138
|
|
|
(69
|
)
|
|||
INCOME BEFORE INCOME TAXES
|
276
|
|
|
437
|
|
|
140
|
|
|||
INCOME TAXES
|
167
|
|
|
57
|
|
|
33
|
|
|||
NET INCOME
|
109
|
|
|
380
|
|
|
107
|
|
|||
Less net income attributable to preferred distributions
|
3
|
|
|
—
|
|
|
—
|
|
|||
Less net income attributable to noncontrolling interest
|
171
|
|
|
298
|
|
|
97
|
|
|||
NET INCOME (LOSS) ATTRIBUTABLE TO NEXTERA ENERGY PARTNERS, LP
|
$
|
(65
|
)
|
|
$
|
82
|
|
|
$
|
10
|
|
(a)
|
Prior-period financial information has been retrospectively adjusted as discussed in Note 2 - Basis of Presentation.
|
•
|
when required by its subsidiaries’ financings;
|
•
|
when its subsidiaries’ financings otherwise permit distributions to be made to NEP OpCo;
|
•
|
when funds are required to be returned to NEP OpCo; or
|
•
|
when otherwise demanded by NEP OpCo.
|
|
Years ended December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(millions)
|
||||||
Cash and cash equivalents
|
$
|
154
|
|
|
$
|
150
|
|
Amounts due under the CSCS agreement
|
87
|
|
|
65
|
|
||
Revolving credit facilities
|
900
|
|
|
400
|
|
||
Less borrowings
|
(150
|
)
|
|
(150
|
)
|
||
Letter of credit facilities
|
107
|
|
|
119
|
|
||
Less letters of credit
|
(93
|
)
|
|
(97
|
)
|
||
Total
(a)
|
$
|
1,005
|
|
|
$
|
487
|
|
(a)
|
Excludes current restricted cash of approximately
$25 million
and
$33 million
at
December 31, 2017
and
2016
, respectively. See Note 2 - Restricted Cash.
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
Thereafter
|
|
Total
|
||||||||||||||
|
(millions)
|
||||||||||||||||||||||||||
Debt, including interest
(a)
|
$
|
292
|
|
|
$
|
292
|
|
|
$
|
641
|
|
|
$
|
308
|
|
|
$
|
825
|
|
|
$
|
3,234
|
|
|
$
|
5,592
|
|
Contractual obligations
(b)
|
37
|
|
|
35
|
|
|
35
|
|
|
35
|
|
|
36
|
|
|
541
|
|
|
719
|
|
|||||||
Revolving credit facilities fees
|
2
|
|
|
2
|
|
|
2
|
|
|
2
|
|
|
1
|
|
|
—
|
|
|
9
|
|
|||||||
Asset retirement activities
(c)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
390
|
|
|
390
|
|
|||||||
MSA and credit support
(d)
|
8
|
|
|
8
|
|
|
8
|
|
|
8
|
|
|
8
|
|
|
90
|
|
|
130
|
|
|||||||
Total
|
$
|
339
|
|
|
$
|
337
|
|
|
$
|
686
|
|
|
$
|
353
|
|
|
$
|
870
|
|
|
$
|
4,255
|
|
|
$
|
6,840
|
|
(a)
|
Includes principal, interest and interest rate swaps. Variable rate interest was computed using
December 31, 2017
rates.
|
(b)
|
Includes obligations related to estimated cash payments related to agreements for the right to use land upon which certain projects are located, differential membership interests and engineering, procurement and construction contracts.
|
(c)
|
Represents expected cash payments adjusted for inflation for estimated costs to perform asset retirement activities.
|
(d)
|
Represents minimum fees under the MSA and CSCS agreement. See Note 11.
|
|
Moody's
(a)
|
|
S&P
(a)
|
|
Fitch
(a)
|
NEP corporate credit rating
(b)
|
Ba1
|
|
BB
|
|
BB+
|
(a)
|
A security rating is not a recommendation to buy, sell or hold securities and should be evaluated independently of any other rating. The rating is subject to revision or withdrawal at any time by the assigning rating organization.
|
(b)
|
The outlook indicated by each of Moody's, S&P and Fitch is stable.
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(millions)
|
||||||||||
Net cash provided by operating activities
|
$
|
413
|
|
|
$
|
415
|
|
|
$
|
288
|
|
Net cash used in investing activities
|
$
|
(1,368
|
)
|
|
$
|
(1,716
|
)
|
|
$
|
(1,899
|
)
|
Net cash provided by financing activities
|
$
|
959
|
|
|
$
|
1,302
|
|
|
$
|
1,608
|
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(millions)
|
||||||||||
Acquisition of membership interests in subsidiaries and equity method investee
|
$
|
(1,074
|
)
|
|
$
|
(869
|
)
|
|
$
|
(1,882
|
)
|
Capital expenditures
|
(349
|
)
|
|
(861
|
)
|
|
(201
|
)
|
|||
Proceeds from CITCs
|
77
|
|
|
13
|
|
|
2
|
|
|||
Payments from (to) related parties under CSCS agreement - net
|
(22
|
)
|
|
1
|
|
|
152
|
|
|||
Distribution from equity method investee
|
—
|
|
|
—
|
|
|
30
|
|
|||
Net cash used in investing activities
|
$
|
(1,368
|
)
|
|
$
|
(1,716
|
)
|
|
$
|
(1,899
|
)
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(millions)
|
||||||||||
Proceeds from issuance of common units – net
|
$
|
—
|
|
|
$
|
645
|
|
|
$
|
343
|
|
Proceeds from issuance of preferred units – net
|
548
|
|
|
—
|
|
|
—
|
|
|||
Issuances (retirements) of long-term debt – net
|
695
|
|
|
131
|
|
|
974
|
|
|||
Partners/Members' contributions
|
316
|
|
|
831
|
|
|
180
|
|
|||
Partners/Members' distributions
|
(307
|
)
|
|
(682
|
)
|
|
(1,122
|
)
|
|||
Proceeds related to differential membership interests - net
|
8
|
|
|
396
|
|
|
456
|
|
|||
Payment of acquisition holdback
|
(186
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from issuance of NEP OpCo common units to noncontrolling interest
|
—
|
|
|
—
|
|
|
702
|
|
|||
Change in amounts due to related party
|
(78
|
)
|
|
4
|
|
|
(20
|
)
|
|||
Proceeds from (repayments of) short-term debt - net
|
—
|
|
|
(12
|
)
|
|
112
|
|
|||
Other
|
(37
|
)
|
|
(11
|
)
|
|
(17
|
)
|
|||
Net cash provided by financing activities
|
$
|
959
|
|
|
$
|
1,302
|
|
|
$
|
1,608
|
|
JAMES L. ROBO
|
|
JOHN W. KETCHUM
|
James L. Robo
Chairman of the Board and Chief Executive Officer
NextEra Energy Partners, LP
|
|
John W. Ketchum
Chief Financial Officer
NextEra Energy Partners, LP
|
TERRELL KIRK CREWS, II
|
|
|
Terrell Kirk Crews, II
Controller and Chief Accounting Officer
NextEra Energy Partners, LP
|
|
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
(a)
|
|
2015
(a)
|
||||||
OPERATING REVENUES
|
|
|
|
|
|
|
|
|
|||
Renewable energy sales
|
$
|
613
|
|
|
$
|
583
|
|
|
$
|
464
|
|
Texas pipelines service revenue
|
194
|
|
|
189
|
|
|
37
|
|
|||
Total operating revenues
(b)
|
807
|
|
|
772
|
|
|
501
|
|
|||
OPERATING EXPENSES
|
|
|
|
|
|
||||||
Operations and maintenance
(c)
|
253
|
|
|
218
|
|
|
113
|
|
|||
Depreciation and amortization
|
226
|
|
|
235
|
|
|
163
|
|
|||
Taxes other than income taxes and other
|
21
|
|
|
20
|
|
|
16
|
|
|||
Total operating expenses
|
500
|
|
|
473
|
|
|
292
|
|
|||
OPERATING INCOME
|
307
|
|
|
299
|
|
|
209
|
|
|||
OTHER INCOME (DEDUCTIONS)
|
|
|
|
|
|
||||||
Interest expense
|
(199
|
)
|
|
(152
|
)
|
|
(117
|
)
|
|||
Benefits associated with differential membership interests - net
|
119
|
|
|
67
|
|
|
24
|
|
|||
Equity in earnings of equity method investee
|
40
|
|
|
40
|
|
|
36
|
|
|||
Equity in earnings (losses) of non-economic ownership interests
|
11
|
|
|
(4
|
)
|
|
(2
|
)
|
|||
Revaluation of contingent consideration
|
—
|
|
|
189
|
|
|
—
|
|
|||
Other - net
|
(2
|
)
|
|
(2
|
)
|
|
(10
|
)
|
|||
Total other income (deductions) - net
|
(31
|
)
|
|
138
|
|
|
(69
|
)
|
|||
INCOME BEFORE INCOME TAXES
|
276
|
|
|
437
|
|
|
140
|
|
|||
INCOME TAXES
|
167
|
|
|
57
|
|
|
33
|
|
|||
NET INCOME
|
109
|
|
|
380
|
|
|
107
|
|
|||
Less net income attributable to preferred distributions
|
3
|
|
|
—
|
|
|
—
|
|
|||
Less net income attributable to noncontrolling interest
(d)
|
171
|
|
|
298
|
|
|
97
|
|
|||
NET INCOME (LOSS) ATTRIBUTABLE TO NEXTERA ENERGY PARTNERS, LP
|
$
|
(65
|
)
|
|
$
|
82
|
|
|
$
|
10
|
|
|
|
|
|
|
|
||||||
Weighted average number of common units outstanding - basic and assuming dilution
|
54.2
|
|
|
43.8
|
|
|
22.8
|
|
|||
Earnings (loss) per common unit attributable to NextEra Energy Partners, LP - basic and assuming dilution
|
$
|
(1.20
|
)
|
|
$
|
1.88
|
|
|
$
|
0.46
|
|
(a)
|
Prior-period financial information has been retrospectively adjusted as discussed in Note 2 - Basis of Presentation.
|
(b)
|
Includes related party revenues of approximately
$9 million
,
$13 million
and
$5 million
for 2017, 2016 and 2015, respectively.
|
(c)
|
Includes operations and maintenance (O&M) expenses related to renewable energy projects of
$132 million
,
$120 million
and
$91 million
and O&M expenses related to the Texas pipelines of
$44 million
,
$45 million
and
$8 million
for 2017, 2016 and 2015, respectively. Total O&M expenses presented includes related party amounts of approximately
$88 million
,
$64 million
and
$20 million
for 2017, 2016 and 2015, respectively.
|
(d)
|
Net income attributable to noncontrolling interest includes the pre-acquisition net income of the common control acquisitions. See Note 2 - Basis of Presentation.
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
(a)
|
|
2015
(a)
|
||||||
NET INCOME
|
$
|
109
|
|
|
$
|
380
|
|
|
$
|
107
|
|
Net unrealized gains (losses) on cash flow hedges:
|
|
|
|
|
|
|
|
|
|||
Effective portion of net unrealized losses (net of $0, $0 and $3 tax benefit, respectively)
|
—
|
|
|
—
|
|
|
(12
|
)
|
|||
Reclassification from accumulated other comprehensive income (loss) to net income (net of $2, $1 and $1 tax expense, respectively)
|
5
|
|
|
7
|
|
|
5
|
|
|||
Net unrealized gains (losses) on foreign currency translation (net of $1 tax expense, $1 tax expense and $2 tax benefit, respectively)
|
7
|
|
|
3
|
|
|
(42
|
)
|
|||
Other comprehensive income related to equity method investee (net of $1 tax benefit, $1 tax expense and $0 tax expense, respectively)
|
5
|
|
|
3
|
|
|
—
|
|
|||
Total other comprehensive income (loss), net of tax
|
17
|
|
|
13
|
|
|
(49
|
)
|
|||
COMPREHENSIVE INCOME
|
126
|
|
|
393
|
|
|
58
|
|
|||
Less comprehensive income attributable to preferred distributions
|
3
|
|
|
—
|
|
|
—
|
|
|||
Less comprehensive income attributable to noncontrolling interest
(b)
|
184
|
|
|
308
|
|
|
51
|
|
|||
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO NEXTERA ENERGY PARTNERS, LP
|
$
|
(61
|
)
|
|
$
|
85
|
|
|
$
|
7
|
|
(a)
|
Prior-period financial information has been retrospectively adjusted as discussed in Note 2 - Basis of Presentation.
|
(b)
|
Comprehensive income attributable to noncontrolling interest includes the pre-acquisition comprehensive in
come
of the common control acquisitions. See Note 2 - Basis of Presentation.
|
|
December 31,
|
||||||
|
2017
|
|
2016
(a)
|
||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
154
|
|
|
$
|
150
|
|
Accounts receivable
|
85
|
|
|
87
|
|
||
Due from related parties
|
88
|
|
|
67
|
|
||
Restricted cash
|
25
|
|
|
33
|
|
||
Other current assets
|
46
|
|
|
30
|
|
||
Total current assets
|
398
|
|
|
367
|
|
||
Non-current assets:
|
|
|
|
||||
Property, plant and equipment - net
|
6,197
|
|
|
6,298
|
|
||
Deferred income taxes
|
181
|
|
|
286
|
|
||
Investment in equity method investee
|
218
|
|
|
298
|
|
||
Investments in non-economic ownership interests
|
11
|
|
|
12
|
|
||
Intangible assets - customer relationships
|
661
|
|
|
678
|
|
||
Goodwill
|
628
|
|
|
628
|
|
||
Other non-current assets
|
101
|
|
|
94
|
|
||
Total non-current assets
|
7,997
|
|
|
8,294
|
|
||
TOTAL ASSETS
|
$
|
8,395
|
|
|
$
|
8,661
|
|
LIABILITIES AND EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable and accrued expenses
|
$
|
26
|
|
|
$
|
331
|
|
Due to related parties
|
45
|
|
|
127
|
|
||
Current maturities of long-term debt
|
99
|
|
|
78
|
|
||
Acquisition holdbacks
|
—
|
|
|
199
|
|
||
Accrued interest
|
39
|
|
|
25
|
|
||
Derivatives
|
11
|
|
|
18
|
|
||
Other current liabilities
|
56
|
|
|
40
|
|
||
Total current liabilities
|
276
|
|
|
818
|
|
||
Non-current liabilities:
|
|
|
|
||||
Long-term debt
|
4,218
|
|
|
3,508
|
|
||
Deferral related to differential membership interests
|
1,442
|
|
|
1,553
|
|
||
Deferred income taxes
|
63
|
|
|
47
|
|
||
Asset retirement obligation
|
81
|
|
|
78
|
|
||
Non-current due to related party
|
21
|
|
|
22
|
|
||
Other non-current liabilities
|
86
|
|
|
69
|
|
||
Total non-current liabilities
|
5,911
|
|
|
5,277
|
|
||
TOTAL LIABILITIES
|
6,187
|
|
|
6,095
|
|
||
COMMITMENTS AND CONTINGENCIES
|
|
|
|
||||
EQUITY
|
|
|
|
||||
Common units (54.3 and 54.2 units issued and outstanding, respectively)
|
1,639
|
|
|
1,746
|
|
||
Preferred units (14.0 and 0 units issued and outstanding, respectively)
|
548
|
|
|
—
|
|
||
Accumulated other comprehensive income (loss)
|
1
|
|
|
(3
|
)
|
||
Noncontrolling interest
|
20
|
|
|
823
|
|
||
TOTAL EQUITY
|
2,208
|
|
|
2,566
|
|
||
TOTAL LIABILITIES AND EQUITY
|
$
|
8,395
|
|
|
$
|
8,661
|
|
(a)
|
Prior-period financial information has been retrospectively adjusted as discussed in Note 2 - Basis of Presentation.
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
(a)
|
|
2015
(a)
|
||||||
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
||||||
Net income
|
$
|
109
|
|
|
$
|
380
|
|
|
$
|
107
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
|
|
||||
Depreciation and amortization
|
226
|
|
|
235
|
|
|
163
|
|
|||
Change in value of derivative contracts
|
11
|
|
|
(27
|
)
|
|
(10
|
)
|
|||
Deferred income taxes
|
162
|
|
|
56
|
|
|
24
|
|
|||
Benefits associated with differential membership interests - net
|
(119
|
)
|
|
(67
|
)
|
|
(24
|
)
|
|||
Equity in earnings of equity method investee, net of distributions received
|
7
|
|
|
10
|
|
|
(6
|
)
|
|||
Equity in earnings of non-economic ownership interests
|
(11
|
)
|
|
4
|
|
|
2
|
|
|||
Change in the fair value of contingent consideration for pipeline acquisition
|
—
|
|
|
(189
|
)
|
|
—
|
|
|||
Other - net
|
11
|
|
|
22
|
|
|
14
|
|
|||
Changes in operating assets and liabilities:
|
|
|
|
|
|
||||||
Accounts receivable
|
1
|
|
|
(14
|
)
|
|
(7
|
)
|
|||
Other current assets
|
(7
|
)
|
|
(3
|
)
|
|
14
|
|
|||
Other non-current assets
|
(5
|
)
|
|
(2
|
)
|
|
—
|
|
|||
Accounts payable and accrued expenses
|
6
|
|
|
3
|
|
|
—
|
|
|||
Due to related parties
|
1
|
|
|
(2
|
)
|
|
3
|
|
|||
Other current liabilities
|
28
|
|
|
4
|
|
|
5
|
|
|||
Payment of acquisition holdback
|
(14
|
)
|
|
—
|
|
|
—
|
|
|||
Other non-current liabilities
|
7
|
|
|
5
|
|
|
3
|
|
|||
Net cash provided by operating activities
|
413
|
|
|
415
|
|
|
288
|
|
|||
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
||||||
Acquisition of membership interests in subsidiaries and equity method investee
|
(1,074
|
)
|
|
(869
|
)
|
|
(1,882
|
)
|
|||
Capital expenditures
|
(349
|
)
|
|
(861
|
)
|
|
(201
|
)
|
|||
Proceeds from CITCs
|
77
|
|
|
13
|
|
|
2
|
|
|||
Payments from (to) related parties under CSCS agreement - net
|
(22
|
)
|
|
1
|
|
|
152
|
|
|||
Distribution from equity method investee
|
—
|
|
|
—
|
|
|
30
|
|
|||
Net cash used in investing activities
|
(1,368
|
)
|
|
(1,716
|
)
|
|
(1,899
|
)
|
|||
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
||||||
Proceeds from issuance of common units - net
|
—
|
|
|
645
|
|
|
343
|
|
|||
Proceeds from issuance of preferred units - net
|
548
|
|
|
—
|
|
|
—
|
|
|||
Issuances of long-term debt
|
1,880
|
|
|
771
|
|
|
1,369
|
|
|||
Retirements of long-term debt
|
(1,185
|
)
|
|
(640
|
)
|
|
(395
|
)
|
|||
Deferred financing costs
|
(24
|
)
|
|
(11
|
)
|
|
(17
|
)
|
|||
Capped call transaction including fees
|
(13
|
)
|
|
—
|
|
|
—
|
|
|||
Partners/Members' contributions
|
316
|
|
|
831
|
|
|
180
|
|
|||
Partners/Members' distributions
|
(307
|
)
|
|
(682
|
)
|
|
(1,122
|
)
|
|||
Proceeds from differential membership investors
|
33
|
|
|
416
|
|
|
463
|
|
|||
Payments to differential membership investors
|
(25
|
)
|
|
(20
|
)
|
|
(7
|
)
|
|||
Proceeds from short-term debt
|
—
|
|
|
—
|
|
|
425
|
|
|||
Repayments of short-term debt
|
—
|
|
|
(12
|
)
|
|
(313
|
)
|
|||
Change in amounts due to related parties
|
(78
|
)
|
|
4
|
|
|
(20
|
)
|
|||
Proceeds from issuance of NEP OpCo common units to noncontrolling interest
|
—
|
|
|
—
|
|
|
702
|
|
|||
Payment of acquisition holdback
|
(186
|
)
|
|
—
|
|
|
—
|
|
|||
Net cash provided by financing activities
|
959
|
|
|
1,302
|
|
|
1,608
|
|
|||
Effect of exchange rate changes on cash
|
3
|
|
|
4
|
|
|
(7
|
)
|
|||
NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS, AND RESTRICTED CASH
|
7
|
|
|
5
|
|
|
(10
|
)
|
|||
CASH, CASH EQUIVALENTS AND RESTRICTED CASH - BEGINNING OF YEAR
|
191
|
|
|
186
|
|
|
196
|
|
|||
CASH, CASH EQUIVALENTS AND RESTRICTED CASH - END OF YEAR
|
$
|
198
|
|
|
$
|
191
|
|
|
$
|
186
|
|
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
|
|
|
|
|
|
|
|
||||
Cash paid for interest, net of amounts capitalized
|
$
|
163
|
|
|
$
|
170
|
|
|
$
|
110
|
|
Members’ noncash contributions for construction costs and other
|
$
|
13
|
|
|
$
|
225
|
|
|
$
|
526
|
|
Change in noncash investments in equity method investees - net
|
$
|
7
|
|
|
$
|
108
|
|
|
$
|
(5
|
)
|
Repayments of short-term debt via deferral related to differential membership interest
|
$
|
—
|
|
|
$
|
100
|
|
|
$
|
—
|
|
Partners/Members' noncash distributions
|
$
|
—
|
|
|
$
|
33
|
|
|
$
|
42
|
|
Assumption of debt and acquisition holdbacks in connection with Texas pipelines acquisition
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,078
|
|
Asset retirement obligation additions
|
$
|
3
|
|
|
$
|
26
|
|
|
$
|
12
|
|
Accrued but not paid for capital and other expenditures
|
$
|
2
|
|
|
$
|
314
|
|
|
$
|
811
|
|
Noncash member contribution upon transition from predecessor method
|
$
|
3
|
|
|
$
|
19
|
|
|
$
|
3
|
|
Change in goodwill related to change in purchase accounting valuation
|
$
|
—
|
|
|
$
|
6
|
|
|
$
|
—
|
|
Accrued preferred distributions
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(a)
|
Prior-period financial information has been retrospectively adjusted as discussed in Note 2 - Basis of Presentation and Restricted Cash.
|
|
Preferred Units
|
|
Common Units
|
|
|
|
|
|
|
||||||||||||||||
|
Units
|
|
Amount
|
|
Units
|
|
Amount
|
|
Accumulated
Other
Comprehensive Income
(Loss)
(a)
|
|
Non-controlling
Interest
(a)
|
|
Total
Equity
(a)
|
||||||||||||
Balances, December 31, 2014
|
—
|
|
|
$
|
—
|
|
|
18.7
|
|
|
$
|
551
|
|
|
$
|
(3
|
)
|
|
$
|
1,672
|
|
|
$
|
2,220
|
|
Limited partners/related party contribution and transition
|
—
|
|
|
—
|
|
|
—
|
|
|
51
|
|
(b)
|
—
|
|
|
3
|
|
(c)
|
54
|
|
|||||
Issuance of common units - net
|
—
|
|
|
—
|
|
|
11.9
|
|
|
343
|
|
|
—
|
|
|
—
|
|
|
343
|
|
|||||
Acquisition of membership interests in subsidiaries
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(949
|
)
|
|
(949
|
)
|
|||||
Acquisition of noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
69
|
|
|
69
|
|
|||||
Related party note receivable
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(28
|
)
|
|
(28
|
)
|
|||||
Net income
(d)
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
97
|
|
|
107
|
|
|||||
Other comprehensive loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
(46
|
)
|
|
(49
|
)
|
|||||
Proceeds from issuance of NEP OpCo common units to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
702
|
|
|
702
|
|
|||||
Related party contributions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
706
|
|
|
706
|
|
|||||
Related party distributions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,117
|
)
|
|
(1,117
|
)
|
|||||
Changes in non-economic ownership interests and equity method investees
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
5
|
|
|||||
Distributions to unitholders
(e)
|
—
|
|
|
—
|
|
|
—
|
|
|
(20
|
)
|
|
—
|
|
|
—
|
|
|
(20
|
)
|
|||||
Balances, December 31, 2015
|
—
|
|
|
—
|
|
|
30.6
|
|
|
935
|
|
|
(6
|
)
|
|
1,114
|
|
|
2,043
|
|
|||||
Limited partners/related party contribution and transition
|
—
|
|
|
—
|
|
|
—
|
|
|
139
|
|
(b)
|
—
|
|
|
(19
|
)
|
(c)
|
120
|
|
|||||
Issuance of common units - net
|
—
|
|
|
—
|
|
|
23.6
|
|
|
645
|
|
|
—
|
|
|
—
|
|
|
645
|
|
|||||
Acquisition of membership interests in subsidiaries and equity method investee
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(869
|
)
|
|
(869
|
)
|
|||||
Related party note receivable
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(19
|
)
|
|
(19
|
)
|
|||||
Net income
(d)
|
—
|
|
|
—
|
|
|
—
|
|
|
82
|
|
|
—
|
|
|
298
|
|
|
380
|
|
|||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
10
|
|
|
13
|
|
|||||
Related party contributions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,052
|
|
|
1,052
|
|
|||||
Related party distributions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(634
|
)
|
|
(634
|
)
|
|||||
Changes in non-economic ownership interests and equity method investees
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(110
|
)
|
|
(110
|
)
|
|||||
Distributions to unitholders
(e)
|
—
|
|
|
—
|
|
|
—
|
|
|
(55
|
)
|
|
—
|
|
|
—
|
|
|
(55
|
)
|
|||||
Balances, December 31, 2016
|
—
|
|
|
—
|
|
|
54.2
|
|
|
1,746
|
|
|
(3
|
)
|
|
823
|
|
|
2,566
|
|
|||||
Limited partners/related party contribution and transition
|
—
|
|
|
—
|
|
|
—
|
|
|
51
|
|
(b)
|
—
|
|
|
(3
|
)
|
(c)
|
48
|
|
|||||
Issuance of common units - net
|
—
|
|
|
—
|
|
|
0.1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
Acquisition of membership interests in subsidiaries and equity method investee
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,074
|
)
|
|
(1,074
|
)
|
|||||
Issuance of preferred units - net
|
14
|
|
|
548
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
548
|
|
|||||
Capped call transaction
|
—
|
|
|
—
|
|
|
—
|
|
|
(13
|
)
|
|
—
|
|
|
—
|
|
|
(13
|
)
|
|||||
Related party note receivable
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
7
|
|
|||||
Net income
(d)
|
—
|
|
|
3
|
|
|
—
|
|
|
(65
|
)
|
|
—
|
|
|
171
|
|
|
109
|
|
|||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
13
|
|
|
17
|
|
|||||
Related party contributions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
321
|
|
|
321
|
|
|||||
Related party distributions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(226
|
)
|
|
(226
|
)
|
|||||
Changes in non-economic ownership interests and equity method investee
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
|
(12
|
)
|
|||||
Distributions to unitholders
(e)
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
(81
|
)
|
|
—
|
|
|
—
|
|
|
(84
|
)
|
|||||
Balances, December 31, 2017
|
14
|
|
|
$
|
548
|
|
|
54.3
|
|
|
$
|
1,639
|
|
|
$
|
1
|
|
|
$
|
20
|
|
|
$
|
2,208
|
|
(a)
|
Prior-period financial information has been retrospectively adjusted as discussed in Note 2 - Basis of Presentation.
|
|||||||||||
(b)
|
Deferred tax asset recognized by NEP related to NEP equity issuances and/or acquisition of subsidiary membership interests.
|
|||||||||||
(c)
|
Related party noncash contributions, net, upon transition from predecessor accounting method.
|
|||||||||||
(d)
|
Net income attributable to noncontrolling interest includes the pre-acquisition net income of the common control acquisitions. See Note 2 - Basis of Presentation.
|
|||||||||||
(e)
|
Distributions per common unit were $1.49, $1.2975, and $0.905 for the years ended December 31, 2017, 2016, and 2015, respectively. At December 31, 2017, approximately $3 million of preferred unit distributions were accrued and are payable in February 2018.
|
|
Year Ended December 31, 2015
|
||
|
(millions)
|
||
Unaudited pro forma results of operations:
|
|
||
Pro forma revenues
|
$
|
572
|
|
Pro forma operating income
|
$
|
251
|
|
Pro forma net income
|
$
|
94
|
|
Pro forma net income (loss) attributable to NEP
|
$
|
9
|
|
•
|
reflect the historical results of the Texas pipeline business beginning on January 1, 2014, excluding certain operations which were not acquired by NEP;
|
•
|
reflect the estimated depreciation and amortization expense based on the estimated fair value of property, plant and equipment - net and the intangible assets - customer relationships;
|
•
|
reflect additional interest expense related to financing transactions to fund the acquisition; and
|
•
|
reflect related income tax effects.
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(millions)
|
||||||||||
U.S.
|
$
|
209
|
|
|
$
|
395
|
|
|
$
|
92
|
|
Foreign
|
67
|
|
|
42
|
|
|
48
|
|
|||
Income before income taxes
|
$
|
276
|
|
|
$
|
437
|
|
|
$
|
140
|
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(millions)
|
||||||||||
Federal:
|
|
|
|
|
|
||||||
Current
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4
|
|
Deferred
|
143
|
|
|
51
|
|
|
19
|
|
|||
Total federal
|
143
|
|
|
51
|
|
|
23
|
|
|||
State:
|
|
|
|
|
|
||||||
Current
|
—
|
|
|
—
|
|
|
—
|
|
|||
Deferred
|
8
|
|
|
11
|
|
|
1
|
|
|||
Total state
|
8
|
|
|
11
|
|
|
1
|
|
|||
Foreign:
|
|
|
|
|
|
||||||
Current
|
5
|
|
|
1
|
|
|
5
|
|
|||
Deferred
|
11
|
|
|
(6
|
)
|
|
4
|
|
|||
Total foreign
|
16
|
|
|
(5
|
)
|
|
9
|
|
|||
Total income tax expense
|
$
|
167
|
|
|
$
|
57
|
|
|
$
|
33
|
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(millions)
|
||||||||||
Income tax expense at 35% statutory rate
|
$
|
97
|
|
|
$
|
153
|
|
|
$
|
49
|
|
Increases (reductions) resulting from:
|
|
|
|
|
|
||||||
Taxes attributable to U.S. noncontrolling interest
|
(32
|
)
|
|
(74
|
)
|
|
(13
|
)
|
|||
State income taxes, net of federal tax benefit
|
6
|
|
|
7
|
|
|
1
|
|
|||
Tax credits
|
(1
|
)
|
|
(9
|
)
|
|
(7
|
)
|
|||
Valuation allowance
|
(1
|
)
|
|
(6
|
)
|
|
9
|
|
|||
Effect of flow through entities and foreign tax differential
|
(7
|
)
|
|
(6
|
)
|
|
(4
|
)
|
|||
U.S. taxes on foreign earnings
|
7
|
|
|
4
|
|
|
2
|
|
|||
Impact of tax reform
|
101
|
|
|
—
|
|
|
—
|
|
|||
Withholding taxes, net of U.S. federal tax
|
—
|
|
|
(2
|
)
|
|
(3
|
)
|
|||
Effect of Canadian tax restructuring, net of U.S. federal tax
|
—
|
|
|
(11
|
)
|
|
—
|
|
|||
Other
|
(3
|
)
|
|
1
|
|
|
(1
|
)
|
|||
Income tax expense
|
$
|
167
|
|
|
$
|
57
|
|
|
$
|
33
|
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(millions)
|
||||||
Deferred tax liabilities:
|
|
|
|
||||
Property
|
$
|
(70
|
)
|
|
$
|
(51
|
)
|
Investment in partnership
|
(7
|
)
|
|
(120
|
)
|
||
Other
|
(4
|
)
|
|
(3
|
)
|
||
Total deferred tax liabilities
|
(81
|
)
|
|
(174
|
)
|
||
Deferred tax asset:
|
|
|
|
||||
Net operating loss
|
184
|
|
|
321
|
|
||
Investment in partnership
|
—
|
|
|
68
|
|
||
Tax credit carryforwards
|
8
|
|
|
17
|
|
||
Other
|
8
|
|
|
8
|
|
||
Valuation allowance
|
(1
|
)
|
|
(1
|
)
|
||
Total deferred tax asset
|
199
|
|
|
413
|
|
||
Net deferred tax asset
|
$
|
118
|
|
|
$
|
239
|
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(millions)
|
||||||
Deferred income taxes - assets
|
$
|
181
|
|
|
$
|
286
|
|
Deferred income taxes - liabilities
|
(63
|
)
|
|
(47
|
)
|
||
Net deferred income taxes
|
$
|
118
|
|
|
$
|
239
|
|
|
Amount
|
|
Expiration Dates
|
||
|
(millions)
|
|
|
||
Net operating loss carryforwards:
|
|
|
|
||
Federal
|
$
|
157
|
|
|
2034 - 2037
|
State
|
27
|
|
|
2024 - 2037
|
|
Total net operating loss carryforwards
|
$
|
184
|
|
|
|
Tax credit carryforwards
|
$
|
8
|
|
|
2019 - 2037
|
|
December 31, 2017
|
|
December 31, 2016
|
||||||||||||||||||||
|
Level 1
|
|
Level 2
|
|
Total
|
|
Level 1
|
|
Level 2
|
|
Total
|
||||||||||||
|
(millions)
|
||||||||||||||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Cash equivalents
|
$
|
61
|
|
|
$
|
—
|
|
|
$
|
61
|
|
|
$
|
66
|
|
|
$
|
—
|
|
|
$
|
66
|
|
Restricted cash equivalents
|
31
|
|
|
—
|
|
|
31
|
|
|
29
|
|
|
—
|
|
|
29
|
|
||||||
Foreign currency contracts
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
||||||
Interest rate contracts
|
—
|
|
|
15
|
|
|
15
|
|
|
—
|
|
|
15
|
|
|
15
|
|
||||||
Total assets
|
$
|
92
|
|
|
$
|
15
|
|
|
$
|
107
|
|
|
$
|
95
|
|
|
$
|
16
|
|
|
$
|
111
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Foreign currency contracts
|
$
|
—
|
|
|
$
|
3
|
|
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Interest rate contracts
|
—
|
|
|
44
|
|
|
44
|
|
|
—
|
|
|
44
|
|
|
44
|
|
||||||
Total liabilities
|
$
|
—
|
|
|
$
|
47
|
|
|
$
|
47
|
|
|
$
|
—
|
|
|
$
|
44
|
|
|
$
|
44
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||||||||||
|
Carrying
Value
|
|
Fair
Value
|
|
Carrying
Value
|
|
Fair
Value
|
||||||||
|
(millions)
|
||||||||||||||
Long-term debt, including current maturities
(a)
|
$
|
4,317
|
|
|
$
|
4,456
|
|
|
$
|
3,586
|
|
|
$
|
3,680
|
|
(a)
|
At
December 31, 2017 and 2016, approximately
$3,552 million
and
$2,808 million
, respectively, of the fair value is estimated using a market approach based on quoted market prices for the same or similar issues (Level 2); the balance is estimated using an income approach utilizing a discounted cash flow valuation technique, considering the current credit profile of the debtor (Level 3).
|
|
December 31, 2017
|
|||||||||||||||
|
|
Fair Values of Derivatives Not
Designated as Hedging
Instruments for Accounting
Purposes - Gross Basis
|
|
Total Derivatives Combined -
Net Basis
|
||||||||||||
|
|
Assets
|
|
Liabilities
|
|
Assets
|
|
Liabilities
|
||||||||
|
(millions)
|
|||||||||||||||
Interest rate contracts
|
|
$
|
15
|
|
|
$
|
44
|
|
|
$
|
18
|
|
|
$
|
47
|
|
Foreign currency contracts
|
|
—
|
|
|
3
|
|
|
—
|
|
|
3
|
|
||||
Total fair values
|
|
$
|
15
|
|
|
$
|
47
|
|
|
$
|
18
|
|
|
$
|
50
|
|
|
|
|
|
|
|
|
|
|
||||||||
Net fair value by balance sheet line item:
|
|
|
|
|
|
|
|
|
||||||||
Other current assets
|
|
|
|
|
|
$
|
10
|
|
|
|
||||||
Other non-current assets
|
|
|
|
|
|
8
|
|
|
|
|||||||
Current derivative liabilities
|
|
|
|
|
|
|
|
$
|
11
|
|
||||||
Other non-current liabilities
|
|
|
|
|
|
|
|
39
|
|
|||||||
Total derivatives
|
|
|
|
|
|
$
|
18
|
|
|
$
|
50
|
|
|
December 31, 2016
|
|||||||||||||||
|
|
Fair Values of Derivatives Not
Designated as Hedging
Instruments for Accounting
Purposes - Gross Basis
|
|
Total Derivatives Combined -
Net Basis
|
||||||||||||
|
|
Assets
|
|
Liabilities
|
|
Assets
|
|
Liabilities
|
||||||||
|
(millions)
|
|||||||||||||||
Interest rate contracts
|
|
$
|
15
|
|
|
$
|
44
|
|
|
$
|
17
|
|
|
$
|
46
|
|
Foreign currency contracts
|
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
||||
Total fair values
|
|
$
|
16
|
|
|
$
|
44
|
|
|
$
|
18
|
|
|
$
|
46
|
|
|
|
|
|
|
|
|
|
|
||||||||
Net fair value by balance sheet line item:
|
|
|
|
|
|
|
|
|
||||||||
Other current assets
|
|
|
|
|
|
$
|
1
|
|
|
|
||||||
Other non-current assets
|
|
|
|
|
|
17
|
|
|
|
|||||||
Current derivative liabilities
|
|
|
|
|
|
|
|
$
|
18
|
|
||||||
Other non-current liabilities
|
|
|
|
|
|
|
|
28
|
|
|||||||
Total derivatives
|
|
|
|
|
|
$
|
18
|
|
|
$
|
46
|
|
|
Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(millions)
|
||||||||||
Interest rate contracts:
|
|
||||||||||
Losses recognized in other comprehensive income
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(15
|
)
|
Losses reclassified from AOCI to interest expense
|
$
|
(7
|
)
|
|
$
|
(8
|
)
|
|
$
|
(6
|
)
|
Gains (losses) recognized in interest expense
|
$
|
(14
|
)
|
|
$
|
14
|
|
|
$
|
8
|
|
|
2017
|
|
2016
|
|
Range of Useful
Lives (in years) |
||||
|
(millions)
|
|
|
||||||
Power-generation assets
(a)
|
$
|
5,712
|
|
|
$
|
5,643
|
|
|
5 - 35
|
Pipeline assets, including temporary rights-of-way
|
807
|
|
|
771
|
|
|
50
|
||
Land improvements and buildings
|
262
|
|
|
244
|
|
|
25 - 35
|
||
Land, including perpetual rights-of-way
|
60
|
|
|
71
|
|
|
|
||
Construction work in progress
|
7
|
|
|
7
|
|
|
|
||
Other depreciable assets
|
280
|
|
|
282
|
|
|
3 - 35
|
||
Property, plant and equipment, gross
|
7,128
|
|
|
7,018
|
|
|
|
||
Accumulated depreciation
|
(931
|
)
|
|
(720
|
)
|
|
|
||
Property, plant and equipment - net
|
$
|
6,197
|
|
|
$
|
6,298
|
|
|
|
(a)
|
Approximately
82%
of power generation assets represent machinery and equipment used to generate electricity with a
35
-year depreciable life.
|
|
2017
|
|
2016
|
||||
|
(millions)
|
||||||
Current assets
|
$
|
135
|
|
|
$
|
291
|
|
Noncurrent assets
|
$
|
1,349
|
|
|
$
|
1,392
|
|
Current liabilities
|
$
|
64
|
|
|
$
|
64
|
|
Noncurrent liabilities
|
$
|
1,003
|
|
|
$
|
1,043
|
|
Revenues
|
$
|
207
|
|
|
$
|
211
|
|
Operating income
|
$
|
127
|
|
|
$
|
129
|
|
Net income
|
$
|
80
|
|
|
$
|
80
|
|
|
|
|
|
||||
NEP's share of underlying equity in the equity method investee
|
$
|
208
|
|
|
$
|
288
|
|
Difference between investment carrying amount and underlying equity in net assets
(a)
|
10
|
|
|
10
|
|
||
NEP's investment carrying amount
|
$
|
218
|
|
|
$
|
298
|
|
(a)
|
Substantially all of the difference between the investment carrying amount and the underlying equity in net assets is being amortized over the life of the related projects.
|
|
|
|
December 31,
|
||||||||||||
|
|
|
2017
|
|
2016
|
||||||||||
|
Maturity
Date |
|
Balance
|
|
Weighted-Average
Interest Rate
|
|
Balance
|
|
Weighted-Average
Interest Rate
|
||||||
|
|
|
(millions)
|
|
|
|
(millions)
|
|
|
||||||
NEP:
|
|
|
|
|
|
|
|
|
|
||||||
Senior unsecured convertible notes - fixed
(a)
|
2020
|
|
$
|
300
|
|
|
1.50
|
%
|
|
$
|
—
|
|
|
|
|
NEP OpCo:
|
|
|
|
|
|
|
|
|
|
||||||
Senior unsecured notes - fixed
(b)
|
2024 - 2027
|
|
1,100
|
|
|
4.38
|
%
|
|
$
|
—
|
|
|
|
||
Term loans - variable
(c)(d)
|
2018 - 2019
|
|
—
|
|
|
|
|
|
600
|
|
|
2.87
|
%
|
||
Project level:
|
|
|
|
|
|
|
|
|
|
||||||
Senior secured limited-recourse debt - fixed
|
2030 - 2038
|
|
1,355
|
|
|
5.33
|
%
|
|
1,364
|
|
|
5.34
|
%
|
||
Senior secured limited-recourse debt - variable
(c)(d)
|
2019 - 2033
|
|
648
|
|
|
3.20
|
%
|
|
695
|
|
|
2.60
|
%
|
||
Bank loan
(c)(d)
|
2020
|
|
200
|
|
|
3.52
|
%
|
|
200
|
|
|
2.66
|
%
|
||
Limited-recourse revolving credit facility - variable
(c)(e)
|
2020
|
|
150
|
|
|
3.72
|
%
|
|
150
|
|
|
2.73
|
%
|
||
Non-recourse notes payable - fixed
|
2028
|
|
22
|
|
|
6.30
|
%
|
|
24
|
|
|
6.30
|
%
|
||
Limited-recourse term loan - variable
(c)(d)
|
2022
|
|
604
|
|
|
3.82
|
%
|
|
604
|
|
|
2.97
|
%
|
||
Unamortized debt issuance costs
|
|
|
(64
|
)
|
|
|
|
(53
|
)
|
|
|
||||
Unamortized discount
|
|
|
2
|
|
|
|
|
2
|
|
|
|
||||
Total long-term debt
|
|
|
4,317
|
|
|
|
|
3,586
|
|
|
|
||||
Less current maturities of long-term debt
|
|
|
99
|
|
|
|
|
78
|
|
|
|
||||
Long-term debt, excluding current maturities
|
|
|
$
|
4,218
|
|
|
|
|
$
|
3,508
|
|
|
|
(a)
|
See additional discussion of the convertible notes below.
|
(b)
|
Represents
$550 million
in aggregate principal amount of
4.25%
senior unsecured notes due 2024 and
$550 million
in aggregate principal amount of
4.50%
senior unsecured notes due 2027.
|
(c)
|
Variable rate is based on an underlying index plus a margin.
|
(d)
|
Interest rate contracts, primarily swaps, have been entered into for a majority of these debt issuances. See Note 6.
|
(e)
|
The limited-recourse revolving credit facility provides up to
$150 million
of revolving credit loans if certain conditions are satisfied, including, among other things, meeting a leverage ratio at the time of any borrowing that does not exceed a specified ratio.
|
|
Accumulated Other Comprehensive Income (Loss)
|
|||||||||||||||||
|
Net Unrealized
Gains (Losses) on
Cash Flow Hedges
|
|
Net Unrealized
Gains (Losses) on
Foreign Currency
Translation
|
|
Other Comprehensive
Income (Loss) Related to
Equity Method Investee
|
Total
|
||||||||||||
|
(millions)
|
|||||||||||||||||
Balances, December 31, 2014
|
$
|
(4
|
)
|
|
$
|
(66
|
)
|
|
$
|
(38
|
)
|
$
|
(108
|
)
|
||||
Other comprehensive loss before reclassification
|
(12
|
)
|
|
(42
|
)
|
|
—
|
|
(54
|
)
|
||||||||
Amounts reclassified from AOCI to interest expense
|
5
|
|
|
—
|
|
|
—
|
|
5
|
|
||||||||
Net other comprehensive loss
|
(7
|
)
|
|
(42
|
)
|
|
—
|
|
(49
|
)
|
||||||||
Balances, December 31, 2015
|
(11
|
)
|
|
(108
|
)
|
|
(38
|
)
|
(157
|
)
|
||||||||
Other comprehensive income before reclassification
|
—
|
|
|
3
|
|
|
—
|
|
3
|
|
||||||||
Amounts reclassified from AOCI to interest expense
|
7
|
|
|
—
|
|
|
—
|
|
7
|
|
||||||||
Other comprehensive income related to equity method investee
|
—
|
|
|
—
|
|
|
3
|
|
3
|
|
||||||||
Net other comprehensive income
|
7
|
|
|
3
|
|
|
3
|
|
13
|
|
||||||||
Balances, December 31, 2016
|
(4
|
)
|
|
(105
|
)
|
|
(35
|
)
|
(144
|
)
|
||||||||
Other comprehensive income before reclassification
|
—
|
|
|
7
|
|
|
—
|
|
7
|
|
||||||||
Amounts reclassified from AOCI to interest expense
|
5
|
|
|
—
|
|
|
—
|
|
5
|
|
||||||||
Other comprehensive income related to equity method investee
|
—
|
|
|
—
|
|
|
5
|
|
5
|
|
||||||||
Net other comprehensive income
|
5
|
|
|
7
|
|
|
5
|
|
17
|
|
||||||||
Balances, December 31, 2017
|
$
|
1
|
|
|
$
|
(98
|
)
|
|
$
|
(30
|
)
|
$
|
(127
|
)
|
||||
AOCI attributable to noncontrolling interest
|
$
|
(1
|
)
|
|
$
|
(96
|
)
|
|
$
|
(31
|
)
|
$
|
(128
|
)
|
||||
AOCI attributable to NextEra Energy Partners, December 31, 2017
|
$
|
2
|
|
|
$
|
(2
|
)
|
|
$
|
1
|
|
$
|
1
|
|
Year Ending December 31,
|
|
Commitments
|
||
|
|
(millions)
|
||
2018
|
|
$
|
37
|
|
2019
|
|
35
|
|
|
2020
|
|
35
|
|
|
2021
|
|
35
|
|
|
2022
|
|
36
|
|
|
Thereafter
|
|
541
|
|
|
Total estimated payments
|
|
$
|
719
|
|
|
March 31
(a)
|
|
June 30
(a)
|
|
September 30
(a)
|
|
December 31
(a)
|
||||||||
|
(millions, except per unit amounts)
|
||||||||||||||
2017
|
|
|
|
|
|
|
|
||||||||
Operating revenues
(b)
|
$
|
198
|
|
|
$
|
220
|
|
|
$
|
192
|
|
|
$
|
197
|
|
Operating income
(c)
|
$
|
82
|
|
|
$
|
92
|
|
|
$
|
68
|
|
|
$
|
65
|
|
Net income (loss)
(d)
|
$
|
57
|
|
|
$
|
62
|
|
|
$
|
48
|
|
|
$
|
(56
|
)
|
Net income (loss) attributable to NEP
|
$
|
12
|
|
|
$
|
13
|
|
|
$
|
1
|
|
|
$
|
(91
|
)
|
Earnings (loss) per unit - basic and assuming dilution
|
$
|
0.22
|
|
|
$
|
0.24
|
|
|
$
|
0.01
|
|
|
$
|
(1.67
|
)
|
Distributions per unit
|
$
|
0.35
|
|
|
$
|
0.37
|
|
|
$
|
0.38
|
|
|
$
|
0.39
|
|
High-low common unit sales prices
|
$33.90 - $25.32
|
|
|
$39.83 - $31.78
|
|
|
$43.68 - $36.37
|
|
|
$44.00 - $36.42
|
|
||||
2016
|
|
|
|
|
|
|
|
||||||||
Operating revenues
(b)
|
$
|
185
|
|
|
$
|
195
|
|
|
$
|
199
|
|
|
$
|
191
|
|
Operating income
(c)
|
$
|
78
|
|
|
$
|
82
|
|
|
$
|
81
|
|
|
$
|
59
|
|
Net income
(d)
|
$
|
(6
|
)
|
|
$
|
44
|
|
|
$
|
155
|
|
|
$
|
189
|
|
Net income attributable to NEP
|
$
|
5
|
|
|
$
|
8
|
|
|
$
|
27
|
|
|
$
|
42
|
|
Earnings per unit - basic and assuming dilution
|
$
|
0.14
|
|
|
$
|
0.19
|
|
|
$
|
0.62
|
|
|
$
|
0.78
|
|
Distributions per unit
|
$
|
0.31
|
|
|
$
|
0.32
|
|
|
$
|
0.33
|
|
|
$
|
0.34
|
|
High-low common unit sales prices
|
$30.15 - $23.78
|
|
|
$30.59 - $25.86
|
|
|
$32.42 - $27.60
|
|
|
$28.93 - $23.90
|
|
(a)
|
In the opinion of management, all adjustments, which consist of normal recurring accruals necessary to present a fair statement of the amounts shown for such periods, have been made. Results of operations for an interim period generally will not give a true indication of results for the year. Variations in operations reported on a quarterly basis primarily reflect the seasonal nature of NEP's business, and, in 2017, reflect the impact of tax reform in December 2017. The sum of the quarterly amounts may not equal the total for the year due to rounding.
|
(b)
|
Operating revenues include increases of approximately
$23 million
,
$16 million
,
$15 million
,
$14 million
,
$7 million
,
$8 million
and
$15 million
for the quarterly periods ended March 31, 2017, June 30, 2017, September 30, 2017, March 31, 2016, June 30, 2016, September 30, 2016 and December 31, 2016, respectively, from previously reported amounts reflecting retrospective adjustments for common control acquisitions.
|
(c)
|
Operating income includes increases of approximately
$9 million
,
$4 million
,
$2 million
,
$5 million
,
$1 million
and
$1 million
for the quarterly periods ended March 31, 2017, June 30, 2017, September 30, 2017, March 31, 2016, September 30, 2016 and December 31, 2016, respectively, from previously reported amounts reflecting retrospective adjustments for common control acquisitions.
|
(d)
|
Net income includes increases of approximately
$16 million
,
$12 million
,
$10 million
,
$6 million
,
$3 million
,
$20 million
and
$4 million
for the quarterly periods ended March 31, 2017, June 30, 2017, September 30, 2017, March 31, 2016, June 30, 2016, September 30, 2016 and December 31, 2016, respectively, from previously reported amounts reflecting retrospective adjustments for common control acquisitions.
|
Name
|
|
Age
|
|
Position
|
James L. Robo
|
|
55
|
|
Chairman of the Board and Chief Executive Officer, Director
|
Susan D. Austin
|
|
50
|
|
Director
|
Mark E. Hickson
|
|
51
|
|
Executive Vice President, Strategy and Corporate Development, Director
|
John W. Ketchum
|
|
47
|
|
Chief Financial Officer, Director
|
Peter H. Kind
|
|
61
|
|
Director
|
Armando Pimentel, Jr.
|
|
55
|
|
President, Director
|
James N. Suciu
|
|
61
|
|
Director
|
Terrell Kirk Crews, II
|
|
39
|
|
Controller and Chief Accounting Officer
|
Paul I. Cutler
|
|
58
|
|
Treasurer and Assistant Secretary
|
Charles E. Sieving
|
|
45
|
|
General Counsel
|
(1)
|
Complaints or similar communications regarding accounting, internal accounting controls or auditing matters will be handled in accordance with the NextEra Energy Partners, LP Procedures for Receipt, Retention and Treatment of Complaints and Concerns Regarding Accounting, Internal Accounting Controls or Auditing Matters.
|
(2)
|
All other legitimate communications related to the duties and responsibilities of the board or any committee will be promptly forwarded by the general counsel to the applicable directors, including, as appropriate under the circumstances, to the chairman of the board and/or the appropriate committee chair.
|
(3)
|
All other unitholder, customer, vendor, employee and other complaints, concerns and communications will be handled by management, with board involvement as advisable with respect to those matters that management reasonably concludes to be significant.
|
Name
|
Fees
Earned
or Paid in
Cash
|
|
Unit
Awards
|
|
Option
Awards
|
|
Non-Equity
Incentive Plan
Compensation
|
|
Change in
Pension Value
and Nonqualified
Deferred
Compensation
Earnings
|
|
All Other
Compensation
|
|
Total
|
||||||||||||||
Susan D. Austin
(a)
|
$
|
60,000
|
|
|
$
|
110,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
170,000
|
|
Robert J. Byrne
(b)
|
$
|
37,500
|
|
|
$
|
110,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
147,500
|
|
Peter H. Kind
(c)
|
$
|
75,000
|
|
|
$
|
110,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
185,000
|
|
James N. Suciu
(d)
|
$
|
56,250
|
|
|
$
|
110,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
166,250
|
|
(a)
|
Ms. Austin was granted 3,570 common units in 2017 with a grant date fair value of $110,000. As of December 31, 2017, Ms. Austin owned 9,970 common units.
|
(b)
|
Mr. Byrne was granted 3,570 common units in 2017 with a grant date fair value of $110,000. As of December 31, 2017, Mr. Byrne owned 15,200 common units. Mr. Byrne resigned from the board of directors of NEP GP effective April 26, 2017. Mr. Byrne did not serve on the board of directors of NEP.
|
(c)
|
Mr. Kind was granted 3,570 common units in 2017 with a grant date fair value of $110,000. As of December 31, 2017, Mr. Kind owned 13,900 common units.
|
(d)
|
Mr. Suciu was granted 3,290 common units in 2017 with a grant date fair value of $110,000. As of December 31, 2017, Mr. Suciu owned 3,290 common units.
|
Title of Class
|
|
Name of Beneficial Owner
|
|
Amount and Nature of
Beneficial Ownership
(a)
|
|
Percent of
Class
|
Special Voting Units
|
|
NextEra Energy, Inc.
(b)
|
|
101,440,000
|
|
100.00%
|
Common Units
|
|
Neuberger Berman Group LLC
(c)
|
|
7,907,794
|
|
14.58%
|
Common Units
|
|
Energy Income Partners, LLC
(d)
|
|
5,746,574
|
|
10.59%
|
Common Units
|
|
The Charger Corporation
(e)
|
|
3,816,144
|
|
7.03%
|
Preferred Units
(f)
|
|
BlackRock, Inc.
(g)
|
|
8,922,811
|
|
63.64%
|
Preferred Units
(f)
|
|
KKR Flatirons Aggregator L.P.
(h)
|
|
5,098,750
|
|
36.36%
|
(a)
|
The amounts and percentage of units beneficially owned are reported pursuant to the SEC rules governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a "beneficial owner" of a security if that person has or shares "voting power," which includes the power to vote or to direct the voting of such security, or "investment power," which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities, and a person may be deemed a beneficial owner of securities as to which he has no economic interest. The voting rights of NEP’s units are subject to certain limitations described in NEP’s partnership agreement.
|
|
|
(b)
|
NEE Equity holds non-economic special voting units that provide NEE Equity with a number of votes on matters to be voted on by NEP’s unitholders that equals the aggregate number of common units of NEP OpCo held by NEE Equity on the relevant record date. As of February 20, 2018, NEE Equity held 101,440,000 special voting units. Furthermore, NEE has implemented a NEP common unit repurchase program. Under the program, another subsidiary of NEE has acquired 1,402,483 common units. In the aggregate, the special voting units and common units held by subsidiaries of NEE represent approximately 60.6% of NEP's outstanding voting power. The address of NextEra Energy, Inc. is 700 Universe Blvd., Juno Beach, FL 33408
|
|
|
(c)
|
This information has been derived from a statement on Schedule 13G/A of Neuberger Berman Group LLC and Neuberger Berman Investment Advisers LLC filed with the SEC on February 15, 2018 and is as of December 31, 2017. Neuberger Berman Group LLC, Neuberger Berman Trust Co N.A., Neuberger Berman Trust Co of Delaware N.A., NB Alternatives Advisers LLC and Neuberger Berman Investment Advisers LLC and certain affiliated persons may be deemed to beneficially own the securities in their various fiduciary capacities by virtue of the provisions of Exchange Act Rule 13d-3. Neuberger Berman Group LLC, through its subsidiaries Neuberger Berman Fixed Income Holdings LLC, NB Alternatives Holdings LLC and Neuberger Trust Holdings LLC, controls Neuberger Berman Trust Co N.A., Neuberger Berman Trust Co of Delaware N.A., NB Alternatives Advisers LLC, Neuberger Berman Investment Advisers LLC and certain affiliated persons. With regard to 7,552,361 NEP common units, Neuberger Berman Group LLC may be deemed to be the beneficial owner because certain affiliated persons have shared power to retain, dispose of and vote the securities. In addition to the holdings of individual advisory clients, Neuberger Berman Investment Advisers LLC serves as investment manager of Neuberger Berman Group LLC’s various registered mutual funds which hold such shares. The holdings belonging to clients of Neuberger Berman Trust Co N.A., Neuberger Berman Trust Co of Delaware N.A., NB Alternatives Advisers LLC and Neuberger Berman Investment Advisers LLC are also aggregated to comprise the 7,552,361 common units. In addition to the 7,552,361 common units for which Neuberger entities also have shared power to dispose of the common units, the amount of 7,907,794 common units also includes common units from individual client accounts over which Neuberger Berman Investment Advisers LLC has shared power to dispose but do not have voting power over these shares. The holdings of Neuberger Berman Trust Co N.A., Neuberger Berman Trust Co of Delaware N.A., NB Alternatives Advisers LLC and Neuberger Berman Investment Advisers LLC are also aggregated to comprise the amount of 7,907,794 referenced herein. The address of each of Neuberger Berman Group LLC and Neuberger Berman Investment Advisers LLC is 1290 Avenue of the Americas, New York, NY 10104.
|
|
|
(d)
|
This information has been derived from a statement on Schedule 13G/A of Energy Income Partners, LLC and the other entities and individuals described below filed with the SEC on February 14, 2018 and is as of December 31, 2017. James J. Murchie, Eva Pao and John K. Tysseland are the portfolio managers with respect to portfolios managed by Energy Income Partners, LLC. Linda A. Longville and Saul Ballesteros are control persons of Energy Income Partners, LLC. Collectively, Energy Income Partners, LLC and such other entities and individuals hold shared voting power and shared dispositive power over the 5,746,574 common units reported above. Energy Income Partners, LLC serves as a sub-advisor to certain registered companies advised by First Trust Advisors LP (Sub-Advised Funds). As of December 31, 2017, the Sub-Advised Funds beneficially owned 8.1% of the common units. The address of each of Energy Income Partners, LLC, Mr. Murchie, Ms. Pao, Mr. Tysseland, Ms. Longville and Mr. Ballesteros is 10 Wright Street, Westport, CT 06880.
|
|
|
(e)
|
This information has been derived from a statement on Schedule 13G/A of The Charger Corporation, First Trust Portfolios L.P. and First Trust Advisors L.P., filed with the SEC on January 23, 2018, and is as of December 31, 2017. The Charger Corporation is the general partner of both First Trust Portfolios L.P. and First Trust Advisors L.P. First Trust Portfolios L.P. acts as sponsor of certain unit investment trusts which hold common units. 3,816,144 common units are held by unit investment trusts sponsored by First Trust Portfolios L.P. First Trust Advisors L.P., an affiliate of First Trust Portfolios L.P., acts as portfolio supervisor of the unit investment trusts sponsored by First Trust Portfolios L.P., certain of which hold common units. None of First Trust Portfolios L.P., First Trust Advisors L.P. or The Charger Corporation has the power to vote the common units held by such unit investment trusts sponsored by First Trust Portfolios L.P. Such common units are voted by the trustee of such unit investment trusts so as to insure that the common units are voted as closely as possible in the same manner and in the same general proportion as are the common units held by owners other than such unit investment trusts. First Trust Advisors L.P., First Trust Portfolios L.P. and The Charger Corporation have shared voting power over 3,813,429 common units and shared dispositive power over 3,816,144 common units. The address of each of The Charger Corporation, First Trust Portfolios L.P. and First Trust Advisors L.P. is 120 East Liberty Drive, Suite 400, Wheaton, IL 60187.
|
|
|
(f)
|
Subject to certain limitations, the preferred units are convertible into common units by the holders of such units at any time after June 20, 2019, or under certain circumstances, at NEP’s option, after November 15, 2018. The preferred units vote on an as-converted basis with the common units and have certain class voting rights with respect to amendments that adversely affect their distribution, liquidation or conversion rights, their ranking or certain other protections under NEP's partnership agreement.
|
|
|
(g)
|
BlackRock, Inc., through its subsidiaries Nasa A HoldCo LLC, Nasa B HoldCo LLC and Nasa Co-Invest Holdings, L.P., has sole voting power and dispositive power with respect to 8,922,811 preferred units. The address of BlackRock, Inc. is 55 East 52
nd
Street, New York, NY 10055. In addition, the following information [with respect to the common units] has been derived from a statement on Schedule 13G/A of BlackRock, Inc., filed with the SEC on January 9, 2018, and is as of December 31, 2017. The subsidiaries of BlackRock, Inc. that acquired the common units on behalf of BlackRock, Inc. are: BlackRock Advisors, LLC, BlackRock Investment Management (UK) Ltd., BlackRock (Luxembourg) S.A., BlackRock Investment Management (Australia) Limited, BlackRock (Netherlands) B.V., BlackRock Fund Advisors, BlackRock Asset Management Ireland Limited, BlackRock Institutional Trust Company, National Association, BlackRock Asset Management Schweiz AG, and BlackRock Investment Management, LLC. BlackRock, Inc. and its subsidiaries have sole voting power with respect to 2,679,531 common units and sole dispositive power with respect to 2,686,584 common units representing 4.95% of the outstanding common units as of February 19, 2018.
|
|
|
(h)
|
KKR Flatirons Aggregator L.P., an affiliate of Kohlberg Kravis Roberts & Co. L.P., has sole voting power and sole dispositive power with respect to 5,098,750 preferred units. The address of KKR Flatirons Aggregator L.P. is c/o Kohlberg Kravis Roberts & Co. L.P., 9 West 57
th
Street, Suite 4200, New York, NY 10019.
|
Name of Beneficial Owner
|
|
Common Units Owned
|
|
Common Units that May Be Acquired within 60 days
|
|
Percent
of Class
|
||
James L. Robo
|
|
143,576
|
|
|
—
|
|
|
*
|
Susan D. Austin
|
|
9,970
|
|
|
—
|
|
|
*
|
Mark E. Hickson
|
|
4,780
|
|
|
—
|
|
|
*
|
John W. Ketchum
|
|
3,310
|
|
|
—
|
|
|
*
|
Peter H. Kind
|
|
13,900
|
|
|
—
|
|
|
*
|
Armando Pimentel, Jr.
|
|
20,000
|
|
|
—
|
|
|
*
|
James N. Suciu
|
|
3,290
|
|
|
—
|
|
|
*
|
Charles E. Sieving
|
|
23,358
|
|
|
—
|
|
|
*
|
Terrell Kirk Crews II
|
|
—
|
|
|
—
|
|
|
*
|
Paul I. Cutler
|
|
36,525
|
|
|
—
|
|
|
*
|
All directors and executive officers as a group (10 persons)
|
|
258,709
|
|
|
—
|
|
|
*
|
Plan Category
|
|
Number of securities
to be issued upon
exercise of outstanding
options, warrants and
rights
|
|
Weighted-average exercise
price of outstanding
options, warrants and
rights
|
|
Number of securities
remaining available for
future issuance under
equity compensation
plans (excluding
securities reflected in
the first column)
|
||||
Equity compensation plans approved by security holders
|
|
—
|
|
|
|
N/A
|
|
1,277,940
|
|
|
Equity compensation plans not approved by security holders
|
|
—
|
|
|
|
N/A
|
|
—
|
|
|
Total
|
|
—
|
|
|
|
N/A
|
|
1,277,940
|
|
|
•
|
NEE Management provides or arranges for the provision of management, operations and administrative services to NEP and its subsidiaries under the direction of the board, including managing their day-to-day affairs and providing individuals to act as executive officers and directors, to the extent such services are not otherwise provided under operations and maintenance services agreements and ASAs between affiliates of NEE and NEP’s subsidiaries;
|
•
|
NEP OpCo pays on NEP’s behalf all operations and maintenance services or other expenses NEP or NEP’s subsidiaries incur; and
|
•
|
NEP OpCo makes certain payments to NEE Management based on the achievement by NEP OpCo of certain target quarterly distribution levels to its common unitholders.
|
•
|
establishing and approving NEP’s annual operating budget;
|
•
|
evaluating and approving capital decisions;
|
•
|
evaluating and approving debt and equity financing decisions;
|
•
|
assessing and approving quarterly cash distributions to unitholders; and
|
•
|
analyzing and approving related party transactions among NEE Management, its subsidiaries and any other entity or individual that NEE Management has arranged to provide services.
|
Party
|
|
Date
|
FPL Energy Vansycle L.L.C. (Stateline)
|
|
December 19, 2003, as amended and restated July 29, 2015
|
Northern Colorado Wind Energy, LLC
|
|
April 10, 2009
|
Elk City Wind, LLC
|
|
May 21, 2009
|
Baldwin Wind, LLC
|
|
July 6, 2010
|
Ashtabula Wind III, LLC
|
|
December 22, 2010, as amended and restated July 29, 2015
|
Perrin Ranch Wind, LLC
|
|
August 23, 2012 (with an effective date of June 29, 2012)
|
Tuscola Bay Wind, LLC
|
|
August 23, 2012
|
Mammoth Plains Wind Project, LLC
|
|
October 27, 2014, as amended and restated December 18, 2014
|
Seiling Wind, LLC
|
|
October 28, 2014
|
Seiling Wind II, LLC
|
|
October 28, 2014
|
Palo Duro Wind Energy, LLC
|
|
December 18, 2014
|
Golden Hills Wind, LLC
|
|
September 23, 2015
|
Cedar Bluff Wind, LLC
|
|
September 23, 2015
|
Golden West Power Partners, LLC
|
|
September 25, 2015
|
Javelina Wind Energy, LLC
|
|
December 30, 2015
|
Brady Wind, LLC
|
|
September 1, 2016
|
Brady Wind II, LLC
|
|
September 1, 2016
|
Brady Wind Interconnection, LLC
|
|
September 1, 2016
|
Party
|
|
Date
|
Genesis Solar, LLC
|
|
August 22, 2011
|
McCoy Solar, LLC
|
|
December 19, 2014
|
Shafter Solar, LLC
|
|
April 7, 2015, as amended May 29, 2015
|
Adelanto Solar, LLC
|
|
April 7, 2015
|
Adelanto Solar II, LLC
|
|
April 7, 2015
|
Party
|
|
Date
|
Sombra Project Entity
|
|
April 27, 2012
|
Moore Project Entity
|
|
April 27, 2012
|
Conestogo Project Entity
|
|
November 16, 2012
|
Summerhaven Project Entity
|
|
August 2, 2013
|
Bluewater Project Entity
|
|
June 10, 2014
|
Jericho Wind, LP
|
|
February 27, 2015, as amended April 2, 2015
|
Party
|
|
Date of Agreement
|
|
Annual Fee
|
||
FPL Energy Vansycle L.L.C. (Stateline)
|
|
December 19, 2003, as amended and restated July 24, 2015
|
|
$
|
206,000
|
|
Northern Colorado Wind Energy, LLC
|
|
April 10, 2009, as amended and restated June 12, 2009
|
|
$
|
120,000
|
|
Elk City Wind, LLC
|
|
May 21, 2009, as amended as of February 22, 2010
|
|
$
|
122,000
|
|
Mountain Prairie Wind
|
|
February 22, 2010
|
|
$
|
125,000
|
|
Baldwin Wind, LLC
|
|
July 6, 2010
|
|
$
|
125,000
|
|
Ashtabula Wind III, LLC
|
|
December 22, 2010, as amended and restated July 29, 2015
|
|
$
|
125,000
|
|
Genesis Solar, LLC
|
|
August 22, 2011
|
|
$
|
125,000
|
|
Perrin Ranch Wind, LLC
|
|
August 23, 2012, with an effective date of June 29, 2012
|
|
$
|
128,000
|
|
Tuscola Bay Wind, LLC
|
|
August 23, 2012
|
|
$
|
128,000
|
|
Canyon Wind
|
|
August 23, 2012
|
|
$
|
128,000
|
|
Genesis Solar Funding, LLC
|
|
June 13, 2014
|
|
$
|
1
|
|
Mammoth Plains Wind Project, LLC
|
|
October 27, 2014, as amended and restated December 18, 2014
|
|
$
|
125,000
|
|
Seiling Wind, LLC
|
|
October 28, 2014
|
|
$
|
125,000
|
|
Seiling Wind II, LLC
|
|
October 28, 2014
|
|
$
|
125,000
|
|
Seiling Wind Portfolio, LLC
|
|
October 28, 2014
|
|
$
|
1
|
|
Seiling Wind Interconnection, LLC
|
|
October 28, 2014
|
|
$
|
1
|
|
Palo Duro Wind Energy, LLC
|
|
December 18, 2014
|
|
$
|
125,000
|
|
Palo Duro Interconnection Services, LLC
|
|
December 18, 2014
|
|
$
|
125,000
|
|
McCoy Solar, LLC
|
|
December 19, 2014
|
|
$
|
250,000
|
|
McCoy Solar Funding, LLC
|
|
December 19, 2014
|
|
$
|
50,000
|
|
Shafter Solar, LLC
|
|
April 7, 2015
|
|
$
|
125,000
|
|
Adelanto Solar, LLC
|
|
April 7, 2015
|
|
$
|
125,000
|
|
Adelanto Solar II, LLC
|
|
April 7, 2015
|
|
$
|
125,000
|
|
Adelanto Solar Holdings, LLC
|
|
April 7, 2015
|
|
$
|
125,000
|
|
Meadowlark Wind, LLC
|
|
July 24, 2015
|
|
$
|
1
|
|
Golden Hills Wind, LLC
|
|
September 23, 2015
|
|
$
|
125,000
|
|
Cedar Bluff Wind, LLC
|
|
September 23, 2015
|
|
$
|
125,000
|
|
Golden West Power Partners, LLC
|
|
September 23, 2015
|
|
$
|
125,000
|
|
Golden Hills Interconnection, LLC
|
|
December 14, 2015
|
|
$
|
1
|
|
Javelina Wind Energy Holdings, LLC
|
|
December 30, 2015
|
|
$
|
62,500
|
|
Javelina Interconnection, LLC
|
|
December 30, 2015
|
|
$
|
1
|
|
Javelina Wind Energy, LLC
|
|
December 30, 2015
|
|
$
|
62,500
|
|
NET Holdings Management, LLC
|
|
December 31, 2015
|
|
$
|
2,250,000
|
|
Nokota Wind, LLC
|
|
September 1, 2016
|
|
$
|
1
|
|
Brady Wind, LLC
|
|
September 1, 2016
|
|
$
|
125,000
|
|
Brady Wind II, LLC
|
|
September 1, 2016
|
|
$
|
125,000
|
|
Brady Interconnection, LLC
|
|
September 1, 2016
|
|
$
|
1
|
|
Party
|
|
Date of Agreement
|
|
Annual Fee
|
Moore Project Entity
|
|
April 27, 2012
|
|
CAD $125,000
|
Sombra Project Entity
|
|
April 27, 2012
|
|
CAD $125,000
|
St. Clair entities
|
|
April 27, 2012 (St. Clair LP was added as a party on June 13, 2014)
|
|
CAD $125,000
|
Summerhaven Project Entity
|
|
September 13, 2013
|
|
CAD $150,000
|
Conestogo Project Entity
|
|
September 13, 2013
|
|
CAD $150,000
|
Trillium
|
|
December 12, 2013
|
|
CAD $150,000
|
Bluewater Project Entity
|
|
June 10, 2014
|
|
CAD $125,000
|
Jericho Wind, LP
|
|
February 27, 2015
|
|
CAD $150,000
|
NEP Subsidiary Party
|
|
Agreement
|
|
Related Parties
(1)
|
|
Purpose
|
|
Payments/Share of Costs
(2)
|
Ashtabula Wind III, LLC
|
|
Shared Facilities Agreement, dated November 30, 2010
|
|
Ashtabula Wind, LLC
|
|
Ashtabula Wind III, LLC granted right to access and use shared facilities.
|
|
$0
(3)(4)(5)
|
Northern Colorado Wind Energy, LLC
|
|
Amended and Restated Shared Facilities Agreement, dated March 11, 2010
|
|
PLI, Logan Wind and
Peetz Table |
|
Northern Colorado Wind Energy, LLC granted right to access and use shared transmission facilities.
|
|
$42,000
(6)(7)
|
Palo Duro Wind Energy, LLC
|
|
Amended and Restated Shared Facilities Agreement, dated October 21, 2014
|
|
Palo Duro Wind Interconnection Services, LLC and Palo Duro Wind Energy II, LLC
|
|
Palo Duro Wind Energy, LLC granted right to access and use shared transmission facilities.
|
|
$0
(4)(5)(8)
|
Bluewater Project Entity
|
|
Shared Facilities Agreement, dated June 10, 2014
|
|
Goshen Wind, LP
|
|
Goshen Wind, LP granted right to access and use an O&M building, a warehouse, and certain equipment held by Bluewater Project Entity.
|
|
$621,000
(7)(9)
|
Jericho Wind, LP
|
|
Common Facilities Agreement, effective November 6, 2014
|
|
Kerwood Wind, LP (Adelaide Wind) and Bornish Wind, LP (Bornish Wind)
|
|
Each party is granted the right to access and use of certain shared facilities, which include an O&M building and warehouse owned by Bornish Wind and certain equipment.
|
|
$143,000
(10)
|
Baldwin Wind, LLC
|
|
Common Facilities Services Agreement, dated October 29, 2010 (amended as of May 12, 2015)
|
|
FPL Energy Burleigh County Wind, LLC and Wilton Wind II, LLC
|
|
Addresses rights and responsibilities related to O&M and use of common facilities.
|
|
$429,000
(11)(12)
|
FPL Energy Vansycle L.L.C. (the Stateline Project Entity)
|
|
Common Facilities Services Agreement, dated December 18, 2003
|
|
FPL Energy Stateline II, Inc.
|
|
Addresses rights and responsibilities related to O&M and use of common facilities.
|
|
$107,000
(11)(13)
|
Jericho Wind, LP
|
|
Shared Transmission Facilities Co-Owners Agreement, dated August 15, 2014
|
|
Adelaide Wind, LP and Bornish Wind, LP
|
|
Provides for the mutual understanding of the parties thereto as tenants in common with respect to the ownership, operation, development, financing and holding of their shared transmission facilities
|
|
$185,000
(10)(11)
|
NEP Subsidiary Party
|
|
Agreement
|
|
Related Parties
(1)
|
|
Purpose
|
|
Payments/Share of Costs
(2)
|
Jericho Wind, LP
|
|
Billing and Metering Agreement, dated August 15, 2014
|
|
Bornish Wind, LP and Kerwood Wind, LP
|
|
Establishes and imposes limitations, restrictions, covenants and conditions to provide for the proper and orderly metering, billing and reconciliation of, and allocation of losses to and curtailment for each party's project.
|
|
$0
(11)
|
Stateline Project Entity
|
|
Two Transmission Line Easement Agreements, each dated December 18, 2003
|
|
FPL Energy Stateline II, Inc.
|
|
Stateline Project Entity granted a non-exclusive easement to FPL Energy Stateline II, Inc. over certain real property owned by Stateline Project Entity relating to energy transmission by Vansycle II.
|
|
$0
(11)(14)
|
Stateline Project Entity
|
|
Cotenancy Agreement, dated December 18, 2003
|
|
FPL Energy Stateline II, Inc.
|
|
Governs rights and obligations as tenants in common with respect to common facilities.
|
|
$0
(11)(15)
|
Golden Hills Wind, LLC
|
|
Shared Facilities Agreement, dated December 7, 2015
|
|
Golden Hills North Wind, LLC
|
|
Golden Hills Wind, LLC granted right to access and use shared transmission facilities.
|
|
$0
(4)(5)(16)
|
Golden Hills Wind, LLC
|
|
Common Facilities Agreement, dated December 7, 2016
|
|
Golden Hills North Wind, LLC, Diablo Winds, LLC, Vasco Winds, LLC
|
|
Addresses rights and responsibilities related to O&M and use of common facilities.
|
|
$0
(5)(17)
|
Javelina Wind Energy, LLC
|
|
Common Facilities Agreement, dated December 8, 2015
|
|
Javelina Wind Energy II, LLC
|
|
Addresses rights and responsibilities related to O&M and use of common facilities.
|
|
$0
(5)(18)
|
Javelina Wind Energy, LLC
|
|
Shared Facilities Agreement, dated December 30, 2015
|
|
Javelina Wind Energy II, LLC
|
|
Javelina Wind Energy, LLC granted right to access and use shared transmission facilities.
|
|
$0
(4)(5)(19)
|
Genesis Solar, LLC
|
|
Joint Use Pole Agreement, dated October 20, 2010, and Memorandum of Joint Use Pole Agreement, Partial Assignment of Easements and Consent to Entry, dated November 15, 2010
|
|
Blythe Energy, LLC
|
|
Genesis is granted right to use certain pole structure of the transmission line owned and operated by Blythe Energy, LLC, and Blythe Energy, LLC provides easements in furtherance thereof.
|
|
$0
(20)
|
McCoy Solar, LLC
|
|
Joint Use Pole Agreement, dated October 20, 2010, and Memorandum of Joint Use Pole Agreement, Partial Assignment of Easements and Consent to Entry, dated November 21, 2014
|
|
Blythe Energy, LLC
|
|
McCoy is granted right to use certain pole structure of the transmission line owned and operated by Blythe Energy, LLC, and Blythe Energy, LLC provides easements in furtherance thereof.
|
|
$0
(20)
|
(1)
|
Each of the related parties is an indirect subsidiary of NEE.
|
(2)
|
Reflects amount paid by NEP subsidiary in 2017.
|
(3)
|
O&M costs and expenses for shared facilities are allocated 100% to Ashtabula Wind, LLC.
|
(4)
|
NEP subsidiary’s right of access and use may be restricted or suspended if a force majeure event occurs that prevents a party from fulfilling its obligations (other than payment obligations) under the agreement or a material breach occurs that is not cured within 30 days after the breaching party receives notice. If a change in law necessitates an amendment of the agreement, the parties are required to negotiate a mutually agreeable amendment.
|
(5)
|
The agreement continues until terminated by mutual agreement or on the date that all parties or their successors permanently cease operation of the applicable projects.
|
(6)
|
O&M costs and expenses incurred for shared facilities are shared equally among the four parties. Northern Colorado Wind Energy, LLC’s right of access and use may be restricted or suspended if a force majeure event occurs that prevents a party from fulfilling its obligations (other than payment obligations) under the agreement or a material breach occurs that is not cured within 30 days after the breaching party receives notice.
|
(7)
|
In the event of a change of control of the parties or a change in law or applicable regulations, the parties are required to negotiate and implement a mutually acceptable ownership structure for the shared facilities. The agreement continues until terminated by mutual agreement.
|
(8)
|
Palo Duro Wind Energy, LLC and Palo Duro Wind Energy II, LLC own 88% and 12%, respectively, of the membership interest in Palo Duro Wind Interconnection Services, LLC. The O&M costs and expenses of the shared facilities are allocated 100% to Palo Duro Wind Energy, LLC until such time as the project owned by Palo Duro Wind Energy II, LLC is energized, and on an 88%/12% basis with Palo Duro Wind Energy II, LLC thereafter.
|
(9)
|
Forty percent of the O&M costs for shared facilities are allocated to the Bluewater Project Entity and 60% of such costs are allocated to Goshen Wind, LP. Goshen Wind, LP’s right of access to and use of such building and equipment is granted to the extent that it does not, in any material respect, (i) limit Bluewater Project Entity’s ability to perform its obligations under any agreement it has entered into or (ii) adversely affect the operations or profitability of Bluewater Project Entity.
|
(10)
|
Each party is responsible for its pro rata share of all expenses attributable to the shared facilities (Jericho Wind, LP has an approximately 53% interest, Bornish Wind has a 26% interest and Adelaide Wind has a 21% interest in the shared facilities). The agreement terminates upon the earliest to occur of the written agreement of all the parties or one party becoming the sole owner of the shared facilities.
|
(11)
|
The agreement may be terminated upon the occurrence of certain customary events or by mutual agreement.
|
(12)
|
Baldwin Wind, LLC pays NEOS its pro rata share (based on the parties’ respective percentage ownership interests of the common facilities at the time such costs are incurred) of the O&M costs for the common facilities. At December 31, 2016, Baldwin Wind, LLC’s ownership interest was 50%. NEOS is designated as operator under the agreement. The agreement continues until December 31, 2041.
|
(13)
|
The Stateline Project Entity and FPL Energy Stateline II, Inc. each pay NEOS its pro rata share (based on the parties’ respective percentage ownership interests of the common facilities at the time such costs are incurred) of the O&M costs for the common facilities. NEOS is designated as operator under the agreement. The agreement continues until December 31, 2035.
|
(14)
|
Each easement agreement continues until December 31, 2035.
|
(15)
|
The agreement continues until December 31, 2035. Each party is responsible for paying all costs, expenses and charges that directly relate to its projects use of or activities with respect to the common facilities and which are assessed under the Common Facilities Services Agreement.
|
(16)
|
Golden Hills Wind, LLC and Golden Hills North Wind, LLC own 67.6% and 32.4%, respectively, of the membership interest in Golden Hills Interconnection, LLC. The O&M costs and expenses of the shared facilities are allocated 100% to Golden Hills Wind, LLC until such time as the project owned by Golden Hills North Wind, LLC is energized, and on a 67.6%/32.4% basis with Golden Hills North Wind, LLC thereafter.
|
(17)
|
Each party is responsible for its pro rata share of all expenses attributable to the shared facilities based upon relative MW percentage of each project to the total MWs of the projects combined.
|
(18)
|
Javelina Wind Energy, LLC and Albercas Wind Energy II, LLC own 55% and 45%, respectively, of the membership interest in Javelina Interconnection, LLC. The O&M costs and expenses of the common facilities are allocated 100% to Javelina Wind Energy, LLC until such time as the project owned by Albercas Wind Energy II, LLC is energized, and on a 55%/45% basis with Albercas Wind Energy II, LLC thereafter. NEOS is designated as operator under the agreement.
|
(19)
|
Javelina Wind Energy, LLC and Albercas Wind Energy II, LLC own 55% and 45%, respectively, of the membership interest in Javelina Interconnection, LLC. The O&M costs and expenses of the shared facilities are allocated 100% to Javelina Wind Energy, LLC until such time as the project owned by Albercas Wind Energy II, LLC is energized, and on a 55%/45% basis with Albercas Wind Energy II, LLC thereafter.
|
(20)
|
Each party is required to pay the other party for any costs and/or lost revenues borne by the other party resulting from the need to deenergize the other party's line for purposes of performing maintenance on its own transmission line. Upon the abandonment of the use of any joint use pole by either party, the agreement will terminate with respect to the specific joint use poles affected by the abandonment.
|
|
|
Transportation Rates and
Reimbursements
|
||||||||||
Pipeline Entity
|
|
2017
|
|
2016
|
|
2015
|
||||||
Monument Pipeline LP
|
|
$
|
4,659,000
|
|
|
$
|
8,505,000
|
|
|
$
|
1,340,000
|
|
South Shore Pipeline, L.P.
|
|
$
|
1,653,000
|
|
|
$
|
649,000
|
|
|
$
|
—
|
|
Mission Valley Pipeline Company, LP
|
|
$
|
111,000
|
|
|
$
|
87,000
|
|
|
$
|
44,000
|
|
Mission Natural Gas Company, LP
|
|
$
|
62,000
|
|
|
$
|
62,000
|
|
|
$
|
16,000
|
|
LaSalle Pipeline, LP
|
|
$
|
212,000
|
|
|
$
|
180,000
|
|
|
$
|
43,000
|
|
NET Mexico Pipeline Partners, LLC
|
|
$
|
4,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Party
|
|
Date
|
Palo Duro Wind Energy, LLC
|
|
December 18, 2014
|
Mammoth Plains Wind Project, LLC
|
|
December 22, 2014
|
Seiling Wind, LLC and Seiling Wind II, LLC
|
|
December 23, 2014
|
Golden West Power Partners, LLC
|
|
December 1, 2015
|
Golden Hills Wind, LLC and Cedar Bluff Wind, LLC
|
|
December 30, 2015
|
Brady Wind, LLC
|
|
December 9, 2016
|
NextEra Energy Partners Acquisitions, LLC
|
|
May 1, 2017
|
NextEra Energy Partners Acquisitions, LLC
|
|
November 20, 2017
|
•
|
NEER provides certain existing limited credit support on behalf of NEP’s subsidiaries for the projects and, upon NEP OpCo’s request and at NEER’s option, may agree to provide credit support on behalf of any projects NEP may acquire in the future on similar terms, and NEP OpCo will reimburse NEER to the extent NEER or its affiliates are required to make payments under such credit support or to post cash collateral, subject to certain exceptions; and
|
•
|
when the projects in NEP’s portfolio receive revenues or when NEP OpCo receives distributions from NEP’s subsidiaries, NEER or one of its affiliates borrow excess funds from NEP’s subsidiaries, including NEP OpCo, and hold them in an account of NEER or one of its affiliates for the benefit of NEER and its affiliates until such funds are required to fund distributions or pay NEP’s subsidiaries’ expenses or NEP OpCo otherwise demands the returns of such funds.
|
|
|
2017
|
|
2016
|
||||
Audit Fees
(a)
|
|
$
|
2,088,000
|
|
|
$
|
2,124,000
|
|
Audit-Related Fees
(b)
|
|
2,067,000
|
|
|
1,984,000
|
|
||
Tax Fees
(c)
|
|
—
|
|
|
25,000
|
|
||
All Other Fees
|
|
—
|
|
|
—
|
|
||
Total Fees
|
|
$
|
4,155,000
|
|
|
$
|
4,133,000
|
|
(a)
|
Audit fees consist of fees billed for professional services rendered for the audit of NEP's annual consolidated financial statements for the fiscal year and the reviews of the financial statements included in Quarterly Reports on Form 10-Q during the fiscal year and the audit of the effectiveness of internal control over financial reporting, comfort letters, consents, and other services related to SEC matters.
|
(b)
|
Audit-related fees consist of fees billed for assurance and related services that are reasonably related to the performance of the audit or review of NEP's consolidated financial statements and are not reported under audit fees. These fees primarily related to audits of subsidiary (non-SEC registrant) financial statements.
|
(c)
|
Tax fees consist of fees billed for professional services rendered for tax advice and tax planning.
|
|
|
|
Page(s)
|
(a)
|
1.
|
Financial Statements
|
|
|
|
Management's Report on Internal Control over Financial Reporting
|
|
|
|
Attestation Report of Independent Registered Public Accounting Firm
|
|
|
|
Report of Independent Registered Public Accounting Firm
|
|
|
|
Consolidated Statements of Income
|
|
|
|
Consolidated Statements of Comprehensive Income
|
|
|
|
Consolidated Balance Sheets
|
|
|
|
Consolidated Statements of Cash Flows
|
|
|
|
Consolidated Statements of Changes in Equity
|
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
|
|
|
2.
|
Financial Statement Schedules - Schedules are omitted as not applicable or not required.
|
|
|
|
|
|
|
3.
|
Exhibits (including those incorporated by reference)
|
|
Exhibit
Number
|
|
Description
|
2.1*
|
|
|
2.2*
|
|
|
2.3*
|
|
|
3.1*
|
|
|
3.2*
|
|
|
3.3*
|
|
|
3.4*
|
|
|
4.1*
|
|
|
4.2*
|
|
|
4.3*
|
|
|
4.4*
|
|
|
4.5*
|
|
|
10.1*
|
|
|
10.2*
|
|
|
10.3*
|
|
Exhibit
Number
|
|
Description
|
10.4*
|
|
|
10.4(a)*
|
|
|
10.5*
|
|
|
10.6*
|
|
|
10.7*
|
|
|
10.8*
|
|
|
10.9*
|
|
|
10.10*
|
|
|
10.11*
|
|
|
10.12*
|
|
|
10.12(a)*
|
|
|
10.13*
|
|
|
10.14*
|
|
|
10.15*
|
|
|
10.16
|
|
|
10.17
|
|
|
12
|
|
|
21
|
|
|
23
|
|
|
31(a)
|
|
|
31(b)
|
|
|
32
|
|
|
101.INS
|
|
XBRL Instance Document
|
101.SCH
|
|
XBRL Schema Document
|
101.PRE
|
|
XBRL Presentation Linkbase Document
|
101.CAL
|
|
XBRL Calculation Linkbase Document
|
101.LAB
|
|
XBRL Label Linkbase Document
|
101.DEF
|
|
XBRL Definition Linkbase Document
|
*
|
Incorporated herein by reference.
|
NEXTERA ENERGY PARTNERS, LP
|
|
(Registrant)
|
|
|
|
|
|
|
|
|
|
JAMES L. ROBO
|
|
James L. Robo
Chairman of the Board, Chief Executive Officer
and Director
(Principal Executive Officer)
|
JOHN W. KETCHUM
|
|
TERRELL KIRK CREWS, II
|
John W. Ketchum
Chief Financial Officer and Director
(Principal Financial Officer)
|
|
Terrell Kirk Crews, II
Controller and Chief Accounting Officer
(Principal Accounting Officer)
|
SUSAN DAVENPORT AUSTIN
|
|
ARMANDO PIMENTEL, JR.
|
Susan Davenport Austin
Director
|
|
Armando Pimentel, Jr.
Director
|
MARK E. HICKSON
|
|
JAMES N. SUCIU
|
Mark E. Hickson
Director
|
|
James N. Suciu
Director
|
|
|
|
PETER H. KIND
|
|
|
Peter H. Kind
Director
|
|
|
Annual Retainer
(payable quarterly)
|
$65,000
|
|
|
Committee Chair retainer (annual)
(payable quarterly)
|
$15,000
|
|
|
Annual grant of restricted common units
(under 2014 Long-Term Incentive Plan)
|
That number of common units determined by dividing $115,000 by closing price of NextEra Energy Partners, LP common units on effective date of grant (rounded up to the nearest 10 common units)
|
Miscellaneous
|
Travel and Accident Insurance (including spouse coverage)
|
–
|
{{AMTVESTINGYR1}} units
on the later to occur of (i)
{{VESTDATE1}}
, or (ii) the date on which the Committee makes the certification described in section 2(b)(i) hereof (the “First Vest”);
|
–
|
{{AMTVESTINGYR2}} units
on the later to occur of (i)
{{VESTDATE2}}
, or (ii) the date on which the Committee makes the certification described in section 2(b)(ii) hereof (the “Second Vest”); and
|
–
|
{{AMTVESTINGYR3}} units
on the later to occur of (i)
{{VESTDATE3}}
, or (ii) the date on which the Committee makes the certification described in section 2(b)(iii) hereof (the “Final Vest”).
|
(a)
|
The Grantee shall not be entitled to delivery of unrestricted units until vesting.
|
(b)
|
The Grantee may not sell, transfer, assign, pledge or otherwise encumber or dispose of the Awarded Units prior to vesting.
|
(c)
|
In addition to the provisions set forth in section 4 hereof, a breach by the Grantee of the terms and conditions set forth in this Agreement shall result in the immediate forfeiture of all then unvested Awarded Units.
|
(d)
|
Notwithstanding anything herein to the contrary, if all or a portion of the Awarded Units do not vest, whether upon the termination of the Grantee’s Service (including without limitation Service to any successors to the Company or an Affiliate), or otherwise (including without limitation if the Company fails to meet one or more Performance Targets established as described in section 2(b) hereof or if the Grantee breaches any provision hereof, including without limitation the provisions of section 9 hereof), all distributions paid to the Grantee on Awarded Units which have not vested (and which shall not thereafter vest in accordance with section 4 hereof) shall be forfeited, and shall be repaid to the Company within thirty (30) days after the date on which the Grantee’s obligation to repay such distributions accrues. For purposes hereof, such obligation to repay such distributions shall accrue (1) on such date as the Committee establishes that a Performance Target has not been met, as to all distributions paid on Awarded Units which are forfeited due to failure to meet such Performance Target; (2) on the date of termination of Service, as to all distributions paid on Awarded Units which are forfeited upon such termination of Service; and (3) upon forfeiture of unvested Awarded Units upon a breach by the Grantee of the terms and conditions set forth in this Agreement (including without limitation any such forfeiture occurring after termination of Service).
|
(a)
|
If the Grantee’s termination of Service is due to resignation, discharge, or retirement prior to age 55 and does not meet the condition set forth in section 4(d) hereof, all rights to Awarded Units not theretofore vested (including without limitation rights to distributions not theretofore paid and rights to retain distributions on Awarded Units which have not theretofore vested, as more fully set forth in section 3(d) hereof) under this Agreement shall be immediately forfeited. Forfeited distributions shall be repaid to the Company within thirty (30) days after the Grantee’s termination of Service.
|
(b)
|
If the Grantee’s termination of Service is due to Disability or death, or if the Grantee converts to inactive employee status on account of a determination of such Grantee’s total and permanent Disability under any long-term disability plan of the Company or an Affiliate (a “Disability Plan”), the then-unvested portion of the Awarded Units shall vest (1) in the case of the Grantee’s Disability, on the vesting schedule and otherwise in accordance with the terms and conditions (including without limitation satisfaction of the applicable Performance Targets) set forth in section 2 hereof, notwithstanding that the Grantee’s Service shall have previously terminated or the Grantee has converted to inactive employee status on account of Disability under any Disability Plan, and (2) in the case of the Grantee’s death, upon such termination of Service (treating the applicable Performance Targets in section 2 hereof as having been achieved).
|
(c)
|
If the Grantee’s termination of Service is due to retirement on or after age 55 after completing at least ten years of continuous Service with the Company and does not meet the condition set forth in section 4(d) hereof, a pro rata unit of the then-unvested portion of the Awarded Units (determined as follows: (A) with respect to any unvested Awarded Units included in the First Vest, the product of (x) the quotient (which shall not exceed 1.0) of (I) the total number of full days of the Grantee’s Service completed during the Restricted Period divided by (II) 365, multiplied by (y) such unvested portion of the Awarded Units, and rounded to the nearest common unit; (B) with respect to any unvested Awarded Units included in the Second Vest, the product of (x) the quotient (which shall not exceed 1.0) of (I) the total number of full days of the Grantee’s Service completed during the Restricted Period divided by (II) 730, multiplied by (y) such unvested portion of the Awarded Units, and rounded to the nearest common unit; and (C) with respect to any unvested Awarded Units included in the Final Vest, the product of (x) the quotient (which shall not exceed 1.0) of (I) the total number of full days of the Grantee’s Service completed during the Restricted Period divided by (II) 1,095, multiplied by (y) such unvested portion of the Awarded Units, and rounded to the nearest common unit) shall vest on the vesting schedule and otherwise in accordance with the terms and conditions (including without limitation satisfaction of the applicable Performance Targets) set forth in section 2 hereof, notwithstanding that the Grantee’s Service shall have previously terminated. For
|
(d)
|
If the Grantee’s termination of Service is due to retirement on or after age 50, and if, but only if, such retirement is evidenced by a writing which specifically acknowledges that this provision shall apply to such retirement and is executed by the Company’s chief executive officer (or, if the Grantee is an executive officer, by a member of the Committee or the chief executive officer at the direction of the Committee, other than with respect to himself), the then-unvested portion of the Awarded Units shall vest on the vesting schedule and otherwise in accordance with the terms and conditions (including without limitation satisfaction of the applicable Performance Targets) set forth in section 2 hereof, notwithstanding that the Grantee’s Service shall have previously terminated. Notwithstanding the foregoing, if, after termination of Service but prior to vesting of all or a portion of the Awarded Units, the Grantee breaches any provision hereof, including without limitation the provisions of section 9 hereof, the Grantee shall immediately forfeit all rights to the then-unvested Awarded Units and any distributions theretofore paid on such then-unvested Awarded Units. Forfeited distributions shall be repaid to the Company within thirty (30) days after the date on which the Grantee’s obligation to repay such distributions accrues.
|
(e)
|
If the Grantee's Service is terminated prior to vesting of all or a portion of the Awarded Units for any reason other than as set forth in sections 4(a), (b), (c), and (d) hereof, or if an ambiguity exists as to the interpretation of those sections, the Committee shall determine whether the Grantee's then-unvested Awarded Units shall be forfeited or whether the Grantee shall be entitled to full vesting or pro rata vesting as set forth above based upon completed days of service during the Restricted Period, and any Awarded Units which may vest shall do so on the vesting schedule and otherwise in accordance with the terms and conditions (including without limitation satisfaction of the applicable Performance Targets) set forth in section 2 hereof, notwithstanding that the Grantee’s Service shall have previously terminated. Notwithstanding the foregoing, if, after termination of Service but prior to vesting of all or a portion of the Awarded Units, the Grantee breaches any provision hereof, including without limitation the provisions of section 9 hereof, the Grantee shall immediately forfeit all rights to the then-unvested Awarded Units and any distributions theretofore paid on such then-unvested Awarded Units. Forfeited distributions shall be repaid to the Company
|
(a)
|
During the Grantee's Service with the Company, and for a two-year period following the termination of the Grantee's Service with the Company, the Grantee agrees not to (i) compete or attempt to compete for, or act as a broker or otherwise participate in, any projects in which the Company has at any time done any work or undertaken any development efforts, or (ii) directly or indirectly solicit any of the Company’s customers, vendors, contractors, agents, or any other parties with which the Company has an existing or prospective business relationship, for the benefit of the Grantee or for the benefit of any third party, nor shall the Grantee accept consideration or negotiate or enter into agreements with such parties for the benefit of the Grantee or any third party.
|
(b)
|
During the Grantee's Service with the Company, and for a two-year period following the termination of the Grantee's Service with the Company, the Grantee shall not, directly or indirectly, on behalf of the Grantee or for any other business, person or entity, entice, induce or solicit or attempt to entice, induce or solicit any employee of the Company or its Subsidiaries or other Affiliates to leave the Company's employ (or the employ of such Subsidiary or other Affiliate) or to hire or to cause any employee of the Company to become employed for any reason whatsoever.
|
(c)
|
The Grantee shall not, at any time or in any way, disparage the Company or its current or former officers, directors, and employees, orally or in writing, or make any statements that may be derogatory or detrimental to the Company’s good name or business reputation.
|
(d)
|
The Grantee acknowledges that the Company would not have an adequate remedy at law for monetary damages if the Grantee breaches these Protective Covenants. Therefore, in addition to all remedies to which the Company may be entitled for a breach or threatened breach of these Protective Covenants, including but not limited to monetary damages, the Company shall be entitled to specific enforcement of these Protective Covenants and to injunctive or other equitable relief as a remedy for a breach or threatened breach. In addition, upon any breach of these Protective Covenants or any separate confidentiality agreement or confidentiality provision between the Company and the Grantee, all the Grantee’s rights to receive theretofore unvested Awarded Units and distributions relating thereto under this Agreement shall be forfeited.
|
(e)
|
For purposes of this section 9, the term “Company” shall include all Subsidiaries and other Affiliates of the Company (such Subsidiaries and other Affiliates being hereinafter referred to as the “NextEra Entities”). The Company and the Grantee agree that each of the NextEra Entities is an intended third-party beneficiary of this section 9, and further agree that each of the NextEra Entities is entitled to enforce the provisions of this section 9 in accordance with its terms.
|
(f)
|
Notwithstanding anything to the contrary contained in this Agreement, the terms of these Protective Covenants shall survive the termination of this Agreement and shall remain in effect.
|
|
Years Ended December 31,
|
||||||||||||||||||
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
|
(millions of dollars)
|
||||||||||||||||||
Earnings, as defined:
|
|
|
|
|
|
|
|
|
|
||||||||||
Net income
|
$
|
109
|
|
|
$
|
380
|
|
|
$
|
107
|
|
|
$
|
141
|
|
|
$
|
17
|
|
Income taxes
|
167
|
|
|
57
|
|
|
33
|
|
|
(50
|
)
|
|
26
|
|
|||||
Fixed charges included in the determination of net income, as below
|
212
|
|
|
163
|
|
|
125
|
|
|
103
|
|
|
52
|
|
|||||
Amortization of capitalized interest
|
6
|
|
|
6
|
|
|
3
|
|
|
2
|
|
|
—
|
|
|||||
Distributed income of equity method investee
|
47
|
|
|
50
|
|
|
62
|
|
|
—
|
|
|
—
|
|
|||||
Less: Equity in earnings of equity method investee and non-economic ownership interests
|
(51
|
)
|
|
(36
|
)
|
|
(34
|
)
|
|
(15
|
)
|
|
4
|
|
|||||
Total earnings, as defined
|
$
|
490
|
|
|
$
|
620
|
|
|
$
|
296
|
|
|
$
|
181
|
|
|
$
|
99
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges, as defined:
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense
|
$
|
199
|
|
|
$
|
152
|
|
|
$
|
117
|
|
|
$
|
100
|
|
|
$
|
49
|
|
Rental interest factor
|
13
|
|
|
11
|
|
|
8
|
|
|
3
|
|
|
3
|
|
|||||
Fixed charges included in the determination of net income
|
212
|
|
|
163
|
|
|
125
|
|
|
103
|
|
|
52
|
|
|||||
Capitalized interest
|
—
|
|
|
6
|
|
|
9
|
|
|
4
|
|
|
30
|
|
|||||
Total fixed charges, as defined
|
$
|
212
|
|
|
$
|
169
|
|
|
$
|
134
|
|
|
$
|
107
|
|
|
$
|
82
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Preferred unit distributions requirement
|
$
|
3
|
|
|
|
|
|
|
|
|
|
||||||||
Ratio of income before income taxes to net income
|
2.53
|
|
|
|
|
|
|
|
|
|
|||||||||
Preferred unit distributions requirement before income taxes
|
$
|
8
|
|
|
|
|
|
|
|
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Combined fixed charges and preferred unit distributions requirement
|
$
|
220
|
|
|
|
|
|
|
|
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of earnings to fixed charges
|
2.31
|
|
|
3.67
|
|
|
2.21
|
|
|
1.69
|
|
|
1.21
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of earnings to combined fixed charges and preferred unit distributions
(a)
|
2.23
|
|
|
3.67
|
|
|
2.21
|
|
|
1.69
|
|
|
1.21
|
|
(a)
|
Prior to 2017, NextEra Energy Partners, LP had no preference equity securities outstanding; therefore, the ratio of earnings to fixed charges is the same as the ratio of earnings to combined fixed charges and preferred unit distributions.
|
Subsidiary
|
|
Jurisdiction
|
NextEra Energy Operating Partners GP, LLC
|
|
Delaware
|
NextEra Energy Operating Partners, LP
(a)
|
|
Delaware
|
(a)
|
Includes 88 subsidiaries that operate in the United States and 48 subsidiaries that operate in Canada in the same line of business as NextEra Energy Operating Partners, LP.
|
1.
|
I have reviewed this Form 10-K for the annual period ended
December 31, 2017
of NextEra Energy Partners, LP (the registrant);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date:
|
February 20, 2018
|
JAMES L. ROBO
|
James L. Robo
Chairman and Chief Executive Officer
of NextEra Energy Partners, LP
|
1.
|
I have reviewed this Form 10-K for the annual period ended
December 31, 2017
of NextEra Energy Partners, LP (the registrant);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date:
|
February 20, 2018
|
JOHN W. KETCHUM
|
John W. Ketchum
Chief Financial Officer
of NextEra Energy Partners, LP
|
(1)
|
The Annual Report on Form 10-K of NextEra Energy Partners, LP (the registrant) for the annual period ended
December 31, 2017
(Report) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the registrant.
|
Dated:
|
February 20, 2018
|
|
JAMES L. ROBO
|
|
|
James L. Robo
Chairman and Chief Executive Officer
of NextEra Energy Partners, LP
|
|
|
JOHN W. KETCHUM
|
|
|
John W. Ketchum
Chief Financial Officer
of NextEra Energy Partners, LP
|
|