CLEARWAY ENERGY, INC.
10-Ks and 10-Qs
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
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x
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year ended December 31, 2013.
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition period from to .
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Commission File Number: 001-36002
NRG Yield, Inc.
(Exact name of registrant as specified in its charter)
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Delaware
(State or other jurisdiction of incorporation or organization)
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46-1777204
(I.R.S. Employer Identification No.)
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211 Carnegie Center, Princeton, New Jersey
(Address of principal executive offices)
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08540
(Zip Code)
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(609) 524-4500
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
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Title of Each Class
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Name of Exchange on Which Registered
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Common Stock, Class A, par value $0.01
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes
o
No
x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes
o
No
x
Indicate by check mark whether the registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes
x
No
o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes
x
No
o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
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Large accelerated filer
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Accelerated filer
o
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Non-accelerated filer
x
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Smaller reporting company
o
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(Do not check if a smaller reporting company)
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes
o
No
x
The registrant completed its initial public offering of its Class A common stock on July 22, 2013. The registrant was not a public company as of the last business day of its most recently completed second fiscal quarter and therefore cannot calculate the aggregate market value of its voting and non-voting common equity held by non-affiliates as of such date.
Indicate the number of shares outstanding of each of the registrant's classes of common stock as of the latest practicable date
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Class
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Outstanding at February 26, 2014
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Common Stock, Class A, par value $0.01 per share
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22,511,250
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Common Stock, Class B, par value $0.01 per share
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42,738,750
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Documents Incorporated by Reference:
Portions of the Registrant's definitive Proxy Statement relating to its 2014 Annual Meeting of Stockholders
are incorporated by reference into Part III of this Annual Report on Form 10-K
1
TABLE OF CONTENTS
Index
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GLOSSARY OF TERMS
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PART I
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Item 1 — Business
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Item 1A — Risk Factors
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Item 1B — Unresolved Staff Comments
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Item 2 — Properties
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Item 3 — Legal Proceedings
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Item 4 — Mine Safety Disclosures
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PART II
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Item 5 — Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
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Item 6 — Selected Financial Data
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Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations
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Item 7A — Quantitative and Qualitative Disclosures About Market Risk
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Item 8 — Financial Statements and Supplementary Data
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Item 9 — Changes in Disagreements With Accountants on Accounting and Financial Disclosure
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Item 9A — Controls and Procedures
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Item 9B — Other Information
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PART III
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Item 10 — Directors, Executive Officers and Corporate Governance
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Item 11 — Executive Compensation
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Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
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Item 13 — Certain Relationships and Related Transactions, and Director Independence
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Item 14 — Principal Accounting Fees and Services
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PART IV
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Item 15 — Exhibits, Financial Statement Schedules
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EXHIBIT INDEX
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2
GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
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ARRA
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American Recovery and Reinvestment Act of 2009
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ASC
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The FASB Accounting Standards Codification, which the FASB established as the source of
authoritative U.S. GAAP
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ASU
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Accounting Standards Updates – updates to the ASC
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CfD
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Contract for Differences
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COD
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Commercial operations date
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CFTC
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U.S. Commodity Future Trading Commission
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DGCL
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Delaware General Corporation Law
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Distributed Solar
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Solar power projects, typically less than 20 MW in size, that primarily sell power produced to customers for usage on site, or are interconnected to sell power into the local distribution grid
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EPC
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Engineering, Procurement and Construction
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ERCOT
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Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
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EWG
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Exempt Wholesale Generator
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Exchange Act
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The Securities Exchange Act of 1934, as amended
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FASB
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Financial Accounting Standards Board
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FCM
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Forward Capacity Market
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FERC
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Federal Energy Regulatory Commission
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FFB
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Federal Financing Bank
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FPA
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Federal Power Act
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ISO
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Independent System Operator, also referred to as Regional Transmission Organization, or RTO
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ISO-NE
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ISO New England Inc.
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ITC
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Investment Tax Credit
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JOBS Act
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Jumpstart Our Business Startups Act
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LIBOR
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London Inter-Bank Offered Rate
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Marsh Landing
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NRG Marsh Landing LLC, formerly GenOn Marsh Landing LLC
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MMBtu
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Million British Thermal Units
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MW
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Megawatt
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MWh
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Saleable megawatt hours, net of internal/parasitic load megawatt-hours
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MWt
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Megawatts Thermal Equivalent
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NEPOOL
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New England Power Pool
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NERC
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North American Electric Reliability Corporation
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Net Exposure
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Counterparty credit exposure to NRG Yield, Inc. net of collateral
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NOLs
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Net operating losses
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NPNS
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Normal Purchase Normal Sale
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NRG
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NRG Energy, Inc.
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NRG Yield
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Accounting predecessor, representing the combination of the projects that were acquired by NRG Yield LLC
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NRG Yield, Inc.
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NRG Yield, Inc., or the Company
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NRG Yield LLC
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The holding company through which the projects are owned by NRG, the holder of Class B common units, and NRG Yield, Inc., the holder of the Class A common units
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NRG Yield Operating LLC
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The holder of the project assets that belong to NRG Yield LLC
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OCI
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Other comprehensive income
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OMB
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Office of Management and Budget
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PPA
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Power Purchase Agreement
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3
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PUCT
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Public Utility Commission of Texas
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PURPA
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Public Utility Regulatory Policies Act of 1978
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QF
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Qualifying Facility under PURPA
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RPM
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Reliability Pricing Model
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RPS
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Renewable Portfolio Standard
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RTO
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Renewable Transmission Originator
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U.S.
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United States of America
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U.S. DOE
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U.S. Department of Energy
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U.S. GAAP
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Accounting principles generally accepted in the United States
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Utility Scale Solar
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Solar power projects, typically 20 MW or greater in size (on an alternating current, or AC, basis), that are interconnected into the transmission or distribution grid to sell power at a wholesale level
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VaR
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Value at Risk
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VIE
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Variable Interest Entity
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4
General
NRG Yield, Inc., or the Company, is a dividend growth-oriented company formed to serve as the primary vehicle through which NRG will own, operate and acquire contracted renewable and conventional generation and thermal infrastructure assets. The Company owns a diversified portfolio of contracted renewable and conventional generation and thermal infrastructure assets in the United States. The contracted generation portfolio includes
three
natural gas or dual-fired facilities,
eight
utility-scale solar and wind generation facilities and
two
portfolios of distributed solar facilities that collectively represent
1,324
net MW. Each of these assets sells substantially all of its output pursuant to long-term, fixed price offtake agreements to credit-worthy counterparties. The average remaining contract life, weighted by MWs, of these offtake agreements was approximately
16
years as of
December 31, 2013
. The Company also owns thermal infrastructure assets with an aggregate steam and chilled water capacity of
1,346
net MWt and electric generation capacity of
123
net MW. These thermal infrastructure assets provide steam, hot water and/or chilled water, and in some instances electricity, to commercial businesses, universities, hospitals and governmental units in
multiple
locations, principally through long-term contracts or pursuant to rates regulated by state utility commissions.
History
The Company was formed by NRG as a Delaware corporation on December 20, 2012. On July 22, 2013, the Company closed the initial public offering of
22,511,250
shares of its Class A common stock at an offering price of $22.00 per share. In connection with the offering, the Company’s shares of Class A common stock began trading on the New York Stock Exchange under the symbol “NYLD”. The proceeds to the Company from the offering, before deducting underwriting discounts, were approximately $468 million of which the Company used approximately $395 million to purchase
19,011,250
NRG Yield LLC Class A common units from NRG.
The Company is the sole managing member of NRG Yield LLC and operates and controls all of the business and affairs and consolidates the financial results of NRG Yield LLC and its subsidiaries. NRG Yield LLC is a holding company for the companies that directly and indirectly own and operate NRG Yield, Inc.'s business.
As of December 31, 2013, NRG owned
42,738,750
NRG Yield LLC Class B common units and the Company owned 22,511,250 NRG Yield LLC Class A common units, and NRG through its holdings of Class B common stock has 65.5% of the voting power in the Company, and the holders of the Company's issued and outstanding shares of Class A common stock have 34.5% of the voting power in the Company. As a result of the current ownership of the Class B common stock and the NRG Yield LLC Class A common units, NRG continues at the present time to control the Company, and the Company in turn, as the sole managing member of NRG Yield LLC, controls NRG Yield LLC and its subsidiaries.
See Item 1A -
Risk Factors
and Item 13 -
Certain Relationships and Related Transactions, and Director Independence
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5
The diagram below depicts the Company’s organizational structure as of
December 31, 2013
:
6
Operations Overview
The Company's operating assets are comprised of the following projects:
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Projects
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Percentage Ownership
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Net Capacity (MW)
(a)
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Offtake Counterparty
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Expiration
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Conventional
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GenConn Middletown
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49.95
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%
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95
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Connecticut Light & Power
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2041
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GenConn Devon
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49.95
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%
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95
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Connecticut Light & Power
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2040
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Marsh Landing
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100
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%
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720
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Pacific Gas and Electric
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2023
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910
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Utility Scale Solar
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Alpine
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100
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%
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66
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Pacific Gas and Electric
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2033
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Avenal
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49.95
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%
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23
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Pacific Gas and Electric
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2031
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Avra Valley
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100
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%
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25
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Tucson Electric Power
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2032
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Blythe
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100
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%
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21
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Southern California Edison
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2029
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Borrego
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100
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%
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26
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San Diego Gas and Electric
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2038
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Roadrunner
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100
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%
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20
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El Paso Electric
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2031
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CVSR
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48.95
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%
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122
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Pacific Gas and Electric
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2038
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303
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Distributed Solar
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AZ DG Solar Projects
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100
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%
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5
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Various
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2025 - 2033
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PFMG DG Solar Projects
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51
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%
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5
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Various
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2032
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10
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Wind
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South Trent
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100
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%
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101
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AEP Energy Partners
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2029
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Thermal
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Thermal equivalent MWt
(b)
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100
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%
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1,346
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Various
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Various
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Thermal generation
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100
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%
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123
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Various
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Various
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Total net capacity (excluding equivalent MWt)
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1,447
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(a) Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of
December 31, 2013
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(b) For thermal energy, net capacity represents MWt for steam or chilled water.
During the year ended
December 31, 2013
, the Company derived approximately
34%
of its consolidated revenue from Pacific Gas and Electric.
Business Strategy
The Company's primary business strategy is to focus on the acquisition and ownership of assets with minimal long term price or volumetric offtake risk in order that it may be able to increase the cash dividends of Class A common stock over time without compromising the ongoing stability of the business. The Company's plan for executing this strategy includes the following key components:
Focus on contracted renewable energy and conventional generation and thermal infrastructure assets.
The Company owns and operates renewable energy and natural gas-fired generation, thermal and other infrastructure assets with proven technologies, low operating risks and stable cash flows. The Company believes by focusing on this core asset class and leveraging its industry knowledge, it will maximize its strategic opportunities, be a leader in operational efficiency and maximize its overall financial performance.
7
Growing the business through acquisitions of contracted operating assets.
NRG Yield, Inc. believes that its base of operations and relationship with NRG provide a platform in the power generation and thermal sectors for strategic growth through cash accretive and tax advantaged acquisitions complementary to its existing portfolio. NRG has granted the Company a right of first offer to acquire
s
ix of its power generating assets, or the NRG ROFO Assets, if and to the extent NRG elects to sell any of these assets prior to July 2018. The table below lists the NRG ROFO Assets.
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Asset
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Fuel Type
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Net Capacity
(MW)
(1)
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COD
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Offtake
(Term/Offtaker)
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TA High Desert†
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Solar
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20
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2013
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20 year PPA/Southern California Edison
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RE Kansas South†
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Solar
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20
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2013
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20 year PPA/Pacific Gas & Electric
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El Segundo†
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Natural Gas
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550
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2013
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10 year Tolling Agreement/Southern California Edison
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CVSR†
(2)
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Solar
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128
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2013
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25 year PPA/Pacific Gas & Electric
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Ivanpah
(3)
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Solar
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193
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2013
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20-25 year PPA/Pacific Gas & Electric and Southern California Edison
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Agua Caliente
(4)
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Solar
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148
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Early 2014
(5)
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25 year PPA/Pacific Gas & Electric
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† Indicates NRG ROFO Assets the Company expects NRG to offer the opportunity to purchase during 2014. However, NRG is not obligated to sell any of the NRG ROFO Assets and, therefore, the Company has no assurances when, if ever, these assets will be offered to it or, if offered, that they will be offered on favorable terms.
(1) Represents the maximum, or rated, electricity generating capacity of the facility in MW multiplied by NRG’s percentage ownership interest in the facility as of December 31, 2013.
(2) Represents NRG’s remaining 51.05% ownership interest in CVSR.
(3) Represents NRG’s 49.95% ownership interest in Ivanpah. Following a sale of this 49.95% interest, the remaining 50.05% of Ivanpah would be owned by NRG, Google Inc. and BrightSource Energy Inc.
(4) Represents NRG’s 51% ownership interest in Agua Caliente. The remaining 49% of Agua Caliente is owned by MidAmerican Energy Holdings Inc.
(5) While Agua Caliente is expected to fully achieve commercial operations in early 2014, the maximum capacity deliverable under the PPA of 290 MWs is currently on-line.
In addition, NRG recently announced its agreement to acquire substantially all of the assets of Edison Mission Energy, or EME, pursuant to an acquisition agreement that is expected to close in the first quarter of 2014, subject to customary conditions, including federal and state regulatory approvals and confirmation of a Plan of Reorganization by the U.S. Bankruptcy Court of the Northern District of Illinois. NRG has stated publicly its near-term plan to commence offering to the Company certain of the EME assets it believes fit within the Company’s asset portfolio following the consummation of the EME acquisition, or the NYLD-Eligible Assets. NRG is not obligated to sell the NRG ROFO Assets or the NYLD - Eligible Assets to the Company and, if offered, the Company cannot be sure whether these assets will be offered on acceptable terms, or that the Company will choose to consummate such acquisitions. The NYLD-Eligible Assets are currently owned by EME and may never be acquired by NRG, in which event it is uncertain that the Company will ever be able to acquire them.
In addition, the Company expects to have significant opportunities to acquire other generation and thermal infrastructure assets from third parties where the Company believes its knowledge of the market, operating expertise and access to capital provides it with a competitive advantage.
Focus on North America.
The Company intends to focus its investments in North America and its unincorporated territories. The Company believes that industry fundamentals in North America present it with significant opportunity to acquire renewable, natural gas-fired generation and thermal infrastructure assets, without creating significant exposure to currency and sovereign risk. By focusing its efforts on North America, the Company believes it will best leverage its regional knowledge of power markets, industry relationships and skill sets to maximize value for the stockholders.
Maintain sound financial practices to grow the dividend.
The Company intends to maintain a commitment to disciplined financial analysis and a balanced capital structure to enable it to increase the dividend over time and serve the long-term interests of stockholders. The Company's financial practices will include a risk and credit policy focused on transacting with credit-worthy counterparties; a financing policy, which will focus on seeking an optimal capital structure through various capital formation alternatives to minimize interest rate and refinancing risks, ensure stable long-term dividends and maximize value; and a dividend policy, which is based on distributing all or substantially all cash available for distribution each quarter. The Company intends to evaluate various alternatives for financing future acquisitions and refinancing of existing project-level debt, in each case, to reduce the cost of debt, extend maturities and maximize cash available for distribution. The Company
believes it has additional flexibility to seek alternative financing arrangements, including, but not limited to, debt financings at a holding company level.
8
Competition
Power generation is a capital-intensive, commodity-driven business with numerous industry participants. The Company competes on the basis of the location of its plants and ownership of portfolios of plants in various regions, which increases the stability and reliability of its energy supply. Power generation is a regional business that is currently highly fragmented and diverse in terms of industry structure. As such, there is a wide variation in terms of the capabilities, resources, nature and identity of the companies with whom the Company competes with depending on the market. Competitors include regulated utilities, other independent power producers and power marketers or trading companies, including those owned by financial institutions, municipalities and cooperatives.
The Company's thermal business has certain cost efficiencies that may form barriers to entry. Generally, there is only one district energy system in a given territory, for which the only competition comes from on-site systems. While the district energy system can usually make an effective case for the efficiency of its services, some building owners nonetheless may opt for on-site systems, either due to corporate policies regarding allocation of capital, unique situations where an on-site system might in fact prove more efficient, or because of previously committed capital in systems that are already on-site. Growth in existing district energy system generally comes from new building construction or existing building conversions within the service territory of the district energy provider.
Competitive Strengths
Stable, high quality cash flows with attractive tax profile.
The Company's facilities have a highly stable, predictable cash flow profile consisting of predominantly long-life electric generation assets that sell electricity under long-term fixed priced contracts or pursuant to regulated rates with credit-worthy counterparties. Additionally, the Company's facilities have minimal fuel risk. For the Company's three conventional assets, fuel is provided by the toll counterparty or the cost thereof is a pass-through cost under the CfD. Renewable facilities have no fuel costs, and most of the Company's thermal infrastructure assets have contractual or regulatory tariff mechanisms for fuel cost recovery. The offtake agreements for the Company's conventional and renewable generation facilities have a weighted-average remaining duration of approximately 16 years based on net capacity under contract, providing long-term cash flow stability. The Company's generation offtake agreements for rated counterparties for whom credit ratings are available have a weighted-average Moody’s rating of A3 based on rated capacity under contract. Based on the current portfolio of assets, the Company does not expect to pay significant federal income tax for a period of approximately ten years. All of the Company's assets are in the United States and accordingly have no currency or repatriation risks.
High quality, long-lived assets with low operating and capital requirements.
The Company benefits from a portfolio of relatively newly-constructed assets, with all of its conventional and renewable assets either having achieved COD within the past five years or in the late stages of construction. The Company's assets are comprised of proven and reliable technologies, provided by leading original equipment manufacturers such as General Electric, or GE, Siemens AG, SunPower Corporation, or SunPower, and First Solar Inc., or First Solar. Given the modern nature of the portfolio, which includes a substantial number of relatively low operating and maintenance cost solar generation assets, the Company expects to achieve high fleet availability and expend modest maintenance-related capital expenditures. Additionally, with the support of services provided by NRG, the Company expects to continue to implement the same rigorous preventative operating and management practices that NRG uses across its fleet of assets. In 2012, NRG achieved its best safety performance with a 0.52 Occupational Safety and Health Administration (OSHA) recordable rate, well within the top decile plant operating performance for its entire fleet, based on applicable or OSHA, standards. The Company estimates its solar portfolio has a weighted average remaining expected life (based on rated MW) of approximately 29 years.
Significant scale and diversity.
The Company owns and operates a large and diverse portfolio of contracted electric generation and thermal infrastructure assets. The Company's
1,324
net MW contracted generation portfolio, consisting of eleven assets and two distributed solar generation portfolios, benefits from significant diversification in terms of technology, fuel type, counterparty and geography. The Company's thermal business consists of
nine
Energy Centers and has over
690
steam and chilled water customers. The Company believes its scale and access to best practices across the fleet improves its business development opportunities through enhanced industry relationships, reputation and understanding of regional power market dynamics. Furthermore, the Company's diversification reduces its operating risk profile and reliance on any single market.
9
Relationship with NRG.
The Company believes its relationship with NRG, including NRG’s expressed intention to maintain a controlling interest in the Company, provides significant benefits, including management and operational expertise, and future growth opportunities. The Company's executive officers have considerable experience in owning and operating, as well as developing, acquiring and integrating, generation and thermal infrastructure assets, with, on average, over 15 years in the energy sector:
•
NRG Management and Operational Expertise.
The Company has access to the significant resources of NRG, the largest competitive power generator in the United States, to support the operational, finance, legal, regulatory and environmental aspects, and growth strategy of its business. As such, the Company believes it avails itself of best-in-class resources, including management and operational expertise.
•
NRG Asset Development and Acquisition Track Record.
Over the last five years, excluding assets acquired from GenOn, NRG has constructed or has acquired eight conventional assets totaling 2,420 MW, nine utility scale solar assets totaling 1,113 MW, four wind assets totaling 451 MW and 40 MW of distributed solar facilities. In addition, NRG acquired the 134 MWt Phoenix Energy Center in 2010 and recently constructed the 38 MWt Princeton Energy Center. NRG’s growth is supported by considerable development and strategic teams, including over 70 professionals focused on the development and acquisition of renewable generation assets, as well as approximately 6,000 MW of conventional and other renewable projects under development as of
December 31, 2013
.
•
NRG Financing Experience.
The Company believes NRG has demonstrated a successful track record of sourcing attractive low-cost, long duration capital to fund project development and acquisitions. Since 2009, NRG has raised approximately $6 billion in long-term non-recourse project financing for over 15 projects from financial institutions and institutional debt markets as well as under the U.S. DOE loan guarantee program. The Company expects to realize significant benefits from NRG’s financing and structuring expertise as well as its relationships with financial institutions and other lenders.
Environmentally well-positioned portfolio of assets.
On a net capacity basis, the Company's portfolio of electric generation assets consists of 414 net MW of renewable generation capacity that are non-emitting sources of power generation. The Company's conventional assets consist of the dual fuel-fired GenConn assets as well as the Marsh Landing simple cycle natural gas-fired peaking generation facility. The Company does not anticipate having to expend any significant capital expenditures in the foreseeable future to comply with current environmental regulations applicable to its generation assets. Taken as a whole, the Company believes its strategy will be a net beneficiary of current and potential environmental legislation and regulatory requirements that may serve as a catalyst for capacity retirements and improve market opportunities for environmentally well-positioned assets like the Company's assets once its current offtake agreements expire.
Thermal infrastructure business has high entry costs.
Significant capital has been invested to construct the Company's thermal infrastructure assets, serving as a barrier to entry in the markets in which such assets operate. As of
December 31, 2013
, the Company's thermal gross property, plant, and equipment was approximately $421 million. The Company's thermal district energy centers are located in urban city areas, with the chilled water and steam delivery systems located underground. Constructing underground delivery systems in urban areas requires long lead times for permitting, rights of way and inspections and is costly. By contrast, the incremental cost to add new customers in existing markets is relatively low. Once thermal infrastructure is established, the Company believes it has the ability to retain customers over long periods of time and to compete effectively for additional business against stand-alone on-site heating and cooling generation facilities. Installation of stand-alone equipment can require significant modification to a building as well as significant space for equipment and funding for capital expenditures. The Company's system technologies often provide economies of scale in terms of fuel procurement, ability to switch between multiple types of fuel to generate thermal energy, and fuel conversion efficiency. The Company's top ten thermal customers, which make up approximately 18% of the Company's consolidated revenues for the twelve months ended
December 31, 2013
, have had a relationship with the Company for an average of over 20 years.
10
Segment Review
The following table summarizes the Company's operating revenues, net income and assets by segment for the years ended
December 31, 2013
,
2012
and
2011
, as discussed in Item 15 -
Note 12
,
Segment Reporting
, to the Consolidated Financial Statements. Refer to that footnote for additional information about the Company's segments. In addition, refer to Item 2 - Properties, for information about the facilities in each of the Company's segments.
|
|
Year ended December 31, 2013
|
||||||||||||||||||
|
(In millions)
|
Conventional Generation
|
|
Renewables
|
|
Thermal
|
|
Corporate
|
|
Total
|
||||||||||
|
Operating revenues
|
$
|
82
|
|
$
|
79
|
|
$
|
152
|
|
$
|
—
|
|
$
|
313
|
|
||||
|
Net income/(loss)
|
64
|
|
40
|
|
20
|
|
(15
|
)
|
109
|
|
|||||||||
|
Total assets
|
839
|
|
866
|
|
436
|
|
172
|
|
2,313
|
|
|||||||||
|
Year ended December 31, 2012
|
|||||||||||||||||||
|
(In millions)
|
Conventional Generation
|
Renewables
|
Thermal
|
Corporate
|
Total
|
||||||||||||||
|
Operating revenues
|
$
|
—
|
|
$
|
33
|
|
$
|
142
|
|
$
|
—
|
|
$
|
175
|
|
||||
|
Net income/(loss)
|
15
|
|
(1
|
)
|
16
|
|
(17
|
)
|
13
|
|
|||||||||
|
Total assets
|
744
|
|
893
|
|
326
|
|
1
|
|
1,964
|
|
|||||||||
|
Year ended December 31, 2011
|
|||||||||||||||||||
|
(In millions)
|
Conventional Generation
|
Renewables
|
Thermal
|
Corporate
|
Total
|
||||||||||||||
|
Operating revenues
|
$
|
—
|
|
$
|
26
|
|
$
|
138
|
|
$
|
—
|
|
$
|
164
|
|
||||
|
Net income/(loss)
|
12
|
|
5
|
|
13
|
|
(15
|
)
|
15
|
|
|||||||||
Government Incentives
Government incentives enhance the economic viability of the Company's operating assets by providing additional sources of funding for the construction of such assets. NRG has applied for and received cash grants in lieu of ITCs, pursuant to section 1603 of the American Recovery and Reinvestment Tax Act of 2009, for assets that are currently operating including Blythe, South Trent, Roadrunner, Avra Valley and certain Distributed Solar assets. In addition, NRG has submitted applications for cash grants in lieu of ITCs for Alpine and Borrego of
$72 million
and
$39 million
, respectively. The amounts receivable by the Company for the Alpine and Borrego projects were subsequently reduced to
$66 million
and
$36 million
, respectively, as a result of automatic federal spending cuts in 2013 that have taken place pursuant to the Balanced Budget and Emergency Deficit Control Act of 1985 as amended, commonly known as sequestration. Cash grants are treated as a reduction to the book basis of the property, plant and equipment and reduce the related depreciation over the useful life of the asset.
In January 2014, the Company received from the U.S. Treasury Department $66 million in cash grants for Alpine.
One of the Company's equity method investments, CVSR, obtained a loan guarantee from the U.S. DOE in support of its borrowings from the Federal Financing Bank, or FFB, to fund the construction of the facility, and CVSR submitted applications for cash grants in lieu of ITCs of $414 million ($392 million net of sequestration). In connection with the CVSR financing, as of
December 31, 2013
, there was $
341 million
in outstanding DOE-guaranteed cash grant bridge loans on the project, of which
$166 million
was due on February 5, 2014, and the remaining amount was due on August 5, 2014. In January 2014, the U.S. Treasury Department awarded cash grants on the CVSR project of $307 million ($285 million net of sequestration), which is approximately 75% of the cash grant amount for which the Company had applied. The cash grant proceeds were used to pay the outstanding balance of the bridge loan due in February 2014 and the remaining amount was used to pay a portion of the outstanding balance on the bridge loan due in August 2014. The remaining balance of the bridge loan due in August 2014 was paid by SunPower. CVSR is evaluating the basis for the U.S. Treasury Department’s award and all of its options for recovering the amount by which the U.S. Treasury Department reduced the CVSR cash grant award.
11
Regulatory Matters
As operators of power plants and participants in wholesale energy markets, certain of the Company's entities are subject to regulation by various federal and state government agencies. These include the CFTC, FERC, and the PUCT, as well as other public utility commissions in certain states where the Company's generating, thermal, or distributed solar assets are located. In addition, the Company is subject to the market rules, procedures and protocols of the various ISO markets in which it participates. The Company must also comply with the mandatory reliability requirements imposed by the North American Electric Reliability Corporation and the regional reliability entities in the regions where the Company operates.
The Company's operations within the ERCOT footprint are not subject to rate regulation by the FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. These operations are subject to regulation by PUCT.
CFTC
The CFTC, among other things, has regulatory oversight authority over the trading of electricity and natural gas commodities, including financial products and derivatives, under the Commodity Exchange Act, or CEA. The Dodd-Frank Wall Street Reform and Consumer Protection Act, or Dodd-Frank Act, among other things, aims to improve transparency and accountability in derivative markets. The Dodd-Frank Act increases the CFTC’s regulatory authority on matters related to over-the-counter derivatives, market clearing, position reporting, and capital requirements.
The Company expects that in 2014, the CFTC will clarify the scope of the Dodd-Frank Act and issue final rules concerning position limits, margin requirements, and other issues that will affect NRG’s over-the-counter derivatives trading. Because there are many details that remain to be addressed in CFTC rulemaking proceedings, at this time the expected impact to the Company on its current operations cannot be measured.
FERC
FERC, among other things, regulates the transmission and the wholesale sale of electricity in interstate commerce under the authority of the FPA. The transmission of electric energy occurring wholly within ERCOT is not subject to the FERC’s jurisdiction under Sections 203 or 205 of the FPA. Under existing regulations, the FERC determines whether an entity owning a generation facility is an EWG, as defined in the PUHCA. FERC also determines whether a generation facility meets the ownership and technical criteria of a Qualifying Facility, or QF, under the PURPA. Each of the Company’s non-ERCOT U.S. generating facilities qualifies as an EWG.
The FPA gives the FERC exclusive rate-making jurisdiction over the wholesale sale of electricity and transmission of electricity in interstate commerce of public utilities (as defined by the FPA). Under the FPA, the FERC, with certain exceptions, regulates the owners of facilities used for the wholesale sale of electricity or transmission in interstate commerce as public utilities, and establishes market rules that are just and reasonable.
Public utilities are required to obtain the FERC’s acceptance, pursuant to Section 205 of the FPA, of their rate schedules for the wholesale sale of electricity. All of the Company’s non-QF generating entities located outside of ERCOT make sales of electricity pursuant to market-based rates, as opposed to traditional cost-of-service regulated rates. Every three years FERC will conduct a review of the Company’s market based rates and potential market power on a regional basis, consistent with FERC’s prior reviews of NRG’s market based rates and potential market power.
In accordance with the Energy Policy Act of 2005, the FERC has approved the NERC as the national Energy Reliability Organization, or ERO. As the ERO, NERC is responsible for the development and enforcement of mandatory reliability standards for the wholesale electric power system. In addition to complying with NERC requirements, each NRG entity must comply with the requirements of the regional reliability entity for the region in which it is located.
PUHCA provides the FERC with certain authority over and access to books and records of public utility holding companies not otherwise exempt by virtue of their ownership of EWGs, QFs, and Foreign Utility Companies. The Company is exempt from many of the accounting, record retention, and reporting requirements of the PUHCA.
PURPA was passed in 1978 in large part to promote increased energy efficiency and development of independent power producers. PURPA created QFs to further both goals, and the FERC is primarily charged with administering PURPA as it applies to QFs. Certain QFs are exempt from regulation, either in whole or in part, under the FPA as public utilities.
12
Regulatory Developments
Thermal
NRG Energy Center Harrisburg LLC Rate Case
— On April 12, 2013, NRG Energy Center Harrisburg LLC, or NRG Harrisburg, one of the Company's regulated steam utility in Harrisburg, Pennsylvania, filed a base rate case with the Pennsylvania Public Utility Commission, or PA PUC, for an increase in annual revenues of $875,000. On December 5, 2013, the PA PUC approved the base rate increase and the new rates became effective December 6, 2013.
Conventional Generation
Performance Incentive Proposal
— On January 17, 2014, ISO-NE filed at FERC to fundamentally revamp its forward capacity market, or FCM, by making a resource’s forward capacity market compensation dependent on resource output during short intervals of operating reserve scarcity. The ISO-NE proposal would replace the existing shortage event penalty structure with a new performance incentive, or PI, mechanism, resulting in capacity payments to resources that would be the combination of two components: (1) a base capacity payment and (2) a performance payment or charge. The performance payment or charge would be entirely dependent upon the resource’s delivery of energy or operating reserves during scarcity conditions, and could be larger than the base payment.
NEPOOL, the ISO-NE stakeholder group, filed an alternative proposal to ISO-NE’s PI proposal at FERC, under which the market rules would be revised to maintain the FCM capacity product as a tool to ensure resource adequacy
,
and would place real-time performance incentive-related improvements directly into the energy and reserve markets. The Company supports the NEPOOL alternative. The matter is pending at FERC.
Employees
The Company does not employ any of the individuals who manage operations. The personnel that carry out these activities are employees of NRG, and their services are provided for the Company's benefit under the Management Services Agreement with NRG as described in
Item 15,
Note 14
,
Related Party Transactions
.
Available Information
The Company's annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to section 13(a) or 15(d) of the Exchange Act are available free of charge through the Company's website, www.nrgyield.com, as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. The Company also routinely posts press releases, presentations, webcasts, and other information regarding the Company on its website.
13
Risks Related to the Business
Certain facilities are newly constructed and may not perform as expected.
All of the Company's conventional and renewable assets have achieved commercial operations within the past 5 years. The ability of these facilities to meet the Company's performance expectations is subject to the risks inherent in newly constructed power generation facilities and the construction of such facilities, including, but not limited to, degradation of equipment in excess of the Company's expectations, system failures, and outages. The failure of these facilities to perform as the Company expects could have a material adverse effect on the Company's business, financial condition, results of operations and cash flows and its ability to pay dividends to holders of the Company's Class A common stock.
Pursuant to the Company's cash dividend policy, the Company intends to distribute all or substantially all of the cash available for distribution through regular quarterly distributions and dividends, and the Company's ability to grow and make acquisitions through cash on hand could be limited.
The Company expects to distribute all or substantially all of the cash available for distribution each quarter and to rely primarily upon external financing sources, including the issuance of debt and equity securities and, if applicable, borrowings under the Company's revolving credit facility to fund acquisitions and growth capital expenditures. The Company may be precluded from pursuing otherwise attractive acquisitions if the projected short-term cash flow from the acquisition or investment is not adequate to service the capital raised to fund the acquisition or investment, after giving effect to the Company's available cash reserves. The Company's growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent the Company issues additional equity securities in connection with any acquisitions or growth capital expenditures, the payment of dividends on these additional equity securities may increase the risk that the Company will be unable to maintain or increase its per share dividend. The incurrence of bank borrowings or other debt by NRG Yield Operating LLC or by the Company project-level subsidiaries to finance the Company’s growth strategy will result in increased interest expense and the imposition of additional or more restrictive covenants, which, in turn, may impact the cash distributions the Company receives to distribute to holders of the Company’s Class A common stock.
The Company may not be able to effectively identify or consummate any future acquisitions on favorable terms, or at all.
The Company business strategy includes growth through the acquisitions of additional generation assets (including through corporate acquisitions). This strategy depends on the Company’s ability to successfully identify and evaluate acquisition opportunities and consummate acquisitions on favorable terms. However, the number of acquisition opportunities is limited. In addition, the Company will compete with other companies for these limited acquisition opportunities, which may increase the Company’s cost of making acquisitions or cause the Company to refrain from making acquisitions at all. Some of the Company’s competitors for acquisitions are much larger than the Company with substantially greater resources. These companies may be able to pay more for acquisitions and may be able to identify, evaluate, bid for and purchase a greater number of assets than the Company’s financial or human resources permit. If the Company is unable to identify and consummate future acquisitions, it will impede the Company’s ability to execute its growth strategy and limit the Company’s ability to increase the amount of dividends paid to holders of the Company’s Class A common stock.
Furthermore, the Company’s ability to acquire future renewable facilities may depend on the viability of renewable assets generally. These assets currently are largely contingent on public policy mechanisms including ITCs, cash grants, loan guarantees, accelerated depreciation, RPS and carbon trading plans. These mechanisms have been implemented at the state and federal levels to support the development of renewable generation, demand-side and smart grid and other clean infrastructure technologies. The availability and continuation of public policy support mechanisms will drive a significant part of the economics and viability of the Company’s growth strategy and expansion into clean energy investments.
14
The Company’s ability to effectively consummate future acquisitions will also depend on the Company’s ability to arrange the required or desired financing for acquisitions.
The Company may not have sufficient availability under the Company’s credit facilities or have access to project-level financing on commercially reasonable terms when acquisition opportunities arise. An inability to obtain the required or desired financing could significantly limit the Company’s ability to consummate future acquisitions and effectuate the Company’s growth strategy. If financing is available, utilization of the Company’s credit facilities or project-level financing for all or a portion of the purchase price of an acquisition could significantly increase the Company’s interest expense, impose additional or more restrictive covenants and reduce cash available for distribution. Similarly, the issuance of additional equity securities as consideration for acquisitions could cause significant stockholder dilution and reduce the Company’s per share cash available for distribution if the acquisitions are not sufficiently accretive. The Company’s ability to consummate future acquisitions may also depend on the Company’s ability to obtain any required regulatory approvals for such acquisitions, including, but not limited to, approval by the U.S. FERC under Section 203 of the FPA.
Finally, the acquisition of companies and assets are subject to substantial risks, including the failure to identify material problems during due diligence (for which the Company may not be indemnified post-closing), the risk of over-paying for assets (or not making acquisitions on an accretive basis) and the ability to retain customers. Further, the integration and consolidation of acquisitions requires substantial human, financial and other resources and, ultimately, the Company acquisitions may divert management’s attention from the Company existing business concerns, disrupt the Company ongoing business or not be successfully integrated. There can be no assurances that any future acquisitions will perform as expected or that the returns from such acquisitions will support the financing utilized to acquire them or maintain them. As a result, the consummation of acquisitions may have a material adverse effect on the Company business, financial condition, results of operations and cash flows and ability to pay dividends to holders of the Company’s Class A common stock.
The Company’s indebtedness could adversely affect its ability to raise additional capital to fund the Company’s operations or pay dividends. It could also expose the Company to the risk of increased interest rates and limit the Company’s ability to react to changes in the economy or the Company’s industry as well as impact the Company’s cash available for distribution.
As of December 31, 2013, the Company had approximately
$1,133 million
of total consolidated indebtedness, all of which was incurred by the Company's non-guarantor subsidiaries. In addition, the Company’s share of its unconsolidated affiliates’ total indebtedness and letters of credit outstanding as of December 31, 2013 totaled approximately
$715 million
and $25 million, respectively (calculated as the Company’s unconsolidated affiliates’ total indebtedness as of such date multiplied by the Company’s percentage membership interest in such assets). On July 22, 2013, the Company entered into a $60 million revolving credit facility. In addition, the Company had $90 million of letters of credit outstanding to support contracted obligations at the Company’s project-level entities. All of the Company’s existing indebtedness is incurred at the project level. In February 2014, the Company closed on its offering of
$300 million
aggregate principal amount of 3.50% Convertible Senior Notes (Notes) due 2019. Additionally, the initial purchasers exercised their option to purchase an additional $45 million in aggregate principal amount of the NRG Yield Senior Notes. The Notes are convertible, under certain circumstances, into the Company’s common stock, cash or a combination thereof at an initial conversion price of $46.55 per Class A common share, which is equivalent to an initial conversion rate of approximately 21.4822 shares of Class A common stock per $1,000 principal amount of Notes. The Company’s substantial debt could have important negative consequences on the Company’s financial condition, including:
|
•
|
increasing the Company’s vulnerability to general economic and industry conditions;
|
|
•
|
requiring a substantial portion of the Company’s cash flow from operations to be dedicated to the payment of principal and interest on the Company’s indebtedness, therefore reducing the Company’s ability to pay dividends to holders of the Company’s Class A common stock or to use the Company’s cash flow to fund its operations, capital expenditures and future business opportunities;
|
|
•
|
limiting the Company’s ability to enter into long-term power sales or fuel purchases which require credit support;
|
|
•
|
limiting the Company’s ability to fund operations or future acquisitions;
|
|
•
|
restricting the Company’s ability to make certain distributions with respect to the Company’s Class A common stock and the ability of the Company’s subsidiaries to make certain distributions to it, in light of restricted payment and other financial covenants in the Company’s credit facilities and other financing agreements;
|
|
•
|
exposing the Company to the risk of increased interest rates because certain of the Company’s borrowings, which may include borrowings under the Company’s revolving credit facility, are at variable rates of interest;
|
|
•
|
limiting the Company’s ability to obtain additional financing for working capital including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; and
|
|
•
|
limiting the Company’s ability to adjust to changing market conditions and placing it at a competitive disadvantage compared to the Company’s competitors who have less debt.
|
15
The Company revolving credit facility contains financial and other restrictive covenants that limit the Company’s ability to return capital to stockholders or otherwise engage in activities that may be in the Company’s long-term best interests. The Company’s inability to satisfy certain financial covenants could prevent the Company from paying cash dividends, and the Company’s failure to comply with those and other covenants could result in an event of default which, if not cured or waived, may entitle the related lenders to demand repayment or enforce their security interests, which could have a material adverse effect on the Company’s business, financial condition, results of operations and cash flows. In addition, failure to comply with such covenants may entitle the related lenders to demand repayment and accelerate all such indebtedness.
The agreements governing the Company’s project-level financing contain financial and other restrictive covenants that limit the Company’s project subsidiaries’ ability to make distributions to it or otherwise engage in activities that may be in the Company’s long-term best interests. The project-level financing agreements generally prohibit distributions from the project entities to the Company unless certain specific conditions are met, including the satisfaction of certain financial ratios. The Company’s inability to satisfy certain financial covenants may prevent cash distributions by the particular project(s) to it and, the Company’s failure to comply with those and other covenants could result in an event of default which, if not cured or waived may entitle the related lenders to demand repayment or enforce their security interests, which could have a material adverse effect on the Company’s business, results of operations and financial condition. In addition, failure to comply with such covenants may entitle the related lenders to demand repayment and accelerate all such indebtedness. If the Company is unable to make distributions from the Company’s project-level subsidiaries, it would likely have a material adverse effect on the Company’s ability to pay dividends to holders of the Company’s Class A common stock.
Letter of credit facilities to support project-level contractual obligations generally need to be renewed after five to seven years, at which time the Company will need to satisfy applicable financial ratios and covenants. If the Company is unable to renew the Company’s letters of credit as expected or replace them with letters of credit under different facilities on favorable terms or at all, the Company may experience a material adverse effect on its business, financial condition or results of operations and cash flows. Furthermore, such inability may constitute a default under certain project-level financing arrangements, restrict the ability of the project-level subsidiary to make distributions to it and/or reduce the amount of cash available at such subsidiary to make distributions to the Company.
In addition, the Company’s ability to arrange financing, either at the corporate level or at a non-recourse project-level subsidiary, and the costs of such capital, are dependent on numerous factors, including:
|
•
|
general economic and capital market conditions;
|
|
•
|
credit availability from banks and other financial institutions;
|
|
•
|
investor confidence in the Company, its partners, NRG, as the Company’s principal stockholder (on a combined voting basis) and manager under the Management Services Agreement, and the regional wholesale power markets;
|
|
•
|
the Company’s financial performance and the financial performance of the Company subsidiaries;
|
|
•
|
the Company’s level of indebtedness and compliance with covenants in debt agreements;
|
|
•
|
maintenance of acceptable project credit ratings or credit quality;
|
|
•
|
cash flow; and
|
|
•
|
provisions of tax and securities laws that may impact raising capital.
|
The Company may not be successful in obtaining additional capital for these or other reasons. Furthermore, the Company may be unable to refinance or replace project-level financing arrangements or other credit facilities on favorable terms or at all upon the expiration or termination thereof. The Company failure, or the failure of any of the Company’s projects, to obtain additional capital or enter into new or replacement financing arrangements when due may constitute a default under such existing indebtedness and may have a material adverse effect on the Company business, financial condition, results of operations and cash flows.
The Company's long-term contracts may be challenged or declared invalid by a court of competent jurisdiction.
A significant portion of the Company's revenues are derived from long-term bilateral contracts. Those contracts may be subject to challenge under a variety of legal doctrines. If those contracts were to be declared invalid, profitability may suffer and the Company would be exposed to merchant market risk.
16
The generation of electric energy from solar and wind energy sources depends heavily on suitable meteorological conditions.
If solar or wind conditions are unfavorable, the Company's electricity generation and revenue from renewable generation facilities may be substantially below the Company's expectations. The electricity produced and revenues generated by a solar electric or wind energy generation facility is highly dependent on suitable solar or wind conditions, as applicable, and associated weather conditions, which are beyond the Company's control. Furthermore, components of the Company's systems, such as solar panels and inverters, could be damaged by severe weather, such as hailstorms or tornadoes. In addition, replacement and spare parts for key components may be difficult or costly to acquire or may be unavailable. Unfavorable weather and atmospheric conditions could impair the effectiveness of the Company's assets or reduce their output beneath their rated capacity or require shutdown of key equipment, impeding operation of the Company's renewable assets.
The Company bases its investment decisions with respect to each renewable generation facility on the findings of related wind and solar studies conducted on-site prior to construction or based on historical conditions at existing facilities. However, actual climatic conditions at a facility site, particularly wind conditions, may not conform to the findings of these studies and therefore, the Company's solar and wind energy facilities may not meet anticipated production levels or the rated capacity of the Company's generation assets, which could adversely affect the business, financial condition and results of operations and cash flows.
Operation of electric generation facilities involves significant risks and hazards customary to the power industry that could have a material adverse effect on the business, financial condition, results of operations and cash flows.
The ongoing operation of the Company's facilities involves risks that include the breakdown or failure of equipment or processes or performance below expected levels of output or efficiency due to wear and tear, latent defect, design error or operator error or force majeure events, among other things. Operation of the Company's facilities also involves risks that the Company will be unable to transport its product to its customers in an efficient manner due to a lack of transmission capacity. Unplanned outages of generating units, including extensions of scheduled outages due to mechanical failures or other problems, occur from time to time and are an inherent risk of the business. Unplanned outages typically increase operation and maintenance expenses and may reduce revenues as a result of selling fewer MWh or require the Company to incur significant costs as a result of obtaining replacement power from third parties in the open market to satisfy forward power sales obligations. The Company's inability to operate its electric generation assets efficiently, manage capital expenditures and costs and generate earnings and cash flow from the Company's asset-based businesses could have a material adverse effect on the business, financial condition, results of operations and cash flows. While the Company maintains insurance, obtains warranties from vendors and obligates contractors to meet certain performance levels, the proceeds of such insurance, warranties or performance guarantees may not cover the Company's lost revenues, increased expenses or liquidated damages payments should it experience equipment breakdown or non-performance by contractors or vendors.
Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems.
In addition to natural risks such as earthquake, flood, lightning, hurricane and wind, other hazards, such as fire, explosion, structural collapse and machinery failure are inherent risks in the Company's operations. These and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment and contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in the Company being named as a defendant in lawsuits asserting claims for substantial damages, including for environmental cleanup costs, personal injury and property damage and fines and/or penalties. The Company maintains an amount of insurance protection that it considers adequate but cannot provide any assurance that the Company's insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which the Company may be subject. Furthermore, the Company's insurance coverage is subject to deductibles, caps, exclusions and other limitations. A loss for which the Company is not fully insured (which may include a significant judgment against any facility or facility operator) could have a material adverse effect on the Company's business, financial condition, results of operations or cash flows. Further, due to rising insurance costs and changes in the insurance markets, the Company cannot provide any assurance that its insurance coverage will continue to be available at all or at rates or on terms similar to those presently available. Any losses not covered by insurance could have a material adverse effect on the Company's business, financial condition, results of operations and cash flows.
17
Maintenance, expansion and refurbishment of electric generation facilities involve significant risks that could result in unplanned power outages or reduced output.
The Company's facilities may require periodic upgrading and improvement. Any unexpected operational or mechanical failure, including failure associated with breakdowns and forced outages, could reduce the Company's facilities' generating capacity below expected levels, reducing the Company's revenues and jeopardizing the Company's ability to pay dividends to holders of its Class A common stock at forecasted levels or at all. Degradation of the performance of the Company's solar facilities above levels provided for in the related offtake agreements may also reduce the Company's revenues. Unanticipated capital expenditures associated with maintaining, upgrading or repairing the Company's facilities may also reduce profitability.
If the Company makes any major modifications to its conventional power generation facilities, it may be required to install the best available control technology or to achieve the lowest achievable emission rates as such terms are defined under the new source review provisions of the federal Clean Air Act in the future. Any such modifications could likely result in substantial additional capital expenditures. The Company may also choose to repower, refurbish or upgrade its facilities based on its assessment that such activity will provide adequate financial returns. Such facilities require time for development and capital expenditures before commencement of commercial operations, and key assumptions underpinning a decision to make such an investment may prove incorrect, including assumptions regarding construction costs, timing, available financing and future fuel and power prices. This could have a material adverse effect on the Company's business, financial condition, results of operations and cash flows.
Counterparties to the Company's offtake agreements may not fulfill their obligations and, as the contracts expire, the Company may not be able to replace them with agreements on similar terms in light of increasing competition in the markets in which the Company operates.
A significant portion of the electric power the Company generates is sold under long-term offtake agreements with public utilities or industrial or commercial end-users, with a weighted average remaining duration of approximately 16 years (based on net capacity under contract). As of
December 31, 2013
, the largest customers of the Company's power generation assets, including assets in which the Company has less than a 100% membership interest, were PG&E, CL&P and American Electric Power, which represented 70%, 14% and 8% respectively, of the net electric generation capacity of the Company's facilities.
If, for any reason, any of the purchasers of power under these agreements are unable or unwilling to fulfill their related contractual obligations or if they refuse to accept delivery of power delivered thereunder or if they otherwise terminate such agreements prior to the expiration thereof, the Company's assets, liabilities, business, financial condition, results of operations and cash flow could be materially and adversely affected. Furthermore, to the extent any of the Company's power purchasers are, or are controlled by, governmental entities, the Company's facilities may be subject to legislative or other political action that may impair their contractual performance.
The power generation industry is characterized by intense competition and the Company's electric generation assets encounter competition from utilities, industrial companies and other independent power producers, in particular with respect to uncontracted output. In recent years, there has been increasing competition among generators for offtake agreements and this has contributed to a reduction in electricity prices in certain markets characterized by excess supply above designated reserve margins. In light of these market conditions, the Company may not be able to replace an expiring or terminated agreement with an agreement on equivalent terms and conditions, including at prices that permit operation of the related facility on a profitable basis. In addition, the Company believes many of its competitors have well-established relationships with the Company's current and potential suppliers, lenders, customers and have extensive knowledge of its target markets. As a result, these competitors may be able to respond more quickly to evolving industry standards and changing customer requirements than the Company will be able to. Adoption of technology more advanced than the Company's could reduce its competitors' power production costs resulting in their having a lower cost structure than is achievable with the technologies currently employed by the Company and adversely affect its ability to compete for offtake agreement renewals. If the Company is unable to replace an expiring or terminated offtake agreement, the affected facility may temporarily or permanently cease operations. External events, such as a severe economic downturn, could also impair the ability of some counterparties to the Company's offtake agreements and other customer agreements to pay for energy and/or other products and services received.
The Company's inability to enter into new or replacement offtake agreements or to compete successfully against current and future competitors in the markets in which the Company operates could have a material adverse effect on the Company's business, financial condition, results of operations and cash flows.
18
Certain of the Company thermal generation assets operate, wholly or partially, without long-term power sale agreements.
The Company’s Dover and Paxton thermal generation assets have 116 net MW of generation capacity that have been sold through May 2017 in the annual Base Residual Auction, or BRA, under the PJM-administered RPM. Capacity revenue beginning in June 2017 is not yet determined. These facilities do not have offtake agreements for energy sales and sell energy through NRG Power Marketing, an NRG affiliate, into the bid-based auction market for energy administered by PJM based on economic dispatch of their units. If the Company is unable to sell available capacity from those facilities beginning in June 2017 through the BRA or one of the other RPM capacity auctions or is unable to enter into a offtake agreement or otherwise sell unallocated or unsold capacity at favorable terms, there may be a material adverse effect on the Company's business, financial condition, results of operations and cash flows.
A portion of the steam and chilled water produced by the Company's thermal assets is sold at regulated rates, and the revenue earned by the Company's GenConn assets is established each year in a rate case; accordingly, the profitability of these assets is dependent on regulatory approval.
Approximately 395 net MWt of capacity from certain of the Company's thermal assets are sold at rates approved by one or more federal or state regulatory commissions, including the Pennsylvania Public Utility Commission and the California Public Utilities Commission for the thermal assets. Similarly, the revenues related to approximately 380 MW of capacity from the GenConn assets are established each year by the Connecticut Public Utilities Regulatory Authority. While such regulatory oversight is generally premised on the recovery of prudently incurred costs and a reasonable rate of return on invested capital, the rates that the Company may charge, or the revenue that the Company may earn with respect to this capacity are subject to authorization of the applicable regulatory authorities. There can be no assurance that such regulatory authorities will consider all of the costs to have been prudently incurred or that the regulatory process by which rates or revenues are determined will always result in rates or revenues that achieve full recovery of costs or an adequate return on the Company's capital investments. While the Company's rates and revenues are generally established based on an analysis of costs incurred in a base year, the rates the Company is allowed to charge, and the revenues the Company is authorized to earn, may or may not match the costs at any given time. If the Company's costs are not adequately recovered through these regulatory processes, it could have a material adverse effect on the business, financial condition, results of operations and cash flows.
Supplier concentration at certain of the Company's facilities may expose the Company to significant financial credit or performance risks.
The Company often relies on a single contracted supplier or a small number of suppliers for the provision of fuel, transportation of fuel, equipment, technology and/or other services required for the operation of certain facilities. In addition, certain of the Company's suppliers provide long-term warranties with respect to the performance of their products or services. If any of these suppliers cannot perform under their agreements with the Company, or satisfy their related warranty obligations, the Company will need to utilize the marketplace to provide or repair these products and services. There can be no assurance that the marketplace can provide these products and services as, when and where required. The Company may not be able to enter into replacement agreements on favorable terms or at all. If the Company is unable to enter into replacement agreements to provide for fuel, equipment, technology and other required services, it would seek to purchase the related goods or services at market prices, exposing the Company to market price volatility and the risk that fuel and transportation may not be available during certain periods at any price. The Company may also be required to make significant capital contributions to remove, replace or redesign equipment that cannot be supported or maintained by replacement suppliers, which could have a material adverse effect on the business, financial condition, results of operations, credit support terms and cash flows.
In addition, potential or existing customers at the Company’s district energy centers and combined heat and power plants, or the Energy Centers, may opt for on-site systems in lieu of using the Company’s Energy Centers, either due to corporate policies regarding the allocation of capital, unique situations where an on-site system might in fact prove more efficient, because of previously committed capital in systems that are already on-site, or otherwise.
The failure of any supplier to fulfill its contractual obligations to the Company or the Company’s loss of potential or existing customers could have a material adverse effect on its financial results. Consequently, the financial performance of the Company's facilities is dependent on the credit quality of, and continued performance by, the Company's suppliers and vendors and the Company’s ability to solicit and retain customers.
19
The Company currently owns, and in the future may acquire, certain assets in which the Company has limited control over management decisions and its interests in such assets may be subject to transfer or other related restrictions.
The Company has limited control over the operation of GenConn, Avenal and CVSR because the Company beneficially owns 49.95%, 49.95% and 48.95%, respectively, of the membership interests in such assets. The Company may seek to acquire additional assets in which it owns less than a majority of the related membership interests in the future. In these investments, the Company will seek to exert a degree of influence with respect to the management and operation of assets in which it owns less than a majority of the membership interests by negotiating to obtain positions on management committees or to receive certain limited governance rights, such as rights to veto significant actions. However, the Company may not always succeed in such negotiations. The Company may be dependent on its co-venturers to operate such assets. The Company's co-venturers may not have the level of experience, technical expertise, human resources management and other attributes necessary to operate these assets optimally. In addition, conflicts of interest may arise in the future between the
Company and its stockholders, on the one hand, and the Company's co-venturers, on the other hand, where the Company's co-venturers' business interests are inconsistent with the interests of the Company and its stockholders. Further, disagreements or disputes between the Company and its co-venturers could result in litigation, which could increase expenses and potentially limit the time and effort the Company's officers and directors are able to devote to the business.
The approval of co-venturers also may be required for the Company to receive distributions of funds from assets or to sell, pledge, transfer, assign or otherwise convey its interest in such assets, or for the Company to acquire NRG's interests in such co-ventures as an initial matter. Alternatively, the Company's co-venturers may have rights of first refusal or rights of first offer in the event of a proposed sale or transfer of the Company's interests in such assets. These restrictions may limit the price or interest level for interests in such assets, in the event the Company wants to sell such interests.
Furthermore, certain of the Company's facilities, including Alpine, Avra Valley, Blythe and Roadrunner, are operated by third-party operators, such as First Solar. To the extent that third-party operators do not fulfill their obligations to manage operations of the facilities or are not effective in doing so, the amount of cash available for distribution may be adversely affected.
The Company's assets are exposed to risks inherent in the use of interest rate swaps and forward fuel purchase contracts and the Company may be exposed to additional risks in the future if it utilizes other derivative instruments.
The Company uses interest rate swaps to manage interest rate risk. In addition, the Company uses forward fuel purchase contracts to hedge its limited commodity exposure with respect to the Company's district energy assets. If the Company elects to enter into such commodity hedges, the related asset could recognize financial losses on these arrangements as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. If actively quoted market prices and pricing information from external sources are not available, the valuation of these contracts would involve judgment or the use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts. If the values of these financial contracts change in a manner that the Company does not anticipate, or if a counterparty fails to perform under a contract, it could harm the business, financial condition, results of operations and cash flows.
The Company's business is subject to restrictions resulting from environmental, health and safety laws and regulations.
The Company is subject to various federal, state and local environmental and health and safety laws and regulations. In addition, the Company may be held primarily or jointly and severally liable for costs relating to the investigation and clean-up of any property where there has been a release or threatened release of a hazardous regulated material as well as other affected properties, regardless of whether the Company knew of or caused the release. In addition to these costs, which are typically not limited by law or regulation and could exceed an affected property's value, the Company could be liable for certain other costs, including governmental fines and injuries to persons, property or natural resources. Further, some environmental laws provide for the creation of a lien on a contaminated site in favor of the government as security for damages and any costs the government incurs in connection with such contamination and associated clean-up. Although the Company generally requires its operators to undertake to indemnify it for environmental liabilities they cause, the amount of such liabilities could exceed the financial ability of the operator to indemnify the Company. The presence of contamination or the failure to remediate contamination may adversely affect the Company's ability to operate the business.
20
The Company does not own all of the land on which its power generation or thermal assets are located, which could result in disruption to its operations.
The Company does not own all of the land on which its power generation or thermal assets are located and the Company is, therefore, subject to the possibility of less desirable terms and increased costs to retain necessary land use if it does not have valid leases or rights-of-way or if such rights-of-way lapse or terminate. Although the Company has obtained rights to construct and operate these assets pursuant to related lease arrangements, the rights to conduct those activities are subject to certain exceptions, including the term of the lease arrangement. The loss of these rights, through the Company's inability to renew right-of-way contracts or otherwise, may adversely affect the Company's ability to operate its generation and thermal infrastructure assets.
The electric generation business is subject to substantial governmental regulation and may be adversely affected by changes in laws or regulations, as well as liability under, or any future inability to comply with, existing or future regulations or other legal requirements.
The Company's electric generation business is subject to extensive U.S. federal, state and local laws and regulation. Compliance with the requirements under these various regulatory regimes may cause the Company to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines, and/or civil or criminal liability. Public utilities under the FPA are required to obtain FERC acceptance of their rate schedules for wholesale sales of electric energy, capacity and ancillary services. Except for generating facilities within the footprint of ERCOT which are regulated by the PUCT, all of the Company’s assets make wholesale sales of electric energy, capacity and ancillary services in interstate commerce and are public utilities for purposes of the FPA, unless otherwise exempt from such status. The FERC's orders that grant such wholesale sellers market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that the seller can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, public utilities are subject to FERC reporting requirements that impose administrative burdens and that, if violated, can expose the company to criminal and civil penalties or other risks.
The Company's market-based sales will be subject to certain market behavior rules, and if any of the Company's generating companies are deemed to have violated those rules, they will be subject to potential disgorgement of profits associated with the violation, penalties, suspension or revocation of market based rate authority. If such generating companies were to lose their market-based rate authority, such companies would be required to obtain the FERC's acceptance of a cost-of-service rate schedule and could become subject to the significant accounting, record-keeping, and reporting requirements that are imposed on utilities with cost- based rate schedules. This could have a material adverse effect on the rates the Company is able to charge for power from its facilities.
Most of the Company's assets are operating as Exempt Wholesale Generators as defined under the PUHCA, or Qualifying Facilities as defined under the PURPA, as amended, and therefore are exempt from certain regulation under PUHCA. If a facility fails to maintain its status as an Exempt Wholesale Generator or a Qualifying Facility or there are legislative or regulatory changes revoking or limiting the exemptions to PUHCA, then the Company may be subject to significant accounting, record-keeping, access to books and records and reporting requirements and failure to comply with such requirements could result in the imposition of penalties and additional compliance obligations.
Substantially all of the Company's generation assets are also subject to the reliability standards of the NERC. If the Company fails to comply with the mandatory reliability standards, it could be subject to sanctions, including substantial monetary penalties and increased compliance obligations. The Company will also be affected by legislative and regulatory changes, as well as changes to market design, market rules, tariffs, cost allocations, and bidding rules that occur in the existing regional markets operated by RTOs or ISOs, such as PJM. The RTOs/ISOs that oversee most of the wholesale power markets impose, and in the future may continue to impose, mitigation, including price limitations, offer caps, and other mechanisms to address some of the volatility and the potential exercise of market power in these markets. These types of price limitations and other regulatory mechanisms may have a material adverse effect on the profitability of the Company's generation facilities acquired in the future that sell energy, capacity and ancillary products into the wholesale power markets. The regulatory environment for electric generation has undergone significant changes in the last several years due to state and federal policies affecting wholesale competition and the creation of incentives for the addition of large amounts of new renewable generation and, in some cases, transmission assets. These changes are ongoing and the Company cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on the Company's business. In addition, in some of these markets, interested parties have proposed material market re-regulate the markets or require divestiture of electric generation assets by asset owners or operators to reduce their market share. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process. If competitive restructuring of the electric power markets is reversed, discontinued, or delayed, the Company's business prospects and financial results could be negatively impacted.
21
The Company is subject to environmental laws and regulations that impose extensive and increasingly stringent requirements on its operations, as well as potentially substantial liabilities arising out of environmental contamination.
The Company's assets are subject to numerous and significant federal, state and local laws, including statutes, regulations, guidelines, policies, directives and other requirements governing or relating to, among other things: protection of wildlife, including threatened and endangered species; air emissions; discharges into water; water use; the storage, handling, use, transportation and distribution of dangerous goods and hazardous, residual and other regulated materials, such as chemicals; the prevention of releases of hazardous materials into the environment; the prevention, presence and remediation of hazardous materials in soil and groundwater, both on and offsite; land use and zoning matters; and workers' health and safety matters. The Company's facilities could experience incidents, malfunctions and other unplanned events that could result in spills or emissions in excess of permitted levels and result in personal injury, penalties and property damage. As such, the operation of the Company's facilities carries an inherent risk of environmental, health and safety liabilities (including potential civil actions, compliance or remediation orders, fines and other penalties), and may result in the assets being involved from time to time in administrative and judicial proceedings relating to such matters. The Company has implemented environmental, health and safety management programs designed to continually improve environmental, health and safety performance. Environmental laws and regulations have generally become more stringent over time, and the Company expects this trend to continue. Significant costs may be incurred for capital expenditures under environmental programs to keep the assets compliant with such environmental laws and regulations. If it is not economical to make those expenditures, it may be necessary to retire or mothball facilities or restrict or modify the Company's operations to comply with more stringent standards. These environmental requirements and liabilities could have a material adverse effect on the business, financial condition, results of operations and cash flows.
Risks that are beyond the Company's control, including but not limited to acts of terrorism or related acts of war, natural disaster, hostile cyber intrusions or other catastrophic events, could have a material adverse effect on the business, financial condition, results of operations and cash flows.
The Company's generation facilities that were acquired or those that the Company otherwise acquires or constructs and the facilities of third parties on which they rely may be targets of terrorist activities, as well as events occurring in response to or in connection with them, that could cause environmental repercussions and/or result in full or partial disruption of the facilities ability to generate, transmit, transport or distribute electricity or natural gas. Strategic targets, such as energy-related facilities, may be at greater risk of future terrorist activities than other domestic targets. Hostile cyber intrusions, including those targeting information systems as well as electronic control systems used at the generating plants and for the related distribution systems, could severely disrupt business operations and result in loss of service to customers, as well as create significant expense to repair security breaches or system damage.
Furthermore, certain of the Company's power generation thermal assets are located in active earthquake zones in California and Arizona, and certain project companies and suppliers conduct their operations in the same region or in other locations that are susceptible to natural disasters. In addition, California and some of the locations where certain suppliers are located, from time to time, have experienced shortages of water, electric power and natural gas. The occurrence of a natural disaster, such as an earthquake, drought, flood or localized extended outages of critical utilities or transportation systems, or any critical resource shortages, affecting the Company or its suppliers, could cause a significant interruption in the business, damage or destroy the Company's facilities or those of its suppliers or the manufacturing equipment or inventory of the Company's suppliers. Any such terrorist acts, environmental repercussions or disruptions or natural disasters could result in a significant decrease in revenues or significant reconstruction or remediation costs, beyond what could be recovered through insurance policies, which could have a material adverse effect on the business, financial condition, results of operations and cash flows.
Government regulations providing incentives for renewable generation could change at any time and such changes may negatively impact the Company's growth strategy.
The Company's growth strategy depends in part on government policies that support renewable generation and enhance the economic viability of owning renewable electric generation assets. Renewable generation assets currently benefit from various federal, state and local governmental incentives such as ITCs, cash grants in lieu of ITCs, loan guarantees, RPS, programs, modified accelerated cost-recovery system of depreciation and bonus depreciation. For example, the U.S. Internal Revenue Code of 1986, as amended, provides an ITC of 30% of the cost-basis of an eligible resource, including solar energy facilities placed in service prior to the end of 2016, which percentage is currently scheduled to be reduced to 10% for solar energy systems placed in service after December 31, 2016.
22
Many states have adopted RPS programs mandating that a specified percentage of electricity sales come from eligible sources of renewable energy. However, the regulations that govern the RPS programs, including pricing incentives for renewable energy, or reasonableness guidelines for pricing that increase valuation compared to conventional power (such as a projected value for carbon reduction or consideration of avoided integration costs), may change. If the RPS requirements are reduced or eliminated, it could lead to fewer future power contracts or lead to lower prices for the sale of power in future power contracts, which could have a material adverse effect on the Company's future growth prospects.
Such material adverse effects may result from decreased revenues, reduced economic returns on certain project company investments, increased financing costs, and/or difficulty obtaining financing. Furthermore, the ARRA included incentives to encourage investment in the renewable energy sector, such as cash grants in lieu of ITCs, bonus depreciation and expansion of the U.S. DOE loan guarantee program. It is uncertain what loan guarantees may be made by the U.S. DOE loan guarantee program in the future. In addition, the cash grant in lieu of ITCs program only applies to facilities that commenced construction prior to December 31, 2011, which commencement date may be determined in accordance with the safe harbor if more than 5% of the total cost of the eligible property was paid or incurred by December 31, 2011.
If the Company is unable to utilize various federal, state and local government incentives to acquire additional renewable assets in the future, or the terms of such incentives are revised in a manner that is less favorable to the Company, it may suffer a material adverse effect on the business, financial condition, results of operations and cash flows.
A significant reduction or elimination of government subsidies under the 1603 Cash Grant Program may have a material adverse effect on the Company's existing operations and may reduce the Company's cash available for distribution. The ARRA section 1603 Cash Grant Program provides a cash payment from the federal government in lieu of ITCs for eligible renewable generation sources for which construction commenced prior to December 31, 2011, which commencement date may be determined in accordance with the 5% safe harbor. The amount of the 1603 Cash Grant Proceeds received is based on an application filed with the U.S. Treasury Department after a facility has reached COD. The applications are reviewed by, and are subject to approval by, the U.S. Treasury Department. In addition, the U.S. Treasury Department has said that it may reduce the amount of an applicant's cash grant award in cases where project costs exceed certain per watt cost benchmarks or in cases where project costs exceed certain percentage thresholds. The amount of 1603 Cash Grant Proceeds that the Company actually receives may differ materially from the amount expected and/or may be received at a later time than expected. On March 1, 2013, the federal sequestration went into effect, and, as a result, 1603 Cash Grant Proceeds for approved applications through September 30, 2013 were subject to an 8.7% reduction and approved applications after September 30, 2013 were subject to a 7.2% reduction.
The Company has submitted applications for and has received the related 1603 Cash Grant Proceeds for Alpine, Blythe, CVSR, South Trent, Roadrunner, Avra Valley and certain Distributed Solar assets. In addition, NRG has submitted an application for cash grants for Borrego of $39 million.
The amount receivable by the Company was reduced to
$36 million
as a result of sequestration.
If the Company does not receive the expected 1603 Cash Grant Proceeds for Borrego, the related financing will have to be repaid by other means before distributions from Borrego are available to be part of the quarterly dividend to holders of the Company's Class A common stock. If the Company does not receive the expected 1603 Cash Grant Proceeds, or if such proceeds are materially reduced, its financial position could be materially adversely affected. Additionally, reductions in or eliminations or expirations of, the 1603 Cash Grant Program or the U.S. Treasury Department's rejection of the Company's application for cash grants could also have a material adverse effect on the Company’s business, financial condition, results of operations and cash flows and may reduce the cash available for distribution.
23
The Company relies on electric interconnection and transmission facilities that it does not own or control and that are subject to transmission constraints within a number of the Company's regions. If these facilities fail to provide the Company with adequate transmission capacity, it may be restricted in its ability to deliver electric power to its customers and may either incur additional costs or forego revenues.
The Company depends on electric interconnection and transmission facilities owned and operated by others to deliver the wholesale power it will sell from its electric generation assets to its customers. A failure or delay in the operation or development of these interconnection or transmission facilities or a significant increase in the cost of the development of such facilities could result in lost revenues. Such failures or delays could limit the amount of power the Company's operating facilities deliver or delay the completion of the Company's construction projects. Additionally, such failures, delays or increased costs could have a material adverse effect on the business, financial condition and results of operations. If a region's power transmission infrastructure is inadequate, the Company's recovery of wholesale costs and profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have a sufficient incentive to invest in expansion of transmission infrastructure. The Company also cannot predict whether interconnection and transmission facilities will be expanded in specific markets to accommodate competitive access to those markets. In addition, certain of the Company's operating facilities' generation of electricity may be curtailed without compensation due to transmission limitations or limitations on the electricity grid's ability to accommodate intermittent electricity generating sources, reducing the Company's revenues and impairing its ability to capitalize fully on a particular facility's generating potential. Such curtailments could have a material adverse effect on the business, financial condition, results of operations and cash flows. Furthermore, economic congestion on transmission networks in certain of the markets in which the Company operates may occur and the Company may be deemed responsible for congestion costs. If the Company were liable for such congestion costs, its financial results could be adversely affected.
The Company's costs, results of operations, financial condition and cash flows could be adversely impacted by the disruption of the fuel supplies necessary to generate power at its conventional and thermal power generation facilities.
Delivery of fossil fuels to fuel the Company's conventional and thermal generation facilities is dependent upon the infrastructure (including natural gas pipelines) available to serve each such generation facility as well as upon the continuing financial viability of contractual counterparties. As a result, the Company is subject to the risks of disruptions or curtailments in the production of power at these generation facilities if a counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure.
Risks Related to the Relationship with NRG
NRG is the Company's controlling stockholder and exercises substantial influence over the Company. The Company is highly dependent on NRG.
NRG owns all of the Company's outstanding Class B common stock. Each share of the Company's outstanding Class B common stock is entitled to one vote per share. As a result of its ownership of the Class B common stock, NRG owns 65.5% of the combined voting power of the Company's Class A and Class B common stock as of
December 31, 2013
. NRG has also expressed its intention to maintain a controlling interest in the Company. As a result of this ownership, NRG has a substantial influence on the Company's affairs and its voting power will constitute a large percentage of any quorum of the Company's stockholders voting on any matter requiring the approval of the Company's stockholders. Such matters include the election of directors, the adoption of amendments to the Company's amended and restated certificate of incorporation and bylaws and approval of mergers or sale of all or substantially all of its assets. This concentration of ownership may also have the effect of delaying or preventing a change in control of the Company or discouraging others from making tender offers for their shares. In addition, NRG will have the right to appoint all of the Company's directors. NRG may cause corporate actions to be taken even if their interests conflict with the interests of the Company's other stockholders (including holders of the Company's Class A common stock).
Furthermore, the Company depends on the management and administration services provided by or under the direction of NRG under the Management Services Agreement. NRG personnel and support staff that provide services to the Company under the Management Services Agreement are not required to, and the Company does not expect that they will, have as their primary responsibility the management and administration of the Company or to act exclusively for the Company and the Management Services Agreement does not require any specific individuals to be provided by NRG. Under the Management Services Agreement, NRG has the discretion to determine which of its employees perform assignments required to be provided to the Company. Any failure to effectively manage the Company's operations or to implement its strategy could have a material adverse effect on the business, financial condition, results of operations and cash flows. The Management Services Agreement will continue in perpetuity, until terminated in accordance with its terms.
24
The Company also depends upon NRG for the provision of management and administration services at all of the Company's facilities. Any failure by NRG to perform its requirements under these arrangements or the failure by the Company to identify and contract with replacement service providers, if required, could adversely affect the operation of the Company's facilities and have a material adverse effect on the business, financial condition, results of operations and cash flows.
The Company may not be able to consummate future acquisitions from NRG.
The Company's ability to grow through acquisitions depends, in part, on NRG's ability to identify and present the Company with acquisition opportunities. NRG established the Company to hold and acquire a diversified suite of power generating assets in the United States and its territories. Although NRG has agreed to grant the Company a right of first offer with respect to certain power generation assets that NRG may elect to sell in the future, NRG will be under no obligation to sell the NRG ROFO Assets or to accept any related offer from us. Furthermore, NRG has no obligation to source acquisition opportunities specifically for the Company. In addition, NRG has not agreed to commit any minimum level of dedicated resources for the pursuit of renewable power-related acquisitions. There are a number of factors which could materially and adversely impact the extent to which suitable acquisition opportunities are made available from NRG, including:
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the same professionals within NRG's organization that are involved in acquisitions that are suitable for the Company have responsibilities within NRG's broader asset management business, which may include sourcing acquisition opportunities for NRG. Limits on the availability of such individuals will likewise result in a limitation on the availability of acquisition opportunities for the Company; and
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in addition to structural limitations, the question of whether a particular asset is suitable is highly subjective and is dependent on a number of factors including an assessment by NRG relating to the Company's liquidity position at the time, the risk profile of the opportunity and its fit with the balance of the Company's then current operations and other factors. If NRG determines that an opportunity is not suitable for the Company, it may still pursue such opportunity on its own behalf, or on behalf of another NRG affiliate.
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In making these determinations, NRG may be influenced by factors that result in a misalignment or conflict of interest.
The departure of some or all of NRG's employees could prevent the Company from achieving its objectives.
The Company depends on the diligence, skill and business contacts of NRG's professionals and the information and opportunities they generate during the normal course of their activities. Furthermore, approximately 58.8% of NRG's employees at the Company generation plants are covered by collective bargaining agreements as of
December 31, 2013
. The Company's future success will depend on the continued service of these individuals, who are not obligated to remain employed with NRG, or otherwise successfully renegotiate their collective bargaining agreements when such agreements expire or otherwise terminate. NRG has experienced departures of key professionals and personnel in the past and may do so in the future, and the Company cannot predict the impact that any such departures will have on its ability to achieve its objectives. The departure of a significant number of NRG's professionals or a material portion of the NRG employees who work at any of the Company's facilities for any reason, or the failure to appoint qualified or effective successors in the event of such departures, could have a material adverse effect on the Company's ability to achieve its objectives. The Management Services Agreement does not require NRG to maintain the employment of any of its professionals or to cause any particular professional to provide services to the Company or on its behalf.
The Company's organizational and ownership structure may create significant conflicts of interest that may be resolved in a manner that is not in the best interests of the Company or the best interests of holders of its Class A common stock and that may have a material adverse effect on the business, financial condition, results of operations and cash flows.
The Company's organizational and ownership structure involves a number of relationships that may give rise to certain conflicts of interest between the Company and holders of its Class A common stock, on the one hand, and NRG, on the other hand. The Company has entered into a Management Services Agreement with NRG. Each of the Company's executive officers are a shared NRG executive and devote his or her time to both the Company and NRG as needed to conduct the respective businesses pursuant to the Management Services Agreement. Although the Company's directors and executive officers owe fiduciary duties to the Company's stockholders, these shared NRG executives have fiduciary and other duties to NRG, which duties may be inconsistent with the Company's best interests and holders of the Company's Class A common stock. In addition, NRG and its representatives, agents and affiliates have access to the Company's confidential information. Although some of these persons are subject to confidentiality obligations pursuant to confidentiality agreements or implied duties of confidence, the Management Services Agreement does not contain general confidentiality provisions.
25
Additionally, all of the Company's executive officers continue to have economic interests in NRG and, accordingly, the benefit to NRG from a transaction between the Company and NRG will proportionately inure to their benefit as holders of economic interests in NRG. NRG is a related party under the applicable securities laws governing related party transactions and may have interests which differ from the Company's interests or those of holders of the Class A common stock, including with respect to the types of acquisitions made, the timing and amount of dividends by the Company, the reinvestment of returns generated by the Company's operations, the use of leverage when making acquisitions and the appointment of outside advisors and service providers. Any material transaction between the Company and NRG will be subject to the Company's related party transaction policy, which will require prior approval of such transaction by the Company's corporate committees. Those of the Company's executive officers who have economic interests in NRG may be conflicted when advising the Company's corporate committees or otherwise participating in the negotiation or approval of such transactions. These executive officers have significant project- and industry-specific expertise that could prove beneficial to the Company's decision-making process and the absence of such strategic guidance could have a material adverse effect on the corporate committees' ability to evaluate any such transaction. Furthermore, the creation of corporate committees and the Company's related party transaction approval policy may not insulate the Company from derivative claims related to related party transactions and the conflicts of interest described in this risk factor. Regardless of the merits of such claims, the Company may be required to expend significant management time and financial resources in the defense thereof. Additionally, to the extent the Company fails to appropriately deal with any such conflicts, it could negatively impact the Company's reputation and ability to raise additional funds and the willingness of counterparties to do business with the Company, all of which could have a material adverse effect on the business, financial condition, results of operations and cash flows.
The Company may be unable or unwilling to terminate the Management Services Agreement.
The Management Services Agreement provides that the Company may terminate the agreement upon 30 days prior written notice to NRG upon the occurrence of any of the following: (i) NRG defaults in the performance or observance of any material term, condition or covenant contained therein in a manner that results in material harm to the Company and the default continues unremedied for a period of 30 days after written notice thereof is given to NRG; (ii) NRG engages in any act of fraud, misappropriation of funds or embezzlement that results in material harm to the Company; (iii) NRG is grossly negligent in the performance of its duties under the agreement and such negligence results in material harm to the Company; or (iv) upon the happening of certain events relating to the bankruptcy or insolvency of NRG. Furthermore, if the Company requests an amendment to the scope of services provided by NRG under the Management Services Agreement and is not able to agree with NRG as to a change to the service fee resulting from a change in the scope of services within 180 days of the request, the Company will be able terminate the agreement upon 30 days prior notice to NRG. The Company will not be able to terminate the agreement for any other reason, including if NRG experiences a change of control, and the agreement continues in perpetuity, until terminated in accordance with its terms. If NRG's performance does not meet the expectations of investors, and the Company is unable to terminate the Management Services Agreement, the market price of the Class A common stock could suffer.
If NRG terminates the Management Services Agreement or defaults in the performance of its obligations under the agreement the Company may be unable to contract with a substitute service provider on similar terms, or at all.
The Company relies on NRG to provide it with management services under the Management Services Agreement and will not have independent executive or senior management personnel. The Management Services Agreement provides that NRG may terminate the agreement upon 180 days prior written notice of termination to the Company if it defaults in the performance or observance of any material term, condition or covenant contained in the agreement in a manner that results in material harm and the default continues unremedied for a period of 30 days after written notice of the breach is given. If NRG terminates the Management Services Agreement or defaults in the performance of its obligations under the agreement, the Company may be unable to contract with a substitute service provider on similar terms or at all, and the costs of substituting service providers may be substantial. In addition, in light of NRG's familiarity with the Company's assets, a substitute service provider may not be able to provide the same level of service due to lack of pre-existing synergies. If the Company cannot locate a service provider that is able to provide substantially similar services as NRG does under the Management Services Agreement on similar terms, it would likely have a material adverse effect on the business, financial condition, results of operation and cash flows.
26
The liability of NRG is limited under the Company's arrangements with it and the Company has agreed to indemnify NRG against claims that it may face in connection with such arrangements, which may lead it to assume greater risks when making decisions relating to the Company than it otherwise would if acting solely for its own account.
Under the Management Services Agreement, NRG does not assume any responsibility other than to provide or arrange for the provision of the services described in the Management Services Agreement in good faith. In addition, under the Management Services Agreement, the liability of NRG and its affiliates will be limited to the fullest extent permitted by law to conduct involving bad faith, fraud, willful misconduct or gross negligence or, in the case of a criminal matter, action that was known to have been unlawful. In addition, the Company has agreed to indemnify NRG to the fullest extent permitted by law from and against any claims, liabilities, losses, damages, costs or expenses incurred by an indemnified person or threatened in connection with the Company's operations, investments and activities or in respect of or arising from the Management Services Agreement or the services provided by NRG, except to the extent that the claims, liabilities, losses, damages, costs or expenses are determined to have resulted from the conduct in respect of which such persons have liability as described above. These protections may result in NRG tolerating greater risks when making decisions than otherwise would be the case, including when determining whether to use leverage in connection with acquisitions. The indemnification arrangements to which NRG is a party may also give rise to legal claims for indemnification that are adverse to the Company and holders of its Class A common stock.
Risks Inherent in an Investment in the Company
The Company may not be able to continue paying comparable or growing cash dividends to holders of its Class A common stock in the future.
The amount of cash available for distribution principally depends upon the amount of cash the Company generates from its operations, which will fluctuate from quarter to quarter based on, among other things:
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•
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the level and timing of capital expenditures the Company makes;
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•
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the completion of ongoing construction activities on time and on budget;
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•
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the level of operating and general and administrative expenses, including reimbursements to NRG for services provided to the Company in accordance with the Management Services Agreement;
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•
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seasonal variations in revenues generated by the business;
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•
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debt service requirements and other liabilities;
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•
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fluctuations in working capital needs;
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•
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the Company's ability to borrow funds and access capital markets;
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•
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restrictions contained in the Company's debt agreements (including project-level financing and the Company's revolving credit facility); and
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•
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other business risks affecting cash levels.
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As a result of all these factors, the Company cannot guarantee that it will have sufficient cash generated from operations to pay a specific level of cash dividends to holders of its Class A common stock. Furthermore, holders of the Company's Class A common stock should be aware that the amount of cash available for distribution depends primarily on cash flow, and is not solely a function of profitability, which is affected by non-cash items. The Company may incur other expenses or liabilities during a period that could significantly reduce or eliminate its cash available for distribution and, in turn, impair its ability to pay dividends to holders of the Company's Class A common stock during the period. Because the Company is a holding company, its ability to pay dividends on the Company's Class A common stock is limited by restrictions on the ability of the Company's subsidiaries to pay dividends or make other distributions to the Company, including restrictions under the terms of the agreements governing project-level financing. The project-level financing agreements generally prohibit distributions from the project entities prior to COD and thereafter prohibit distributions to the Company unless certain specific conditions are met, including the satisfaction of financial ratios. The Company's revolving credit facility will also restrict the Company's ability to declare and pay dividends if an event of default has occurred and is continuing or if the payment of the dividend would result in an event of default.
NRG Yield LLC's cash available for distribution will likely fluctuate from quarter to quarter, in some cases significantly, due to seasonality. As result, the Company may cause NRG Yield LLC to reduce the amount of cash it distributes to its members in a particular quarter to establish reserves to fund distributions to its members in future periods for which the cash distributions the Company would otherwise receive from NRG Yield LLC would otherwise be insufficient to fund its quarterly dividend. If the Company fails to cause NRG Yield LLC to establish sufficient reserves, the Company may not be able to maintain its quarterly dividend with a respect to a quarter adversely affected by seasonality.
Finally, dividends to holders of the Company's Class A common stock will be paid at the discretion of the Company's board of directors. The Company's board of directors may decrease the level of or entirely discontinue payment of dividends.
27
The Company is a holding company and its only material asset is its interest in NRG Yield LLC, and the Company is accordingly dependent upon distributions from NRG Yield LLC and its subsidiaries to pay dividends and taxes and other expenses.
The Company is a holding company and has no material assets other than its ownership of membership interests in NRG Yield LLC, a holding company that has no material assets other than its interest in NRG Yield Operating LLC, whose sole material assets are the project companies. None of the Company, NRG Yield LLC or NRG Yield Operating LLC has any independent means of generating revenue. The Company intends to cause NRG Yield Operating LLC's subsidiaries to make distributions to NRG Yield Operating LLC and, in turn, make distributions to NRG Yield LLC, and, in turn, to make distributions to the Company in an amount sufficient to cover all applicable taxes payable and dividends, if any, declared by the Company. To the extent that the Company needs funds for a quarterly cash dividend to holders of the Company's Class A common stock or otherwise, and NRG Yield Operating LLC or NRG Yield LLC is restricted from making such distributions under applicable law or regulation or is otherwise unable to provide such funds (including as a result of NRG Yield Operating LLC's operating subsidiaries being unable to make distributions), it could materially adversely affect the Company's liquidity and financial condition and limit the Company's ability to pay dividends to holders of the Company's Class A common stock.
The Company has a limited operating history and as a result there is no assurance the Company can operate on a profitable basis.
The Company has a limited operating history on which to base an evaluation of its business and prospects. The Company's prospects must be considered in light of the risks, expenses and difficulties frequently encountered by companies in their early stages of operation. The Company cannot assure investors that it will be successful in addressing the risks the Company may encounter, and the Company's failure to do so could have a material adverse effect on its business, financial condition, results of operations and cash flows.
Market interest rates may have an effect on the value of the Company's Class A common stock.
One of the factors that will influence the price of shares of the Company's Class A common stock will be the effective dividend yield of such shares (i.e., the yield as a percentage of the then market price of the Company's shares) relative to market interest rates. An increase in market interest rates, which are currently at low levels relative to historical rates, may lead investors of shares of the Company's Class A common stock to expect a higher dividend yield and the Company's inability to increase its dividend as a result of an increase in borrowing costs, insufficient cash available for distribution or otherwise, could result in selling pressure on, and a decrease in the market price of the Company's Class A common stock as investors seek alternative investments with higher yield.
If the Company is deemed to be an investment company, the Company may be required to institute burdensome compliance requirements and the Company's activities may be restricted, which may make it difficult for the Company to complete strategic acquisitions or effect combinations.
If the Company is deemed to be an investment company under the Investment Company Act of 1940, or the Investment Company Act, the Company's business would be subject to applicable restrictions under the Investment Company Act, which could make it impracticable for the Company to continue its business as contemplated.
The Company believes its company is not an investment company under Section 3(b)(1) of the Investment Company Act because the Company is primarily engaged in a non-investment company business. The Company intends to conduct its operations so that the Company will not be deemed an investment company. However, if the Company were to be deemed an investment company, restrictions imposed by the Investment Company Act, including limitations on the Company's capital structure and the Company's ability to transact with affiliates, could make it impractical for the Company to continue its business as contemplated.
Market volatility may affect the price of the Company's Class A common stock.
The market price of the Company's Class A common stock may fluctuate significantly in response to a number of factors, most of which the Company cannot predict or control, including general market and economic conditions, disruptions, downgrades, credit events and perceived problems in the credit markets; actual or anticipated variations in its quarterly operating results or dividends; changes in the Company's investments or asset composition; write-downs or perceived credit or liquidity issues affecting the Company's assets; market perception of NRG, the Company's business and the Company's assets; the Company's level of indebtedness and/or adverse market reaction to any indebtedness the Company incur in the future; the Company's ability to raise capital on favorable terms or at all; loss of any major funding source; the termination of the Management Services Agreement or additions or departures of NRG's key personnel; changes in market valuations of similar power generation companies; and speculation in the press or investment community regarding the Company or NRG.
28
Securities markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. Any broad market fluctuations may adversely affect the trading price of the Company's Class A common stock.
The Company is a "controlled company," controlled by NRG, whose interest in the Company's business may be different from the holders of the Company's Class A common stock.
As of
December 31, 2013
, NRG controls 65.5% of the Company's combined voting power and is able to elect all of the Company's board of directors. As a result, the Company is considered a "controlled company" for the purposes of the NYSE listing requirements. As a "controlled company," the Company is permitted to, and the Company may, opt out of the NYSE listing requirements that would require (i) a majority of the members of the Company's board of directors to be independent, (ii) that the Company establish a compensation committee and a nominating and governance committee, each comprised entirely of independent directors, or (iii) that the compensation of the Company's executive officers and nominees for directors are determined or recommended to the Company's board of directors by the independent members of the Company's board of directors. The NYSE listing requirements are intended to ensure that directors who meet the independence standard are free of any conflicting interest that could influence their actions as directors.
Provisions of the Company's charter documents or Delaware law could delay or prevent an acquisition of the Company, even if the acquisition would be beneficial to holders of the Company's Class A common stock, and could make it more difficult to change management.
Provisions of the Company's amended and restated certificate of incorporation and bylaws may discourage, delay or prevent a merger, acquisition or other change in control that holders of the Company's Class A common stock may consider favorable, including transactions in which such stockholders might otherwise receive a premium for their shares. This is because these provisions may prevent or frustrate attempts by stockholders to replace or remove members of the Company's management. These provisions include:
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a prohibition on stockholder action through written consent;
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•
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a requirement that special meetings of stockholders be called upon a resolution approved by a majority of the Company's directors then in office;
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•
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advance notice requirements for stockholder proposals and nominations; and
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•
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the authority of the board of directors to issue preferred stock with such terms as the board of directors may determine.
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Section 203 of the DGCL prohibits a publicly held Delaware corporation from engaging in a business combination with an interested stockholder, generally a person that together with its affiliates owns or within the last three years has owned 15% of voting stock, for a period of three years after the date of the transaction in which the person became an interested stockholder, unless the business combination is approved in a prescribed manner.
Additionally, the Company's amended and restated certificate of incorporation prohibits any person and any of its associate or affiliate companies in the aggregate, public utility or holding company from acquiring, other than secondary market transactions, an amount of the Company's Class A common stock sufficient to result in a transfer of control without the prior written consent of the Company's board of directors. Any such change of control, in addition to prior approval from the Company's board of directors, would require prior authorization from FERC. Similar restrictions may apply to certain purchasers of the Company's securities which are holding companies regardless of whether the Company's securities are purchased in offerings by the Company or NRG, in open market transactions or otherwise. A purchaser of the Company's securities which is a holding company will need to determine whether a given purchase of the Company's securities may require prior FERC approval.
Investors may experience dilution of ownership interest due to the future issuance of additional shares of the Company's Class A common stock.
The Company is in a capital intensive business, and may not have sufficient funds to finance the growth of the Company's business, future acquisitions or to support the Company's projected capital expenditures. As a result, the Company may require additional funds from further equity or debt financings, including tax equity financing transactions or sales of preferred shares or convertible debt to complete future acquisitions, expansions and capital expenditures and pay the general and administrative costs of the Company's business. In the future, the Company may issue the Company's previously authorized and unissued securities, resulting in the dilution of the ownership interests of purchasers of the Company's Class A common stock offered hereby. Under the Company's amended and restated certificate of incorporation, the Company is authorized to issue 500,000,000 shares of Class A common stock, 500,000,000 shares of Class B common stock and 10,000,000 shares of preferred stock with preferences and rights as determined by the Company's board of directors. The potential issuance of additional shares of common stock or preferred stock or convertible debt may create downward pressure on the trading price of the Company's Class A common stock.
29
If securities or industry analysts do not publish or cease publishing research or reports about the Company, the Company's business or the Company's market, or if they adversely change their recommendations regarding the Company's Class A common stock adversely, the stock price and trading volume of the Company's Class A common stock could decline.
The trading market for the Company's Class A common stock is influenced by the research and reports that industry or securities analysts may publish about the Company, the Company's business, the Company's market or the Company's competitors. If any of the analysts who may cover the Company change their recommendation regarding the Company's Class A common stock adversely, or provide more favorable relative recommendations about the Company's competitors, the price of the Company's Class A common stock would likely decline. If any analyst who covers the Company were to cease coverage of the Company or fail to regularly publish reports on the Company, the Company could lose visibility in the financial markets, which in turn could cause the stock price or trading volume of the Company's Class A common stock to decline.
Future sales of the Company's common stock by NRG may cause the price of the Company's Class A common stock to fall.
The market price of the Company's Class A common stock could decline as a result of sales by NRG of such shares (issuable to NRG upon the exchange of some or all of its NRG Yield LLC Class B units) in the market, or the perception that these sales could occur. The market price of the Company's Class A common stock may also decline as a result of NRG disposing or transferring some or all of the Company's outstanding Class B common stock, which disposals or transfers would reduce NRG's ownership interest in, and voting control over the Company. These sales might also make it more difficult for the Company to sell equity securities at a time and price that the Company deem appropriate.
NRG and certain of its affiliates have certain demand and piggyback registration rights with respect to shares of the Company's Class A common stock issuable upon the exchange of NRG Yield LLC's Class B units. The presence of additional shares of the Company's Class A common stock trading in the public market, as a result of the exercise of such registration rights may have a material adverse effect on the market price of the Company's securities.
The Company is an "emerging growth company" and may elect to comply with reduced public company reporting requirements, which could make the Company's Class A common stock less attractive to investors.
The Company currently is an "emerging growth company," as defined by the JOBS Act. For as long as the Company continues to be an emerging growth company, the Company may choose to take advantage of exemptions from various public company reporting requirements. These exemptions include, but are not limited to, (i) not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, (ii) reduced disclosure obligations regarding executive compensation in the Company's periodic reports, proxy statements and registration statements, and (iii) exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. The Company could be an emerging growth company for up to five years after the first sale of the Company's common equity securities pursuant to an effective registration statement under the Securities Act, which such fifth anniversary will occur in July 2017. However, if certain events occur prior to the end of such five-year period, including if the Company becomes a "large accelerated filer," the Company's annual gross revenues exceed $1.0 billion or the Company issues more than $1.0 billion of non-convertible debt in any three-year period, the Company would cease to be an emerging growth company prior to the end of such five-year period. The Company intends to take advantage of certain of the reduced disclosure obligations regarding executive compensation and may elect to take advantage of other reduced burdens in future filings. As a result, the information that the Company provides to holders of the Company's Class A common stock may be different than you might receive from other public reporting companies in which they hold equity interests. The Company cannot predict if investors will find the Company's Class A common stock less attractive as a result of the Company's reliance on these exemptions. If some investors find the Company's Class A common stock less attractive as a result of any choice the Company makes to reduce disclosure, there may be a less active trading market for the Company's Class A common stock and the price for the Company's Class A common stock may be more volatile.
Under the JOBS Act, emerging growth companies can delay adopting new or revised accounting standards until such time as those standards apply to private companies. However, the Company has irrevocably elected not to avail itself of this extended transition period for complying with new or revised accounting standards and, therefore, the Company will be subject to the same new or revised accounting standards as other public companies that are not emerging growth companies.
30
Risks Related to Taxation
The Company's future tax liability may be greater than expected if the Company does not generate NOLs sufficient to offset taxable income.
The Company expects to generate NOLs and NOL carryforwards that it can utilize to offset future taxable income. Based on the Company's current portfolio of assets, which include renewable assets that benefit from an accelerated tax depreciation schedule, and subject to potential tax audits, which may result in income, sales, use or other tax obligations, the Company does not expect to pay significant federal income tax for a period of approximately ten years. While the Company expect these losses will be available to the Company as a future benefit, in the event that they are not generated as expected, successfully challenged by the IRS (in a tax audit or otherwise) or subject to future limitations as discussed below, the Company's ability to realize these benefits may be limited. A reduction in the Company's expected NOLs, a limitation on the Company's ability to the use such losses or future tax audits, may result in a material increase in the Company's estimated future income tax liability and may negatively impact the Company's liquidity and financial condition.
The Company's ability to use NOLs to offset future income may be limited.
The Company's ability to the use NOLs generated in the future could be substantially limited if the Company were to experience an "ownership change" as defined under Section 382 of the Code. In general, an "ownership change" would occur if the Company's "5-percent shareholders," as defined under Section 382 of the Code, collectively increased their ownership in the Company by more than 50 percentage points over a rolling three-year period. A corporation that experiences an ownership change will generally be subject to an annual limitation on the use of its pre-ownership change deferred tax assets equal to the equity value of the corporation immediately before the ownership change, multiplied by the long-term tax-exempt rate for the month in which the ownership change occurs. Future sales of the Company's Class A common stock by NRG, as well as future issuances by the Company, could contribute to a potential ownership change.
A valuation allowance may be required for the Company's deferred tax assets.
The Company's expected NOLs will be reflected as a deferred tax asset as they are generated until utilized to offset income. Valuation allowances may need to be maintained for deferred tax assets that the Company estimates are more likely than not to be unrealizable, based on available evidence at the time the estimate is made. Valuation allowances related to deferred tax assets can be affected by changes to tax laws, statutory tax rates and future taxable income levels and based on input from the Company's auditors, tax advisors or regulatory authorities. In the event that the Company were to determine that the Company would not be able to realize all or a portion of the Company's net deferred tax assets in the future, the Company would reduce such amounts through a charge to income tax expense in the period in which that determination was made, which could have a material adverse impact on the Company's financial condition and results of operations and the Company's ability to maintain profitability.
Distributions to holders of the Company's Class A common stock may be taxable as dividends.
It is difficult to predict whether the Company will generate earnings or profits as computed for federal income tax purposes in any given tax year. If the Company makes distributions from current or accumulated earnings and profits as computed for federal income tax purposes, such distributions will generally be taxable to holders of the Company's Class A common stock in the current period as ordinary dividend income for federal income tax purposes. Under current law, such dividends would be eligible for the lower tax rates applicable to qualified dividend income of non-corporate taxpayers. While the Company expects that a portion of its distributions to holders of the Company's Class A common stock may exceed the Company's current and accumulated earnings and profits as computed for federal income tax purposes and therefore constitute a non-taxable return of capital distribution to the extent of a stockholder's basis in the Company's Class A common stock, no assurance can be given that this will occur.
31
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Annual Report on Form 10-K of NRG Yield, Inc., or the Company, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. The words "believes," "projects," "anticipates," "plans," "expects," "intends," "estimates" and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause the Company's actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These factors, risks and uncertainties include the factors described under Item 1A —
Risk Factors
and the following:
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The Company's ability to maintain and grow its quarterly dividend;
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The Company's ability to successfully identify, evaluate and consummate acquisitions;
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Hazards customary to the power production industry and power generation operations such as fuel and electricity price volatility, unusual weather conditions, catastrophic weather-related or other damage to facilities, unscheduled generation outages, maintenance or repairs, unanticipated changes to fuel supply costs or availability due to higher demand, shortages, transportation problems or other developments, environmental incidents, or electric transmission or gas pipeline system constraints and the possibility that the Company may not have adequate insurance to cover losses as a result of such hazards;
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The Company's ability to operate its businesses efficiently, manage maintenance capital expenditures and costs effectively, and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations;
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Counterparties to the Company's offtake agreements willingness and ability to fulfill their obligations under such agreements;
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The Company's ability to enter into contracts to sell power and procure fuel on acceptable terms and prices as current offtake agreements expire;
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Government regulation, including compliance with regulatory requirements and changes in market rules, rates, tariffs and environmental laws;
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The Company's ability to receive anticipated cash grants with respect to certain renewable (wind and solar) assets;
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Operating and financial restrictions placed on the Company and its subsidiaries that are contained in the project-level debt facilities and other agreements of certain subsidiaries and project-level subsidiaries generally and in the NRG Yield Operating LLC revolving credit facility; and
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The Company's ability to borrow additional funds and access capital markets, as well as the Company's substantial indebtedness and the possibility that the Company may incur additional indebtedness going forward.
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Forward-looking statements speak only as of the date they were made, and the Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors that could cause the Company's actual results to differ materially from those contemplated in any forward-looking statements included in this Annual Report on Form 10-K should not be construed as exhaustive.
None.
32
Listed below are descriptions of NRG Yield, Inc.'s interests in facilities, operations and/or projects owned or leased as of
December 31, 2013
.
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Capacity
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|||||||||||||||||||
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Rated MW
|
Net MW
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Owner-ship
|
PPA Terms
|
||||||||||||||||
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Assets
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Location
|
Fuel
|
COD
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Counterparty
|
Expiration
|
||||||||||||||
|
Conventional
|
|||||||||||||||||||
|
GenConn Devon
|
Milford, CT
|
190
|
|
95
|
|
49.95
|
%
|
Natural gas/Oil
|
June 2010
|
CL&P
|
2040
|
||||||||
|
GenConn Middletown
|
Middletown, CT
|
190
|
|
95
|
|
49.95
|
%
|
Natural gas/Oil
|
June 2011
|
CL&P
|
2041
|
||||||||
|
Marsh Landing
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Antioch, CA
|
720
|
|
720
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100
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%
|
Natural gas
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May 2013
|
PG&E
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2023
|
||||||||
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Total Conventional
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1,100
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|
910
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|
|||||||||||||||
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Utility Scale Solar
|
|||||||||||||||||||
|
Blythe
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Blythe, CA
|
21
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|
21
|
|
100
|
%
|
Solar
|
December 2009
|
SCE
|
2029
|
||||||||
|
Roadrunner
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Santa Teresa, NM
|
20
|
|
20
|
|
100
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%
|
Solar
|
August 2011
|
El Paso Electric
|
2031
|
||||||||
|
Avenal
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Avenal, CA
|
45
|
|
23
|
|
49.95
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%
|
Solar
|
August 2011
|
PG&E
|
2031
|
||||||||
|
Avra Valley
|
Pima County, AZ
|
25
|
|
25
|
|
100
|
%
|
Solar
|
December 2012
|
Tucson Electric Power
|
2032
|
||||||||
|
Alpine
|
Lancaster, CA
|
66
|
|
66
|
|
100
|
%
|
Solar
|
January 2013
|
PG&E
|
2033
|
||||||||
|
Borrego
|
Borrego Springs, CA
|
26
|
|
26
|
|
100
|
%
|
Solar
|
February 2013
|
SDG&E
|
2038
|
||||||||
|
CVSR
|
San Luis Obispo, CA
|
250
|
|
122
|
|
48.95
|
%
|
Solar
|
October 2013
|
PG&E
|
2038
|
||||||||
|
Total Utility Scale Solar
|
453
|
|
303
|
|
|||||||||||||||
|
Thermal Generation
|
|||||||||||||||||||
|
Dover
|
Dover, DE
|
104
|
|
104
|
|
100
|
%
|
Natural Gas
|
June 2013
|
Power sold into PJM markets
|
|||||||||
|
Princeton Hospital
|
Princeton, NJ
|
5
|
|
5
|
|
100
|
%
|
Natural Gas
|
January 2012
|
Excess power sold into local grid
|
|||||||||
|
Paxton Creek Cogen
|
Harrisburg, PA
|
12
|
|
12
|
|
100
|
%
|
Natural Gas
|
November 1986
|
Power sold into PJM markets
|
|||||||||
|
Tucson Convention Center
|
Tucson, AZ
|
2
|
|
2
|
|
100
|
%
|
Natural Gas
|
January 2003
|
Excess power sold into local grid
|
|||||||||
|
Total Thermal Generation
|
123
|
|
123
|
|
|||||||||||||||
|
Distributed Solar
|
|||||||||||||||||||
|
AZ DG Solar Projects
|
AZ
|
5
|
|
5
|
|
100
|
%
|
Solar
|
December 2010 - January 2013
|
Various public entities
|
2025-2033
|
||||||||
|
PFMG DG Solar Projects
|
CA
|
9
|
|
5
|
|
51
|
%
|
Solar
|
October 2012 - December 2012
|
Various public entities
|
2032
|
||||||||
|
Total Distributed Solar
|
14
|
|
10
|
|
|||||||||||||||
|
Wind
|
|||||||||||||||||||
|
South Trent
|
Sweetwater, TX
|
101
|
|
101
|
|
100
|
%
|
Wind
|
January 2009
|
AEP Energy Partners
|
2029
|
||||||||
|
Total Wind
|
101
|
|
101
|
|
|||||||||||||||
|
Total NRG Yield, Inc.
|
1,791
|
|
1,447
|
|
|||||||||||||||
33
The following table summarizes the Company's thermal steam and chilled water facilities as of
December 31, 2013
:
|
Name and Location of Facility
|
% Owned
|
Thermal Energy Purchaser
|
Megawatt
Thermal Equivalent Capacity (MWt) |
Generating
Capacity |
|||||
|
NRG Energy Center Minneapolis, MN
|
100.0
|
Approx. 100 steam and 50 chilled water customers
|
334
141 |
|
Steam: 1,140 MMBtu/hr.
Chilled water: 40,200 tons |
||||
|
NRG Energy Center San Francisco, CA
|
100.0
|
Approx 175 steam customers
|
133
|
|
Steam: 454 MMBtu/hr.
|
||||
|
NRG Energy Center Omaha, NE
|
100.0
12.0 100.0
|
Approx 60 steam and 60 chilled water customers
|
142
9
77
|
|
Steam: 485 MMBtu/hr
Steam: 30 MMBtu/hr Chilled water: 22,000 tons |
||||
|
NRG Energy Center Harrisburg, PA
|
100.0
|
Approx 140 steam and 3 chilled water customers
|
129
12 |
|
Steam: 440 MMBtu/hr.
Chilled water: 3,600 tons |
||||
|
NRG Energy Center Phoenix, AZ
|
100.0
0%(a) |
Approx 35 chilled water customers
|
106
28 |
|
Chilled water: 30,100 tons
Chilled water: 8,000 tons |
||||
|
NRG Energy Center Pittsburgh, PA
|
100.0
|
Approx 25 steam and 25 chilled water customers
|
87
46 |
|
Steam: 296 MMBtu/hr.
Chilled water: 12,920 tons |
||||
|
NRG Energy Center San Diego, CA
|
100.0
|
Approx 20 chilled water customers
|
26
|
|
Chilled water: 7,425 tons
|
||||
|
NRG Energy Center Dover, DE
|
100.0
|
Kraft Foods Inc. and Procter & Gamble Company
|
66
|
|
Steam: 225 MMBtu/hr.
|
||||
|
NRG Energy Center Princeton, NJ
|
100.0
|
Princeton HealthCare System
|
21
17 |
|
Steam: 72 MMBtu/hr.
Chilled water: 4,700 tons |
||||
|
Total Generating Capacity (MWt)
|
1,374
|
|
|||||||
|
(a)
|
Capacity available under right-to-use provision of the Chilled Water Service Agreement.
|
None.
Not applicable.
34
Market Information and Holders
The Company's Class A common stock trades on the New York Stock Exchange under the symbol “NYLD.” The Company's Class B common stock is not publicly traded.
As of
February 26, 2014
, there was one holder of record of the Class A common stock and one holder of record of the Class B common stock.
The following table sets forth, for the period indicated, the high and low sales prices as well as the closing price of the Company's Class A common stock as reported by the New York Stock Exchange from July 17, 2013, the first day of trading following the Company's initial public offering announcement, through December 31, 2013. The initial public offering price of the Company's Class A common stock was $22.00 per share.
|
Common Stock Price
|
Fourth
Quarter
2013
|
Period from July 17 to September 30, 2013
|
|
|
High
|
$41.18
|
$31.26
|
|
|
Low
|
30.07
|
26.50
|
|
|
Closing
|
40.01
|
30.29
|
|
|
Dividends Per Common Share
|
$0.23
|
n/a
|
|
Dividends
On December 16, 2013, NRG Yield, Inc. paid a quarterly dividend on the Company's Class A and Class B common stock of $0.23 per share.
On January 30, 2014, NRG Yield, Inc. declared a quarterly dividend on the Company's Class A and Class B common stock of $0.33 per share payable on March 17, 2014 to shareholders of record as of March 3, 2014.
35
Stock Performance Graph
The performance graph below compares NRG Yield, Inc.'s cumulative total stockholder return on the Company's Class A common stock for the period from July 16, 2013 through
December 31, 2013
, with the cumulative total return of the Standard & Poor's 500 Composite Stock Price Index, or S&P 500, and the Philadelphia Utility Sector Index, or UTY.
The performance graph shown below is being furnished and compares each period assuming that $100 was invested on the initial public offering date in each of the Class A common stock of the Company, the stocks included in the S&P 500 and the stocks included in the UTY, and that all dividends were reinvested.
Comparison of Cumulative Total Return
|
July 16, 2013
|
December 31, 2013
|
||||||
|
NRG Yield, Inc.
|
$
|
100.00
|
|
$
|
183.04
|
|
|
|
S&P 500
|
100.00
|
|
111.36
|
|
|||
|
UTY
|
100.00
|
|
97.77
|
|
|||
36
The following table presents the Company's historical selected financial data. For all periods prior to the initial public offering, the data below reflects the Company's accounting predecessor, or NRG Yield, which were prepared on a ''carve-out'' basis from NRG and are intended to represent the financial results of the contracted renewable energy and conventional generation and thermal infrastructure assets in the United States that were acquired by NRG Yield LLC on July 22, 2013. For all periods subsequent to the initial public offering, the data below reflects the Company's consolidated financial results.
This historical data should be read in conjunction with the Consolidated Financial Statements and the related notes thereto in Item 15 and Item 7,
Management's Discussion and Analysis of Financial Condition and Results of Operations.
|
Fiscal year ended December 31,
|
|||||||||||||||
|
(In millions)
|
2013
|
2012
|
2011
|
2010
|
|||||||||||
|
Statement of Income Data:
|
|||||||||||||||
|
Operating Revenues:
|
|||||||||||||||
|
Total operating revenues
|
$
|
313
|
|
$
|
175
|
|
$
|
164
|
|
$
|
143
|
|
|||
|
Operating Costs and Expenses
|
|||||||||||||||
|
Cost of operations
|
127
|
|
112
|
|
108
|
|
102
|
|
|||||||
|
Depreciation and amortization
|
51
|
|
25
|
|
22
|
|
16
|
|
|||||||
|
General and administrative - affiliate
|
7
|
|
7
|
|
6
|
|
5
|
|
|||||||
|
Total operating costs and expenses
|
185
|
|
144
|
|
136
|
|
123
|
|
|||||||
|
Operating Income
|
128
|
|
31
|
|
28
|
|
20
|
|
|||||||
|
Other Income/(Expense)
|
|||||||||||||||
|
Equity in earnings of unconsolidated affiliates
|
22
|
|
19
|
|
13
|
|
1
|
|
|||||||
|
Other income, net
|
2
|
|
1
|
|
2
|
|
3
|
|
|||||||
|
Interest expense
|
(35
|
)
|
(28
|
)
|
(19
|
)
|
(13
|
)
|
|||||||
|
Total other expense
|
(11
|
)
|
(8
|
)
|
(4
|
)
|
(9
|
)
|
|||||||
|
Income Before Income Taxes
|
117
|
|
23
|
|
24
|
|
11
|
|
|||||||
|
Income tax expense
|
8
|
|
10
|
|
9
|
|
4
|
|
|||||||
|
Net income
|
$
|
109
|
|
$
|
13
|
|
$
|
15
|
|
$
|
7
|
|
|||
|
Other Financial Data:
|
|||||||||||||||
|
Capital expenditures
|
238
|
|
380
|
|
132
|
|
25
|
|
|||||||
|
Cash Flow Data:
|
|||||||||||||||
|
Net cash provided by (used in):
|
|||||||||||||||
|
Operating activities
|
$
|
141
|
|
$
|
58
|
|
$
|
33
|
|
$
|
36
|
|
|||
|
Investing activities
|
(388
|
)
|
(405
|
)
|
(219
|
)
|
(160
|
)
|
|||||||
|
Financing activities
|
261
|
|
345
|
|
180
|
|
136
|
|
|||||||
|
Balance Sheet Data (at period end):
|
|||||||||||||||
|
Cash and cash equivalents
|
$
|
36
|
|
$
|
22
|
|
$
|
24
|
|
$
|
30
|
|
|||
|
Property and equipment, net
|
1,541
|
|
1,598
|
|
526
|
|
421
|
|
|||||||
|
Total assets
|
2,313
|
|
1,964
|
|
874
|
|
676
|
|
|||||||
|
Total liabilities
|
1,302
|
|
1,124
|
|
487
|
|
483
|
|
|||||||
|
Total stockholders' equity
|
1,011
|
|
840
|
|
387
|
|
193
|
|
|||||||
37
The following discussion analyzes the Company's historical financial condition and results of operations. For all periods prior to the initial public offering, the discussion reflects the financial statements of the Company's accounting predecessor, or NRG Yield, which were prepared on a ''carve-out'' basis from NRG and are intended to represent the financial results of the contracted renewable energy and conventional generation and thermal infrastructure assets in the United States that were acquired by NRG Yield LLC on July 22, 2013. For all periods subsequent to the initial public offering, the discussion reflects the Company's consolidated financial results. As you read this discussion and analysis, refer to the Company's Consolidated Statements of Operations to this Form 10-K, which present the results of operations for the years ended
December 31, 2013
,
2012
and
2011
. Also refer to Item 1 — Business, which includes detailed discussions of various items impacting the Company's business, results of operations and financial condition.
The discussion and analysis below has been organized as follows:
|
•
|
Executive Summary, including a description of the business and significant events that are important to understanding the results of operations and financial condition;
|
|
•
|
Results of operations, including an explanation of significant differences between the periods in the specific line items of the consolidated statement of operations;
|
|
•
|
Financial condition addressing liquidity position, sources and uses of cash, capital resources and requirements, commitments, and off-balance sheet arrangements;
|
|
•
|
Known trends that may affect the Company’s results of operations and financial condition in the future; and
|
|
•
|
Critical accounting policies which are most important to both the portrayal of the Company's financial condition and results of operations, and which require management's most difficult, subjective or complex judgment.
|
38
Executive Summary
Introduction and Overview
NRG Yield, Inc. is a dividend growth-oriented company formed to serve as the primary vehicle through which NRG will own, operate and acquire contracted renewable and conventional generation and thermal infrastructure assets. The Company owns a diversified portfolio of contracted renewable and conventional generation and thermal infrastructure assets in the United States. The contracted generation portfolio includes
three
natural gas or dual-fired facilities,
eight
utility-scale solar and wind generation facilities and
two
portfolios of distributed solar facilities that collectively represent
1,324
net MW. Each of these assets sells substantially all of its output pursuant to long-term, fixed price offtake agreements to credit-worthy counterparties. The average remaining contract life, weighted by MWs, of these offtake agreements was approximately
16
years as of
December 31, 2013
. The Company also owns thermal infrastructure assets with an aggregate steam and chilled water capacity of
1,346
net MWt and electric generation capacity of
123
net MW. These thermal infrastructure assets provide steam, hot water and/or chilled water, and in some instances electricity, to commercial businesses, universities, hospitals and governmental units in
multiple
locations, principally through long-term contracts or pursuant to rates regulated by state utility commissions.
Government Incentives
Government incentives enhance the economic viability of the Company's operating assets by providing additional sources of funding for the construction of these assets. NRG has applied for and received cash grants in lieu of ITCs, pursuant to section 1603 of the ARRA, for assets that are currently operating including Blythe, South Trent, Roadrunner, Avra Valley and certain Distributed Solar assets. In addition, NRG has submitted applications for cash grants in lieu of ITCs for Alpine and Borrego of $
72 million
and $
39 million
, respectively. The amounts receivable by the Company for the Alpine and Borrego projects were subsequently reduced to $
66 million
and $
36 million
, respectively, as a result of automatic federal spending cuts in 2013 that have taken place pursuant to the Balanced Budget and Emergency Deficit Control Act of 1985 as amended, commonly known as sequestration. Cash grants are treated as a reduction to the book basis of the property, plant and equipment and reduce the related depreciation over the useful life of the asset.
In January 2014, the Company received from the U.S. Treasury Department $66 million in cash grants for Alpine.
One of the Company's equity method investments, CVSR, obtained a loan guarantee from the U.S. DOE in support of its borrowings from the Federal Financing Bank, or FFB, to fund the construction of the facility, and CVSR submitted applications for cash grants in lieu of ITCs of $414 million ($392 million net of sequestration). In connection with the CVSR financing, as of
December 31, 2013
, there was $
341 million
in outstanding DOE-guaranteed cash grant bridge loans on the project, of which $
166 million
was due on February 5, 2014, and the remaining amount was due on August 5, 2014. In January 2014, the U.S. Treasury Department awarded cash grants on the CVSR project of $307 million ($285 million net of sequestration), which is approximately 75% of the cash grant amount for which the Company had applied. The cash grant proceeds were used to pay the outstanding balance of the bridge loan due in February 2014 and the remaining amount was used to pay a portion of the outstanding balance on the bridge loan due in August 2014. The remaining balance of the bridge loan due in August 2014 was paid by SunPower. CVSR is evaluating the basis for the U.S. Treasury Department’s award and all of its options for recovering the amount by which the U.S. Treasury Department reduced the CVSR cash grant award.
If the full amount of the cash grant for Borrego is not received, as a result of review of the application or as a result of sequestration, net income will be reduced by the amount of the additional depreciation over the useful life of the assets, which is approximately 28 years, partially offset by less deferred tax expense.
Regulatory Matters
Details of regulatory matters are presented in Item 1,
Business — Regulatory Matters
. Some of this information relates to costs that may be material to the Company's financial results.
Significant Events During the
Twelve
Months Ended
December 31, 2013
During 2013, Alpine, Borrego, Marsh Landing and CVSR achieved COD. In addition, Borrego completed a financing arrangement with a group of lenders. See Item - 15,
Note 9
,
Long-term Debt
, for information related to these financing activities. The Company completed its initial public offering of its Class A common stock on July 22, 2013. See Item - 15,
Note 1
,
Nature of Business
, for information related to the initial public offering.
On December 31, 2013, NRG Energy Center Omaha Holdings, LLC, an indirect wholly owned subsidiary of NRG Yield LLC, acquired Energy Systems Company, or Energy Systems, an operator of steam and chilled thermal facilities that provides heating and cooling services to nonresidential customers in Omaha, Nebraska.
See Item - 15,
Note 3
,
Business Acquisitions
, for information related to the acquisition.
39
Significant Events During the
Twelve
Months Ended
December 31, 2012
During 2012, Alpine completed a financing arrangement with a group of lenders. See Item 15 -
Note 9
,
Long-term Debt
for information related to this financing activity.
Significant Events During the
Twelve
Months Ended December 31, 2011
In late 2011, Roadrunner reached COD and entered into the Roadrunner financing arrangement. Construction began on Alpine, Avra Valley and Borrego. On September 30, 2011, CVSR was acquired by NRG.
Basis of Presentation
For all periods prior to the Company's initial public offering, the accompanying combined financial statements represent the combination of the assets that NRG Yield LLC acquired and were prepared using NRG's historical basis in the assets and liabilities. For the purposes of the combined financial statements, the term "NRG Yield" represents the accounting predecessor, or the combination of the acquired businesses. For all periods subsequent to the initial public offering, the accompanying consolidated financial statements represent the consolidated results of NRG Yield, Inc., which consolidates NRG Yield LLC through its controlling interest.
Consolidated Results of Operations
2013
compared to
2012
The following table provides selected financial information:
|
|
Year ended December 31,
|
|||||||||
|
(In millions except otherwise noted)
|
2013
|
2012
|
Change %
|
|||||||
|
Operating Revenues
|
||||||||||
|
Total operating revenues
|
$
|
313
|
|
$
|
175
|
|
79
|
|
||
|
Operating Costs and Expenses
|
||||||||||
|
Cost of operations
|
127
|
|
112
|
|
13
|
|
||||
|
Depreciation and amortization
|
51
|
|
25
|
|
104
|
|
||||
|
General and administrative — affiliate
|
7
|
|
7
|
|
—
|
|
||||
|
Total operating costs and expenses
|
185
|
|
144
|
|
28
|
|
||||
|
Operating Income
|
128
|
|
31
|
|
313
|
|
||||
|
Other Income/(Expense)
|
|
|||||||||
|
Equity in earnings of unconsolidated affiliates
|
22
|
|
19
|
|
16
|
|
||||
|
Other income, net
|
2
|
|
1
|
|
100
|
|
||||
|
Interest expense
|
(35
|
)
|
(28
|
)
|
25
|
|
||||
|
Total other expense
|
(11
|
)
|
(8
|
)
|
38
|
|
||||
|
Income Before Income Taxes
|
117
|
|
23
|
|
409
|
|
||||
|
Income tax expense
|
8
|
|
10
|
|
(20
|
)
|
||||
|
Net Income
|
109
|
|
$
|
13
|
|
738
|
|
|||
|
Less: Predecessor income prior to initial public offering on July 22, 2013
|
54
|
|
||||||||
|
Net Income Subsequent to Initial Public Offering
|
55
|
|
||||||||
|
Less: Net income attributable to noncontrolling interest
|
42
|
|
|
|
||||||
|
Net Income Attributed to NRG Yield Inc. Subsequent to Initial Public Offering
|
$
|
13
|
|
|
|
|
||||
|
Year ended December 31,
|
|||||
|
Business metrics:
|
2013
(a)
|
2012
(a)
|
|||
|
Renewable MWh sold (in millions)
|
963
|
|
464
|
|
|
|
Thermal MWht sold (in thousands)
|
1,679
|
|
1,517
|
|
|
(a) Volumes sold reflect MWh for Renewables and MWht for Thermal and do not include MWh of 139 thousand and 88 thousand for thermal generation.
40
Management’s discussion of the results of operations for the year ended
December 31, 2013
and
2012
Operating Revenues
Operating revenues
increased
by
$138 million
during the
twelve
months ended
December 31, 2013
compared to the same period in
2012
:
|
Conventional
|
Renewables
|
Thermal
|
Total
|
||||||||||||
|
(In millions)
|
|||||||||||||||
|
Year ended December 31, 2013
|
$
|
82
|
|
$
|
79
|
|
$
|
152
|
|
$
|
313
|
|
|||
|
Year ended December 31, 2012
|
—
|
|
33
|
|
142
|
|
175
|
|
|||||||
The increase in operating revenues is due to:
|
Increase in Conventional Generation revenues as Marsh Landing reached commercial operations in 2013
|
$
|
82
|
|
|
Increase in Renewables revenue as Alpine, Avra Valley and Borrego reached commercial operations in late 2012 and early 2013
|
46
|
|
|
|
Increase in Thermal revenue due to repowering of Dover facilities in 2013 as well as full year of operation of the Princeton hospital
|
$
|
10
|
|
|
$
|
138
|
|
|
Operating Costs
Operating expense
increased
by
$15 million
during the year ended
December 31, 2013
compared
2012
, primarily due to an increase in operations and maintenance expense related to Marsh Landing, Alpine, Borrego and Avra Valley reaching commercial operations in late 2012 and 2013, as well as the repowering of the Dover facility completed in 2013.
Depreciation and Amortization
Depreciation and amortization
increased
by
$26 million
during the year ended
December 31, 2013
compared to
2012
, due primarily to additional depreciation for the projects that reached commercial operations in late 2012 and 2013.
Equity in Earnings of Unconsolidated Affiliates
Equity in earnings of unconsolidated affiliates
increased
by
$3 million
during the year ended
December 31, 2013
compared to
2012
, due primarily to CVSR reaching commercial operations in 2013.
Interest Expense
Interest expense
increased
by
$7 million
during the year ended
December 31, 2013
compared to
2012
, due primarily to the additional interest expense for the projects that reached commercial operations in late 2012 and 2013, offset in part by the recognition of an unrealized gain on the Alpine interest rate swap in the current year compared to an unrealized loss in the prior year.
Income Tax Expense
For the year ended
December 31, 2013
, the Company recorded income tax expense of
$8 million
on pretax income of
$117 million
. For the same period in
2012
, the Company recorded income tax expense of
$10 million
on pretax income of
$23 million
. For the year ended
December 31, 2013
, the overall effective tax rate was different than the statutory rate of 35% primarily due to taxable earnings allocated to NRG resulting from its 65.5% interest in NRG Yield LLC. For the same period in
2012
, the Company's overall effective tax rate was different than the statutory rate of 35% primarily due to the impact of state and local income taxes.
Noncontrolling Interest
Noncontrolling interest of
$42 million
represents NRG's 65.5% interest in NRG Yield LLC's net income during the period from July 22, 2013 through
December 31, 2013
.
41
Consolidated Results of Operations
2012
compared to
2011
The following table provides selected financial information:
|
|
Year ended December 31,
|
|||||||||
|
(In millions except otherwise noted)
|
2012
|
2011
|
Change %
|
|||||||
|
Operating Revenues
|
||||||||||
|
Total operating revenues
|
$
|
175
|
|
$
|
164
|
|
7
|
|
||
|
Operating Costs and Expenses
|
||||||||||
|
Cost of operations
|
112
|
|
108
|
|
4
|
|
||||
|
Depreciation and amortization
|
25
|
|
22
|
|
14
|
|
||||
|
General and administrative — affiliate
|
7
|
|
6
|
|
17
|
|
||||
|
Total operating costs and expenses
|
144
|
|
136
|
|
6
|
|
||||
|
Operating Income
|
31
|
|
28
|
|
11
|
|
||||
|
Other Income/(Expense)
|
||||||||||
|
Equity in earnings of unconsolidated affiliates
|
19
|
|
13
|
|
46
|
|
||||
|
Other income, net
|
1
|
|
2
|
|
(50
|
)
|
||||
|
Interest expense
|
(28
|
)
|
(19
|
)
|
47
|
|
||||
|
Total other expense
|
(8
|
)
|
(4
|
)
|
100
|
|
||||
|
Income Before Income Taxes
|
23
|
|
24
|
|
(4
|
)
|
||||
|
Income tax expense
|
10
|
|
9
|
|
11
|
|
||||
|
Net Income
|
$
|
13
|
|
$
|
15
|
|
(13
|
)
|
||
|
Year ended December 31,
|
|||||
|
Business metrics:
|
2012
(a)
|
2011
(a)
|
|||
|
Renewable MWh sold (in millions)
|
464
|
|
420
|
|
|
|
Thermal MWht sold (in thousands)
|
1,517
|
|
1,541
|
|
|
(a) Volumes sold reflect MWh for Renewables and MWht for Thermal and do not include MWh of 88 thousand and 100 thousand for thermal generation.
42
Management’s discussion of the results of operations for the year ended
December 31, 2012
, and
2011
Operating Revenues
Operating revenues
increased by
$11 million
, during the year ended
December 31, 2012
, compared to
2011
, due to:
|
Renewables
|
Thermal
|
Total
|
|||||||||
|
(In millions)
|
|||||||||||
|
Year ended December 31, 2012
|
$
|
33
|
|
$
|
142
|
|
$
|
175
|
|
||
|
Year ended December 31, 2011
|
26
|
|
138
|
|
164
|
|
|||||
The increase in operating revenues is due primarily to increased volume from the Roadrunner facility, which reached commercial operations in late 2011, and additional revenue from distributed solar projects, of which one AZ DG project and all of the PFMG DG projects commenced commercial operations in 2012.
Operating Costs
Operating expense increased by
$5 million
, during the year ended
December 31, 2012
compared to the same period in
2011
, primarily due to an increase in Renewables operating costs primarily due to an increase in operations and maintenance expense related to Roadrunner reaching commercial operations in 2011 as well as an increase in operations for the two distributed solar portfolios.
Depreciation and Amortization
Depreciation and amortization increased by
$3 million
during the year ended
December 31, 2012
compared to the same period in
2011
, due primarily to additional depreciation for solar projects that reached commercial operations in late 2011.
Equity in Earnings of Unconsolidated Affiliates
Equity in earnings of unconsolidated affiliates increased by
$6 million
during the year ended
December 31, 2012
compared to the same period in
2011
, as GenConn Middletown reached commercial operations in June 2011.
Interest Expense
Interest expense increased by
$9 million
during the year ended
December 31, 2012
compared to the same period in
2011
, due primarily to the recognition of the ineffective portion of the unrealized loss on the Alpine interest rate swap.
Income Tax Expense
For the year ended December 31, 2012, the Company recorded income tax expense of $10 million on pretax income of $23 million. For the same period in 2011, the Company recorded income tax expense of $9 million on pretax income of $24 million. For the year ended December 31, 2012 and 2011 the Company's overall effective tax rate was different than the statutory rate of 35% primarily due to the impact of state and local income taxes.
Liquidity and Capital Resources
The Company's principal liquidity requirements are to finance current operations, fund capital expenditures, including acquisitions from time to time, and to service debt. Historically, the Company's predecessor operations were financed as part of NRG's integrated operations and largely relied on internally generated cash flows as well as corporate and/or project-level borrowings to satisfy its capital expenditure requirements.
As a normal part of the Company's business, depending on market conditions, the Company will from time to time consider opportunities to repay, redeem, repurchase or refinance its indebtedness. Changes in the Company's operating plans, lower than anticipated sales, increased expenses, acquisitions or other events may cause the Company to seek additional debt or equity financing in future periods. There can be no guarantee that financing will be available on acceptable terms or at all. Debt financing, if available, could impose additional cash payment obligations and additional covenants and operating restrictions.
Liquidity Position
As of
December 31, 2013
and
December 31, 2012
, the Company's liquidity was approximately
$150 million
and
$42 million
, respectively, comprised of cash and restricted cash, and as of December 31, 2013, availability under the Company's revolving credit facility. The Company's various financing arrangements are described in Item 15 -
Note 9
,
Long-term Debt
.
43
Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance growth, operating and maintenance capital expenditures, to fund dividends to holders of the Company's Class A common stock and other liquidity commitments. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management.
Sources of Liquidity
The Company's principal sources of liquidity include cash on hand, cash generated from operations, borrowings under new and existing financing arrangements and the issuance of additional equity securities as appropriate given market conditions. As described in Item 15 -
Note 9
,
Long-term Debt
, the Company's financing arrangements consist mainly of the project-level financings for its various assets.
On July 22, 2013, the Company issued 22,511,250 shares of Class A common stock in an initial public offering at a price of $22 per share, which resulted in net proceeds of $468 million, net of underwriting discounts. The Company used $395 million to acquire Class A units of NRG Yield LLC from NRG. The remaining $73 million was used to acquire Class A units of NRG Yield LLC directly from NRG Yield LLC.
In connection with the initial public offering of the Company's Class A common stock, as further described in Item 15 -
Note 1
,
Nature of Business
, NRG Yield LLC and its direct wholly owned subsidiary, NRG Yield Operating LLC, entered into a senior secured revolving credit facility which provides a revolving line of credit of $60 million. The Company's revolving credit facility can be used for cash or for the issuance of letters of credit.
On February 11, 2014, the Company closed on its offering of
$300 million
aggregate principal amount of 3.50% Convertible Senior Notes, or Notes, due 2019.
T
he initial purchasers exercised their option to purchase an additional
$45 million
in aggregate principal amount of the NRG Yield Senior Notes. NRG Yield, Inc. expects to receive the related proceeds in early March. The Notes are convertible, under certain circumstances, into the Company’s common stock, cash or a combination thereof at an initial conversion price of $46.55 per Class A common share, which is equivalent to an initial conversion rate of approximately 21.4822 shares of Class A common stock per $1,000 principal amount of Notes. Interest on the Notes is payable semi-annually in arrears on February 1 and August 1 of each year, commencing on August 1, 2014.
Uses of Liquidity
The Company's requirements for liquidity and capital resources, other than for operating its facilities, are categorized as: (i) debt service obligations, as described more fully in Item 15 -
Note 9
,
Long-term Debt
; (ii) capital expenditures; and (iii) cash dividends to investors.
Debt Service Obligations
Principal payments on debt as of
December 31, 2013
, are due in the following periods:
|
Description
|
2014
|
2015
|
2016
|
2017
|
2018
|
Thereafter
|
Total
|
||||||||||||||||||||
|
(In millions)
|
|||||||||||||||||||||||||||
|
NRG Marsh Landing LLC, due 2017 and 2023
|
42
|
|
43
|
|
45
|
|
47
|
|
49
|
|
247
|
|
$
|
473
|
|
||||||||||||
|
NRG Solar Alpine LLC, due 2022
|
69
|
|
7
|
|
8
|
|
8
|
|
7
|
|
122
|
|
221
|
|
|||||||||||||
|
NRG Energy Center Minneapolis LLC, senior secured notes, due 2017 and 2025
|
7
|
|
12
|
|
12
|
|
13
|
|
8
|
|
75
|
|
127
|
|
|||||||||||||
|
NRG Solar Borrego I LLC, due 2024 and 2038
|
3
|
|
3
|
|
3
|
|
2
|
|
2
|
|
65
|
|
78
|
|
|||||||||||||
|
South Trent Wind LLC, due 2020
|
4
|
|
4
|
|
4
|
|
4
|
|
4
|
|
49
|
|
69
|
|
|||||||||||||
|
NRG Solar Avra Valley LLC, due 2031
|
3
|
|
3
|
|
3
|
|
3
|
|
3
|
|
48
|
|
63
|
|
|||||||||||||
|
NRG Roadrunner LLC, due 2031
|
2
|
|
2
|
|
2
|
|
3
|
|
3
|
|
32
|
|
44
|
|
|||||||||||||
|
NRG Solar Blythe LLC, due 2028
|
1
|
|
2
|
|
1
|
|
2
|
|
2
|
|
16
|
|
24
|
|
|||||||||||||
|
PFMG and related subsidiaries, due 2030
|
1
|
|
2
|
|
2
|
|
2
|
|
1
|
|
24
|
|
32
|
|
|||||||||||||
|
NRG Energy Center Princeton LLC, due 2017
|
1
|
|
—
|
|
1
|
|
—
|
|
—
|
|
—
|
|
2
|
|
|||||||||||||
|
Total debt
|
$
|
133
|
|
$
|
78
|
|
$
|
81
|
|
|
$
|
84
|
|
|
$
|
79
|
|
|
$
|
678
|
|
|
$
|
1,133
|
|
||
44
Capital Expenditures
The Company's capital spending program is focused on completing the construction of assets where construction is in process and maintaining the assets currently operating. The Company develops annual capital spending plans based on projected requirements for maintenance capital and completion of facilities under construction. For the years ended
December 31, 2013
,
2012
and
2011
, the Company used approximately
$238 million
,
$380 million
, and
$132 million
, respectively, to fund capital expenditures, primarily related to the construction of its solar generating assets and Marsh Landing.
Acquisitions
The Company intends to acquire generation assets developed and constructed by NRG in the future, as well as generation and thermal infrastructure assets from third parties where the Company believes its knowledge of the market, operating expertise and access to capital provides a competitive advantage, and to utilize such acquisitions as a means to grow its cash available for distribution.
On December 31, 2013, the Company completed its acquisition of Energy Systems Company, a thermal district energy supplier in Omaha, Nebraska, for approximately $120 million in cash. Energy Systems is an operator of steam and chilled water thermal facilities that provide heating and cooling services to nonresidential customers in Omaha, Nebraska. The acquisition was recorded as a business combination under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The purchase price was primarily allocated to property, plant and equipment of
$60 million
, customer relationships of
$59 million
, and
$1 million
of working capital.
Cash Dividends to Investors
The Company intends to use the amount of cash that it receives from its distributions from NRG Yield LLC to pay quarterly dividends to the holders of its Class A common stock. NRG Yield LLC intends to distribute to its unit holders in the form of a quarterly distribution all of the cash available for distribution that is generated each quarter less reserves for the prudent conduct of the business, including among others, maintenance capital expenditures to maintain the operating capacity of the assets. Cash available for distribution is defined as earnings before income taxes, depreciation and amortization, excluding contract amortization, cash interest paid, income taxes paid, maintenance capital expenditures, investments in unconsolidated affiliates, growth capital expenditures, net of capital and debt funding, and principal amortization of indebtedness, and including cash distributions from unconsolidated affiliates.
The Company declared a pro-rated initial dividend of $0.23 per common share on October 31, 2013, and paid the dividend on Class A and Class B common stock
on December 16, 2013, to shareholders of record as of December 2, 2013.
On January 30, 2014, the Company declared a quarterly dividend on its Class A and Class B common stock of $0.33 per share payable on March 17, 2014 to shareholders of record as of March 3, 2014.
The common stock dividend is subject to available capital, market conditions, and compliance with associated laws and regulations.
45
Cash Flow Discussion
Year Ended December 31, 2013 Compared to Year Ended December 31, 2012
The following table reflects the changes in cash flows for the year ended
December 31, 2013
compared to
2012
:
|
Year ended December 31,
|
2013
|
2012
|
Change
|
||||||||
|
(In millions)
|
|||||||||||
|
Net cash provided by operating activities
|
$
|
141
|
|
$
|
58
|
|
$
|
83
|
|
||
|
Net cash used by investing activities
|
(388
|
)
|
(405
|
)
|
17
|
|
|||||
|
Net cash provided by financing activities
|
261
|
|
345
|
|
(84
|
)
|
|||||
Net Cash Provided By Operating Activities
|
Changes to net cash provided by operating activities were driven by:
|
|||
|
Increase in operating income due to Borrego, Avra Valley, Alpine and Marsh Landing being placed in service in late 2012 or 2013 adjusted for non-cash charges
|
$
|
100
|
|
|
Higher net distributions from unconsolidated affiliates for the period ending December 31, 2013 compared to the same period in 2012
|
(8
|
)
|
|
|
Increased working capital requirements due to assets placed in service in late 2012 and 2013
|
(9
|
)
|
|
|
$
|
83
|
|
|
Net Cash Used By Investing Activities
|
Changes to net cash used by investing activities were driven by:
|
|||
|
Decrease in capital expenditures for Borrego, Avra Valley and Alpine as the assets were placed in service in late 2012 or 2013
|
$
|
142
|
|
|
Acquisition of Energy Systems in December 2013
|
(120
|
)
|
|
|
Increase in restricted cash, primarily for Marsh Landing
|
(22
|
)
|
|
|
Increase in investments in unconsolidated affiliates
|
(7
|
)
|
|
|
Decrease in notes receivable
|
27
|
|
|
|
Decrease in proceeds from renewable grants
|
(3
|
)
|
|
|
$
|
17
|
|
|
Net Cash Provided By Financing Activities
|
Changes in net cash provided by financing activities were driven by:
|
|||
|
Increase in dividends and returns of capital to NRG, net of change in cash contributions from NRG
|
$
|
(819
|
)
|
|
Proceeds from the issuance of Class A common stock
|
468
|
|
|
|
Net increase in cash received from proceeds for issuance of long-term debt, net of payments
|
275
|
|
|
|
Dividends to Class A and Class B common shareholders in 2013
|
(15
|
)
|
|
|
Decrease in cash paid for deferred financing costs
|
7
|
|
|
|
$
|
(84
|
)
|
|
46
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
The following table reflects the changes in cash flows for the year ended
December 31, 2012
compared to
2011
:
|
Year ended December 31,
|
2012
|
2011
|
Change
|
||||||||
|
(In millions)
|
|||||||||||
|
Net cash provided by operating activities
|
$
|
58
|
|
$
|
33
|
|
$
|
25
|
|
||
|
Net cash used by investing activities
|
(405
|
)
|
(219
|
)
|
(186
|
)
|
|||||
|
Net cash provided by financing activities
|
345
|
|
180
|
|
165
|
|
|||||
Net Cash Provided By Operating Activities
Increase in net cash provided by operating activities was primarily driven by a reduction in affiliate balance for Thermal, as well as by cash dividends received from the Company's investment in GenConn, as Middletown reached commercial operations in June of 2011.
Net Cash Used By Investing Activities
|
Changes to net cash used by investing activities were driven by:
|
|||
|
Increase in capital expenditures, primarily for construction activities at Alpine, Borrego and Avra Valley
|
$
|
(248
|
)
|
|
Increase in notes receivable, primarily for reimbursable network upgrades for Alpine and Borrego
|
(21
|
)
|
|
|
Proceeds from renewable energy grants
|
28
|
|
|
|
Change in restricted cash
|
(8
|
)
|
|
|
Decrease in investments in unconsolidated affiliates
|
61
|
|
|
|
Other
|
2
|
|
|
|
$
|
(186
|
)
|
|
Net Cash Provided By Financing Activities
|
Changes in net cash provided by financing activities were driven by:
|
|||
|
Net increase in cash received from proceeds for the issuance of long-term debt, net of payments
|
$
|
91
|
|
|
Increase in capital contributions from NRG
|
137
|
|
|
|
Increase in dividends and returns of capital paid to NRG
|
(54
|
)
|
|
|
Increase in cash paid for deferred financing costs
|
(9
|
)
|
|
|
$
|
165
|
|
|
NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740
The Company has no tax effected uncertain tax benefits. As of
December 31, 2013
, the Company has generated NOL carryforwards of $173 million for financial statement purposes and does not anticipate any federal income tax payments for
2014
. As a result of the Company's tax position, and based on current forecasts, the Company does not anticipate significant income tax payments for state and local jurisdictions in
2014
.
47
Off-Balance Sheet Arrangements
Obligations under Certain Guarantee Contracts
The Company may enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties.
Retained or Contingent Interests
The Company does not have any material retained or contingent interests in assets transferred to an unconsolidated entity.
Obligations Arising Out of a Variable Interest in an Unconsolidated Entity
Variable interest in equity investments
— As of
December 31, 2013
, the Company has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method. One of these investments is a variable interest entity for which the Company is not the primary beneficiary.
The Company's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately
$715 million
as of
December 31, 2013
. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to the Company. See also Item 15 -
Note 5
,
Investments Accounted for by the Equity Method and Variable Interest Entities
.
Contractual Obligations and Commercial Commitments
The Company has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to the Company's capital expenditure programs. The following table summarizes the Company's contractual obligations. See Item 15 -
Note 9
,
Long-Term
Debt
and Item 15 -
Note 15
,
Commitments and Contingencies
, to the Company's audited financial statements for additional discussion.
|
|
By Remaining Maturity at December 31,
|
||||||||||||||||||||||
|
|
2013
|
|
|||||||||||||||||||||
|
Contractual Cash Obligations
|
Under
1 Year
|
1-3 Years
|
3-5 Years
|
Over
5 Years
|
Total
|
2012
|
|||||||||||||||||
|
|
(In millions)
|
||||||||||||||||||||||
|
Long-term debt (including estimated interest)
|
$
|
196
|
|
$
|
272
|
|
$
|
259
|
|
$
|
848
|
|
$
|
1,575
|
|
$
|
1,186
|
|
|||||
|
Operating leases
|
2
|
|
4
|
|
3
|
|
9
|
|
18
|
|
18
|
|
|||||||||||
|
Fuel purchase and transportation obligations
|
16
|
|
7
|
|
6
|
|
26
|
|
55
|
|
14
|
|
|||||||||||
|
Other liabilities
|
3
|
|
6
|
|
5
|
|
11
|
|
25
|
|
7
|
|
|||||||||||
|
Total
|
$
|
217
|
|
$
|
289
|
|
$
|
273
|
|
$
|
894
|
|
$
|
1,673
|
|
$
|
1,225
|
|
|||||
Fair Value of Derivative Instruments
The Company may enter into long-term fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at certain generation facilities. In addition, in order to mitigate interest rate risk associated with the issuance of variable rate and fixed rate debt, the Company enters into interest rate swap agreements.
The tables below disclose the activities that include non-exchange traded contracts accounted for at fair value in accordance with ASC 820. Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values at
December 31, 2013
, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at
December 31, 2013
. For a full discussion of the Company's valuation methodology of its contracts, see
Derivative Fair Value Measurements
in Item 15 -
Note 6
,
Fair Value of Financial Instruments
.
|
Derivative Activity Gains/(Losses)
|
(In millions)
|
||
|
Fair value of contracts as of December 31, 2012
|
$
|
(80
|
)
|
|
Contracts realized or otherwise settled during the period
|
20
|
|
|
|
Changes in fair value
|
33
|
|
|
|
Fair value of contracts as of December 31, 2013
|
$
|
(27
|
)
|
48
|
Fair Value of Contracts as of December 31, 2013
|
|||||||||||||||||||
|
Maturity
|
|||||||||||||||||||
|
Fair value hierarchy Gains/(Losses)
|
1 Year or Less
|
Greater Than 1 Year to 3 Years
|
Greater Than 3 Years to 5 Years
|
Greater Than 5 Years
|
Total Fair
Value
|
||||||||||||||
|
(In millions)
|
|||||||||||||||||||
|
Level 2
|
$
|
(21
|
)
|
$
|
(27
|
)
|
$
|
—
|
|
$
|
22
|
|
$
|
(26
|
)
|
||||
|
Level 3
|
(1
|
)
|
—
|
|
—
|
|
—
|
|
(1
|
)
|
|||||||||
|
Total
|
$
|
(22
|
)
|
$
|
(27
|
)
|
$
|
—
|
|
$
|
22
|
|
$
|
(27
|
)
|
||||
The Company has elected to disclose derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. As discussed below in
Quantitative and Qualitative Disclosures about Market Risk -Commodity Price Risk,
the
Company measures the sensitivity of the portfolio to potential changes in market prices using VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. The Company's risk management policy places a limit on one-day holding period VaR, which limits the net open position.
Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase or decrease in natural gas prices across the term of the derivative contracts would cause a change of approximately $1 million in the net value of derivatives as of December 31, 2013.
Critical Accounting Policies and Estimates
The Company's discussion and analysis of the financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with U.S. GAAP. The preparation of these financial statements and related disclosures in compliance with U.S. GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and the fair value of certain assets and liabilities. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies has not changed.
On an ongoing basis, the Company evaluates these estimates, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any event, actual results may differ substantially from the Company's estimates. Any effects on the Company's business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the information that gives rise to the revision becomes known.
The Company's significant accounting policies are summarized in Item 15 -
Note 2
,
Summary of Significant Accounting Policies
. The Company identifies its most critical accounting policies as those that are the most pervasive and important to the portrayal of the Company's financial position and results of operations, and that require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain. The Company's critical accounting policies include derivative instruments, income taxes and valuation allowance for deferred tax assets, impairment of long lived assets and other intangible assets, and contingencies.
49
|
Accounting Policy
|
Judgments/Uncertainties Affecting Application
|
|
Derivative Instruments
|
Assumptions used in valuation techniques
|
|
Market maturity and economic conditions
|
|
|
Contract interpretation
|
|
|
Market conditions in the energy industry, especially the effects of price volatility on contractual commitments
|
|
|
Income Taxes and Valuation Allowance for Deferred Tax Assets
|
Ability to withstand legal challenges of tax authority decisions or appeals
|
|
Anticipated future decisions of tax authorities
|
|
|
Application of tax statutes and regulations to transactions
|
|
|
Ability to utilize tax benefits through carry backs to prior periods and carry forwards to future periods
|
|
|
Impairment of Long Lived Assets
|
Recoverability of investment through future operations
|
|
Regulatory and political environments and requirements
|
|
|
Estimated useful lives of assets
|
|
|
Environmental obligations and operational limitations
|
|
|
Estimates of future cash flows
|
|
|
Estimates of fair value
|
|
|
Judgment about triggering events
|
|
|
Contingencies
|
Estimated financial impact of event(s)
|
|
Judgment about likelihood of event(s) occurring
|
|
|
Regulatory and political environments and requirements
|
|
Derivative Instruments
The Company follows the guidance of ASC 815 to account for derivative instruments. ASC 815 requires the Company to mark-to-market all derivative instruments on its balance sheet, and recognize changes in the fair value of non-hedge derivative instruments immediately in earnings. In certain cases, the Company may apply hedge accounting to derivative instruments. The criteria used to determine if hedge accounting treatment is appropriate are: (i) the designation of the hedge to an underlying exposure; (ii) whether the overall risk is being reduced; and (iii) if there is a correlation between the changes in fair value of the derivative instrument and the underlying hedged item. Changes in the fair value of derivatives instruments accounted for as hedges are either recognized in earnings as an offset to the changes in the fair value of the related hedged item, or deferred and recorded as a component of Other Comprehensive Income, or OCI, and subsequently recognized in earnings when the hedged transactions occur.
For purposes of measuring the fair value of derivative instruments, the Company uses quoted exchange prices and broker quotes. When external prices are not available, the Company uses internal models to determine the fair value. These internal models include assumptions of the future prices of energy commodities based on the specific market in which the energy commodity is being purchased or sold, using externally available forward market pricing curves for all periods possible under the pricing model. In order to qualify derivative instruments for hedged transactions, the Company estimates the forecasted borrowings for interest rate swaps occurring within a specified time period. Judgments related to the probability of forecasted borrowings are based on the estimated timing of project construction, which can vary based on various factors. The probability that hedged forecasted borrowings will occur by the end of a specified time period could change the results of operations by requiring amounts currently classified in OCI to be reclassified into earnings, creating increased variability in the Company's earnings. These estimations are considered to be critical accounting estimates.
50
Income Taxes and Valuation Allowance for Deferred Tax Assets
In assessing the recoverability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is primarily dependent upon earnings in various jurisdictions.
The Company's operating companies, as former subsidiaries of NRG, continue to be under audit for multiple years by taxing authorities in other jurisdictions. Considerable judgment is required to determine the tax treatment of a particular item that involves interpretations of complex tax laws. The project-level entities, as former subsidiaries of NRG, are subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and local jurisdictions. NRG is no longer subject to U.S. federal income tax examinations for years prior to 2007. With few exceptions, state and local income tax examinations are no longer open for years before 2007.
Evaluation of Assets for Impairment and Other Than Temporary Decline in Value
In accordance with ASC 360,
Property, Plant, and Equipment
, or ASC 360, property, plant and equipment and certain intangible assets are evaluated for impairment whenever indicators of impairment exist. Examples of such indicators or events are:
|
•
|
Significant decrease in the market price of a long-lived asset;
|
|
•
|
Significant adverse change in the manner an asset is being used or its physical condition;
|
|
•
|
Adverse business climate;
|
|
•
|
Accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset;
|
|
•
|
Current-period loss combined with a history of losses or the projection of future losses; and
|
|
•
|
Change in the Company's intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold or disposed of before the end of its previously estimated useful life.
|
Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to the future net cash flows expected to be generated by the asset, through considering project specific assumptions for long-term power pool prices, escalated future project operating costs and expected plant operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets by factoring in the probability weighting of different courses of action available to us. Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. The Company uses its best estimates in making these evaluations and considers various factors, including forward price curves for energy, fuel costs and operating costs. However, actual future market prices and project costs could vary from the assumptions used in the Company's estimates, and the impact of such variations could be material.
The Company is also required to evaluate its equity method investments to determine whether or not they are impaired. ASC 323,
Investments - Equity Method and Joint Ventures
, or ASC 323, provides the accounting requirements for these investments. The standard for determining whether an impairment must be recorded under ASC 323 is whether the value is considered an "other than a temporary" decline in value. The evaluation and measurement of impairments under ASC 323 involves the same uncertainties as described for long-lived assets that the Company owns directly and accounts for in accordance with ASC 360. Similarly, the estimates that the Company makes with respect to its equity method investments are subjective, and the impact of variations in these estimates could be material. Additionally, if the projects in which the Company holds these investments recognize an impairment under the provisions of ASC 360, the Company would record its proportionate share of that impairment loss and would evaluate its investment for an other than temporary decline in value under ASC 323.
Recent Accounting Developments
See Item 15 -
Note 2
,
Summary of Significant Accounting Policies
, to the audited financial statements for a discussion of recent accounting developments.
51
The Company is exposed to several market risks in its normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's power generation or with an existing or forecasted financial or commodity transaction. The types of market risks we are exposed to are commodity price risk, interest rate risk, liquidity risk, and credit risk.
Commodity Price Risk
Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities, and correlations between various commodities, such as natural gas and power. The Company manages the commodity price risk of its merchant generation operations by entering into derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted purchases of fuel. The portion of forecasted transactions hedged may vary based upon management's assessment of market, weather, operation and other factors.
Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase or decrease in natural gas prices across the term of the derivative contracts would cause a change of approximately
$1 million
in the net value of derivatives as of
December 31, 2013
.
Interest Rate Risk
The Company is exposed to fluctuations in interest rates through its issuance of variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. The Company's risk management policies allow it to reduce interest rate exposure from variable rate debt obligations.
Most of the Company's project subsidiaries enter into interest rate swaps, intended to hedge the risks associated with interest rates on non-recourse project level debt. See Item 15 —
Note 9
,
Long-term Debt
, for more information about interest rate swaps of the Company's project subsidiaries.
If all of the above swaps had been discontinued on
December 31, 2013
, the Company would have owed the counterparties
$27 million
. Based on the investment grade rating of the counterparties, the Company believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant.
The Company has long-term debt instruments that subject it to the risk of loss associated with movements in market interest rates. As of
December 31, 2013
, a 1% change in interest rates would result in an approximately
$1 million
change in interest expense on a rolling twelve month basis.
As of
December 31, 2013
, the fair value of the Company's debt was
$1,135 million
and the carrying value was
$1,133 million
. The Company estimates that a 1% decrease in market interest rates would have increased the fair value of its long-term debt by
$80 million
.
Liquidity Risk
Liquidity risk arises from the general funding needs of the Company's activities and in the management of the Company's assets and liabilities.
Counterparty Credit Risk
Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process, and (ii) the use of credit mitigation measures such as prepayment arrangements or volumetric limits. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk by having a diversified portfolio of counterparties.
The financial statements and schedules are listed in Part IV, Item 15 of this Form 10-K.
52
None.
Conclusion Regarding the Effectiveness of Disclosure Controls
and
Procedures
Under the supervision and with the participation of the Company's management, including its principal executive officer, principal financial officer and principal accounting officer, the Company conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures, as such term is defined in Rules 13a-15(e) or 15d-15(e) of the Exchange Act. Based on this evaluation, the Company's principal executive officer, principal financial officer and principal accounting officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this report on Form 10-K.
Changes in Internal Control over Financial Reporting
There were no changes in the Company’s internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the fourth quarter of 2013 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Management's Report on Internal Control over Financial Reporting
This annual report does not include a report of management's assessment regarding internal control over financial reporting or an attestation report of the Company's registered public accounting firm due to a transition period established by rules of the Securities and Exchange Commission for newly public companies.
None.
53
Directors
Kirkland B. Andrews
has served as Executive Vice President, Chief Financial Officer and Director since the Company's formation in December 2012. Mr. Andrews has served as Executive Vice President and Chief Financial Officer of NRG Energy since September 2011. Prior to joining NRG, he served as Managing Director and Co-Head Investment Banking, Power and Utilities—Americas at Deutsche Bank Securities from June 2009 to September 2011. Prior to this, he served in several capacities at Citigroup Global Markets Inc., including Managing Director, Group Head, North American Power from November 2007 to June 2009, and Head of Power M&A, Mergers and Acquisitions from July 2005 to November 2007. In his banking career, Mr. Andrews led multiple large and innovative strategic, debt, equity and commodities transactions. Mr. Andrews’ extensive investment banking experience, specifically in the energy industry and financial structuring, brings important experience and skills to the Company’s board of directors.
John F. Chlebowski
has served as a Director since July 2013.
Mr. Chlebowski had been a director of NRG from December 2003 to July 2013. Mr. Chlebowski served as the President and Chief Executive Officer of Lakeshore Operating Partners, LLC, a bulk liquid distribution firm, from March 2000 until his retirement in December 2004. From July 1999 until March 2000, Mr. Chlebowski was a senior executive and cofounder of Lakeshore Liquids Operating Partners, LLC, a private venture firm in the bulk liquid distribution and logistics business, and from January 1998 until July 1999, he was a private investor and consultant in bulk liquid distribution. From 1994 until 1997, he was the President and Chief Executive Officer of GATX Terminals Corporation, a subsidiary of GATX Corporation. Prior to that, he served as Vice President of Finance and Chief Financial Officer of GATX Corporation from 1986 to 1994. Mr. Chlebowski is a director of First Midwest Bancorp Inc. and the Non-Executive Chairman of SemGroup Corporation. Mr. Chlebowski also served as a director of Laidlaw International, Inc. from June 2003 until October 2007, SpectraSite, Inc. from June 2004 until August 2005, and Phosphate Resource Partners Limited Partnership from June 2004 until August 2005. Mr. Chlebowski’s extensive leadership and financial expertise, as a result of his position as a former chief executive officer and his service on several boards of companies involved in the restructuring or recovery of their core business, enable him to contribute to the board of directors significant managerial, strategic, and financial oversight skills. Furthermore, Mr. Chlebowski’s service on other public boards, notably as a non-executive Chairman, provides valuable insight into the application of various governance principals to the Company’s board of directors.
David W. Crane
has served as the President, Chief Executive Officer and Director since the Company's formation in December 2012. Mr. Crane has served as the President, Chief Executive Officer of NRG and a director of NRG since December 2003. Prior to joining NRG, Mr. Crane served as Chief Executive Officer of International Power plc, a UK-domiciled wholesale power generation company, from January 2003 to November 2003, and as Chief Operating Officer from March 2000 through December 2002. Mr. Crane was Senior Vice President—Global Power New York at Lehman Brothers Inc., an investment banking firm, from January 1999 to February 2000, and was Senior Vice President—Global Power Group, Asia (Hong Kong) at Lehman Brothers from June 1996 to January 1999. Mr. Crane was also a director of El Paso Corporation from December 2009 to May 2012. As Chief Executive Officer of the Company, Mr. Crane provides the board of directors with management's perspective regarding the Company's day-to-day operations and overall strategic plan. His extensive leadership experience enables Mr. Crane to play a key role in all matters involving the Company's board of directors and act as the head of management to the independent directors of the Company's board of directors. In addition having recently served as a director of El Paso Corporation, Mr. Crane is able to contribute an additional perspective from the energy industry.
Brian R. Ford
has served as a Director since July 2013. Mr. Ford was the Chief Executive Officer of Washington Philadelphia Partners, LP, a real estate investment company, from 2008 through 2010. He retired as a partner from Ernst & Young LLP in June 2008 where he had been employed since 1971. Mr. Ford currently serves on the board of various public companies: GulfMark Offshore, Inc., a global provider of marine transportation, since 2009, where he also serves as the chairman of the audit committee and as a member of the governance nominating committee; AmeriGas Propane, Inc., a propane company, since 2013, where he also serves as a member of its audit committee and corporate governance committee; FSIC III, newly organized specialty finance company that invests primarily in the debt securities of private U.S. middle-market companies, since 2013, where he also serves as the chairman of the audit committee. He also serves on the boards of Drexel University and Drexel University College of Medicine. Mr. Ford received his B.S. in Economics from Rutgers University. Mr. Ford extensive experience in accounting and public company matters provides strong financial, audit and accounting skills to the Company's board of directors.
54
Mauricio Gutierrez
has served as Executive Vice President, Chief Operating Officer and Director since the Company's formation in December 2012. Mr. Gutierrez has served as Executive Vice President and Chief Operating Officer of NRG since July 2010. In this capacity, Mr. Gutierrez oversees NRG's Plant Operations, Commercial Operations, Environmental Compliance, as well as the Engineering, Procurement and Construction division. He previously served as Executive Vice President, Commercial Operations, from January 2009 to July 2010 and Senior Vice President, Commercial Operations, from March 2008 to January 2009. In this capacity, he was responsible for the optimization of NRG's asset portfolio and fuel requirements. Prior to this, Mr. Gutierrez served as Vice President Commercial Operations Trading from May 2006 to March 2008. Prior to joining NRG in August 2004, Mr. Gutierrez held various positions within Dynegy, Inc., including Managing Director, Trading—Southeast and Texas, Senior Trader East Power and Asset Manager. Prior to Dynegy, Mr. Gutierrez served as senior consultant and project manager at DTP involved in various energy and infrastructure projects in Mexico. Mr. Gutierrez’s knowledge of the Company’s assets, operations and businesses bring important experience and skills to the Company’s board of directors.
Ferrell P. McClean
has served as a Director since July 2013. Ms. McClean was a Managing Director and the Senior Advisor to the head of the Global Oil & Gas Group in Investment Banking at J.P. Morgan Chase & Co. from 2000 through the end of 2001. She joined J.P. Morgan & Co. Incorporated in 1969 and founded the Leveraged Buyout and Restructuring Group within the Mergers & Acquisitions Group in 1986. From 1991 until 2000, Ms. McClean was a Managing Director and co-headed the Global Energy Group within the Investment Banking Group at J.P. Morgan & Co. She is currently a director of GrafTech International. She retired as a director of Unocal Corporation in 2005 and as a director of El Paso Corporation in 2012. Ms. McClean's experience in investment banking for industrial companies as well as her experience and understanding of financial accounting, finance and disclosure matters enables her to provide essential guidance to the Company's board of directors and management team.
Christopher Sotos
has served as a Director since May 2013. Mr. Sotos has served as Senior Vice President—Strategy and Mergers and Acquisitions of NRG since November 2012. Previously, he served as NRG's Senior Vice President and Treasurer from March 2008 to September 2012. In this role, he was responsible for all treasury functions, including raising capital, valuation, debt administration and cash management. Mr. Sotos joined NRG in 2004 as a Senior Finance Analyst, following more than nine years in key financial roles within the energy sector and other industries for Houston-based companies such as Koch Capital Markets, Entergy Wholesale Operations and Service Corporation International. Mr. Sotos brings strong financial and accounting skills to the Company's board of directors.
Executive Officers
For biographical information for Mr. Crane, Mr. Andrews and Mr. Gutierrez, see above under “Directors.”
David R. Hill
has served as Executive Vice President and General Counsel since the Company's formation in December 2012. Mr. Hill has served as Executive Vice President and General Counsel of NRG since September 2012. Prior to joining NRG, Mr. Hill was a partner and co-head of Sidley Austin LLP's global energy practice group. Prior to joining Sidley Austin, Mr. Hill served as General Counsel of the U.S. Department of Energy from August 2005 to January 2009 and, for the three years prior to that, as Deputy General Counsel for Energy Policy of the DOE. Prior to his federal government services, Mr. Hill was a partner at major law firms in Washington D.C. and Kansas City, Missouri, and handled a variety of regulatory, litigation and corporate matters. He received his law degree from Northwestern University School of Law in Chicago.
Ronald B. Stark
has served as Vice President and Chief Accounting Officer since the Company's formation in December 2012. Mr. Stark has served as Vice President and Chief Accounting Officer of NRG since March 2012. Mr. Stark served as the Vice President, Internal Audit of NRG from August 2011 to February 2012. He previously served as Director, Financial Reporting of NRG from October 2007 through July 2011. Mr. Stark joined NRG in January 2007. Prior to joining NRG, Mr. Stark held various executive and managerial accounting positions at Pegasus Communications and Berlitz International and began his career with Deloitte and Touche.
Code of Ethics
The Company has adopted a code of ethics entitled "NRG Yield Code of Conduct" that applies to directors and officers of the Company. It may be accessed through the Corporate Governance section of the Company's website at
http://www.nrgyield.com/corpgov.htm.
The Company also elects to disclose the information required by Form 8-K, Item 5.05, "Amendments to the Registrant's Code of Ethics, or Waiver of a Provision of the Code of Ethics," through the Company's website, and such information will remain available on this website for at least a 12-month period. A copy of the "NRG Yield, Inc. Code of Conduct" is available in print to any stockholder who requests it.
Information required by this Item will be incorporated by reference to the similarly named section of the Company's definitive Proxy Statement for its 2014 Annual Meeting of Stockholders.
55
Other information required by this Item will be incorporated by reference to the similarly named section of the Company's Definitive Proxy Statement for its
2014
Annual Meeting of Stockholders.
Securities Authorized for Issuance under Equity Compensation Plans
|
Plan Category
|
(a)
Number of Securities
to be Issued Upon
Exercise of
Outstanding Options,
Warrants and Rights
|
(b)
Weighted-Average Exercise
Price of Outstanding
Options, Warrants and
Rights
|
(c)
Number of Securities
Remaining Available
for Future Issuance
Under Equity Compensation
Plans (Excluding
Securities Reflected
in Column (a))
|
||||||
|
Equity compensation plans approved by security holders
|
14,887
|
|
$
|
—
|
|
963,863
|
|
||
|
Equity compensation plans not approved by security holders
|
—
|
|
N/A
|
|
—
|
|
|||
|
Total
|
14,887
|
|
$
|
—
|
|
963,863
|
|
||
Other information required by this Item will be incorporated by reference to the similarly named section of NRG Yield, Inc.'s Definitive Proxy Statement for its 2014 Annual Meeting of Stockholders.
Information required by this Item will be incorporated by reference to the similarly named section of the Company's Definitive Proxy Statement for its
2014
Annual Meeting of Stockholders.
Information required by this Item will be incorporated by reference to the similarly named section of the Company's Definitive Proxy Statement for its
2014
Annual Meeting of Stockholders.
56
(a)(1) Financial Statements
The following consolidated financial statements of NRG Yield, Inc. and related notes thereto, together with the report thereon of KPMG LLP, are included herein:
Consolidated Statement of Operations — Years ended December 31,
2013
,
2012
and
2011
Consolidated Statements of Comprehensive Income — Years ended December 31,
2013
,
2012
and
2011
Consolidated Balance Sheets — December 31,
2013
and
2012
Consolidated Statements of Cash Flows — Years ended December 31,
2013
,
2012
and
2011
Consolidated Statement of Stockholders' Equity — Years ended December 31,
2013
,
2012
and
2011
Notes to Consolidated Financial Statements
(a)(2) Financial Statement Schedules
The following schedules of NRG Yield, Inc. are filed as part of Item 15(d) of this report and should be read in conjunction with the Consolidated Financial Statements.
NRG Yield, Inc. Financial Statements for the year ended December 31, 2013 and 2012 are included in NRG Yield, Inc.'s Annual Report on Form 10-K pursuant to the requirements of Rule 5-04(c) of Regulation S-X
GCE Holding LLC Unaudited Consolidated Financial Statements for the year ended December 31, 2013 and GCE Holding LLC Audited Consolidated Financial Statements for the years ended December 31, 2012, 2011 and 2010 are included in NRG Yield, Inc.'s Annual Report on Form 10-K pursuant to the requirements of Rule 3-09 of Regulation S-X
All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable, and therefore, have been omitted
(a)(3) Exhibits: See Exhibit Index submitted as a separate section of this report
(b) Exhibits
See Exhibit Index submitted as a separate section of this report
(c) Not applicable
57
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
NRG Yield, Inc.
We have audited the accompanying consolidated balance sheets of NRG Yield, Inc. and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2013. In connection with our audits of the consolidated financial statements, we also have audited financial statement schedule “Schedule I. Condensed Financial Information of Registrant.” These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits. We did not audit the December 31, 2012 and 2011 consolidated financial statements of GCE Holding, LLC (a 50% owned investee company). NRG Yield, Inc.’s investment in GCE Holding, LLC at December 31, 2012 and 2011, was $125 million and $131 million, respectively, and its equity in earnings of GCE Holding, LLC was $15 million and $12 million for the years ended December 31, 2012 and 2011, respectively. The consolidated financial statements of GCE Holding, LLC were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for GCE Holding, LLC, is based solely on the report of the other auditors.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of NRG Yield, Inc. and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for the years then ended in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
|
/s/ KPMG LLP
|
|
|
|
KPMG LLP
|
|
Philadelphia, Pennsylvania
|
|
|
February 28, 2014
|
|
58
NRG YIELD, INC.
|
Year ended December 31,
|
|||||||||||
|
(In millions, except per share amounts)
|
2013
|
2012
|
2011
|
||||||||
|
Operating Revenues
|
|||||||||||
|
Total operating revenues
|
$
|
313
|
|
$
|
175
|
|
$
|
164
|
|
||
|
Operating Costs and Expenses
|
|||||||||||
|
Cost of operations
|
127
|
|
112
|
|
108
|
|
|||||
|
Depreciation and amortization
|
51
|
|
25
|
|
22
|
|
|||||
|
General and administrative — affiliate
|
7
|
|
7
|
|
6
|
|
|||||
|
Total operating costs and expenses
|
185
|
|
144
|
|
136
|
|
|||||
|
Operating Income
|
128
|
|
31
|
|
28
|
|
|||||
|
Other Income/(Expense)
|
|||||||||||
|
Equity in earnings of unconsolidated affiliates
|
22
|
|
19
|
|
13
|
|
|||||
|
Other income, net
|
2
|
|
1
|
|
2
|
|
|||||
|
Interest expense
|
(35
|
)
|
(28
|
)
|
(19
|
)
|
|||||
|
Total other income/(expense)
|
(11
|
)
|
(8
|
)
|
(4
|
)
|
|||||
|
Income Before Income Taxes
|
117
|
|
23
|
|
24
|
|
|||||
|
Income tax expense
|
8
|
|
10
|
|
9
|
|
|||||
|
Net Income
|
$
|
109
|
|
$
|
13
|
|
$
|
15
|
|
||
|
Less: Predecessor income prior to initial public offering on July 22, 2013
|
54
|
|
|||||||||
|
Net Income Subsequent to Initial Public Offering
|
55
|
|
|
|
|||||||
|
Less: Net income attributable to noncontrolling interest
|
42
|
|
|||||||||
|
Net Income Attributed to NRG Yield, Inc. Subsequent to Initial Public Offering
|
$
|
13
|
|
||||||||
|
Earnings Per Share Attributable to NRG Yield, Inc. Class A Common Stockholders
|
|||||||||||
|
Weighted average number of Class A common shares outstanding - basic and diluted
|
23
|
|
|||||||||
|
Earnings per Weighted Average Class A Common Share - Basic and Diluted
|
$
|
0.57
|
|
||||||||
|
Dividends Per Common Share
|
$
|
0.23
|
|
||||||||
See accompanying notes to consolidated financial statements.
59
NRG YIELD, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
|
Year ended December 31,
|
|||||||||||
|
2013
|
2012
|
2011
|
|||||||||
|
(In millions)
|
|||||||||||
|
Net Income
|
$
|
109
|
|
$
|
13
|
|
$
|
15
|
|
||
|
Other Comprehensive (Loss)/Income, net of tax
|
|||||||||||
|
Unrealized gain/(loss) on derivatives, net of income tax (expense)/benefit of ($16), $7, and $10
|
24
|
|
(9
|
)
|
(15
|
)
|
|||||
|
Other comprehensive income/(loss)
|
24
|
|
(9
|
)
|
(15
|
)
|
|||||
|
Comprehensive Income
|
133
|
|
$
|
4
|
|
$
|
—
|
|
|||
|
Less: Predecessor comprehensive income prior to initial public offering on July 22, 2013
|
73
|
|
|||||||||
|
Comprehensive Income Subsequent to Initial Public Offering
|
60
|
|
|
||||||||
|
Less: Comprehensive income attributable to noncontrolling interest
|
45
|
|
|||||||||
|
Comprehensive Income Attributed to NRG Yield Inc. Subsequent to Initial Public Offering
|
$
|
15
|
|
|
|||||||
See accompanying notes to consolidated financial statements.
60
NRG YIELD, INC.
|
December 31, 2013
|
December 31, 2012
|
||||||
|
ASSETS
|
(In millions)
|
||||||
|
Current Assets
|
|
|
|||||
|
Cash and cash equivalents
|
$
|
36
|
|
$
|
22
|
|
|
|
Restricted cash
|
54
|
|
20
|
|
|||
|
Accounts receivable — trade
|
40
|
|
22
|
|
|||
|
Accounts receivable — affiliate
|
1
|
|
—
|
|
|||
|
Inventory
|
14
|
|
5
|
|
|||
|
Derivative instruments
|
1
|
|
—
|
|
|||
|
Notes receivable
|
2
|
|
9
|
|
|||
|
Renewable energy grant receivable
|
102
|
|
—
|
|
|||
|
Deferred income taxes
|
—
|
|
1
|
|
|||
|
Prepayments and other current assets
|
17
|
|
2
|
|
|||
|
Total current assets
|
267
|
|
81
|
|
|||
|
Property, plant and equipment
|
|||||||
|
In service
|
1,699
|
|
710
|
|
|||
|
Under construction
|
6
|
|
1,003
|
|
|||
|
Total property, plant and equipment
|
1,705
|
|
1,713
|
|
|||
|
Less accumulated depreciation
|
(164
|
)
|
(115
|
)
|
|||
|
Net property, plant and equipment
|
1,541
|
|
1,598
|
|
|||
|
Other Assets
|
|
|
|||||
|
Equity investments in affiliates
|
227
|
|
220
|
|
|||
|
Notes receivable
|
6
|
|
8
|
|
|||
|
Notes receivable — affiliate
|
2
|
|
6
|
|
|||
|
Intangible assets, net of accumulated amortization of $6 and $3
|
86
|
|
30
|
|
|||
|
Derivative instruments
|
11
|
|
—
|
|
|||
|
Deferred income taxes
|
146
|
|
—
|
|
|||
|
Other non-current assets
|
27
|
|
21
|
|
|||
|
Total other assets
|
505
|
|
285
|
|
|||
|
Total Assets
|
$
|
2,313
|
|
$
|
1,964
|
|
|
See accompanying notes to consolidated financial statements.
61
NRG YIELD, INC.
CONSOLIDATED BALANCE SHEETS (Continued)
|
December 31, 2013
|
December 31, 2012
|
||||||
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
(In millions, except share information)
|
||||||
|
Current Liabilities
|
|
|
|||||
|
Current portion of long-term debt
|
$
|
133
|
|
$
|
58
|
|
|
|
Accounts payable
|
40
|
|
166
|
|
|||
|
Accounts payable — affiliate
|
41
|
|
26
|
|
|||
|
Derivative instruments
|
23
|
|
19
|
|
|||
|
Accrued expenses and other current liabilities
|
20
|
|
16
|
|
|||
|
Total current liabilities
|
257
|
|
285
|
|
|||
|
Other Liabilities
|
|
|
|||||
|
Long-term debt
|
1,000
|
|
723
|
|
|||
|
Long-term debt — affiliate
|
—
|
|
26
|
|
|||
|
Deferred income taxes
|
—
|
|
4
|
|
|||
|
Derivative instruments
|
16
|
|
61
|
|
|||
|
Other non-current liabilities
|
29
|
|
25
|
|
|||
|
Total non-current liabilities
|
1,045
|
|
839
|
|
|||
|
Total Liabilities
|
1,302
|
|
1,124
|
|
|||
|
Commitments and Contingencies
|
|
|
|
|
|||
|
Stockholders'/Members' Equity
|
|
|
|||||
|
Preferred stock, $0.01 par value; 10,000,000 shares authorized at December 31, 2013; none issued at December 31, 2013
|
—
|
|
—
|
|
|||
|
Class A common stock, $0.01 par value; 500,000,000 shares authorized at December 31, 2013; 22,511,250 shares issued at December 31, 2013
|
—
|
|
—
|
|
|||
|
Class B common stock, $0.01 par value; 500,000,000 shares authorized at December 31, 2013; 42,738,750 shares issued at December 31, 2013
|
—
|
|
—
|
|
|||
|
Members' equity
|
—
|
|
840
|
|
|||
|
Additional paid-in capital
|
621
|
|
—
|
|
|||
|
Retained earnings
|
8
|
|
—
|
|
|||
|
Noncontrolling interest
|
382
|
|
—
|
|
|||
|
Total Stockholders'/Members' Equity
|
1,011
|
|
840
|
|
|||
|
Total Liabilities and Stockholders’/Members' Equity
|
$
|
2,313
|
|
$
|
1,964
|
|
|
See accompanying notes to consolidated financial statements.
62
NRG YIELD, INC.
|
Year ended December 31,
|
|||||||||||
|
2013
|
2012
|
2011
|
|||||||||
|
(In millions)
|
|||||||||||
|
Cash Flows from Operating Activities
|
|||||||||||
|
Net income
|
$
|
109
|
|
$
|
13
|
|
$
|
15
|
|
||
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|||||||||||
|
Distributions and equity in earnings of unconsolidated affiliates
|
(6
|
)
|
2
|
|
(5
|
)
|
|||||
|
Depreciation and amortization
|
51
|
|
25
|
|
22
|
|
|||||
|
Amortization of financing costs and debt discount/premiums
|
2
|
|
—
|
|
—
|
|
|||||
|
Amortization of intangibles and out-of-market contracts
|
1
|
|
—
|
|
1
|
|
|||||
|
Changes in deferred income taxes
|
8
|
|
10
|
|
9
|
|
|||||
|
Changes in derivative instruments
|
(21
|
)
|
2
|
|
2
|
|
|||||
|
Changes in other working capital
|
(3
|
)
|
6
|
|
(11
|
)
|
|||||
|
Net Cash Provided by Operating Activities
|
141
|
|
58
|
|
|
33
|
|
||||
|
Cash Flows from Investing Activities
|
|
|
|||||||||
|
Capital expenditures
|
(238
|
)
|
(380
|
)
|
(132
|
)
|
|||||
|
Acquisition of businesses, net of cash acquired
|
(120
|
)
|
—
|
|
—
|
|
|||||
|
Increase in restricted cash, net
|
(34
|
)
|
(12
|
)
|
(4
|
)
|
|||||
|
Decrease/(increase) in notes receivable (including affiliates)
|
13
|
|
(14
|
)
|
7
|
|
|||||
|
Proceeds from renewable energy grants
|
25
|
|
28
|
|
—
|
|
|||||
|
Investments in unconsolidated affiliates
|
(34
|
)
|
(27
|
)
|
(88
|
)
|
|||||
|
Other
|
—
|
|
—
|
|
(2
|
)
|
|||||
|
Net Cash Used by Investing Activities
|
(388
|
)
|
(405
|
)
|
|
(219
|
)
|
||||
|
Cash Flows from Financing Activities
|
|
|
|||||||||
|
Capital contributions from NRG
|
171
|
|
355
|
|
218
|
|
|||||
|
Dividends and returns of capital to NRG
|
(707
|
)
|
(72
|
)
|
(18
|
)
|
|||||
|
Proceeds from issuance of Class A common stock
|
468
|
|
—
|
|
—
|
|
|||||
|
Payment of dividends to Class A and Class B common stockholders
|
(15
|
)
|
—
|
|
—
|
|
|||||
|
Proceeds from issuance of long-term debt — external
|
420
|
|
117
|
|
61
|
|
|||||
|
Payment of debt issuance costs
|
(5
|
)
|
(12
|
)
|
(3
|
)
|
|||||
|
Payments for long-term debt — external
|
(69
|
)
|
(37
|
)
|
(78
|
)
|
|||||
|
Payments for long-term debt — affiliate
|
(2
|
)
|
(6
|
)
|
—
|
|
|||||
|
Net Cash Provided by Financing Activities
|
261
|
|
345
|
|
180
|
|
|||||
|
Net Increase/(Decrease) in Cash and Cash Equivalents
|
14
|
|
(2
|
)
|
(6
|
)
|
|||||
|
Cash and Cash Equivalents at Beginning of Period
|
22
|
|
24
|
|
30
|
|
|||||
|
Cash and Cash Equivalents at End of Period
|
$
|
36
|
|
$
|
22
|
|
$
|
24
|
|
||
|
Supplemental Disclosures
|
|||||||||||
|
Interest paid, net of amount capitalized
|
$
|
49
|
|
$
|
17
|
|
$
|
17
|
|
||
|
Non-cash investing and financing activities:
|
|||||||||||
|
Additions to fixed assets for accrued capital expenditures
|
—
|
|
102
|
|
28
|
|
|||||
|
Decrease to fixed assets for accrued grants and related tax impact
|
(166
|
)
|
(1
|
)
|
(25
|
)
|
|||||
|
Non-cash addition to additional paid-in capital for change in tax basis of property, plant and equipment
|
153
|
|
—
|
|
—
|
|
|||||
|
Non-cash capital contributions from NRG
|
50
|
|
166
|
|
5
|
|
|||||
|
Non-cash return of capital and dividends to NRG
|
(87
|
)
|
—
|
|
(11
|
)
|
|||||
|
Decrease to notes receivable for equity conversion
|
—
|
|
—
|
|
63
|
|
|||||
See accompanying notes to consolidated financial statements.
63
NRG YIELD, INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
|
Preferred Stock
|
Class A Common Stock
|
Class B Common Stock
|
Additional
Paid-In
Capital
|
Retained Earnings
|
NRG Yield (Predecessor)
|
Accumulated
Other
Comprehensive
Income/(Loss)
|
Noncon-trolling
Interest
|
Members' Equity
|
Total
Members' / Stockholders'
Equity
|
||||||||||||||||||||||||||||||
|
(In millions)
|
|||||||||||||||||||||||||||||||||||||||
|
Balances at December 31, 2010
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
193
|
|
$
|
193
|
|
|||||||||
|
Net income
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
15
|
|
15
|
|
|||||||||||||||||||
|
Unrealized gain on derivatives, net
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(15
|
)
|
(15
|
)
|
|||||||||||||||||||
|
Capital contributions from NRG - cash
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
218
|
|
218
|
|
|||||||||||||||||||
|
Capital contributions from NRG - non-cash
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
5
|
|
5
|
|
|||||||||||||||||||
|
Return of capital to NRG
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(18
|
)
|
(18
|
)
|
|||||||||||||||||||
|
Dividend - settlement with affiliate
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(11
|
)
|
(11
|
)
|
|||||||||||||||||||
|
Balances at December 31, 2011
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
387
|
|
$
|
387
|
|
|||||||||
|
Net income
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
13
|
|
13
|
|
|||||||||||||||||||
|
Unrealized gain on derivatives, net
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(9
|
)
|
(9
|
)
|
|||||||||||||||||||
|
Capital contributions from NRG - cash
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
355
|
|
355
|
|
|||||||||||||||||||
|
Capital contributions from NRG - non-cash
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
166
|
|
166
|
|
|||||||||||||||||||
|
Return of capital to NRG
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(49
|
)
|
(49
|
)
|
|||||||||||||||||||
|
Cash distributions to NRG
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(23
|
)
|
(23
|
)
|
|||||||||||||||||||
|
Balances at December 31, 2012
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
840
|
|
$
|
840
|
|
|||||||||
|
Net Income
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
54
|
|
54
|
|
|||||||||||||||||||
|
Capital contributions from NRG - cash
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
171
|
|
171
|
|
|||||||||||||||||||
|
Capital contributions from NRG - non-cash
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
50
|
|
50
|
|
|||||||||||||||||||
|
Return of capital to NRG
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(311
|
)
|
(311
|
)
|
|||||||||||||||||||
|
Return of capital to NRG - non-cash
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(29
|
)
|
(29
|
)
|
|||||||||||||||||||
|
Unrealized gain on derivatives, net of tax
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
19
|
|
19
|
|
|||||||||||||||||||
|
Dividends paid to NRG
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(1
|
)
|
(1
|
)
|
|||||||||||||||||||
|
Non-cash dividends to NRG
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(5
|
)
|
(5
|
)
|
|||||||||||||||||||
|
Balance as of July 22, 2013
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
788
|
|
$
|
788
|
|
|||||||||
|
Return of capital to NRG
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(395
|
)
|
(395
|
)
|
|||||||||||||||||||
|
Transfer of predecessors' equity to noncontrolling interest
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
3
|
|
390
|
|
(393
|
)
|
—
|
|
|||||||||||||||||||
|
Net Income
|
—
|
|
—
|
|
—
|
|
—
|
|
13
|
|
—
|
|
—
|
|
42
|
|
—
|
|
55
|
|
|||||||||||||||||||
|
Unrealized gain on derivatives, net
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(3
|
)
|
3
|
|
—
|
|
—
|
|
|||||||||||||||||||
|
Common shares issued in public offering
|
—
|
|
—
|
|
—
|
|
468
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
468
|
|
|||||||||||||||||||
|
Non-cash addition for change in tax basis of property, plant and equipment
|
—
|
|
—
|
|
—
|
|
153
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
153
|
|
|||||||||||||||||||
|
Non-cash adjustment to noncontrolling interest
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(43
|
)
|
—
|
|
(43
|
)
|
|||||||||||||||||||
|
Common stock dividends
|
—
|
|
—
|
|
—
|
|
—
|
|
(5
|
)
|
—
|
|
—
|
|
(10
|
)
|
—
|
|
(15
|
)
|
|||||||||||||||||||
|
Balances at December 31, 2013
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
621
|
|
$
|
8
|
|
$
|
—
|
|
$
|
—
|
|
$
|
382
|
|
$
|
—
|
|
$
|
1,011
|
|
|||||||||
See accompanying notes to consolidated financial statements.
64
NRG YIELD, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1
—
Nature of Business
NRG Yield, Inc., or the Company, was formed by NRG as a Delaware corporation on December 20, 2012. On July 22, 2013, the Company issued
22,511,250
shares of Class A common stock in an initial public offering. The Company utilized the net proceeds of the initial public offering to acquire
19,011,250
Class A units of NRG Yield LLC from NRG in return for
$395 million
, and
3,500,000
Class A units of NRG Yield LLC directly from NRG Yield LLC in return for
$73 million
. In connection with the acquisition of the Class A units, the Company also became the sole managing member of NRG Yield LLC thereby acquiring a controlling interest in NRG Yield LLC.
Immediately prior to the acquisition, NRG Yield LLC acquired a portfolio of contracted renewable and conventional generation and thermal infrastructure assets, primarily located in the Northeast, Southwest and California regions of the United States, from NRG in return for Class B units in NRG Yield LLC. These assets were simultaneously contributed by NRG Yield LLC to its direct wholly owned subsidiary NRG Yield Operating LLC. Following the initial public offering, the Company owns
34.5%
of NRG Yield LLC and consolidates the results of NRG Yield LLC through its controlling interest, with NRG's
65.5%
interest shown as noncontrolling interest in the financial statements.
The following table represents the structure of the Company after the initial public offering:
65
For all periods prior to the initial public offering, the accompanying combined financial statements represent the combination of the assets that NRG Yield LLC acquired and were prepared using NRG's historical basis in the assets and liabilities. For the purposes of the combined financial statements, the term "NRG Yield" represents the accounting predecessor, or the combination of the acquired businesses. For all periods subsequent to the initial public offering, the accompanying audited consolidated financial statements represent the consolidated results of the Company, which consolidates NRG Yield LLC through its controlling interest.
The Company's operating assets are comprised of the following projects:
|
Projects
|
Percentage Ownership
|
Net Capacity (MW)
(a)
|
Offtake Counterparty
|
Expiration
|
||||||
|
Conventional
|
||||||||||
|
GenConn Middletown
|
49.95
|
%
|
95
|
|
Connecticut Light & Power
|
2041
|
||||
|
GenConn Devon
|
49.95
|
%
|
95
|
|
Connecticut Light & Power
|
2040
|
||||
|
Marsh Landing
|
100
|
%
|
720
|
|
Pacific Gas and Electric
|
2023
|
||||
|
910
|
|
|||||||||
|
Utility Scale Solar
|
||||||||||
|
Alpine
|
100
|
%
|
66
|
|
Pacific Gas and Electric
|
2033
|
||||
|
Avenal
|
49.95
|
%
|
23
|
|
Pacific Gas and Electric
|
2031
|
||||
|
Avra Valley
|
100
|
%
|
25
|
|
Tucson Electric Power
|
2032
|
||||
|
Blythe
|
100
|
%
|
21
|
|
Southern California Edison
|
2029
|
||||
|
Borrego
|
100
|
%
|
26
|
|
San Diego Gas and Electric
|
2038
|
||||
|
Roadrunner
|
100
|
%
|
20
|
|
El Paso Electric
|
2031
|
||||
|
CVSR
|
48.95
|
%
|
122
|
|
Pacific Gas and Electric
|
2038
|
||||
|
303
|
|
|||||||||
|
Distributed Solar
|
||||||||||
|
AZ DG Solar Projects
|
100
|
%
|
5
|
|
Various
|
2025 - 2033
|
||||
|
PFMG DG Solar Projects
|
51
|
%
|
5
|
|
Various
|
2032
|
||||
|
10
|
|
|||||||||
|
Wind
|
||||||||||
|
South Trent
|
100
|
%
|
101
|
|
AEP Energy Partners
|
2029
|
||||
|
Thermal
|
||||||||||
|
Thermal equivalent MWt
(b)
|
100
|
%
|
1,346
|
|
Various
|
Various
|
||||
|
Thermal generation
|
100
|
%
|
123
|
|
Various
|
Various
|
||||
|
Total net capacity (excluding equivalent MWt)
|
1,447
|
|
||||||||
(a) Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of
December 31, 2013
.
(b) For thermal energy, net capacity represents MWt for steam or chilled water.
Substantially all of the Company's generation assets are under long-term contractual arrangements for the output or capacity from these assets. The thermal assets are comprised of district energy systems and combined heat and power plants that produce steam, hot water and/or chilled water and in some instances, electricity at a central plant. Three of the district energy systems are subject to rate regulation by state public utility commissions while the other district energy systems have rates determined by negotiated bilateral contracts.
The historical combined financial statements include allocations of certain NRG corporate expenses and income tax expense. Management believes the assumptions and methodology underlying the allocation of general corporate overhead expenses are reasonable. The allocated costs include legal, accounting, tax, treasury, information technology, insurance, employee benefit costs, and other corporate costs. However, such expenses may not be indicative of the actual level of expense that would have been incurred if the Company had operated as an independent, publicly-traded company during the periods prior to the offering or of the costs expected to be incurred in the future. Allocations of NRG corporate expenses were
$4 million
for the period beginning on January 1, 2013 and ending on July 22, 2013,
$7 million
for the year ended December 31, 2012 and
$6 million
for the year ended December 31, 2011. In connection with the initial public offering, the Company entered into a management services agreement with NRG for various services, including human resources, accounting, tax, legal, information systems, treasury, and risk management. Costs incurred by the Company under this agreement were
$3 million
for the period beginning July 23, 2013 and ending
December 31, 2013
.
66
For all periods prior to the initial public offering, member's equity represents the combined equity of the Company's subsidiaries, including adjustments necessary to present the Company's financial statements as if the Company were in existence as of the beginning of the periods represented. Member's equity represents NRG's equity in the subsidiaries, and accordingly, in connection with the initial public offering, the balance was reclassified into noncontrolling interest. Subsequent to the initial public offering, stockholders' equity represents the equity associated with the Class A common shareholders, with the equity associated with the Class B common shareholders, or NRG, classified as noncontrolling interest.
Note 2
—
Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
The Company's consolidated and combined financial statements have been prepared in accordance with U.S. GAAP. The Financial Accounting Standards Board, or FASB, Accounting Standards Codification, or ASC, is the source of authoritative U.S. GAAP to be applied by nongovernmental entities. In addition, the rules and interpretative releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants.
The consolidated and combined financial statements include the Company's accounts and operations and those of its subsidiaries in which it has a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation. The usual condition for a controlling financial interest is ownership of a majority of the voting interests of an entity. However, a controlling financial interest may also exist through arrangements that do not involve controlling voting interests. As such, the Company applies the guidance of ASC 810,
Consolidations,
or ASC 810, to determine when an entity that is insufficiently capitalized or not controlled through its voting interests, referred to as a variable interest entity, or VIE, should be consolidated.
Cash and Cash Equivalents
Cash and cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase.
Restricted Cash
Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within the Company's projects that are restricted in their use. These funds are used to pay for capital expenditures, current operating expenses and current debt service payments as well as to fund required equity contributions, per the restrictions of the debt agreements.
Trade Receivables and Allowance for Doubtful Accounts
Trade receivables are reported on the balance sheet at the invoiced amount adjusted for any write-offs and the allowance for doubtful accounts. The allowance for doubtful accounts is reviewed periodically based on amounts past due and significance. The allowance for doubtful accounts was immaterial as of
December 31, 2013
and
2012
.
Inventory
Inventory consists principally of spare parts and fuel oil and is valued at the lower of weighted average cost or market, unless evidence indicates that the weighted average cost will be recovered with a normal profit in the ordinary course of business. The Company removes fuel inventories as they are used in the production of steam, chilled water or electricity. Spare parts inventory are removed when they are used for repairs, maintenance or capital projects.
Property, Plant and Equipment
Property, plant and equipment are stated at cost or, in the case of business acquisitions, fair value; however impairment adjustments are recorded whenever events or changes in circumstances indicate that their carrying values may not be recoverable. See Note 3,
Business Acquisitions,
for more information on acquired property, plant and equipment. Significant additions or improvements extending asset lives are capitalized as incurred, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation is computed using the straight-line method over the estimated useful lives. Certain assets and their related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in cost of operations in the consolidated statements of operations.
67
Additionally, the Company reduces the book value of the property, plant and equipment of its eligible renewable energy projects for any cash grants that are submitted to the U.S. Treasury Department when the receivable is recorded for the net realizable amount. The related deferred tax asset is also recorded with a corresponding reduction to the book value of the property, plant and equipment.
Asset Impairments
Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with ASC 360. An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset's carrying amount and fair value with the difference recorded in operating costs and expenses in the statements of operations. Fair values are determined by a variety of valuation methods, including appraisals, sales prices of similar assets and present value techniques.
Investments accounted for by the equity method are reviewed for impairment in accordance with ASC 323,
Investments-Equity Method and Joint Ventures
, or ASC 323, which requires that a loss in value of an investment that is other than a temporary decline should be recognized. The Company identifies and measures losses in the value of equity method investments based upon a comparison of fair value to carrying value.
Capitalized Interest
Interest incurred on funds borrowed to finance capital projects is capitalized, until the project under construction is ready for its intended use. The amount of interest capitalized for the years ended
December 31, 2013
,
2012
and
2011
was
$7 million
,
$14 million
and
$2 million
, respectively.
When a project is available for operations, capitalized interest is reclassified to property, plant and equipment and amortized on a straight-line basis over the estimated useful life of the project's related assets.
Debt Issuance Costs
Debt issuance costs are capitalized and amortized as interest expense on a basis which approximates the effective interest method over the term of the related debt.
Intangible Assets
Intangible assets represent contractual rights held by NRG Yield, Inc. The Company recognizes specifically identifiable intangible assets including customer contracts, customer relationship, power purchase agreements and development rights when specific rights and contracts are acquired. These intangible assets are amortized primarily on a straight-line basis.
Intangible assets determined to have indefinite lives are not amortized, but rather are tested for impairment at least annually or more frequently if events or changes in circumstances indicate that such acquired intangible assets have been determined to have finite lives and should now be amortized over their useful lives. The Company had no intangible assets with indefinite lives recorded as of
December 31, 2013
.
Notes Receivable
Notes receivable consist of receivables related to the financing of required network upgrades and a variable-rate note secured by the equity interest in a joint venture. The notes issued with respect to network upgrades will be repaid within a
5
year period following the date each facility reaches commercial operations.
Income Taxes
The Company accounts for income taxes using the liability method in accordance with ASC 740,
Income Taxes
, or ASC 740, which requires that it use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.
The Company has two categories of income tax expense or benefit — current and deferred, as follows:
|
•
|
Current income tax expense or benefit consists solely of current taxes payable less applicable tax credits, and
|
|
•
|
Deferred income tax expense or benefit is the change in the net deferred income tax asset or liability, excluding amounts charged or credited to accumulated other comprehensive income.
|
68
The Company reports some of its revenues and expenses differently for financial statement purposes than for income tax return purposes, resulting in temporary and permanent differences between the Company's financial statements and income tax returns. The tax effects of such temporary differences are recorded as either deferred income tax assets or deferred income tax liabilities in the Company's consolidated balance sheets. The Company measures its deferred income tax assets and deferred income tax liabilities using income tax rates that are currently in effect. The Company believes it is more likely than not that the results of future operations will generate sufficient taxable income which includes the future reversal of existing taxable temporary differences to realize deferred tax assets, net of valuation allowances. A valuation allowance is recorded to reduce the net deferred tax assets to an amount that is more-likely-than-not to be realized.
The Company accounts for uncertain tax positions in accordance with ASC 740, which applies to all tax positions related to income taxes. Under ASC 740, tax benefits are recognized when it is more-likely-than-not that a tax position will be sustained upon examination by the authorities. The benefit recognized from a position that has surpassed the more-likely-than-not threshold is the largest amount of benefit that is more than
50%
likely to be realized upon settlement. The Company recognizes interest and penalties accrued related to uncertain tax benefits as a component of income tax expense.
In accordance with ASC 805 and as discussed further in Note 13,
Income Taxes
, changes to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits, are recorded to income tax expense.
Revenue Recognition
Power Purchase Agreements, or PPAs
A significant majority of the Company's revenues are obtained through PPAs or other contractual arrangements. All of these PPAs are accounted for as operating leases in accordance with ASC 840,
Leases,
or
ASC 840. ASC 840 requires minimum lease payments to be amortized over the term of the lease and contingent rentals are recorded when the achievement of the contingency becomes probable. Certain of these leases have no minimum lease payments and all of the rental income under these leases is recorded as contingent rent on an actual basis when the electricity is delivered. The contingent rental income recognized in the years ended
December 31, 2013
,
2012
and
2011
was
$161 million
,
$33 million
and
$26 million
, respectively.
Thermal Revenues
Steam and chilled water revenue is recognized based on customer usage as determined by meter readings taken at month-end. Some locations read customer meters throughout the month, and recognize estimated revenue for the period between meter read date and month-end. Thermal's subsidiaries collect and remit state and local taxes associated with sales to their customers, as required by governmental authorities. Related revenues are presented on a net basis in the income statement.
Derivative Financial Instruments
The Company accounts for derivative financial instruments under ASC 815,
Derivatives and Hedging
, or ASC 815, which requires the Company to record all derivatives on the balance sheet at fair value unless they qualify for a NPNS exception. Changes in the fair value of non-hedge derivatives are immediately recognized in earnings. Changes in the fair value of derivatives accounted for as hedges, if elected for hedge accounting, are either:
|
•
|
Recognized in earnings as an offset to the changes in the fair value of the related hedged assets, liabilities and firm commitments; or
|
|
•
|
Deferred and recorded as a component of accumulated OCI until the hedged transactions occur and are recognized in earnings.
|
The Company's primary derivative instruments are fuels purchase contracts used to control customer reimbursable fuel cost and interest rate instruments used to mitigate variability in earnings due to fluctuations in interest rates. On an ongoing basis, the Company assesses the effectiveness of all derivatives that are designated as hedges for accounting purposes in order to determine that each derivative continues to be highly effective in offsetting changes in fair values or cash flows of hedged items. Internal analyses that measure the statistical correlation between the derivative and the associated hedged item determine the effectiveness of such an energy contract designated as a hedge. If it is determined that the derivative instrument is not highly effective as a hedge, hedge accounting will be discontinued prospectively. In this case, the gain or loss previously deferred in accumulated OCI would be frozen until the underlying hedged item is delivered unless the transaction being hedged is no longer probable of occurring in which case the amount in OCI would be immediately reclassified into earnings.
69
Revenues and expenses on contracts that qualify for the NPNS exception are recognized when the underlying physical transaction is delivered. While these contracts are considered derivative financial instruments under ASC 815, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings.
Concentrations of Credit Risk
Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of accounts receivable, notes receivable and derivative instruments. Accounts receivable, notes receivable, and derivative instruments are concentrated within entities engaged in the energy and financial industry. These industry concentrations may impact the overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. In addition, many of the Company's projects have only one customer. However, the Company believes that the credit risk posed by industry concentration is offset by the diversification and creditworthiness of its customer base. See
Note 6
,
Fair Value of Financial Instruments
,
for a further discussion of derivative concentrations.
Fair Value of Financial Instruments
The carrying amount of cash and cash equivalents, receivables, accounts payables, and accrued liabilities approximate fair value because of the short-term maturity of these instruments. See Note 6,
Fair Value of Financial Instruments
for a further discussion of fair value of financial instruments.
Asset Retirement Obligations
Asset retirement obligations, or AROs, are accounted for in accordance with ASC 410-20,
Asset Retirement Obligations,
or ASC 410-20. Retirement obligations associated with long-lived assets included within the scope of ASC 410-20 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. ASC 410-20 requires an entity to recognize the fair value of a liability for an ARO in the period in which it is incurred and a reasonable estimate of fair value can be made.
Upon initial recognition of a liability for an ARO, the asset retirement cost is capitalized by increasing the carrying amount of the related long-lived asset by the same amount. Over time, the liability is accreted to its future value, while the capitalized cost is depreciated over the useful life of the related asset. The Company's asset retirement obligations were
$6 million
and
$4 million
for the years ended
December 31, 2013
and
2012
, respectively.
Guarantees
The Company enters into various contracts that include indemnification and guarantee provisions as a routine part of its business activities. Examples of these contracts include EPC agreements, operation and maintenance agreements, service agreements, commercial sales arrangements and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. Because many of the guarantees and indemnities the Company issues to third parties and affiliates do not limit the amount or duration of its obligations to perform under them, there exists a risk that the Company may have obligations in excess of the amounts described above. For those guarantees and indemnities that do not limit the liability exposure, it may not be able to estimate what the liability would be, until a claim is made for payment or performance, due to the contingent nature of these contracts.
Investments Accounted for by the Equity Method
The Company has investments in three energy projects accounted for by the equity method. The equity method of accounting is applied to these investments in affiliates because the ownership structure prevents the Company from exercising a controlling influence over the operating and financial policies of the projects. Under this method, equity in pre-tax income or losses of the investments are reflected as equity in earnings of unconsolidated affiliates.
Business Combinations
The Company accounts for its business combinations in accordance with ASC 805,
Business Combinations,
or ASC 805. ASC 805 requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. It also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity's financial statements to evaluate the nature and financial effects of the business combination. In addition, transaction costs are expensed as incurred.
70
Liquidity
Many of the Company's projects were under construction in 2012 with construction completed for all projects in 2013. As further discussed in Note 9,
Long-Term Debt,
in order to fund current obligations, the Company typically borrows under the related financing arrangements or receives funding from NRG.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, environmental liabilities, acquisition accounting and legal costs incurred in connection with recorded loss contingencies, among others. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
Reclassifications
Certain prior-year amounts have been reclassified for comparative purposes.
Recent Accounting Developments
ASU 2011-11
- Effective January 1, 2013, the Company adopted the provisions of ASU No. 2011-11,
Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities
, or ASU No. 2011-11, and began providing enhanced disclosures regarding the effect or potential effect of netting arrangements on an entity's financial position by improving information about financial instruments and derivative instruments that either (1) offset in accordance with either ASC 210-20-45 or ASC 810-20-45 or (2) are subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. Reporting entities are required to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The disclosures required by ASU No. 2011-11 are required to be adopted retroactively. As this guidance provides only disclosure requirements, the adoption of this standard did not impact the Company's results of operations, cash flows or financial position.
ASU 2013-02
- Effective January 1, 2013, the Company adopted the provisions of ASU No. 2013-02,
Other Comprehensive Income (Topic 220) Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income
, or ASU No. 2013-02, and began reporting the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income within the notes to the financial statements if the amount being reclassified is required under U.S. GAAP to be reclassified in its entirety to net income in the same reporting period. For other amounts not required by U.S. GAAP to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures which provide additional information about the amounts. The provisions of ASU No. 2013-02 are required to be adopted prospectively. As this guidance provides only presentation requirements, the adoption of this standard did not impact the Company's results of operations, cash flows or financial position.
Other
- The following accounting standard was issued in 2013 and was adopted January 1, 2014:
ASU 2013-11
- In July 2013, the FASB issued ASU No. 2013-11,
Income Taxes (Topic 740) Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists
, or ASU No. 2013-11. The amendments of ASU 2013-11 requires an entity to present an unrecognized tax benefit, or a portion of an unrecognized tax benefit, as a reduction of a deferred tax asset for a net operating loss, or NOL, a similar tax loss or tax credit carryforwards rather than a liability when the uncertain tax position would reduce the NOL or other carryforward under the tax law of the applicable jurisdiction and the entity intends to use the deferred tax asset for that purpose. The guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013 with early adoption permitted. The adoption of this standard will result in net presentation within the Company’s financial position. The adoption of this standard will not impact the Company’s results of operations or cash flows.
71
Note 3
—
Business Acquisitions
2013 Acquisitions
Energy Systems
—
On December 31, 2013, NRG Energy Center Omaha Holdings, LLC, an indirect wholly owned subsidiary of NRG Yield LLC, acquired Energy Systems Company, or Energy Systems, for approximately
$120 million
. The acquisition was financed from cash on hand. Energy Systems is an operator of steam and chilled water thermal facilities that provides heating and cooling services to nonresidential customers in Omaha, Nebraska. The acquisition was recorded as a business combination under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The purchase price was primarily allocated to property, plant and equipment of
$60 million
, customer relationships of
$59 million
, and
$1 million
of working capital. The initial accounting for the business combination is not complete because the evaluations necessary to assess the fair values of certain net assets acquired are still in process. The provisional amounts are subject to revision until the evaluations are completed to the extent that additional information is obtained about the facts and circumstances about the facts and circumstances that existed as of the acquisition date.
The provisional fair value of the identified intangible assets at the acquisition date was measured primarily based on significant inputs that are not observable in the market and thus represent a Level 3 measurement as defined in ASC 820. Significant considerations in determining fair value measurements as defined in ASC 820 and significant inputs were as follows:
Customer relationships
- Customer relationships were valued using a variation of the income approach. Under this approach, the present value of the expected future cash flows resulting from existing customer relationships, considering attrition and charges for contributory assets (such as working capital, fixed assets, and workforce) utilized in the business were estimated and then discounted back at an integrated utility peer group's weighted average cost of capital adjusted to be consistent with the risk inherent in the cash flows. Customer relationships are amortized to depreciation and amortization expense, on a straight-line basis, over
33 years
.
Property, plant & equipment
- The fair value of property, plant and equipment acquired were valued utilizing the cost approach. Under this approach, the fair value approximates the current cost of replacing an asset with another of equivalent economic utility adjusted for functional obsolescence and physical depreciation.
2012 Acquisitions
Marsh Landing
- On December 14, 2012, through its acquisition of GenOn Energy, Inc., or GenOn, NRG acquired
100%
of the Marsh Landing project, a
720
MW natural gas-fueled peaking facility being constructed near Antioch, California. Immediately prior to the initial public offering, NRG transferred ownership of Marsh Landing to NRG Yield LLC. Power generated from Marsh Landing is sold to Pacific Gas & Electric, or PG&E, under a
10
year PPA. In connection with the acquisition, the Company assumed obligations under a credit agreement for up to
$650 million
in construction and permanent financing for the Marsh Landing generating facility.
The Marsh Landing generating facility reached commercial operations on May 1, 2013.
The fair value of the net assets acquired was
$138 million
. The accounting for the acquisition was completed on December 13, 2013. The Company recorded a measurement period adjustment increasing the provisional fair value of the acquired property, plant and equipment by
$73 million
, from
$537 million
to
$610 million
. The primary driver for the revised fair value was the refinement of the methodology used to value the assets.
2011 Acquisitions
California Valley Solar Ranch
- On September 30, 2011, NRG acquired
100%
of the
250
MW California Valley Solar Ranch project, or CVSR, in eastern San Luis Obispo County, California. Power generated from CVSR is sold to PG&E under a
25
year PPA. In connection with the acquisition of High Plains Ranch II, LLC, the direct owner of the CVSR project, entered into a financing agreement with the FFB, which is guaranteed by the U.S. DOE to borrow up to
$1.2 billion
to fund the costs of constructing this solar facility, or the CVSR Financing Agreement. Operations commenced on the first
22
MW phase in September 2012 and
105
MWs for Phases 2 and 4 in December 2012. For the completion of the final phase,
21
MWs commenced operation in the third quarter of 2013 and
102
MWs commenced operation in October 2013.
The fair value of the property, plant and equipment at the acquisition date was measured primarily based on significant inputs that are not observable in the market and thus represent a Level 3 measurement as defined by ASC 820. The fair value of the property, plant and equipment acquired was determined utilizing the cost approach. Under this approach, the fair value approximates the current cost of replacing an asset with another equivalent economic utility adjusted for functional obsolescence and physical depreciation. The Company owns 48.95% of CVSR and accounts for it under the equity method, as further discussed in
Note 5
,
Investments Accounted for by the Equity Method and Variable Interest Entities
.
72
Note 4
—
Property, Plant and Equipment
The Company’s major classes of property, plant, and equipment were as follows:
|
December 31, 2013
|
December 31, 2012
|
Depreciable Lives
|
|||||||
|
(In millions)
|
|||||||||
|
Facilities and equipment
|
$
|
1,654
|
|
$
|
680
|
|
5 - 40 Years
|
||
|
Land and improvements
|
45
|
|
30
|
|
|||||
|
Construction in progress
|
6
|
|
1,003
|
|
|||||
|
Total property, plant and equipment
|
1,705
|
|
1,713
|
|
|||||
|
Accumulated depreciation
|
(164
|
)
|
(115
|
)
|
|||||
|
Net property, plant and equipment
|
$
|
1,541
|
|
$
|
1,598
|
|
|||
On February 13, 2013, the Avra Valley solar project, as a qualified renewable energy project, applied for a cash grant in lieu of investment tax credit from the U.S. Treasury Department in the amount of
$27 million
. A receivable for the cash grant application was recorded when the cash grant application was filed, which resulted in a reduction to the book basis of the property, plant, and equipment. In addition, the receivable was subsequently reduced to
$24 million
as a result of the federal government’s sequestration, which went into effect on March 1, 2013. The related deferred tax asset of
$7 million
recognizable was recorded with a corresponding reduction of the book value of Avra Valley’s property, plant and equipment. In June 2013, the Company received payment for the cash grant related to Avra Valley.
Alpine achieved commercial operations on January 18, 2013 and transferred the construction in progress to property, plant and equipment. On March 25, 2013, the Alpine solar project, as a qualified renewable energy project, applied for a cash grant in lieu of investment tax credit from U.S. Treasury Department in the amount of
$72 million
. A receivable for the cash grant application was recorded when the cash grant application was filed, which resulted in a reduction to the book basis of the property, plant and equipment. In addition, the receivable was reduced to
$66 million
as a result of the federal government’s sequestration, which was put into effect on March 1, 2013. The related deferred tax asset of
$19 million
recognizable was recorded with a corresponding reduction of the book value of Alpine’s property plant and equipment. In January 2014, the Company received payment for the cash grant related to Alpine.
Borrego achieved commercial operations on February 12, 2013 and transferred the construction in progress to property, plant and equipment. On May 16, 2013, the Borrego solar project, as a qualified renewable energy project, applied for a cash grant in lieu of investment tax credit from U.S. Treasury Department in the amount of
$39 million
. A receivable for the cash grant application was recorded when the cash grant application was filed, which resulted in a reduction to the book basis of the property, plant and equipment. In addition, the receivable was reduced to
$36 million
as a result of the federal government’s sequestration, which was put into effect on March 1, 2013. The related deferred tax asset of
$10 million
recognizable was recorded with a corresponding reduction of the book value of Borrego’s property plant and equipment.
Marsh Landing achieved commercial operations on May 1, 2013 and transferred the construction in progress to property, plant and equipment. The Marsh Landing project was acquired by NRG through the acquisition of GenOn. See
Note 3
,
Business Acquisitions
,
for further discussion of the acquisition.
73
Note 5
—
Investments Accounted for by the Equity Method and Variable Interest Entities
Equity Method Investments
Avenal
—The Company owns a
49.95%
equity interest in Avenal, which consists of three solar PV projects in Kings County, California, approximately
45
MWs, all of which became commercially operational during the third quarter of 2011. NRG retained a
0.05%
interest and Eurus Energy owns the remaining
50%
of Avenal. Power generated by the projects is sold under a
20
-year PPA. On September 22, 2010, Avenal entered into a
$35 million
promissory note facility with the Company. Amounts drawn under the promissory note facility accrue interest at
4.5%
per annum. As of
December 31, 2013
and
2012
, the amount outstanding under the facility was
$2 million
and
$6 million
, respectively. Also on September 22, 2010, Avenal entered into a
$209 million
financing arrangements with a syndicate of banks, or the Avenal Facility. As of
December 31, 2013
and
2012
, Avenal had outstanding
$112 million
and
$118 million
, respectively, under the Avenal Facility. As of December 31, 2013, the Company had a
$9 million
equity investment in Avenal.
CVSR
—The Company owns
48.95%
of CVSR, located in San Luis Obispo, California, totaling
250
MW, while NRG continues to own the remaining
51.05%
of CVSR. Power generated by the project is sold under a
25
-year PPA. Construction of the project has been funded by the CVSR Financing Agreement. As of December 31, 2013, the Company had a
$100 million
equity investment in CVSR.
As discussed in
Note 3
,
Business Acquisitions
, in connection with the acquisition, High Plains Ranch II, LLC entered into the CVSR Financing Agreement with the FFB to borrow up to
$1.2 billion
to fund the costs of constructing the solar facility. The CVSR Financing Agreement matures in 2037 and the loans provided by the FFB are guaranteed by the U.S. DOE. Amounts borrowed under the CVSR Financing Agreement accrue interest at a fixed rate based on U.S. Treasury rates plus a spread of
0.375%
and are secured by the assets of CVSR. As of
December 31, 2013
and
2012
,
$1,104 million
and
$786 million
, respectively, were outstanding under the loan. In 2012 and 2013, CVSR submitted applications to the U.S. Treasury Department for cash grants as each phase of the project began commercial operations.
In January 2014, the U.S. Treasury Department awarded cash grants on the CVSR project of $307 million ($285 million net of sequestration), which is approximately 75% of the cash grant amount for which the Company had applied. The cash grant proceeds were used to pay the outstanding balance of the bridge loan due in February 2014 and the remaining amount was used to pay a portion of the outstanding balance on the bridge loan due in August 2014. The remaining balance of the bridge loan due in August 2014 was paid by SunPower. CVSR is evaluating the basis for the U.S. Treasury Department’s award and all of its options for recovering the amount by which the U.S. Treasury Department reduced the CVSR cash grant award.
Under the terms of the CVSR Financing Agreement, CVSR entered into a series of swaptions with a notional value of
$686 million
, or
80%
of the guaranteed term loan amount, in order to hedge the project interest rate risk. These swaptions mature over a series of seven scheduled settlement dates to correspond with the completion dates of the project. As of December 31, 2013, all of the swaptions had expired.
The following table presents summarized financial information for CVSR:
|
Year Ended December 31,
|
|||||||||||
|
2013
|
2012
|
2011
(a)
|
|||||||||
|
(In millions)
|
|||||||||||
|
Income Statement Data:
|
|||||||||||
|
Operating revenues
|
$
|
47
|
|
$
|
2
|
|
$
|
—
|
|
||
|
Operating income
|
22
|
|
1
|
|
—
|
|
|||||
|
Net income
|
4
|
|
1
|
|
—
|
|
|||||
|
As of December 31,
|
|||||||||||
|
2013
|
2012
|
||||||||||
|
(In millions)
|
|||||||||||
|
Balance Sheet Data:
|
|||||||||||
|
Current assets
|
$
|
455
|
|
$
|
61
|
|
|||||
|
Non-current assets
|
932
|
|
1,080
|
|
|||||||
|
Current liabilities
|
412
|
|
189
|
|
|||||||
|
Non-current liabilities
|
769
|
|
757
|
|
|||||||
(a) Represents results from September 30, 2011 to December 31, 2011.
74
Variable Interest Entities, or VIEs
GenConn Energy LLC
—
The Company has a
49.95%
interest in GCE Holding LLC, the owner of GenConn Energy LLC, or GenConn, a limited liability company formed to construct, own and operate
two
190
MW peaking generation facilities in Connecticut at NRG’s Devon and Middletown sites. Each of these facilities was constructed pursuant to a 30-year cost of service type contract with the Connecticut Light & Power Company. All
four
units at the GenConn Devon facility reached commercial operation in 2010 and were released to the ISO-NE by July 2010. In June 2011, all
four
units at the GenConn Middletown facility reached commercial operation and were released to the ISO-NE. GenConn is considered a VIE under ASC 810, however the Company is not the primary beneficiary, and accounts for its investment under the equity method.
The project was funded through equity contributions from the owners and non-recourse, project level debt. As of
December 31, 2013
, the Company's investment in GenConn was
$118 million
and its maximum exposure to loss is limited to its equity investment. On September 17, 2013, GenConn refinanced its existing project financing facility. As of
December 31, 2013
, the refinanced facility is comprised of a
$237 million
note with an interest rate of
4.73%
and a maturity date of July 2041 and a 5-year,
$35 million
working capital facility which can be used to issue letters of credit at an interest rate of
1.875%
. The refinancing is secured by all of the GenConn assets.
The following table presents summarized financial information for GCE Holding LLC:
|
Year ended December 31,
|
|||||||||||
|
2013
|
2012
|
2011
|
|||||||||
|
Income Statement Data:
|
(In millions)
|
||||||||||
|
Operating revenues
|
$
|
80
|
|
$
|
78
|
|
$
|
67
|
|
||
|
Operating income
|
45
|
|
45
|
|
37
|
|
|||||
|
Net income
|
31
|
|
29
|
|
24
|
|
|||||
|
December 31, 2013
|
December 31, 2012
|
||||||
|
Balance Sheet Data:
|
(In millions)
|
||||||
|
Current assets
|
$
|
32
|
|
$
|
37
|
|
|
|
Non-current assets
|
453
|
|
459
|
|
|||
|
Current liabilities
|
18
|
|
24
|
|
|||
|
Non-current liabilities
|
231
|
|
223
|
|
|||
The following table presents undistributed equity earnings for the Company's three equity method investments:
|
|
As of December 31,
|
||||||
|
|
2013
|
2012
|
|||||
|
|
(In millions)
|
||||||
|
Undistributed earnings from equity investments
|
$
|
11
|
|
$
|
5
|
|
|
75
Note 6
—
Fair Value of Financial Instruments
For cash and cash equivalents, restricted cash, accounts receivable, accounts payable, intercompany accounts payable and receivable, accrued expenses and other liabilities, the carrying amount approximates fair value because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.
The estimated carrying amounts and fair values of the Company’s recorded financial instruments not carried at fair market value are as follows:
|
As of December 31, 2013
|
As of December 31, 2012
|
||||||||||||||
|
Carrying Amount
|
Fair Value
|
Carrying Amount
|
Fair Value
|
||||||||||||
|
|
(In millions)
|
||||||||||||||
|
Assets:
|
|
|
|
|
|||||||||||
|
Notes receivable, including current portion — affiliate
|
$
|
2
|
|
$
|
2
|
|
$
|
6
|
|
$
|
6
|
|
|||
|
Notes receivable, including current portion
|
8
|
|
8
|
|
17
|
|
17
|
|
|||||||
|
Liabilities:
|
|||||||||||||||
|
Long-term debt, including current portion — affiliate
|
—
|
|
—
|
|
26
|
|
26
|
|
|||||||
|
Long-term debt, including current portion
|
1,133
|
|
1,135
|
|
781
|
|
785
|
|
|||||||
The fair value of notes receivable and long-term debt are based on expected future cash flows discounted at market interest rates, or current interest rates for similar instruments and are classified as Level 3 within the fair value hierarchy.
Fair Value Accounting under ASC 820
ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
|
•
|
Level 1—quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access as of the measurement date.
|
|
•
|
Level 2—inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
|
|
•
|
Level 3—unobservable inputs for the asset or liability only used when there is little, if any, market activity for the asset or liability at the measurement date.
|
In accordance with ASC 820, the Company determines the level in the fair value hierarchy within which each fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement.
Recurring Fair Value Measurements
The Company records its derivative assets and liabilities at fair market value on its consolidated balance sheet. The following table presents assets and liabilities measured and recorded at fair value on the Company's condensed consolidated balance sheets on a recurring basis and their level within the fair value hierarchy:
|
As of December 31, 2013
|
|||||||||||
|
Fair Value
(1)
|
|||||||||||
|
(In millions)
|
Level 2
|
Level 3
|
Total
|
||||||||
|
Derivative assets:
|
|
||||||||||
|
Commodity contracts
|
$
|
1
|
|
$
|
—
|
|
$
|
1
|
|
||
|
Interest rate contracts
|
11
|
|
—
|
|
11
|
|
|||||
|
Total assets
|
$
|
12
|
|
$
|
—
|
|
$
|
12
|
|
||
|
Derivative liabilities:
|
|
||||||||||
|
Commodity contracts
|
$
|
1
|
|
$
|
1
|
|
$
|
2
|
|
||
|
Interest rate contracts
|
37
|
|
—
|
|
37
|
|
|||||
|
Total liabilities
|
$
|
38
|
|
$
|
1
|
|
$
|
39
|
|
||
(1) There were
no
assets or liabilities classified as Level 1 as of December 31, 2013.
76
As of December 31, 2012 assets and liabilities measured and recorded at fair value on the Company's balance sheets were classified as Level 2 within the fair value hierarchy. There were
no
transfers during the years ended
December 31, 2013
and
2012
, between Levels 1 and 2. The following table reconciles, for the year ended
December 31, 2013
, the beginning and ending balances for derivative instruments that are recognized at fair value in the consolidated financial statements, at least annually, using significant unobservable inputs:
|
Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
|
|||
|
(In millions)
|
Year ended December 31, 2013
|
||
|
Derivatives
|
|||
|
Beginning balance
|
$
|
—
|
|
|
Purchases
|
(1
|
)
|
|
|
Ending balance as of December 31, 2013
|
$
|
(1
|
)
|
There have been
no
transfers in and/or out of Level 3 during the year ended
December 31, 2013
.
Derivative Fair Value Measurements
A majority of the Company's contracts are non-exchange-traded and valued using prices provided by external sources. For the Company’s energy markets, management receives quotes from multiple sources. To the extent that multiple quotes are received, the prices reflect the average of the bid-ask mid-point prices obtained from all sources believed to provide the most liquid market for the commodity. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available. These contracts are valued using various valuation techniques including but not limited to internal models that apply fundamental analysis of the market and corroboration with similar markets. As of
December 31, 2013
, contracts valued with prices provided by models and other valuation techniques make up
0%
of the total derivative assets and
3%
of the total derivative liabilities.
The fair value of each contract is discounted using a risk free interest rate. In addition, a credit reserve is applied to reflect credit risk, which is calculated based on credit default swaps. To the extent that the net exposure is an asset, the Company uses the counterparty’s default swap rate. If the exposure is a liability, the Company uses its default swap rate. The credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume the liabilities or that a market participant would be willing to pay for the assets. It is possible that future market prices could vary from those used in recording assets and liabilities and such variations could be material.
Concentration of Credit Risk
In addition to the credit risk discussion as disclosed in
Note 2
,
Summary of Significant Accounting Policies
, the following item is a discussion of the concentration of credit risk for the Company's financial instruments. Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process; (ii) a daily monitoring of counterparties' credit limits; (iii) the use of credit mitigation measures such as margin, collateral, prepayment arrangements, or volumetric limits (iv) the use of payment netting agreements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk by having a diversified portfolio of counterparties. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at NRG to cover the credit risk of the counterparty until positions settle.
Counterparty credit exposure includes credit risk exposure under certain long-term agreements, including solar and other PPAs. As external sources or observable market quotes are not available to estimate such exposure, the Company estimates the exposure related to these contracts based on various techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Based on these valuation techniques, as of
December 31, 2013
, credit risk exposure to these counterparties attributable to the Company's ownership interests was approximately
$797 million
for the next
five years
. This amount excludes potential credit exposures for projects with long term PPAs that have not reached commercial operations. The majority of these power contracts are with utilities with strong credit quality and public utility commission or other regulatory support. However, such regulated utility counterparties can be impacted by changes in government regulations, which the Company is unable to predict.
77
Note 7
—
Accounting for Derivative Instruments and Hedging Activities
ASC 815 requires the Company to recognize all derivative instruments on the balance sheet as either assets or liabilities and to measure them at fair value each reporting period unless they qualify for a NPNS exception. The Company may elect to designate certain derivatives as cash flow hedges, if certain conditions are met, and defer the effective portion of the change in fair value of the derivatives to accumulated OCI, until the hedged transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge is immediately recognized in earnings. For derivatives that are not designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings. Certain derivative instruments may qualify for the NPNS exception and are therefore exempt from fair value accounting treatment. ASC 815 applies to the Company's energy related commodity contracts and interest rate swaps.
Energy-Related Commodities
To manage the commodity price risk associated with its competitive supply activities and the price risk associated with wholesale power sales, the Company may enter into derivative hedging instruments, namely, forward contracts that commit the Company to sell energy commodities or purchase fuels in the future. The objectives for entering into derivatives contracts designated as hedges include fixing the price for a portion of anticipated future electricity sales and fixing the price of a portion of anticipated fuel purchases for the operation of its subsidiaries. At
December 31, 2013
, the Company had forward and financial contracts for the purchase/sale of electricity and related products economically hedging the Company's district energy centers' forecasted output or load obligations through 2015. The Company also had forward contracts for the purchase of fuel commodities relating to the forecasted usage of the district energy centers through 2017. At
December 31, 2013
, these contracts were not designated as cash flow or fair value hedges.
Also, as of December 31, 2013, the Company had other energy-related contracts that did not meet the definition of a derivative instrument or qualified for the NPNS exception and were therefore exempt from fair value accounting treatment as follows:
|
•
|
Power tolling contracts through 2038, and
|
|
•
|
Natural gas transportation contracts through 2028
|
Interest Rate Swaps
The Company is exposed to changes in interest rates through the issuance of variable and fixed rate debt. In order to manage interest rate risk, it enters into interest rate swap agreements.
As of
December 31, 2013
, the Company had interest rate derivative instruments on non-recourse debt extending through 2030, the majority of which are designated as cash flow hedges.
Volumetric Underlying Derivative Transactions
The following table summarizes the net notional volume buy/(sell) of the Company's open derivative transactions broken out by commodity as of
December 31, 2013
and
2012
.
|
Total Volume
|
|||||||||
|
December 31, 2013
|
December 31, 2012
|
||||||||
|
Commodity
|
Units
|
(In millions)
|
|||||||
|
Natural Gas
|
MMBtu
|
2
|
|
2
|
|
||||
|
Interest
|
Dollars
|
$
|
802
|
|
$
|
804
|
|
||
78
Fair Value of Derivative Instruments
The following table summarizes the fair value within the derivative instrument valuation on the balance sheet:
|
|
Fair Value
|
||||||||||||||
|
|
Derivative Assets
|
Derivative Liabilities
|
|||||||||||||
|
December 31, 2013
|
December 31, 2012
|
December 31, 2013
|
December 31, 2012
|
||||||||||||
|
(In millions)
|
|||||||||||||||
|
Derivatives Designated as Cash Flow Hedges:
|
|
|
|
|
|||||||||||
|
Interest rate contracts current
|
$
|
—
|
|
$
|
—
|
|
$
|
18
|
|
$
|
14
|
|
|||
|
Interest rate contracts long-term
|
5
|
|
—
|
|
16
|
|
54
|
|
|||||||
|
Total Derivatives Designated as Cash Flow Hedges
|
5
|
|
—
|
|
34
|
|
68
|
|
|||||||
|
Derivatives Not Designated as Cash Flow Hedges
:
|
|
|
|
|
|||||||||||
|
Interest rate contracts current
|
—
|
|
—
|
|
3
|
|
3
|
|
|||||||
|
Interest rate contracts long-term
|
6
|
|
—
|
|
—
|
|
7
|
|
|||||||
|
Commodity contracts current
|
1
|
|
—
|
|
2
|
|
2
|
|
|||||||
|
Total Derivatives Not Designated as Cash Flow Hedges
|
7
|
|
—
|
|
5
|
|
12
|
|
|||||||
|
Total Derivatives
|
$
|
12
|
|
$
|
—
|
|
$
|
39
|
|
$
|
80
|
|
|||
The Company has elected to present derivative assets and liabilities on the balance sheet on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. The following table summarizes the offsetting of derivatives by counterparty master agreement level:
|
Gross Amounts Not Offset in the Statement of Financial Position
|
|||||||||||
|
As of December 31, 2013
|
Gross Amounts of Recognized Assets/Liabilities
|
Derivative Instruments
|
Net Amount
|
||||||||
|
Commodity contracts:
|
(In millions)
|
||||||||||
|
Derivative assets
|
$
|
1
|
|
$
|
—
|
|
$
|
1
|
|
||
|
Derivative liabilities
|
(2
|
)
|
—
|
|
(2
|
)
|
|||||
|
Total commodity contracts
|
(1
|
)
|
—
|
|
(1
|
)
|
|||||
|
Interest rate contracts:
|
|||||||||||
|
Derivative assets
|
11
|
|
(4
|
)
|
7
|
|
|||||
|
Derivative liabilities
|
(37
|
)
|
4
|
|
(33
|
)
|
|||||
|
Total interest rate contracts
|
(26
|
)
|
—
|
|
(26
|
)
|
|||||
|
Total derivative instruments
|
$
|
(27
|
)
|
$
|
—
|
|
$
|
(27
|
)
|
||
As of
December 31, 2012
, the Company's derivative positions were all in liability positions and there was no outstanding collateral paid or received. Thus, there would be no change to the balance sheet if presenting derivative assets and liabilities on a net basis.
Accumulated Other Comprehensive Income (Loss)
The following table summarizes the effects on the Company’s accumulated other comprehensive loss, or OCL, balance attributable to interest rate swaps designated as cash flow hedge derivatives, net of tax:
|
Year ended December 31,
|
|||||||||||
|
2013
|
2012
|
2011
|
|||||||||
|
(In millions)
|
|||||||||||
|
Accumulated OCL beginning balance
|
$
|
(24
|
)
|
$
|
(15
|
)
|
$
|
—
|
|
||
|
Reclassified from accumulated OCL to income due to realization of previously deferred amounts
|
6
|
|
4
|
|
—
|
|
|||||
|
Mark-to-market of cash flow hedge accounting contracts
|
17
|
|
(13
|
)
|
(15
|
)
|
|||||
|
Accumulated OCL ending balance, net of income tax benefit of $0, $17 and $10, respectively
|
$
|
(1
|
)
|
$
|
(24
|
)
|
$
|
(15
|
)
|
||
|
Accumulated OCL attributable to noncontrolling interest
|
(1
|
)
|
|||||||||
|
Accumulated OCL attributable to Class A common shareholders
|
$
|
—
|
|
||||||||
|
Losses expected to be realized from OCI during the next 12 months, net of income tax of $2, $2 and $1
|
$
|
4
|
|
$
|
3
|
|
$
|
2
|
|
||
79
Impact of Derivative Instruments on the Statements of Operations
Unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedges are reflected in current period earnings in interest expense. For the years ended
December 31, 2013
and
2012
, the impact to the statement of operations was a gain of
$13 million
and a loss of
$9 million
, respectively.
The Company’s derivative commodity contracts relate to its Thermal business for the purchase of fuel commodities based on the forecasted usage of the Thermal district energy centers. Realized gains and losses on these contracts are reflected in the fuel costs that are permitted to be billed to customers through the related customer contracts or tariffs and accordingly, no gains or losses are reflected in the statement of operations for these contracts.
See
Note 6
,
Fair Value of Financial Instruments
, for discussion regarding concentration of credit risk.
Note 8
—
Intangible Assets
Intangible Assets
— The Company's intangible assets as of
December 31, 2013
and
2012
primarily reflect intangible assets established from its business acquisitions and are comprised of the following:
|
•
|
Development rights
— Arising primarily from the acquisition of solar businesses in 2010 and 2011, these intangibles are amortized to depreciation and amortization expense on a straight-line basis over the estimated life of the related project portfolio.
|
|
•
|
Customer contracts
— Established with the acquisition of Northwind Phoenix,
these intangibles represent the fair value at the acquisition date of contracts that primarily provide chilled water, steam and electricity to its customers. These contracts are amortized to revenues based on expected volumes.
|
|
•
|
Customer relationships
— Established with the acquisition of Northwind Phoenix and Energy Systems, these intangibles represent the fair value at the acquisition date of the businesses' customer base. The customer relationships are amortized to depreciation and amortization expense based on the expected discounted future net cash flows by year.
|
|
•
|
PPAs
— Represents the fair value of PPAs acquired prior to the construction of the related projects. These will be amortized over the term of the PPA.
|
|
•
|
Other
— Consists of the acquisition date fair value of the contractual rights to a ground lease for South Trent and to utilize certain interconnection facilities for Blythe.
|
The following tables summarize the components of intangible assets subject to amortization:
|
Year Ended December 31, 2013
|
Development
Rights
|
Customer Contracts
|
Customer
Relationships
|
PPAs
|
Other
|
Total
|
|||||||||||||||||
|
|
(In millions)
|
||||||||||||||||||||||
|
January 1, 2013
|
$
|
4
|
|
$
|
15
|
|
$
|
7
|
|
$
|
4
|
|
$
|
3
|
|
$
|
33
|
|
|||||
|
Acquisition of business
|
—
|
|
—
|
|
59
|
|
—
|
|
—
|
|
59
|
|
|||||||||||
|
December 31, 2013
|
4
|
|
15
|
|
66
|
|
4
|
|
3
|
|
92
|
|
|||||||||||
|
Less accumulated amortization
|
(1
|
)
|
(4
|
)
|
(1
|
)
|
—
|
|
—
|
|
(6
|
)
|
|||||||||||
|
Net carrying amount
|
$
|
3
|
|
$
|
11
|
|
$
|
65
|
|
$
|
4
|
|
$
|
3
|
|
$
|
86
|
|
|||||
|
Year Ended December 31, 2012
|
Development Rights
|
Customer Contracts
|
Customer Relationships
|
PPAs
|
Other
|
Total
|
|||||||||||||||||
|
|
(In millions)
|
||||||||||||||||||||||
|
January 1, 2012
|
$
|
4
|
|
$
|
15
|
|
$
|
7
|
|
$
|
4
|
|
$
|
3
|
|
$
|
33
|
|
|||||
|
Purchases
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|||||||||||
|
December 31, 2012
|
4
|
|
15
|
|
7
|
|
4
|
|
3
|
|
33
|
|
|||||||||||
|
Less accumulated amortization
|
—
|
|
(3
|
)
|
—
|
|
—
|
|
—
|
|
(3
|
)
|
|||||||||||
|
Net carrying amount
|
$
|
4
|
|
$
|
12
|
|
$
|
7
|
|
$
|
4
|
|
$
|
3
|
|
$
|
30
|
|
|||||
80
The Company recorded amortization of
$3 million
during the year ended
December 31, 2013
and
$1 million
during each of the years ended December 31,
2012
and
2011
. The following table presents estimated amortization of the Company's intangible assets for each of the next five years:
|
Year Ended December 31,
|
Total
|
|||
|
(In millions)
|
||||
|
2014
|
$
|
2
|
|
|
|
2015
|
2
|
|
||
|
2016
|
2
|
|
||
|
2017
|
2
|
|
||
|
2018
|
3
|
|
||
The weighted average amortization period related to the intangibles acquired in the year ended December 31, 2013 was
33 years
for customer relationships.
Out-of-market contracts
— The out-of-market contract liability represents the out-of-market value of the PPA for Blythe as of the date of the Blythe acquisition. The liability of
$5 million
is recorded to other non-current liabilities and is amortized to revenue on a units-of-production basis over the
twenty
-year term of the agreement.
Note 9
—
Long-term Debt
The Company's borrowings, including short term and long term portions consisted of the following:
|
December 31, 2013
|
December 31, 2012
|
Current interest rate %
(a)
|
|||||||
|
(In millions, except rates)
|
|||||||||
|
Debt — external:
|
|||||||||
|
NRG Marsh Landing LLC, due 2017 and 2023
|
$
|
473
|
|
$
|
390
|
|
L+ 2.75 - 3.00
|
||
|
NRG Solar Alpine LLC, due 2013 and 2022
|
221
|
|
2
|
|
L+ 2.25 - 2.50
|
||||
|
NRG Energy Center Minneapolis LLC, senior secured notes, due 2013, 2017 and 2025
|
127
|
|
137
|
|
5.95 - 7.31
|
||||
|
NRG Solar Borrego I LLC, due 2024 and 2038
|
78
|
|
—
|
|
L+ 2.50/5.65
|
||||
|
South Trent Wind LLC, due 2020
|
69
|
|
72
|
|
L+ 2.625
|
||||
|
NRG Solar Avra Valley LLC, due 2031
|
63
|
|
66
|
|
L+ 2.25
|
||||
|
NRG Roadrunner LLC, due 2031
|
44
|
|
46
|
|
L+ 2.01
|
||||
|
NRG Solar Blythe LLC, due 2028
|
24
|
|
25
|
|
L+ 2.50
|
||||
|
PFMG and related subsidiaries, due 2030
|
32
|
|
41
|
|
6.00
|
||||
|
NRG Energy Center Princeton LLC, due 2017
|
2
|
|
2
|
|
0.00
|
||||
|
Subtotal debt — external
|
1,133
|
|
781
|
|
|||||
|
Debt — affiliate:
|
|||||||||
|
Note payable to NRG Energy, Inc. — South Trent
|
—
|
|
26
|
|
L+ 2.00
|
||||
|
Subtotal debt — affiliate
|
—
|
|
26
|
|
|||||
|
Total debt
|
1,133
|
|
807
|
|
|||||
|
Less current maturities
|
133
|
|
58
|
|
|||||
|
Total long-term debt
|
$
|
1,000
|
|
$
|
749
|
|
|||
(a) As of
December 31, 2013
, L+ equals
3 month LIBOR
plus x%, with the exception of NRG Solar Alpine LLC cash grant loan which is
1 month LIBOR
plus x%.
The financing arrangements listed above contain certain covenants, including financial covenants that the Company is required to be in compliance with during the term of the arrangement. As of
December 31, 2013
, the Company was in compliance with all of the required covenants.
81
Revolving Credit Facility
In connection with the Company's initial public offering of Class A common stock in July 2013, as further described in
Note 1
,
Nature of Business
, NRG Yield LLC and NRG Yield Operating LLC entered into a senior secured revolving credit facility, which provides a revolving line of credit of
$60 million
. The Company's revolving credit facility can be used for cash or for the issuance of letters of credit. There was
no
cash drawn or letters of credit issued under the revolving credit facility as of
December 31, 2013
.
Convertible Notes
On February 11, 2014, the Company closed on its offering of
$300 million
aggregate principal amount of
3.50%
Convertible Senior Notes due 2019, or the Senior Notes. The initial purchasers exercised their option to purchase an additional
$45 million
in aggregate principal amount of the NRG Yield Senior Notes. NRG Yield, Inc. expects to receive the related proceeds in early March. The Senior Notes are convertible, under certain circumstances, into the Company’s common stock, cash or a combination thereof at an initial conversion price of
$46.55
per Class A common share, which is equivalent to an initial conversion rate of approximately
21.4822
shares of Class A common stock per
$1,000
principal amount of Senior Notes. Interest on the Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year, commencing on August 1, 2014. The Senior Notes will mature on February 1, 2019, unless earlier repurchased or converted in accordance with their terms. Prior to the close of business on the business day immediately preceding August 1, 2018, the Senior Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter, at any time until the close of business on the second scheduled trading day immediately preceding the maturity date.
Marsh Landing Credit Agreement Term Conversion
In May 2013, Marsh Landing met the conditions under the credit agreement to convert the construction loan for the facility to a term loan which will amortize on a predetermined basis. Prior to term conversion, Marsh Landing drew the remaining funds available under the facility in order to pay costs due for construction. Marsh Landing issued a
$24 million
letter of credit under the facility in support of its debt service requirements.
Borrego Financing
On March 28, 2013, NRG Solar Borrego I LLC, or Borrego, entered into a credit agreement with a group of lenders, or the Borrego Financing Agreement, for
$45 million
of
5.65%
fixed rate notes and a
$36 million
term loan. The term loan has an interest rate of
3 month LIBOR
plus an applicable margin of
2.50%
, which escalates
0.25%
on the fourth and eighth anniversary of the closing date. The fixed rate notes mature in February 2038 and the term loan matures in December 2024. Both amortize based upon predetermined schedules. The Borrego Financing Agreement also includes a letter of credit facility on behalf of Borrego of up to
$5 million
. Borrego pays an availability fee of
100%
of the applicable margin on issued letters of credit. As of
December 31, 2013
,
$45 million
was outstanding under the fixed rate notes,
$33 million
was outstanding under the term loans, and
$5
million of letters of credit in support of the project were issued.
Under the terms of the Borrego Financing Agreement on March 28, 2013, Borrego was required to enter into
two
fixed for floating interest rate swaps that would fix the interest rate for a minimum of
75%
of the outstanding notional amount. Borrego will pay its counterparty the equivalent of a
1.125%
fixed interest payment on a predetermined notional value, and quarterly, Borrego will receive the equivalent of a floating interest payment based on a
3 month LIBOR
calculated on the same notional value through June 30, 2020. All interest rate swap payments by Borrego and its counterparties are made quarterly and the LIBOR rate is determined in advance of each interest period. The original notional amount of the swaps, which became effective April 3, 2013, is
$15 million
and will amortize in proportion to the term loan.
Subsequent to the borrowing, Borrego returned approximately
$76 million
of capital to NRG. In 2013, prior to the return of capital, NRG had contributed approximately
$19 million
into Borrego.
82
Alpine Financing
On March 16, 2012, NRG Solar Alpine LLC, or Alpine, entered into a credit agreement with a group of lenders for a
$166 million
construction loan that was convertible to a term loan upon completion of the project and a
$68 million
cash grant loan. On January 15, 2013, the credit agreement was amended reducing the cash grant loan to
$63 million
. On March 26, 2013, Alpine met the conditions under the credit agreement to convert the construction loan to a term loan. Immediately prior to the conversion, the Company drew an additional
$164 million
under the construction loan and
$62 million
under the cash grant loan. The term loan amortizes on a predetermined schedule with final maturity in November 2022. As of
December 31, 2013
,
$159
million was outstanding under the term loan,
$62
million under the cash grant loan, and
$37
million of letters of credit were issued under the credit agreement.
Subsequent to the conversion, Alpine returned approximately
$242 million
of capital to NRG. In 2013, prior to the conversion, NRG had contributed approximately
$112 million
into Alpine.
Note Payable to NRG
—
South Trent
On June 14, 2010, NRG South Trent Holdings LLC entered into a
$34 million
promissory note with a wholly owned subsidiary of NRG, with a maturity date of 2020. On July 17, 2013, NRG converted the remaining receivable under the promissory note of approximately
$25 million
into equity in NRG South Trent Holdings LLC and terminated the note.
Interest Rate Swaps
—
Project Financings
Many of the Company's project subsidiaries entered into interest rate swaps, intended to hedge the risks associated with interest rates on non-recourse project level debt. These swaps amortize in proportion to their respective loans and are floating for fixed where the project subsidiary pays its counterparty the equivalent of a fixed interest payment on a predetermined notional value and will receive quarterly the equivalent of a floating interest payment based on the same notional value. All interest rate swap payments by the project subsidiary and its counterparty are made quarterly and the LIBOR is determined in advance of each interest period. The following table summarizes the swaps, some of which are forward starting as indicated, related to the Company's project level debt as of
December 31, 2013
and
2012
.
|
% of Principal
|
Fixed Interest Rate
|
Floating Interest Rate
|
Notional
Amount at December 31, 2013 (In millions) |
Effective Date
|
Maturity Date
|
||||||||||
|
NRG Marsh Landing
|
75
|
%
|
3.244
|
%
|
3-mo. LIBOR
|
473
|
|
June 28, 2013
|
June 30, 2023
|
||||||
|
South Trent Wind LLC
|
75
|
%
|
3.265
|
%
|
3-mo. LIBOR
|
51
|
|
June 15, 2010
|
June 14, 2020
|
||||||
|
South Trent Wind LLC
|
75
|
%
|
4.95
|
%
|
3-mo. LIBOR
|
21
|
|
June 30, 2020
|
June 14, 2028
|
||||||
|
NRG Solar Roadrunner LLC
|
75
|
%
|
4.313
|
%
|
3-mo. LIBOR
|
33
|
|
September 30, 2011
|
December 31, 2029
|
||||||
|
NRG Solar Blythe LLC
|
75
|
%
|
3.563
|
%
|
3-mo. LIBOR
|
18
|
|
June 25, 2010
|
June 25, 2028
|
||||||
|
NRG Solar Avra Valley LLC
|
90
|
%
|
2.333
|
%
|
3-mo. LIBOR
|
56
|
|
November 30, 2012
|
November 30, 2030
|
||||||
|
NRG Solar Alpine LLC
|
85
|
%
|
2.744
|
%
|
3-mo. LIBOR
|
135
|
|
December 31, 2012
|
December 31, 2029
|
||||||
|
NRG Solar Borrego LLC
|
75
|
%
|
1.125
|
%
|
3-mo. LIBOR
|
14
|
|
April 3, 2013
|
June 30, 2020
|
||||||
Annual Maturities
Annual payments based on the maturities of the Company's debt, for the years ending after
December 31, 2013
are as follows:
|
|
(In millions)
|
||
|
2014
|
$
|
133
|
|
|
2015
|
78
|
|
|
|
2016
|
81
|
|
|
|
2017
|
84
|
|
|
|
2018
|
79
|
|
|
|
Thereafter
|
678
|
|
|
|
Total
|
$
|
1,133
|
|
83
Note 10
—
Earnings Per Share
Basic and diluted earnings per common share are computed by dividing net income by the weighted average number of common shares outstanding. Shares issued during the year are weighted for the portion of the year that they were outstanding.
The reconciliation of the Company's basic and diluted earnings per share is shown in the following table:
|
Period from July 23, 2013 to December 31, 2013
|
|||
|
(In millions, except per share data)
|
|||
|
Basic and diluted earnings per share attributable to NRG Yield, Inc. Class A common stockholders
|
|||
|
Net income attributable to NRG Yield, Inc.
|
$
|
13
|
|
|
Weighted average number of Class A common shares outstanding
|
23
|
|
|
|
Earnings per weighted average Class A common share — basic and diluted
|
$
|
0.57
|
|
There were
no
anti-dilutive outstanding equity instruments as of
December 31, 2013
.
Note 11
—
Stockholders' Equity
On July 22, 2013, in connection with its initial public offering, the Company authorized
500,000,000
shares of Class A common stock, par value
$0.01
per share, of which
22,511,250
were issued to the public in connection with the initial public offering and became outstanding. In return for the issuance of these shares, the Company received
$468 million
, net of underwriting discounts and commissions of
$27 million
. In addition, in connection with the initial public offering, the Company authorized
500,000,000
shares of Class B common stock, par value
$0.01
per share, of which
42,738,750
were issued to NRG concurrently with the initial public offering and became outstanding. The Company utilized
$395 million
of the proceeds from the issuance of the Class A common stock to acquire a controlling interest in NRG Yield LLC from NRG. Each share of both of the Class A common stock and Class B common stock entitles the holder to one vote on all matters. Class A common stockholders hold
100%
of the economic interest and a
34.5%
voting interest in the Company. Class B common stockholders hold a
65.5%
voting interest in NRG, Yield, Inc.
On December 16, 2013, NRG Yield, Inc. paid a quarterly dividend on its Class A and Class B common stock of
$0.23
per share.
On January 30, 2014, NRG Yield, Inc. declared a quarterly dividend on the Company's Class A and Class B common stock of
$0.33
per share payable on March 17, 2014 to shareholders of record as of March 3, 2014.
The common stock dividend is subject to available capital, market conditions, and compliance with associated laws and regulations.
The Company also authorized
10,000,000
shares of preferred stock, par value
$0.01
per share.
None
of the shares of preferred stock have been issued.
84
Note 12
—
Segment Reporting
The Company’s segment structure reflects how management currently makes financial decisions and allocates resources. Its businesses are primarily segregated based on conventional power generation, renewable businesses which consist of solar and wind, and the thermal and chilled water business. The Corporate segment reflects the Company's corporate costs.
For the year ended
December 31, 2013
the Company derived more than
34%
of its consolidated revenues from Pacific Gas and Electric, including
$82 million
in the Conventional Generation segment and
$24 million
in the Renewable segment. For the years ended December 31,
2012
and
2011
, the Company derived
10%
or
$16 million
of its consolidated revenues from AEP Energy Partners in the Renewable segment.
|
|
Year ended December 31, 2013
|
||||||||||||||||||
|
(In millions)
|
Conventional Generation
|
|
Renewables
|
|
Thermal
|
|
Corporate
|
|
Total
|
||||||||||
|
Operating revenues
|
$
|
82
|
|
|
$
|
79
|
|
|
$
|
152
|
|
|
$
|
—
|
|
|
$
|
313
|
|
|
Cost of operations
|
7
|
|
|
10
|
|
|
110
|
|
|
—
|
|
|
127
|
|
|||||
|
Depreciation and amortization
|
14
|
|
|
22
|
|
|
15
|
|
|
—
|
|
|
51
|
|
|||||
|
General and administrative — affiliate
|
—
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
7
|
|
|||||
|
Equity in earnings of unconsolidated affiliates
|
16
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
22
|
|
|||||
|
Interest expense
|
(13
|
)
|
|
(15
|
)
|
|
(7
|
)
|
|
—
|
|
|
(35
|
)
|
|||||
|
Income/(loss) before income taxes
|
64
|
|
|
40
|
|
|
20
|
|
|
(7
|
)
|
|
117
|
|
|||||
|
Net income/(loss)
|
$
|
64
|
|
|
$
|
40
|
|
|
$
|
20
|
|
|
$
|
(15
|
)
|
|
$
|
109
|
|
|
Balance Sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Equity investment in affiliates
|
$
|
118
|
|
|
$
|
109
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
227
|
|
|
Capital expenditures
(a)
|
62
|
|
|
19
|
|
|
15
|
|
|
—
|
|
|
96
|
|
|||||
|
Total assets
|
$
|
839
|
|
|
$
|
866
|
|
|
$
|
436
|
|
|
$
|
172
|
|
|
$
|
2,313
|
|
(a) Includes accruals.
|
Year ended December 31, 2012
|
|||||||||||||||||||
|
(In millions)
|
Conventional Generation
|
Renewables
|
Thermal
|
Corporate
|
Total
|
||||||||||||||
|
Operating revenues
|
$
|
—
|
|
$
|
33
|
|
$
|
142
|
|
$
|
—
|
|
$
|
175
|
|
||||
|
Cost of operations
|
—
|
|
9
|
|
103
|
|
—
|
|
112
|
|
|||||||||
|
Depreciation and amortization
|
—
|
|
10
|
|
15
|
|
—
|
|
25
|
|
|||||||||
|
General and administrative — affiliate
|
—
|
|
—
|
|
—
|
|
7
|
|
7
|
|
|||||||||
|
Equity in earnings of unconsolidated affiliates
|
15
|
|
4
|
|
—
|
|
—
|
|
19
|
|
|||||||||
|
Interest expense
|
—
|
|
(20
|
)
|
(8
|
)
|
—
|
|
(28
|
)
|
|||||||||
|
Income/(loss) before income taxes
|
15
|
|
(1
|
)
|
16
|
|
(7
|
)
|
23
|
|
|||||||||
|
Net income/(loss)
|
$
|
15
|
|
$
|
(1
|
)
|
$
|
16
|
|
$
|
(17
|
)
|
$
|
13
|
|
||||
|
Balance sheet
|
|||||||||||||||||||
|
Equity investments in affiliates
|
$
|
125
|
|
$
|
95
|
|
$
|
—
|
|
$
|
—
|
|
$
|
220
|
|
||||
|
Capital expenditures
(a)
|
—
|
|
453
|
|
25
|
|
—
|
|
478
|
|
|||||||||
|
Total assets
|
$
|
744
|
|
$
|
893
|
|
$
|
326
|
|
$
|
1
|
|
$
|
1,964
|
|
||||
(a) Includes accruals.
|
Year ended December 31, 2011
|
|||||||||||||||||||
|
(In millions)
|
Conventional Generation
|
Renewables
|
Thermal
|
Corporate
|
Total
|
||||||||||||||
|
Operating revenues
|
$
|
—
|
|
$
|
26
|
|
$
|
138
|
|
$
|
—
|
|
$
|
164
|
|
||||
|
Cost of operations
|
—
|
|
6
|
|
102
|
|
—
|
|
108
|
|
|||||||||
|
Depreciation and amortization
|
—
|
|
8
|
|
14
|
|
—
|
|
22
|
|
|||||||||
|
General and administrative — affiliate
|
—
|
|
—
|
|
—
|
|
6
|
|
6
|
|
|||||||||
|
Equity in earnings of unconsolidated affiliates
|
12
|
|
1
|
|
—
|
|
—
|
|
13
|
|
|||||||||
|
Interest expense
|
(1
|
)
|
(9
|
)
|
(9
|
)
|
—
|
|
(19
|
)
|
|||||||||
|
Income/(loss) before income taxes
|
12
|
|
5
|
|
13
|
|
(6
|
)
|
24
|
|
|||||||||
|
Net income/(loss)
|
$
|
12
|
|
$
|
5
|
|
$
|
13
|
|
$
|
(15
|
)
|
$
|
15
|
|
||||
85
Note 13
—
Income Taxes
Effective Tax Rate
The income tax provision from continuing operations consisted of the following amounts:
|
|
Year Ended December 31,
|
||||||||||
|
|
2013
|
2012
|
2011
|
||||||||
|
|
(In millions, except percentages)
|
||||||||||
|
Current
|
|
|
|
||||||||
|
U.S. Federal
|
$
|
—
|
|
$
|
7
|
|
$
|
8
|
|
||
|
Total — current
|
—
|
|
7
|
|
8
|
|
|||||
|
Deferred
|
|
|
|
||||||||
|
U.S. Federal
|
14
|
|
1
|
|
—
|
|
|||||
|
State
|
(6
|
)
|
2
|
|
1
|
|
|||||
|
Total — deferred
|
8
|
|
3
|
|
1
|
|
|||||
|
Total income tax expense
|
$
|
8
|
|
$
|
10
|
|
$
|
9
|
|
||
|
Effective tax rate
|
6.8
|
%
|
43.5
|
%
|
37.5
|
%
|
|||||
A reconciliation of the U.S. federal statutory rate of
35%
to the Company's effective rate is as follows:
|
|
Year Ended December 31,
|
||||||||||
|
|
2013
(a)
|
2012
(b)
|
2011
(b)
|
||||||||
|
|
(In millions, except percentages)
|
||||||||||
|
Income Before Income Taxes
|
$
|
117
|
|
$
|
23
|
|
$
|
24
|
|
||
|
Tax at 35%
|
41
|
|
8
|
|
8
|
|
|||||
|
State taxes, net of federal benefit
|
(6
|
)
|
2
|
|
1
|
|
|||||
|
Impact of non-taxable equity earnings
|
(27
|
)
|
—
|
|
—
|
|
|||||
|
Income tax expense
|
$
|
8
|
|
$
|
10
|
|
$
|
9
|
|
||
|
Effective income tax rate
|
6.8
|
%
|
43.5
|
%
|
37.5
|
%
|
|||||
(a)
-
Represents 34.5% ownership for the period July 22, 2013 through December 31, 2013
(b) - Represents proforma tax provision for NRG Yield LLC
For the year ended
December 31, 2013
, the overall effective tax rate was different than the statutory rate of
35%
primarily due to taxable earnings allocated to NRG resulting from its
65.5%
interest in NRG Yield LLC.
For the year ended
December 31, 2012
, the overall effective tax rate was different than the statutory rate of
35%
primarily due to the impact of state and local income taxes.
On July 22, 2013, the Company acquired a controlling interest in NRG Yield LLC and its subsidiary NRG Yield Operating LLC. As a result, the Company owns
34.5%
of NRG Yield LLC and consolidates the results due to its controlling interest. The Company records NRG's
65.5%
ownership as noncontrolling interest in the financial statements. NRG Yield LLC is treated as a partnership for income tax purposes. As such, the Company records income tax on its
34.5%
of the NRG Yield LLC taxable income. NRG records income tax on its
65.5%
share of taxable income generated by NRG Yield LLC.
86
The temporary differences, which gave rise to the Company's deferred tax assets and liabilities consisted of the following:
|
|
As of December 31,
|
||||||
|
|
2013
|
2012
|
|||||
|
|
(In millions)
|
||||||
|
Deferred tax liabilities:
|
|
|
|||||
|
Difference between book and tax basis of property
|
—
|
|
84
|
|
|||
|
Intangibles amortization
|
—
|
|
1
|
|
|||
|
Investment in projects
|
—
|
|
75
|
|
|||
|
Total deferred tax liabilities
|
—
|
|
160
|
|
|||
|
Deferred tax assets:
|
|
|
|||||
|
Investment in projects
|
146
|
|
1
|
|
|||
|
Differences between book and tax basis of contracts
|
—
|
|
2
|
|
|||
|
Derivatives, net
|
—
|
|
41
|
|
|||
|
U.S. Federal net operating loss carryforwards
|
—
|
|
99
|
|
|||
|
State net operating loss carryforwards
|
—
|
|
14
|
|
|||
|
Total deferred tax assets
|
146
|
|
157
|
|
|||
|
Net deferred tax asset (liability)
|
$
|
146
|
|
$
|
(3
|
)
|
|
For the year ended December 31, 2013, the deferred tax asset primarily relates to differences between book and tax basis of property, plant and equipment of
$49 million
in addition to NOLs of
$60 million
for federal income tax purposes and
$4 million
for state income tax purposes.
As a result of the initial public offering, the tax basis of the Company's property, plant and equipment was increased. The increase in tax basis resulted in a non-cash addition of
$153 million
to the Company's additional paid-in capital.
The following table summarizes the Company's net deferred tax position:
|
|
As of December 31,
|
||||||
|
|
2013
|
2012
|
|||||
|
|
(In millions)
|
||||||
|
Net deferred tax asset — current
|
$
|
—
|
|
$
|
1
|
|
|
|
Net deferred tax asset — noncurrent
|
146
|
|
—
|
|
|||
|
Net deferred tax liability — noncurrent
|
—
|
|
4
|
|
|||
|
Net deferred tax asset (liability)
|
$
|
146
|
|
$
|
(3
|
)
|
|
Tax Receivable and Payable
As of December 31, 2013, the Company has a domestic tax receivable of
$102 million
which relates to federal cash grants applied for eligible solar energy projects.
Deferred tax assets and valuation allowance
Net deferred tax balance
— As of
December 31, 2013
, and
2012
, NRG recorded a net deferred tax asset of
$146 million
and a net deferred tax liability of
$3 million
, respectively. The Company believes it is more likely than not that the results of future operations will generate sufficient taxable income which includes the future reversal of existing taxable temporary differences to realize deferred tax assets. In arriving at this conclusion to utilize projections of future profit before tax in its estimate of future taxable income, the Company considered the profit before tax generated in recent years.
NOL carryforwards
— At
December 31, 2013
, the Company had domestic NOLs consisting of carryforwards for federal income tax purposes of
$60 million
and cumulative state NOLs of
$4 million
.
Uncertain tax positions
The Company has not identified any uncertain tax positions that require evaluation as of
December 31, 2013
.
87
Note 14
—
Related Party Transactions
Management Services Agreement with NRG
Subsequent to the initial public offering, NRG provides the Company with various operation, management, and administrative services, which include human resources, accounting, tax, legal, information systems, treasury, and risk management, as set forth in the Management Services Agreement. The base management fee will equal approximately
$1 million
per quarter subject to an inflation based adjustment annually beginning on January 1, 2014 at an inflation factor based on the year-over-year U.S. consumer price index. The fee will also be subject to adjustments following the consummation of future acquisitions and as a result of a change in the scope of services provided under the Management Services Agreement. Costs incurred under this agreement were approximately
$3 million
for the period beginning July 23, 2013 and ending
December 31, 2013
.
Accounts Payable to NRG Solar LLC
During the third quarter of 2013, NRG Solar LLC, a wholly-owned subsidiary of NRG, made capital contributions to CVSR on behalf of the Company. As of
December 31, 2013
, the Company had accounts payable of
$14 million
related to the reimbursement of these capital contributions.
Accounts Payable to NRG Repowering Holdings LLC
During 2013, NRG Repowering Holdings, LLC, a wholly-owned subsidiary of NRG, made payments to BA Leasing BSC, LLC of
$18 million
, which are expected to be received associated with cash grants applications by PFMG DG Solar Projects. As of December 31, 2013, PFMG DG Solar Projects has a corresponding receivable for the reimbursement of the cash grant from BA Leasing BSC, LLC.
GenConn
GenConn incurs fees under Operations and Maintenance (O&M) agreements with two wholly owned subsidiaries of NRG. The fees incurred under the O&M agreements were
$5 million
,
$5 million
and
$4 million
for the years ended
December 31, 2013
,
2012
and
2011
, respectively.
Thermal
NRG Energy Center Dover LLC, or NRG Dover, a subsidiary of the Company is party to a Power Sales and Services Agreement with NRG Power Marketing LLC, or NRG Power Marketing, a wholly-owned subsidiary of NRG. The agreement is automatically renewed on a month-to-month basis unless terminated by either party upon at least 30 day written notice. Under the agreement, NRG Power Marketing has the exclusive right to (i) manage, market and sell power, (ii) procure fuel and fuel transportation for operation of the Dover generating facility, to include for purposes other than generating power, (iii) procure transmission services required for the sale of power, and (iv) procure and market emissions credits for operation of the Dover generating facility.
In addition, NRG Power Marketing has the exclusive right and obligation to direct the output from the generating facility, in accordance with and to meet the terms of any power sales contracts executed against the power generation of the Dover facility. Under the agreement, NRG Power Marketing pays NRG Dover gross receipts generated through sales, less costs incurred by NRG Power Marketing related to providing such services as transmission and delivery costs, as well as fuel costs. During 2011, the existing coal purchase contract expired and NRG Power Marketing entered into a new contract, which expired in December 2012, to purchase coal for the Dover Facility. For the years ended December 31, 2012 and
2011
, NRG Dover purchased approximately
$2 million
and
$4 million
, respectively, under these agreements. In July 2013, the originally coal-fueled plant was converted to become a natural gas facility. For the year ended
December 31, 2013
, NRG Dover purchased approximately
$5 million
of natural gas from its related party.
88
Note 15
—
Commitments and Contingencies
Operating Lease Commitments
The Company leases certain facilities and equipment under operating leases, some of which include escalation clauses, expiring on various dates through 2035. The effects of these scheduled rent increases, leasehold incentives, and rent concessions are recognized on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed. Lease expense under operating leases was
$2 million
for each of the years ended
December 31, 2013
,
2012
and
2011
.
Future minimum lease commitments under operating leases for the years ending after
December 31, 2013
, are as follows:
|
Period
|
(In millions)
|
||
|
2014
|
$
|
2
|
|
|
2015
|
2
|
|
|
|
2016
|
2
|
|
|
|
2017
|
2
|
|
|
|
2018
|
1
|
|
|
|
Thereafter
|
9
|
|
|
|
Total
|
$
|
18
|
|
Gas and Transportation Commitments
The Company has entered into contractual arrangements to procure power, fuel and associated transportation services. For the years ended
December 31, 2013
,
2012
and
2011
, the Company purchased
$36 million
,
$30 million
, and
$36 million
, respectively, under such arrangements.
As of
December 31, 2013
, the Company's commitments under such outstanding agreements are estimated as follows:
|
Period
|
(In millions)
|
||
|
2014
|
$
|
16
|
|
|
2015
|
4
|
|
|
|
2016
|
3
|
|
|
|
2017
|
3
|
|
|
|
2018
|
3
|
|
|
|
Thereafter
|
26
|
|
|
|
Total
|
$
|
55
|
|
Contingencies
In the normal course of business, the Company is subject to various claims and litigation. Management expects that these various litigation items will not have a material adverse effect on the Company's results of operations or financial position.
89
Note 16
—
Unaudited Quarterly Data
Refer to Item 15 -
Note 2
,
Summary of Significant Accounting Policies
and
Note 3
,
Business Acquisitions
for a description of the effect of unusual or infrequently occurring events during the quarterly periods. Summarized unaudited quarterly financial data is as follows:
|
|
Quarter Ended
|
||||||||||||||
|
|
December 31,
|
September 30,
(a)
|
June 30,
|
March 31,
|
|||||||||||
|
|
2013
|
||||||||||||||
|
|
(In millions, except per share data)
|
||||||||||||||
|
Operating revenues
|
$
|
86
|
|
$
|
95
|
|
$
|
79
|
|
$
|
53
|
|
|||
|
Operating income
|
33
|
|
45
|
|
38
|
|
12
|
|
|||||||
|
Net income
|
24
|
|
40
|
|
$
|
34
|
|
$
|
11
|
|
|||||
|
Net income attributable to NRG Yield Inc. subsequent to initial public offering
|
$
|
4
|
|
$
|
9
|
|
n/a
|
|
n/a
|
|
|||||
|
Weighted average number of common shares outstanding — basic and diluted
|
23
|
|
23
|
|
n/a
|
|
n/a
|
|
|||||||
|
Net income per weighted average common share — basic and diluted
|
$
|
0.17
|
|
$
|
0.39
|
|
n/a
|
|
n/a
|
|
|||||
(a) Net income per weighted average common share is calculated for the period of July 22, 2013 to September 30, 2013.
|
|
Quarter Ended
|
||||||||||||||
|
|
December 31,
|
September 30,
|
June 30,
|
March 31,
|
|||||||||||
|
|
2012
|
||||||||||||||
|
|
(In millions, except per share data)
|
||||||||||||||
|
Operating revenues
|
$
|
42
|
|
$
|
47
|
|
$
|
42
|
|
$
|
44
|
|
|||
|
Operating income
|
3
|
|
11
|
|
8
|
|
9
|
|
|||||||
|
Net income/(loss)
|
$
|
5
|
|
$
|
4
|
|
$
|
(1
|
)
|
$
|
5
|
|
|||
90
Schedule I
NRG Yield, Inc. (Parent)
Condensed Financial Information of Registrant
Condensed Statements of Income
For the Year Ended December 31, 2013
|
(In millions)
|
2013
|
||
|
Equity earnings in consolidated subsidiaries
|
$
|
63
|
|
|
Income before income taxes
|
63
|
|
|
|
Income tax expense
|
8
|
|
|
|
Net Income
|
55
|
|
|
|
Less: Net income attributable to noncontrolling interest
|
42
|
|
|
|
Net Income Attributable to NRG Yield, Inc.
|
$
|
13
|
|
See accompanying notes to condensed financial statements.
91
Schedule I
NRG Yield, Inc.
Condensed Balance Sheet
As of December 31, 2013
|
(In millions)
|
2013
|
||
|
Assets
|
|||
|
Noncurrent Assets:
|
|||
|
Investment in consolidated subsidiaries
|
865
|
|
|
|
Deferred income taxes
|
146
|
|
|
|
Total assets
|
$
|
1,011
|
|
|
Equity:
|
|||
|
Preferred stock, $0.01 par value; 10,000,000 shares authorized at December 31, 2013; none issued at December 31, 2013
|
—
|
|
|
|
Class A common stock, $0.01 par value; 500,000,000 shares authorized at December 31, 2013; 22,511,250 shares issued at December 31, 2013
|
—
|
|
|
|
Class B common stock, $0.01 par value; 500,000,000 shares authorized at December 31, 2013; 42,738,750 shares issued at December 31, 2013
|
—
|
|
|
|
Additional paid-in capital
|
621
|
|
|
|
Retained earnings
|
8
|
|
|
|
Noncontrolling Interest
|
382
|
|
|
|
Total stockholders' equity
|
1,011
|
|
|
|
Total liabilities and equity
|
$
|
1,011
|
|
See accompanying notes to condensed financial statements.
92
Schedule I
NRG Yield, Inc.
Condensed Statement of Cash Flows
For the Year Ended December 31, 2013
|
Years ended December 31,
|
|||
|
(In millions)
|
|||
|
Cash Flows from Operating Activities
|
|||
|
Net cash provided by operating activities
|
$
|
5
|
|
|
Cash Flows from Investing Activities
|
|||
|
Investments in consolidated affiliates
|
(468
|
)
|
|
|
Net cash used by investing activities
|
(468
|
)
|
|
|
Cash Flows from Financing Activities
|
|||
|
Proceeds from issuance of Class A common stock
|
468
|
|
|
|
Payment of dividends to Class A common stockholders
|
(5
|
)
|
|
|
Net cash used in financing activities
|
463
|
|
|
|
Net Decrease in Cash and Cash Equivalents
|
—
|
|
|
|
Cash and Cash Equivalents at Beginning of Period
|
—
|
|
|
|
Cash and Cash Equivalents at End of Period
|
$
|
—
|
|
See accompanying notes to condensed financial statements.
93
Schedule I
NRG Yield, Inc. (Parent)
Notes to Condensed Financial Statements
Background
The condensed parent company financial statements have been prepared in accordance with Rule 12-04, Schedule I of
Regulation S-X, as the restricted net assets of NRG Yield, Inc.’s subsidiaries exceed 25% of the consolidated net assets of
NRG Yield, Inc. These statements should be read in conjunction with the consolidated statements and notes thereto of NRG Yield, Inc.
NRG Yield, Inc., or the Company, was formed by NRG as a Delaware corporation on December 20, 2012. On July 22, 2013, the Company issued
22,511,250
shares of Class A common stock in an initial public offering. The Company utilized the net proceeds of the initial public offering to acquire
19,011,250
Class A units of NRG Yield LLC from NRG in return for
$395 million
, and
3,500,000
Class A units of NRG Yield LLC directly from NRG Yield LLC in return for
$73 million
. In connection with the acquisition of the Class A units, the Company also became the sole managing member of NRG Yield LLC thereby acquiring a controlling interest in NRG Yield LLC.
Immediately prior to the acquisition, NRG Yield LLC acquired a portfolio of contracted renewable and conventional generation and thermal infrastructure assets, primarily located in the Northeast, Southwest and California regions of the United States, from NRG in return for Class B units in NRG Yield LLC. These assets were simultaneously contributed by NRG Yield LLC to its direct wholly owned subsidiary NRG Yield Operating LLC. Following the initial public offering, the Company owns
34.5%
of NRG Yield LLC and consolidates the results of NRG Yield LLC through its controlling interest, with NRG's
65.5%
interest shown as noncontrolling interest in the financial statements. NRG Yield, Inc.'s sole purpose is to own 34.5% of NRG Yield LLC.
Basis of Presentation
The condensed financial statements of NRG Yield, Inc. (parent) include the results of NRG Yield, Inc. (parent) for the periods from July 22, 2013 through December 31, 2013. Equity in income/loss of affiliates consists of earnings of direct subsidiaries of NRG Yield, Inc. (parent).
For a discussion of NRG Yield Inc.’s financing arrangements, see Note 9,
Debt and Capital Leases,
to the Company's consolidated financial statements.
See Note 13,
Income Taxes
and Note 15,
Commitments and Contingencies
to the Company's consolidated financial statements for a detailed discussion of NRG Yield, Inc.’s commitments and contingencies.
94
Index to Consolidated Financial Statements
Unaudited Consolidated Financial Statements of GCE Holding LLC
Consolidated Statement of Income - Year ended December 31, 2013
Consolidated Balance Sheet - December 31, 2013
Consolidated Statement of Cash Flows - December 31, 2013
Consolidated Statement of Changes in Equity - December 31, 2013
Notes to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
Audited Consolidated Financial Statements of GCE Holding LLC
Consolidated Statements of Income - Years ended December 31, 2012, 2011 and 2010
Consolidated Balance Sheets - December 31, 2012 and 2011
Consolidated Statement of Cash Flows - December 31, 2012, 2011 and 2010
Consolidated Statement of Changes in Equity - December 31, 2012, 2011 and 2010
Notes to Consolidated Financial Statements
The consolidated financial statements of GCE Holding LLC for the year ended December 31, 2013 are presented herein without the related report of independent accountants in compliance with Rule 3-09 of Regulation S-X.
95
Table of Contents
UNAUDITED
Consolidated Financial Statements:
Report of Independent Auditors
Statements of Income for the years ended December 31, 2013
Balance Sheets as of December 31, 2013
Statements of Cash Flows for the years ended December 31, 2013
Statements of Changes in Partnership Equity for the years ended
December 31, 2013
Notes to the Financial Statements
96
GCE Holding LLC
Consolidated Statement of Operations (Unaudited)
For the Year Ended December 31, 2013
(In thousands)
|
2013
|
|||
|
Operating revenues
|
$
|
80,447
|
|
|
Operating expense
|
15,173
|
|
|
|
Depreciation and amortization expense
|
16,046
|
|
|
|
Taxes other than income
|
4,477
|
|
|
|
Income from operations
|
44,751
|
|
|
|
Other income and (deductions)
|
(24
|
)
|
|
|
Interest expense
|
14,127
|
|
|
|
Income
|
$
|
30,600
|
|
The accompanying Notes to the Consolidated Financial Statements are an integral part of the financial statements.
97
GCE Holding LLC
Consolidated Balance Sheet (Unaudited)
As of December 31, 2013 (In thousands)
|
2013
|
|||
|
Assets
|
|||
|
Current assets:
|
|||
|
Cash
|
$
|
16,367
|
|
|
Restricted cash
|
—
|
|
|
|
Regulatory assets
|
364
|
|
|
|
Accounts receivable
|
9,065
|
|
|
|
Other current assets
|
351
|
|
|
|
Fuel oil inventory
|
3,642
|
|
|
|
Materials & supplies inventory
|
2,077
|
|
|
|
Unamortized debt expense
|
456
|
|
|
|
32,322
|
|
||
|
Property, plant and equipment:
|
|||
|
In-service
|
477,774
|
|
|
|
Accumulated depreciation and amortization
|
(46,592
|
)
|
|
|
431,182
|
|
||
|
Long term assets:
|
|||
|
Unamortized debt expense
|
11,955
|
|
|
|
Regulatory assets
|
9,977
|
|
|
|
21,932
|
|
||
|
Total assets
|
$
|
485,436
|
|
|
Liabilities and Equity
|
|||
|
Current liabilities:
|
|||
|
Accounts payable
|
$
|
3,108
|
|
|
Accrued liabilities
|
2,074
|
|
|
|
Regulatory liabilities
|
1,016
|
|
|
|
Other current liabilities
|
507
|
|
|
|
Current portion of long term debt
|
8,002
|
|
|
|
Current portion of related party notes payable
|
—
|
|
|
|
Interest payable on long term debt
|
3,232
|
|
|
|
Derivative liability
|
—
|
|
|
|
17,939
|
|
||
|
Long term liabilities:
|
|||
|
Long term debt
|
228,498
|
|
|
|
Regulatory liability
|
1,901
|
|
|
|
Asset retirement obligation
|
612
|
|
|
|
Other long-term liabilities
|
49
|
|
|
|
231,060
|
|
||
|
Equity:
|
|||
|
Paid-in capital
|
236,437
|
|
|
|
Retained earnings
|
—
|
|
|
|
236,437
|
|
||
|
Total liabilities and equity
|
$
|
485,436
|
|
The accompanying Notes to the Consolidated Financial Statements are an integral part of the financial statements.
98
GCE Holding LLC
Consolidated Statement of Cash Flows (Unaudited)
For the Year Ended December 31, 2013
(In thousands)
|
Year ended December 31,
|
|||
|
2013
|
|||
|
Net income
|
$
|
30,600
|
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|||
|
Depreciation and amortization
|
15,976
|
|
|
|
Amortization of Debt Issuance Costs
|
1,198
|
|
|
|
Amortization of regulatory assets
|
160
|
|
|
|
Net regulatory asset/liability
|
6,538
|
|
|
|
Net derivative asset/liability
|
(6,538
|
)
|
|
|
Changes in:
|
|||
|
Accounts receivable
|
2,285
|
|
|
|
Other current assets
|
278
|
|
|
|
Fuel oil inventory
|
(22
|
)
|
|
|
Materials & supplies inventory
|
(38
|
)
|
|
|
Accounts payable
|
(1,631
|
)
|
|
|
Accrued liabilities
|
142
|
|
|
|
Other current liabilities
|
415
|
|
|
|
Interest payable on long term debt
|
3,208
|
|
|
|
Regulatory asset/liability
|
(1,502
|
)
|
|
|
Total cash provided by operating activities
|
51,069
|
|
|
|
Plant expenditures including AFUDC debt
|
(2,013
|
)
|
|
|
Changes in restricted cash
|
11,351
|
|
|
|
Total cash provided by investing activities
|
9,338
|
|
|
|
Borrowings of long term debt
|
236,500
|
|
|
|
Repayments of long term debt
|
(228,395
|
)
|
|
|
Debt issuance costs
|
(8,514
|
)
|
|
|
Distribution of capital
|
(43,631
|
)
|
|
|
Total cash used in financing activities
|
(44,040
|
)
|
|
|
Net change for the period
|
16,367
|
|
|
|
Balance at the beginning of the period
|
—
|
|
|
|
Balance at the end of the period
|
$
|
16,367
|
|
|
Cash paid during the period for:
|
|||
|
Interest
|
$
|
8,577
|
|
The accompanying Notes to the Consolidated Financial Statements are an integral part of the financial statements.
99
GCE Holding LLC
Consolidated Statement of Changes in Equity (Unaudited)
For the Years Ended December 31, 2013
(In thousands)
|
Paid-in Capital
|
Consolidated
|
||
|
Balance as of December 31, 2012
|
$
|
249,322
|
|
|
Distribution of capital
|
(12,886
|
)
|
|
|
Balance as of December 31, 2013
|
$
|
236,436
|
|
|
Retained Earnings
|
Consolidated
|
||
|
Balance as of December 31, 2012
|
$
|
145
|
|
|
Income for 2013
|
30,600
|
|
|
|
Distribution to partners
|
(30,745
|
)
|
|
|
Balance as of December 31, 2013
|
$
|
—
|
|
The accompanying Notes to the Consolidated Financial Statements are an integral part of the financial statements.
100
GCE Holding LLC
Notes to the Consolidated Financial Statements (Unaudited)
Organization
GCE Holding LLC (GCE) is a 50-50 joint venture between The United Illuminating Company (UI) and NRG Connecticut Peaking Development LLC, an indirect wholly-owned subsidiary of NRG Energy, Inc. (NRG). GenConn Energy LLC (GenConn) is a wholly-owned subsidiary of GCE. GenConn consists of two peaking generation plants, GenConn Devon LLC (GenConn Devon) and GenConn Middletown LLC (GenConn Middletown), which were chosen by the Connecticut Public Utilities Regulatory Authority (PURA), formerly the Department of Public Utility Control (DPUC), to help address the state’s growing need for more power generation during the heaviest load periods. The two peaking generation plants, each with a nominal capacity of 200 megawatts (MW), are located at NRG’s existing Connecticut plant locations in Devon and Middletown. GenConn Devon became operational in June 2010 and GenConn Middletown became operational in June 2011.
Basis of Presentation
The accounting records of GenConn are maintained in conformity with accounting principles generally accepted in the United States of America (GAAP).
The accounting records for GenConn are also maintained in accordance with the uniform systems of accounts prescribed by the Federal Energy Regulatory Commission (FERC) and PURA.
The preparation of financial statements in conformity with GAAP requires management to use estimates and assumptions that affect (1) the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and (2) the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Certain amounts reported in the Consolidated Financial Statements in previous periods have been reclassified to conform to the current presentation, primarily related to the presentation of intercompany receivables and payables.
Consolidation
The consolidated financial statements of GCE include the results of operations and financial position of its wholly-owned subsidiaries GenConn Devon and GenConn Middletown. Intercompany accounts and transactions have been eliminated in consolidation.
Regulatory Accounting
GenConn bid its full capacity of the GenConn Devon and GenConn Middletown facilities into the ISO-New England, Inc. (ISO-NE) Locational Forward Reserve Market (LFRM) pursuant to directives from PURA for the winter 2011/2012 period (October 1, 2011 - May 31, 2012), for the summer 2012 period (June 1, 2012 - September 30, 2012) and for the winter 2012/2013 period (October 1, 2012 - May 31, 2013). GenConn also had LFRM obligations for the summer of 2013 (June 1, 2013 - September 30, 2013) and for the winter 2013/2014 period (October 1, 2013 - May 31, 2014), as directed in PURA’s decision in Docket No. 12-07-14 Re01, Application of GenConn Energy LLC for Establishment of 2013 Revenue Requirements and PURA’s decision, dated April 11, 2013, in Docket No. 08-01-01RE03, DPUC Review of Peaking Generation Projects - Market Rule Changes re: New Audit Rules. The units have Capacity Supply Obligations in the ISO-NE Forward Capacity Market (FCM) effective June 1, 2013 and for all FCM periods transacted so far, through May 31, 2017.
According to PURA’s decision dated December 11, 2013 in Docket No. 13-6-38, Application of GenConn Energy LLC for Establishment of 2014 Revenue Requirements, GenConn will bid into the Winter 2014/2015 and Summer 2014 Locational Forward Reserve Market auctions using the then latest ISO-NE fast-start capacity ratings with no additional reduction(each bid shall favor the 10-minute market with only excess capacity bid into the 30-minute market) and shall bid into the 2017 FCM as Existing Capacity, and shall not submit any delist bids for the period June 1, 2017 to May 31, 2018.
101
GenConn filed a revenue requirements request with PURA on June 28, 2013, seeking approval of 2014 revenue requirements for the period commencing January 1, 2014 for both the GenConn Devon and GenConn Middletown facilities. As part of the request, GenConn requested an interim decision relative to treatment of ISO-NE market rule changes related to LFRM penalties effective October 1, 2013. A Final Decision was received on September 25, 2013 approving the recommended changes to the Contract for Difference (CfD) to reflect the ISO-NE market rule changes. GenConn requested revisions to the CfD so that the Contract Monthly LFRM Revenue term, that calculates the credit to the Buyer associated with LFRM revenues, includes an adjustment that would reduce the credit to the Buyer associated with the Failure-to-Activate penalty and the Failure-to-Reserve penalty by the amount resulting solely from the market rule change related to LFRM penalties. This change appropriately accounts for and passes charges for recovery through the CfD invoices. A Final Decision was issued by PURA on December 11, 2013 approving revenue requirements of $68.259 million for GenConn ($30.779 million for the GenConn Devon facility and $37.480 million for the GenConn Middletown facility). Additionally, GenConn was granted a 9.95% Return on Equity (ROE) for 2014.
GenConn filed a revenue requirements application with PURA on July 27, 2012, seeking approval of its 2013 revenue requirements for both the GenConn Devon and GenConn Middletown facilities. A final decision (2013 Decision) was issued by PURA on January 9, 2013 approving revenue requirements of $73.3 million for GenConn ($33.1 million for the GenConn Devon facility and $40.2 million for the GenConn Middletown facility). Additionally, GenConn was granted a 9.75% Return on Equity (ROE) for 2013. PURA also ruled in the 2013 Decision that GenConn project costs that were in excess of the proposed costs originally submitted in 2008, were prudently incurred and are recoverable. Recovery of these costs is included in the 2013 Decision. The increase in project costs was driven in large part by increased financing costs and the cost to build interconnection facilities at GenConn Middletown.
Certain ISO-NE revenues and charges that were not included in the Contract for Differences (CfD) calculation were recorded and collected or paid through the ISO-NE settlement process from June 2010 through September 2011. In GenConn’s 2011 revenue requirements proceeding, parties in that proceeding questioned the treatment of the revenues and charges with respect to the CfD calculation. The parties reached a settlement, which was approved by PURA, wherein GenConn reimbursed Connecticut Light & Power (CL&P) $3.0 million during the first quarter of 2012. This amount was fully accrued as of December 31, 2011.
102
Management has determined that GenConn meets the criteria for an entity with regulated operations as defined by the authoritative guidance on accounting for the effects of certain types of regulation. As such, GenConn has established regulatory assets for certain costs deferred if it is probable that it will be able to recover such costs in future revenues, and has established regulatory liabilities for certain obligations recognized if it is probable that it will be relieved of such liabilities in future revenues based on the criteria outlined in the PURA decisions related to the types of costs that are recoverable. Furthermore, GenConn has received approval from PURA in its final revenue requirements decisions allowing for the recovery and/or return of property taxes, transmission related operating costs and interest expense. GenConn’s regulatory assets and liabilities as of December 31, 2013 and 2012 are set forth below (in thousands):
|
Regulatory Assets:
|
Remaining Period
|
As of December 31, 2013
|
||||
|
Mark-to-market adjustments related to interest rate swaps
|
(a)
|
$
|
—
|
|
||
|
Property taxes
|
1 year
|
669
|
|
|||
|
Deferred project costs
|
(b)
|
8,439
|
|
|||
|
Financing costs
|
26 years
|
1,186
|
|
|||
|
Operating costs
|
(c)
|
8
|
|
|||
|
Interest expense
|
(d)
|
39
|
|
|||
|
Total Regulatory Assets
|
10,341
|
|
||||
|
Less current portion of Regulatory Assets
|
364
|
|
||||
|
Regulatory Assets, long-term
|
$
|
9,977
|
|
|||
|
Regulatory Liabilities:
|
||||||
|
Operating costs
|
(c)
|
$
|
1,262
|
|
||
|
Interest expense
|
(d)
|
471
|
|
|||
|
Maintenance costs
|
(e)
|
880
|
|
|||
|
Debt Amortization
|
(f)
|
304
|
|
|||
|
Total Regulatory Liabilities
|
2,917
|
|
||||
|
Less current portion of Regulatory Liabilities
|
1,016
|
|
||||
|
Regulatory Liabilities, long-term
|
$
|
1,901
|
|
|||
|
(a) Interest rate swaps were terminated as part of the September 17, 2013 refinancing of the Company's long-term debt.
|
||||||
|
(b) Represents project repair costs. Recovery to be determined in future revenue requirements.
|
||||||
|
(c) Represents a true-up of actual transmission related operating costs to amounts allowed in revenue requirements. The current portion will be recovered or returned in 2013 as allowed in PURA final decisions. The recovery or return of the long-term portion will be determined in future revenue requirements proceedings.
|
||||||
|
(d) Represents a true-up of actual interest costs to amounts allowed in revenue requirements. The current portion will be recovered or returned in 2013 as allowed in PURA final decisions. The recovery or return of the long-term portion will be determined in future revenue requirements proceedings.
|
||||||
|
(e) Represents current collections for future anticipated large equipment maintenance costs.
|
||||||
|
(f) Represents a true-up of debt amortization expense to amounts allowed in revenue requirements. The return will be determined in future revenue requirements proceedings.
|
||||||
Cash and Temporary Cash Investments
GenConn considers all of its highly liquid debt instruments with an original maturity of three months or less at the date of purchase to be cash and temporary cash investments.
Restricted Cash
The use of all cash, including amounts derived from borrowings of notes payable and long-term debt as well as from the collection of accounts receivable, was restricted per the project financing agreements as certain payments, such as scheduled payments of long-term debt, are required to be made prior to dividend payments. Payments made outside the provisions of the project financing require prior approval from the bank. As a result of the debt refinancing discussed in the Long-Term Debt section, no restrictions exist as of December 31, 2013.
Inventory
Inventory primarily consists of fuel oil and materials and supplies. Fuel oil is stated primarily at the lower of cost or market value under the weighted average cost method. Materials and supplies inventory is valued at weighted average cost and is expensed to operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.
103
Accrued Liabilities
Accrued liabilities primarily consist of accrued property tax expense relating to GenConn Devon and GenConn Middletown which have entered into 30 year tax stabilization agreements with the City of Milford and the City of Middletown, respectively.
Asset Retirement Obligation
The fair value of the liability for an asset retirement obligation is recorded in the period in which it is incurred and the cost is capitalized by increasing the carrying amount of the related long-lived asset. The liability is adjusted to its present value periodically over time, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement, the obligation is settled either at its recorded amount or a gain or a loss is incurred.
Revenue Recognition
Operating revenues are recognized when contractually earned in the period provided and consist of revenues received from power and capacity sales into the ISO-NE markets and from CL&P under the CfD based on authorized rates approved by regulatory bodies and can be changed only through formal proceedings
Property, Plant and Equipment (PP&E)
PP&E is reflected in the accompanying Balance Sheet at cost. Provisions for depreciation on in-service PP&E are computed on a straight-line basis over a 30 year life which was determined by the term of the CfD (see below) and is representative of the economic life of the plant. The costs of current repairs, major maintenance projects and minor replacements are charged to appropriate operating expense accounts as incurred. Other plant includes other project costs primarily related to civil, mechanical, and electrical site work. GCE’s in-service property, plant and equipment were comprised as follows (in thousands):
|
2013
|
||
|
Gas Turbines
|
$ 139,027
|
|
|
Other Plant
|
303,486
|
|
|
Capitalized Interest (AFUDC)
|
35,261
|
|
|
Gross PP&E In-service
|
$ 477,774
|
|
Impairment of Long-Lived Assets and Investments
The authoritative guidance on property, plant, and equipment requires the recognition of impairment losses on long-lived assets when the book value of an asset exceeds the sum of the expected future undiscounted cash flows that result from the use of the asset and its eventual disposition. If impairment arises, then the amount of any impairment is measured based on estimated fair value.
The authoritative guidance on property, plant, and equipment also requires that rate-regulated companies recognize an impairment loss when a regulator excludes all or part of a cost from rates, even if the regulator allows the company to earn a return on the remaining costs allowed. The probability of recovery and the recognition of regulatory assets under the criteria of the authoritative guidance on accounting for the effects of certain types of regulation must be assessed on an ongoing basis. At December 31, 2013, GenConn (as a rate regulated entity) did not have any assets that were impaired under this standard.
Allowance for Funds Used During Construction (AFUDC)
In accordance with the uniform system of accounts prescribed by the FERC and PURA, GenConn capitalizes AFUDC, which represents the approximate cost of debt and equity devoted to plant under construction and is included in Interest Expense for the portion related to debt and Other Income and Deductions for the portion related to equity in the accompanying Consolidated Statements of Operations.
Contract for Differences
GenConn recovers its costs under two PURA-approved CfD agreements which are cost of service based and settle on a monthly basis. GenConn has signed CfDs for both facilities with CL&P both with terms of 30 years beginning upon the operations of each plant. Under the terms of the CfD, CL&P will either pay GenConn Devon and GenConn Middletown for the under-recovery or will be reimbursed by those entities for the over-recovery of revenues based on their participation in the ISO-NE markets.
These contracts are accounted for on an accrual basis. Under the CfDs, GenConn agrees that the PURA will determine its cost-of service rate in accordance with the related decisions. Also under the CfD, GenConn agrees to have the units participate and to bid all of the units in ISO-NE Markets as directed by the PURA.
104
Long-Term Debt
GenConn issued $236.5 million of senior secured notes in the private placement market on September 17, 2013. GenConn used the proceeds to (1) repay $225 million outstanding under a credit agreement that had been obtained from a consortium of banks on April 24, 2009 for construction and related activities; (2) terminate the interest rate swap that had been required under the credit agreement; (3) rebalance its capital structure to the regulated capital structure of 50% debt and 50% equity; and (4) pay issuance costs. Required principal payments and payments from a sinking fund are scheduled so that on the maturity date of July 25, 2041 the senior secured notes will be paid in full. Information regarding principal payments is set forth below (in thousands):
|
During the twelve months ended December 31st:
|
Total
|
|
2014
|
8,002
|
|
2015
|
8,002
|
|
2016
|
8,002
|
|
2017
|
8,002
|
|
2018
|
8,002
|
|
2019 and thereafter
|
196,490
|
|
$ 236,500
|
|
Also on September 17, 2013, GenConn closed on a new secured working capital facility with commitments totaling $35 million from two banks. The working capital facility also permits the issuance of letters of credit. GenConn may borrow under the working capital facility at interest rates equal to either the Base Rate or Eurodollar Rate plus the Applicable Margin, as each is defined in the related agreement. The maturity date of the working capital facility is on September 17, 2018. As of December 31, 2013, there were no borrowings under the working capital facility, and there were letters of credit outstanding totaling approximately $28.5 million.
Substantially all of the assets of GenConn serve as collateral for the private placement debt and working capital facility. As of December 31, 2013, the carrying value of the Long-Term Debt approximated fair value. Under each of the private placement debt and working capital facility agreements, GenConn is required to comply with certain covenants including the requirement to maintain a Consolidated Indebtedness to Total Capitalization ratio (as defined in the agreements) not to exceed 60%. As of December 31, 2013, GenConn’s Total Indebtedness to Total Capitalization ratio was 50%. In addition, GenConn is subject to a dividend payment test whereby dividends are permitted if the debt service coverage ratio (as defined in the agreements) for the last twelve months is at least 1.2 to 1.0. As of December 31, 2013, GenConn’s debt service coverage ratio was 4.38.
Unamortized Debt Expense
GCE and GenConn deferred debt issuance costs incurred on the bank and project financings, which are being amortized over the term of the related debt and allocated evenly to both GenConn Devon and GenConn Middletown. The amortization and associated unamortized debt issuance cost balances are accounted for at GenConn Devon and GenConn Middletown as such amounts are recovered in rates. The unamortized debt issuance costs are included in Unamortized Debt Expense in the accompanying Consolidated Balance Sheet as of December 31, 2013.
Related Party Transactions
There are no employees of GCE or any of its subsidiaries. UI and NRG (the Partners) are paid, through GCE, for services to GenConn which include administration, plant operations, construction and energy management pursuant to contractual arrangements. As of December 31, 2013, amounts owed to the Partners for services of $1.6 million are included in Accounts Payable in the accompanying Consolidated Balance Sheet. For the year ended December 31, 2013, amounts paid to the Partners for services was $12.4 million.
For the year ended December 31, 2013, amounts paid to the Partners, through GCE, for interest was zero.
Interest expense on related party notes from the Partners, for the year ended December 31, 2013 was zero.
GenConn made distributions, through GCE, to the Partners of $43.6 million for the year ended December 31, 2013.
GenConn returned a portion of the Partner’s investment, through GCE, of $12.9 million for the year ended December 31, 2013.
105
GenConn Devon and GenConn Middletown lease both facilities and land from Devon Power LLC (Devon Power) and Middletown Power LLC (Middletown Power), respectively, both of which are subsidiaries of NRG. See the Lease Obligations section for additional details.
Income Taxes
GCE is not subject to federal or state income taxes. UI and NRG are required to report on their federal and, as required, state income tax return its share of GCE’s income, gains, losses, deductions and credits. Accordingly, there is no provision for income taxes in the accompanying consolidated financial statements.
Derivatives
In connection with the Project Financing, in April 2009, GenConn entered into an interest rate swap agreement with each of the five banks participating in the syndication to reduce the risk of unfavorable changes in variable interest rates related to a portion of the Project Financing. The swaps had the effect of converting variable rate payments to fixed rate payments, on approximately $42 million to $121 million principal amount outstanding of Project Financing debt through December 31, 2014, with quarterly settlements that began on March 31, 2010. Any income generated from the agreement was expected to be credited to customers and any expense generated was expected to be recovered from customers through PURA-approved revenue requirements. GenConn accounted for the interest rate swap agreement as an economic hedge. As such, GenConn established a regulatory liability or asset for the mark-to-market adjustments related to the interest rate swaps. As of December 31, 2012, $6.5 million was recorded as a Derivative Liability offset by a Regulatory Asset in the accompanying Consolidating Balance Sheet. On September 17, 2013, the interest swap agreement was terminated in conjunction with the private placement. The settlement payment as a result of such termination is included in unamortized debt expenses as approved by PURA.
The fair value hierarchy levels are Level 1 (quoted prices in active markets for identical assets and liabilities), Level 2 (significant other observable inputs), and Level 3 (significant unobservable inputs).
GenConn utilized an income approach valuation technique to value the interest rate swap derivatives measured and reported at fair value. As required by the authoritative guidance on fair value measurements, financial assets and liabilities are based on the lowest level of input that is significant to the fair value measurement. The interest rate swaps were valued based on the annual London Interbank Offering Rate (LIBOR) index. GenConn’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. GenConn had determined the fair value of its interest rate swap derivatives was measured using Level 2 inputs.
Contingencies
In the ordinary course of business, GCE and its subsidiaries are involved in various proceedings, including legal, tax, regulatory and environmental matters, which require management’s assessment to determine the probability of whether a loss will occur and, if probable, an estimate of probable loss. When assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated, GCE accrues a reserve and discloses the reserve and related matter. GCE discloses matters when losses are probable for which an estimate is reasonably possible. Subsequent analysis is performed on a periodic basis to assess the impact of any changes in events or circumstances and any resulting need to adjust existing reserves or record additional reserves.
GenConn Middletown Cable System
Two circuits, referred to as “5X” and “6X,” connect the four units at the GenConn Middletown facility to the gas insulated substation. In Aprill 2011, the 5X failed. Multiple repairs were made. However, the repairs failed to correct persistent partial discharge that was detected through periodic testing. In March 2012, GenConn filed a lawsuit seeking damages against the electrical contractor responsible for the design and installation of the 5X and 6X and one of its subcontractors. During that same month, the former electrical contractor responsible for the failed installation filed a counterclaim in the amount of approximately $1.8 million and a mechanic’s lien on the GenConn Middletown project in that same amount.
The parties to the litigation are presently discussing a potential mediation to occur in April 2014. Trial is currently expected to begin in June 2014. Please refer to Deferred Project Costs included in the Regulatory Accounting table for further information for costs incurred as of December 31, 2013 regarding the defective equipment.
On July 13, 2012, the 5X circuit and the two units it serviced were taken out of service. On August 8, 2012, the 6X circuit and the remaining two units at the GenConn Middletown facility were taken out of service. This was done because of operation
106
and safety concerns raised by further partial discharge testing and other analysis by retained experts. GenConn has amended its litigation complaint, to seek additional damages, including those related to 6x. Further, GenConn hired another electrical contractor to undertake the replacement of the defective equipment. The defective equipment was replaced during the second half of 2012 and all four units were returned to service on January 19, 2013. As a result of the outage, GenConn incurred penalties for not achieving availability in the LFRM in the amount of approximately $0.1 million during the twelve months ended December 31, 2012. Penalties incurred from January 1 through January 19, 2013 were minor. The penalties incurred are included in the Operating Expenses in the accompanying Consolidated Statements of Operations. The amount is net of the amount of coverage GenConn obtained for the unavailable capacity.
In order to comply with certain covenants under the project financing, GenConn Middletown has posted a surety bond for the total amount of the contractor’s lien, which discharged the lien. As of December 31, 2013, GenConn Middletown has recorded $1.1 million as a regulatory asset related to the underlying $1.8 million counterclaim. Based on information obtained in discovery, the remaining $0.7 million appears to be comprised of the contractor’s alleged costs for performing repair and investigative work related to the April 2011 failure and the subsequent partial discharge, plus overhead and profit, that has yet to be billed. GenConn Middletown is currently assessing this claim, as discovery in ongoing. To the extent that GenConn is required to satisfy any of the claims, recovery of such costs would be expected through future rates.
Other
In July 2011, GenConn Devon and the former general contractor responsible for the construction of the GenConn Devon facility entered into a settlement agreement with respect to change order requests and delay and impact claims and pursuant to which GenConn Devon paid a settlement amount of $10.5 million upon satisfaction of certain conditions performed by the former general contractor. In April 2011, GenConn Middletown settled a claim by the former general contractor for work at the GenConn Middletown facility and entered into a settlement agreement pursuant to which GenConn Middletown paid a settlement amount of $3.0 million which is included in Property, Plant and Equipment in the accompanying Consolidated Balance Sheet. PURA has approved GenConn’s recovery of the associated costs.
In December 2010, GenConn Middletown was required to provide a $1.4 million Letter of Credit (LC) to the owner of the transmission facilities to which GenConn Middletown connects. The LC is related to remaining work on the transmission facilities. Correspondingly, GenConn Middletown had a $3.5 million performance bond from the contractor required to complete the remaining work. In April 2011, GenConn Middletown was required to provide an additional $0.9 million LC for additional work on the same transmission facilities. In February 2013, the $0.9 million LC was reduced to $0.1 million. During the second quarter of 2013, the $0.1 million was released by the owner of the transmission facilities. The $1.4 million LC was released by the owner of the transmission facilities during the first quarter of 2013
.
The $3.5 million performance bond from the contractor was released on October 2, 2013 as all work on the transmission facilities is complete.
Lease Obligations
Operating leases with Devon Power LLC and Middletown Power LLC consist primarily of leases of facilities and land for both GenConn Devon and GenConn Middletown. The term of the leases coincide with the maturity of the senior secured notes (2040 for GenConn Devon and 2041 for GenConn Middletown). For the year ended December 31, 2013, total operating lease expense for GenConn Devon and GenConn Middletown was $1.2 million. The future minimum lease payments under these operating leases are estimated to be as follows (in thousands):
|
GenConn
|
GenConn
|
|||||
|
Twelve months ended December 31st:
|
Devon
|
Middletown
|
||||
|
2014
|
$ 579
|
|
$ 668
|
|
||
|
2015
|
579
|
|
668
|
|
||
|
2016
|
579
|
|
668
|
|
||
|
2017
|
579
|
|
668
|
|
||
|
2018
|
579
|
|
668
|
|
||
|
2019 and thereafter
|
12,401
|
|
14,975
|
|
||
|
$ 15,296
|
|
$ 18,315
|
|
|||
107
Report of Independent Registered Public Accounting Firm
To the Management Committee of GCE Holding LLC:
We have audited the accompanying consolidated financial statements of GCE Holding LLC and its subsidiaries, which comprise the consolidated balance sheets as of December 31, 2012 and December 31, 2011, and the related consolidated statements of income, of changes in equity and of cash flows for the three years ended December 31, 2012.
Management's Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
Auditor's Responsibility
Our responsibility is to express an opinion on the consolidated financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of GCE Holding LLC and its subsidiaries at December 31, 2012 and December 31, 2011, and the results of their operations and their cash flows for the three years ended December 31, 2012 in accordance with accounting principles generally accepted in the United States of America.
Emphasis of Matter
As discussed in the "Related Party Transaction" note to the consolidating financial statements, GCE Holding LLC has entered into significant transactions with The United Illuminating Company and NRG Connecticut Peaking Development LLC, which are related parties.
/s/ PricewaterhouseCoopers LLP
April 26, 2013
108
GCE HOLDING LLC
Consolidated Statement of Income
For the Years Ended December 31, 2012, 2011, and 2010
(in 000's)
|
2012
|
2011
|
2010
|
|||||||||
|
Operating revenues
|
$
|
77,816
|
|
$
|
67,417
|
|
$
|
18,921
|
|
||
|
Operating expense
|
11,528
|
|
13,834
|
|
7,504
|
|
|||||
|
Depreciation and amortization expense
|
16,762
|
|
12,829
|
|
3,393
|
|
|||||
|
Taxes other than income
|
4,763
|
|
4,065
|
|
9
|
|
|||||
|
Income from operations
|
44,762
|
|
36,690
|
|
8,014
|
|
|||||
|
Other income and (deductions)
|
(1
|
)
|
(32
|
)
|
(1
|
)
|
|||||
|
Interest expense
|
15,513
|
|
12,895
|
|
5,578
|
|
|||||
|
Income
|
$
|
29,249
|
|
$
|
23,763
|
|
$
|
2,435
|
|
||
The accompanying Notes to the Consolidated Financial Statements are an integral part of the financial statements.
109
GCE Holding LLC
Consolidated Balance Sheets
As of December 31, 2012 and 2011 (in 000's)
|
2012
|
2011
|
||||||
|
Assets
|
|||||||
|
Current assets:
|
|||||||
|
Cash
|
$
|
—
|
|
$
|
—
|
|
|
|
Restricted cash
|
11,351
|
|
19,473
|
|
|||
|
Regulatory assets
|
6,699
|
|
9,443
|
|
|||
|
Accounts receivable
|
11,351
|
|
9,319
|
|
|||
|
Other current assets
|
628
|
|
46
|
|
|||
|
Fuel oil inventory
|
3,620
|
|
3,833
|
|
|||
|
Materials & supplies inventory
|
2,039
|
|
2,018
|
|
|||
|
Unamortized debt expense
|
1,502
|
|
1,502
|
|
|||
|
37,189
|
|
45,635
|
|
||||
|
Property, plant and equipment:
|
|||||||
|
In-service
|
478,598
|
|
476,544
|
|
|||
|
Accumulated depreciation and amortization
|
(30,663
|
)
|
(14,731
|
)
|
|||
|
Net property, plant & equipment
|
447,935
|
|
461,813
|
|
|||
|
Long term assets:
|
|||||||
|
Unamortized debt expense
|
3,593
|
|
5,007
|
|
|||
|
Regulatory assets
|
7,665
|
|
4,150
|
|
|||
|
11,257
|
|
9,157
|
|
||||
|
Total assets
|
$
|
496,381
|
|
$
|
516,605
|
|
|
|
Liabilities and Equity
|
|||||||
|
Current liabilities:
|
|||||||
|
Accounts payable
|
$
|
6,436
|
|
$
|
3,197
|
|
|
|
Accrued liabilities
|
1,972
|
|
2,370
|
|
|||
|
Regulatory liabilities
|
1,242
|
|
922
|
|
|||
|
Current portion of long term debt
|
8,100
|
|
8,280
|
|
|||
|
Interest payable on long term debt
|
24
|
|
98
|
|
|||
|
Interest payable on related party notes payable
|
—
|
|
256
|
|
|||
|
Derivative liability
|
6,538
|
|
8,505
|
|
|||
|
Other current liabilities
|
92
|
|
100
|
|
|||
|
24,404
|
|
23,727
|
|
||||
|
Long term liabilities:
|
|||||||
|
Long term debt
|
220,295
|
|
228,395
|
|
|||
|
Regulatory liability
|
1,640
|
|
582
|
|
|||
|
Asset retirement obligation
|
565
|
|
522
|
|
|||
|
Other
|
9
|
|
73
|
|
|||
|
222,509
|
|
229,572
|
|
||||
|
Equity:
|
|||||||
|
Paid-in capital
|
249,322
|
|
253,061
|
|
|||
|
Retained earnings
|
145
|
|
10,245
|
|
|||
|
249,467
|
|
263,306
|
|
||||
|
Total liabilities and equity
|
$
|
496,381
|
|
$
|
516,605
|
|
|
The accompanying Notes to the Consolidated Financial Statements are an integral part of the financial statements.
110
GCE Holding LLC
Consolidated Statement of Cash Flows
For the Year Ended December 31, 2012, 2011, and 2010
(in 000's)
|
2012
|
2011
|
2010
|
|||||||||
|
Net income
|
$
|
29,249
|
|
$
|
23,763
|
|
$
|
2,435
|
|
||
|
Adjustments to reconcile income to net cash provided by operating activities:
|
|||||||||||
|
Depreciation & Amortization expense
|
15,975
|
|
12,860
|
|
3,393
|
|
|||||
|
Amortization of Debt Issuance Costs
|
1,502
|
|
1,189
|
|
438
|
|
|||||
|
Amortization of regulatory assets
|
874
|
|
30
|
|
6
|
|
|||||
|
Net regulatory asset/liability
|
1,967
|
|
(1,357
|
)
|
—
|
|
|||||
|
Net derivative asset/liability
|
(1,967
|
)
|
—
|
|
—
|
|
|||||
|
Changes in:
|
|||||||||||
|
Accounts receivable
|
(2,031
|
)
|
(4,044
|
)
|
(5,275
|
)
|
|||||
|
Other current assets
|
(306
|
)
|
65
|
|
(110
|
)
|
|||||
|
Prepayments
|
(276
|
)
|
—
|
|
—
|
|
|||||
|
Fuel oil inventory
|
213
|
|
(2,394
|
)
|
(1,439
|
)
|
|||||
|
Materials & supplies inventory
|
(21
|
)
|
(256
|
)
|
(1,762
|
)
|
|||||
|
Accounts payable
|
1,927
|
|
834
|
|
389
|
|
|||||
|
Accrued liabilities
|
(467
|
)
|
1,419
|
|
29
|
|
|||||
|
Other current liabilities
|
92
|
|
—
|
|
—
|
|
|||||
|
Taxes payable
|
(94
|
)
|
(23
|
)
|
29
|
|
|||||
|
Regulatory asset/liability
|
(1,990
|
)
|
(2,615
|
)
|
—
|
|
|||||
|
Total cash provided by (used in) operating activities
|
44,647
|
|
29,470
|
|
(1,867
|
)
|
|||||
|
Plant expenditures including AFUDC debt
|
(984
|
)
|
(72,946
|
)
|
(184,922
|
)
|
|||||
|
Changes in restricted cash
|
8,123
|
|
13,102
|
|
5,184
|
|
|||||
|
Other
|
(330
|
)
|
2,122
|
|
(467
|
)
|
|||||
|
Total cash provided by (used in) investing activities
|
6,808
|
|
(57,722
|
)
|
(180,205
|
)
|
|||||
|
Borrowings of long term debt
|
—
|
|
43,568
|
|
151,682
|
|
|||||
|
Repayments of long term debt
|
(8,280
|
)
|
(5,215
|
)
|
(1,110
|
)
|
|||||
|
Borrowings of related party notes payable
|
—
|
|
1,852
|
|
19,500
|
|
|||||
|
Debt issuance costs
|
(88
|
)
|
—
|
|
—
|
|
|||||
|
Distribution to partners
|
(43,090
|
)
|
(15,953
|
)
|
—
|
|
|||||
|
Contribution of capital
|
2
|
|
4,000
|
|
12,000
|
|
|||||
|
Total cash provided by (used in) financing activities
|
(51,455
|
)
|
28,252
|
|
182,072
|
|
|||||
|
Net change for the period
|
—
|
|
—
|
|
—
|
|
|||||
|
Balance at beginning of period
|
—
|
|
—
|
|
—
|
|
|||||
|
Balance at end of period
|
—
|
|
—
|
|
—
|
|
|||||
|
Cash paid during the period for:
|
|||||||||||
|
Interest
|
$
|
12,804
|
|
$
|
14,687
|
|
$
|
14,221
|
|
||
|
Non-cash investing activity:
|
|||||||||||
|
Plant expenditures included in ending payables
|
$
|
1,698
|
|
$
|
1,954
|
|
$
|
33,358
|
|
||
|
Non-cash financing activity:
|
|||||||||||
|
Intercompany notes payable
|
$
|
—
|
|
$
|
(125,979
|
)
|
$
|
(111,081
|
)
|
||
|
Contribution of capital
|
$
|
—
|
|
$
|
125,979
|
|
$
|
111,081
|
|
||
The accompanying Notes to the Consolidated Financial Statements are an integral part of the financial statements.
111
GCE Holding LLC
Consolidated Statement of Changes in Equity
For the Years Ended December 31, 2012, 2011, and 2010
(in 000's)
|
Paid-in Capital
|
|||
|
Balance as of December 31, 2009
|
$
|
2
|
|
|
Contribution of capital
|
123,081
|
|
|
|
Balance as of December 31, 2010
|
$
|
123,083
|
|
|
Contribution of capital
|
129,979
|
|
|
|
Balance as of December 31, 2011
|
$
|
253,061
|
|
|
Contribution of capital
|
$
|
2
|
|
|
Return of capital
|
(3,741
|
)
|
|
|
Balance as of December 31, 2012
|
$
|
249,322
|
|
|
Retained Earnings
|
|||
|
Income for 2009
|
$
|
—
|
|
|
Income for 2010
|
$
|
2,435
|
|
|
Income for 2011
|
23,763
|
|
|
|
Distribution to partners
|
(15,953
|
)
|
|
|
Balance as of December 31, 2011
|
$
|
10,245
|
|
|
Income for 2012
|
29,249
|
|
|
|
Distribution to partners
|
(39,349
|
)
|
|
|
Balance as of December 31, 2012
|
$
|
145
|
|
The accompanying Notes to the Consolidated Financial Statements are an integral part of the financial statements.
112
GCE Holding LLC
Notes to the Consolidated Financial Statements
Organization
GCE Holding LLC (GCE) is a 50-50 joint venture between The United Illuminating Company (UI) and NRG Connecticut Peaking Development LLC, an indirect wholly-owned subsidiary of NRG Energy, Inc. (NRG). GenConn Energy LLC (GenConn) is a wholly-owned subsidiary of GCE. GenConn consists of two peaking generation plants, GenConn Devon LLC (GenConn Devon) and GenConn Middletown LLC (GenConn Middletown), which were chosen by the Connecticut Public Utilities Regulatory Authority (PURA), formerly the Department of Public Utility Control (DPUC), to help address the state's growing need for more power generation during the heaviest load periods. The two peaking generation plants, each with a nominal capacity of 200 megawatts (MW), are located at NRG's existing Connecticut plant locations in Devon and Middletown. GenConn Devon became operational in June 2010 and GenConn Middletown became operational in June 2011.
Basis of Presentation
The accounting records of GenConn are maintained in conformity with accounting principles generally accepted in the United States of America (GAAP).
The accounting records for GenConn are also maintained in accordance with the uniform systems of accounts prescribed by the Federal Energy Regulatory Commission (FERC) and PURA.
The preparation of financial statements in conformity with GAAP requires management to use estimates and assumptions that affect (1) the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and (2) the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Certain amounts reported in the Consolidated Financial Statements in previous periods have been reclassified to conform to the current presentation, primarily related to the presentation of intercompany receivables and payables.
GenConn has evaluated subsequent events through the date its financial statements were available to be issued, April 26, 2013.
Consolidation
The consolidated financial statements of GCE include the results of operations and financial position of its wholly-owned subsidiaries GenConn Devon and GenConn Middletown. Intercompany accounts and transactions have been eliminated in consolidation.
New Accounting Standards
In May 2011, the Financial Accounting Standards Board issued amendments to authoritative guidance on fair value measurements and disclosures which did not have an impact on GenConn's consolidating financial statements.
Regulatory Accounting
GenConn bid its full capacity of the GenConn Devon and GenConn Middletown facilities into the ISO-New England, Inc. (ISO-NE) locational forward reserve market (LFRM) for the winter 2011/2012 period (October 1, 2011—May 31, 2012), for the summer 2012 period (June 1, 2012—September 30, 2012) and for the winter 2012/2013 period (October 1, 2012—May 31, 2013). GenConn bids the full capacity of the facilities into the ISO-NE forward capacity market (FCM), once per year, three years in advance and currently has capacity supply obligations through May 31, 2016.
GenConn filed a revenue requirements application with PURA on July 27, 2012, seeking approval of its 2013 revenue requirements for both the GenConn Devon and GenConn Middletown facilities. A final decision (2013 Decision) was issued by PURA on January 9, 2013 approving revenue requirements of $73.3 million for GenConn ($33.1 million for the Devon facility and $40.2 million for the Middletown facility, respectively). Additionally, GenConn was granted a 9.75% Return on Equity (ROE) for 2013 in the 2013 Decision. PURA also ruled in the 2013 Decision that the GenConn project costs that were in excess of the costs originally submitted in 2008, were prudently incurred and are recoverable. Recovery of these costs is included in the determination of the 2013 approved revenue requirements. The increase in project costs was driven in large part by increased financing costs and the cost to build interconnection facilities at GenConn Middletown.
113
Certain ISO-NE revenues and charges that were not included in the Contract for Differences (CfD) calculation were recorded and collected or paid through the ISO-NE settlement process from June 2010 through September 2011. In GenConn's 2011 revenue requirements proceeding, parties in that proceeding questioned the treatment of the revenues and charges with respect to the CfD calculation. The parties reached a settlement, which was approved by PURA, wherein GenConn reimbursed Connecticut Light & Power (CL&P) $3.0 million during the first quarter of 2012. This amount was fully accrued as of December 31, 2011.
Management has determined that GenConn meets the criteria for an entity with regulated operations as defined by the authoritative guidance on accounting for the effects of certain types of regulation. As such, GenConn has established regulatory assets for certain costs deferred if it is probable that it will be able to recover such costs in future revenues, and has established regulatory liabilities for certain obligations recognized if it is probable that it will be relieved of such liabilities in future revenues based on the criteria outlined in the PURA decisions related to the types of costs that are recoverable. Furthermore, GenConn has received approval from PURA in its final revenue requirements decisions allowing for the recovery and/or return of property taxes, transmission related operating costs and interest expense. GenConn's regulatory assets and liabilities as of December 31, 2012 and 2011 included the following (in 000's):
|
Regulatory Assets:
|
Remaining Period
|
As of
December 31, 2012
|
As of
December 31, 2011
|
|||||||
|
Mark-to-market adjustments related to interest rate swaps
|
(a) 4 years
|
$
|
6,539
|
|
$
|
8,505
|
|
|||
|
Property taxes
|
1 year
|
665
|
|
5
|
|
|||||
|
Deferred project costs
|
(b)
|
5,769
|
|
2,804
|
|
|||||
|
Financing costs
|
27 years
|
1,229
|
|
1,273
|
|
|||||
|
Operating costs
|
(c)
|
41
|
|
832
|
|
|||||
|
Interest expense
|
(d)
|
121
|
|
141
|
|
|||||
|
Bonus depreciation
|
(e)
|
—
|
|
33
|
|
|||||
|
Total Regulatory Assets
|
14,364
|
|
13,593
|
|
||||||
|
Less current portion of Regulatory Assets
|
6,699
|
|
9,443
|
|
||||||
|
Regulatory Assets, long-term
|
$
|
7,665
|
|
$
|
4,150
|
|
||||
|
Regulatory Liabilities:
|
||||||||||
|
Interest expense
|
(d)
|
43
|
|
$
|
187
|
|
||||
|
Property tax expense
|
(f)
|
—
|
|
203
|
|
|||||
|
Operating costs
|
(c)
|
2,215
|
|
—
|
|
|||||
|
Maintenance costs
|
(g)
|
624
|
|
542
|
|
|||||
|
Bonus depreciation
|
(e)
|
—
|
|
572
|
|
|||||
|
Total Regulatory Liabilities
|
2,882
|
|
1,504
|
|
||||||
|
Less current portion of Regulatory Liabilities
|
1,242
|
|
922
|
|
||||||
|
Regulatory Liabilities, long-term
|
$
|
1,640
|
|
$
|
582
|
|
||||
(a) Related to debt agreement which expires in April 2016. Balance classified as current as it adjusts with the market.
(b) Represents project repair costs. Recovery to be determined in future revenue requirements.
(c) Represents a true-up of actual transmission related operating costs to amounts allowed in revenue requirements. The current portion will be recovered or returned in 2013 as allowed in PURA final decisions.The recovery or return of the long-term portion will be determined in future revenue requirements proceedings.
(d) Represents a true-up of actual interest costs to amounts allowed in revenue requirements. The current portion will be recovered or returned in 2013 as allowed in PURA final decisions. The recovery or return of the long-term portion will be determined in future revenue requirements proceedings.
(e) True-up of the actual partners' deferred tax effects related to bonus depreciation to amounts allowed in revenue requirements were fully amortized as of 12/31/12.
(f) True-up of property taxes to amounts allowed in revenue requirements were fully amortized as of 12/31/12.
(g) Represents current collections for future anticipated large equipment maintenance costs.
Cash and Temporary Cash Investments
GenConn considers all of its highly liquid debt instruments with an original maturity of three months or less at the date of purchase to be cash and temporary cash investments.
114
Restricted Cash
The use of all cash, including amounts derived from borrowings of notes payable and long-term debt as well as from the collection of accounts receivable, is restricted per the project financing agreements as certain payments, such as scheduled payments of long-term debt, are required to be made prior to dividend payments. Payments made outside the provisions of the project financing require prior approval from the bank.
Inventory
Inventory primarily consists of fuel oil and materials and supplies. Fuel oil is stated primarily at the lower of cost or market value under the weighted average cost method. Materials and supplies inventory is valued at weighted average cost and is expensed to operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.
Accrued Liabilities
Accrued liabilities primarily consist of accrued property tax expense relating to GenConn Devon and GenConn Middletown which have entered into 30 year tax stabilization agreements with the City of Milford and the City of Middletown, respectively.
Asset Retirement Obligation
The fair value of the liability for an asset retirement obligation is recorded in the period in which it is incurred and the cost is capitalized by increasing the carrying amount of the related long-lived asset. The liability is adjusted to its present value periodically over time, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement, the obligation is settled either at its recorded amount or a gain or a loss is incurred.
Revenue Recognition
Operating revenues are recognized when contractually earned in the period provided and consist of revenues received from power and capacity sales into the ISO-NE markets and from CL&P under the CfD based on authorized rates approved by regulatory bodies and can be changed only through formal proceedings
Property, Plant and Equipment (PP&E)
PP&E is reflected in the accompanying Balance Sheet at cost. Provisions for depreciation on in-service PP&E are computed on a straight-line basis over a 30 year life which was determined by the term of the CfD (see below) and is representative of the economic life of the plant. The costs of current repairs, major maintenance projects and minor replacements are charged to appropriate operating expense accounts as incurred. Other plant includes other project costs primarily related to civil, mechanical, and electrical site work.
GCE's in-service property, plant and equipment were comprised as follows (in 000's):
|
2012
|
2011
|
||||||
|
Gas Turbines
|
$
|
139,027
|
|
$
|
147,567
|
|
|
|
Other Plant
|
304,310
|
|
293,716
|
|
|||
|
Capitalized Interest (AFUDC)
|
35,261
|
|
35,261
|
|
|||
|
Gross PP&E In-service
|
$
|
478,598
|
|
$
|
476,544
|
|
|
Impairment of Long-Lived Assets and Investments
The authoritative guidance on property, plant, and equipment requires the recognition of impairment losses on long-lived assets when the book value of an asset exceeds the sum of the expected future undiscounted cash flows that result from the use of the asset and its eventual disposition. If impairment arises, then the amount of any impairment is measured based on estimated fair value.
The authoritative guidance on property, plant, and equipment also requires that rate-regulated companies recognize an impairment loss when a regulator excludes all or part of a cost from rates, even if the regulator allows the company to earn a return on the remaining costs allowed. The probability of recovery and the recognition of regulatory assets under the criteria of the authoritative guidance on accounting for the effects of certain types of regulation must be assessed on an ongoing basis. At December 31, 2012, GenConn (as a rate regulated entity) did not have any assets that were impaired under this standard.
115
Allowance for Funds Used During Construction (AFUDC)
In accordance with the uniform system of accounts prescribed by the FERC and PURA, GenConn capitalizes AFUDC, which represents the approximate cost of debt and equity devoted to plant under construction and is included in Interest Expense for the portion related to debt and Other Income and Deductions for the portion related to equity in the accompanying Consolidated Statements of Operations.
Contract for Differences
GenConn recovers its costs under two PURA-approved CfD agreements which are cost of service based and settle on a monthly basis. GenConn has signed CfDs for both facilities with CL&P both with terms of 30 years beginning upon the operations of each plant. Under the terms of the CfD, CL&P will either pay GenConn Devon and GenConn Middletown for the under-recovery or will be reimbursed by those entities for the over-recovery of revenues based on their participation in the ISO-NE markets.
These contracts are accounted for on an accrual basis. Under the CfDs, GenConn agrees that the PURA will determine its cost-of service rate in accordance with the related decisions. Also under the CfD, GenConn agrees to have the units participate and to bid all of the units in ISO-NE Markets as directed by the PURA.
Long-Term Debt
GenConn obtained project financing from a consortium of banks on April 24, 2009 that made $243 million available for construction and related activities, and $48 million for a working capital facility (collectively, the "Project Financing"). The working capital facility also permits the issuance of letters of credit. The interest rate on the Project Financing is equal to either the Base Rate or Eurodollar Rate plus the Applicable Margin, as each is defined in the related agreements. The effective interest rate as of December 31, 2012 was 4.03%.
The availability under the working capital facility was reduced to $30 million on December 29, 2011 (90 days after the GenConn Middletown completion date). On March 22, 2012, the working capital facility was increased to $35 million. As of December 31, 2012, there were no borrowings under the working capital facility and there were letters of credit outstanding totaling $11.1 million and $22.0 million related to GenConn Devon and GenConn Middletown, respectively.
The maturity date of the Project Financing is April 24, 2016, provided that the working capital facility is paid in full on its maturity date of April 24, 2014. Principal payments are required to be made quarterly on the original $243 million borrowed. Borrowings on the Project Financing are reflected as Long-Term Debt in the accompanying Consolidated Balance Sheet.
Substantially all of the assets of GenConn serve as collateral for the Project Financing. As of December 31, 2012 and 2011, the carrying value of the Long-Term Debt approximated fair value. Under the Project Financing, GenConn is required to comply with certain covenants including the requirement to maintain a historical debt service coverage ratio (as defined) of at least 1.1 to 1.0. As of December 31, 2012, GenConn's historical debt service coverage ratio was 2.59. In addition, GenConn is subject to a dividend payment test whereby quarterly dividends are permitted if the debt service coverage ratio for the last twelve months and the next twelve months are at least 1.3 to 1.0. As of December 31, 2012, GenConn had met all of its debt service coverage ratios to date. Information regarding repayments is set forth below (in 000's):
|
During the twelve months ended December 31st:
|
Total
|
||
|
2013
|
$
|
8,100
|
|
|
2014
|
8,100
|
|
|
|
2015
|
8,100
|
|
|
|
2016
|
204,095
|
|
|
|
$
|
228,395
|
|
|
GenConn filed an application with PURA on June 28, 2012, seeking approval to refinance its long-term debt. In the application, GenConn requested the flexibility to execute a refinancing in order to access credit and/or bank markets when market conditions are deemed favorable by issuing notes in the private placement market or executing a bank loan in the bank market or a combination of notes and bank debt during the financing period, which would end on April 24, 2016, the maturity of the existing project financing. The working capital facility matures on April 24, 2014. PURA issued a final decision on August 13, 2012 granting approval of GenConn's application.
116
Unamortized Debt Expense
GCE and GenConn deferred debt issuance costs incurred on the bank and project financings, which are being amortized over the term of the related debt and allocated evenly to both GenConn Devon and GenConn Middletown. The amortization and associated unamortized debt issuance cost balances are accounted for at GenConn Devon and GenConn Middletown as such amounts are recovered in rates. The unamortized debt issuance costs are included in Unamortized Debt Expense in the accompanying Consolidated Balance Sheet as of December 31, 2012 and 2011.
Related Party Transactions
There are no employees of GCE or any of its subsidiaries. UI and NRG (the Partners) are paid, through GCE, for services to GenConn which include administration, plant operations, construction and energy management pursuant to contractual arrangements. As of December 31, 2012 and December 31, 2011, amounts owed to the Partners for services was $0.8 million and $1.0 million, respectively, are included in Accounts Payable in the accompanying Consolidated Balance Sheet. For the years ended December 31, 2012, 2011, and 2010 amounts paid to the Partners for services was $9.3 million, $22.4 million, and $16.9 million, respectively.
For the years ended December 31, 2012, 2011, and 2010 amounts paid to the Partners, through GCE, for interest was zero, $2.5 million and $7.5 million, respectively.
For the years ended December 31, 2012, 2011, and 2010 interest expense on the related party notes from the Partners was zero, $2.4 million, and $6.7 million, respectively, and is included in the accompanying Consolidated Statements of Operations.
GenConn made distributions, through GCE, to the Partners of $39.3 million, $15.9 million, and zero for the years ended December 31, 2012, 2011, and 2010, respectively.
GenConn returned a portion of the Partner's investment, through GCE, of $3.7 million and zero for the years ended December 31, 2012, 2011, and 2010, respectively.
GenConn Devon and GenConn Middletown lease both facilities and land from Devon Power LLC (Devon Power) and Middletown Power LLC (Middletown Power), respectively, both of which are subsidiaries of NRG. See the Lease Obligations section for additional details.
Income Taxes
GCE is not subject to federal or state income taxes. UI and NRG are required to report on their federal and, as required, state income tax return its share of GCE's income, gains, losses, deductions and credits. Accordingly, there is no provision for income taxes in the accompanying consolidated financial statements.
Derivatives
In connection with the Project Financing, in April 2009, GenConn entered into an interest rate swap agreement with each of the five of the banks participating in the syndication to reduce the risk of unfavorable changes in variable interest rates related to a portion of the Project Financing. The swaps have the effect of converting variable rate payments to fixed rate payments on approximately $42 million to $121 million principal amount outstanding of Project Financing debt through December 31, 2014 with quarterly settlements that began on March 31, 2010. Any income generated from the agreement is expected to be credited to customers and any expense generated is expected to be recovered from customers through PURA-approved revenue requirements. GenConn is accounting for the interest rate swap agreement as an economic hedge. As such, GenConn established a regulatory liability or asset for the mark-to-market adjustments related to the interest rate swaps. As of December 31, 2012 and 2011, $6.5 million and $8.5 million, respectively, were recorded as a Derivative Liability offset by a Regulatory Asset in the accompanying Consolidated Balance Sheet. The fair value hierarchy levels are Level 1 (quoted prices in active markets for identical assets and liabilities), Level 2 (significant other observable inputs), and Level 3 (significant unobservable inputs).
GenConn utilizes an income approach valuation technique to value the interest rate swap derivatives measured and reported at fair value. As required by the authoritative guidance on fair value measurements, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The interest rate swaps are valued based on the annual London Interbank Offering Rate (LIBOR) index. GenConn's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. GenConn has determined that the fair value of its interest rate swap derivatives are measured using Level 2 inputs.
117
Contingencies
In the ordinary course of business, GCE and its subsidiaries are involved in various proceedings, including legal, tax, regulatory and environmental matters, which require management's assessment to determine the probability of whether a loss will occur and, if probable, an estimate of probable loss. When assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated, GCE accrues a reserve and discloses the reserve and related matter. GCE discloses matters when losses are probable for which an estimate is reasonably possible. Subsequent analysis is performed on a periodic basis to assess the impact of any changes in events or circumstances and any resulting need to adjust existing reserves or record additional reserves.
In April 2011, a circuit interconnecting two of the four units at the GenConn Middletown facility to the gas insulated substation failed. The circuit was replaced; however, it continued to exhibit persistent partial discharge and was monitored via periodic testing. In March 2012, GenConn filed a lawsuit seeking damages against the electrical contractor responsible for the design and installation of the defective circuit. Please refer to Deferred Project Costs included in the Regulatory Accounting table for further information for costs incurred as of December 31, 2012 regarding the defective equipment.
On July 13, 2012, two of the four units at the GenConn Middletown facility were taken out of service due to further partial discharge testing results on the related cable and terminal interconnection equipment within the circuit to address operational and safety concerns. On August 8, 2012, the remaining two units at the GenConn Middletown facility were taken out of service due to similar partial discharge test results. GenConn hired another electrical contractor to undertake the replacement of the defective equipment. The defective equipment was replaced during the second half of 2012 and all four units were returned to service on January 19, 2013. As a result of the outage, GenConn incurred penalties for not achieving availability in the LFRM in the amount of $0.1 million during the twelve months ended December 31, 2012. Penalties incurred from January 1 through January 19, 2013 were minor. The penalties incurred are included in the Operating Expenses in the accompanying Consolidated Statements of Operations. The amount is net of the amount of coverage GenConn obtained for the unavailable capacity.
In March 2012, the former electrical contractor responsible for the failed installation filed a mechanic's lien on the GenConn Middletown project in the amount of $1.8 million. In order to comply with certain covenants under the project financing, GenConn Middletown was required to post a surety bond for the total amount which discharged the lien. As of December 31, 2012, GenConn Middletown recorded $0.4 million as a regulatory asset and accrued $0.7 million, which was included in Property, Plant and Equipment, related to the $1.8 million claim. GenConn Middletown is currently awaiting a response from the former electrical contractor for detailed support for the remaining $0.7 million claim. Until a response is received, GenConn Middletown cannot presently assess the merit of this claim. To the extent that GenConn is required to satisfy any of the claims, recovery of such costs would be expected through future rates.
In July 2011, GenConn Devon and the former general contractor responsible for the construction of the GenConn Devon facility entered into a settlement agreement with respect to change order requests and delay and impact claims and pursuant to which GenConn Devon paid a settlement amount of $10.5 million upon satisfaction of certain conditions performed by the former general contractor. In April 2011, GenConn Middletown settled a claim by the former general contractor for work at the GenConn Middletown facility and entered into a settlement agreement pursuant to which GenConn Middletown paid a settlement amount of $3.0 million which is included in Property, Plant and Equipment in the accompanying Consolidated Balance Sheet. PURA has approved GenConn's recovery of the associated costs.
In December 2010, GenConn Middletown was required to provide a $1.4 million Letter of Credit (LC) to the owner of the transmission facilities to which GenConn Middletown connects. The LC is related to remaining work on the transmission facilities. Correspondingly, GenConn Middletown has a $3.5 million performance bond from the contractor required to complete the remaining work. In April 2011, GenConn Middletown was required to provide an additional $0.9 million LC for additional work on the same transmission facilities. In February 2013, the $0.9 million LC was reduced to $0.05 million and the $3.5 million performance bond from the contractor was reduced to $0.1 million as a significant portion of the work on the transmission facilities has been completed. The $1.4 million LC was released by the owner of the transmission facilities during the first quarter of 2013.
118
Lease Obligations
Operating leases with Devon Power and Middletown Power consist primarily of leases of facilities and land for both GenConn Devon and GenConn Middletown. For the years ended December 31, 2012, 2011, and 2010, operating lease expense for GenConn Devon and GenConn Middletown was $0.6 million, $0.7 million, and $0.4 million, respectively. The future minimum lease payments under these operating leases are estimated to be as follows (in 000's):
|
Twelve months ended December 31st:
|
GenConn
Devon
|
GenConn
Middletown
|
|||||
|
2013
|
$
|
579
|
|
$
|
668
|
|
|
|
2014
|
579
|
|
668
|
|
|||
|
2015
|
579
|
|
668
|
|
|||
|
2016
|
579
|
|
668
|
|
|||
|
2017
|
579
|
|
668
|
|
|||
|
2018 and thereafter
|
12,980
|
|
15,643
|
|
|||
|
$
|
15,875
|
|
$
|
18,983
|
|
||
119
EXHIBIT INDEX
|
Number
|
Description
|
Method of Filing
|
||
|
3.1
|
Amended and Restated Certificate of Incorporation of NRG Yield, Inc., dated as of July 22, 2013.
|
Incorporated herein by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed on July 26, 2013.
|
||
|
3.2
|
Second Amended and Restated Bylaws of NRG Yield, Inc., dated as of July 22, 2013.
|
Incorporated herein by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K filed on July 26, 2013.
|
||
|
4.1
|
Second Amended and Restated Limited Liability Company Agreement of NRG Yield LLC, dated as of July 22, 2013.
|
Incorporated herein by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on July 26, 2013.
|
||
|
10.1
|
Registration Rights Agreement, dated as of July 22, 2013, by and between NRG Energy, Inc. and NRG Yield, Inc.
|
Incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on July 26, 2013.
|
||
|
10.2
|
Exchange Agreement, dated as of July 22, 2013, by and among NRG Energy, Inc., NRG Yield, Inc. and NRG Yield LLC.
|
Incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed on July 26, 2013.
|
||
|
10.3
|
Right of First Offer Agreement, dated as of July 22, 2013, by and between NRG Energy, Inc. and NRG Yield, Inc.
|
Incorporated herein by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K filed on July 26, 2013.
|
||
|
10.4
|
Management Services Agreement, dated as of July 22, 2013, by and between NRG Energy, Inc., NRG Yield, Inc., NRG Yield LLC and NRG Yield Operating LLC
|
Incorporated herein by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K filed on July 26, 2013.
|
||
|
10.5
|
Trademark License Agreement, dated as of July 22, 2013, by and between NRG Energy, Inc. and NRG Yield, Inc.
|
Incorporated herein by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K filed on July 26, 2013.
|
||
|
10.6
|
Credit Agreement, dated as of July 22, 2013, by and among NRG Yield Operating LLC, NRG Yield LLC, Bank of America, N.A., as Administrative Agent and L/C Issuer, the lenders party thereto, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Goldman Sachs Bank USA and Citigroup Global Markets Inc., as Joint Lead Arrangers and Joint Book Runners, and Goldman Sachs Bank USA and Citibank, N.A., as Co-Syndication Agents.
|
Incorporated herein by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K filed on July 26, 2013.
|
||
|
10.7
|
Credit Agreement, dated as of October 8, 2010, by and among NRG Marsh Landing LLC (formerly Mirant Marsh Landing, LLC), the Royal Bank of Scotland PLC, as administrative agent and Deutsche Bank Trust Company Americas, as Collateral Agent and Depository Bank
|
Incorporated herein by reference to Exhibit 10.1.48 to GenOn Energy, Inc.'s Annual Report on Form 10-K filed on March 1, 2011.
|
||
|
10.8
|
Loan Guarantee Agreement, dated as of September 30, 2011, by and among High Plains Ranch II, LLC, as borrower, the U.S. Department of Energy, as guarantor, and the U.S. Department of Energy, as loan servicer
|
Incorporated herein by reference to Exhibit 10.8 to the Company's Registration Statement on Form S-1/A filed on March 15, 2013.
|
||
|
10.9
|
Operation and Maintenance Agreement, dated as of January 31, 2011, by and among Avenal Solar Holdings LLC and NRG Energy Services LLC
|
Incorporated herein by reference to Exhibit 10.11 to the Company's Registration Statement on Form S-1/A filed on March 15, 2013.
|
||
|
10.10
|
Asset Management Agreement, dated as of August 30, 2012, by and among NRG Solar Avra Valley LLC and NRG Solar Asset Management LLC
|
Incorporated herein by reference to Exhibit 10.12 to the Company's Registration Statement on Form S-1/A filed on March 15, 2013.
|
||
|
10.11
|
Operation and Maintenance Agreement, dated as of August 1, 2012, by and among NRG Energy Services LLC and NRG Solar Borrego I LLC
|
Incorporated herein by reference to Exhibit 10.13 to the Company's Registration Statement on Form S-1/A filed on March 15, 2013.
|
||
|
10.12
|
Asset Management Agreement, dated as of March 15, 2012, by and among NRG Solar Alpine LLC and NRG Solar Asset Management LLC
|
Incorporated herein by reference to Exhibit 10.14 to the Company's Registration Statement on Form S-1/A filed on March 15, 2013.
|
||
|
10.13
|
Operation and Maintenance Agreement, dated as of September 30, 2011, by and among NRG Energy Services LLC and High Plains Ranch II, LLC
|
Incorporated herein by reference to Exhibit 10.15 to the Company's Registration Statement on Form S-1/A filed on March 15, 2013.
|
||
|
10.14
|
Project Administration Agreement, dated as of August 16, 2010, by and among South Trent Wind LLC and NRG Texas Power LLC
|
Incorporated herein by reference to Exhibit 10.16 to the Company's Registration Statement on Form S-1/A filed on March 15, 2013.
|
||
|
10.15
|
Operation and Maintenance Agreement, dated as of April 24, 2009, by and among GenConn Devon LLC and Devon Power LLC
|
Incorporated herein by reference to Exhibit 10.15 to the Company's Registration Statement on Form S-1 filed on June 6, 2013.
|
||
|
10.16
|
Operation and Maintenance Agreement, dated as of April 24, 2009, by and among GenConn Middletown LLC and Middletown Power LLC
|
Incorporated herein by reference to Exhibit 10.16 to the Company's Registration Statement on Form S-1 filed on June 6, 2013.
|
||
120
|
10.17
|
Administrative Services Agreement, dated as of April 2, 2009, by and among GenOn Energy Services, LLC (formerly Mirant Services, LLC) and NRG Marsh Landing, LLC (formerly Mirant Marsh Landing, LLC
|
Incorporated herein by reference to Exhibit 10.17 to the Company's Registration Statement on Form S-1 filed on June 6, 2013.
|
||
|
10.18†
|
NRG Yield, Inc. 2013 Equity Incentive Plan
|
Incorporated herein by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K filed on July 26, 2013.
|
||
|
10.19
|
Form of Indemnification Agreement
|
Incorporated herein by reference to Exhibit 10.20 to the Company's Registration Statement on Form S-1/A filed on June 21, 2013.
|
||
|
21.1
|
Subsidiaries of NRG Yield, Inc.
|
Filed herewith
|
||
|
23.1
|
Consent of KPMG
|
Filed herewith
|
||
|
31.1
|
Rule 13a-14(a)/15d-14(a) certification of David W. Crane
|
Filed herewith
|
||
|
31.2
|
Rule 13a-14(a)/15d-14(a) certification of Kirkland B. Andrews
|
Filed herewith
|
||
|
31.3
|
Rule 13a-14(a)/15d-14(a) certification of Ronald B. Stark
|
Filed herewith
|
||
|
32
|
Section 1350 Certification
|
Filed herewith
|
||
|
101 INS
|
XBRL Instance Document
|
Filed herewith
|
||
|
101 SCH
|
XBRL Taxonomy Extension Schema
|
Filed herewith
|
||
|
101 CAL
|
XBRL Taxonomy Extension Calculation Linkbase
|
Filed herewith
|
||
|
101 DEF
|
XBRL Taxonomy Extension Definition Linkbase
|
Filed herewith
|
||
|
101 LAB
|
XBRL Taxonomy Extension Label Linkbase
|
Filed herewith
|
||
|
101 PRE
|
XBRL Taxonomy Extension Presentation Linkbase
|
Filed herewith
|
||
|
†
|
Indicates exhibits that constitute compensatory plans or arrangements.
|
|
121
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
|
NRG YIELD, INC.
(Registrant)
|
|
||
|
|
/s/ DAVID W. CRANE
|
|
||
|
|
David W. Crane
|
|
||
|
|
Chief Executive Officer
(Principal Executive Officer)
|
|
||
|
|
||||
|
Date: February 28, 2014
|
|
|||
|
|
||||
122
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints David W. Crane, David R. Hill and Brian E. Curci, each or any of them, such person's true and lawful attorney-in-fact and agent with full power of substitution and resubstitution for such person and in such person's name, place and stead, in any and all capacities, to sign any and all amendments to this report on Form 10-K, and to file the same with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing necessary or desirable to be done in and about the premises, as fully to all intents and purposes as such person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them or his or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
In accordance with the Exchange Act, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on
February 28, 2014
.
|
Signature
|
Title
|
Date
|
||
|
/s/ DAVID W. CRANE
|
President, Chief Executive Officer and
|
February 28, 2014
|
||
|
David W. Crane
|
Chairman of the Board (Principal Executive Officer)
|
|||
|
/s/ KIRKLAND B. ANDREWS
|
Chief Financial Officer
|
February 28, 2014
|
||
|
Kirkland B. Andrews
|
(Principal Financial Officer)
|
|||
|
/s/ RONALD B. STARK
|
Chief Accounting Officer
|
February 28, 2014
|
||
|
Ronald B. Stark
|
(Principal Accounting Officer)
|
|||
|
/s/ JOHN CHLEBOWSKI
|
Director
|
February 28, 2014
|
||
|
John Chlebowski
|
||||
|
/s/ BRIAN FORD
|
Director
|
February 28, 2014
|
||
|
Brian Ford
|
||||
|
/s/ MAURICIO GUTIERREZ
|
Director
|
February 28, 2014
|
||
|
Mauricio Gutierrez
|
||||
|
/s/ FERRELL MCCLEAN
|
Director
|
February 28, 2014
|
||
|
Ferrell McClean
|
||||
|
/s/ CHRISTOPHER SOTOS
|
Director
|
February 28, 2014
|
||
|
Christopher Sotos
|
||||
123
TABLE OF CONTENTS
Part IItem 1 BusinessItem 1A Risk FactorsItem 1B Unresolved Staff CommentsItem 2 PropertiesItem 3 Legal ProceedingsItem 4 Mine Safety DisclosuresPart IIItem 5 Market For Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity SecuritiesItem 6 Selected Financial DataItem 7 Management's Discussion and Analysis Of Financial Condition and The Results Of OperationsItem 7A Quantitative and Qualitative Disclosures About Market RiskItem 8 Financial Statements and Supplementary DataItem 9 Changes in and Disagreements with Accountants on Accounting and Financial DisclosureItem 9A - Controls and ProceduresItem 9B Other InformationPart IIIItem 10 Directors, Executive Officers and Corporate GovernanceItem 11 Executive CompensationItem 12 Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder MattersItem 13 Certain Relationships and Related Transactions, and Director IndependenceItem 14 Principal Accounting Fees and ServicesPart IVItem 15 Exhibits, Financial Statement SchedulesNote 1 Nature Of BusinessNote 2 Summary Of Significant Accounting PoliciesNote 3 Business AcquisitionsNote 4 Property, Plant and EquipmentNote 5 Investments Accounted For By The Equity Method and Variable Interest EntitiesNote 6 Fair Value Of Financial InstrumentsNote 7 Accounting For Derivative Instruments and Hedging ActivitiesNote 8 Intangible AssetsNote 9 Long-term DebtNote 10 Earnings Per ShareNote 11 Stockholders' EquityNote 12 Segment ReportingNote 13 Income TaxesNote 14 Related Party TransactionsNote 15 Commitments and ContingenciesNote 16 Unaudited Quarterly DataNote 1 Background and Basis Of PresentationNote 2 Long-term DebtNote 3 Commitments, Contingencies and Guarantees