UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
xx ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2015
Or
oo TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File No. 001-37660
Avangrid, Inc.
(Exact name of registrant as specified in its charter)
New York 4911 14-1798693
(State or other jurisdiction of
incorporation or organization)
(Primary Standard Industrial
Classification Code Number)
(I.R.S. Employer
Identification No.)
157 Church Street
New Haven, Connecticut
06506
(Address of principal executive offices) (Zip Code)
Telephone: (207) 688-6363
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
Common Stock, $0.01 par value per share par value New York Stock Exchange
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 15(d) of the Act. Yes o No x
Indicate by check mark whether the registrant (1) has filed all reports required 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 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) is not contained herein, and will not be contained, to the best of
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. x
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 definitions of “large
accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o Accelerated filer o
Non-accelerated filer x (Do not check if a smaller reporting company) Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2015, the last business day of the registrant’s most
recently completed second fiscal quarter: the registrants common stock was not publicly traded.
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: 308,962,088 shares of common stock, par value $0.01,
were outstanding as of March 28, 2016.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved.
Designated portions of the Proxy Statement relating to the 2016 Annual Meeting of the Shareholders are incorporated by reference into Part III to the extent described therein.
TABLE OF CONTENTS
GLOSSARY OF TERMS AND ABBREVIATIONS 1
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS 5
PART I 6
Item 1. Business 6
Item 1A. Risk Factors 25
Item 1B. Unresolved Staff Comments. 40
Item 2. Properties. 40
Item 3. Legal Proceedings. 40
Item 4. Mine Safety Disclosures. 43
Executive Officers of AVANGRID 44
PART II 46
Item 5. Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. 46
Item 6. Selected Financial Data 47
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 48
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 77
Item 8. Financial Statements and Supplementary Data 80
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. 168
Item 9A. Controls and Procedures. 168
Item 9B. Other information. 168
PART III 169
Item 10. Directors, Executive Officers and Corporate Governance. 169
Item 11. Executive Compensation. 169
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. 169
Item 13. Certain Relationships and Related Transactions, and Director Independence. 169
Item 14. Principal Accounting Fees and Services. 169
Part IV 170
Item 15. Exhibits and Financial Statement Schedules. 170
SIGNATURES 175
i
GLOSSARY OF TERMS AND ABBREVIATIONS
Unless the context indicates otherwise, the terms “we,” and our” are used to refer to AVANGRID and its subsidiaries.
GenConn Devon refers to GenConn’s peaking generating plant in Devon, Connecticut.
GenConn Middletown refers to GenConns peaking generating plant in Middletown, Connecticut.
Iberdrola Group refers to the group of companies controlled by Iberdrola, S.A.
Iberdrola, S.A. refers to the 81.5% controlling parent company of AVANGRID, Inc.
Installed capacity refers to the production capacity of a power plant or wind farm based either on its rated (nameplate) capacity or actual capacity.
Klamath Plant refers to the Klamath gas-fired cogeneration facility.
Merger Agreement refers to the Agreement and Plan of Merger, dated as of February 25, 2015, by and among AVANGRID, Inc., Green Merger Sub, Inc. and
UIL Holdings Corporation.
NED pipeline refers to TGP’s proposed Northeast Energy Direct project.
Yankee Companies refers to the Maine Yankee Atomic Power Company, the Connecticut Yankee Power Corporation, and the Yankee Atomic Energy
Corporation.
AMI Automated Metering Infrastructure
AOCI
Accumulated other comprehensive income
ARHI Avangrid Renewables Holdings, Inc.
ASC
Accounting Standards Codification
Army Corps U.S. Army Corps of Engineers
ARO Asset retirement obligation
AVANGRID AVANGRID, Inc.
Bcf One billion cubic feet
Berkshire The Berkshire Gas Company
BGEPA Bald and Golden Eagle Protection Act
BLM U.S. Bureau of Land Management
Cayuga Cayuga Operating Company, LLC
CENG Constellation Energy Nuclear Group, LLC
CfDs Contracts for Differences
CFTC Commodity Futures Trading Commission
CL&P The Connecticut Light and Power Company
CMP Central Maine Power Company
CNG Connecticut Natural Gas Corporation
CSC Connecticut Siting Council
DCF Discounted cash flow
DER Distributed energy resources
Dodd-Frank Act Dodd-Frank Wall Street Reform and Consumer Protection Act
DOE Department of Energy
DOJ Department of Justice
DPA Deferred Payment Arrangements
DPU Massachusetts Department of Public Utilities
DSIP Distributed System Implementation Plan
DSP Distributed System Platform
DTh Dekatherm
EBITDA Earnings before interest, taxes, depreciation and amortization
EPA Environmental Protection Agency
EPAct 2005 Energy Policy Act of 2005
ERCOT Electric Reliability Council of Texas
ESA Endangered Species Act
ESC Earnings Smart Community
ESM Earnings sharing mechanism
Exchange Act The Securities Exchange Act of 1934, as amended
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
FirstEnergy FirstEnergy Corp.
FPA Federal Power Act
Gas Enstor Gas, LLC
GenConn GenConn Energy LLC
Ginna Ginna Facility and GNPP
Ginna Facility R.E. Ginna Nuclear Power Plant
GNPP Ginna Nuclear Power Plant
GSRP Greater Springfield Reliability Project
HLPSA Hazardous Liquids Pipeline Safety Act of 1979
IRP Interstate Reliability Project
IRS Internal Revenue Service
ISO Independent system operator
ISO-NE ISO New England, Inc.
Kinder Morgan Kinder Morgan, Inc.
kV Kilovolts
kWh Kilowatt-hour
LIBOR London Interbank Offer Rate
LNS Local Network Service
MBTA Migratory Bird Treaty Act
Mcf One thousand cubic feet of natural gas
2
Merger Sub Green Merger Sub, Inc.
MEPCO Maine Electric Power Corporation
MGP Manufactured Gas Plants
MISO Midcontinent Independent System Operator, Inc.
MHI Mitsubishi Heavy Industries
MNG Maine Natural Gas Corporation
MOU Memorandum of Understanding
MPRP Maine Reliability Power Program
MPUC Maine Public Utilities Commission
MW Megawatts
MWh Megawatt-hours
NAV Net asset value
NEEWS New England East West Solution
NEPA National Environmental Policy Act
NERC North American Electric Reliability Corporation
Networks Avangrid Networks, Inc.
New York TransCo New York TransCo, LLC.
NIPSCO Northern Indiana Public Service Company
NGA Natural Gas Act of 1938
NGPSA Natural Gas Pipeline Safety Act of 1968
NOL Net operating loss
NPNS Normal purchases and normal sales
NYISO New York Independent System Operator, Inc.
NYPA New York Power Authority
NYPSC New York State Public Service Commission
NYSE New York Stock Exchange
NYSEG New York State Electric & Gas Corporation
OATT Open Access Transmission Tariiff
OCC Office of Consumer Counsel
OSHA Occupational Safety and Health Act, as amended
PCB Polychlorinated Biphenyls
PHMSA Pipeline and Hazardous Materials Safety Administration
PPA Power purchase agreement
PTF Pool Transmission Facilities
PUCT Public Utility Commission of Texas
PUHCA 2005 Public Utility Holding Company Act of 2005
3
PURA Connecticut Public Utilities Regulatory Authority
RAM Rate Adjustment Mechanism
RCRA Resource Conservation and Recovery Act
RDM Revenue decoupling mechanism
REC Renewable Energy Certificate
RFP Request for Proposals
Renewables Avangrid Renewables, LLC
REV Reforming the Energy Vision
RGE Rochester Gas and Electric Corporation
ROE Return on equity
RNS Regional Network Service
RPS Renewable Portfolio Standards
RSSA Reliability Support Services Agreement
RTO Regional transmission organizations
SCG The Southern Connecticut Gas Company
SEC United States Securities and Exchange Commission
SNF Spent Nuclear Fuel
SPHI Scottish Power Holdings, Inc.
TEF Tax equity financing arrangements
TGP Tennessee Gas Pipeline Company LLC
TOTS Transmission Owner Transmission Solutions
UI The United Illuminating Company
UIL UIL Holdings Corporation
WECC Western Electricity Coordinating Council
4
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains a number of forward-looking statements. Forward-looking statements may be identified by the use of
forward-looking terms such as “may,” will,“should, “can,” expects, “believes,” anticipates, “intends,” plans,” “estimates, “projects,” “assumes,
“guides,” targets,forecasts,is confident thatand “seeks” or the negative of such terms or other variations on such terms or comparable terminology.
Such forward-looking statements include, but are not limited to, statements about our plans, objectives and intentions, outlooks or expectations for earnings,
revenues, expenses or other future financial or business performance, strategies or expectations, or the impact of legal or regulatory matters on business,
results of operations or financial condition of the business and other statements that are not historical facts. Such statements are based upon the current beliefs
and expectations of our management and are subject to significant risks and uncertainties that could cause actual outcomes and results to differ materially.
Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, without limitation, the
risks and uncertainties set forth under Part I, Item 1A,Risk Factors” in this report. Specifically, forward-looking statements may include statements relating
to:
·
the future financial performance, anticipated liquidity and capital expenditures of the company;
·
success in retaining or recruiting, or changes required in, our officers, key employees or directors;
·
the risk that the businesses will not be coordinated successfully, or that the coordination will be more costly or more time consuming and
complex than anticipated;
·
disruption from the merger making it difficult to maintain business and operational relationships;
·
adverse developments in general market, business, economic, labor, regulatory and political conditions;
·
the impact of any cyber-breaches, acts of war or terrorism or natural disasters; and
·
the impact of any change to applicable laws and regulations affecting operations, including those relating to environmental and climate
change, taxes, price controls, regulatory approval and permitting.
Should one or more of these risks or uncertainties materialize, or should any of the underlying assumptions prove incorrect, actual results may vary in
material respects from those expressed or implied by these forward-looking statements. You should not place undue reliance on these forward-looking
statements. We do not undertake any obligation to update or revise any forward-looking statements to reflect events or circumstances after the date of this
report, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws.
5
PART I
Item 1. Business
Overview
AVANGRID, Inc., or AVANGRID, formerly Iberdrola USA, Inc., is a New York corporation headquartered in New Gloucester, Maine. We are a direct,
majority owned subsidiary of Iberdrola, S.A., a corporation (sociedad anima) organized under the laws of Spain, one of the world’s leading energy
companies. Our primary business is ownership of our operating businesses, which are described below.
Our direct, wholly-owned subsidiaries include Avangrid Networks, Inc., or Networks, Avangrid Renewables Holdings, Inc., or ARHI, and UIL Holdings
Corporation, or UIL. ARHI in turn holds subsidiaries including Avangrid Renewables LLC, or Renewables, and Enstor Gas, LLC, or Gas. Networks, along
with UIL, owns and operates our regulated utility businesses, including electric transmission and distribution and natural gas distribution, transportation and
sales. Renewables operates a portfolio of renewable energy generation facilities primarily using onshore wind power, and also solar, biomass and thermal
power. Gas operates our natural gas storage facilities and gas trading businesses through Enstor Energy Services LLC (gas trading) and Enstor Inc. (gas
storage). Avangrid Service Company, a subsidiary of Networks, provides corporate and back office services on a consolidated basis to our subsidiaries.
On December 16, 2015, we completed an acquisition, pursuant to which UIL merged with and into our wholly-owned subsidiary, Green Merger Sub,
Inc., or Merger Sub, with Merger Sub surviving as our wholly-owned subsidiary. The acquisition was effected pursuant to the Agreement and Plan of Merger,
dated as of February 25, 2015, or the Merger Agreement, by and among us, Merger Sub, and UIL. Following the completion of the acquisition, Merger Sub
was renamed “UIL Holdings Corporation.
The primary business of UIL is the ownership of its operating regulated utility businesses. The utility businesses consist of the electric distribution and
transmission operations of The United Illuminating Company, or UI, and the natural gas transportation, distribution and sales operations of The Southern
Connecticut Gas Company, or SCG, Connecticut Natural Gas Corporation, or CNG, and The Berkshire Gas Company, or Berkshire. For purposes of this
document, all references to “Networks” include UIL and its subsidiaries, unless otherwise indicated.
After the acquisition UIL became a direct subsidiary of AVANGRID, which resulted in the following structure:
We currently anticipate that UIL and its subsidiaries will be moved under Networks in the first half of 2016. Through Networks, we own electric
generation, transmission and distribution companies and natural gas distribution, transportation and sales companies in New York and Maine, and manage
electric generation, transmission and distribution companies and natural gas distribution, transportation and sales companies in Connecticut and
Massachusetts, delivering electricity to approximately 2.2 million electric utility customers and delivering natural gas to approximately 984,000 natural gas
public utility customers as of December 31, 2015. The interstate transmission and wholesale sale of electricity by these regulated utilities is regulated by the
Federal Energy Regulatory
6
Commission, or FERC, under the Federal Power Act, or FPA, including with respect to transmission rates. Further, Networks’ electric and gas distribution
utilities in New York, Maine, Connecticut and Massachusetts are subject to regulation by the New York State Public Service Commission, or NYPSC, the
Maine Public Utilities Commission, or MPUC, the Connecticut Public Utilities Regulatory Authority, or PURA, and the Massachusetts Department of Public
Utilities, or DPU, respectively. Networks strives to be a leader in safety, reliability and quality of service to its utility customers.
Through Renewables, we had a combined wind, solar and thermal installed capacity of 6,330 megawatts, or MW, as of December 31, 2015, including
Renewables’ share of joint projects, of which 5,643 MW was installed wind capacity. Approximately 67% of the capacity was contracted for an average
period of 9.7 years as of December 31, 2015. As the second largest wind operator in the United States based on installed capacity as of December 31, 2015,
Renewables strives to lead the transformation of the U.S. energy industry to a competitive, clean energy future. Renewables currently operates 53 wind farms
in 18 states across the United States.
Through Gas, as of December 31, 2015 we own approximately 67.5 billion cubic feet, or Bcf, of net working gas storage capacity. Through Enstor
Energy Services, LLC, Gas operates 53.25 Bcf of contracted or managed gas storage capacity in North America as of December 31, 2015.
Further information regarding the amount of revenues from external customers, including revenues by products and services, a measure of profit or loss
and total assets for each segment for each of the last three fiscal years is provided in Note 23 of our audited combined and consolidated financial statements
for the three years ended December 31, 2015, which is incorporated herein by reference.
History
We were incorporated in 1997 as a New York corporation under the name NGE Resources, Inc. and subsequently changed our name to Energy East
Corporation. The stock of Energy East Corporation was publicly traded on the New York Stock Exchange, or the NYSE. In 2007, Iberdrola, S.A. acquired
Scottish Power Ltd., or Scottish Power, including ScottishPower Holdings, Inc., or SPHI, the parent company of Scottish Power’s U.S. subsidiaries. Through
this acquisition, Iberdrola, S.A. acquired PPM Energy, a subsidiary that operated SPHI’s U.S. wind business, thermal generation operations and the gas storage
and energy management businesses and changed PPM Energy’s name to Renewables. In 2008, Iberdrola, S.A. acquired Energy East Corporation and we
changed our name to Iberdrola USA, Inc. in December 2009. In 2013, we completed an internal corporate reorganization to create a unified corporate
presence for the Iberdrola brand in the United States, bringing all of its U.S. energy companies under one single holding company, Iberdrola USA. The
internal reorganization, completed in November 2013, resulted in the concentration of our principal businesses in two major subsidiaries: Networks, which
holds all of our regulated utilities; Renewables, which holds our renewable and thermal generation businesses, and gas storage and marketing businesses.
We were the corporate parent of SCG, CNG and Berkshire prior to UIL acquiring those companies in 2010.
On December 16, 2015, UIL became our wholly-owned subsidiary as a result of merging into Merger Sub, our wholly-owned subsidiary, with Merger
Sub surviving as our wholly-owned subsidiary. Following the completion of the acquisition, Merger Sub was renamed “UIL Holdings Corporationand we
were renamed AVANGRID, Inc. On February 18, 2016, the following AVANGRID subsidiaries changed their names as set forth below:
Old Company Name New Company Name
Iberdrola USA Networks, Inc. Avangrid Networks, Inc.
Iberdrola USA Solutions, Inc. Avangrid Solutions, Inc.
Iberdrola USA Group, LLC Avangrid Management Company, LLC
Iberdrola USA Management Corporation Avangrid Service Company
Iberdrola USA Enterprises, Inc. Avangrid Enterprises, Inc.
Iberdrola USA Networks New York TransCo, LLC Avangrid Networks New York TransCo, LLC
Iberdrola Energy Holdings, LLC Enstor Gas, LLC
Iberdrola Energy Services, LLC Enstor Energy Services, LLC
Iberdrola Renewables, LLC Avangrid Renewables, LLC
Iberdrola Renewables Holdings, Inc. Avangrid Renewables Holdings, Inc.
Iberdrola Arizona Renewables, LLC Avangrid Arizona Renewables, LLC
Iberdrola Texas Renewables, LLC Avangrid Texas Renewables, LLC
Iberdrola Logistic Services, LLC Avangrid Logistic Services, LLC
7
Networks
Overview
Networks, a Maine corporation, along with UIL, a Connecticut corporation, hold our regulated utility businesses, including electric transmission and
distribution and natural gas distribution, transportation and sales. Networks serves as a super-regional energy services and delivery company through eight
regulated utilities it owns directly or through UIL:
·
New York State Electric & Gas Corporation, or NYSEG: serves electric and natural gas customers across more than 40% of the upstate New
York geographic area;
·
Rochester Gas and Electric, or RGE: serves electric and natural gas customers within a nine-county region in western New York, centered
around Rochester;
·
UI: serves electric customers in southwestern Connecticut;
·
Central Maine Power Company, or CMP: serves electric customers in central and southern Maine;
·
SCG: serves natural gas customers in Connecticut;
·
CNG: serves natural gas customers in Connecticut;
·
Berkshire: serves natural gas customers in western Massachusetts; and
·
Maine Natural Gas Corporation, or MNG: serves natural gas customers in several communities in central and southern Maine;
For the year ended December 31, 2015, Networks distributed 37,528,920 megawatt-hours, or MWh, of electricity (includes 12 months of operation of
UIL). As of December 31, 2015, Networks provided service to its 2.2 million customers in the states of New York, Maine, Connecticut and Massachusetts. In
total, the electric system of Networks’ regulated utilities consisted of 8,482 miles of transmission lines, 70,916 miles of distribution lines and 826 substations
as of December 31, 2015. Furthermore, for the year ended December 31, 2015, Networks delivered more than 205 million dekatherms, or DTh, of natural gas
(includes 12 months of operation of UIL), to approximately 984,000 customers, providing service in the states of New York, Maine, Connecticut and
Massachusetts.
The demand for electric power and natural gas is affected by seasonal differences in the weather. Demand for electricity in each of the states in which
Networks operates tends to increase during the summer months to meet cooling load or in winter months for heating load while statewide demand for natural
gas tends to increase during the winter to meet heating load.
The following table sets forth certain information relating to the, rate base, number of customers and the amount of electricity or natural gas provided
by each of Networks’ regulated utilities for the year ended December 31, 2015:
Rate Base
(1)
(in billions)
Electricity
Customers
Electricity
Delivered
(in MWh)
Natural Gas
Customers
Natural Gas
Delivered
(in DTh)
Utility
December 31,
2015
December 31,
2015
For the
year ended
December 31,
2015
December 31,
2015
For the
year ended
December 31,
2015
NYSEG $ 2.4 885,000 15,711,000 265,000 56,533,000
RGE $ 1.6 375,000 7,110,000 310,000 51,498,000
CMP $ 2.3 616,979 9,256,920
MNG $ 0.1 4,432 15,400,000
UI $ 1.5 331,216 5,451,000
SCG $ 0.5 192,557 33,978,000
CNG $ 0.4 172,498 37,387,000
Berkshire $ 0.1 39,680 10,569,000
(1) “Rate base” means the net assets upon which a utility can receive a specified return, based on the value of such assets. The rate base is set by the relevant regulatory authority
and typically represents the value of specified property, such as plants, facilities and other investments of the utility.
Over the last five years, Networks has invested nearly $6.0 billion in creating a delivery network with greater capacity and improved reliability,
environmental security and sustainability, efficiency and automation. Networks continuously improves its grid to accommodate new requirements for
advanced metering, demand response and enhanced outage management, while improving its
8
flexibility for the integration and management of distributed energy resources, or DER. From 2009 to 2015, Networks increased capital expenditure
investments in its New York and Maine regulated utilities by 131%, from $315.0 million to $727.0 million.
New York
As of December 31, 2015, NYSEG served approximately 885,000 electricity customers and 265,000 natural gas customers across more than 40% of
upstate New Yorks geographic area, while RGE served approximately 375,000 electricity customers and 310,000 natural gas customers in a nine-county
region centered around Rochester, in western New York.
In 2015, NYSEG and RGE’s nine hydroelectric plants generated nearly 366 million kilowatt-hours, or kWh, of clean hydropower, which is enough
energy to power 51,000 homes across New York State, assuming an average electricity consumption of 600 kWh per month per customer. See “—Properties—
Networks” for more information regarding Networks’ electric generation plants.
Networks also holds an approximate 20% ownership interest in the regulated New York TransCo, LLC, or New York TransCo. Through New York
TransCo, Networks has formed a partnership along with Central Hudson Gas and Electric Corporation, Consolidated Edison, Inc., National Grid, plc and
Orange and Rockland Utilities, Inc. to develop a portfolio of interconnected transmission lines and substations to fulfill the objectives of the New York
energy highway initiative, a proposal to install up to 3,200 MW of new electric generation and transmission capacity in order to deliver more power
generated from upstate New York power plants to downstate New York.
Maine
As of December 31, 2015, CMP delivered electricity to more than 616,000 customers in an 11,000 square-mile service area in central and southern
Maine. CMP has completed a $1.4 billion investment plan for the construction of upgrades to the bulk power transmission grid in Maine, the largest
transmission investment in the history of Maine, which includes the construction of five new 345-kilovolt, or kV, substations and related facilities linked by
approximately 440 miles of new transmission lines (refers to the Maine Power Reliability Program, or MPRP). CMP in 2012 also completed a $200.0 million
investment, one-half of which was funded by the Department of Energy, or DOE, in advanced meter infrastructure, which included the installation of more
than 600,000 smart meters for all of its electric customers. Smart meters monitor and record a customer’s power consumption, eliminating the need for on-
site meter reading.
CMP also owns 78% of the Maine Electric Power Corporation, or MEPCO, a single-asset 182 mile 345kV electric transmission line from Orrington,
Maine to Wiscasset, Maine.
MNG delivers natural gas to 4,432 customers in central and southern Maine and recently completed construction of the first natural gas pipeline in
Augusta, Maine. Through MNG, Networks provides these communities in southern Maine with access to natural gas for the first time, offering a competitive
and clean energy option to homes and businesses.
Connecticut
As of December 31, 2015, UI served more than 331,000 residential, commercial and industrial customers in a service area of approximately 335 square
miles in the southwestern part of Connecticut. The service area includes Bridgeport and New Haven and is home to a diverse array of business sectors
including aerospace manufacturing, healthcare, biotech, financial services, precision manufacturing, retail and education. UI’s retail electric revenues vary
by season, with the highest revenues typically in the third quarter of the year reflecting seasonal rates, hotter weather and air conditioning use.
UI is also a party to a joint venture with certain affiliates of NRG Energy, Inc., pursuant to which UI holds 50% of the membership interests in GCE
Holding LLC, whose wholly owned subsidiary, GenConn Energy LLC, or GenConn, operates peaking generation plants in Devon, Connecticut, or GenConn
Devon, and Middletown, Connecticut, or GenConn Middletown.
As of December 31, 2015, SCG and CNG provided local gas distribution services to approximately 364,000 customers in the greater Hartford-New
Britain area, Greenwich and the southern Connecticut coast from Westport to Old Saybrook, including the cities of Bridgeport and New Haven.
9
Massachusetts
As of December 31, 2015, Berkshire provided local gas distribution services to approximately 40,000 customers in a service area in western
Massachusetts which includes the cities of Pittsfield, North Adams and Greenfield.
The rate base of Networks’ regulated utilities has increased significantly over the last three years, mainly due to the investments in regulated projects,
such as the Maine Reliability Power Program, or MPRP, transmission project in Maine and increased replacement of aging infrastructure and investments in
smart grid automation. The rate base of Networks’ regulated utilities for the years indicated below have been as follows:
Rate base 2013 2014 2015
(in millions)
NYSEG Electric $ 1,702 $ 1,796 $ 1,825
NYSEG Gas 482 508 531
RGE Electric 1,058 1,111 1,175
RGE Gas 427 444 446
Subtotal New York 3,669 3,859 3,977
CMP Dist 714 739 781
CMP Trans 1,252 1,467 1,472
MNG 47 64 60
Subtotal Maine 2,013 2,270 2,313
UI Dist 760 823 942
UI Trans 500 500 508
SCG 468 461 477
CNG 396 382 396
Subtotal Connecticut 2,124 2,166 2,323
Berkshire 70 72 91
Total $ 7,876 $ 8,367 $ 8,704
Earnings Sharing Mechanisms
The regulated utilities’ rate plans approved by regulators in New York, Maine, Connecticut and Massachusetts typically include earnings sharing
mechanisms, or ESM, that are intended to encourage regulated utilities to operate efficiently. Pursuant to ESMs, if certain of the regulated utilities of
Networks earn more than certain threshold amounts, they must share with customers a specified percentage of these earnings. Below is a history of ESMs over
the past three years:
2013 2014 2015
NYSEG Electric
50% / 50%: 10.90% - 11.65%
85% / 15%: over 11.65%;
Based on Actual Equity Ratio
up to 50%
50% / 50%: 10.90% - 11.65%
85% / 15%: over 11.65%;
Based on Actual Equity Ratio
up to 50%
50% / 50%: 10.90% - 11.65%
85% / 15%: over 11.65%;
Based on Actual Equity Ratio
up to 50%
NYSEG Gas Same as above Same as above Same as above
RGE Electric Same as above Same as above Same as above
RGE Gas Same as above Same as above Same as above
CMP Dist.
50% / 50% over 11.0%
Based on 47% Equity Ratio No ESM No ESM
CMP Trans. No ESM No ESM No ESM
MNG No ESM No ESM No ESM
UI 50% / 50% over 8.90%* 50% / 50% over 9.15% 50% / 50% over 9.15%
SCG No ESM No ESM No ESM
CNG No ESM 50% / 50% over 9.18% 50% / 50% over 9.18%
Berkshire No ESM No ESM No ESM
*
UIs rate case decision, effective in August 2013, increased the ROE threshold subject to ESM from 8.75% to 9.15%, resulting in a weighted average of 8.90% for calendar
year 2013.
10
Merger Settlement Agreement – Connecticut and Massachusetts
As part of the process of seeking and obtaining regulatory approval of the acquisition in Connecticut and Massachusetts, AVANGRID and UIL
reached settlement agreements with the Office of Consumer Counsel, or OCC, in Connecticut and with the Attorney General of the Commonwealth of
Massachusetts and the Department of Energy Resources in Massachusetts, which settlement agreements included commitments of actions to be taken after
the transaction closed. See Part II, Item 7, “Managements Discussion and Analysis of Financial Condition and Results of Operations – Networks” for more
information.
In connection with the acquisition proceeding, UI signed a proposed partial consent order, or the consent order that, when approved by the
Commissioner of DEEP, and pursuant to the terms and conditions in the consent order, would require UI to investigate and remediate certain environmental
conditions within the perimeter of the English Station site. To the extent that the investigation and remediation is less than $30 million, UI would remit to
the State of Connecticut the difference between such costs and $30 million for a public purpose as determined in the discretion of the Governor, the Attorney
General of Connecticut and the Commissioner of DEEP. Pursuant to the consent order, upon its issuance and subject to its terms and conditions, UI would be
obligated to comply with the consent order, even if the cost of such compliance exceeds $30 million. See Part I, Item 1, “Business Environmental, Health
and Safety - Management, Disposal and Remediation of Hazardous Substances” for more information.
Renewables
The Renewables business, based in Portland Oregon, is engaged primarily in the design, development, construction, management and operation of
generation plants that produce electricity using renewable resources and, with more than 50 renewable energy projects, is one of the leaders in renewable
energy production in the United States based on installed capacity. Renewables’ primary business is onshore wind energy generation, which represents
approximately 89% of Renewables’ combined installed capacity as of December 31, 2015. For the year ended December 31, 2015, Renewables produced
approximately 14,135,000 MWh of energy through wind power generation. Renewables had a pipeline of approximately 5,900 MW of future renewable
energy projects in various stages of development as of December 31, 2015.
Typically, Renewables enters into long-term lease agreements with property owners who lease their land for renewable projects. Electricity generated
at a wind project is then transmitted to customers through long-term agreements with purchasers. There are a limited number of turbine suppliers in the
market. Renewables’ largest turbine suppliers, Gamesa Wind US and GE Wind, in the aggregate supplied turbines which accounted for 67% of its installed
capacity as of December 31, 2015.
Renewables currently operates 53 wind farms in 18 states across the United States.
To monetize the tax benefits resulting from production tax credits
and accelerated tax depreciation available to qualifying wind energy projects, Renewables has entered into “tax equity” financing structures with third party
investors for a portion of its wind farms. Renewables holds 12 operating wind farms under these structures through limited liability companies jointly owned
by one or more third party investors. These investors generally provide an up-front investment or, in some cases, enter into fixed and contingent notes for
their membership interests in the financing structures. In return, the investors receive a majority or all of the cash flows and tax benefits generated by the wind
farms until such benefits achieve a negotiated return on their investment. Upon attainment of this target return, the sharing of the cash flows and tax benefits
flip, with Renewables receiving substantially all of these amounts thereafter. We also have an option to repurchase the investor’s interest within a certain
timeframe after the target return is met. Renewables maintains operational and management control over the wind farm businesses, subject to investor
approval of certain major decisions. See “—Properties—Renewables” for more information regarding Renewables’ wind power generation properties.
Additionally, as part of the Renewables portfolio, Renewables operates two thermal generation facilities in the United States, with 636 MW of
combined capacity as of December 31, 2015. Renewables worked closely with the City of Klamath Falls, Oregon to develop the Klamath Plant, which has a
current capacity of 536 MW, operating by creating two useful forms of energy, electricity and process steam, from a single fuel source of natural gas. In
addition, Renewables operates a highly flexible 100 MW Klamath Peaking Plant adjacent to the Klamath Plant, providing customers of Renewables
additional capability to meet their peak summer and winter power needs.
In addition to its wind assets, Renewables operates two solar photovoltaic facilities with an installed capacity of 50 MW. The solar photovoltaic
facilities produced over 126,000 MWh of renewable energy for the year ended December 31, 2015. Solar accounted for 0.9% of the total renewable energy
generation from Renewables in these same periods.
Renewables is pursuing the continued development of a large pipeline of wind energy projects in various regions across the United States. Each site
features a range of different atmospheric characteristics that ultimately drive the selection of turbine technology for the proposed project. As part of
Renewables’ wind resource assessment investigation, critical atmospheric parameters such as mean wind speed, extreme wind speed, turbulence intensity, and
mean air density are characterized to represent long-term
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conditions, for over 20 years. The summary wind characteristics are then combined with a terrain, or orography, analysis to assess siting risks in order to
mitigate any future operations and maintenance concerns that may arise due to improper turbine siting.
Renewables maintains close relationships with key turbine suppliers, including Gamesa, GE, Vestas, Siemens, and others in order to identify the
turbine technology that safely delivers the lowest cost of energy for each candidate project in its portfolio. Renewables has deployed the following mix of
turbines under this strategy. See “—Properties—Renewables” for more information regarding Renewables’ turbine technology.
MFG Model Rating Turbines MW
Gamesa G83 2.0 61 122
Gamesa G87 2.0 643 1,286
Gamesa G90 2.0 237 474
Gamesa G97 2.0 101 202
GE 1.5s 1.5 133 200
GE 1.5sle 1.5 1,072 1,608
MHI MWT62/1.0 1.0 45 45
MHI MWT92/2.4 2.4 168 403
MHI MWT95/2.4 2.4 125 300
MHI MWT102/2.4 2.4 1 2
NEG NM48 0.7 3 2
Siemens SWT2.3-93 2.3 44 101
Suzlon S88 2.1 341 716
Vestas V47 0.7 34 22
Vestas V82 1.7 97 160
Total 3,105 5,643
The Renewables meteorology team supports the commercial development of wind energy projects in Renewables’ pipeline by performing a wide
variety of detailed investigations to characterize the expected wind energy production from a proposed wind farm in its pre-construction phase of
development. These investigations include measuring the wind resource with several well-equipped meteorological masts, utilizing state of the art laser-
based and acoustic-based remote sensing equipment, computational fluid dynamics modeling software, and energy modeling software packages that
characterize wake losses from any upwind turbines that may be present. The Renewables fleet of measurement masts consists of over 160 towers that are
currently in operation. Additionally, a total of 8 light detecting and ranging, and 6 sonic detecting and ranging, remote sensing devices are deployed at sites
across the United States. These remote sensing devices allow hub-height wind speed measurement from a ground-based sensor that can be rapidly deployed
and moved as the project matures or changes in nature. The resulting pre-construction energy production estimates that utilize these measurements have been
shown to be accurate in a multi-year internal study that compares results to actual, operational data in a benchmarking analysis. This study provides a critical
feedback loop that is used to define methodology requirements for future pre-construction energy production estimates to ensure confidence in project
investment. Renewables’ commitment to obtaining robust atmospheric measurement is driven by a company culture that values business case confidence and
understands the role that accurate meteorological data play in the pursuit of this goal.
Gas
The Gas business, based in Houston, Texas, operates a natural gas storage and natural gas trading business through its wholly-owned direct
subsidiaries, Enstor, Inc., an Oregon corporation (natural gas storage) and Enstor Energy Services LLC, a Delaware limited liability company (natural gas
trading). Gas owns and operates four natural gas storage facilities, with a total storage capacity of 88.5 Bcf and a net working gas storage capacity of 67.5 Bcf.
Enstor Operating Company, LLC, a Texas limited liability company and wholly-owned direct subsidiary of Enstor, Inc., manages all four natural gas storage
facilities. The demand for natural gas storage is dependent upon the seasonal differences in the weather. Since market prices and temporal price spreads for
natural gas reflect the demand for these products and their availability at a given time, the overall operating results of Gas’ business may fluctuate
substantially on a seasonal basis. Severe weather, such as ice and snow storms, hurricanes and other natural disasters may cause outages, bodily injury or
property damage, which may require Gas to incur additional costs, such as operation and maintenance expenses, which may not be recoverable from
customers. See —Properties—Gas” for more information regarding Gas’ natural gas storage facilities. Enstor Energy Services LLC also contracts and
manages natural gas storage and pipeline capacity throughout the United States and parts of Canada. Gas operates 53.25 Bcf of contracted or managed
natural gas storage capacity in North America through Enstor Energy Services, LLC, as of December 31, 2015.
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Regulatory Environment and Principal Markets
Federal Energy Regulatory Commission
Among other things, FERC regulates the transmission and wholesale sales of electricity in interstate commerce and the transmission and sale of natural
gas for resale in interstate commerce. Certain aspects of Networks’ businesses, Renewables’ competitive generation and Gas’ natural gas storage and energy
trading businesses are subject to regulation by FERC.
Pursuant to the FPA, electric utilities must maintain tariffs and rate schedules on file with FERC which govern the rates, terms and conditions for the
provision of FERC-jurisdictional wholesale power and transmission services. Unless otherwise exempt, any person that owns or operates facilities used for the
wholesale sale or transmission of power in interstate commerce is a public utility subject to FERCs jurisdiction. FERC regulates, among other things, the
disposition of certain utility property, the issuance of securities by public utilities, the rates, the terms and conditions for the transmission or wholesale sale of
power in interstate commerce, interlocking officer and director positions, and the uniform system of accounts and reporting requirements for public utilities.
With respect to Networks’ regulated electric utilities in Maine, New York and Connecticut, FERC governs the return on equity, or ROE, rates, terms
and conditions of transmission of electric energy in interstate commerce, interconnection service in interstate commerce (which applies to independent power
generators, for example), and the rates, terms and conditions of wholesale sales of electric energy in interstate commerce, which includes cost-based rates,
market-based rates and the operations of regional capacity and electric energy markets in New England administered by an independent entity, ISO New
England, Inc., or ISO-NE, and in New York, administered by another independent entity, the New York Independent System Operator, Inc., or NYISO. FERC
approves the Networks’ regulated electric utilities transmission revenue requirements. Wholesale electric transmission revenues are recovered through
formula rates that are approved by FERC. CMP’s, MEPCO’s and UI’s electric transmission revenues are recovered from New England customers through
charges that recover costs of transmission and other transmission-related services provided by all regional transmission owners. NYSEG’s and RGE’s electric
transmission revenues are recovered from New York customers through charges that recover the costs of transmission, and other transmission-related services
provided by all transmission owners in New York. Several of our affiliates have been granted authority to engage in sales at market-based rates and blanket
authority to issue securities, and have also been granted certain waivers of FERC reporting and accounting regulations available to non-traditional public
utilities; however, we cannot be assured that such authorizations or waivers will not be revoked for these affiliates or will be granted in the future to other
affiliates.
Pursuant to a series of orders involving the ROE for regionally planned New England electric transmission projects, the FERC established a base-level
transmission ROE of 11.14%, as well as a 50 basis point ROE adder on Pool Transmission Facilities, or PTF, for participation in the RTO for New England
and a 100 basis point ROE incentive for projects included in the ISO-NE Regional System Plan that were completed and on line as of December 31, 2008.
Beginning in 2011, several parties filed three separate complaints with the FERC against ISO-NE and several New England transmission owners,
including UI and CMP, claiming that the current approved base ROE of 11.14% was not just and reasonable, seeking a reduction of the base ROE and a
refund to customers for the 15-month refund periods beginning October 1, 2011, December 27, 2012 and July 31, 2014, respectively.
In 2014, the FERC determined that the base ROE should be set at 10.57% for the first complaint refund period and that a utility's total or maximum
ROE should not exceed 11.74%. The FERC issued an order consolidating the second and third complaints and establishing hearing procedures. The
administrative law judge issued an initial decision in the second and third complaints on March 22, 2016. The initial decision determined that, 1) for the 15
month refund period in the second complaint, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and
2) for the 15 month refund period in the third complaint and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19%. The
initial decision is the administrative law judge’s recommendation to the FERC Commissioners. The FERC is expected to make its final decision in late 2016
or early 2017.
On March 3, 2015, the FERC issued an Order on Rehearing in the first complaint denying all rehearing requests from the complainants and the New
England transmission owners. Appeals of the FERCs decisions on the first complaint are currently pending before the D.C. Circuit.
On December 28, 2015, the FERC issued an order instituting section 206 proceedings and establishing hearing and settlement judge
procedures. Pursuant to section 206 of the FPA, the FERC finds that ISO-NE Transmission, Markets, and Services Tariff is unjust, unreasonable, and unduly
discriminatory or preferential. FERC stated that ISO-NE’s Tariff lacks adequate transparency and challenge procedures with regard to the formula rates for
ISO-NE Participating Transmission Owners, including UI, MEPCO and CMP. FERC also found that the current Regional Network Service, or RNS and Local
Network Service, or LNS, formula rates appear to be unjust, unreasonable, unduly discriminatory or preferential, or otherwise unlawful as the formula rates
appear to lack sufficient
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detail in order to determine how certain costs are derived and recovered in the formula rates. A settlement judge has been appointed and a settlement
conference has convened. We are unable to predict the outcome of this proceeding at this time.
FERC has the right to review books and records of “holding companies,” as defined in the Public Utility Holding Company Act of 2005, or PUHCA
2005, that are determined by FERC to be relevant to the companies’ respective FERC-jurisdictional rates. We are a holding company, as defined in PUHCA
2005.
FERC has civil penalty authority over violations of any provision of Part II of the FPA, as well as any rule or order issued thereunder. FERC is
authorized to assess a maximum civil penalty of $1.0 million per violation for each day that the violation continues. The FPA also provides for the
assessment of criminal fines and imprisonment for violations under Part II of the FPA. Pursuant to the Energy Policy Act of 2005, or EPAct 2005, the North
American Electric Reliability Corporation, or NERC, has been certified by FERC as the Electric Reliability Organization to develop and oversee the
enforcement of electric system reliability standards applicable throughout the United States. FERC-approved reliability standards may be enforced by FERC
independently, or, alternatively, by NERC and the regional reliability organizations with frontline responsibility for auditing, investigating and otherwise
ensuring compliance with reliability standards, subject to FERC oversight.
Gas’ current natural gas storage operations in the United States are subject to the jurisdiction of FERC under the Natural Gas Act of 1938, or NGA, as a
Section 7(c) natural gas storage provider (i.e., Caledonia Energy Partners, L.L.C. and Freebird Gas Storage, LLC each with Enstor Operating Company, LLC
as their manager) and by providing interstate storage and storage related services under Section 311 of the Natural Gas Policy Act of 1978 (i.e., Enstor Katy
Storage and Transportation, L.P. and Enstor Grama Ridge Storage and Transportation, LLC with Enstor Operating Company, LLC as their general partner and
manager, respectively), at market based rates. Gas’ interstate and intrastate high-deliverability multi-cycle natural gas storage service projects and operations
are subject to FERC regulation under the NGA for rates and terms of service.
Furthermore, Gas’ natural gas trading operations in the United States are subject to the jurisdiction of FERC under EPAct 2005. FERC possesses
regulatory oversight over gas markets, including the purchase, sale and transportation of gas by “any entity” in order to enforce the anti-market manipulation
provisions in EPAct 2005. The gas distribution operations of NYSEG, RGE, SCG, CNG and Berkshire, similar to Gas, are also subject to FERC regulation
with respect to their gas purchases/sales and contracted transportation/storage capacity. FERC has civil penalty authority under the NGA to impose penalties
for certain violations of up to $1.0 million per day for violations. FERC also has the authority to order the disgorgement of profits from transactions deemed
to violate the NGA and EPAct 2005. Additionally, Gas’ current natural gas trading operations are also subject to FERC regulation with respect to matters
such as market manipulation and capacity release rules.
Market Anti-Manipulation Regulation
The FERC and the Commodity Futures Trading Commission, or CFTC, monitor certain segments of the physical and futures energy commodities
market pursuant to the FPA and the Commodity Exchange Act, including our businesses’ energy transactions and operations in the United States. In July
2010, Congress passed the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which incorporated an expansion of the
authority of the CFTC to prohibit market manipulation in the markets regulated by the CFTC. With regard to the physical purchases and sales of electricity
and natural gas, the gathering storage, transmission and delivery of these energy commodities and any related trading or hedging transactions that some of
our operating subsidiaries undertake, our operating subsidiaries are required to observe these anti-market manipulation laws and related regulations enforced
by the FERC and CFTC. The FERC and CFTC hold substantial enforcement authority, including the ability to assess civil penalties of up to $1.0 million per
day per violation, to order disgorgement of profits and to recommend criminal penalties.
State Regulation
Networks’ regulated utilities in New York, Maine, Connecticut and Massachusetts are subject to regulation by the applicable state public utility
commissions, including with regard to their rates, terms and conditions of service, issuance of securities, purchase or sale of utility assets and other
accounting and operational matters. NYSEG and RGE are subject to regulation by the NYPSC; CMP and MNG are subject to regulation by the MPUC; UI,
SCG and CNG are subject to regulation by the PURA; and Berkshire is subject to regulation by the DPU. The NYPSC, MPUC and the Connecticut Siting
Council, or CSC, exercise jurisdiction over the siting of electric transmission lines in their respective states, and each of the NYPSC, MPUC, PURA and DPU
exercise jurisdiction over the approval of certain mergers or other business combinations involving Networks’ regulated utilities. In addition, each of the
utility commissions has the authority to impose penalties on these regulated utilities, which could be substantial, for violating state utility laws and
regulations and their orders.
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Networks’ regulated distribution utilities deliver electricity and/or natural gas to all customers in their service territory at rates established under cost
of service regulation. Under this regulatory structure, Networks’ regulated distribution utilities recover the cost of providing distribution service to their
customers based on its costs, and earn a return on their capital investment in utility assets.
The following provides a summary of Networks regulated utilities’ most recent rate cases:
·
New York. NYSEG and RGE have each completed one distribution rate case decision since they were acquired by Iberdrola, S.A. in 2008. On
September 17, 2009, NYSEG and RGE initiated a distribution rate case to allow the companies to recover past and future investments, provide
safe and adequate service, and improve their credit ratings. On February 19, 2016, the NYSEG, RGE and other signatory parties filed a Joint
Proposal, or the proposal, with the NYPSC for a three-year rate plan for electric and gas service at NYSEG and RGE commencing May 1, 2016.
The proposal balances the varied interests of the signatory parties including but not limited to maintaining the companies’ credit quality and
mitigating the rate impacts to customers. The proposal reflects many customer attributes including: acceleration of the companies’ natural gas
leak prone main replacement programs and enhanced electric vegetation management to provide continued safe and reliable service. The
allowed rate of return on common equity for NYSEG Electric, NYSEG Gas, RGE Electric and RGE Gas is 9.00%. The equity ratio for each
company is 48%. The proposal includes an ESM applicable to each company. The customer share of earnings would increase at higher
earnings levels, with customers receiving 50%, 75% and 90% of earnings over 9.5%, 10.0% and 10.5% of ROE, respectively, in the first year.
Earnings thresholds would increase in subsequent years. The proposal reflects the recovery of deferred NYSEG Electric storm costs of
approximately $262 million, of which $123 million will be amortized over ten years and the remaining $139 million will be amortized over
five years. The proposal also continues reserve accounting for qualifying Major Storms ($21.4 million annually for NYSEG Electric and $2.5
million annually for RGE Electric). Incremental maintenance costs incurred to restore service in qualifying divisions will be chargeable to the
Major Storm Reserve provided they meet certain thresholds. The administrative law judges assigned to the New York rate case will issue a
procedural schedule establishing the remaining procedure for review and decision on the proposal. We expect hearings on the proposal to be
held in April 2016 and a NYPSC decision to be made in May 2016.
·
Maine. On May 1, 2013, CMP filed a distribution service rate case in order to recover past and future investments and provide safe and
adequate service. On August 25, 2014, MPUC approved a stipulation agreement which provided for a distribution rate increase of
approximately $24.3 million effective July 1, 2014 with an allowed ROE of 9.45% and an allowed equity ratio of 50%.
On March 5, 2015, MNG filed a rate case in order to recover future investments and provide safe and adequate service. MNG requested a
10.0% ROE and 50% equity ratio. The MPUC Staff has recommended a separate revenue requirement for MNG’s Augusta customers and
MNG’s non-Augusta customers. Staff has recommended a $19.95 million disallowance of the Augusta Expansion investment based upon the
Staffs conclusion that MNG’s management of the Augusta Expansion Project was imprudent. On November 6, 2015, a stipulation was filed
with the MPUC, which was executed by MNG, the Office of Public Advocate and the City of Augusta. The stipulation contained a combined
revenue requirement for Augusta and Non-Augusta based on a 9.55% ROE and 50% equity ratio. The stipulation also provided for an initial
Augusta investment disallowance of $6 million and an investment phase-in of $10 million. On December 22, 2015, MPUC rejected the
proposed stipulation as not in the public interest. In January 2016, the administrative law judge established a new litigation schedule. The
litigation was suspended at the end of January 2016 for settlement discussions. We cannot predict the outcome of the proceeding.
·
Connecticut. In August 2013, PURA approved distribution rate schedules for UI for two years that became effective at that time and which,
among other things, increased the UI distribution allowed ROE from 8.75% to 9.15%, continued UI’s existing earnings sharing mechanism,
continued the existing decoupling mechanism (under which the actual energy delivery revenues are compared on a periodic basis with the
authorized delivery revenues and the difference accrued, with interest, for refund to or recovery from customers, as applicable), and approved
the establishment of the requested storm reserve. In connection with the approval by PURA of the acquisition, UI agreed not to file a rate case
for new rates effective before January 1, 2017.
The allowed ROEs established by PURA for CNG and SCG, are 9.18% and 9.36%, respectively. SCG and CNG each have purchased gas
adjustment clauses that enable them to pass their reasonably incurred cost of gas purchases through to customers. These clauses allow utilities
to recover costs associated with changes in the market price of purchased natural gas, substantially eliminating exposure to natural gas price
risk.
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On January 22, 2014, PURA approved base delivery rates for CNG, with an effective date of January 10, 2014, which, among other things,
approved an allowed ROE of 9.18%, continued the purchased gas adjustment clause, instituted a revenue decoupling mechanism, established
two separate ratemaking mechanisms that reconcile actual revenue requirements related to CNG’s cast iron and bare steel replacement program
and system expansion and an earnings sharing mechanism by which CNG and customers share on a 50/50 basis all earnings above the allowed
ROE in a calendar year. In accordance with the approval by PURA of the acquisition, SCG and CNG agreed not to file rate cases for new rates
effective before January 1, 2018.
·
Massachusetts. Berkshire’s rates are established by the DPU. Berkshire’s 10-year rate plan, which was approved by the DPU and included an
approved ROE of 10.5%, expired on January 31, 2012. Berkshire continues to charge the rates that were in effect at the end of the rate plan. In
accordance with the approval by the DPU of the acquisition, Berkshire agreed not to file a rate case for new rates effective before June 1, 2018.
Further, as a result of a restructuring of the utility industry in New York, Maine, Connecticut and Massachusetts, most of Networks’ distribution
utilities’ customers have the opportunity to purchase their electricity or natural gas supplies from third-party energy supply vendors. Most customers in New
York, however, continue to purchase such supplies through the distribution utilities under regulated energy rates and tariffs. In Maine, CMP customers can
also purchase electric supply from competitive providers but the majority receives baseline standard offer service that is provided through a MPUC
procurement process. Networks’ regulated utilities in New York, Connecticut and Massachusetts and MNG purchase electricity or natural gas from
unaffiliated wholesale suppliers and recover the actual approved costs of these supplies on a pass-through basis, as well as certain costs associated with
industry restructuring, through reconciling rate mechanisms that are periodically adjusted.
In April 2014 the NYPSC instituted its Reforming the Energy Visions, or REV, proceeding, the goals of which are to improve electric system
efficiency and reliability, encourage renewable energy resources, support DER, and empower customer choice. In this proceeding, the NYPSC is examining
the establishment of a Distributed System Platform, or DSP, to manage and coordinate DER, and provide customers with market data and tools to manage
their energy use. The NYPSC has determined distribution utilities should be the DSP providers. The NYPSC also is examining how its regulatory practices
should be modified to incent utility practices to promote REV objectives. The proceeding is following a two-phased schedule with an order relating to policy
determinations for DSP and related matters issued in February 2015 and an order for regulatory design and regulatory matters, expected in 2016. All electric
utilities have been ordered to file an initial Distributed System Implementation Plan, or DSIP, by June 30, 2016. The DSIP will also include information
regarding the potential deployment of Automated Metering Infrastructure, or AMI.
State public utility commissions may also have jurisdiction over certain aspects of Renewables’ competitive generation businesses. For example, in
New York, certain Renewables’ generation subsidiaries are electric corporations subject to lightened regulation by the NYPSC. As such, the NYPSC
exercises its jurisdictional authority over certain non-rate aspects of the facilities, including safety, retirements, and the issuance of debt secured by recourse
to those generation assets located in New York. In Texas, Renewables’ operations within the Electric Reliability Council of Texas, or ERCOT, footprint are
not subject to regulation by FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. These operations are
subject to regulation by the Public Utility Commission of Texas, or PUCT. In California, Renewables’ generation subsidiaries are subject to regulation by the
California Public Utilities Commission with regard to certain non-rate aspects of the facilities, including health and safety, outage reporting and other aspects
of the facilities’ operations. Furthermore, Gas’ natural gas storage operations are subject to certain state regulations, such as the Railroad Commission of
Texas for its facilities located in Texas.
RTOs and ISOs
Networks’ regulated electric utilities in New York, Connecticut and Maine, as well as some of Renewables’ generation fleet, operate in or have access
to organized energy markets, known as regional transmission organizations, or RTOs, or independent system operators, or ISOs, particularly NYISO and ISO-
NE. Each organized market administers centralized bid-based energy, capacity and ancillary services markets pursuant to tariffs approved by FERC, or in the
case of ERCOT, market rules approved by the PUCT. These tariffs and rules dictate how the energy, capacity and ancillary service markets operate, how
market participants bid, clear, are dispatched, make bilateral sales with one another, and how entities with market-based rates are compensated. Certain of
these markets set prices, referred to as Locational Marginal Prices that reflect the value of energy, capacity or certain ancillary services, based upon
geographic locations, transmission constraints, and other factors. Each market is subject to market mitigation measures designed to limit the exercise of
market power. Some markets limit the prices of the bidder based upon some level of cost justification. These market structures impact the bidding, operation,
dispatch and sale of energy, capacity and ancillary services.
The RTOs and ISOs are also responsible for transmission planning and operations within their respective regions. Each of Networks’ transmission-
owning subsidiaries in New York, Connecticut and Maine has transferred operational control over certain of its electric transmission facilities to its respective
ISOs, such as ISO-NE and NYISO.
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New Renewable Source Generation
Under Connecticut law Public Act 11-80, or PA 11-80, Connecticut electric utilities are required to enter into long-term contracts to purchase
Connecticut Class I Renewable Energy Certificates, or RECs, from renewable generators located on customer premises. Under this program, UI is required to
enter into contracts totaling approximately $200 million in commitments over an approximate 21-year period. The obligations will phase in over a six-year
solicitation period, and are expected to peak at an annual commitment level of about $13.6 million per year after all selected projects are online. Upon
purchase, UI accounts for the RECs as inventory. UI expects to partially mitigate the cost of these contracts through the resale of the RECs. PA 11-80
provides that the remaining costs (and any benefits) of these contracts, including any gain or loss resulting from the resale of the RECs, are fully recoverable
from (or credited to) customers through electric rates.
On October 23, 2013, PURA approved UIs renewable connections program filed in accordance with PA 11-80, through which UI will develop up to
10 MW of renewable generation. The costs for this program will be recovered on a cost of service basis. PURA established a base ROE to be calculated as the
greater of: (A) the current UI authorized distribution ROE (currently 9.15%) plus 25 basis points and (B) the current authorized distribution ROE for The
Connecticut Light and Power Company, or CL&P, (currently 9.17%), less target equivalent market revenues (reflected as 25 basis points). In addition, UI will
retain a percentage of the market revenues from the project, which percentage is expected to equate to approximately 25 basis points on a levelized basis over
the life of the project. UI expects the cost of this program, a planned 2.8 MW fuel cell facility in New Haven, solar photovoltaic and fuel cell facilities
totaling 5 MW in Bridgeport, and a 2.2 MW fuel cell facility in Woodbridge, to be approximately $47 million.
Pursuant to Section 8 of Connecticut Public Act 13-303, An Act Concerning Connecticuts Clean Energy Goals,” in January 2014, at DEEP’s
direction, UI entered into three contracts for the purchase of RECs associated with an aggregate of 5.7 MW of energy production from biomass plants in New
England. The costs of these agreements will be fully recoverable through electric rates.
Under Maine law 35-A M.R.S.A §§ 3210-C, 3210-D, the MPUC is authorized to conduct periodic requests for proposals seeking long-term supplies of
energy, capacity or RECs, from qualifying resources. The MPUC is further authorized to order Maine Transmission and Distribution Utilities to enter into
contracts with sellers selected from the MPUCs competitive solicitation process. Pursuant to a MPUC Order dated October 8, 2009, CMP entered into a 20-
year agreement with Evergreen Wind Power III, LLC, on March 31, 2010, to purchase capacity and energy from Evergreens 60 MW Rollins wind farm in
Penobscot County, Maine. CMP’s purchase obligations under the Rollins contract are approximately $7 million per year. In accordance with subsequent
MPUC orders, CMP periodically auctions the purchased Rollins energy to wholesale buyers in the New England regional market. Under applicable law, CMP
is assured recovery of any differences between power purchase costs and achieved market revenues through a reconcilable component of its retail distribution
rates. Although the MPUC has conducted multiple requests for proposals under M.R.S.A §3210-C and has tentatively accepted long-term proposals from
other sellers, these selections have not yet resulted in additional currently effective contracts with CMP.
New England East-West Solution
Pursuant to an agreement with CL&P, UI has the right to invest in, and own transmission assets associated with, the Connecticut portion of CL&P’s,
New England East West Solution, or NEEWS, projects to improve regional energy reliability. NEEWS originally consisted of four inter-related transmission
projects being developed by subsidiaries of Northeast Utilities (doing business as Eversource Energy), the parent company of CL&P, in collaboration with
National Grid USA. Three of the original projects have portions located in Connecticut: (1) the Greater Springfield Reliability Project, which was fully
energized in November 2013, (2) the Interstate Reliability Project, which was placed in service in the fourth quarter of 2015 and (3) the Central Connecticut
Reliability Project, the need for which is now planned to be addressed by CL&Ps Greater Hartford Central Connecticut solutions, in which UI does not
anticipate making any investments. Under the agreement, as of December 31, 2015, UI had made aggregate deposits of approximately $45 million since its
inception, with assets valued at approximately $44.6 million having been transferred to UI. UI does not anticipate making any additional investments in
NEEWS under the agreement.
Environmental, Health and Safety
Permitting and Other Regulatory Requirements
Networks. Similar to Renewables and Gas, Networks’ distribution utilities in New York, Maine, Connecticut and Massachusetts are subject to various
federal, state and local laws and regulations in connection with the environmental, health and safety effects of its operations. The distribution utilities of
Networks are subject to regulation by the applicable state public utility commission with respect to the siting and approval of electric transmission lines, with
the exception of UI, the siting of whose transmission lines is subject to the jurisdiction of the CSC, and with respect to pipeline safety regulations for
intrastate gas pipeline operators.
17
The National Environmental Policy Act, or NEPA, requires that detailed statements of the environmental effect of Networks’ facilities be prepared in
connection with the issuance of various federal permits and licenses. Federal agencies are required by NEPA to make an independent environmental
evaluation of the facilities as part of their actions during proceedings with respect to these permits and licenses.
Under the federal Toxic Substances Control Act, the Environmental Protection Agency, or EPA, has issued regulations that control the use and
disposal of Polychlorinated Biphenyls, or PCBs. PCBs were widely used as insulating fluids in many electric utility transformers and capacitors
manufactured before the federal Toxic Substances Control Act prohibited any further manufacture of such PCB equipment. Fluids with a concentration of
PCBs higher than 500 parts per million and materials (such as electrical capacitors) that contain such fluids must be disposed of through burning in high
temperature incinerators approved by the EPA. For our gas distribution companies, PCBs are sometimes found in the distribution system. Networks and UIL
test any distribution piping being removed or repaired for the presence of PCBs and comply with relevant disposal procedures, as needed.
Under the federal Resource Conservation and Recovery Act, or RCRA, the generation, transportation, treatment, storage and disposal of hazardous
wastes are subject to regulations adopted by the EPA. All of Networks’ and UILs subsidiaries have complied with the notification and application
requirements of present regulations, and the procedures by which the subsidiaries handle, store, treat and dispose of hazardous waste products comply with
these regulations.
Prior to the last quarter of the 20th century, when environmental best practices laws and regulations were implemented, utility companies, including
Networks and UIL subsidiaries, often disposed of residues from operations by depositing or burying them on-site or disposing of them at off-site landfills or
other facilities. Typical materials disposed of include coal gasification byproducts, fuel oils, ash, and other materials that might contain PCBs or that
otherwise might be hazardous. In recent years it has been determined that such disposal practices, under certain circumstances, can cause groundwater
contamination.
Renewables. Renewables’ projects are subject to a variety of state environmental review and permitting requirements. Many states where Renewables’
projects are located, or may in the future be located, have laws that require state agencies to evaluate a broad array of environmental impacts before granting
state permits. State agencies evaluate similar issues as federal agencies, including the projects impact on wildlife, historic sites, aesthetics, wetlands and
water resources, agricultural operations and scenic areas. States may impose different or additional monitoring or mitigation requirements than federal
agencies. Additional approvals may be required for specific aspects of a project, such as stream or wetland crossings, impacts to designated significant
wildlife habitats, storm water management and highway department authorizations for oversize loads and state road closings during construction. Permitting
requirements related to transmission lines may be required in certain cases.
Renewables’ projects also are subject to local environmental and regulatory requirements, including county and municipal land use, zoning, building
and transportation requirements. Permitting at the local municipal or county level often consists of obtaining a special use or conditional use permit under a
land use ordinance or code, or, in some cases, rezoning in connection with the project. Obtaining a permit usually depends on Renewables demonstrating that
the project will conform to development standards specified under the ordinance so that the project is compatible with existing land uses and protects natural
and human environments. Local or state regulatory agencies may require modeling and measurement of permissible sound levels in connection with the
permitting and approval of Renewables’ projects. Local or state agencies also may require Renewables to develop decommissioning plans for dismantling the
project at the end of its functional life and establish financial assurances for carrying out the decommissioning plan.
In addition to permits required under state and local laws, Renewables’ projects may be subject to permitting and other regulatory requirements arising
under federal law. For example, if a project is located near wetlands, a permit may be required from the U.S. Army Corps of Engineers, or Army Corps, with
respect to the discharge of dredged or fill material into the waters of the United States. The Army Corps may also require the mitigation of any loss of wetland
functions and values that accompanies the project’s activities. In addition, Renewables may be required to obtain permits under the federal Clean Water Act
for water discharges, such as storm water runoff associated with construction activities, and to follow a variety of best management practices to ensure that
water quality is protected and impacts are minimized. Renewables’ projects also may be located, or partially located, on lands administered by the U.S.
Bureau of Land Management, or BLM. Therefore, Renewables may be required to obtain and maintain BLM right-of-way grants for access to, or operations
on, such lands. To obtain and maintain a grant, there must be environmental reviews conducted, a plan of development implemented and a demonstration
that there has been compliance with the plan to protect the environment, including measures to protect biological, archeological and cultural resources
encountered on the grant.
Renewables’ projects may be subject to requirements pursuant to the Endangered Species Act, or ESA, and analogous state laws. For example, federal
agencies granting permits for Renewables’ projects consider the impact on endangered and threatened species and their habitat under the ESA, which
prohibits and imposes stringent penalties for harming endangered or threatened species and their habitats. Renewables’ projects also need to consider the
Migratory Bird Treaty Act, or MBTA, and the Bald and Golden
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Eagle Protection Act, or BGEPA, which protect migratory birds and bald and golden eagles and are administered by the U.S. Fish and Wildlife Service.
Criminal liability can result from violations of the MBTA and the BGEPA, even for incidental takings of migratory birds. For example, the U.S. Department
of Justice, or DOJ, has recently entered into settlements with two large wind farm operators, pursuant to which those operators pled guilty to criminal
violations of the MBTA and agreed to substantial penalties and mitigation measures.
In addition to regulations, voluntary wind turbine siting guidelines established by the U.S. Fish and Wildlife Service set forth siting, monitoring and
coordination protocols that are designed to support wind development in the United States while also protecting both birds and bats and their habitats. These
guidelines include provisions for specific monitoring and study conditions which need to be met in order for projects to be in adherence with these voluntary
guidelines. Most states also have similar laws. Because the operation of wind turbines may result in injury or fatalities to birds and bats, federal and state
agencies often recommend or require that Renewables conduct avian and bat risk assessments prior to issuing permits for its projects. They may also require
ongoing monitoring or mitigation activities as a condition to approving a project.
Gas. Gas’ natural gas storage operations are regulated by the U.S. Department of Transportation Office of Pipeline Safety through the Pipeline and
Hazardous Materials Safety Administration, or PHMSA, under the Natural Gas Pipeline Safety Act of 1968, or NGPSA, as amended by Pipeline Safety Act of
1979, and the Hazardous Liquids Pipeline Safety Act of 1979, or HLPSA. PHMSA, through the NGPSA and HLPSA, regulates the design, installation, testing,
construction, operation, maintenance, repair, inspection, replacement and management of interstate and certain intrastate natural gas pipeline facilities.
PHMSA has also developed regulations that require transportation pipeline operators to implement integrity management programs to comprehensively
evaluate certain high risk areas along Gas’ natural gas pipelines and take additional measures to protect natural gas pipeline segments located in highly
populated areas.
Gas’ natural gas storage operations are also regulated by the EPA, and equivalent state environmental agencies, with respect to the environmental
effects of its operations, including air and water quality control, solid and hazardous waste disposal, greenhouse gas emissions, noise and limitations on land
use.
Global Climate Change and Greenhouse Gas Emission Issues
Global climate change and greenhouse gas emission issues continue to receive an increased focus from state governments and the federal
government. In November 2010, EPA published final rules for monitoring and reporting requirements for petroleum and natural gas systems that emit
greenhouse gases under the authority of the Clean Air Act beginning in 2011. These regulations apply to facilities that emit greenhouse gases above the
threshold level of 25,000 metric tons equivalent per year. SCG and CNG both exceed this threshold and are subject to reporting requirements. The LNG
facilities owned and/or contracted by SCG and CNG are also subject to the monitoring and reporting requirements of the new regulations. Similarly,
Networks and UIL are subject to reporting requirements under provisions of the greenhouse gases regulations, which regulate electric transmission and
distribution equipment that emit sulfur hexafluoride.
We are continually evaluating the regulatory risks and regulatory uncertainty presented by climate change and greenhouse gas emission
concerns. Such concerns could potentially lead to additional rules and regulations that impact how we operate our business. We expect that any costs of
these rules and regulations would be recovered from customers.
OSHA and Certain Other Federal Safety Laws
Our operating subsidiaries are subject to the requirements of the federal Occupational Safety and Health Act, as amended, or OSHA, and comparable
state laws that regulate the protection of the health and safety of employees. In addition, OSHAs hazard communication standard and standards administered
by other federal as well as state agencies, including the Emergency Planning and Community Right to Know Act and implementing regulations require that
information be maintained about hazardous materials used or produced in operations of our subsidiaries and that this information be provided to employees,
state and local government authorities and citizens.
Management, Disposal and Remediation of Hazardous Substances
Our operating subsidiaries own or lease real property and may be subject to federal, state and local requirements regarding the storage, use,
transportation and disposal of petroleum products and toxic or hazardous substances, including spill prevention, control and counter-measure requirements.
Project properties and materials stored or disposed thereon may be subject to the federal RCRA, the Toxic Substances Control Act, the Comprehensive
Environmental Response, Compensation and Liability Act and analogous state laws. If any operating subsidiary’s owned or leased properties are
contaminated, whether during or prior to their ownership or operation, the operating subsidiary could be responsible for the costs of investigation and
cleanup and for any related liabilities,
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including claims for damage to property, persons or natural resources. Such responsibility may arise even if the operating subsidiary was not at fault and did
not cause the contamination. In addition, waste generated by our operating subsidiaries is at times sent to third party disposal facilities. If such facilities
become contaminated, the operating subsidiary and any other persons who arranged for the disposal or treatment of hazardous substances at those sites may
be jointly and severally responsible for the costs of investigation and remediation, as well as for any claims of damages to third parties, their property or
natural resources.
On September 16, 2015, UI signed a proposed partial consent order that, when issued by the Commissioner of DEEP would require UI to investigate
and remediate certain environmental conditions within the perimeter of a former generation site on the Mill River in New Haven, the English Station site, that
UI sold to Quinnipiac Energy in 2000 and which is currently owned by Evergreen Power, LLC and Asnat Realty LLC. Under the proposed partial consent
order, to the extent that the cost of this investigation and remediation is less than $30 million, UI will remit to the State of Connecticut the difference between
such cost and $30 million to be used for a public purpose as determined in the discretion of the Governor of the State of Connecticut, the Attorney General of
the State of Connecticut, and the Commissioner of DEEP. Pursuant to the proposed partial consent order, upon its issuance and subject to its terms and
conditions, UI would be obligated to comply with the proposed partial consent order, even if the cost of such compliance exceeds $30 million. The State will
discuss options with UI on recovering or funding any cost above $30 million such as through public funding or recovery from third parties, however it is not
bound to agree to or support any means of recovery or funding. The State is continuing to discuss English Station site access with the current owners and the
proposed partial consent order has not been filed.
Customers
Networks delivers natural gas and electricity to residential, commercial and institutional customers through its regulated utilities in New York, Maine,
Connecticut and Massachusetts. As a result of the acquisition of UIL, we now deliver natural gas and electricity to approximately 735,000 additional
customers through our regulated utilities in Connecticut and Massachusetts. Networks’ customer payment terms are regulated by the states of New York, with
respect to NYSEG and RGE; Maine, with respect to CMP and MNG; Connecticut, with respect to UI, SCG and CNG; and Massachusetts, with respect to
Berkshire, and each of the regulated utilities must provide extended payment arrangements to customers for past due balances. See —Networks” for more
information relating to the customers of Networks.
Renewables sells the majority of its output to large investor-owned utilities, public utilities and other credit-worthy entities. Additionally, Renewables
generates and provides power, among other services, to federal and state agencies, institutional retail and joint action agencies. Offtakers typically purchase
renewable energy from Renewables through long-term power purchase agreements, or PPAs, allowing Renewables to limit its exposure to market volatility.
Approximately 67% of Renewables’ wind generating capacity is fully committed under PPAs with an average duration of 9.7 years. Renewables also delivers
thermal output to wholesale customers in the Western United States.
Gas’ natural gas storage and management services customers include a diversified mix of natural gas distribution companies, power generators, natural
gas marketers and producers, utilities using gas as fuel, gas storage customers, financial institutions and energy marketers.
Competition
Networks’ regulated public utilities in New York, Maine, Connecticut and Massachusetts do not generally face competition from other companies that
transmit and distribute electricity and natural gas. However, demand for electricity and natural gas may be negatively impacted by federal and state
legislation mandating that certain percentages of power delivered to end users be produced from renewable resources, such as wind, thermal and solar energy.
Networks faces competition from self-contained micro-grids that integrate renewable energy sources in the areas served by Networks. However, there
has been limited development of these micro-grids in Networks’ service areas to date, and Networks expects that growth in distributed generation of
renewable energy will continue due to financial incentives being provided by federal and state legislation. Networks has experienced significant growth in
alternative distribution sources of generation on its network over the past ten years, with over 90% of the growth coming from solar photovoltaic facilities.
Renewables has competitive advantages, including a robust development pipeline, a management team with extensive experience, strong
relationships with suppliers and clients, expert regulatory knowledge and brand awareness. However, Renewables faces competition throughout the life
cycles of its energy facilities, including during the development phase, in the identification and procurement of suitable sites with high wind resource
availability, grid connection capacity and land availability. Renewables also competes with other suppliers in securing long-term PPAs with power
purchasers and participates in competitive bilateral and organized energy markets with other energy sources for power that is not sold under PPAs.
Competitive conditions may be
20
substantially affected by various forms of energy legislation and regulation considered from time to time by federal, state and local legislatures and
administrative agencies.
Gas, through its subsidiaries, Enstor, Inc. and Enstor Energy Services LLC, faces competition from others in the natural gas market. Enstor, Inc.
encounters regional competition, such as in the Gulf South region, from other independent natural gas storage providers, a combination of interstate and
intrastate pipeline companies and local distribution companies. Furthermore, Enstor Energy Services LLC competes with various entities, ranging from
natural gas marketing companies, to financial institutions and producer/marketers.
Properties
Networks
The following table sets forth certain information relating to Networks’ electricity generation facilities and their respective locations, type and
installed capacity as of December 31, 2015. Unless noted otherwise, Networks owns each of these facilities.
Operating Company Facility Location Facility Type
Installed Capacity
(in MW)
Year(s)
Commissioned
NYSEG Newcomb, NY Diesel Turbine 1.7 1967
NYSEG Auburn, NY(1)
Natural Gas Turbine
7.3 2000
NYSEG
Eastern New York
(6 locations) Hydroelectric 61.4
19211983
RGE
Rochester, NY
(3 locations) Hydroelectric 57.5
19171960
(1) The Auburn, NY natural gas turbine generating unit is leased.
UI is also party to a 50-50 joint venture with certain affiliates of NRG Energy, Inc. in GCE Holding LLC, whose wholly owned subsidiary, GenConn,
operates two 188 MW peaking generation plants, GenConn Devon and GenConn Middletown, in Connecticut.
The following table sets forth certain operating data relating to the electricity transmission and distribution activities of each of Networks’ regulated
utilities as of December 31, 2015.
Utility State Substations
Transmission
Lines
(in miles)
Overhead
Distribution
Lines
(in pole
miles)
Underground
Lines
(in miles)
Total
Distribution
(in miles)
Electricity
Customers
NYSEG New York 435 4,463 32,319 2,702 35,021 885,000
RGE New York 153 1,025 6,091 2,834 8,925 375,000
CMP Maine 209 2,856 21,056 1,428 22,484 616,979
UI Connecticut 29 138 3,284 202 3,486 331,216
The following table sets forth certain operating data relating to the natural gas transmission and distribution activities of each of Networks’ regulated
utilities, as of December 31, 2015.
Utility State
Natural Gas
Customers
Transmission
Pipeline
(in miles)
Distribution
Pipeline
(in miles)
NYSEG New York 265,000 20 8,151
RGE New York 310,000 105 10,592
MNG Maine 4,432 2 190
SCG Connecticut 192,557 2,391
CNG Connecticut 172,498 2,118
Berkshire Massachusetts 39,680 763
CNG owns and operates a liquefied natural gas, or LNG, plant which can store up to 1.2 Bcf of natural gas and can vaporize up to 97,000 Mcf per day
of LNG to meet peak demand. SCG has contract rights to and operates a similar plant with the same capabilities to store up to 1.2 Bcf of natural gas. SCGs
LNG facilities can vaporize up to 82,500 Mcf per day of LNG to meet peak demand. SCG and CNG have also contracted for 21 Bcf of storage with a
maximum peak day delivery capability of 209,000 Mcf per day.
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Renewables
The following table sets forth Renewables’ portfolio of wind projects as of December 31, 2015. Unless noted otherwise, Renewables wholly-owns each
of these facilities.
Location Wind Project Turbines
Total Installed
Capacity
(MW)
Commercial
Operation
Date
North American
Electric
Reliability
Corporation
(“NERC”)
Region
Arizona Dry Lake I 30 (Suzlon S88, 2.1 MW) 63 2009 WECC
Dry Lake II 31 (Suzlon, 2.1 MW) 65 2010
California Dillon 45 (Mitsubishi, 1 MW) 45 2008 WECC
Manzana 126 (GE, 1.5 MW) 189 2011 WECC
Mountain View III 34 (Vestas V47, 0.66 MW) 22 2003 WECC
Phoenix Wind Power 3 (Neg Micon (Vestas), 0.66 MW) 2 1999 WECC
Shiloh 100 (GE, 1.5 MW) 150 2006
Colorado Colorado Green(1) 54 (GE, 1.5 MW) 81 2003 WECC
Twin Buttes 50 (GE, 1.5 MW) 75 2007
Illinois Providence Heights 36 (Gamesa G87, 2.0 MW) 72 2008 MRO
Streator Cayuga Ridge South 150 (Gamesa, 2.0MW) 300 2010
Iowa Barton 80 (Gamesa, 2.0 MW) 160 2009 MRO
Flying Cloud 29 (GE, 1.5 MW) 44 2004 MRO
New Harvest 50 (Gamesa G87, 2.0W) 100 2012 MRO
Top of Iowa II 40 (Gamesa G87, 2.0 MW) 80 2008 MRO
Winnebago I 10 (Gamesa G83, 2.0 MW) 20 2008 MRO
Kansas Elk River 100 (GE, 1.5 MW) 150 2005 MRO
Massachusetts Hoosac 19 (GE, 1.5 MW) 29 2012 NPCC
Minnesota Elm Creek 66 (GE, 1.5 MW) 99 2008 MRO
MinnDakota 100 (GE, 1.5 MW) 150 2008 MRO
Trimont 67 (GE, 1.5 MW) 100 2005 MRO
Elm Creek II 62 (Mitsubishi, 2.4) 149 2010 MRO
Moraine I 34 (GE, 1.5 MW) 51 2003 MRO
Moraine II 33 (GE, 1.5 MW) 50 2009 MRO
Missouri Farmers City 73 (Gamesa G87, 2.0 MW) 146 2009 MRO
New Hampshire Groton 24 (Gamesa G87, 2.0 MW) 48 2012 NPCC
Lempster 12 (Gamesa, 2 MW) 24 2008 NPCC
New York Hardscrabble 37 (Gamesa G90, 2MW) 74 2011 NPCC
Maple Ridge I(2) 70 (Vestas V82, 1.65 MW) 116 2006 NPCC
Maple Ridge II(2) 27 (Vestas V82, 1.65 MW) 45 2006 NPCC
North Dakota Rugby 71 (Suzlon S88, 2.1 MW) 149 2009 MRO
Ohio Blue Creek 152 (Gamesa G90 2.0 MW) 304 2012 RFC
Oregon Hay Canyon 48 (Suzlon S88, 2.1 MW) 101 2009 WECC
Klondike I 16 (GE, 1.5 S – 1.5 MW) 24 2001 WECC
Klondike II 50 (GE, 1.5 S – 1.5 MW) 75 2005 WECC
Klondike III
44 (Siemens, 2.3 MW); 80 (GE,
1.5 SLE, 1.5 MW); 1
(Mitsubishi, 2.4 MW) 224 2007 WECC
Klondike IIIa 51 (GE, 1.5 MW) 77 2008 WECC
Leaning Juniper II 74 (GE, 1.5 MW); 43 (Suzlon, 2.1 MW) 201 2011 WECC
Pebble Springs 47 (Suzlon S88/2100, 2.1 MW) 99 2009 WECC
Star Point 47 (Suzlon, 2.1 MW) 99 2010 WECC
Pennsylvania Casselman 23 (GE, 1.5 MW) 35 2008 RFC
Locust Ridge I 13 (Gamesa G87, 2.0) 26 2006 RFC
Locust Ridge II 51 (Gamesa G83, 2.0 MW) 102 2009 RFC
South Chestnut 23 (Gamesa, 2.0 MW) 46 2012 RFC
South Dakota Buffalo Ridge I 24 (Suzlon, 2.1 MW) 50 2009 MRO
Buffalo Ridge II 105 (Gamesa G87, 2.0 MW) 210 2010 MRO
Texas Baffin 101 (Gamesa G97, 2.0 MW) 202 2015 TRE
Barton Chapel 60 (Gamesa, 2.0 MW) 120 2009 TRE
Peñascal I 84 (Mitsubishi, 2.4 MW) 202 2009 TRE
Peñascal II 84 (Mitsubishi, 2.4 MW) 202 2010 TRE
Washington Big Horn I 133 (GE, 1.5 MW) 200 2006 WECC
Big Horn II 25 (Gamesa, 2.0 MW) 50 2010 WECC
Juniper Canyon 63 (Mitsubishi, 2.4 MW) 151 2011 WECC
(1) Jointly owned with Shell Wind Energy; capacity amounts represent only Renewables’ share of the wind farm.
(2) Jointly owned with Horizon Wind Energy; capacity amounts represent only Renewables’ share of the wind farm.
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Additionally, unless noted otherwise, Renewables owns the following solar and thermal facilities as of December 31, 2015.
Facility Location
Type of
Facility
Installed
Capacity
(MW)
Commercial
Operation
Date
Copper Crossing Solar Ranch
Pinal County, Arizona
Solar 20 2011
San Luis Valley Solar Ranch(1) Alamosa County, Colorado Solar 30 2012
Klamath Cogeneration Klamath Falls, Oregon Thermal 536 2001
Klamath Peakers Klamath Falls, Oregon Thermal 100 2009
(1) Operated pursuant to a sale-and-leaseback agreement.
Gas
Gas owns and operates four natural gas storage facilities, all near key trading hubs. The following table provides an overview of these storage facilities
as of December 31, 2015. Unless noted otherwise, Enstor, Inc., a wholly-owned direct subsidiary of Gas, owns and operates each of these facilities.
Facility Type of Facility
Storage
capacity
(Bcf)
Max Injection
(MMcfd)/ Max
Withdrawal
(MMcfd)
Pipeline
Connections
Commercial
Operation
Date
Caledonia Energy Partners, L.L.C., Mississippi
Depleted gas
reservoir 18.5 558/550
Tennessee Gas
Pipeline 500 2005
Freebird Gas Storage, LLC, Alabama(1)
Depleted gas
reservoir 9.8 350/305
Tennessee Gas
Pipeline 500 2001
Enstor Grama Ridge Storage and
Transportation, LLC, New Mexico
Depleted gas
reservoir 15.7 200/200
El Paso Natural Gas,
Natural Gas Pipeline
Company of America and
the DCP Midstream
Raptor Pipeline 1973
Enstor Katy Storage and
Transportation, L.P., Texas
Depleted gas
reservoir 23.5 750/700
Connected to 14
different pipelines 1992
(1) 13% owned by Northwest Alabama Gas District.
Infrastructure Protection and Cyber Security Measures
We have security measures in place designed to protect our facilities and assets, such as our transmission and distribution system. While we have not
had any significant security breaches, a physical security intrusion could potentially lead to theft and the release of critical operating information. In addition
to physical security intrusions, a cyber breach could potentially lead to theft and the release of critical operating information or confidential customer
information. To manage these operational risks, in accordance with the Cybersecurity Risk Policy and with the Corporate Security Policy of Iberdrola, S.A. as
adopted by us, we have implemented cyber and physical security measures and continue to strengthen our security posture by improving and expanding our
physical and cyber security capabilities to protect critical assets.
In an effort to reduce our vulnerability to cyber attacks, we have established a dedicated Corporate Security Office, responsible for improving and
coordinating security across the company and have adopted a comprehensive company-wide physical and cyber security program, which is supported by a
company-wide governance policy to manage, oversee and assist us in meeting our corporate, legal, and regulatory responsibilities with regard to the
protection of our cyber, physical and information assets. However, as threats evolve and grow increasingly more sophisticated, we cannot ensure that a
potential security breach may not occur or quantify the potential impact of such an event. We continue to invest in technology, processes, security measures
and services to detect, mitigate and protect our assets, both physical and cyber. These investments include upgrades to network architecture and physical
security measures, regular intrusion detection monitoring and compliance with emerging industry regulation.
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Employees
As of December 31, 2015, we had 6,809 employees excluding 15 international assignees. Of these 6,809 employees, 47.7% are represented by a union.
The following table provides an overview of the number of employees at each business segment as of December 31, 2015:
Business Segment
Number of
Employees
(excluding
International
Assignees)
% of Union
Workforce
Subject
to Collective
Bargaining
Agreement
Networks 5,795 56.0%
Renewables 686
Gas 103
Corporate 225
Total 6,809 47.7 %
We have not experienced any work stoppages in the last five years and enjoy good relations with our labor unions. Virtually all of our employees
work fulltime.
Available Information
Copies of our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to these reports filed
with the Securities and Exchange Commission, or SEC, may be requested, viewed, or downloaded on-line, free of charge, on our website www.avangrid.com.
Printed copies of these reports may be obtained free of charge by writing to our Investor Relations Department at 157 Church Street, New Haven,
Connecticut, 06506.
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Item 1A. Risk Factors
Risks Relating to Our Regulatory Environment
Our businesses are subject to substantial regulation by federal, state and local regulatory agencies and our businesses, results of operations and
prospects may be materially adversely affected by legislative or regulatory changes, as well as liability under, or any future inability to comply with,
existing or future regulations or requirements.
The operations of our businesses are subject to, and influenced by, complex and comprehensive federal, state and local regulation and legislation,
including regulations promulgated by state utility commissions and FERC. This extensive regulatory and legislative framework, portions of which are more
specifically identified in the following risk factors, regulates, among other things and to varying degrees, the industries in which our subsidiaries operate, our
business segments, rates for our products and services, financings, capital structures, cost structures, construction, environmental obligations (including in
respect of, among others, air emissions, water consumption, water discharge, protections for wildlife and humans, nuisance prohibitions and allowances, and
regulation of gas infrastructure operations, and associated environmental and facility permitting), development and operation of electric generation facilities
and electric and gas transmission and distribution facilities, natural gas transportation, processing and storage facilities, acquisition, disposal, depreciation
and amortization of facilities and other assets, service reliability, hedging, derivatives transactions and commodities trading.
In our business planning and in the management of our subsidiaries’ operations, we must address the effects of regulation on our businesses, including
the significant and increasing compliance costs imposed on our operations as a result of such regulation, and any inability or failure to do so timely and
adequately could have a material adverse effect on our businesses, results of operations, financial condition and cash flows. The federal, state and local
political and economic environment has had, and may in the future have, an adverse effect on regulatory decisions with negative consequences for our
businesses. These decisions may require, for example, our businesses to cancel or delay planned development activities, to reduce or delay other planned
capital expenditures or investments or otherwise incur costs that we may not be able to recover through rates, any of which could have a material adverse
effect on the business, results of operations, financial condition and cash flows of our businesses. In addition, changes in the nature of the regulation of our
business could have a material adverse effect on our business, results of operations, financial condition and cash flows. We are unable to predict future
legislative or regulatory changes, initiatives or interpretations, and there can be no assurance that we will be able to respond adequately or sufficiently
quickly to such changes, although any such changes, initiatives or interpretations may increase costs and competitive pressures on us, which could have a
material adverse effect on our business, results of operations, financial condition and cash flows. There can be no assurance that we will be able to respond
adequately or sufficiently quickly to such rules and developments, or to any other changes that reverse or restrict the competitive restructuring of the energy
industry in those jurisdictions in which such restructuring has occurred. Any of these events could have a material adverse effect on our business, results of
operations, financial condition and cash flows.
Our businesses are subject to the jurisdiction of various federal, state and local regulatory agencies including, but not limited to, FERC, the CFTC, the
DOE, and the EPA. Further, Networks’ regulated utilities in New York, Maine, Connecticut and Massachusetts are subject to the jurisdiction of the NYPSC,
the MPUC, the New York State Department of Environmental Conservation, the Maine Department of Environmental Protection, the PURA, the CSC, the
DEEP, and the DPU. These regulatory agencies cover a wide range of business activities, including, among other items, the retail and wholesale rates for
electric energy, capacity and ancillary services, and for the transmission and distribution of these products, the costs charged to Networks’ customers through
tariffs including cost recovery clauses, the terms and conditions of Networks’ services, procurement of electricity for Networks’ customers, issuances of
securities, the provision of services by affiliates and the allocation of those service costs, certain accounting matters, and certain aspects of the siting,
construction and transmission and distribution systems. FERC has the authority to impose penalties on our regulated utilities, which could be substantial, for
violations of the FPA, the NGA, or related rules, including reliability and cyber security rules as described in further detail below. The Financial Accounting
Standards Board, or FASB, or the SEC, may enact new accounting standards that could impact the way we are required to record revenue, expenses, assets and
liabilities. Certain regulatory agencies have the authority to review and disallow recovery of costs that they consider excessive or imprudently incurred and
to determine the level of return that our businesses are permitted to earn on invested capital.
The regulatory process, which may be adversely affected by the political, regulatory and economic environment in New York, Maine, Connecticut and
Massachusetts, as applicable, may limit our ability to increase earnings and does not provide any assurance as to achievement of authorized or other earnings
levels. The disallowance of the recovery of costs incurred by us or a decrease in the rate of return that we are permitted to earn on our invested capital could
have a material adverse effect on our business, results of operation, financial condition and cash flows. Certain of these regulatory agencies also have the
authority to audit the management and operations of our businesses in New York, Maine, Connecticut and Massachusetts and require or recommend
operational changes. Such audits and post-audit work requires the attention of our management and employees and may divert their attention from other
regulatory, operational or financial matters. The last management audit of UI by PURA was completed in 2015. This audit resulted in 64
recommendations. In
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December 2015, UI filed its response to the audits recommendations with PURA. The NYPSC is in process of an operations audit of staffing levels at major
utilities. The audit is expected to be completed later in 2016. We cannot predict the outcome of this audit.
Any failure to meet the reliability standards mandated by NERC could have a material adverse effect on our business, results of operation, financial
condition and cash flows.
As a result of the EPAct 2005, owners, operators and users of bulk electric systems are subject to mandatory reliability standards developed by the
NERC and are subject to oversight by FERC in the U.S. and governmental authorities in Canada. The standards are based on the functions that need to be
performed to ensure that the bulk electric system operates reliably. Networks’ and Renewables’ businesses have been, and will continue to be, subject to
routine audits and monitoring with respect to compliance with applicable NERC reliability standards, including standards approved by FERC that could
result in an increase in the number of assets (including cyber-security assets) designated as “critical assets,” which would subject such assets to NERC cyber-
security standards. NERC and FERC can be expected to continue to refine existing reliability standards as well as develop and adopt new reliability
standards. Compliance with modified or new reliability standards may subject Networks’ and/or Renewables’ businesses to new requirements resulting in
higher operating costs and/or increased capital expenditures. If Networks’ and/or Renewables’ businesses were found not to be in compliance with the
mandatory reliability standards, it could be subject to penalties of up to $1.0 million per day per violation. Both the costs of regulatory compliance and the
costs that may be imposed as a result of any actual or alleged compliance failures could have a material adverse effect on our business, results of operation,
financial condition and prospects.
The NYPSC has initiated a proceeding that may result in the alteration of the public utility model in New York State and could materially and
adversely impact our business and operations in New York State.
In April 2014, the NYPSC commenced a proceeding titled REV, which is an initiative to reform New York States energy industry and regulatory
practices. REV has followed several simultaneous paths, including a formal Track 1 dealing with Market Design and Platform Technology and Track 2
dealing with Regulatory Reform. REVs objectives include the promotion of more efficient use of energy, increased utilization of renewable energy resources
such as wind and solar in support of New York States renewable energy goals, and wider deployment of “distributed” energy resources, such as micro grids,
on-site power supplies, and storage. Track 1 of the REV initiative involves the examination of the role that distribution utilities will have in the enablement
of market-based deployment of DER to promote load management, system efficiency, and peak load reductions. NYSEG and RGE are participating in all
aspects of the REV initiative with other New York utilities as well as providing their unique perspective. PSC staff has conducted public statement hearings
across New York State regarding REV.
Various other REV-related proceedings have also been initiated by the PSC, each of which is following its own schedule. These proceedings include
the Clean Energy Fund, Demand Response Tariffs, Community Choice Aggregation, Large Scale Renewables, and Community Distributed Generation.
Track 2 of the REV initiative is also underway, and through a NYPSC Staff Whitepaper review process, is examining potential changes in current
regulatory, tariff, market design and incentive structures which could better align utility interests with achieving New York State and NYPSC policy
objectives. New York utilities will also be addressing related regulatory issues in their individual rate cases.
We are not able to predict the outcome of the REV proceeding or its impact on our business, results of operations, financial condition and cash flows.
While the end result of the REV process at the NYPSC remains unclear, it could alter the utility model in New York in a manner that could create material
adverse impacts on our businesses and operations in New York.
Changes in regulatory and/or legislative policy could negatively impact Networks’ transmission planning and cost allocation.
The existing FERC-approved ISO-NE, transmission tariff allocates the costs of transmission facilities that provide regional benefits to all customers of
participating transmission-owning utilities. As new investment in regional transmission infrastructure occurs in any one state, its cost is shared across New
England in accordance with a FERC-approved formula found in the transmission tariff. Participating New England transmission owners’ agreement to this
regional cost allocation is set forth in the Transmission Operating Agreement. This agreement can be modified with the approval of a majority of the
transmission-owning utilities and approval by FERC. In addition, other parties, such as state regulators, may seek certain changes to the regional cost
allocation formula, which could have adverse effects on the rates Networks’ distribution companies in New England charge their retail customers.
FERC has issued rules requiring all RTOs, and transmission owning utilities to make compliance changes to their tariffs and contracts in order to
further encourage the construction of transmission for generation, including renewable generation. This compliance will require RTOs (such as ISO-NE and
NYISO) and the transmission owners in New England and New York to develop
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methodologies that allow for regional planning and cost allocation for transmission projects chosen in the regional plan that are designed to meet public
policy goals such as reducing greenhouse gas emissions or encouraging renewable generation. Such compliance may also allow non-incumbent utilities and
other entities to participate in the planning and construction of new projects in Networks’ service areas and regionally.
Changes in RTO tariffs, transmission owners’ agreements, or legislative policy, or implementation of these new FERC planning rules, could adversely
affect our transmission planning, results of operations, financial condition and cash flows.
We are subject to numerous environmental laws, regulations and other standards, including rules and regulations with respect to climate change, that
could result in capital expenditures, increased operating costs and various liabilities, and could require us to cancel or delay planned projects or limit or
eliminate certain operations.
Our businesses are subject to environmental laws and regulations, including, but not limited to, extensive federal, state and local environmental
statutes, rules and regulations relating to air quality, water quality and usage, climate change, emissions of greenhouse gases (including, but not limited to
carbon dioxide), waste management, hazardous wastes (including the clean-up of former manufactured gas and electric generation facilities), marine, avian
and other wildlife mortality and habitat protection, historical artifact preservation, natural resources and health and safety (including, but not limited to,
electric and magnetic fields from power lines and substations, and ice throw, shadow flicker and noise related to wind turbines) that could, among other
things, prevent or delay the development of power generation, power or natural gas transmission, or other infrastructure projects, restrict the output of some
existing facilities, limit the availability and use of some fuels required for the production of electricity, require additional pollution control equipment, and
otherwise increase costs, increase capital expenditures and limit or eliminate certain operations. There are significant capital, operating and other costs
associated with compliance with these environmental statutes, rules and regulations, and those costs could be even more significant in the future as a result of
new legislation, the current trend toward more stringent standards, and stricter and more expansive application and enforcement of existing environmental
regulations. For example, new laws, regulations or treaties relating to climate change could mandate new or increased requirements to control or reduce the
emission of greenhouse gases, such as carbon dioxide, taxes or fees on fossil fuels or emissions, cap and trade programs, emission limits and clean or
renewable energy standards. Violations of current or future laws, rules, regulations or other standards could expose our subsidiaries to regulatory and legal
proceedings, disputes with, and legal challenges by, third parties, and potentially significant civil fines, criminal penalties and other sanctions, which could
have an adverse effect on our operations, financial condition and cash flows.
Our regulated utility operations may not be able to recover costs in a timely manner or at all or obtain a return on certain assets or invested capital
through base rates, cost recovery clauses, other regulatory mechanisms or otherwise.
Our regulated utilities in New York, Maine, Connecticut and Massachusetts are subject to periodic review of their rates by the NYPSC, MPUC, PURA
and DPU respectively, and the retail rates charged to our regulated utilities’ customers through base rates and cost recovery clauses are subject to the
jurisdiction of the NYPSC, MPUC, PURA and DPU as applicable. New rates may be proposed by Networks businesses, which are then subject to review,
modification and final authorization and implementation by regulators. Alternatively, regulators may review the rates of Networks’ regulated utilities on their
own motion. Networks’ regulated utilities’ rate plans cover specified periods, but rates determined pursuant to a plan generally continue in effect until a new
rate plan is approved by the state utility regulator. Networks’ regulated utilities’ business rate plans approved by state utility regulators limit the rates
Networks’ regulated utilities can charge their customers. The rates are generally designed for, but do not guarantee, the recovery of Networks’ regulated
utilities’ respective cost of service and the opportunity to earn a reasonable rate of return (ROE). Actual costs may increase due to inflation or other factors
and exceed levels provided for such costs in the rate plans for Networks’ regulated utilities. Utility regulators can initiate proceedings to prohibit Networks’
regulated utilities from recovering from their customers the cost of service (including energy costs) that the regulators determine to have been imprudently
incurred. Networks’ regulated utilities defer for future recovery certain costs including major storm costs and environmental costs. In a number of proceedings
in recent years, Networks’ regulated subsidiaries have been denied recovery, or deferred recovery pending the next general rate case, including denials or
deferrals related to major storm costs and construction expenditures. In some instances, denial of recovery may cause the regulated subsidiaries to record an
impairment of assets. If Networks’ regulated utilities’ costs are not fully and timely recovered through the rates ultimately approved by regulators, our cash
flows, results of operations and financial condition, and our ability to earn a return on investment and meet financial obligations, could be adversely affected.
Certain of the current electric and gas rate plans of Networks’ regulated utilities include revenue decoupling mechanisms, or RDMs, and the
provisions for the recovery of energy costs, including reconciliation of the actual amount paid by such regulated utilities. There is no guarantee that such
decoupling mechanisms or recovery and reconciliation mechanism will remain part of the rate plan of Networks in future rate proceedings.
In addition, there are pending challenges at FERC against New England transmission owners (including UI and CMP) seeking to lower the ROE that
these transmission owners are allowed by FERC to receive for wholesale transmission service pursuant to the
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ISO-NE Open Access Transmission Tariff. Reductions to ROE adversely impact the revenues that Networks’ regulated utilities receive from wholesale
transmission customers and could have a material adverse effect on our business, results of operations, financial condition and cash flows.
Harming of protected species can result in curtailment of wind project operations and could have a material adverse effect on our business, results of
operation, financial condition and cash flows.
The operation of energy projects and transmission of energy can adversely affect endangered, threatened or otherwise protected animal species under
federal and state statutes, laws, rules and regulations. Wind projects involve a risk that protected flying species, such as birds and bats, will be harmed due to
collision. Transmission and distribution lines are another source of potential avian collision as well as electrocution. Energy generation and transmission
facilities can result in impacts to protected wildlife, including death caused by collision, electrocution and poisoning. Energy infrastructure occasionally
affects endangered or protected species. Our businesses observe industry guidelines and government-recommended best practices to avoid, minimize and
mitigate harm to protected species, but complete avoidance is not possible and subsequent penalties may result. Where appropriate, our businesses can apply
for an incidental take” permit for some protected species, which may be conditioned upon the institution of costly avoidance and remediation measures.
Violations of wildlife protection laws in certain jurisdictions may result in civil or criminal penalties, including violations of certain laws protecting
migratory birds, endangered species and eagles. The ESA and analogous state laws restrict activities without a permit that may adversely affect endangered
and threatened species or their habitat. The ESA also provides for private causes of actions against a development project, an operating facility, or the agency
that oversees the alleged violation of law. Similar protections are offered to migratory birds under the MBTA, which implements various treaties and
conventions between the United States and certain other nations for the protection of migratory birds and, pursuant to which the taking, killing or possessing
of migratory birds is unlawful. Complying with the state and federal laws protecting migratory birds, endangered species and eagles may require
implementation of operating restrictions or a temporary, seasonal, or permanent ban on operations in affected areas, which can have a material adverse effect
on the revenue of those projects. For example, there have been recent sightings of the protected California condor at Renewables’ Manzana wind facility.
Any incidental taking of a California condor could result in substantial financial, legal and reputational harm to us. The DOJ is currently investigating
Renewables for potential violations under the MBTA and the ESA at its Blue Creek facility and for potential violations of the MBTA and BGEPA at its three
wind farms located in the state of Washington.
Renewables relies in part on governmental policies that support utility-scale renewable energy. Any reductions to, or the elimination of, governmental
incentives that support utility-scale renewable energy or the imposition of additional taxes or other assessments on renewable energy, could result in a
material adverse effect on our business, results of operations, financial condition and cash flows.
Renewables relies, in part, upon government policies that support utility-scale renewable energy projects and enhance the economic feasibility of
developing and operating wind energy projects in regions in which Renewables operates or plans to develop and operate renewable energy facilities. The
federal government and many states and local jurisdictions have policies or other mechanisms, such as tax incentives or Renewable Portfolio Standards, or
RPS, that support the sale of energy from utility-scale renewable energy facilities, such as wind energy facilities. As a result of budgetary constraints,
political factors or otherwise, federal, state and local governments from time to time may review their policies and other mechanisms that support renewable
energy and consider actions that would make them less conducive to the development or operation of renewable energy facilities. Any reductions to, or the
elimination of, governmental policies or other mechanisms that support renewable energy or the imposition of additional taxes or other assessments on
renewable energy, could result in, among other items, the lack of a satisfactory market for the development of new renewable energy projects, Renewables
abandoning the development of new renewable energy projects, a loss of Renewables’ investments in the projects and reduced project returns, any of which
could have a material adverse effect on our business, results of operations, financial condition and cash flows.
Our businesses may face risks related to obtaining governmental approvals and permits in respect of project siting, financing, construction, operation
and the negotiation of project development agreements which could cause delay a project and could materially adversely affect our businesses, results of
operations or financial condition.
Renewables owns, develops, constructs and/or operates electricity generation, including renewable and thermal generators, and associated
transmission facilities. Networks develops, constructs, manages and operates transmission and distribution facilities to meet customer needs. As part of these
operations, our businesses must periodically apply for licenses and permits from various local, state, federal and other regulatory authorities and abide by
their respective conditions. In particular, with respect to Renewables, over the past two years noise standards and siting criteria in the Northeast, where
population density is higher compared to the Northwest, where Renewables also operates, have grown more restrictive. If our businesses are unsuccessful in
obtaining necessary licenses or
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permits on acceptable terms, there is a delay in obtaining or renewing necessary licenses or permits or regulatory authorities initiate any associated
investigations or enforcement actions or impose related penalties or disallowances on us, having a material adverse effect on our businesses, results of
operations, financial condition and cash flows.
Our operating subsidiaries’ purchases and sales of energy commodities and related transportation and services expose us to potential regulatory risks
which could have a material adverse effect on our business, results of operations, financial condition and cash flows.
Under the EPAct 2005 and the Dodd-Frank Act, our businesses are subject to enhanced FERC and CFTC statutory authority to monitor certain
segments of the physical and financial energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of
the electricity and gas markets. Under these laws, FERC and CFTC have promulgated new regulations that have increased compliance costs and imposed new
reporting requirements on our businesses. For example, the Dodd-Frank Act substantially increased regulation of the over-the-counter derivative contracts
market and futures contract markets, which impacts our businesses. The new regulations require our operating subsidiaries to comply with certain margin
requirements for our over-the-counter derivative contracts with certain CFTC- or SEC-registered entities and if the rules implementing the new regulations
require us to post significant amounts of cash collateral with respect to swap transactions, this could have a material adverse effect on our liquidity. We
cannot predict the impact these new regulations will have on our businesses’ ability to hedge their commodity and interest rate risks or on over-the-counter
derivatives markets as a whole, but they could potentially have a material adverse effect on our businesses’ risk exposure, as well as reduce market liquidity
and further increase the cost of hedging activities.
With regard to the physical purchases and sales of energy commodities, the physical trading of energy commodities and any related transportation
and/or hedging activities that some of our operating subsidiaries undertake, our operating subsidiaries are required to observe the market-related regulations
and certain reporting and other requirements enforced by the FERC, the CFTC and the SEC. Additionally, to the extent that the operating subsidiaries enter
into transportation contracts with natural gas pipelines or transmission contracts with electricity transmission providers that are subject to FERC regulation,
the operating subsidiaries are subject to FERC requirements related to the use of such transportation or transmission capacity. Any failure on the part of our
operating subsidiaries to comply with the regulations and policies of the FERC, the CFTC or the SEC relating to the physical or financial trading and sales of
natural gas or other energy commodities, transportation or transmission of these energy commodities or trading or hedging of these commodities could result
in the imposition of significant civil and criminal penalties. Failure to comply with such regulations, as interpreted and enforced, could have a material
adverse effect on our business, results of operations, financial condition and cash flows.
Renewables’ ability to generate revenue from certain utility-scale wind energy power plants depends on having continuing interconnection
arrangements, PPAs, or other market mechanisms and depends upon interconnecting utility and RTO rules, policies, procedures and FERC tariffs that do
not present restrictions to current and future wind project operations.
The electric generation facilities owned by Renewables rely on interconnection and/or transmission agreements and transmission networks in order to
sell the energy generated by such facility. If the interconnection and/or transmission agreement of an electric generating facility Renewables owns is
terminated for any reason, Renewables may not be able to replace it with an interconnection or transmission arrangement on terms as favorable as the existing
arrangement, or at all, or it may experience significant delays or costs in securing a replacement. If a transmission network to which one or more of
Renewables’ electric generating facilities is connected experiences outages or curtailments, the affected projects may lose revenue. These factors could
materially affect Renewables’ ability to forecast operations and negatively affect our business, results of operations, financial condition and cash flow. In
addition, certain of Renewables’ operating facilities’ generation of electricity may be physically or economically curtailed, and offtakers or transmission or
interconnection providers may be permitted to restrict wind project operations without paying full compensation to Renewables pursuant to PPAs or
interconnection agreements or FERC tariff provisions or rules, policies or procedures of RTOs, which may reduce our revenues and impair our ability to
capitalize fully on a particular facility’s generating potential. Such curtailments or operational limitations could have a material adverse effect on our
business, financial condition, results of operations and cash flows. Furthermore, economic congestion on the transmission grid (for instance, a negative price
difference between the location where power is put on the grid by a project and the location where power is taken off the grid by the project’s customer) in
certain of the bulk power markets in which Renewables operates may occur and its businesses may be responsible for those congestion costs. Similarly,
negative congestion costs may require that the wind projects either not participate in the energy markets or bid and clear at negative prices which may require
the wind projects to pay money to operate each hour in which prices are negative. If such businesses were liable for such congestion costs or if the wind
projects are required to pay money to operate in any given hour when prices are negative, then our financial results could be adversely affected.
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Risks Relating to Our Business and Operations
Disruptions, uncertainty or volatility in the credit and capital markets may negatively affect our liquidity and capital needs and our ability to meet our
growth objectives and can also materially adversely affect our results of operations and financial condition.
A credit crisis affecting the banking system and the financial markets and the resultant deterioration of macroeconomic conditions, including a global
reduction in credit and liquidity in the financial markets and severe volatility in stock and bond markets could impact our financial operating conditions, our
day-to-day activities, our liquidity and cash positions, the loss of significant investment opportunities, the value of our business and our financial condition.
In addition, during periods of slow or little economic growth, energy conservation efforts often increase and the amount of uncollectible customer accounts
increases. These factors may also reduce earnings and cash flow.
Increases in interest rates or reductions in credit ratings could have an adverse impact on our cash flows, results of operations and financial condition.
Trends in the general level of interest rates and in the debt capital and credit markets could increase the cost of our borrowings. Borrowings from our
credit facilities and on our auction rate bonds are set by reference to the London Interbank Offer Rate , or LIBOR, and the cost of new long-term debt can be
affected by the level of US treasury rates and conditions in the debt capital markets that affect credit spreads.
In addition, AVANGRID and certain of its subsidiaries are parties to revolving credit facilities which contain facility fees and borrowing spread
pricing that are a function of the credit rating of the borrower. A lower credit rating automatically increases the cost of these facilities. A downgrade to the
lowest investment grade rating of the borrower would likely preclude access to the commercial paper market for NYSEG and CMP, which each have
commercial paper programs. Lower credit ratings would also increase the cost of debt and equity capital and, depending on the rating and market conditions,
can preclude access to the debt and equity capital markets. Any of these events could have a materially adverse effect on our business, results of operations,
financial condition and cash flows.
If Networks’ electricity and natural gas transmission, transportation and distribution systems do not operate as expected, they could require unplanned
expenditures, including the maintenance and refurbishment of Networks’ facilities, which could adversely affect our business, results of operations,
financial position and cash flows.
Networks’ ability to operate its electricity and natural gas transmission, transportation and distribution systems is critical to the financial performance
of our business. The ongoing operation of Networks’ facilities involves risks customary to the electric and natural gas industry that include the breakdown,
failure, loss of use or destruction of Networks’ facilities, equipment or processes or the facilities, equipment or processes of third parties due to war or acts of
terrorism, operational and safety performance below expected levels, errors in the operation or maintenance of these facilities and the inability to transport
electricity or natural gas to customers in an efficient manner. These and other occurrences could reduce potential earnings and cash flows and increase the
costs of repairs and replacement of assets. Losses incurred by Networks in respect of such occurrences may not be fully recoverable through insurance or
customer rates. Further, certain of Networks’ facilities require periodic upgrading and improvement. In addition, unplanned outages typically increase
Networks’ operation and maintenance expenses. Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated
capital expenditures, accident, failure of major equipment, shortage of or inability to acquire critical replacement or spare parts could result in reduced
profitability or regulatory penalties. For more information, see Risks Relating to Our Regulatory Environment above.
Our businesses operations and power production may fall below expectations due to the impact of severe weather or other natural events, which could
adversely affect our cash flows, results of operations and financial position.
Weather conditions directly influence the demand for electricity and natural gas and other fuels and affect the price of energy and energy-related
commodities. Severe weather, such as ice and snow storms, hurricanes and other natural disasters, such as floods and earthquakes, can be destructive and
cause power outages, bodily injury and property damage or affect the availability of fuel and water, which may require additional costs or loss of revenues,
for example, to restore service and repair damaged facilities, to obtain replacement power and to access available financing sources, that may not be
recoverable from customers, which could adversely affect our cash flows, results of operations and financial position. Many of our facilities could be placed
at greater risk of damage should changes in the global climate produce unusual variations in temperature and weather patterns, resulting in more intense,
frequent and extreme weather events, abnormal levels of precipitation and a change in sea level. A disruption or failure of electric generation, transmission or
distribution systems or natural gas production, transmission, transportation, storage or distribution systems in the event of ice and snow storms, long periods
of severe weather, hurricane, tornado or other severe weather event, or otherwise, could prevent us from operating our business in the normal course and could
result in any of the adverse consequences described above. Because utility companies, including our regulated utilities, have large
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customer bases, they are subject to adverse publicity focused on the reliability of their distribution services and the speed with which they are able to respond
to electric outages, natural gas leaks and similar interruptions caused by storm damage or other unanticipated events. Adverse publicity of this nature could
harm our reputations and the reputations of our subsidiaries.
Furthermore, many of operating facilities of Networks and Enstor, Inc., Gas’ wholly-owned direct subsidiary, are located either in, or close to, densely
populated public places. A failure of, or damage to, these facilities, could result in bodily injury or death, property damage, the release of hazardous
substances or extended service interruptions. The cost of repairing damage to Networks’ and Gas’ facilities and the potential disruption of their operations
due to storms, natural disasters or other catastrophic events could be substantial. In respect of our businesses where cost recovery is available, recovery of
costs to restore service and repair damaged facilities is or may be subject to regulatory approval, and any determination by the regulator not to permit timely
and full recovery of the costs incurred could have a material adverse effect on our business, results of operations, financial condition and cash flows.
If wind conditions are unfavorable or below Renewables’ production forecasts, or Renewables’ wind turbines are not available for operation,
Renewables projects’ electricity generation and the revenue generated from its projects may be substantially below our expectations.
Changing wind patterns or lower than expected wind resource could cause reductions in electricity generation at Renewables’ projects, which could
affect the revenues produced by these wind generating facilities. Renewables’ wind projects are sited, developed and operated to maximize wind
performance. Prior to siting a wind facility, detailed studies are conducted to measure the wind resource in order to estimate future production. However, wind
patterns or wind resource in the future might deviate from historical patterns and are difficult to predict. These events could negatively impact the results of
operations of Renewables, which may vary significantly from period to period, depending on the level of available resources. To the extent that resources are
not available at planned levels, the financial results from these facilities may be less than expected. Changing wind patterns or lower than expected wind
resources could also degrade equipment or components and the interconnection and transmission facilities’ lives or maintenance costs. Replacement and
spare parts for wind turbines and key pieces of electrical equipment may be difficult or costly to acquire or may be unavailable. The loss of any suppliers or
service providers or inability to find replacement suppliers or service providers or to purchase turbines at rates currently offered by Renewables’ existing
suppliers or a change in the terms of Renewables’ supply or operations and maintenance agreements, such as increased prices for maintenance services or for
spare parts, could have a material adverse effect on Renewables’ ability to construct and maintain wind farms or the profitability of wind farm development
and operation.
The revenues generated by Renewables’ facilities depend upon Renewables’ ability to maintain the working order of its wind turbines. A natural
disaster, severe weather, accident, failure of major equipment, shortage of or inability to acquire critical replacement or spare parts, failure in the operation of
any future transmission facilities that Renewables may acquire, including the failure of interconnection to available electricity transmission or distribution
networks, could damage or require Renewables to shut down its turbines or related equipment and facilities, leading to decreases in electricity generation
levels and revenues. Additionally, Renewables’ operating projects generally do not hold spare substation main transformers in inventory. These transformers
are designed specifically for each wind power project, and order lead times can be lengthy. If one of Renewables’ projects had to replace any of its substation
main transformers, it would be unable to sell all of its power until a replacement is installed.
If Renewables experiences a prolonged interruption at one of its operating projects due to natural events or operational problems and such events are
not fully covered by insurance, Renewables’ electricity generation levels could materially decrease, which could have a material adverse effect on its
business, results of operation and financial condition and could adversely affect our cash flows, results of operations and financial position.
Cyber breaches, acts of war or terrorism, grid disturbances or security breaches involving the misappropriation of confidential and proprietary
customer, employee, financial or system operating information could negatively impact our business.
Cyber breaches, acts of war or terrorism or grid disturbances resulting from internal or external sources could target our generation, transmission and
distribution facilities or our information technology systems. In the regular course of business, we maintain sensitive customer, employee, financial and
system operating information and are required by various federal and state laws to safeguard this information. Cyber or physical security intrusions could
potentially lead to disabling damage to our generation, transmission and distribution facilities and to theft and the release of critical operating information or
confidential customer or employee information, which could adversely affect our operations or adversely impact our reputation, and could result in
significant costs, fines and litigation. Additionally, because our generation and transmission facilities are part of an interconnected regional grid, we face the
risk of blackout due to a disruption on a neighboring interconnected system. As threats evolve and grow increasingly more sophisticated, we cannot ensure
that a potential security breach may not occur or quantify the potential impact of such an event. Any such cyber breaches could result in a significant
decrease in revenues, significant expense to
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repair system damage or security breaches, adversely impact our reputation, regulatory penalties and liability claims, which could have a material adverse
effect on our cash flows, results of operations and financial condition.
Risks including but not limited to any physical security breach involving unauthorized access, electricity or equipment theft and vandalism could
adversely affect our business operations and adversely impact our reputation.
A physical attack on our transmission and distribution infrastructure could interfere with normal business operations and affect our ability to control
our transmission and distribution assets. A physical security intrusion could potentially lead to theft and the release of critical operating information, which
could adversely affect our operations or adversely impact our reputation, and could result in significant costs, fines and litigation. Additionally, certain of our
power generation and transmission and distribution assets and equipment are at risk for theft and damage. For example, Networks is at risk for copper wire
theft, especially, due to an increased demand for copper in the United States and internationally. Theft of copper wire or solar panels can cause significant
disruption to Networks’ and Renewables’ operations, respectively, and can lead to operating losses at those locations. Furthermore, Renewables can incur
damage to wind turbine equipment, either through natural events such as lightning strikes that damage blades or in-ground electrical systems used to collect
electricity from turbines, or through vandalism, such as gunshots into towers or other generating equipment. Such damage can cause disruption of operations
for unspecified periods which may lead to operating losses at those locations.
Our risk management policies cannot fully eliminate the risk associated with some of our operating subsidiaries’ commodity trading and hedging
activities, which may result in significant losses.
Renewables has exposure to commodity price movements through their “naturallong positions in electricity and natural gas storage in addition to
proprietary trading and hedging activities. Since market prices and temporal price spreads for natural gas reflect the demand for these products and their
availability at a given time, the overall operating results of Gas’ business may fluctuate substantially on a seasonal basis.
Networks and Renewables manage the exposure to risks of commodity price movements through internal risk management policies, enforcement of
established risk limits and risk management procedures. These risk policies, risk limits and risk management procedures may not work as planned and cannot
eliminate all risks associated with these activities. Even when these risk policies and procedures are followed, and decisions are made based on projections
and estimates of future performance, results of operations may be diminished if the judgments and assumptions underlying those decisions prove to be
incorrect. Our risk management tools and metrics associated with our hedging and trading procedures, such as daily value at risk, stop loss limits and
liquidity guidelines, are based on historical price movements. Due to the inherent uncertainty involved in price movements and potential deviation from
historical pricing behavior, we are unable to assure that our risk management tools and metrics will be effective to protect against material adverse effects on
our business, financial condition, results of operations and prospects. Factors, such as future prices and demand for power and other energy-related
commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, we cannot
fully predict the impact that some of our subsidiaries’ commodity trading and hedging activities and risk management decisions may have on our business,
results of operations, financial condition and cash flows.
We expect to invest in development opportunities in all segments of our business, but such opportunities may not be successful, projects may not
commence operation as scheduled and/or within budget or at all, which could have a material adverse effect on our business prospects.
We are pursuing broader development investment opportunities related to all segments of our business, particularly in respect of additional
opportunities related to electric transmission, renewable energy generation, interconnections to generating resources and other development investment
opportunities. The development, construction and expansion of such projects involve numerous risks. Various factors could result in increased costs or
result in delays or cancellation of these projects. Risks include regulatory approval processes, permitting, new legislation, economic events, environmental
and community concerns, negative publicity, design and siting issues, difficulties in obtaining required rights of way, construction delays and cost overruns,
including delays in equipment deliveries, particularly of wind turbines or transformers, severe weather, competition from incumbent facilities and other
entities, and actions of strategic partners. For example, there may be delays or unexpected developments in completing current and future construction
projects. While most of Renewables’ construction projects are constructed under fixed-price and fixed-schedule contracts with construction and equipment
suppliers, these contracts provide for limitations on the liability of these contractors to pay liquidated damages for cost overruns and construction delays.
These circumstances could prevent Renewables’ construction projects from commencing operations or from meeting original expectations about how much
electricity it will generate or the returns it will achieve. In addition, for Renewables’ projects that are subject to PPAs, substantial delays could cause defaults
under the PPAs, which generally require the completion of project construction by a certain date at specified performance levels. A delay resulting in a wind
project failing to qualify for federal production tax credits could result in losses that would be substantially greater than the amount of
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liquidated damages paid to Renewables. In December 2015, the Consolidated Appropriations Act, 2016 extended the expiration date for this tax credit to
December 31, 2019, for wind facilities commencing construction, with a phase-down beginning for wind projects commencing construction after December
31, 2016. Furthermore, as required by Connecticuts Comprehensive Energy Strategy, CNG and SCG filed, jointly with Yankee Gas Services Company, a
comprehensive natural gas expansion plan (“Expansion Plan”) outlining a structured approach to add approximately 280,000 new gas heating customers
(approximately 200,000 of which relate to SCG and CNG) state-wide over the next 10 years. In order to serve new customers to comply with the Expansion
Plan, SCG and CNG need to lay significant miles of new pipeline, maintain, expand and potentially upgrade their existing distribution and/or storage
infrastructure, and build new gate stations. Various factors may prevent or delay SCG and CNG from completing such projects or make completion more
costly, such as the inability to obtain required approval from local or state regulatory and governmental bodies, public opposition to the project, inability to
obtain adequate financing, construction delays, cost overruns, and inability to negotiate acceptable agreements relating to rights-of-way, construction or
other material development components. As a result, SCG and CNG may not be able to adequately support the proposed customer growth, which would
negatively impact their businesses, cash flows, results of operations and financial condition. Additionally, RGE’s Rochester Area Reliability Project, which
includes the development of a new substation and transmission lines and was approved by the NYPSC, has encountered significant delays due to the
concerns of landowners. Should any of these factors result in such delays or cancellations, our growth projections, financial position, results of operations,
and cash flows could be adversely affected or our future growth opportunities may not be realized as anticipated.
Advances in technology and rate design initiatives could impair or eliminate the competitive advantage of our business or could result in customer
defection, which could have a material adverse effect on our growth, business, financial condition and results of operations.
The emergence of technology and initiatives designed to reduce greenhouse gas emissions or limit the effects of global warming and overall climate
change has increased the development of new technologies for power generation, energy efficiency, and for investment in research and development to make
those technologies more efficient and cost effective. There is a potential that new technology or rate design incentives could adversely affect the demand for
services of our regulated subsidiaries thus impacting our revenues, which could adversely affect our cash flows, results of operations and financial concerns.
For example, net energy metering allows electricity customers who supply their own electricity from on-site generation to pay only for the net energy
obtained from the utility. Further, the behind-the-meter storage systems and grid integration components such as inverters or electronics could result in
electricity delivery customers abandoning the grid system or replacing part of grid services with self-supply or self-balancing, which could impact the return
on current or future Networks’ assets deployed and designed to serve projected load. Such emergence of alternative sources of energy supply can result in
customers relying on the power grid for limited use, such as in the case of a deficit or an emergency, or completely abandoning the grid, which is known as
customer defection. While certain of the regulated utilities of Networks are subject to RDMs, these are temporary in nature and there is no assurance such
mechanisms will always be extended. The progressive reduction in the costs of distributed energy assets, as a result of technological improvements, large
scale deployment in certain jurisdictions and constructive support regimes could result in customer defection (individually or integrated in micro-grids)
when a net benefit analysis of investing in self-supply and storage of energy compared to energy provided by utility service appears attractive for certain
customer classes. Similarly, future investments in Networks could be impacted if adequate rate making does not fully contemplate the characteristics of an
integrated reliable grid from a unified perspective, regardless of customer disconnection. Further, the interoperability, integration and standard connection of
these distributed energy devices and systems could place a burden on the system of Networks’ operating subsidiaries, without adequately compensating
them. Furthermore, the technologies used in the renewable energy sector change and evolve rapidly. Techniques for the production of electricity from
renewable sources are constantly improving and becoming more complex. In order to maintain Renewables’ competitiveness and expand its business,
Renewables must adjust effectively to changes in technology. If Renewables fails to react effectively to current and future technological changes in the
sector in a timely manner, Renewables’ future business growth, results of operations and financial condition could be materially adversely affected.
Renewables’ revenue may be reduced significantly upon expiration of PPAs if the market price of electricity decreases and Renewables is otherwise
unable to negotiate favorable pricing terms.
Renewables’ portfolio of PPAs is made up of PPAs that primarily have fixed or otherwise predetermined electricity prices for the life of the PPA. A
decrease in the market price of electricity, including lower prices for traditional fossil fuels, could result in a decrease in revenues once a PPA has expired or
upon a renewal of a PPA. Any decrease in the price payable to Renewables under new PPAs could have a material adverse effect on our business, results of
operations, financial conditions and cash flows. For the majority of Renewables’ wind energy generation projects, upon the expiration of a PPA, the project
becomes a merchant project subject to market risks, unless Renewables can negotiate a renewal of the PPA. If Renewables is not able to replace an expiring
PPA with a contract on equivalent terms and conditions or otherwise obtain prices that permit operation of the related facility on a profitable basis, the
affected site may temporarily or permanently cease operations.
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There are a limited number of purchasers of utility-scale quantities of electricity, which exposes Renewables’ utility-scale projects to additional risk
that could have a material adverse effect on its business.
Since the transmission and distribution of electricity is highly concentrated in most jurisdictions, there are a limited number of possible purchasers for
utility-scale quantities of electricity in a given geographic location, including transmission grid operators, state and investor-owned power companies, public
utility districts and cooperatives. As a result, there is a concentrated pool of potential buyers for electricity generated by Renewables’ businesses, which may
restrict our ability to negotiate favorable terms under new PPAs and could impact our ability to find new customers for the electricity generated by our
generation facilities should this become necessary. Furthermore, if the financial condition of these utilities and/or power purchasers deteriorated or the RPS
programs, climate change programs or other regulations to which they are currently subject and that compel them to source renewable energy supplies
change, demand for electricity produced by Renewables’ businesses could be negatively impacted.
Lower prices for other fuel sources may reduce the demand for wind and solar energy development, which could have a material adverse effect on
Renewables’ ability to grow its business.
Wind and solar energy demand is affected by the price and availability of other fuels, including nuclear, coal, natural gas and oil, as well as other
sources of renewable energy. To the extent renewable energy, particularly wind energy, becomes less cost-competitive due to reduced government targets,
increases in the cost of wind energy, as a result of new regulations, and incentives that favor alternative renewable energy, cheaper alternatives or otherwise,
demand for wind energy and other forms of renewable energy could decrease. Slow growth or a long-term reduction in the demand for renewable energy
could have a material adverse effect on Renewables’ ability to grow its business.
Volatility in the price of natural gas and home heating oil could adversely impact the demand for gas conversions and could have a material adverse
effect on our regulated gas utilities’ ability to grow their businesses.
Conversion from home heating oil to natural gas requires a significant investment by customers. If the price of natural gas does not remain sufficiently
below the prices of home heating oil, current oil heating customers may elect not to convert to natural gas. Recent reductions in oil prices demonstrate that it
is difficult to predict future home heating costs. In addition, any new regulations imposed on natural gas, particularly on extraction of natural gas from shale
formations, could lead to substantial increases in the price of natural gas. Reduced prices for heating oil or increases in in prices for natural gas may cause
potential natural gas customers to forgo converting their heating systems to natural gas and as a result, could negatively impact the forecasted growth of the
CNG, SCG and Berkshire businesses, and their cash flows, results of operations and financial condition.
Our subsidiaries do not own all of the land on which their projects are located and their use and enjoyment of real property rights for their projects may
be adversely affected by the rights of lienholders and leaseholders that are superior to those of the grantors of those real property rights to our
subsidiaries’ projects, which could have a material adverse effect on their business, results of operations, financial condition and cash flows.
Our subsidiaries do not own all of the land on which their projects are located. For example, Renewables does not own all of the land on which its
wind projects are located and Gas does not own all of the land on which its natural gas storage projects are located. Such projects generally are, and future
projects may be, located on land occupied under long-term easements, leases and rights of way. The ownership interests in the land subject to these
easements, leases and rights of way may be subject to mortgages securing loans or other liens and other easements, lease rights and rights of way of third
parties that were created previously. As a result, some of the rights under such easements, leases or rights of way held by our operating subsidiaries may be
subject to the rights of these third parties, and the rights of our operating subsidiaries to use the land on which their projects are or will be located and their
projects rights to such easements, leases and rights of way could be lost or curtailed. Any such loss or curtailment of the rights of our operating subsidiaries
to use the land on which their projects are or will be located could have a material adverse effect on their business, results of operations, financial condition
and cash flows.
We and our subsidiaries are subject to litigation or administrative proceedings, the outcome or settlement of which could adversely affect our business,
results of operations, financial condition and cash flows.
Our operating subsidiaries have been and continue to be involved in legal proceedings, administrative proceedings, claims and other litigation that
arise in the ordinary course of business. These actions may include environmental claims, employment-related claims and contractual disputes or claims for
personal injury or property damage that occur in connection with services performed relating to the operation of our businesses, or actions by regulatory or
tax authorities. Unfavorable outcomes or developments relating to these proceedings or future proceedings, such as judgments for monetary damages,
injunctions or denial or revocation of permits, could have a material adverse effect on our business, financial condition and results of operations. In addition,
settlement of claims could adversely affect our business, results of operations, financial condition and cash flows.
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Storing, transporting and distributing natural gas involves inherent risks that could cause us to incur significant financial losses.
There are inherent hazards and operation risks in gas distribution activities, such as leaks, accidental explosions and mechanical problems that could
cause the loss of human life, significant damage to property, environmental pollution and impairment of operations. The location of pipelines and storage
facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting
from these risks. These activities may subject us to litigation and administrative proceedings that could result in substantial monetary judgments, fines or
penalties. To the extent that the occurrence of any of these events is not fully covered by insurance or natural gas hedges, they could adversely affect our
revenue, earnings and cash flow.
We are not able to insure against all potential risks and may become subject to higher insurance premiums, and our ability to obtain insurance and the
terms of any available insurance coverage could be materially adversely affected by international, national, state or local events and company-specific
events, as well as the financial condition of insurers.
Our businesses and activities are exposed to the risks inherent in the construction and operation of our respective assets, such as electrical power
plants, wind power plants and other renewable energy projects and natural gas storage facilities, including breakdowns, manufacturing defects, natural
disasters, terrorist attacks, cyber attacks and sabotage. Our subsidiaries are also exposed to third party liability risks and environmental risks. While our
operating subsidiaries maintain insurance coverage, such insurance may not continue to be offered on an economically feasible basis and may not cover all
events that could give rise to a loss or claim involving the assets or operations of our subsidiaries. For example, Renewables currently has 409 megawatts, or
MW, of installed capacity in California subject to known earthquake risks and approximately 600 MW of installed capacity on the Texas Gulf Coast subject
to known hurricane and windstorm risks. Further, while insurance coverage applies to property damages and business interruptions, this coverage is limited as
a result of severe insurance market restrictions and we are generally not fully insured against all significant losses. In addition, our subsidiaries’ insurance
policies are subject to annual review by their insurers. Our ability to obtain insurance and the terms of any available insurance coverage could be materially
adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers. If insurance
coverage is not available or obtainable on acceptable terms, we may be required to pay costs associated with adverse future events. If one of our operating
subsidiaries were to incur a serious uninsured loss or a loss significantly exceeding the limits of their insurance policies, the results could have a material
adverse effect on our business, results of operations, financial condition and cash flows.
Furthermore, Networks’ gas distribution and transportation activities involve a variety of inherent hazards and operating risks, such as leaks,
accidents, explosions, and mechanical problems and could result in serious injury to employees and non-employees, loss of human life, significant damage to
property, environmental pollution and impairment of our subsidiaries’ operations. In accordance with customary industry practice, our subsidiaries maintain
insurance against some, but not all, of these risks and losses. The location of natural gas pipelines and natural gas storage facilities near populated areas,
including residential areas, commercial business centers and industrial sites, could increase the level of damages that could potentially result from these risks.
The occurrence of any of these events not fully covered by insurance could adversely affect our business, results of operations, financial position and cash
flows.
The benefits of any warranties provided by the suppliers of equipment for Networks and Renewables’ projects may be limited by the ability of a supplier
to satisfy its warranty obligations, or if the term of the warranty has expired or has liability limits which could have a material adverse effect on our
business, results of operation, financial condition and cash flows.
Networks and Renewables expect to benefit from various warranties, including product quality and performance warranties, provided by suppliers in
connection with the purchase of equipment. The suppliers of our operating subsidiaries may fail to fulfill their warranty obligations or a particular defect may
not be covered by a warranty. Even if a supplier fulfills its obligations, the warranty may not be sufficient to compensate the operating subsidiary for all of its
losses. In addition, these warranties generally expire within two to five years after the date each equipment item is delivered or commissioned and are subject
to liability limits. If installation is delayed, the operating subsidiaries may lose all or a portion of the benefit of a warranty. If Networks or Renewables seeks
warranty protection and a supplier is unable or unwilling to perform its warranty obligations, whether as a result of its financial condition or otherwise, or if
the term of the warranty has expired or a liability limit has been reached, there may be a reduction or loss of warranty protection for the affected equipment,
which could have a material adverse effect on our business, results of operation, financial condition and cash flows.
A disruption in the wholesale energy markets or failure by an energy supplier could adversely affect our business and results of operation.
Almost all the electricity and gas that Networks sells to full-service customers is purchased through the wholesale energy markets or pursuant to
contracts with energy suppliers. A disruption in the wholesale energy markets or a failure on the part of energy
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suppliers or operators of energy delivery systems that connect to Networks’ energy facilities could adversely affect Networks’ ability to meet its customers’
energy needs and adversely affect our business and results of operation.
The increased cost of purchasing natural gas during periods in which natural gas prices are rising significantly could adversely impact our earnings
and cash flow.
The rates that are permitted to be charged by our regulated natural gas utilities that allow for rate recovery generally allow such businesses to recover
their cost of purchasing natural gas. In general, the various regulatory agencies allow our regulated utilities to recover the costs of natural gas purchased for
customers on a dollar-for-dollar basis (in the absence of disallowances), without a profit component. Networks’ regulated natural gas utilities periodically
adjust customer rates for increases and decreases in the cost of gas purchased by such regulated utilities for sale to its customers. Under the regulatory body-
approved gas cost recovery pricing mechanisms, the gas commodity charge portion of gas rates charged to customers may be adjusted upward on a periodic
basis. If the cost of purchasing natural gas increases and Networks’ regulated natural gas utilities is unable to recover these costs from its customers
immediately, or at all, Networks may incur increased costs associated with higher working capital requirements and/or realize increased costs. In addition,
any increases in the cost of purchasing natural gas may result in higher customer bad debt expense for uncollectible accounts and reduced sales volume and
related margins due to lower customer consumption.
Pension and post-retirement benefit plans could require significant future contributions to such plan which could adversely impact our business, results
of operations, financial condition and cash flows.
We provide defined benefit pension plans and other post-retirement benefits administered by our subsidiaries for a significant number of employees,
former employees and retirees. Financial market disruptions and significant declines in the market values of the investments held to meet the pension and
post-retirement obligations, discount rate assumptions, participant demographics and increasing longevity, and changes in laws and regulations may require
us to make significant contributions to the plans. Large funding requirements or significant increases in expenses could adversely impact our business, results
of operations, financial condition and cash flows.
Long-term low natural gas prices and/or seasonal or locational variation in natural gas price spreads could have a negative impact on the natural gas
business and gas storage services.
The natural gas business benefits from price volatility and temporal price spreads. Variation in price spreads can impact the level of demand and the
rates that can be charged for natural gas storage services. If natural gas prices and volatility remain low, or prices decline further, then the natural gas business
could generate less revenue and lower demand for natural gas storage services. A sustained decline in these prices and volatility could have an adverse
impact on gas business, results of operation, financial condition and cash flows.
Our existing credit facilities contain, and agreements that we may enter into in the future may contain covenants that could restrict our financial
flexibility.
Our existing credit facilities, and the credit facilities of our subsidiaries, contain covenants imposing certain requirements on our business including
covenants regarding the ratio of indebtedness to total capitalization. Furthermore, our subsidiaries periodically issue long-term debt, historically consisting
of both secured and unsecured indebtedness. These third-party debt agreements also contain covenants, including covenants regarding the ratio of
indebtedness to total capitalization. These requirements may limit our ability and the ability of our subsidiaries to take advantage of potential business
opportunities as they arise and may adversely affect our conduct and our operating subsidiaries’ current business, including restricting our ability to finance
future operations and capital needs and limiting the subsidiaries’ ability to engage in other business activities. Other covenants place or could place
restrictions on our ability and the ability of our operating subsidiaries to, among other things, incur additional debt, create liens, and sell or transfer assets.
Agreements we and our operating subsidiaries enter into in the future may also have similar or more restrictive covenants, especially if the general
credit market deteriorates. A breach of any covenant in the existing credit facilities or the agreements governing our other indebtedness would result in an
event of default. Certain events of default may trigger automatic acceleration of payment of the underlying obligations or may trigger acceleration of
payment if not remedied within a specified period. Events of default under one agreement may trigger events of default under other agreements, although our
regulated utilities are not subject to the risk of default of affiliates. Should payments become accelerated as the result of an event of default, the principal and
interest on such borrowing would become due and payable immediately. If that should occur, we may not be able to make all of the required payments or
borrow sufficient funds to refinance the accelerated debt obligations. Even if new financing is then available, it may not be on terms that are acceptable to us.
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We may be unable to meet our financial obligations and to pay dividends on our common stock if our subsidiaries are unable to pay dividends or repay
loans from us.
We are a holding company and, as such, have no revenue-generating operations of our own. We are dependent on dividends and the repayment of
loans from our subsidiaries and on external financings to provide the cash that is necessary to make future investments, service debt we have incurred, pay
administrative costs and pay dividends. Our subsidiaries are separate legal entities and have no independent obligation to pay us dividends. Prior to paying
us dividends, the subsidiaries have financial obligations that must be satisfied, including among others, their operating expenses and obligations to creditors.
Furthermore, our regulated utilities are restricted by regulatory decision from paying us dividends unless a minimum equity-to-total capital ratio is
maintained. The future enactment of laws or regulations may prohibit or further restrict the ability of our subsidiaries to pay upstream dividends or to repay
funds. In addition, in the event of a subsidiarys liquidation or reorganization, our right to participate in a distribution of assets is subject to the prior claims
of the subsidiarys creditors. As a result, our ability to pay dividends on our common stock and meet our financial obligations is reliant on the ability of our
subsidiaries to generate sustained earnings and cash flows and pay dividends to and repay loans from us.
Our investments and cash balances are subject to the risk of loss.
Our cash balances and cash balances at our subsidiaries may be deposited in banks, may be invested in liquid securities such as commercial paper or
money market funds or may be deposited in a notional cash pooling account in which we are a participant along with other affiliates of the Iberdrola Group.
Bank deposits in excess of federal deposit insurance limits would be subject to risks in the counterparty bank. Liquid securities and money market funds are
subject to loss of principal, more likely in an adverse market situation, and to the risk of illiquidity. Moreover, under the agreement governing the notional
cash pooling account mentioned above, credit balances in the cash pooling account are pledged as collateral for the debit balances of other cash pooling
participants. We are therefore subject to the credit risk of the affiliated parties to the cash pooling agreement and to Iberdrolas ability to manage the overall
liquidity of the Iberdrola Group.
We and our subsidiaries may suffer the loss of key personnel or the inability to hire and retain qualified employees, which could result in a material
adverse effect on our business, financial condition, results of operations and prospects.
The operations of our operating subsidiaries depend on the continued efforts of our employees and our subsidiaries’ employees. Retaining key
employees and maintaining the ability to attract new employees are important to our financial performance and for our subsidiaries’ operations and financial
performance. We cannot guarantee that any member of our management or of our subsidiaries’ management will continue to serve in any capacity for any
particular period of time. In addition, a significant portion of our and our subsidiaries’ workforce, including many workers with specialized skills maintaining
and servicing the electrical infrastructure, will be eligible to retire over the next five to ten years. Such highly skilled individuals cannot be quickly replaced
due to the technically complex work they perform. If a significant amount of such workers retire and are not replaced, the subsequent loss in productivity and
increased recruiting and training costs could result in a material adverse effect on our business, financial condition, results of operations and prospects.
We and our subsidiaries face the risk of strikes, work stoppages or an inability to negotiate future collective bargaining agreements on commercially
reasonable terms which could have a material adverse effect on our business, results of operations, financial condition and cash flows.
A majority of the employees at Networks’ facilities are subject to collective bargaining agreements with various unions. Additionally, unionization
activities, including votes for union certification, could occur among non-union employees. If union employees strike, participate in a work stoppage or
slowdown or engage in other forms of labor strike or disruption, our subsidiaries could experience reduced power generation or outages if replacement labor
is not procured. The ability to procure such replacement labor is uncertain, though risks are reduced by rigorous contingency planning. Strikes, work
stoppages or an inability to negotiate future collective bargaining agreements on commercially reasonable terms could have a material adverse effect on our
business, results of operations, financial condition and cash flows.
Changes in tax laws, as well as judgments and estimates used in the determination of tax-related asset and liability amounts, could materially
adversely affect our business, results of operations, financial condition and cash flows.
Our provision for income taxes and reporting of tax-related assets and liabilities require significant judgments and the use of estimates. Amounts of
tax-related assets and liabilities involve judgments and estimates of the timing and probability of recognition of income, deductions and tax credits,
including, but not limited to, estimates for potential adverse outcomes regarding tax positions that have been taken and the ability to utilize tax benefit
carryforwards, such as net operating loss, or NOL, and tax credit carryforwards. Actual income taxes could vary significantly from estimated amounts due to
the future impacts of, among other things, changes in tax laws, regulations and interpretations, our financial condition and results of operations.
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Risks Relating to Ownership of Our Common Stock
The trading price and volume of our common stock may be volatile and the value of your investment could decline.
The trading price of and demand for our common stock could fluctuate and will depend on a number of conditions, including:
the risk factors described in this annual report on Form 10-K;
general economic conditions internationally and within the U.S., including changes in interest rates;
changes in electricity and natural gas prices;
actual or anticipated fluctuations in our quarterly and annual results and those of its competitors;
the businesses, operations, results and prospects of us;
future mergers and strategic alliances;
market conditions in the energy industry;
changes in government regulation, taxes, legal proceedings or other developments;
shortfalls in our operating results from levels forecasted by securities analysts;
investor sentiment toward the stock of energy companies in general;
announcements concerning us or its competitors;
maintenance of acceptable credit ratings or credit quality; and
the general state of the securities markets.
These and other factors may impair the development or sustainability of a liquid market for our common stock and the ability of investors to sell
shares at an attractive price. These factors also could cause the market price and demand for our common stock to fluctuate substantially, which may
negatively affect the price and liquidity of our common stock. These fluctuations could cause you to lose all or part of your investment in our common stock.
Many of these factors and conditions are beyond our control and may not be related to our operating performance.
If securities or industry analysts do not publish research or publish inaccurate or unfavorable research about us or our businesses, the price and
trading volume of our common stock could decline.
The trading market for our common stock will, to some extent, depend on the research and reports that securities or industry analysts publish about us
or our business. We do not have any control over these analysts. If one or more of the analysts who cover us should downgrade our shares or change their
opinion of our business prospects, our share price would likely decline. If one or more of these analysts cease coverage of us or fail to publish reports on us
regularly, demand for our common stock could decrease, which might cause our stock price and trading volume to decline.
Iberdrola, S.A. will exercise significant influence over us, and its interests in us may be different than yours. Additionally, future sales or issuances of
our common stock by Iberdrola, S.A. could have a negative impact on the price of our common stock.
Iberdrola, S.A. owns approximately 81.5% of our common stock and will be able to exercise significant influence over our business policies and
affairs, including the composition of our board of directors and any action requiring the approval of our shareholders, including the adoption of amendments
to the certificate of incorporation and bylaws and the approval of a merger or sale of substantially all of our assets, subject to applicable law and the
limitations set forth in the shareholder agreement. The directors designated by Iberdrola, S.A. will have significant authority to effect decisions affecting our
capital structure, including the issuance of additional capital stock, incurrence of additional indebtedness, the implementation of stock repurchase programs
and the decision of whether or not to declare dividends.
The interests of Iberdrola, S.A. may conflict with the interests of our other shareholders. For example, Iberdrola, S.A. may support certain long-term
strategies or objectives for us that may not be accretive to shareholders in the short term. The concentration of ownership may also delay, defer or even
prevent a change in control, even if such a change in control would benefit our other shareholders, and may make some transactions more difficult or
impossible without the support of Iberdrola, S.A. This significant
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concentration of share ownership may adversely affect the trading price for our common stock because investors may perceive disadvantages in owning stock
in companies with shareholders who own significant percentages of a company’s outstanding stock.
Further, sales of our common stock by Iberdrola, S.A. or the perception that sales may be made by it could significantly reduce the market price of our
common stock. We and Iberdrola, S.A. are parties to a shareholder agreement pursuant to which Iberdrola, S.A. will be generally restricted from transferring
shares of our common stock, subject to certain exceptions. Iberdrola, S.A. will also be restricted, for a period of three years after the completion of the
proposed merger, from transferring more than an aggregate of 10% of the outstanding shares of our common stock in any transaction or series of transactions,
unless all of our shareholders are entitled to participate in such transaction (on a pro rata basis) and are entitled to the same per share consideration to be
received in such transaction as Iberdrola, S.A. In addition, even if Iberdrola, S.A. does not sell a large number of our common stock into the market, its right to
transfer such shares may depress the price of our common stock. Furthermore, pursuant to the shareholder agreement and subject to the terms and conditions
therein, Iberdrola, S.A. will be entitled to customary registration rights of our common stock, including the right to choose the method by which the common
stock are distributed, a choice as to the underwriter and fees and expenses to be borne by us. Iberdrola, S.A. will also retain preemptive rights to protect
against dilution in connection with issuances of equity by us. If Iberdrola, S.A. exercises its registration rights and/or its preemptive rights, the market price of
shares of our common stock may be adversely affected.
We have elected to take advantage of the “controlled company” exemption to the corporate governance rules for NYSE-listed companies, which could
make our common stock less attractive to some investors or otherwise harm our stock price.
Under the rules of the NYSE, a company in which over 50% of the voting power is held by an individual, a group or another company is a “controlled
company” and is not required to have:
a majority of its board of directors be independent directors;
a nominating and corporate governance committee or a compensation committee, or to have such committees be composed entirely of
independent directors; and
the compensation of the chief executive officer be determined, or recommended to the board of directors for determination, either by a
compensation committee comprised of independent directors or by a majority of the independent directors on the board of directors.
In light of our status as a controlled company, we currently rely on these exemptions. Accordingly, you will not have the same protections afforded to
shareholders of companies that are subject to all of the corporate governance requirements of the NYSE without regard to the exemptions available for
“controlled companies.” Our status as a controlled company could make our common stock less attractive to some investors or otherwise harm our stock
price.
Our dividend policy is subject to the discretion of our board of directors and may be limited by our debt agreements and limitations under New York
law.
Although we currently anticipate paying a regular quarterly dividend, any such determination to pay dividends is at the discretion of our board of
directors and dependent on conditions such as our financial condition, earnings, legal requirements, including limitations under New York law, restrictions in
our debt agreements that limit our ability to pay dividends to shareholders and other factors the board of directors deem relevant. Our board of directors may,
in its sole discretion, change the amount or frequency of dividends or discontinue the payment of dividends entirely. For these reasons, you will not be able
to rely on dividends to receive a return on your investment.
If we are unable to implement and maintain effective internal control over financial reporting in the future, investors may lose confidence in the
accuracy and completeness of our financial reports and the trading price of our common stock may be negatively affected.
As a public company, we are subject to reporting, disclosure control and other obligations under the Exchange Act, the Sarbanes-Oxley Act, or SOX,
the Dodd-Frank Act, as well as rules adopted, and to be adopted, by the SEC and the NYSE. For example, beginning with our annual report on Form 10-K for
the fiscal year ending December 31, 2016, Section 404 of SOX will require our management to report on the effectiveness of our internal control over
financial reporting and our independent registered public accounting firm to attest to the effectiveness of our internal controls. Our management and other
personnel will continue to devote a substantial amount of time to these compliance activities. If we are not able to comply with the requirements of Section
404 in a timely manner or if we are unable to conclude that our internal control over financial reporting is effective, our ability to accurately report our cash
flows, results of operations or financial condition could be inhibited and additional financial and management resources could be required. Any failure to
maintain internal control over financial reporting or if our independent
39
registered public accounting firm determines the we have a material weakness or significant deficiency in our internal control over financial reporting, could
cause investors to lose confidence in the accuracy and completeness of our financial reports, a decline in the market price of our common stock, or subject us
to sanctions or investigations by the NYSE, the SEC or other regulatory authorities. Failure to remedy any material weakness or significant deficiency in our
internal control over financial reporting, or to implement or maintain other effective control systems required of public companies, could also restrict our
future access to the capital markets and reduce or eliminate the trading market for our common stock. Further, as a result of becoming a public company, we
have incurred and will continue to incur higher legal, accounting and other expenses than we did as a private company, and these expenses may increase
even more in the future.
Item 1B. Unresolved Staff Comments.
None
Item 2. Properties.
We have included descriptions of the location and general character of our principal physical operating properties by segment in “Item 1. Business”,
which is incorporated herein by reference. The principal offices of AVANGRID and Networks are located in New Gloucester, Maine Rochester, New York and
New Haven and Orange, Connecticut. Renewables’ headquarters is located in Portland, Oregon, while Gas is principally located in Houston, Texas. In
addition, AVANGRID and its subsidiaries have various administrative offices located throughout the United States. AVANGRID leases part of its
administrative and local offices.
The following table sets forth the principal properties of AVANGRID, by location, type, lease or ownership and size as of December 31, 2015:
Location Type of Facility Lease/Owned
Size (square
feet)
New Haven, Connecticut Office Leased 51,300
Orange, Connecticut Office Owned 426,294
Augusta, Maine Office Leased 220,400
New Gloucester, Maine Office Leased 60,913
Rochester, New York Office Owned 122,493
Portland, Oregon Office Leased 57,027
Houston, Texas Office Leased 21,571
We believe that our office facilities are adequate for our current needs and that additional office space can be obtained if necessary.
Item 3. Legal Proceedings.
We are involved in various proceedings, legal actions and claims arising in the normal course of our respective businesses. The outcomes of these
matters will generally not be known for an extended period of time. In certain of the legal proceedings, the claimants seek damages, as well as other
compensatory relief, which could result in the payment of significant claims and settlements. While the ultimate outcome and impact of any proceeding
cannot be predicted with certainty, management believes that the resolution of its pending proceedings will not have a material adverse effect on its financial
condition or results of operations.
FirstEnergy
NYSEG sued FirstEnergy Corp., or FirstEnergy, under the Comprehensive Environmental Response, Compensation, and Liability Act to recover
environmental cleanup costs at nineteen former manufactured gas sites. In July 2011, the District Court issued a decision and order in NYSEG’s favor. Based
on past and future cleanup costs at the nineteen sites in dispute, FirstEnergy would be required to pay NYSEG approximately $60 million if the decision were
upheld on appeal. On September 9, 2011, FirstEnergy paid NYSEG $30 million, representing their share of past costs of $27 million and pre-judgment
interest of $3 million.
FirstEnergy appealed the decision to the Second Circuit Court of Appeals. On September 11, 2014, the Second Circuit Court of Appeals affirmed the
District Courts decision in NYSEG’s favor, but modified the decision for nine sites, reducing NYSEG’s damages for incurred costs from $27 million to $22
million, excluding interest, and reducing FirstEnergys allocable share of future costs at these sites. NYSEG refunded FirstEnergy the excess $5 million in
November 2014.
40
FirstEnergy remains liable for a substantial share of clean-up expenses at nine MPG Energy sites. In January 2015, NYSEG sent FirstEnergy a demand
for $16 million representing FirstEnergys share of clean-up expenses incurred by NYSEG at the nine sites from January 2010 to November 2014 while the
District Court appeal was pending. This amount has been paid by FirstEnergy. FirstEnergy would also be liable for a share of post 2014 costs, which, based
on current projections, would be $26 million. This amount is being treated as a contingent asset and has not been recorded as either a receivable or a decrease
to the environmental provision.
Century Indemnity and OneBeacon
NYSEG filed suit in federal court on August 14, 2013 against two excess insurers, Century Indemnity and OneBeacon, who provided excess liability
coverage to NYSEG. NYSEG seeks payment for clean-up costs associated with contamination at twenty-two former manufactured gas plants. Based on
estimated clean-up costs of $282 million, the carriers’ allocable share is approximately $89 million, excluding pre-judgment interest. Any recovery will be
flowed through to NYSEG ratepayers.
Century and OneBeacon have answered the complaints admitting issuance of the policies and receipt of notice of the claims, but asserting a number of
legal defenses. The legal discovery process is expected to close in 2016. We cannot predict the outcome of this matter.
Shareholder Derivative Action
On February 27, 2015, a complaint was filed in Connecticut state court against us, UIL, its board of directors and others related to our acquisition of
UIL. The complaint is a class action filed on behalf of all UIL shareowners. The complaint includes two counts: (a) that the UIL directors breached their
fiduciary duties by failing to engage in an appropriate process and failing to get a fair price; and (b) we aided and abetted that breach by rendering
“substantial assistance” to the UIL directors. Subsequently, four other similar complaints were filed in Connecticut. The cases have been consolidated and
transferred to the complex litigation court and the time to respond to the complaint has been extended by mutual agreement.
On October 2, 2015, the plaintiffs filed a consolidated amended complaint in the Superior Court for the Judicial District of Stamford/Norwalk,
Complex Litigation Docket. The consolidated amended complaint generally alleges that UILs directors breached their fiduciary duties by failing to
maximize shareowner value in negotiating and approving the acquisition, and that we, UIL, and/or Morgan Stanley aided and abetted the UIL Boards
alleged breaches.
On November 30, 2015, the plaintiffs and the defendants executed a binding Memorandum of Understanding, or MOU, that sets forth the terms on
which the parties have agreed to settle the consolidated action. The settlement terms do not include any change in the acquisition consideration but only
additional disclosures relating to information included in our Registration Statement on Form S-4 filed with the SEC, which was declared effective on
November 12, 2015. Under the terms of the MOU, the defendants allowed the plaintiffs to conduct some additional confirmatory discovery, which was
completed in February 2016, and agreed to negotiate in good faith in an effort to agree upon reasonable plaintiffs counsel fees, but in any event to pay the
plaintiffs’ counsel fees as determined by the court. The plaintiffs agreed to petition the court to (1) certify the shareholder class, (2) approve the terms of the
settlement, (3) decide the amount of attorneys’ fees to be awarded to plaintiffs’ counsel, and (4) dismiss the consolidated action.
Avangrid Renewables, LLC and Northern Indiana Public Service Company
Renewables has a contractual dispute with the Northern Indiana Public Service Company, or NIPSCO, concerning the interpretation of two November
2007 PPAs, entered into between two subsidiaries of Renewables and NIPSCO. Renewables and NIPSCO disagree regarding how, if at all, NIPSCO's response
to a March 2013 change in the regulations of the Midcontinent Independent System Operator, or MISO, which administers the energy markets in which
NIPSCO participates, affects their rights and obligations under the PPAs. Because of the disagreement, NIPSCO has refused to pay, and denied any obligation
to pay, certain invoices Renewables’ affiliates have issued to NIPSCO. These invoices seek compensation for periods during which Renewables’ affiliates’
power plants were not permitted to produce power as a result of NIPSCO's bids submitted under the new MISO regulations.
To resolve this dispute, on July 25, 2013, Renewables filed a complaint against NIPSCO in the Federal District Court for the Northern District of
Illinois. Fact discovery and expert discovery in that action is complete. The parties to the dispute are seeking dismissal of the case through summary
judgment. The court is expected to rule on the summary judgment motions in early 2016. No trial date has been set. We cannot predict the ultimate outcome
of this matter.
41
California Energy Crisis Litigation
Public Utilities Commission of the State of California v. Sellers of Long Term Contracts to the California Department of Water Resources (Federal
Energy Regulatory Commission, Docket Nos. EL02-60-000 and EL02-62-000)
Two California agencies brought a complaint against a long-term power purchase agreement entered into by Renewables as seller to the California
Department of Water Resources as purchaser, alleging that the terms and conditions of the power purchase agreement were unjust and unreasonable. FERC
dismissed Renewables from the proceedings; however, the Ninth Circuit Court of Appeals reversed FERC's dismissal of Renewables.
Joining with two other parties, Renewables filed a petition for certiorari in the United States Supreme Court on May 3, 2007. In an order entered on
June 27, 2008, the Supreme Court granted Renewables’ petition for certiorari, vacated the appellate court's judgment, and remanded the case to the appellate
court for further consideration in light of the Supreme Courts decision in a similar case. In light of the Supreme Court's order, on December 4, 2008, the
Ninth Circuit Court of Appeals vacated its prior opinion and remanded the complaint proceedings to the FERC for further proceedings consistent with the
Supreme Court's rulings. The parties have filed pleadings in the remand proceedings to determine the procedural framework for proceeding with the
remanded cases, including whether additional discovery and/or evidentiary hearings will be required. Following discovery, the FERC Trial Staff
recommended that the complaint against Renewables be dismissed.
A hearing was held before an administrative law judge of FERC in November and Early December 2015. A preliminary proposed ruling by the
administrative law judge is expected in April 2016. We cannot predict the outcome of this proceeding.
Yankee Nuclear Spent Fuel Disposal Claim
CMP and UI are stockholders in Connecticut Yankee Atomic Power Company and CMP is a stockholder in Maine Yankee Atomic Power Company
and Yankee Atomic Energy Corporation, (collectively, the Yankee Companies). The Yankee Companies have completed the physical decommissioning of
their respective generation facilities and are now engaged in the long-term storage of their spent nuclear fuel. Beginning in 1998 and every 6 years, in
accordance with the relevant statute of limitations, the Yankee Companies file a lawsuit to recover damages from the DOE for breach of the Nuclear Spent
Fuel Disposal Contract to remove Spent Nuclear Fuel, or SNF, as required by contract and the Nuclear Waste Policy Act beginning in 1998. The damages are
the incremental costs for the government’s failure to take the spent nuclear fuel.
In 2012, the U.S. Court of Appeals issued a favorable decision in the Yankee Companies’ claim for the first 6 year period (Phase I). Total damages
awarded to the Yankee Companies were nearly $160 million. CMPs share of the award was approximately $36.5 million and UIs share was approximately
$3.8 million. The Federal Appeals Court affirmed the September 2010 U.S. Court of Federal Claims award of $40.3 million to Connecticut Yankee Atomic
Power Company; affirmed the Court of Federal Claims award of $65 million to Maine Yankee Atomic Power Company; and increased Yankee Atomic
Electric Companys damages award from $21.4 million to $37.8 million. The Phase I damage award became final on December 4, 2012. The Yankee
Companies received payment from DOE in January 2013.
In November 2013 the U.S. Court of Claims issued its decision in the Phase II case (the second 6 year period). The Trial Court decision awarded the
Yankee companies a combined $235.4 million (Connecticut Yankee $126.3 million, Maine Yankee $37.7 million, and Yankee Atomic $73.3 million). The
damage awards flow through the Yankee Companies to shareholders to reduce retail customer charges. In January 2014 the DOE informed the Yankee
Companies it would not appeal the Trial Court decision, as a result the Yankee Companies received full payment in April 2014.
In August 2013, the Yankee Companies filed a third round of claims against the DOE seeking damages for the years 2009-2014 (Phase III). The Phase
III trial was completed in July 2015 and the Court issued its decision on March 25, 2016 awarding the Yankee companies a combined $76.8 million
(Connecticut Yankee $32.6 million, Maine Yankee $24.6 million and Yankee Atomic $19.6 million). The damage awards will potentially flow through the
Yankee Companies to shareholders, including CMP and UI, upon FERC approval, and will reduce retail customer charges or otherwise as specified by law.
CMP and UI will receive their proportionate share of the awards based on percentage ownership. We cannot predict the timing or amount of damage awards
that may ultimately flow through to shareholders.
English Station
In January 2012, Evergreen Power, LLC and Asnat Realty LLC, then and current owners of a former generation site on the Mill River in New Haven,
the English Station site, that UI sold to Quinnipiac Energy in 2000, filed a lawsuit in federal district court in Connecticut against UI seeking, among other
things: (i) an order directing UI to reimburse the plaintiffs for costs they have incurred
42
and will incur for the testing, investigation and remediation of hazardous substances at the English Station site and (ii) an order directing UI to investigate
and remediate the site. In December 2013, Evergreen and Asnat filed a subsequent lawsuit in Connecticut state court seeking among other things: (i)
remediation of the property; (ii) reimbursement of remediation costs; (iii) termination of UIs easement rights; (iv) reimbursement for costs associated with
securing the property; and (v) punitive damages. These proceedings have been stayed pending the disposition of the proposed partial consent order
described below.
On April 8, 2013, DEEP issued an administrative order addressed to UI, Evergreen Power, Asnat and others, ordering the parties to take certain actions
related to investigating and remediating the English Station site. Mediation of the matter began in the fourth quarter of 2013 and concluded unsuccessfully
in April of 2015. These proceedings have been stayed pending the disposition of the proposed partial consent order described below.
On September 16, 2015, in connection with the merger of UIL and AVANGRID, UI signed a proposed partial consent order that, when issued by the
Commissioner of DEEP and subject to the terms and conditions in the proposed partial consent order, would require UI to investigate and remediate certain
environmental conditions within the perimeter of the English Station site. Under the proposed partial consent order, to the extent that the cost of this
investigation and remediation is less than $30 million, UI will remit to the State of Connecticut the difference between such cost and $30 million to be used
for a public purpose as determined in the discretion of the Governor of the State of Connecticut, the Attorney General of the State of Connecticut, and the
Commissioner of DEEP. Pursuant to the proposed partial consent order, upon its issuance and subject to its terms and conditions, UI would be obligated to
comply with the proposed partial consent order, even if the cost of such compliance exceeds $30 million. The State will discuss options with UI on
recovering or funding any cost above $30 million such as through public funding or recovery from third parties, however it is not bound to agree to or
support any means of recovery or funding. On September 30, 2015, the hearing officer in DEEPs administrative proceeding approved a motion for stay of
further proceedings filed by DEEP, staying all proceedings on the administrative order for 120 days, subsequently extended by DEEP until a status
conference scheduled for May 11, 2016.
Other Legal Proceedings
We have included descriptions of the regulatory environment and environmental, health and safety inItem 1. Business,” general information about
several significant risks in “Item 1A. Risk Factorsand other legal proceedings that we believe could be material to us in Note 13 of our audited combined
and consolidated financial statements for the three years ended December 31, 2015, which are incorporated herein by reference.
Item 4. Mine Safety Disclosures.
Not Applicable.
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Executive Officers of AVANGRID
The names and ages of all executive officers of AVANGRID as of April 1, 2016 and a brief account of the business experience during the past five
years of each executive officer are as follows:
Name Age* Title
James P. Torgerson 63 Chief Executive Officer
Richard J. Nicholas 60 Senior Vice President – Chief Financial Officer
Daniel Alcain 42 Senior Vice President – Controller
Frank Burkhartsmeyer 51 Chief Executive Officer of Renewables
Sara J. Burns 60 President and Chief Executive Officer of CMP
Sheila Duncan 51 Senior Vice President – Human Resources & Corporate Administration
Ignacio Estella 46 Senior Vice President – Corporate Development
Daryl W. Gee 52 Chief Executive Officer of Gas
Robert D. Kump 54 President and Chief Executive Officer of Networks
Mark S. Lynch 62 President and Chief Executive Officer of NYSEG and RGE
R. Scott Mahoney 50 Senior Vice President – General Counsel and Chief Compliance Officer; Secretary
John J. Prete 58 President and Chief Executive Officer of UIL
(*) Age as of December 31, 2015.
James P. Torgerson. Mr. Torgerson was appointed Chief Executive Officer of AVANGRID on December 16, 2015 upon completion of the acquisition
of UIL. Previously, Mr. Torgerson served as President and Chief Executive Officer of UIL since 2006. Prior to 2006, Mr. Torgerson was President and Chief
Executive Officer of MISO. He is a Trustee of the Yale-New Haven Hospital and a Director of Yale New Haven Health System. Mr. Torgerson is the Chairman
of the Connecticut Institute for the 21st Century. He is the former Chairman and a Director of the Connecticut Business and Industry Association and is a
member of the board of the Edison Electric Institute and the American Gas Association. Mr. Torgerson is a Trustee of the Catholic Cemetery Association,
Archdiocese of Hartford and a member of the Fairfield Business Council. Mr. Torgerson holds a bachelor’s of business administration degree in accounting
from Cleveland State University.
Richard J. Nicholas. Mr. Nicholas was appointed Chief Financial Officer of AVANGRID on December 17, 2015 upon completion of the acquisition of
UIL. Previously, Mr. Nicholas served as Executive Vice President and Chief Financial Officer of two subsidiaries of AVANGRID, UIL and UI, from March
2005 until December 2015. Effective November 16, 2010, Mr. Nicholas was appointed Chief Financial Officer of Berkshire, CNG and SCG, all of which are
subsidiaries of AVANGRID. Mr. Nicholas earned his undergraduate degree from Duquesne University and holds a M.B.A. from the University of New Haven.
Daniel Alcain. Mr. Alcain was appointed Senior Vice President Controller of AVANGRID on December 17, 2015. Previously, Mr. Alcain was Chief
Financial Officer of Scottish Power, from April 2012 until December 2015, and Iberdrola USA, Inc., from December 2009 until March 2012. Mr. Alcain joined
the Iberdrola Group in 2001 and worked for four years in Latin America within the Control area. He holds two degrees in Economy and Law from the
University of Valladolid.
Frank Burkhartsmeyer. Mr. Burkhartsmeyer was appointed Chief Executive Officer of Renewables in April 2015. Mr. Burkhartsmeyer previously
served as Senior Vice President of Finance of ARHI from July 2012 until March 2015 and as Vice President of Strategy, Planning and Market Fundamentals
at Renewables from July 2006 until June 2012, both subsidiaries of AVANGRID. He also served as Managing Director of Corporate Strategy of Scottish
Power between June 2004 and September 2005. Mr. Burkhartsmeyer earned a B.A. from the University of Montana and a M.B.A. from the University of
Oregon.
Sara J. Burns. Ms. Burns was appointed President and Chief Executive Officer of CMP in 2005. She has served as President of CMP since 1998. Ms.
Burns is the Chairman of the Board of Directors of Maine & Company and serves on the Board of Directors of the Mitchell Institute and the Maine State
Chamber of Commerce. She holds a B.A. in Political Science and Government from Colby College.
Sheila Duncan. Ms. Duncan was appointed Senior Vice President Human Resources & Corporate Administration of AVANGRID on December 17,
2015. She previously served as Human Resources and Shared Services Director of Scottish Power from March 2009 until December 2015. Ms. Duncan
currently serves on the Board of the Scottish Huntingtons Association. She holds a Master of Arts (Hons) from the University of Glasgow and is a Chartered
Fellow of the Institute of Personnel & Development in the UK.
44
Ignacio Estella. Mr. Estella was appointed Senior Vice President Corporate Development of AVANGRID on December 17, 2015. Previously, Mr.
Estella served as Corporate Vice President of Business Origination of Iberdrola, S.A from May 2009 until November 2013 and Vice President Corporate
Development of Iberdrola USA, Inc., from December 2013 to December 16, 2015. He served as Gas Markets Development Director of Iberdrola, S.A. between
February 2007 and April 2009. Mr. Estella holds a degree in Law and Business Administration from the Universidad Pontificia Comillas and a Master of
Public Adminstration, with concentration in Regulation and Industry Analysis and Negotiation and Conflict Resolution from Harvard University.
Daryl W. Gee. Mr. Gee was appointed Chief Executive Officer of Gas in May, 2014. He has also served as Chief Executive Officer and President of
Enstor Energy Services LLC and Enstor, Inc. since 2014, both subsidiaries of AVANGRID. Previously, Mr. Gee served as Chief Compliance Officer and Vice
President of Gas, Enstor Energy Services LLC and Enstor, Inc. between March, 2013 and May, 2014. From 2002 through March 2013, Mr. Gee served as
Director of Regulatory Affairs and Director of Business Development for Enstor, Inc. Mr. Gee holds a Bachelor of Applied Arts and Sciences in Petroleum
Land Management /Petroleum Technology and Marketing from the Stephen F. Austin State University.
Robert D. Kump. Mr. Kump was appointed Chief Executive Officer of Networks in November 2010. Mr. Kump was appointed as AVANGRID’s Chief
Corporate Officer in January 2014. Mr. Kump also has served as a Director of AVANGRIDs subsidiaries CMP, NYSEG, and RGE since 2009, as the President
of the Avangrid Management Company, LLC since March 2012 and as the Chief Executive Officer of AVANGRID Service Company since October 2009.
Mr. Kump held various positions from February 1997 to October 2009 as AVANGRID’s Senior Vice President and Chief Financial Officer, Vice President,
Controller and Chief Accounting Officer, Treasurer and Secretary. Mr. Kump also previously held a number of positions at NYSEG from 1986 to 1997,
including Senior Accountant-External Financial Reporting, Director-Investor Relations, Director-Financial Services, and Treasurer. Mr. Kump earned a B.A.
in accounting from Binghamton University and is a C.P.A. in New York.
Mark S. Lynch. Mr. Lynch was appointed President of NYSEG and RGE in January 2010 and Chief Executive Officer in January, 2014. Mr. Lynch
has served as President of NYSEG and RGE since 2009, both subsidiaries of AVANGRID. Mr. Lynch also served as President and CEO of NYISO from 2005
to 2008. Mr. Lynch earned a Bachelor of Electrical Engineering from Villanova University.
R. Scott Mahoney. Mr. Mahoney was appointed Senior Vice President – General Counsel and Chief Compliance Officer of AVANGRID on December
17, 2015. He was appointed Secretary of AVANGRID on January 27, 2016 and is currently Vice President-General Counsel and Secretary of Networks. Mr.
Mahoney has served as AVANGRID’s General Counsel since June 2012. Mr. Mahoney previously served as Deputy General Counsel and Chief FERC
Compliance Officer for AVANGRID from January 2007 to June 2012 and previously served in legal and senior executive positions at AVANGRID
subsidiaries from October 1996 until January 2007. Mr. Mahoney also serves on the Board of Directors of the Gulf of Maine Research Institute. Mr. Mahoney
earned a B.A. from St. Lawrence University, a J.D. from the University of Maine, a Master’s Degree in Environmental Law from the Vermont Law School, and
a Postgraduate Diploma in Business Administration from the University of Warwick. He has received bar admission to the State of Maine, the State of New
York, the U.S. Court of Appeals, the U.S. District Court and the U.S. Court of Military Appeals.
John J. Prete. Mr. Prete was appointed President and Chief Executive Officer of UIL on December 17, 2015. Mr. Prete previously served as Senior
Vice President Electric Operations of UIL since May 2013 and currently serves as Senior Vice President and Chief Operating Officer of UI, a subsidiary of
AVANGRID. Previously, Mr. Prete served as Vice President of Technical Services of UIL and Senior Vice President – Electric Transmission and Distribution
of UI, from November 16, 2010 through May 2013, and Vice President Transmission Business of UI from October 1, 2007 through November 2010. Mr.
Prete holds a Bachelor’s Degree from the University of Bridgeport and an Associate’s Degree from the University of New Haven.
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PARTII
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market Information and Holders
Our common stock started trading on the New York Stock Exchange, or NYSE, on December 17, 2015 under the symbol “AGR.” Prior to that time,
there was no public market for our common stock. The following table sets forth on a per share basis, for the periods indicated, the high and low sale prices of
our common stock as reported by the NYSE.
Year Ended December 31, 2015 High Low
Fourth quarter (beginning December 17, 2015) $ 38.90 $ 32.45
As of March 28, 2016, there were 3,210 shareholders of record.
Dividends
AVANGRID expects to follow policy of paying quarterly cash dividends, although there is no assurance as to the amount of future dividends which
depends on future earnings, capital requirements, and financial condition.
Further information regarding payment of dividends is provided in Item 7. Managements Discussion and Analysis of Financial Condition and
Results of Operations” of this Form 10-K.
Performance Graph
The line graph appearing below compares the change in AVANGRIDs total shareowner return on its common stock with the return on the S&P
Composite-500 Stock Index, the S&P Electric Utilities Index and the S&P Utilities Index for the period December 17, 2015 through December 31, 2015.
December 17, 2015 December 31, 2015
AVANGRID $ 100 $ 106.30
S&P 500 $ 100 $ 100.70
S&P Electric Utilities Index $ 100 $ 100.50
S&P Utilities Index $ 100 $ 100.10
The above information assumes that the value of the investment in AVANGRID’s common stock and each index was $100 on December 17, 2015. No
dividends were reinvested during this time period. The changes displayed are not necessarily indicative of future returns.
46
Recent Sales of Unregistered Securities
None.
Issuer Repurchases of Equity Securities
None.
Equity Compensation Plan Information
For information regarding securities authorized for issuance under equity compensation plans, see Part III, Item 12 of this Annual Report on Form 10-
K.
Item 6. Selected Financial Data
During the year ended December 31, 2015, we identified a correction necessary to certain depreciation and amortization expenses that were recorded
in prior periods. For further details, refer to Note 2 in our combined and consolidated financial statements included in this Annual Report on Form 10-K.
Accordingly, we have reflected the correction of these prior period amounts in the periods in which they originated and the following tables include our
revised selected historical combined and consolidated statements of operations and balance sheet data for the years ended December 31, 2013 and 2012 and
as of December 31, 2014 and 2013, respectively.
Year Ended December 31,
(millions, except per share data)
Consolidated and Combined Statements of Operations Data: * 2015 2014 2013 2012 2011
Operating Revenues $ 4,367 $ 4,594 $ 4,313 $ 4,055 $ 4,761
Operating Income From Continuing Operations 513 885 179 262 72
Income (Loss) Before Income Tax 301 706 (15) 60 (257 )
Income tax expense (benefit) 34 282 35 (117 ) (213 )
Net Income (Loss) From Continuing Operations 267 424 (50 ) 177 (44)
Net Income From Discontinued Operations 74 4
Net Income (Loss) 267 424 (50) 251 (40 )
Less: Net income attributable to noncontrolling interests 1 1 2
Net Income (Loss) Attributable to AVANGRID, Inc. 267 424 (51 ) 250 (42 )
Earnings (Loss) Per Common Share,
Basic and Diluted:
Earnings (loss) from continuing operations per
common share, basic and diluted 1.05 1.68 (0.20) 0.69 (0.18)
Earnings (loss) from discontinued operations
per common share, basic and diluted 0.30 0.02
Total Earnings (Loss) Per Common
Share, Basic and Diluted $ 1.05 $ 1.68 $ (0.20) $ 0.99 $ (0.16)
Weighted-average Number of Common
Shares Outstanding:
Basic 254,588,212 252,235,232 252,235,232 252,235,232 252,235,232
Diluted 254,605,111 252,235,232 252,235,232 252,235,232 252,235,232
Consolidated and Combined Balance Sheet Data:* (millions)
As of December 31, 2015 2014 2013 2012 2011
(Millions)
Total Property, Plant and Equipment 20,711 17,133 16,715 16,643 16,618
Total Other Assets 3,795 2,075 2,137 2,376 2,401
Total Assets $ 30,743 $ 24,162 $ 23,170 $ 23,671 $ 23,915
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(millions)
As of December 31, 2015 2014 2013 2012 2011
(Millions)
Liabilities
Current portion of debt $ 206 $ 148 $ 25 $ 354 $ 157
Non-current debt 4,530 2,489 2,669 2,780 2,876
Total Liabilities 15,677 11,685 11,119 12,323 12,809
Total Stockholder’s Equity 15,053 12,461 12,036 11,334 11,079
Total Equity $ 15,066 $ 12,477 $ 12,051 $ 11,348 $ 11,106
*Selected financial data for UIL is included from December 16, 2015.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
You should read the following discussion of our financial condition and results of operations in conjunction with the consolidated financial
statements and the notes thereto included elsewhere in this Annual Report on Form 10-K . In addition to historical consolidated financial information, the
following discussion contains forward-looking statements that reflect our plans, estimates, and beliefs. Our actual results could differ materially from those
discussed in the forward-looking statements. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this
Annual Report on Form 10-K, particularly in Part I, Item 1A, “Risk Factors.”
We are a direct, majority owned subsidiary of Iberdrola, S.A., a corporation (sociedad anima) organized under the laws of Spain, one of the world’s
leading energy companies. Our direct, wholly-owned subsidiaries include Networks, ARHI, and UIL. ARHI in turn holds subsidiaries including Renewables,
and Gas. Networks, along with UIL, owns and operates our regulated utility businesses through its subsidiaries, including electric transmission and
distribution and natural gas distribution, transportation and sales. Avangrid Service Company, a subsidiary of Networks, provides corporate and back office
services on a consolidated basis to our subsidiaries. We anticipate UIL and its subsidiaries will be moved under Networks in the first half of 2016.
Renewables operates a portfolio of renewable energy generation facilities primarily using onshore wind power and also solar, biomass and thermal
power. Gas operates our natural gas storage facilities and gas trading businesses through Enstor Energy Services LLC (gas trading) and Enstor Inc. (gas
storage).
On December 16, 2015, we completed our acquisition of UIL. In connection with the acquisition we issued 309,490,839 shares of common stock of
AVANGRID, out of which 252,234,989 shares were issued to Iberdrola, S.A. through a stock dividend accounted for as a stock split, with no change to par
value and, at par value of $0.01 per share. UIL shareowners received an aggregate of 57,255,850 shares (including those held in trust as treasury stock) and an
aggregate payment of $595 million in cash. Immediately following the completion of the acquisition, former UIL shareowners owned 18.5% of the
outstanding shares of common stock of AVANGRID, and Iberdrola, S.A. owned the remaining shares. The acquisition was accounted for as a business
combination. This method requires, among other things, that assets acquired and liabilities assumed in a business combination be recognized at their fair
values as of the acquisition date. The goodwill generated from the acquisition amounted to $1,754 million. The results of operations of UIL since the
acquisition date have been included in the 2015 consolidated results of AVANGRID. Further information regarding the accounting for the acquisition is
provided in Note 4 of our audited combined and consolidated financial statements for the three years ended December 31, 2015, which are incorporated
herein by reference. For purposes of this Item 7, all references to “Networks” include UIL and its subsidiaries, unless otherwise indicated.
Through Networks, we own electric generation, transmission and distribution companies and natural gas distribution, transportation and sales
companies in New York, Maine, Connecticut and Massachusetts, delivering electricity to approximately 2.2 million electric utility customers and delivering
natural gas to approximately 984,000 natural gas public utility customers as of December 31, 2015.
Networks, a Maine corporation, along with UIL, a Connecticut corporation, hold our regulated utility businesses, including electric transmission and
distribution and natural gas distribution, transportation and sales. Networks serves as a super-regional energy services and delivery company through eight
regulated utilities it owns directly or through UIL:
·
NYSEG: serves electric and natural gas customers across more than 40% of the upstate New York geographic area;
·
RGE: serves electric and natural gas customers within a nine-county region in western New York, centered around Rochester;
·
UI: serves electric customers in southwestern Connecticut;
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·
CMP: serves electric customers in central and southern Maine;
·
SCG: serves natural gas customers in Connecticut;
·
CNG: serves natural gas customers in Connecticut; and
·
Berkshire: serves natural gas customers in western Massachusetts
·
MNG: serves natural gas customers in several communities in central and southern Maine;
Through Renewables, we had a combined wind, solar and thermal installed capacity of 6,330 megawatts, or MW, as of December 31, 2015, including
Renewables’ share of joint projects, of which 5,643 MW was installed wind capacity. Approximately 67% of the capacity was contracted for an average
period of 9.7 years as of December 31, 2015. As the second largest wind operator in the United States based on installed capacity as of December 31, 2015,
Renewables strives to lead the transformation of the U.S. energy industry to a competitive, clean energy future. Renewables currently operates 53 wind farms
in 18 states across the United States.
Through Gas, as of December 31, 2015 we own approximately 67.5 Bcf, of net working gas storage capacity. Gas operates 53.25 Bcf of contracted or
managed natural gas storage capacity in North America through Enstor Energy Services, LLC, as of December 31, 2015.
Our operating revenues decreased by 5%, from $4.6 billion for the year ended December 31, 2014 to $4.4 billion for the year ended December 31,
2015.
The decrease in operating revenues was primarily due to a 10% decrease in revenues at Renewables primarily as a result of a reduction in output from
our renewable generation facilities, unfavorable results from power trading activities and reduced trading opportunities created by lower price volatility in
the northwest markets, decreased revenues in Gas of 123% due to unfavorable changes on mark-to-market, or MtM, derivatives, partially offset by a slight
increase in Networks’ revenues.
Net income decrease primarily related to a 20% increase in operations and maintenance at Networks as a result of higher expenses for labor, bad debt
expense, and transmission system reliability support expenses, and a 10% decrease in revenues at Renewables primarily as a result of a reduction in output
from our renewable generation facilities combined with unfavorable results from power trading activities and 123% decrease in revenues in Gas due to
adverse market price volatility on derivatives, partially offset by a 22% decrease in purchased power, natural gas and fuel used for Networks as a result of
lower gas sales volumes and rates in 2015 compared to 2014 and a slight increase in Networks’ revenues.
Adjusted earnings before interest, tax, depreciation and amortization, or adjusted EBITDA, decreased by 21% from $1.5 billion for the year ended
December 31, 2014 to $1.2 billion for the year ended December 31, 2015 primarily as a result of a 26% decrease in adjusted EBITDA at Renewables as a
result of a reduction in output from our renewable generation facilities combined with unfavorable results from power trading activities, a 263% decrease in
adjusted EBITDA in Gas due to unfavorable changes on MtM derivatives and a 3% decrease in adjusted EBTIDA at Networks as a result of an increase in
operations and maintenance and lower sales volumes and rates in 2015 compared to 2014.
See “Results of Operations” for further analysis of our operating results for the year.
Our financial condition and financing capability will be dependent on many factors, including the level of income and cash flow of its subsidiaries,
conditions in the bank and capital markets, economic conditions, interest rates and legislative and regulatory developments.
Immaterial Corrections to Prior Periods
During the year ended December 31, 2015, we identified a correction necessary to certain depreciation and amortization expenses that were recorded
in prior periods. For further details, refer to Note 2 in our combined and consolidated financial statements included in this Annual Report on Form 10-K.
Accordingly, we have reflected the correction of these prior period amounts in the periods in which they originated. “Item 7. Managements Discussion and
Analysis of Financial Condition and Results of Operations” of this Form 10-K is based on the revised financial results for the year ended December 31, 2013.
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Networks
Electric Transmission and Distribution and Natural Gas Distribution
The operating subsidiaries of Networks are regulated electric distribution and transmission and natural gas transportation and distribution utilities
whose structure and operations are significantly affected by legislation and regulation. FERC regulates, under the FPA, the interstate transmission and
wholesale sale of electricity by these regulated utilities, including transmission rates and allowed ROE. Further, the distribution rates and allowed ROEs for
Networks’ regulated utilities in New York, Maine, Connecticut and Massachusetts are subject to regulation by the NYPSC, the MPUC, PURA and DPU,
respectively. Legislation and regulatory decisions implementing legislation establish a framework for Networks’ operations. Other factors affecting Networks’
financial results are operational matters, such as the ability to manage expenses, uncollectibles and capital expenditures, in addition to major weather
disturbances and environmental regulation. Networks expects to continue to make significant capital investments in its distribution and transmission
infrastructure.
Pursuant to Maine law, CMP earns revenue for the delivery of energy to its retail customers, but is prohibited from selling power to them. CMP
generally does not enter into purchase or sales arrangements for power with ISO-NE, the New England Power Pool, or any other ISO or similar entity. CMP
generally sells all of its power entitlements under its nonutility generator and other PPAs to unrelated third parties under bilateral contracts. If the MPUC does
not approve the terms of bilateral contracts, it can direct CMP to sell power entitlements that it receives from those contracts on the spot market through ISO-
NE. NYSEG and RGE enter into power purchase and sales transactions with the NYISO to have adequate supplies for their customers who choose to purchase
energy directly from them. Customers may also choose to purchase energy from other energy supply companies.
Under Connecticut law, UIs retail electricity customers are able to choose their electricity supplier while UI remains their electric distribution
company. UI purchases power for those of its customers under standard service rates who do not choose a retail electric supplier and have a maximum demand
of less than 500 kilowatts and its customers under supplier of last resort service for those who are not eligible for standard service and who do not choose to
purchase electric generation service from a retail electric supplier. The cost of the power is a “pass-through to those customers through the generation
services charge on their bills.
UI has wholesale power supply agreements in place for its entire standard service load for the first half of 2016, 80% of its standard service load for the
second half of 2016 and for 30% of its standard service load for the first half of 2017. Supplier of last resort service is procured on a quarterly basis, however,
from time to time there are no bidders in the procurement process for supplier of last resort service and in such cases UI manages the load directly.
For additional information regarding Networks, including a comprehensive overview of our regulated businesses, please see the section entitled,
“Business—Networks.
Revenues
Networks utilizes regulatory deferrals to evaluate its financial condition and operating performance by reconciling differences between actual revenue
received or cost incurred with the rate allowances provided under the tariffs set by the state utilities commissions and FERC. Regulatory deferrals create
regulatory assets and liabilities under FERC, consistent with U.S. GAAP financial accounting standards. Regulatory deferrals in New York include electric
and gas supply costs, PPAs, downward net plant reconciliations, revenue decoupling, system benefit charges, renewable portfolio standards, energy efficiency
portfolio standards, economic development programs, low income programs, gross receipt taxes, pension costs, other post-employment benefits costs,
environmental remediation costs, major storm costs, downward adjustments for vegetation management, research and development, incremental maintenance
initiatives, property taxes and certain legislative, accounting, regulatory and tax related actions. Regulatory deferrals in Maine include stranded costs,
revenue decoupling, power tax regulatory asset, environmental remediation, storm reserve accounting, electric thermal storage pilot costs, standard offer
retainage costs, AMI opt-out program costs, AMI deferral costs, AMI legal / health proceeding costs, conservation program costs, demand side management
costs, low income program costs, Electric Lifeline Program costs, Make-Ready line extension costs, electric vehicle pilot program costs and transmission
planning and related cost allocation.
Regulatory deferrals in Connecticut include electric and gas supply costs, PPAs, revenue decoupling, system benefit charges, certain hardship bad
debt expense, transmission revenue requirements, gas distribution integrity management program costs, gas system expansion costs, certain public policy
costs, certain environmental remediation costs, major storm costs, and certain legislative, accounting, regulatory and tax related actions.
Regulatory deferrals in Massachusetts include gas supply costs, gas supply-related bad debt costs, environmental remediation costs, arrearage
management program costs, gas system enhancement program costs, energy efficiency program costs and certain other public policy costs.
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NYSEG’s and RGE’s electric and natural gas rate plans and CMPs and UI’s electric rates and CNG’s gas rates, each contain a RDM under which their
actual energy delivery revenues are compared on a periodic basis with the authorized delivery revenues and the difference accrued, with interest, for refund to
or recovery from customers, as applicable.
NYSEG, RGE and UI are energy delivery companies and provide energy supply as providers of last resort. Energy costs that are set on the wholesale
markets are passed on to consumers. The difference between actual energy costs that are incurred and those that are initially billed are reconciled in a process
that results in either immediate or deferred tariff adjustments. These procedures apply to other costs, which are in most cases exceptional, such as the effects of
extreme weather conditions, environmental factors, regulatory and accounting changes, and treatment of vulnerable customers, that are offset in the tariff
process.
Pursuant to agreements with, or decisions of the NYPSC and, the MPUC, Networks’ Maine and New York regulated utilities are each subject to a
minimum equity ratio requirement that is tied to the capital structure assumed in establishing revenue requirements. Pursuant to these requirements, each of
NYSEG, RGE, CMP and MNG must maintain a minimum equity ratio equal to the ratio in its currently effective rate plan or decision measured using a
trailing 13-month average. On a monthly basis, each utility must maintain a minimum equity ratio of no less than 300 basis points below the equity ratio
used to set rates. The minimum equity ratio requirement has the effect of limiting the amount of dividends that can be paid if the minimum equity ratio is not
maintained and can, under certain circumstances, require that AVANGRID contribute equity capital. For CMP and MNG, equity distributions that would
result in equity falling below the minimum level are prohibited. For NYSEG and RGE, equity distributions that would result in a 13-month average common
equity less than maximum equity ratio, utilized for the earnings sharing mechanism, are prohibited if the credit rating of NYSEG, RGE, AVANGRID or
Iberdrola, S.A. are downgraded by a nationally recognized rating agency to the lowest investment grade with a negative watch or downgraded to
noninvestment grade. UI, SCG, CNG and BGC may not pay dividends if paying such dividend would result in a common equity ratio lower than 300 basis
points below the equity percentage used to set rates in the most recent distribution rate proceeding as measured using a trailing 13-month average calculated
as of the most recent quarter end. In addition, UI, SCG, CNG and BGC are prohibited from paying dividend to their parent if the utilitys credit rating as rated
by any of the three major credit rating agencies, falls below investment grade, or if the utilitys credit rating, as determined by two of the three major credit
rating agencies falls to the lowest investment grade and there is a negative watch or review downgrade notice. We believe that these minimum equity ratio
requirements do not present any material risk with respect to our performance, cash flow or ability to pay quarterly dividends. In the ordinary course,
Networks utilities manage their capital structures to allow the maximum level of returns consistent with the levels of equity authorized to set rates, and
accordingly, compliance with these requirements does not alter ordinary equity level management. Additionally, the lower monthly minimum equity ratio
requirement (a cushion of 300 basis points) provides flexibility to have short-term fluctuations that result in temporary shortfalls of the maximum equity ratio
in any given month. The regulated utility subsidiaries are also prohibited by regulation from lending to unregulated affiliates.
Rates
On September 17, 2009, NYSEG and RGE initiated a distribution rate case to allow the companies to recover past and future investments, provide safe
and adequate service, and improve their credit ratings. On February 19, 2016, the NYSEG, RGE and other signatory parties filed a Joint Proposal, or the
proposal, with the NYPSC for a three-year rate plan for electric and gas service at NYSEG and RGE commencing May 1, 2016. The proposal balances the
varied interests of the signatory parties including but not limited to maintaining the companies’ credit quality and mitigating the rate impacts to
customers. The proposal reflects many customer attributes including: acceleration of the companies’ natural gas leak prone main replacement programs and
enhanced electric vegetation management to provide continued safe and reliable service. The delivery rate increase in the proposal can be summarized as
follows:
May 1, 2016
May 1, 2017
May 1, 2018
Rate
Increase
Delivery
Rate
Increase
Rate
Increase
Delivery
Rate
Increase
Rate
Increase
Delivery
Rate
Increase
Utility (Millions) % (Millions) % (Millions) %
NYSEG Electric $ 29.6 4.10 % $ 29.9 4.10 % $ 30.3 4.10%
NYSEG Gas 13.1 7.30% 13.9 7.30% 14.8 7.30 %
RGE Electric 3.0 0.70% 21.6 5.00% 25.9 5.70 %
RGE Gas 8.8 5.20 % 7.7 4.40 % 9.5 5.20%
The allowed rate of return on common equity for NYSEG Electric, NYSEG Gas, RGE Electric and RGE Gas is 9.00%. The equity ratio for each
company is 48%. The proposal includes an ESM applicable to each company. The customer share of earnings would increase at higher earnings levels, with
customers receiving 50%, 75% and 90% of earnings over 9.5%, 10.0% and 10.5% of ROE, respectively, in the first year. Earnings thresholds would increase
in subsequent years. The proposal reflects the recovery of deferred NYSEG Electric storm costs of approximately $262 million, of which $123 million will be
amortized over ten years and the
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remaining $139 million will be amortized over five years. The proposal also continues reserve accounting for qualifying Major Storms ($21.4 million
annually for NYSEG Electric and $2.5 million annually for RGE Electric). Incremental maintenance costs incurred to restore service in qualifying divisions
will be chargeable to the Major Storm Reserve provided they meet certain thresholds. The administrative law judges assigned to the New York rate case will
issue a procedural schedule establishing the remaining procedure for review and decision on the proposal. We expect hearings on the proposal to be held in
April 2016 and a NYPSC decision to be made in May 2016.
On August 25, 2014, the MPUC approved a stipulation agreement for a CMP rate change which provided for a distribution rate increase of
approximately $24.3 million effective July 1, 2014 with an allowed ROE of 9.45% and an allowed equity ratio of 50%. On December 22, 2009, MPUC
approved a stipulation which provided for a rate increase to MNGs base distribution rates for a three year period, with a 12% increase effective January 1,
2010, a 10% increase effective December 1, 2010 and another 10% increase effective December 1, 2011.
On March 5, 2015, MNG filed a rate case in order to further recover future investments and provide safe and adequate service. MNG requested a
10.0% ROE and 50% equity ratio. The MPUC Staff has recommended a separate revenue requirement for MNGs Augusta customers and MNG’s non-
Augusta customers. Staff has recommended a $19.95 million disallowance of the Augusta Expansion investment based upon the Staffs conclusion that
MNG’s management of the Augusta Expansion Project was imprudent. On November 6, 2015, a stipulation was filed with the MPUC, which was executed by
MNG, the Office of Public Advocate and the City of Augusta. The stipulation contained a combined revenue requirement for Augusta and Non-Augusta
based on a 9.55% ROE and 50% equity ratio. The stipulation also provided for an initial Augusta investment disallowance of $6 million and an investment
phase-in of $10 million. On December 22, 2015, MPUC rejected the proposed Stipulation as not in the public interest. In January 2016, the administrative
law judge established a new litigation schedule. The litigation was suspended at the end of January 2016 for settlement discussions. We cannot predict the
outcome of the proceeding. We reserved $6 million for this case at the end of 2015.
In August 2013, PURA approved distribution rate schedules for UI for two years that became effective at that time and which, among other things,
increased the UI distribution allowed ROE from 8.75% to 9.15%, continued UIs existing earnings sharing mechanism, continued the existing decoupling
mechanism, and approved the establishment of the requested storm reserve. In accordance with the approval by PURA of the acquisition, UI agreed not to file
a rate case for new rates effective before January 1, 2017.
On January 22, 2014, PURA approved base delivery rates for CNG, with an effective date of January 10, 2014, which, among other things, approved an
allowed ROE of 9.18%, a decoupling mechanism, two separate ratemaking mechanisms that reconcile actual revenue requirements related to CNG’s cast iron
and bare steel replacement program and system expansion and an earnings sharing mechanism by which CNG and customers share on a 50/50 basis all
earnings above the allowed ROE in a calendar year. In accordance with the approval by PURA of the acquisition, SCG and CNG agreed not to file a rate case
for new rates effective before January 1, 2018.
Berkshire’s rates are established by the DPU. Berkshires 10-year rate plan, which was approved by the DPU and included an approved ROE of 10.5%,
expired on January 31, 2012. Berkshire continues to charge the rates that were in effect at the end of the rate plan. In accordance with the approval by the
DPU of the acquisition, Berkshire agreed not to file a rate case for new rates effective before June 1, 2018.
CMP’s and UI’s electric transmission rates are determined by a tariff regulated by FERC and administered by ISO-NE. Transmission rates are set
annually pursuant to a FERC authorized formula that allows for recovery of direct and allocated transmission operating and maintenance expenses, including
return of and on investment in assets. FERC currently provides an initial base ROE of 10.57% and additional incentive adders applicable to assets based
upon vintage, voltage, and other factors.
In September 2011, several New England governmental entities, including PURA, the Connecticut Attorney General and the OCC, filed a joint
complaint with FERC against ISO-NE and several New England transmission owners (including CMP and UI) claiming that the current approved base ROE
used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by the New England transmission owners of
11.14% was not just and reasonable and seeking a reduction of the base ROE with refunds to customers for the refund period of October 1, 2011 through
December 31, 2012, or the refund period. FERC issued an order in 2014 to reset the base ROE at 10.57% and capped the incentive rate at 11.74% for
applicable projects for the refund period. Two additional complaints have also been filed for subsequent periods. The complaints have been consolidated and
the administrative law judge issued an initial decision on March 22, 2016. The initial decision determined that, 1) for the 15 month refund period in the
second complaint, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and 2) for the 15 month refund
period in the third complaint and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19%. The initial decision is the
administrative law judge’s recommendation to the FERC Commissioners. The
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FERC is expected to make its final decision in late 2016 or early 2017. The results of the decision in the initial complaint, as well as the results of any future
decisions, will be reconciled in future transmission rates.
On December 28, 2015, the FERC issued an order instituting section 206 proceedings and establishing hearing and settlement judge
procedures. Pursuant to section 206 of the FPA, the FERC found that ISO-NE Transmission, Markets, and Services Tariff is unjust, unreasonable, and unduly
discriminatory or preferential. FERC stated that ISO-NE’s Tariff lacks adequate transparency and challenge procedures with regard to the formula rates for
ISO-NE Participating Transmission Owners, including UI and CMP. FERC also found that the current RNS and LNS formula rates appear to be unjust,
unreasonable, unduly discriminatory or preferential, or otherwise unlawful as the formula rates appear to lack sufficient detail in order to determine how
certain costs are derived and recovered in the formula rates.
Merger Settlement Agreement – Connecticut and Massachusetts
As part of the process of seeking and obtaining regulatory approval of the acquisition in Connecticut and Massachusetts, AVANGRID and UIL
reached settlement agreements with the Office of Consumer Counsel, or OCC, in Connecticut and with the Attorney General of the Commonwealth of
Massachusetts and the Department of Energy Resources in Massachusetts, which settlement agreements included commitments of actions to be taken after
the transaction closed.
As a result, the following commitments have been made in Connecticut:
·
A one-time, $20 million rate credit to customers in 2016, allocated among UI, SCG and CNG customers based on the total number of retail
customers.
·
Additional rate credits of $1.25 million/year for ten years (2018-2027) to CNG customers.
·
Additional rate credits of $0.75 million/year for ten years (2018-2027) to SCG customers.
·
$1.6 million in savings to SCG customers, associated with SCG making additional infrastructure capital investments over a three-year period
without seeking recovery until the next SCG rate case.
·
Agreement not to seek to increase UI distribution base rates effective before January 1, 2017, and agreement not to seek to increase CNG and
SCG distribution base rates effective before January 1, 2018.
·
Contribution of $2 million/year for three years to the DEEP, to stimulate investment in energy efficiency and clean energy technologies.
·
$5 million in benefits to customers resulting from UI recovering only the debt rate rather than the equity return for two years, on an increased
$50 million of investment in storm resiliency programs.
·
Contribution of $1 million for disaster relief entities.
·
Maintaining charitable contribution at historical contribution levels (between $500,000 and $800,000) for at least four years.
·
Upon the resolution of all appeals of the PURA decision approving the acquisition, UI will withdraw its appeals of two PURA dockets relating
to PURA’s disallowance of certain reconciliation amounts.
In connection with the acquisition proceeding, UI signed a proposed partial consent order, or the consent order that, when approved by the
Commissioner of DEEP, and pursuant to the terms and conditions in the consent order, would require UI to investigate and remediate certain environmental
conditions within the perimeter of the English Station site. To the extent that the investigation and remediation is less than $30 million, UI would remit to
the State of Connecticut the difference between such costs and $30 million for a public purpose as determined in the discretion of the Governor the Attorney
General of Connecticut and the Commissioner of DEEP. Pursuant to the consent order, upon its issuance and subject to its terms and conditions, UI would be
obligated to comply with the consent order, even if the cost of such compliance exceeds $30 million. The State will discuss options with UI on recovering or
funding any cost above $30 million such as through public funding or recovery from third parties, however it is not bound to agree to or support any means
of recovery or funding.
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The following commitments have been made in Massachusetts:
·
Customers of Berkshire will receive a total of $4.0 million in rate credits, to be spread over the months of November through April 2016-2017
and November through April 2017-2018.
·
Berkshire will contribute $1 million to alternative heating programs.
·
Berkshire will not seek to increase distribution base rates effective before June 1, 2018.
As a result of the merger settlement agreement we have recorded $44 million as regulatory liabilities relating to the rate credits and an additional
$19.8 million as liabilities.
New England Clean Energy Request for Proposals
The DEEP, Eversource Energy, National Grid and Unitil conducted a Request for Proposals, or RFP, for Clean Energy and Transmission in order to
identify projects that will advance the clean energy goals of Connecticut, Massachusetts and Rhode Island. The RFP was issued in November 2015, and bids
were received on January 28, 2016. AVANGRID companies have offered two transmission projects and three wind projects as components of various joint
bids with other parties. The bids are currently under review by an evaluation team that is expected to select winning bids by the end of July 2016. Any
contracts negotiated with chosen projects would require regulatory approvals in the contracting utilities’ states and the projects will need various regulatory
and permitting approvals, including FERC approval for transmission tariffs.
Reforming the Energy Vision
In April 2014, the NYPSC instituted its REV proceeding, the goals of which are to improve electric system efficiency and reliability, encourage
renewable energy resources, support DER, and empower customer choice. In this proceeding, the NYPSC is examining the establishment of a DSP, to manage
and coordinate DER, and provide customers with market data and tools to manage their energy use. The NYPSC is also examining how its regulatory
practices should be modified to incentivize utility practices to promote REV objectives. REV has been divided into two tracks, Track 1 for market design and
technology, and Track 2 for regulatory reform. REV proposes regulatory changes that are intended to promote more efficient use of energy, deeper
penetration of renewable energy resources such as wind and solar, and wider deployment of DER, such as micro grids, on-site power supplies and storage. The
NYPSC Order on Track 1 affirmed that utilities would serve as the DSP and required utilities to file implementation plans before the end of 2015. Track 2 is
undertaken in parallel with the Track 1, and examines changes in current regulatory, tariff, and market designs, and incentive structures to better align utility
interests with achieving NYPSCs policy objectives. The NYPSC staff Whitepaper for Track 2 was issued in the third quarter of 2015. New York utilities will
also be addressing related regulatory issues in their individual rate cases. We expect an Order by the end of the second quarter of 2016.
Ginna Reliability Support Service Agreement
Ginna Nuclear Power Plant, LLC, or GNPP, which is a subsidiary of Constellation Energy Nuclear Group, LLC, or CENG, owns and operates the R.E.
Ginna Nuclear Power Plant, or Ginna Facility, and together with GNPP, Ginna, a 581 MW single-unit pressurized water reactor located in Ontario, New
York. In May 2014, NYISO produced a Reliability Study, confirming that the Ginna Facility needs to remain in operation to avoid bulk transmission and
non-bulk local distribution system reliability violations in 2015 and 2018.
On July 11, 2014, GNPP filed a petition requesting that the NYPSC initiate a proceeding to examine a proposal for the continued operation of the
Ginna Facility. Ginna asserted that in the two preceding calendar years, 2012 and 2013, it had sustained cumulative losses at the Facility of nearly $100
million (including the allocation of CENG corporate overhead)” and that “CENG has not been compensated for any operational risk or an appropriate return
on its investment over this period.” Based on the results of the 2014 Reliability Study, GNPP requested that: 1) the NYPSC determine that the continued
operation of the Ginna Facility is required to preserve system reliability; and 2) the NYPSC issue an Order directing RGE to negotiate and file a Reliability
Support Services Agreement, or RSSA, for the continued operation of the Ginna Facility.
In November 2014, the NYPSC ruled that GNPP had demonstrated that the Ginna Facility is required to maintain system reliability and that its actions
with respect to meeting the relevant retirement notice requirements were satisfactory. The NYPSC also accepted the findings of the 2014 Reliability Study
and stated that it established “the reliability need for continued operation of the Ginna Facility that is the essential prerequisite to negotiating an RSSA.” As
such, the NYPSC ordered RGE and GNPP to negotiate an RSSA.
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On February 13, 2015, RGE submitted to the NYPSC an executed RSSA between RGE and GNPP. RGE requested that the NYPSC accept the RSSA
and approve cost recovery by RGE from its customers of all amounts payable to GNPP under the RSSA utilizing the cost recovery surcharge mechanism.
On October 21, 2015, RGE, GNPP, New York Department of Public Service, Utility Intervention Unit and Multiple Intervenors filed a Joint Proposal
with the NYPSC for approval of the RSSA, as modified. The Joint Proposal provides a term of the RSSA from April 1, 2015 through March 31, 2017. RGE
shall make monthly payments to Ginna in the amount of $15.4 million. RGE will be entitled to 70% of revenues from Ginnas sales into the NYISO energy
and capacity markets, while Ginna will be entitled to 30% of such revenues. The signatory parties recommend that the NYPSC authorize RGE to implement a
rate surcharge effective January 1, 2016 to recover amounts paid to Ginna pursuant to the RSSA. RGE's payment obligation to Ginna shall not begin until the
rate surcharge is in effect and FERC has issued an order authorizing the FERC Settlement agreement in the Settlement Docket. RGE will use deferred rate
credit amounts (regulatory liabilities) to offset the full amount of the Deferred Collection Amount (including carrying costs), plus credit amounts to offset all
RSSA costs that exceed $2.3 million per month, not to exceed a total use of credits in the amount of $110 million, applicable through June 30, 2017. To the
extent that the available credits are insufficient to satisfy the final payment from RGE to Ginna then the RSSA surcharge may continue past March 31, 2017
to recover up to $2.3 million per month until the final payment has been recovered by RGE from ratepayers. In the month following the expiration of the term
on March 31, 2017, Ginna shall prepare and issue an invoice to RGE for, and RGE shall pay to Ginna, a one-time payment in the amount of $11.5 million.
This amount is being accrued pro-rata over the term of the agreement and will be recovered from ratepayers. On February 23, 2016, the NYPSC unanimously
adopted the Joint Proposal in the Ginna RSSA proceeding as in the public interest. On March 1, 2016, FERC issued an order approving the contested
Settlement agreement, subject to conditions.
New York Transco
Networks holds an approximately 20% ownership interest in the New York Transco. The New York Transco was established by the New York
transmission utilities to develop, own, and operate electric transmission in New York. In December 2014, New York Transco filed for regulatory approval of
its rates, terms, and conditions with FERC. The filing requests a formula base ROE of 10.6%, 150 basis points ROE incentives, construction work in progress,
a formula rate mechanism, and a proposed cost allocation. Various parties, including the NYPSC, have protested the filing with FERC, including the base
ROE, the ROE incentives, and the cost allocation. The New York Transco will not make final decisions on transmission project development until a FERC
decision.
On April 2, 2015, the FERC issued an order granting, inter alia, the New York Transcos owners’ request for a 50 basis point adder for NY Transco’s
membership in the NYISO RTO, subject to the adder being capped within the zone of reasonableness after a determination of where within that zone its base
level ROE should be set. The FERC also set the formula rate and base ROE issue for hearing and settlement judge procedures. In addition, the FERC rejected
the New York Transcos owners’ cost allocation method for the Transmission Owner Transmission Solutions, or TOTS, Projects because it would allocate
costs to Power Supply Long Island and New York Power Authority that they did not voluntarily agree to pay.
On November 5, 2015, the New York Transco’s owners, filed the Settlement with the FERC to resolve all outstanding issues associated with the TOTS
Projects, including issues related to the TOTS Projects that were set for hearing and issues pending on rehearing. The issues regarding certain other projects
remain pending.
Weather Impact
The demand for electric power and natural gas is affected by seasonal differences in the weather. Statewide demand for electricity in New York,
Connecticut and Maine tends to increase during the summer months to meet cooling load or in winter months for heating load while statewide demand for
natural gas tends to increase during the winter to meet heating load. Market prices for both electricity and natural gas reflect the demand for these products
and their availability at that time. Overall operating results of Networks do not fluctuate due to commodity costs as the regulated utilities generally recover
those costs coincident with their expense or defer any differences for future recovery. Networks has historically sold less power when weather conditions are
milder and may also be affected by severe weather, such as ice and snow storms, hurricanes and other natural disasters which may result in additional cost or
loss of revenues that may not be recoverable from customers. However, Networks’ regulated utilities, other than MNG, SCG and Berkshire, have approved
revenue decoupling mechanisms, or RDMs, as part of the NYPSC, PURA and MPUC rate plans. The RDM allows the regulated utilities to defer for future
recovery and shortfall from projected revenues whether due to weather, economic conditions, conservation or other factors.
New Renewable Source Generation
Under Connecticut law Public Act 11-80, or PA 11-80, Connecticut electric utilities are required to enter into long-term contracts to purchase
Connecticut Class I RECs, from renewable generators located on customer premises. Under this program, UI is
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required to enter into contracts totaling approximately $200 million in commitments over an approximate 21-year period. The obligations will phase in over
a six-year solicitation period, and are expected to peak at an annual commitment level of about $13.6 million per year after all selected projects are online.
Upon purchase, UI accounts for the RECs as inventory. UI expects to partially mitigate the cost of these contracts through the resale of the RECs. PA 11-80
provides that the remaining costs (and any benefits) of these contracts, including any gain or loss resulting from the resale of the RECs, are fully recoverable
from (or credited to) customers through electric rates. On October 23, 2013, PURA approved UIs renewable connections program filed in accordance with PA
11-80, through which UI will develop up to 10 MW of renewable generation. The costs for this program will be recovered on a cost of service basis. PURA
established a base ROE to be calculated as the greater of: (A) the current UI authorized distribution ROE (currently 9.15%) plus 25 basis points and (B) the
current authorized distribution ROE for CL&P, (currently 9.17%), less target equivalent market revenues (reflected as 25 basis points). In addition, UI will
retain a percentage of the market revenues from the project, which percentage is expected to equate to approximately 25 basis points on a levelized basis over
the life of the project. UI expects the cost of this program, a planned 2.8 MW fuel cell facility in New Haven, solar photovoltaic and fuel cell facilities
totaling 5 MW in Bridgeport, and a 2.2 MW fuel cell facility in Woodbridge, to be approximately $47 million. Pursuant to Section 8 of Public Act 13-303,
“An Act Concerning Connecticuts Clean Energy Goals, in January 2014, at the DEEP’s direction, UI entered into three contracts for the purchase of RECs
associated with an aggregate of 5.7 MW of energy production from biomass plants in New England. The costs of these agreements will be fully recoverable
through electric rates.
Under Maine law 35-A M.R.S.A §§ 3210-C, 3210-D, the MPUC is authorized to conduct periodic requests for proposals seeking long-term supplies of
energy, capacity or RECs, from qualifying resources. The MPUC is further authorized to order Maine Transmission and Distribution Utilities to enter into
contracts with sellers selected from the MPUCs competitive solicitation process. Pursuant to a MPUC Order dated October 8, 2009, CMP entered into a 20-
year agreement with Evergreen Wind Power III, LLC, on March 31, 2010, to purchase capacity and energy from Evergreens 60 MW Rollins wind farm in
Penobscot County, Maine. CMP’s purchase obligations under the Rollins contract are approximately $7 million per year. In accordance with subsequent
MPUC orders, CMP periodically auctions the purchased Rollins energy to wholesale buyers in the New England regional market. Under applicable law, CMP
is assured recovery of any differences between power purchase costs and achieved market revenues through a reconcilable component of its retail distribution
rates. Although the MPUC has conducted multiple requests for proposals under M.R.S.A §3210-C and has tentatively accepted long-term proposals from
other sellers, these selections have not yet resulted in additional currently effective contracts with CMP.
Renewables
Renewable Energy Incentives
Renewables relies, in part, upon government policies that support utility-scale renewable energy and enhance the economic feasibility of
development and operating wind energy projects in regions in which Renewables operates or plans to develop and operate renewable energy facilities. In
support of this, on December 18, 2015 Congress passed and President Obama signed into law the Consolidated Appropriations Act, Public Law 114-113.
This law includes provisions extending the qualifying dates for the Production Tax Credit available to wind energy generating facilities (Internal Revenue
Code Section 45) and the Investment Tax Credit available to commercial solar generating facilities (Internal Revenue Code Section 48). The law also
extends an option for wind generation facilities to elect to receive an Investment Tax Credit in lieu of the Production Tax Credit. In general, both provisions
allow new wind and solar facilities to qualify for the respective credits at full value over the next several years, with reductions in the value of the authorized
tax credits for facilities phased in during subsequent periods. Production tax credits will be reduced to 80% for facilities commencing construction in 2017
reduced to 60% for facilities commencing construction in 2018 and reduced to 40% for facilities commencing construction in 2019. Investment tax credits
will be 30% for projects commencing construction through 2019, then reduce to 26%, 22% and 10% for projects commencing construction in 2020, 2021
and 2022, respectively. The Internal Revenue Service, or IRS, previously issued guidance related to which projects will qualify for the production tax credits,
including criteria for the beginning of construction for a project and the continuous program of construction or the continuous efforts to advance the project
to completion. The IRS has not updated its guidance for the December 2015 extension. Multi-year extension of these credits is likely to provide
opportunities for Renewables to develop, construct, and market new renewable generating facilities in several US markets.
Additionally, the federal government and many states and local jurisdictions have policies or other mechanisms, such as tax incentives or RPS that
support the sale of energy from utility-scale renewable energy facilities, such as wind and solar energy facilities. As a result of budgetary constraints, political
factors or otherwise, U.S., state or local governments from time to time may review their policies and other mechanisms that support renewable energy and
consider actions that would make them less conducive to the development and operation of renewable energy facilities. Any reductions to, or the elimination
of, governmental policies or other mechanisms that support renewable energy or the imposition of additional taxes or other assessments on renewable energy,
could result in, among other items, the lack of a satisfactory market for the development of new renewable energy projects, Renewables abandoning the
development of new renewable energy projects, a loss of Renewables’ investments in the projects and
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reduced project returns, any of which could have a material adverse effect on Renewables’ business, financial condition, results of operations and prospects.
Renewable Energy Demand
Since the transmission and distribution of electricity is highly concentrated in most jurisdictions, there are a limited number of possible purchasers for
utility-scale quantities of electricity in a given geographic location, including transmission grid operators, state and investor-owned power companies, public
utility districts and cooperatives. As a result, there is a concentrated pool of potential buyers for electricity generated by Renewables’ business, which may
restrict their ability to negotiate favorable terms under new PPAs, and could impact their ability to find new customers for the electricity generated by their
generation facilities should this become necessary. Furthermore, if the financial condition of these utilities and/or power purchasers deteriorated or the RPS
programs, climate change programs or other regulations to which they are currently subject and that compel them to source renewable energy supplies
change, demand for electricity produced by Renewables’ businesses could be negatively impacted.
Energy Prices
Renewables has exposure to commodity price movements through its “natural” long positions in electricity from its generation. Renewables manages
the exposure to risks of commodity price movements through internal risk management policies, enforcement of established risk limits and risk management
procedures. In 2015 we began designating those derivatives contracts at Renewables that qualify as hedges. This designation was made prospectively, and in
accordance with all the requirements of hedge accounting.
Wind Conditions
If wind conditions are unfavorable, or if Renewables’ wind turbines are not available for operation, Renewables projects’ electricity generation and
related revenue may be substantially below our expectations. Renewables’ wind projects are sited, developed and operated to maximize wind performance.
Prior to siting a wind facility, detailed studies are conducted to measure the wind resource in order to estimate future production. However, wind patterns or
wind resource in the future might deviate from historical patterns. These events could also degrade equipment or components and the interconnection and
transmission facilities’ lives or maintenance costs. Historically, Renewables wind production is greater in the first, second and fourth quarters.
Wind Turbine Supply
Replacement and spare parts for wind turbines and key pieces of electrical equipment may be difficult or costly to acquire or may be unavailable.
Although Renewables has expanded and diversified its supplier base, the loss of any of these suppliers or service providers or inability to find replacement
suppliers or service providers or to purchase turbines at rates currently offered by Renewables’ existing suppliers or a change in the terms of Renewables’
supply or operations and maintenance agreements, such as increased prices for maintenance services or for spare parts, could have a material adverse effect on
Renewables’ ability to construct and maintain wind farms or the profitability of wind farm development and operation.
Gas
Gas benefits from price volatility and temporal price spreads, which impacts the level of demand for services and the rates that can be charged for
natural gas storage services. On a system-wide basis, natural gas is typically injected into storage between April and October when natural gas prices are
generally lower and withdrawn during the winter months of November through March when natural gas prices are typically higher. Largely due to the
abundant supply of natural gas made available by hydraulic fracturing techniques, natural gas prices have dropped significantly to levels that are near
historic lows. If prices and volatility remain low or declines further, then the demand for natural gas storage services, and the prices that Gas will be able to
charge for those services, may decline or be depressed for a prolonged period of time. Conversely, if prices and volatility remain high or increase then the
demand for natural gas storage services and the prices that Gas will be able to charge for these services may increase for a period of time. In 2015 we began
designating those derivatives contracts at Gas that qualify as hedges. This designation was made prospectively, and in accordance with all the requirements
of hedge accounting.
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Results of Operations
The following table sets forth our operating revenues and expenses items for each of the periods indicated and as a percentage of operating revenues:
Year Ended December 31,
(millions)
2015 % 2014 % 2013 %
Operating Revenues $ 4,367 100 % $ 4,594 100 % $ 4,313 100%
Operating Expenses
Purchased power, natural gas and fuel used 972 22 1,181 26 1,088 25
Operations and maintenance 1,808 42 1,560 34 1,541 36
Impairment of noncurrent assets 12 25 1 620 15
Depreciation and amortization 695 16 629 14 594 14
Taxes other than income taxes 367 8 314 7 291 7
Total Operating Expenses 3,854 88 3,709 81 4,134 96
Operating income 513 12 885 19 179 4
Other Income and (Expense)
Other income and (expense) 55 1 52 1 54 1
Earnings (losses) from equity method investments 12 (3)
Interest expense, net of capitalization (267 ) (6 ) (243 ) (5 ) (245 ) (5)
Income Before Income Tax 301 7 706 15 (15 )
Income tax expense (benefit) 34 1 282 6 35 1
Net Income (Loss) 267 6 424 9 (50) (1)
Less: Net income attributable to noncontrolling
interests 1
Net Income $ 267 6 % $ 424 9 % $ (51) (1)%
The following tables set forth our segment revenues and expenses by segment for each of the periods indicated and as a percentage of the total
consolidated operating revenues and operating expenses, respectively:
Year Ended December 31, 2015
Total Networks Renewables Gas Other(1)
(in millions)
Operating revenues $ 4,367 $ 3,386 $ 1,067 $ (19) $ (67)
Operating revenues % 78% 24% (2)%
Operating expenses $ 3,854 $ 2,849 $ 967 $ 66 $ (28)
Operating expenses % 74% 25% 2 % (1)%
Year Ended December 31, 2014
Total Networks Renewables Gas Other(1)
(in millions)
Operating revenues $ 4,594 $ 3,397 $ 1,189 $ 84 $ (76)
Operating revenues % 74% 26% 2 % (2 )%
Operating expenses $ 3,709 $ 2,781 $ 932 $ 68 $ (72)
Operating expenses % 75% 25% 2 % (2)%
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Year Ended December 31, 2013
Total Networks Renewables Gas Other(1)
(in millions)
Operating revenues $ 4,313 $ 3,319 $ 1,097 $ (27) $ (76)
Operating revenues % 77% 25% (2)%
Operating expenses $ 4,134 $ 2,616 $ 975 $ 620 $ (77)
Operating expenses % 63% 24% 15% (2)%
(1) Other amounts represent corporate and company eliminations.
Comparison of Period to Period Results of Operations
Our operating revenues decreased by 5%, from $4.6 billion for the year ended December 31, 2014 to $4.4 billion for the year ended December 31,
2015.
Our purchased power, natural gas and fuel used decreased by 18% from $1.2 billion for the year ended December 31, 2014 to $ 972 million for the
year ended December 31, 2015.
Our operations and maintenance increased by 15% from $1.6 billion for the year ended December 31, 2014 to $1.8 billion for the year ended
December 31, 2015.
Details of the period to period comparison are described below at the segment level.
Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014
Networks
Operating revenues for the year ended December 31, 2015 decreased by $11 million or less than 1% from $3,397 million for the year ended
December 31, 2014 to $3,386 million. UIL contributed $36 million in additional revenue, offset by underlying revenue being $47 million lower due to lower
gas rates in 2015 as compared to 2014. There were also lower gas sales volumes, as consumption declined due to milder weather.
Purchased power, natural gas and fuel used for the year ended December 31, 2015 decreased by $235 million, or 22%, from $1.1 billion for the year
ended December 31, 2014 to $821 million. UIL contributed $34 million in additional expense, resulting in underlying expense being $269 million lower.
Purchased power decreased by $189 million, resulting from a decrease in the market price of electricity in 2015, with 2014 prices being higher due to colder
temperatures causing less efficient generation to be used, increasing the marginal price of electricity. Additionally, gas purchase expenses decreased by $80
million due to a decrease in gas market prices, with prices lower in 2015 due to continuing shale gas production increasing supply, and a decline in oil prices,
which are closely correlated with gas prices.
Operations and maintenance during the year ended December 31, 2015 increased by $206 million or 17% from approximately $1.2 billion for the year
ended December 31, 2014 to approximately $1.4 billion. Excluding the impact of UIL, underlying expense increased by $153 million, with the main drivers
being increased spending in 2015 on reliability support services of $80 million, combined with regulatory refunds received in 2014 for the Yankee DOE
phase 2 of $28 million together with smaller increases in energy efficiency programs and corporate recharges.
Renewables
Operating revenues for the year ended December 31, 2015 decreased by $122 million or 10% from approximately $1.2 billion for the year ended
December 31, 2014 to approximately $1.1 billion. The decrease was due primarily to a reduction in output from our renewable generation facilities which
were 592 GWh lower and lower merchant prices with a resulting reduction of $70 million, unfavorable results from power trading activities of $34 million,
due to reduced trading opportunities created by lower price volatility in the northwest markets and a decrease of $9 million attributable to unrealized losses
from changes in fair value of energy derivative transactions entered into for economic hedging purposes.
Purchased power, natural gas and fuel used for the year ended December 31, 2015 increased by $9 million, or 5%, from $193 million for the year
ended December 31, 2014 to $202 million. The increase is attributable to costs for our thermal power plant.
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Operations and maintenance for the year ended December 31, 2015 increased $27 million or 8% from $336 million for the year ended December 31,
2014 to $363 million, primarily as a result of higher corporate recharges, combined with several non-recurring expenses and lower capitalization of expenses.
Gas
Operating revenues for the year ended December 31, 2015 decreased by $103 million, or 123%, from $84 million for the year ended December 31,
2014 to negative $19 million. The decrease in operating revenues was due to $105 million in changes relating to change in value of derivatives, with
unrealized losses in 2015 compared to unrealized gains in 2014.
Purchased power, natural gas and fuel used for the year ended December 31, 2015 remained consistent over the periods at $1 million.
Operations and maintenance for the year ended December 31, 2015 decreased by $2 million, or 4%, from $40 million for the year ended December 31,
2014 to $38 million. The decrease is mainly due to reduction in operational expense in the trading and storage businesses.
Depreciation, Amortization and Impairment of Non-Current Assets
Depreciation, amortization and impairment expenses for the year ended December 31, 2015 increased by $53 million or 8% from $654 million for the
year ended December 31, 2014 to $707 million. The depreciation expense for Gas, Renewables and Networks increased by $67 million. Asset increases at
Networks accounted for $43 million and a further $10 million at Renewables, and UIL accounts for a further $6 million. Partially offsetting this is a reduction
of $12 million on impairment expense related to renewable development projects.
Other Income and (Expense) and Equity Earnings
Other income and (expense) and equity earnings for the year ended December 31, 2015 decreased by $9 million, or 14%, from $64 million other
income for the year ended December 31, 2014 to $55 million. The decrease in other income is associated with lower equity earnings of $11 million due to the
impact of lower power prices and production on the joint venture windfarms of Renewables. For additional information, please see Note 21 to our audited
combined and consolidated financial statements for the year ended December 31, 2015 included in this Form 10-K.
Interest Expense, Net of Capitalization
Interest expense for the year ended December 31, 2015 increased $24 million or 10% from $243 million for the year ended December 31, 2014 to
$267 million. Networks expense increased $30 million, consistent with the change in debt and UIL contributed $4 million in additional
expense. Renewables expense decreased corresponding with a decrease as their debt amortized.
Income Tax Expense (Benefit)
Income tax expense for the year ended December 31, 2015 was $71 million lower than it would have been at the statutory federal income tax rate of
35% due predominately to production tax credits, filing of amended returns in the State of New York and the impact of tax equity financing arrangements.
This resulted in an effective tax rate of 11.30%. Income tax expense for the year ended December 31, 2014 was $35 million higher than it would have been at
the statutory federal income tax rate of 35% due predominately to remeasurement of the deferred income tax liability caused by the imposition of a unitary
tax regime in New York effective January 1, 2015, production tax credits, and the impact of tax equity financing arrangements. This resulted in an effective
tax rate of 39.94%.
Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013
Networks
Operating revenues for the year ended December 31, 2014 increased by $78 million or 2% from $3.3 billion for the year ended December 31, 2013 to
$3.4 billion. The increase in operating revenues was primarily related to increased volume of transmission of $51 million and increased rates of $65 million.
Additionally, revenues increased by $12 million associated with increased transmission sales related to growth in CMP. These increases were offset by
decreases in the amount of $37 million revenues associated with regulatory adjustments and New York rate decreases of $12 million.
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Purchased power, natural gas and fuel used for the year ended December 31, 2014 increased by $99 million, or 10%, from $1 billion for the year ended
December 31, 2013 to $1.1 billion. The increase in purchased power, natural gas and fuel used was due to the $60 million increase in electric retail prices, as
well as higher wholesale prices of $5 million. Additionally, gas purchase expenses increased due to an increase in volume purchased of $26 million and
higher fuel prices in the amount of $9 million.
Operations and maintenance during the year ended December 31, 2014 increased by $47 million or 4% from approximately $1.1 billion for the year
ended December 31, 2013 to approximately $1.0 billion. Operations and maintenance increased due to higher spending associated with weather, including
storm-related expenses of $15 million, uncollected debt of $5 million, increased labor-related expenses (net of capitalization) of $14 million, and $15 million
in revenue related to regulatory adjustments.
Renewables
Operating revenues for the year ended December 31, 2014 increased by $92 million or 8% from $1.1 billion for the year ended December 31, 2013 to
$1.2 billion. The increase was due to higher results from existing wind assets with output sold under long term contracts reflecting stronger wind resource of
$4 million, increased prices realized in the market on existing merchant wind assets of $7 million, collection from customers and control area operators for
curtailments and pass-through of transmission charges of $5 million, favorable results from power trading activities due to significant price volatility in the
northwest markets due to cold weather and abundant hydro conditions of $15 million. Additionally, transmission revenue increased by $2 million. The
remaining increase of $44 million is largely attributable to unrealized gains from changes in fair value of energy derivative transactions entered into for
economic hedging purposes.
Purchased power, natural gas and fuel used for the year ended December 31, 2014 decreased by $1 million, from $194 million for the year ended
December 31, 2013 to $193 million. The decrease in purchased power was due to the reduction in generated power transmission of $1 million.
Operations and maintenance for the year ended December 31, 2014 decreased by $15 million or 4% from $351 million for the year ended
December 31, 2013 to $336 million for the year ended December 31, 2014, primarily as a result of reductions in labor-related expenses of $5 million, lower
turbine maintenance fees of $4 million, and decreases in indirect expenses of $5 million.
Gas
Operating revenues for the year ended December 31, 2014 increased by $111 million from negative revenues of $27 million for the year ended
December 31, 2013 to positive revenues of $84 million. The increase in operating revenues was due to $125 million unrealized gain driven by changes in
MtM from a gain in value on storage and transport hedges due to average price decreases in 2014 compared to a loss in value due to average price increases
in 2013.
Purchased power, natural gas and fuel used for the year ended December 31, 2014 decreased by $3 million, or 75%, from $4 million for the year ended
December 31, 2013 to $1 million. The decrease in purchased power, natural gas and fuel used was due to the decreased usage of gas in operation of storage
facilities in the amount of $3 million.
Operations and maintenance for the year ended December 31, 2014 remained consistent over the periods at $40 million.
Depreciation, Amortization and Impairment of Non-Current Assets
Depreciation, amortization and impairment expenses for the years ended December 31, 2014 and December 31, 2013 were $654 million and $1.2
billion, respectively. The decrease of $560 million was driven by a 2013 provision, relating mainly to natural gas storage facilities of $382 million and
impairment of goodwill of the Gas business of $163 million in view of the potential long term low margins for natural gas, given the impact of shale gas on
the North American energy market. Additionally, Renewables had year-over-year impairment decreases of $51 million. This was offset by an increase in
depreciation expense at Networks of $18 million associated with increased transmission assets in Maine and increased base assets in New York.
Other Income and (Expense) and Equity Earnings
Other income and (expense) and equity earnings for the year ended December 31, 2014 increased by $13 million from $51 million other income for
the year ended December 31, 2013 to $64 million for the year ended December 31, 2014. The increase in other income is associated with higher equity
earnings of which $9 million is attributable to joint ventures of Renewables in the Flat Rock and Colorado Green projects.
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Interest Expense, Net of Capitalization
Interest expense for the year ended December 31, 2014 and December 31, 2013 were $243 million and $245 million, respectively. The decrease of $2
million or less than 1% shows the expenses were consistent over these periods driven primarily by Networks’ debt costs.
Income Tax Expense (Benefit)
Income tax expense from continuing operations for the year ended December 31, 2014 was $35 million higher than it would have been at the statutory
federal income tax rate of 35% due predominately to remeasurement of the deferred income tax liability caused by the imposition of a unitary tax regime in
New York effective January 1, 2015, production tax credits, and the impact of tax equity financing arrangements. This resulted in an effective tax rate of
39.94%. Income tax expense from continuing operations for the year ended December 31, 2013 was $40 million higher than it would have been at the
statutory federal income tax rate of 35% due predominately to the book impairment of non-deductible goodwill. This resulted in an effective tax rate of
233%.
Non-GAAP Financial Measures
We supplement the use of U.S. GAAP financial measures in this document with non-GAAP financial measures, including adjusted gross margin and
adjusted EBITDA. We refer to these measures as “non-GAAP financial measures” given they are not required by, or presented in accordance with U.S. GAAP.
We define adjusted EBITDA as net income (loss) attributable to AVANGRID, adding back net income (loss) attributable to other non-controlling
interests, income tax expense (benefit), depreciation and amortization, impairment of non-current assets and interest expense, net of capitalization, and then
subtracting other income and (expense), earnings (losses) from equity method investments and income from discontinued operations. We also believe that
presenting earnings excluding certain non-recurring items and reflecting a full twelve-month period for UIL, is useful in understanding and evaluating actual
and projected financial performance and contribution of AVANGRID and to more fully compare and explain our results without including the impact of the
non-recurring items and with reflecting pro forma information to reflect a full year of results for merged entities. Additionally, we evaluate the nature of our
revenues and expenses and adjust to reflect classification by nature for evaluation of our non-GAAP financial measures as opposed to by function. The most
directly comparable U.S. GAAP measure to adjusted EBITDA is net income. We also define adjusted gross margin as adjusted EBITDA adding back
operations and maintenance and taxes other than income taxes and then subtracting transmission wheeling.
We present non-GAAP financial measures because we believe that they and other similar measures are widely used by certain investors, securities
analysts and other interested parties as supplemental measures of performance. We also use these measures internally to establish budgets and operational
goals to manage and monitor our business, as well as to evaluate our underlying historical performance. The non-GAAP financial measures may not be
comparable to other similarly titled measures of other companies and have limitations as analytical tools and should not be considered in isolation or as a
substitute for analysis of our operating results as reported under U.S. GAAP.
Non-GAAP financial measures are not primary measurements of our performance under U.S. GAAP and should not be considered as alternatives to
operating income (loss) from continuing operations, net income or any other performance measures determined in accordance with U.S. GAAP.
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Reconciliation of the Net Income (Loss) attributable to AVANGRID to the consolidated Adjusted EBITDA and adjusted gross margin before
combining a full year of UIL results, non-recurring and by nature items for the years ended December 31, 2015, 2014 and 2013 is as follows:
Years Ended December 31, 2015 2014 2013
(Millions)
Net Income (Loss) Attributable to AVANGRID, Inc. $ 267 $ 424 $ (51 )
Add: Net income (loss) attributable to other noncontrolling interests 1
Income tax expense 34 282 35
Depreciation and amortization 695 629 594
Impairment of non-current assets 12 25 620
Interest expense, net of capitalization 267 243 245
Less: Other income and (expense) 55 52 54
Earnings (losses) from equity method investments 12 (3)
Consolidated Adjusted EBITDA before combining a full year of
UIL results, non-recurring and by nature items $ 1,220 $ 1,539 $ 1,393
Add: Operations and maintenance (1) 1,808 1,560 1,541
Taxes other than income taxes 367 314 291
Less: Transmission wheeling (1) 149 143 149
Adjusted gross margin before combining a full year of UIL results,
non-recurring and by nature items $ 3,246 $ 3,270 $ 3,076
(1) Transmission wheeling is a component of operations and maintenance and is considered a component of adjusted gross margin because it is directly associated with the power
supply costs included in the cost of sales.
The following tables set forth our adjusted EBITDA and adjusted gross margin before combining a full year of UIL results, non-recurring and by nature
items by segment for each of the periods indicated and as a percentage of operating revenues:
Year Ended December 31, 2015
Total Networks Renewables Gas Other(1)
(in millions)
Adjusted gross margin before combining a full year of UIL
results, non-recurring and by nature items $ 3,246 $ 2,417 $ 865 $ (20) $ (16)
Adjusted gross margin % 71% 81 % 105 % 24 %
Adjusted EBITDA before combining a full year of UIL results,
non-recurring and by nature items $ 1,220 $ 865 $ 456 $ (62) (39)
Adjusted EBITDA % 26% 43 % 326 % 58 %
Year Ended December 31, 2014
Total Networks Renewables Gas Other(1)
(in millions)
Adjusted gross margin before combining a full year of UIL
results, non-recurring and by nature items $ 3,270 $ 2,199 $ 997 $ 83 $ (9 )
Adjusted gross margin % 65% 84% 99 % 12%
Adjusted EBITDA before combining a full year of UIL results,
non-recurring and by nature items $ 1,539 $ 891 $ 613 $ 38 $ (3 )
Adjusted EBITDA % 26% 52% 45 % 4 %
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Year Ended December 31, 2013
Total Networks Renewables Gas Other(1)
(in millions)
Adjusted gross margin before combining a full year of UIL
results, non-recurring and by nature items $ 3,076 $ 2,213 $ 904 $ (31) $ (10)
Adjusted gross margin % 67% 82% 115% 13 %
Adjusted EBITDA before combining a full year of UIL results,
non-recurring and by nature items $ 1,393 $ 960 $ 507 $ (76 ) $ 2
Adjusted EBITDA % 29% 46% 281% (3)%
(1) Other amounts represent corporate and company eliminations.
Comparison of Period to Period Results of Operations
Our adjusted gross margin before combining a full year of UIL results, non-recurring and by nature items decreased by $24 million, or less than 1%
from $3,270 million for the year ended December 31, 2014 to $3,246 million for the year ended December 31, 2015.
Our adjusted EBITDA before combining a full year of UIL results, non-recurring and by nature items decreased by $319 million, or 21%, from $1.5
billion for the year ended December 31, 2014 to $1.2 billion for the year ended December 31, 2015.
Details of the period to period comparison are described below at the segment level.
Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014
Networks
Adjusted gross margin before combining a full year of UIL results, non-recurring and by nature items for the year ended December 31, 2015 increased
by $218 million to $2.4 billion. The increase is associated primarily with the decrease of purchased power by $189 million due to a decrease in the market
price of electricity in 2015, with 2014 prices being higher due to colder temperatures causing less efficient generation to be used, increasing the marginal
price of electricity. The remaining difference represents the cost of transmission wheeling year over year.
Adjusted EBITDA before combining a full year of UIL results, non-recurring and by nature items for the year ended December 31, 2015 decreased by
$26 million or 3% from $891 million for the year ended December 31, 2014 to $865 million. The decrease is primarily due to the reasons discussed above
regarding adjusted gross margin before combining a full year of UIL results, non-recurring and by nature items and increase in operations and maintenance
with the main drivers being increased spending in 2015 on reliability support services.
Renewables
Adjusted gross margin before combining a full year of UIL results, non-recurring and by nature items for the year ended December 31, 2015 decreased
by $132 million or 13% from $997 million for the year ended December 31, 2014 to $865 million. The decrease was due primarily to a reduction in output
from our renewable generation facilities, which were 592 GWh lower, and lower merchant prices with a resulting reduction of $70 million, unfavorable results
from power trading activities of $34 million, due to reduced trading opportunities created by lower price volatility in the northwest markets and a decrease of
$9 million attributable to unrealized losses from changes in fair value of energy derivative transactions entered into for economic hedging purposes.
Adjusted EBITDA before combining a full year of UIL results, non-recurring and by nature items for the year ended December 31, 2015 decreased by
$157 million or 26% from $613 million for the year ended December 31, 2014 to $456 million. The increase was due primarily to the same reasons discussed
above for adjusted gross margin before combining a full year of UIL results, non-recurring and by nature items.
Gas
Adjusted gross margin before combining a full year of UIL results, non-recurring and by nature items for the year ended December 31, 2015 decreased
by $103 million, or 124%, from $83 million for the year ended December 31, 2014 to negative $20 million. The decrease is associated with the decrease in
operating revenues due to $105 million in changes relating to change in value of derivatives, with unrealized losses in 2015 compared to unrealized gains in
2014.
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Adjusted EBITDA before combining a full year of UIL results, non-recurring and by nature items for the year ended December 31, 2015 decreased by
$100 million, or 263%, from $38 million for the year ended December 31, 2014 to negative $62 million. The decrease was due primarily to the same reasons
discussed above for adjusted gross margin before combining a full year of UIL results, non-recurring and by nature items.
Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013
Networks
Adjusted gross margin before combining a full year of UIL results, non-recurring and by nature items for the year ended December 31, 2014 decreased
by $14 million to $2.2 billion. The decrease is associated with the increase in purchased power, natural gas and fuel used primarily due to the increase in
electric retail prices, as well as higher wholesale prices. The remaining difference represents the cost of transmission wheeling year over year.
Adjusted EBITDA before combining a full year of UIL results, non-recurring and by nature items for the year ended December 31, 2014 decreased by
$69 million or 7% from $960 million for the year ended December 31, 2013 to $891 million. The decrease is primarily due to the reasons discussed above
regarding adjusted gross margin before combining a full year of UIL results, non-recurring and by nature items and higher spending on operations and
maintenance, including storm-related and labor-related expenses.
Renewables
Adjusted gross margin before combining a full year of UIL results, non-recurring and by nature items for the year ended December 31, 2014 increased
by $93 million or 10% from $904 million for the year ended December 31, 2013 to $997 million. The increase was due to higher results from existing wind
assets with output sold under long term contracts reflecting stronger wind resource of $4 million, increased prices realized in the market on existing merchant
wind assets of $7 million, collection from customers and control area operators for curtailments and pass-through of transmission charges of $5 million,
favorable results from power trading activities due to significant price volatility in the northwest markets due to cold weather and abundant hydro conditions
of $15 million. Additionally, transmission revenue increased by $2 million. The remaining increase of $44 million is largely attributable to unrealized gains
for changes in fair value on energy derivative transactions entered into for economic hedging purposes.
Adjusted EBITDA before combining a full year of UIL results, non-recurring and by nature items for the year ended December 31, 2014 increased by
$106 million or 21% from $507 million for the year ended December 31, 2013 to $613 million. The increase was due to the same reasons discussed above for
adjusted gross margin before combining a full year of UIL results, non-recurring and by nature items and the reduction in operating expenses compared to the
prior period.
Gas
Adjusted gross margin before combining a full year of UIL results, non-recurring and by nature items for the year ended December 31, 2014 increased
by $114 million from negative $31 million for the year ended December 31, 2013 to positive $83 million. The increase was due to to $125 million
unrealized gain driven by changes in MtM from a gain in value on storage and transport hedges due to average price decreases in 2014 compared to a loss in
value due to average price increases in 2013.
Adjusted EBITDA before combining a full year of UIL results, non-recurring and by nature items for the year ended December 31, 2014 was positive
$38 million compared to negative $76 million for the year ended December 31, 2013, an increase of $114 million. The increase was due to the same reasons
discussed above for adjusted gross margin before combining a full year of UIL results, non-recurring and by nature items.
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The following table provides a reconciliation between Net Income (Loss) attributable to AVANGRID and adjusted gross margin and adjusted EBITDA
after reflecting a full year results of UIL, non-recurring and by nature items for the years ended December 31, 2015, 2014 and 2013:
AVANGRID Consolidated
Year Ended December 31,
(millions)
2015 2014 2013
Net Income (Loss) Attributable to AVANGRID, Inc. $ 267 $ 424 $ (51)
Adjustment for full year UIL and non-recurring items:
Add: Net Income representing a full year for UIL 130 110 115
Merger Costs 71 5
Adjusted Net Income $ 468 $ 539 $ 64
Add: Net income (loss) attributable to other noncontrolling interests 1
Income tax expense including full year UIL, non-recurring and by
nature items 169 376 128
Depreciation and amortization including full year UIL, non-
recurring and by nature items 992 877 784
Impairment of non-current assets 12 25 620
Interest expense, net of capitalization including full year UIL, non-
recurring and by nature items 309 300 332
Less: Other income and (expense) 55 52 75
Earnings (losses) from equity method investments including full
year UIL and non-recurring items 11 23 12
Adjusted EBITDA after full year UIL, non-recurring and by nature
items $ 1,884 $ 2,042 $ 1,842
Add: Operations and maintenance including full year UIL items (1) 1,506 1,521 1,484
Taxes other than income taxes including full year UIL items 529 500 472
Adjusted Gross Margin $ 3,919 $ 4,063 $ 3,798
(1) Transmission wheeling is a component of operations and maintenance and is considered a component of adjusted gross margin because it is directly associated with the power
supply costs included in the cost of sales.
Liquidity and Capital Resources
Our operating, investing, developing and acquisition activities have significant short-term liquidity and long-term capital requirements. Historically,
we have used cash from operations, and borrowings under our credit facilities and commercial paper programs as our primary sources of liquidity. Our long-
term capital requirements have been met primarily through retention of earnings, equity contributions from Iberdrola, S.A. and borrowings in the investment
grade debt capital markets. Continued access to these sources of liquidity and capital are critical to us. Risks may increase due to circumstances beyond our
control, such as a general disruption of the financial markets and adverse economic conditions.
Liquidity Resources
At December 31, 2015, we had cash and cash equivalents of $427 million, as compared to $482 million at December 31, 2014. In addition to cash on
hand, we and our subsidiaries have access to committed credit facilities totaling $1.3 billion.
We optimize our liquidity within the United States through a series of arms’-length intercompany lending arrangements with our subsidiaries and
among our regulated utilities to provide for lending of surplus cash to subsidiaries with liquidity needs, subject to the limitation that the regulated utilities
may not lend to unregulated affiliates.
We manage our overall liquidity position as part of the broader Iberdrola Group and are a party to a notional cash pooling agreement with Bank
Mendes Gans, N.V., or BMG, along with other Iberdrola, S.A. subsidiaries. The notional cash pooling agreement aids the Iberdrola Group in efficient cash
management and reduces the need for external borrowing by the pool participants. Parties to the agreement, including us, may deposit funds with or borrow
from BMG, provided that the net balance of
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funds deposited or borrowed by all pool participants in the aggregate is not less than zero. Under the cash pooling agreement, affiliates with credit balances
have pledged those balances to cover the debit balances of the other affiliated parties to the agreement. Interest accrues on a daily basis at the rate of
(i) overnight LIBOR minus 3 basis points for credit balances and (ii) overnight LIBOR plus 100 basis points for debit balances. Deposits are available for
next day withdrawal. Deposits in the cash pooling account were $449 million and $353 million at December 31, 2014 and December 31, 2015, respectively.
The deposit amounts are reflected in our consolidated balance sheet under cash and cash equivalents because our deposited surplus funds under the cash
pooling agreement are highly-liquid short-term investments.
AVANGRID Revolving Credit Facility
In May 2012, we entered into a $300 million revolving credit facility for the purpose of providing for our liquidity needs and those of our unregulated
subsidiaries. The facility has a termination date in May 2019. We pay an annual facility fee of $0.7 million. As of December 31, 2015 and December 31, 2014
the facility was undrawn.
The revolving credit facility contains a covenant that requires us to maintain a ratio of consolidated indebtedness to consolidated total capitalization
that does not exceed 0.65 to 1.00 at any time. For purposes of calculating this maximum ratio of consolidated indebtedness to consolidated total
capitalization, the facility excludes from consolidated net worth the balance of accumulated other comprehensive income, or AOCI, as it appears on the
consolidated balance sheets.
Iberdrola Financiacn, S.A.U. Credit Facility
In August 2011, we entered into a revolving credit facility with Iberdrola Financiación, S.A., a subsidiary of Iberdrola, S.A., under which we could
borrow up to $600 million. We terminated the facility on October 28, 2015. The facility was never utilized.
Joint Utility Revolving Credit Facility
In July 2011, NYSEG, RGE and CMP jointly entered into a bank provided revolving credit facility, the Joint Utility Facility, that allows maximum
aggregate borrowings of up to $600 million and expires in July 2018. Each subsidiary is currently subject to a $200 million credit limit. Each borrower pays
a facility fee ranging from fifteen to twenty basis points annually depending on the rating of its unsecured debt.
CMP and NYSEG have established commercial paper programs backstopped by the Joint Utility Facility. These companies use commercial paper as
an alternative to revolving credit facilities as a source of short-term credit.
In the Joint Utility Facility each joint borrower covenants not to permit, without the lender’s consent, its ratio of total indebtedness to total
capitalization to exceed 0.65 to 1.00 at any time. For purposes of calculating the maximum ratio of consolidated indebtedness to total capitalization, the
facility excludes from consolidated net worth the balance of AOCI as it appears on the consolidated balance sheets. As of December 31, 2015 and December
31, 2014 there were no outstanding loans, no outstanding commercial paper and $14 million of outstanding letters of credit at both dates.
UIL Credit Facility
In November 2011 UIL, UI, CNG, SCG, and Berkshire became parties to a revolving credit agreement that will expire in November, 2016, or the UIL
Credit Facility. In connection with the consummation of the acquisition, Merger Sub assumed all rights and obligations of UIL under the UIL Credit Facility
through an assumption agreement dated as of December 15, 2015. The aggregate borrowing limit under the UIL Credit Facility is $400 million, all of which
is available to UIL, $250 million of which is available to UI, $150 million of which is available to each of CNG and SCG, and $25 million of which is
available to Berkshire, all subject to the aggregate limit of $400 million. UIL pays a facility fee of twenty basis points annually.
The UIL Credit Facility contains a covenant that requires each borrower to maintain a ratio of consolidated indebtedness to consolidated total
capitalization that does not exceed 0.65 to 1.00 at any time. For purposes of calculating this maximum ratio of consolidated indebtedness to consolidated
total capitalization, the facility excludes from consolidated net worth unrealized gains and losses reflected in other comprehensive income in respect of
qualified and non-qualified defined benefit pension plans, as well as other post-retirement benefit plans of such Borrower.
As of December 31, 2015 there were $163 million in outstanding loans and $4 million in outstanding letters of credit. We believe that we have
sufficient liquidity resources to fund our operations and investments over the next 12 months.
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Long-Term Capital Resources
We expect to meet our long-term capital requirements through the use of our cash surplus, credit facilities, cash from operations, and long-term
borrowing. At December 31, 2015 we had no outstanding debt at the holding company level and $4,736 million of long-term debt attributable to our
subsidiaries (including the current portion thereof), which consisted of first mortgage bonds, fixed and variable unsecured pollution control notes and other
various non-current debt, as further described below. We have investment grade ratings from Standard and Poors, Moody’s and Fitch and we believe that we
could raise capital on competitive terms in the investment grade debt capital and/or bank markets.
Networks regulated utilities are required by regulatory order to maintain a minimum ratio of common equity to total capital that is tied to the capital
structure used in the establishment of their revenue requirements. Pursuant to these requirements, each of NYSEG, RGE, CMP and MNG must maintain a
minimum equity ratio equal to the ratio in its currently effective rate plan or decision measured using a trailing 13-month average. On a monthly basis, each
utility must maintain a minimum equity ratio of no less than 300 basis points below the equity ratio used to set rates. Networks’ regulated utilities were in
compliance with these regulatory orders as of December 31, 2015. UI, SCG, CNG and BGC are restricted from paying dividends if paying such dividend
would result in their respective common equity ratio being lower than 300 basis points below the equity percentage used to set rates in the most recent
distribution rate proceeding as measured using a trailing 13-month average calculated as of the most recent quarter end. The regulated utilities periodically
pay dividends to, or receive capital contributions from AVANGRID, in order to maintain the minimum equity ratio requirement. They each independently
incur indebtedness by issuing investment grade debt securities. Of the $4,736 million of our long-term debt (including the current portion thereof) at
December 31, 2015, $4,132 million are obligations of Network’s regulated utilities.
ARHI has historically been financed primarily with equity contributions from Iberdrola. The last such contribution of $800 million was made in
February 2013. ARHI has also sourced capital through tax equity financing arrangements associated with particular wind farm projects. The arrangements
allocate tax losses and production tax credits to the tax equity investor in exchange for an initial contribution. The obligations created under the tax equity
financing arrangements are recorded as a liability with an aggregate balance of $292 million, of which $107 million is current, at December 31, 2015. ARHI
has also sourced capital through sale-leaseback arrangements and project financing, the balance of which are included in long-term debt and totaled $62
million at December 31, 2015.
In our credit facilities, long-term borrowing and tax-equity partnerships, we and our affiliates that are parties to the agreements are subject to
covenants that are standard for such agreements. Affirmative covenants impose certain obligations on the borrower and negative covenants limit certain
activities by the borrower. The agreements also define certain events of default, including but not limited to non-compliance with the covenants that may
automatically in some circumstances, or at the option of the lenders in other circumstances, trigger acceleration of the obligations. We and our affiliates were
in compliance with all such covenants at December 31, 2015.
Capital Requirements
Funding Future Common Dividend Payments
We expect to fund any quarterly shareholder dividends primarily from the cash provided by operations of our businesses in the future. We have a
revolving credit facility, as described above, to fund short-term liquidity needs and we believe that we will have access to the capital markets should
additional, long-term growth capital be necessary.
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Capital Expenditures
The regulated utilities’ capital expenditures over the last 3 years have been the following:
2013 2014 2015
(in millions)
NYSEG $ 235 $ 247 $ 259
RGE 195 181 157
CMP (non-MPRP(1)) 149 172 120
CMP (MPRP) 255 112 108
MNG 36 15 3
UI 160 142 187
SCG 50 64 62
CNG 36 55 62
Berkshire 10 13 16
Total $ 1,126 $ 1,001 $ 974
(1) MPRP refers to the Maine Power Reliability Program.
Renewables’ capital expenditures for the years set forth below were as follows:
2013 2014 2015
(in millions)
Wind & solar $ 35 $ 270 $ 58
Thermal 19 14 11
Corporate(1) 5 9 8
Total capital expenditures 59 293 77
Cash grants(2) (29 )
Total capital expenditures less cash grants $ 30 $ 293 $ 77
(1) Includes information technology and facilities and safety (security).
(2) Payments received from the United States Department of Treasury under Section 1603 of the American Recovery and Reinvestment Act of 2009, as a reimbursement for a
portion of the costs related to the construction of wind farms, and in lieu of production tax credits.
The yearly decreases from 2013 to 2015 in Networks capital expenditures are primarily due to a reduced spending for CMP’s transmission project in
Maine, the MPRP, with 2012 being the peak year for our investment for this multiyear project. Other investments have remained relatively flat across
Networks during this period.
Renewables also made capital investments during this three year period. In 2015 there were capital expenditures of $73 million on construction of the
Desert Wind and other wind assets, $11 million in capital expenditures on the Klamath gas-fired cogeneration facility, or the Klamath Plant, $31 million on
improvements to operating wind assets and $9 million in development costs.
In 2014 there were capital expenditures of $257 million primarily for construction of the Baffin Bay wind asset, $14 million for capital expenditures
on the Klamath gas-fired cogeneration facility, or the Klamath Plant, $14 million on improvements to operating wind assets and $13 million in development
costs, partially offset by $16 million in net refunds of wind turbine deposits.
In 2013, capital expenditures for Renewables included $35 million related to the Baffin Bay wind asset, $19 million of capital expenditures for the
Klamath Plant, $14 million on improvements to operating wind assets, and $17 million in development costs, partially offset by $42 million for refunds of
unused wind turbine deposits and $29 million received in cash grants under the U.S. Treasury cash grant program.
Capital Improvement Projects
An important part of our business strategy involves capital improvement projects. Through Networks we plan to invest a total of approximately $6.7
billion from 2016 to 2020 to upgrade and expand electricity and natural gas transmission and distribution infrastructure. In the next 12 months, CMP plans
to invest $24 million in the Lewiston Loop project, which complements the already completed MPRP, a project which enhanced the bulk power transmission
grid in Maine. In addition to that, CMP plans to invest $32 million in its new Customer Relationship Management and Billing System. RGE plans to invest
in the next 12 months $77 million in the Ginna Retirement Transmission Alternative project to provide a transmission solution to address the planned
retirement of the
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Ginna nuclear power plant near Rochester, $6.2 million on the Rochester Area Reliability project to develop a new substation and transmission lines, $35
million for the new line and upgrades in Station 23 related to the Rochester Area Reliability project and $2 million on the Station 2 Generation
Modernization Project for improvements at RGE’s hydroelectric generating plant on the Genesee River. NYSEG plans to invest in the next 12 months $26
million in the Marcy South Series Capacitance project to upgrade various elements of the transmission system between the Marcy and Fraser—Cooper
Corners substations, $22 million on the Auburn Transmission Project to construct a new electric transmission line over a distance of approximately 14.5
miles from the City of Auburn to the Town of Elbridge in New York.
On July 24, 2015, UIL announced its participation in Tennessee Gas Pipeline Company LLC’s, or TGP, proposed Northeast Energy Direct project, or
NED pipeline, through an acquisition of a 2.5% equity interest in Northeast Expansion LLC. Northeast Expansion LLC is a joint venture between an affiliate
of Kinder Morgan, Inc., or Kinder Morgan, and Liberty Utilities Corp., which will construct and own the NED pipeline, a new, “market path natural gas
pipeline segment of approximately 188 miles from Wright, New York, to Dracut, Massachusetts. This 2.5% equity interest, which totaled approximately $1.6
million as of December 31, 2015, commits UIL to an initial capital investment opportunity that is expected to total up to approximately $80 million,
depending on the final pipeline configuration and design capacity. Pursuant to an option agreement with Kinder Morgan, UIL also has the option to acquire
up to an additional 12.5% of equity interests in Northeast Expansion LLC under certain limited circumstances, including if certain additional firm
transportation agreements for service on the NED pipeline are entered into or if TGP does not sell additional volume on the NED pipeline. Any increase in
equity ownership would increase UILs investment commitment proportionately. In addition, as a condition to making this investment, UIL entered into a
20-year Precedent Agreement with TGP for pipeline capacity of 70,000 DTh/day on the NED pipeline, which capacity commitment, under the terms of the
Precedent Agreement, would be reduced in the event that TGP enters into additional precedent agreements with third parties for capacity on the NED
pipeline.
Through Renewables we plan to invest a total of approximately $2.8 billion from 2016 to 2020 in order to add 1,400 MWs of generation capacity.
744 MW are approved for construction in 2016 and 2017 and these projects have long-term associated PPA contracts.
We expect to fund these capital improvement projects through a combination of retained earnings, cash provided by operations, and access to the
capital markets, including debt borrowings at either the subsidiary or holding company level. Additionally, we have a revolving credit facility, as described
above, to fund short-term liquidity needs.
Cash Flows
Our cash flows depend on many factors, including general economic conditions, regulatory decisions, weather, commodity price movements, and
operating expense and capital spending control.
The following is a summary of the cash flows by activity for the years ended December 31, 2015, 2014 and 2013:
Year Ended
December 31,
2015 2014 2013
(in millions)
Cash Flows
Net cash from operating activities $ 1,361 $ 1,331 $ 1,177
Net cash used in investing activities (1,518 ) (888 ) (868 )
Net cash from (used in) financing activities 102 (180) (144)
Net (decrease) increase in cash and cash equivalents $ (55) $ 263 $ 165
Operating Activities
Our primary sources of operating cash inflows are proceeds from transmission and distribution of electricity and natural gas, sales of wholesale energy
and energy related products and services, and natural gas revenues from natural gas storage services. Our primary operating cash outflows are power and
natural gas purchases and transmission operating and maintenance expenses, as well as personnel costs and other employee-related expenditures. As our
business has expanded, our working capital requirements have grown. We expect our working capital to grow as we continue to grow our business.
In 2015, net cash provided by operating activities was approximately $1.4 billion. During the period, Renewables contributed $531 million of
operating cash associated with wholesale sales of energy, Networks contributed $867 million of operating cash as the result of regulated transmission and
distribution sales of electricity and natural gas, and Gas used cash of $42 million associated with gains on marketing of wholesale gas and gas storage
services. We used $5 million in cash associated with operating expenses in
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support of our segments. In addition, changes in working capital contributed $12 million in cash. The cash from operating activities for the year ended
December 31, 2015 compared to the year ended December 31, 2014 increased by $30 million and this is primarily driven by a slight increase in Networks
revenues. The $19 million net change in our net operating assets and liabilities during the year ended December 31, 2015 was primarily attributable to a
decrease in inventory costs driven by a decrease in inventory levels of $4 million, partially offset by environmental cost deferrals of $32 million.
In 2014, net cash provided by operating activities was approximately $1.3 billion. During the period, Renewables contributed $724 million of
operating cash associated with wholesale sales of energy, Networks contributed $734 million of operating cash as the result of regulated transmission and
distribution sales of electricity and natural gas, and Gas contributed cash of $17 million associated with gains on marketing of wholesale gas and gas storage
services. We used $60 million in cash associated with operating expenses in support of our segments. In addition, changes in working capital used $84
million in cash. The cash from operating activities for the year ended December 31, 2014 compared to the year ended December 31, 2013 increased $154
million and this is primarily driven by the increased revenues at Renewables due to increase in wind source, prices, power trading activities and abundant
hydro conditions as well as Gas due to lower gas prices. The $35 million net change in our net operating assets and liabilities during the year ended
December 31, 2014 was primarily attributable to a decrease in inventory costs driven by a decrease in inventory levels of $58 million, partially offset by
storm cost deferrals of $20 million.
In 2013, net cash provided by operating activities was approximately $1.2 billion. During the period, Renewables contributed $541 million of
operating cash associated with wholesale sales of energy, Networks contributed $556 million of operating cash as the result of regulated transmission and
distribution sales of electricity and natural gas, and Gas contributed cash of $89 million associated with gains on marketing of wholesale gas and gas storage
services. We contributed cash of $9 million in support of our segments. In addition, changes in working capital used $16 million in cash. The cash from
operating activities for the year ended December 31, 2013 compared to the year ended December 31, 2012 increased $454 million, driven by a full year
operation in 2013 of six new wind assets of 716 MW, favorable pricing and increased power generation at the Klamath facility. In addition, $215 million of
cash from operating activities was provided from the change in working capital. The $181 million net change in our net operating assets and liabilities
during the year ended December 31, 2013 was primarily attributable to a decrease in accounts receivable of $56 million driven by improvements in
collection, receipts from short-term deposits and guarantees of $27 million, a decrease in accounts payable of $208 million primarily driven by lower supply
costs and an increase in regulatory assets driven by storm cost deferrals of $29 million and environmental cost deferrals of $68 million, partially offset by
surcharge deferrals of $33 million.
Investing Activities
Our investing activities have primarily focused on enhancing, automating, and reinforcing the asset base to support safety, reliability, and customer
growth in accordance with the regulatory markets within which we operate, as well as constructing solar and wind assets and spending on gas generation
assets. During 2013 through 2015, we invested primarily in upgrading and expanding our electricity and natural gas infrastructure across our energy service
and utility companies. The cost of investments however has been offset, partially, by refunds received from the U.S. Treasury cash grant program and from
deposits made for turbine purchases and transmission interconnections.
In 2015, the cash used in investing activities was $1.5 billion, compared to $888 million in 2014 and $868 million in 2013. The increase in 2015
compared to prior years is primarily related to cash paid for acquisition of UIL (net of cash acquired) of $547 million.
The cash outflows related to capital expenditures for Networks were $773 million in 2015, $775 million in 2014, and $906 million in 2013. The
decrease from 2013 to 2015 in Networks capital expenditures are primarily due to a reduced spending for CMP’s transmission project in Maine, the MPRP,
with 2012 being the peak year for our investment for this multiyear project. The remaining capital expenditure related cash outflows in 2015 represent
principally capital expenditures in Renewables of $304 million. This amount is driven by significant progress in construction of the Baffin Bay wind asset in
2014. Under a turbine supply agreement, with Gamesa, payment for the supplied turbines did not take place until first quarter of 2015.
Financing Activities
Our financing activities have primarily consisted of using our credit facilities and long-term debt issued or redeemed by our regulated Networks
subsidiaries.
In 2015, cash provided by financing activities was $102 million reflecting primarily a net increase in non-current notes payable of $350 million less
maturities of $141 million and $102 million in payments on the tax equity financing arrangements.
In 2014, cash used in financing activities was $180 million reflecting primarily maturities of notes payable and $119 million in payments on the tax
equity financing arrangements.
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In 2013, cash used in financing activities was $144 million. Non-current note issuance of $225 million and an equity contribution from Iberdrola, S.A.
that included a cash infusion of $153 million were offset by maturities of non-current debt of $273 million, a reduction of $165 million in short-term debt
and payments on the tax equity financing arrangements of $173 million.
Contractual Obligations
As of December 31, 2015, our contractual obligations (excluding any tax reserves) were as follows:
Total 2016 2017 2018 2019 2020 Thereafter
(in millions)
Operating leases(1) $ 679 $ 216 $ 90 $ 26 $ 24 $ 25 $ 298
Projected future pension benefit
plan contributions(2) 183 43 44 51 32 13
Long-term debt (including
current maturities)(3) 4,736 206 302 162 354 721 2,991
Interest payments(4) 2,455 218 208 191 171 155 1,512
Material purchase commitments(5) 2,470 496 351 271 211 184 957
Total Contractual Obligations $ 10,523 $ 1,179 $ 995 $ 701 $ 792 $ 1,098 $ 5,758
(1) Represents lease contracts relating to operational facilities, office building leases, and vehicle and equipment leases. These amounts represent our expected portion of the costs
to pay as amounts related to contingent payments are predominantly linked to electricity generation at the respective facilities. Obligations under operating lease significantly
decrease from 2016 onwards as commitments on Cayuga and Ginna facilities are scheduled to terminate from 2017.
(2) The qualified pension plans’ contributions are generally based on the estimated minimum pension contributions required under ERISA and the Pension Protection Act of 2006,
as well as contributions necessary to avoid benefit restrictions and at-risk status and agreements with state regulatory agencies. These amounts represent estimates that are based
on assumptions that are subject to change. The minimum required contributions for years after 2020 are not included as projection beyond 2020 are not available.
(3) See debt payment discussion in “Long-term Capital Resources.”
(4) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2015 and do not reflect anticipated future refinancing, early
redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2015
(5) Represents forward purchase commitments under power, gas, and other arrangements.
Critical Accounting Policies and Estimates
The financial statements provided herein have been prepared in accordance with U.S. GAAP and include the accounts of AVANGRID.
In preparing the accompanying financial statements, our management has made certain estimates and assumptions that affect the reported amounts of
assets, liabilities, shareholder’s equity, revenues and expenses, and the disclosures thereof. Our management recorded the net assets of ARHI in these
combined and consolidated financial statements at the historical accounting basis of AVANGRID. The historical accounting basis of AVANGRID includes
purchase accounting adjustments related to AVANGRIDs acquisition of ARHI in 2007. Prior to the 2013 reorganization of AVANGRID, Networks was not
considered to be a substantive operating entity as it did not hold any direct operations and had always been a part of AVANGRID. As a result, the net assets of
Networks in these combined and consolidated financial statements are recorded at the historical accounting basis of AVANGRID, which do not include
purchase accounting adjustments related to Iberdrola, S.A.’s acquisition of AVANGRID in 2008.
Accounting for Regulated Public Utilities
U.S. GAAP allows regulated entities to give accounting recognition to the actions of regulatory authorities. In order to apply such regulatory
accounting treatment and record regulatory assets and liabilities, certain criteria must be met. In determining whether the criteria are met for our operations,
our management makes significant judgments, which involve (i) determining whether rates for services provided to customers are subject to approval by an
independent, third-party regulator, (ii) determining whether the regulated rates are designed to recover specific costs of providing the regulated service,
(iii) considering relevant historical precedents and recent decisions of the regulatory authorities and (iv) considering the fact that decisions made by
regulatory commissions or legislative changes at a later date could vary from earlier interpretations made by management and that the impact of such
variations could be material. Our regulated subsidiaries have deferred recognition of costs (a regulatory asset) or have recognized obligations (a regulatory
liability) if it is probable that such costs will be recovered or obligations relieved in the future through the ratemaking process. Management regularly
reviews our regulatory assets and liabilities to determine whether adjustments to its previous conclusions are necessary based on the current regulatory
environment as well as recent rate orders. If our regulated subsidiaries, or a portion of their assets or operations, were to cease meeting the criteria for
application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously
deferred costs would be required in the year in which such criteria are no longer met.
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Accounting for Pensions and Other Post-retirement Benefits
We provide pensions and other post-retirement benefits for a significant number of employees, former employees and retirees. We account for these
benefits in accordance with the accounting rules for retirement benefits. In accounting for its pension and other post-retirement benefit plans, or the
AVANGRID plans, assumptions are made regarding the valuation of benefit obligations and the performance of plan assets. Delayed recognition of
differences between actual results and those assumed allows for a smoother recognition of changes in benefit obligations and plan performance over the
working lives of the employees who benefit under the AVANGRID plans. The primary assumptions include the discount rate, the expected return on plan
assets, health care cost trend rate, mortality assumptions and demographic assumptions. We apply consistent estimation techniques regarding our actuarial
assumptions, where appropriate, across the AVANGRID plans of our operating subsidiaries. The estimation technique utilized to develop the discount rate for
the AVANGRID plans is based upon the settlement of such liabilities as of December 31, 2015 utilizing a hypothetical portfolio of actual, high quality
bonds, which would generate cash flows required to settle the liabilities. We believe such an estimate of the discount rate accurately reflects the settlement
value for plan obligations and results in cash flows which closely match the expected payments to participants.
We reflect all unrecognized prior service costs and credits and unrecognized actuarial gains and losses for the regulated utilities of Networks as
regulatory assets or liabilities as it is probable that such items will be recovered through the ratemaking process in future periods.
During 2015, the Society of Actuaries issued updated mortality tables and projection scales. AVANGRID, in conjunction with its actuaries, performed
an analysis to determine the appropriateness of adopting these tables and the related mortality projections. As a result, our pension and post-retirement plan
liabilities as of December 31, 2015 reflect updated mortality assumptions.
Business Combinations
We apply the acquisition method of accounting to account for business combinations. The consideration transferred for an acquisition is the fair value
of the assets transferred, the liabilities incurred by the acquirer to former owners of acquiree and the equity interests issued by the acquirer. Acquisition
related costs are expensed as incurred. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured
initially at their fair values at the acquisition date. The excess of the consideration transferred over the fair value of the identifiable net assets acquired is
recorded as goodwill.
Goodwill
Goodwill is not amortized, but is subject to an assessment for impairment at least annually or more frequently if events occur or circumstances change
that will more likely than not reduce the fair value of the reporting unit below its carrying amount. A reporting unit is an operating segment or one level
below an operating segment and is the level at which goodwill is tested for impairment.
In assessing goodwill for impairment, we have the option of first performing a qualitative assessment to determine whether a quantitative assessment is
necessary, or step zero. If it is determined, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not greater than the
carrying amount, no further testing is required. If we bypass step zero or perform the qualitative assessment but determine that it is more likely than not that
its fair value is less than its carrying amount, a quantitative two step, fair value based test is performed. Step one compares the fair value of the reporting unit
to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, step two is performed. Step two requires an
allocation of fair value to the individual assets and liabilities using business combination accounting guidance to determine the implied fair value of
goodwill. If the implied fair value of goodwill is less than its carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to
operating expense.
Our step zero qualitative assessment involves evaluating key events and circumstances that could affect the fair value of our reporting units, as well as
other factors. Events and circumstances evaluated include macroeconomic conditions, industry, regulatory and market considerations, cost factors and their
effect on earnings and cash flows, overall financial performance as compared with projected results and actual results of relevant prior periods, other relevant
entity specific events, and events affecting a reporting unit.
Our step one impairment testing, and step two if required, includes various assumptions, primarily the discount rate, which is based on an estimate of
our marginal, weighted average cost of capital, and forecasted cash flows. We test the reasonableness of the conclusions of our step one impairment testing
using a range of discount rates and a range of assumptions for long term cash flows.
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Renewables
Based on the results of our step one impairment test for Renewables, conducted in 2015, its estimated fair value exceeds carrying value by
approximately 1.55%. Due to this 1.55% excess of fair value over carrying value in step one, step two calculations were performed according to the operating
plans of the reporting unit, in order to assess whether a potential material impairment charge may be recognized in the near term.
The current operating plans of Renewables include significant assumptions and estimates associated with revenue growth, profitability and related
cash flows, along with cash flows associated with taxes and capital expenditures. In addition, our projections contemplate the continuation of renewable
energy projects in the future. The discount rate used to estimate fair value was risk-adjusted to consider economic conditions of Renewables, the reporting
unit. We also considered other assumptions that market participants may use. By their nature, projections are uncertain. Potential events and circumstances,
such as declining wind energy output and prices obtained per kWh, changes in government incentives established to promote renewable energies and
increases in capital expenditures per MW could have an adverse effect on our assumptions.
The conclusion of the step two analysis is that the implied fair value of the goodwill within Renewables is 1.28x of its carrying amount as of
December 31, 2015. Management will continue to monitor the performance of the reporting unit and any potential implications on goodwill.
Impairment of Long Lived Assets
We evaluate property, plant, and equipment and other long lived assets for impairment when events or changes in circumstances indicate that the
carrying amount may not be recoverable. An impairment loss is required to be recognized if the carrying amount of the asset exceeds the undiscounted future
net cash flows associated with that asset.
We determine the fair value of a long-lived asset (asset group) by applying the approaches prescribed under the fair value measurement accounting
framework. Generally, the market approach and income approach are most relevant in the fair value measurement of our long-lived assets; however, due to the
lack of available relevant observable market information in many circumstances, we often rely on the income approach. We develop the underlying
assumptions consistent with our internal budgets and forecasts for such valuations. We use an internal discounted cash flow valuation model, or the DCF
model, based on the principles of present value techniques, to estimate the fair value of our long-lived assets under the income approach. The DCF model
estimates fair value by discounting AVANGRID’s cash flow forecasts at an appropriate discount rate. Management applies considerable judgment in
selecting several input assumptions during the development of our internal budgets and cash flow forecasts. Examples of the input assumptions that our
budgets and forecasts are sensitive to include macroeconomic factors such as growth rates, industry demand, inflation, power prices and commodity prices.
Whenever appropriate, management obtains these input assumptions from observable market data sources and extrapolates the market information if an input
assumption is not observable for the entire forecast period. Many of these input assumptions are dependent on other economic assumptions, which are often
derived from statistical economic models with inherent limitations such as estimation differences. Further, several input assumptions are based on historical
trends which often do not recur. The input assumptions most significant to our budgets and cash flows are based on expectations of macroeconomic factors
which may be volatile. The use of a different set of input assumptions could produce significantly different budgets and cash flow forecasts.
A considerable amount of judgment is also applied in the estimation of the discount rate used in the DCF model. To the extent practical, inputs to the
discount rate are obtained from market data sources.
Fair value of a long-lived asset (asset group) is sensitive to both input assumptions related to our budgets and cash flow forecasts and the discount rate.
Further, estimates of long-term growth and terminal value are often critical to the fair value determination. As part of the impairment evaluation process,
management analyzes the sensitivity of fair value to various underlying assumptions. The level of scrutiny increases as the gap between fair value and
carrying amount decreases. Changes in any of these assumptions could result in management reaching a different conclusion regarding the potential
impairment, which could be material. Our impairment evaluations inherently involve uncertainties from uncontrollable events that could positively or
negatively impact the anticipated future economic and operating conditions.
Capitalization and Recovery of Project Development Costs
Development and construction of our various facilities are carried out in stages. Project costs are expensed during early stage development activities.
Once certain development milestones are achieved and it is probable that we can obtain future economic benefits from a project, salaries and wages for
persons directly involved in the project, and engineering, permits, licenses, wind measurement and insurance costs are capitalized.
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Development projects in construction are reviewed periodically for any indications of impairment. Furthermore, we assess the recoverability of
development costs that have been capitalized using several criteria to assess economic recoverability and probability of future economic benefit including
energy prices, government regulation, and the internal rate of return to be earned on the project. If based on these factors, we conclude that we will not
proceed with the related project, or that the project is no longer viable, the cost of the project is expensed in full.
Fair Value Measurement
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of
the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place in
either the principal market for the asset or liability, or, in the absence of a principal market, in the most advantageous market for the asset or liability.
We use valuation techniques and methodologies that maximize the use of observable inputs and minimize the use of unobservable inputs. Where
available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices are not available,
valuation models are applied to estimate the fair value using the available observable inputs. The valuation techniques involve some level of management
estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.
To increase consistency and enhance disclosure of the fair value of financial instruments, the fair value measurement standard includes a fair value
hierarchy to prioritize the inputs used to measure fair value into three categories. An asset or liabilitys level within the fair value hierarchy is based on the
lowest level of input significant to the fair value measurement, where Level 1 is the highest and Level 3 is the lowest.
Income Tax
For the 2015 tax year, AVANGRID will file a consolidated federal income tax return, which will include the UIL taxable income or loss for the period
from December 17, 2015 to December 31, 2015. UIL will file a separate consolidated federal income tax return for the period from January 1, 2015 to
December 16, 2015.
AVANGRID filed a consolidated federal income tax return that includes the taxable income or loss of all its subsidiaries (excluding UIL), including
ARHI, which are 80% or more owned for the 2014 tax period. UIL filed separate consolidated federal income tax returns including the income or loss of its
subsidiaries for all tax years including the most recently filed 2014 return.
AVANGRID (excluding ARHI and UIL), and ARHI filed separate consolidated federal income tax returns that included the taxable income or loss of
all their respective subsidiaries, which are 80% or more owned, for all tax periods prior to 2013.
In addition, a consolidated federal income tax return, that included the taxable income or loss of ARHI and all of its subsidiaries for the entire 2013
tax year and the taxable income or loss of AVANGRID (without UIL), and all of its subsidiaries for the tax period of November 21, 2013 through December
31, 2013, was filed.
For the period of January 1, 2013 through November 20, 2013, AVANGRID (excluding ARHI and UIL) filed a consolidated federal income tax return
that included the taxable income or loss of all its subsidiaries, which are 80% or more owned.
We use the liability method of accounting for income taxes. Deferred tax assets and liabilities reflect the expected future tax consequences based on
enacted tax law of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts. In accordance with U.S. GAAP
for regulated industries, our regulated subsidiaries have established a regulatory asset for the net revenue requirements to be recovered from customers for the
related future tax expense associated with certain of these temporary differences. The investment tax credits are deferred when used and amortized over the
estimated lives of the related assets.
Deferred tax assets and liabilities are measured at the expected tax rate for the period in which the asset or liability will be realized or settled, based on
legislation enacted as of the balance sheet date. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged
or credited directly to OCI. Significant judgment is required in determining income tax provisions and evaluating tax positions. Our tax positions are
evaluated under a more-likely-than-not recognition threshold before they are recognized for financial reporting purposes. Valuation allowances are recorded
to reduce deferred tax assets when it is not more-likely-than not that all or a portion of a tax benefit will be realized.
The excess of state franchise tax computed as the higher of a tax based on income or a tax based on capital is recorded inTaxes other than income
taxes” and Taxes accrued” in the accompanying combined and consolidated financial statements.
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Positions taken or expected to be taken on tax returns, including the decision to exclude certain income or transactions from a return, are recognized
in the financial statements when it is more likely than not the tax position can be sustained based solely on the technical merits of the position. The amount
of a tax return position that is not recognized in the financial statements is disclosed as an unrecognized tax benefit. Changes in assumptions on tax benefits
may also impact interest expense or interest income and may result in the recognition of tax penalties. Interest and penalties related to unrecognized tax
benefits are recorded within “Interest expense, net of capitalization and “Other income and (expense) of the combined and consolidated statements of
operations.
Uncertain tax positions have been classified as noncurrent unless expected to be paid within one year. Our policy is to recognize interest and penalties
on uncertain tax positions as a component of interest expense in the combined and consolidated statements of operations.
Federal production tax credits applicable to our renewable facilities, that are not part of a tax equity financing arrangement, are shown in the financial
statements as a reduction in Income tax expense and as a reduction in deferred income tax liabilities.
Our income tax expense, deferred tax assets and liabilities, and liabilities for unrecognized tax benefits reflect management’s best assessment of
estimated current and future taxes to be paid. Significant judgments and estimates are required in determining the consolidated income tax components of
the financial statements.
Off-Balance Sheet Arrangements
At December 31, 2015, we had approximately $2.4 billion of standby letters of credit, surety bonds, guarantees and indemnifications
outstanding. These instruments provide financial assurance to the business and trading partners of the company and its subsidiaries in their normal course of
business. The instruments only represent liabilities if the company or its subsidiaries fail to deliver on contractual obligations. We therefore believe it is
unlikely that any material liabilities associated with these instruments will be incurred and, accordingly, at December 31, 2015, neither the company nor its
subsidiaries have any liabilities recorded for these instruments.
New Accounting Standards
Simplifying the Presentation of Debt Issuance Costs - In April 2015the FASB issued an amendment that is intended to simplify the presentation of
debt issuance costs.
Balance Sheet Classification of Deferred Taxes - In November 2015 the FASB issued an amendment that is intended to simplify the presentation of
deferred income taxes by requiring entities that present a classified statement of financial position to classify deferred tax liabilities and assets as noncurrent
in their balance sheet.
Pushdown Accounting - In November 2014 the FASB issued an amendment on when and how an acquired entity that is a business or nonprofit
activity, whether public or nonpublic, can apply pushdown accounting in its separate financial statements upon the occurrence of an event in which an
acquirer, either an individual or an entity, obtains control of the acquired entity.
Discontinued Operations and Disposals of Components of an Entity - In April 2014 the FASB issued an amendment that changed the requirements for
the reporting of discontinued operations.
Revenue from Contracts with Customers - In May 2014 the FASB issued an amendment related to the recognition of revenue from contracts with
customers and required disclosures.
Presentation of an Unrecognized Tax Benefit - In July 2013 the FASB issued guidance on the financial statement presentation of an unrecognized tax
benefit when a net operating loss, or NOL, carryforward, a similar tax loss, or a tax credit carryforward exists.
Fair Value Measurement Disclosures for Certain Investments - In May 2015 the FASB issued amendments that affect reporting entities that elect to
estimate the fair value of certain investments within scope using the net asset value, or NAV, per share (or its equivalent) practical expedient, as specified.
Simplifying the Measurement of Inventory - In July 2015 the FASB issued amendments that require entities to measure inventory at the lower of cost
and net realizable value, rather than the lower of cost or market.
Application of the Normal Purchases and Normal Sales Scope Exception - In August 2015 the FASB issued amendments to specify that the use of
locational marginal pricing by an ISO does not constitute net settlement of a contract for the purchase or sale of
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electricity on a forward basis that necessitates transmission through, or delivery to a location within, a nodal energy market, even when legal title to the
associated electricity is conveyed to the ISO during transmission.
Classifying and Measuring Financial Instruments - In January 2016 the FASB issued final guidance on the classification and measurement of
financial instruments.
Simplifying the Accounting for Measurement-Period Adjustments - In September 2015 the FASB issued amendments that require an acquirer to
recognize adjustments to provisional amounts relating to a business combination that are identified during the measurement period in the reporting period in
which the adjustment amounts are determined.
Leases - In February 2016 the FASB issued new guidance that affects all companies and organizations that lease assets, and requires them to record on
their balance sheet assets and liabilities for the rights and obligations created by those leases.
Derivative contract novations - In March 2016 the FASB issued amendments concerning the effect of derivative contract novations on existing hedge
accounting relationships.
For further discussion of new accounting pronouncements affecting AVANGRID refer to Note 3 of our audited combined and consolidated
financial statements for the three years ended December 31, 2015, which are incorporated herein by reference.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
We are exposed to risks associated with adverse changes in commodity prices, interest rates and equity prices. Financial instruments and positions
affecting our financial statements described below are held primarily for purposes other than trading. Market risk is measured as the potential loss in fair
value resulting from hypothetical reasonably possible changes in commodity prices, interest rates or equity prices over the next year. Management has
established risk management policies to monitor and manage such market risks, as well as credit risks.
Commodity Price Risk
Renewables and Gas face a number of energy market risk exposures, including fixed price, basis (both location and time), and heat rate risk.
Long-term supply contracts reduce our exposure to market fluctuations. We have electricity commodity purchases and sales contracts for energy
(physical contracts) that have been designated and qualify for the normal purchase normal sale exemption in accordance with the accounting requirements
concerning derivative instruments and hedging activities.
Renewables merchant wind facilities are subject to fixed price power risk, which is hedged with fixed price power trades. Its combined cycle power
plant is subject to heat rate risk, which is hedged with fixed price power and fixed price gas and basis positions. Contracted natural gas storage exposures are
affected by gas price differentials across time. We manage this exposure with fixed price, basis, and index gas derivatives. In addition, contracted transport
positions are subject to gas price risk across location (i.e., the price differentials between the receipt and delivery points associated with the leased pipelines).
We hedge this exposure with basis swaps. Those measures mitigate our commodity price exposure, but do not completely eliminate it.
Renewables and Gas use a Monte Carlo Simulation Value-at-Risk, or VaR, technique to measure and control the level of risk it undertakes. VaR is a
statistical technique used to measure and quantify the level of risk within a portfolio over a given timeframe and within a specified level of confidence. VaR
is primarily composed of three variables: the measured amount of potential loss, the probability of not exceeding the amount of potential loss, and the
portfolio holding period.
Renewables and Gas use a 99% probability level over a five-day holding period, indicating that it can be 99% confident that losses over five days
would not exceed that value. The average VaR for 2015 was $14.0 million compared to a 2014 average of $12.5 million.
As noted above, VaR is a statistical technique and is not intended to be a guarantee of the maximum loss ARHI may incur.
Networks also experiences commodity price risk, due to volatility in the wholesale energy markets. Networks manages that risk through a combination
of regulatory mechanisms, such as the pass-through of the market price of electricity and natural gas to customers, and through comprehensive risk
management processes. Those measures mitigate our commodity price exposure, but do not completely eliminate it. Networks also uses electricity contracts,
both physical and financial, to manage fluctuations in electricity
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commodity prices in order to provide price stability to customers. It also uses natural gas futures and forwards to manage fluctuations in natural gas
commodity prices in order to provide price stability to customers. It includes the cost or benefit of those contracts in the amount expensed for electricity or
natural gas purchased when the related electricity is sold.
Because all gains or losses on Networks’ commodity contracts will ultimately be passed on to retail customers, no sensitivity analysis is performed for
Networks. Further information regarding the derivative financial instruments and sensitivity analysis is provided in Notes 11 and 12 of our audited combined
and consolidated financial statements for the three years ended December 31, 2015, which are incorporated herein by reference.
Interest Rate Risk
Total debt outstanding, including tax equity of $292 million and borrowings under the UIL Credit Facility of $163 million, was $5.2 billion at
December 31, 2015 of which $461 million had a floating interest rate; a change of 25 basis points in this interest rate would result in an interest expense
fluctuation of approximately $1.0 million annually. The estimated fair value of our debt excluding the debt associated with capital leases and tax equity at
December 31, 2015 was $4.9 billion, in comparison to a book value of $4.7 billion.
There are no interest rate derivative contracts outstanding at December 31, 2015 and 2014.
Pension and Post-Retirement Plans
We provide pensions and other post-retirement benefits for a significant number of employees, former employees and retirees. In applying relevant
accounting policies, we have made critical estimates related to actuarial assumptions, including assumptions of expected returns on plan assets, discount
rates, health care cost trends and future compensation. The cost of pension and other post-retirement benefits in future periods will depend on actual returns
on plan assets, assumptions for future periods, contributions and benefit experience. In 2015, we contributed $27 million to our pension plans. Our
contribution to the pension plans in 2016 is expected to be approximately $21 million.
The discount rate used in accounting for pension and other benefit obligations in 2015 ranged from 3.80% to 3.90%. The expected rate of return on
plan assets for qualified pension benefits in 2015 ranged from 5.50% to 7.50%. The following tables reflect the estimated sensitivity associated with a change
in certain significant actuarial assumptions (each assumption change is presented mutually exclusive of other assumption changes):
Impact on 2015
Pension Expense
Increase (Decrease)
Change in
Assumption
Pension
Benefits
Post
Retirement
(in millions)
Increase in discount rate
50 basis points
$ 13 $ 2
Decrease in discount rate 50 basis points (13) (2)
Increase in return on plan asset 50 basis points 11 1
Decrease in return on plan asset 50 basis points (11) (1)
Credit Risk
This risk is defined as the risk that a third party will not fulfill its contractual obligations and, therefore, generate losses for AVANGRID. Networks is
exposed to nonpayment of customer bills. Standard debt recovery procedures are in place, in accordance with best practices and in compliance with
applicable state regulations and embedded tariff mechanisms to manage uncollectable expense. Our credit department, based on guidelines approved by our
board, establishes and manages its counterparty credit limits. We have developed a matrix of unsecured credit thresholds that are dependent on a
counterpartys or the counterparty guarantor’s applicable credit rating. Credit risk is mitigated by contracting with multiple counterparties and limiting
exposure to individual counterparties or counterparty families to clearly defined limits based upon the risk of counterparty default. At the counterparty level,
we employ specific eligibility criteria in determining appropriate limits for each prospective counterparty and supplement this with netting and collateral
agreements, including margining, guarantees, letters of credit, and cash deposits, where appropriate.
Renewables and Gas are also exposed to credit risk through their energy marketing and trading operations. We manage counterparty credit risk for our
subsidiaries with energy marketing and trading operations through established policies, including
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counterparty credit limits, and in some cases credit enhancements, such as cash prepayments, letters of credit, cash and other collateral and guarantees.
Some relevant considerations when assessing the credit risk exposure of the energy marketing and trading operations follows:
·
Operations are primarily concentrated in the energy industry.
·
Trade receivables and other financial instruments are predominately with energy, utility and financial services related companies, as well as
municipalities, cooperatives and other trading companies in the U.S.
·
Overall credit risk is managed through established credit policies by a Credit Risk Management group that is independent of the energy
marketing and trading functions.
·
Prospective and existing customers are reviewed for creditworthiness based upon established standards, with customers not meeting minimum
standards providing various credit enhancements or secured payment terms, such as letters of credit or the posting of margin cash collateral.
·
Master netting agreements are used, where appropriate, to offset cash and non-cash gains and losses arising from derivative instruments with the
same counterparty.
Based on our policies and risk exposures related to credit risk from its energy marketing and trading operations in ARHI, we do not anticipate a
material adverse effect on our financial statements as a result of counterparty nonperformance. As of December 31, 2015, approximately 98% of our energy
marketing and trading counterparty credit risk exposure is associated with companies that have investment grade credit ratings.
The following table displays the credit quality of our trading counterparties as of December 31, 2015:
Credit Exposure
Before Cash
Collateral
Cash
Collateral
Net
Credit
Exposure
(in millions)
Investment Grade(1) $ 2,719 $ $ 2,719
A- and Greater 2,051 2,051
BBB+ and BBB 556 556
BBB- 112 112
Total Investment Grade 2,719 2,719
Non-investment grade(2) (3) (4) 54 4 50
Total $ 2,773 $ 4 $ 2,769
(1) This category includes counterparties with minimum credit ratings of Baa3 assigned by Moodys and BBB- assigned by Standard & Poor’s, if rated by both agencies. The five
largest counterparty exposures, combined, for this category represented approximately 36.9% of the total gross credit exposure.
(2) This category includes counterparties with credit ratings that are below investment grade. The five largest counterparty exposures, combined, for this category represented
approximately 0.2% of the total gross credit exposure.
(3) This category includes counterparties that have not been rated by Moodys or Standard & Poors, but are considered investment grade based on our evaluation of the
counterparty’s creditworthiness. The five largest counterparty exposures, combined, for this category represented approximately 0.9% of the total gross credit exposure.
(4) This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, and are considered non-investment grade based on our evaluation of the
counterparty’s creditworthiness. The five largest counterparty exposures, combined, for this category represented approximately 0.5% of the total gross credit exposure.
Treasury Management (including Liquidity Risk)
We manage our overall liquidity position as part of the broader Iberdrola Group and are a party to a notional cash pooling agreement with Bank
Mendes Gans, N.V., or BMG, along with other Iberdrola, S.A. subsidiaries. We optimize our liquidity within the United States through a series of arms’-length
intercompany lending arrangements with our subsidiaries and among the regulated utilities to provide for lending of surplus cash to subsidiaries with
liquidity needs, subject to the limitation that the regulated utilities may not lend to unregulated affiliates. These arrangements minimize overall short-term
funding costs and maximize returns on the temporary cash investments of the subsidiaries. We have the capacity to borrow from third parties through three
separate credit facilities totaling $1.3 billion. For more information, see the section entitled “—Liquidity and Capital Resources—Liquidity Resources” of
this Form 10-K.
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Networks
Networks’ regulated utilities fund their operations independently, except to the extent that they borrow on a short-term basis from unregulated
affiliates and from each other when circumstances warrant in order to minimize short-term funding costs and maximize returns on temporary cash investments.
The regulated utilities are prohibited by regulatory order from lending to unregulated affiliates. Networks’ regulated utilities each independently access the
investment grade debt capital markets for long-term funding and each are borrowers under committed credit facilities described in “—Liquidity and Capital
Resources—Liquidity Resources” of this Form 10-K.
Networks’ regulated utilities are subjected by regulatory order to certain credit quality maintenance measures, including minimum equity ratios, that
are linked to the level of equity assumed in the establishment of revenue requirements. The companies maintain their equity ratios at or above the minimum
through dividend declarations or, when necessary, capital contributions from AVANGRID.
Renewables
Renewables has historically funded itself through a combination of normal operations and through equity contributions from Iberdrola, S.A. The last
such equity contribution of $800 million was made in February 2013. Renewables has also raised a small percentage of its capital through tax equity
partnerships, project loans and sale-leaseback arrangements. The balance of the outstanding tax equity financing arrangement at December 31, 2015 was
$292 million and the balance of leases and project financing was $62 million. During 2015, Renewables authorized dividend payments of $1.4 billion to
AVANGRID, of which $950 million was in cash ($750 million paid in 2015) and the remainder in financial instruments.
Item 8. Financial Statements and Supplementary Data
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Avangrid, Inc.
We have audited the accompanying consolidated balance sheets of Avangrid, Inc. and subsidiaries (the “Company”) as of December 31, 2015 and 2014, and
the related combined and consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for each of the three years in
the period ended December 31, 2015. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements
and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule
based on our audits. We did not audit the consolidated balance sheet of UIL Holdings Corporation, a wholly-owned subsidiary acquired in 2015, which
statement reflects total assets of $5,270 million as of December 31, 2015. That balance sheet was audited by other auditors whose report has been furnished
to us, and our opinion, insofar as it relates to the balance sheet amounts included for UIL Holdings Corporation, is based solely on the report of 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. We were not engaged
to perform an audit of the Companys internal control over financial reporting. Our audits included consideration of internal control over financial reporting
as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the
Companys internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management,
and evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our
opinion.
In our opinion, based on our audits and, as to the balance sheet at December 31, 2015, the report of other auditors, the financial statements referred to above
present fairly, in all material respects, the consolidated financial position of Avangrid, Inc. and subsidiaries at December 31, 2015 and 2014, and the
combined and consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, 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
financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Ernst & Young, LLP
New York, New York
April 1, 2016
81
Independent Auditor’s Report
To the Board of Directors of UIL Holdings Corporation.
In our opinion, the consolidated balance sheet (not presented herein) presents fairly, in all material respects, the financial position of UIL Holdings
Corporation and its subsidiaries at December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. The
balance sheet is the responsibility of the Companys management. Our responsibility is to express an opinion on the balance sheet based on our audit. We
conducted our audit of this statement in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in
accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the
amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the
overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Boston, MA
April 1, 2016
82
AVANGRID, Inc. and Subsidiaries
Combined and Consolidated Statements of Operations
Years Ended December 31, 2015 2014 2013
(Millions, except for number of shares and per share data)
Operating Revenues $ 4,367 $ 4,594 $ 4,313
Operating Expenses
Purchased power, natural gas and fuel used 972 1,181 1,088
Operations and maintenance 1,808 1,560 1,541
Impairment of non-current assets 12 25 620
Depreciation and amortization 695 629 594
Taxes other than income taxes 367 314 291
Total Operating Expenses 3,854 3,709 4,134
Operating Income 513 885 179
Other Income and (Expense)
Other income and (expense) 55 52 54
Earnings (losses) from equity method investments 12 (3)
Interest expense, net of capitalization (267 ) (243 ) (245 )
Income (Loss) Before Income Tax 301 706 (15)
Income tax expense 34 282 35
Net Income (Loss) 267 424 (50)
Less: Net income attributable to noncontrolling interests 1
Net Income (Loss) Attributable to AVANGRID, Inc. $ 267 $ 424 $ (51 )
Earnings (Loss) Per Common Share, Basic: $ 1.05 $ 1.68 $ (0.20)
Earnings (Loss) Per Common Share, Diluted: $ 1.05 $ 1.68 $ (0.20)
Weighted-average Number of Common Shares Outstanding:
Basic 254,588,212 252,235,232 252,235,232
Diluted 254,605,111 252,235,232 252,235,232
The accompanying notes are an integral part of our combined and consolidated financial statements.
83
AVANGRID, Inc. and Subsidiaries
Combined and Consolidated Statements of Comprehensive Income (Loss)
Years Ended December 31, 2015 2014 2013
(Millions)
Net Income (Loss) $ 267 $ 424 $ (50 )
Other Comprehensive Income
Amounts arising during the year:
Gain on defined benefit plans, net of income taxes of $2.2, $0.6 and $0.5,
respectively 4 1 1
Amortization of pension cost for nonqualified plans, net of income taxes of $1.7,
($1.9) and $1.0, respectively 3 (3 ) (1)
Unrealized gain (loss) during the year on derivatives qualifying
as cash flow hedges, net of income taxes of $20.9, ($1.4) and $0, respectively 33 (2)
Reclassification to net income of losses on cash flow hedges, net of income taxes of
$4.9, $4.1 and $4.6, respectively 7 5 7
Other Comprehensive Income 47 1 7
Comprehensive Income (Loss) 314 425 (43)
Less:
Comprehensive income attributable to noncontrolling interests 1
Comprehensive Income (Loss) attributable to AVANGRID, Inc. $ 314 $ 425 $ (44)
The accompanying notes are an integral part of our combined and consolidated financial statements.
84
AVANGRID, Inc. and Subsidiaries
Consolidated Balance Sheets
As of December 31, 2015 2014
(Millions)
Assets
Current Assets
Cash and cash equivalents $ 427 $ 482
Accounts receivable and unbilled revenues, net 974 841
Accounts receivable from affiliates 70 50
Notes receivable from affiliates 6
Derivative assets 88 134
Fuel and gas in storage 307 229
Materials and supplies 98 98
Prepayments and other current assets 285 288
Regulatory assets 219 80
Total Current Assets 2,474 2,202
Property, plant and equipment, at cost 25,745 21,499
Less: accumulated depreciation (6,372 ) (5,762)
Net Property, Plant and Equipment in Service 19,373 15,737
Construction work in progress 1,338 1,396
Total Property, Plant and Equipment 20,711 17,133
Equity method investments 385 262
Other investments 64 91
Regulatory assets 3,314 2,399
Other Assets
Goodwill 3,115 1,361
Intangible assets 556 569
Derivative assets 89 93
Other 35 52
Total Other Assets 3,795 2,075
Total Assets $ 30,743 $ 24,162
The accompanying notes are an integral part of our combined and consolidated financial statements.
85
AVANGRID, Inc. and Subsidiaries
Consolidated Balance Sheets
As of December 31, 2015 2014
(Millions, except share information)
Liabilities
Current Liabilities
Current portion of debt $ 206 $ 148
Tax equity financing arrangements 107 124
Notes payable 163
Interest accrued 61 39
Accounts payable 830 684
Accounts payable to affiliates 90 239
Taxes accrued 55 8
Derivative liability 91 103
Other current liabilities 285 262
Regulatory liabilities 147 165
Total Current Liabilities 2,035 1,772
Regulatory liabilities 1,841 1,229
Deferred income taxes regulatory 519 433
Other Non-current Liabilities
Deferred income taxes 2,798 2,269
Deferred income 1,553 1,621
Pension and other postretirement 1,202 785
Tax equity financing arrangements 185 277
Derivative liability 94 38
Asset retirement obligations 184 234
Environmental remediation costs 406 284
Other 330 254
Total Other Non-current Liabilities 6,752 5,762
Non-current Debt 4,530 2,489
Total Non-current Liabilities 13,642 9,913
Total Liabilities 15,677 11,685
Commitments and Contingencies
Equity
Stockholders' Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 309,491,082 and 252,235,232 shares
issued; 308,864,609 and 252,235,232 shares outstanding, respectively 3 3
Additional paid-in capital 13,653 11,375
Retained earnings 1,449 1,182
Accumulated other comprehensive loss (52 ) (99)
Total Stockholders' Equity 15,053 12,461
Noncontrolling interests 13 16
Total Equity 15,066 12,477
Total Liabilities and Equity $ 30,743 $ 24,162
The accompanying notes are an integral part of our combined and consolidated financial statements.
86
AVANGRID, Inc. and Subsidiaries
Combined and Consolidated Statements of Cash Flows
Years Ended December 31, 2015 2014 2013
(Millions)
Cash Flow from Operating Activities
Net income (loss) $ 267 $ 424 $ (50)
Adjustments to reconcile net income (loss) to net cash provided by
operating activities
Depreciation and amortization 695 629 594
Impairment of non-current assets 12 25 620
Accretion expenses 14 14 14
Regulatory assets/liabilities amortization 101 (38) (2)
Regulatory assets/liabilities carrying cost 41 35 21
Pension cost 115 74 96
(Earnings) losses from equity method investments (12) 3
Unrealized losses (gains) on marked to market derivative contracts 10 (116) 4
Deferred taxes 87 261 58
Changes in current operating assets and liabilities, net of effects of acquisition
Decrease (increase) in accounts receivable and unbilled revenues 160 (1) 56
Decrease (increase) in inventories 4 58 (1)
Decrease in other assets (42) (101) (126)
(Decrease) increase in accounts payable (10) 27 (208)
(Decrease) increase in other liabilities (188) (110) 123
Increase (decrease) in taxes accrued 21 (13) 2
Increase (decrease) in regulatory assets/liabilities 74 175 (27)
Net Cash provided by Operating Activities 1,361 1,331 1,177
Cash Flow from Investing Activities
Capital expenditures (1,082) (1,030) (944)
Proceeds from disposal of property, plant and equipment 2
Contributions in aid of construction 38 43 24
Government grants 17 4 31
Acquisition of business, net of $48 million cash acquired (547)
Proceeds from sale of businesses, net of cash 3 31
(Payments to) receipts from affiliates (6) 10
Other investments and equity method investments 59 54 19
Net Cash used in Investing Activities (1,518) (888) (868)
Cash Flow from Financing Activities
Capital contributions from Parent 153
Non-current note issuance 350 225
Repayments of non-current debt (141) (27) (273)
Proceeds (repayments) of other short-term debt, net 10 (14) (165)
Proceeds from sales leaseback 110
Repayments of capital leases (12) (21) (21)
Payments on tax equity financing arrangements (102) (119) (173)
Contribution from noncontrolling interests 4
Dividends to noncontrolling interests (3) (3)
Net Cash Provided by (used in) Financing Activities 102 (180) (144)
Net (Decrease) Increase in Cash and Cash Equivalents (55) 263 165
Cash and Cash Equivalents, Beginning of Year 482 219 54
Cash and Cash Equivalents, End of Year $ 427 $ 482 $ 219
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized $ 132 $ 133 $ 147
Cash paid (refund) for income taxes 7 21 (30)
The accompanying notes are an integral part of our combined and consolidated financial statements.
87
AVANGRID, Inc. and Subsidiaries
Combined and Consolidated Statements of Changes in Equity
AVANGRID, Inc. Stockholders
(Millions, except for number of shares)
Number of
shares (*)
Common
stock
Additional
paid-in
capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
Stockholders'
Equity
Noncontro-
lling Interests
Total
Equity
Balances, December 31, 2012
252,235,232 $ 3 $ 10,629 $ 809 $ (107 ) $ 11,334 $ 14
$ 11,348
Net income (loss)
(51) (51) 1
(50 )
Other comprehensive income, net of tax
of $6.1 7 7
7
Comprehensive loss
(43 )
Capital contribution
746 746
746
Balances, December 31, 2013
252,235,232 3 11,375 758 (100 ) 12,036 15
12,051
Net income
424 424
424
Other comprehensive income, net of tax
of $1.4 1 1
1
Comprehensive income
425
Capital contribution from noncontrolling
interests 4
4
Dividends to noncontrolling interests
(3)
(3 )
Balances, December 31, 2014
252,235,232 3 11,375 1,182 (99 ) 12,461 16
12,477
Net income
267 267
267
Other comprehensive income, net of tax
of $29.7 47 47
47
Comprehensive income
314
Issuance of common stock
57,255,850 2,278 2,278
2,278
Treasury stock
(626,473 )
Dividends to noncontrolling interests
(3)
(3 )
Balances, December 31, 2015
308,864,609 $ 3 $ 13,653 $ 1,449 $ (52 ) $ 15,053 $ 13
$ 15,066
(*) Par value of share amounts is $.01
The accompanying notes are an integral part of our combined and consolidated financial statements.
88
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements
Note 1. Background and Nature of Operations
AVANGRID, Inc., formerly Iberdrola USA, Inc. (AVANGRID, We or the Company), is an energy services holding company engaged through its principal
subsidiaries AVANGRID Networks, Inc. (Networks), UIL Holdings Corporation (UIL) and AVANGRID Renewables Holding, Inc. (ARHI) in the regulated
energy distribution, renewable energy generation (Renewables) and gas businesses (Gas), collectively (Renewables and Gas). AVANGRID is an 81.5% owned
subsidiary of Iberdrola, S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain. The remaining outstanding shares are publicly
traded on the New York Stock Exchange and owned by various shareholders. AVANGRID was organized in 1997 as Energy East Corporation under the laws
of New York as the holding company for the principal operating utility companies.
Reorganization
On November 20, 2013, we completed a series of reorganizations (Reorganization) of entities under common control. The Reorganization included the
transfer of ARHI from an affiliate of Iberdrola to AVANGRID, and the transfer of the principal operating utility companies from AVANGRID to Networks.
AVANGRID and ARHI were acquired by Iberdrola in 2008 and 2007, respectively, and they have been under common control of Iberdrola for all periods
presented. Networks was formed as part of the Reorganization in November 2013. Networks is a public utility sub-holding company operating under the
Public Utility Holding Company Act of 2005 with operations in New York and Maine. The wholly owned subsidiaries and the operating utility companies of
Networks include: CMP Group - Central Maine Power Company (CMP), RGS - New York State Electric & Gas Corporation (NYSEG), Rochester Gas &
Electric Corporation (RGE) and Maine Natural Gas Company (MNG). ARHI is the sub-holding company of the unregulated energy business that includes the
renewable energy and the gas trading and storage businesses.
The transfer of a business among entities under common control is accounted for at carrying amount with retrospective adjustment of prior period financial
statements similar to the manner in which a pooling-of-interest was accounted for under accounting principles generally accepted in the United States of
America (U.S.GAAP).
Acquisition of UIL
On December 16, 2015 (acquisition date), UIL Holdings Corporation, a Connecticut corporation (UIL), became a wholly-owned subsidiary of AVANGRID as
a result of the merger of Green Merger Sub, Inc., a Connecticut corporation and a wholly-owned subsidiary of AVANGRID (Merger Sub), with UIL, with
Merger Sub surviving as a wholly-owned subsidiary of AVANGRID (the acquisition). The acquisition was effected pursuant to the Agreement and Plan of
Merger, dated as of February 25, 2015, by and among AVANGRID, Merger Sub, and UIL. Following the completion of the acquisition, Merger Sub was
renamed “UIL Holdings Corporation. In connection with the acquisition, we issued 309,490,839 shares of common stock of AVANGRID, out of which
252,234,989 shares were issued to Iberdrola through a stock dividend, accounted for as a stock split, with no change to par value, at par value of $0.01 per
share and 57,255,850 shares (including those held in trust as Treasury Stock) were issued to UIL shareowners in addition to payment of $10.50 in cash per
each share of the common stock of UIL issued and outstanding at the acquisition date. Following the completion of the acquisition, former UIL shareowners
owned 18.5% of the outstanding shares of common stock of AVANGRID and Iberdrola owned the remaining shares. See Note 4 Acquisition of UIL for
further details.
The regulated utility businesses of UIL consist of the electric distribution and transmission operations of The United Illuminating Company (UI) and the
natural gas transportation, distribution and sales operations of The Southern Connecticut Gas Company (SCG), Connecticut Natural Gas Corporation (CNG)
and The Berkshire Gas Company.
UI is also a party to a joint venture with certain affiliates of NRG Energy, Inc. (NRG affiliates) pursuant to which UI holds 50% of the membership interests in
GCE Holding LLC, whose wholly owned subsidiary, GenConn Energy LLC (collectively with GCE Holding LLC, GenConn) operates peaking generation
plants in Devon, Connecticut (GenConn Devon) and Middletown, Connecticut (GenConn Middletown).
89
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Note 2. Basis of Presentation
The accompanying combined and consolidated financial statements have been prepared in accordance with U.S GAAP and are presented on a combined basis
prior to the Reorganization, and on a consolidated basis subsequent to the Reorganization. For the periods prior to the Reorganization the combined
financial statements include AVANGRID, ARHI and Networks (combined entities) all of which were under common control of Iberdrola, and for the periods
subsequent to the Reorganization, the consolidated financial statements include AVANGRID and its consolidated subsidiaries Networks and ARHI until
December 16, 2015, and Networks, UIL and ARHI (consolidated entities) afterwards. The combined financial statements have been prepared on a combined
basis to allow for comparability with the consolidated financial statements for the periods subsequent to the Reorganization. All intercompany transactions
and accounts have been eliminated in all periods presented. All share and per share information included in the combined and consolidated financial
statements have been retroactively adjusted to reflect the impact of the stock dividend.
As a result of the common control transfers occurring as part of the Reorganization, management recorded the net assets of ARHI in these combined and
consolidated financial statements at the historical accounting basis of Iberdrola. The historical accounting basis of Iberdrola includes purchase accounting
adjustments related to Iberdrolas acquisition of ARHI in 2007. At the time of the Reorganization, the holding of Networks was not considered to be a
substantive operating entity as it did not hold any direct operations prior to it and the Networks businesses had always been a part of AVANGRID. As a result
the net assets of Networks in these combined and consolidated financial statements are recorded at the historical accounting basis of AVANGRID, which do
not include purchase accounting adjustments related to Iberdrolas acquisition of Energy East in 2008.
Immaterial corrections to prior periods
During the year ended December 31, 2015, we identified immaterial corrections to prior periods related to property, plant and equipment and depreciation
expense in our Renewables reportable segment. The corrections resulted in an overstatement of depreciation expense and an understatement of income tax
expense in the combined and consolidated statements of operations for the years ended December 31, 2013 and 2012. The recorded balances of accumulated
depreciation were likewise overstated with deferred income tax liabilities being understated in the consolidated balance sheets as of December 31, 2014,
2013 and 2012. We evaluated the effects of these corrections on prior periods’ combined and consolidated financial statements, individually and in the
aggregate, in accordance with the guidance in Accounting Standards Codification (ASC) Topic 250, Accounting Changes and Error Corrections, ASC Topic
250-10-S99-1, Assessing Materiality, and ASC Topic 250-10-S99-2, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in
Current Year Financial Statements, and concluded that no prior period is materially misstated. However, in accordance with the aforementioned ASC Topics,
we have determined to revise our combined and consolidated financial statements for the prior periods presented herein.
As a result of the correction, the cumulative effect of the change on retained earnings as of December 31, 2013 and 2012 was an increase of $21 million and
$7 million, respectively. Total assets, deferred income taxes, total other non-current liabilities, total non-current liabilities and total liabilities as reported in
the table below are shown after reclassifications discussed in Note 3 of these combined and consolidated financial statements. Net loss per common share as
reported in the table below is shown after retroactive application of stock split discussed in Note 17 of these combined and consolidated financial statements.
The revision had no net impact on our net cash provided by operating activities for the year ended December 31, 2013. The segment information related to
Renewables reportable segment as of and for the years ended December 31, 2014 and 2013 provided in Note 23 has also been revised to reflect these
corrections.
90
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
A summary of the effect of the correction on the consolidated balance sheet as of December 31, 2014 is as follows:
As of December 31, 2014 As Reported Correction As Revised
(Millions)
Accumulated depreciation $ (5,796) $ 34 $ (5,762)
Net Property, Plant and Equipment in Service 15,703 34 15,737
Total Property, Plant and Equipment 17,099 34 17,133
Total assets 24,128 34 24,162
Deferred income taxes 2,256 13 2,269
Total Other Non-current Liabilities 5,749 13 5,762
Total Non-current Liabilities 9,900 13 9,913
Total liabilities 11,672 13 11,685
Retained earnings 1,161 21 1,182
Total Stockholders' Equity 12,440 21 12,461
Total Equity 12,456 21 12,477
Total Liabilities and Equity $ 24,128 $ 34 $ 24,162
A summary of the effect of the correction on the combined and consolidated statement of operations for the year ended December 31, 2013 is as follows:
Year Ended December 31, 2013 As Reported Correction As Revised
(Millions, except per share data)
Depreciation and amortization $ 617 $ (23 ) $ 594
Total Operating Expenses 4,157 $ (23 ) 4,134
Operating income 156 23 179
Loss Before Income Tax (38) 23 (15)
Income tax expense 26 9 35
Net Loss (64 ) 14 (50)
Net Loss Per Common Share, Basic and Diluted:
$ (0.26)
$ (0.06)
$ (0.20 )
Note 3. Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates
Significant Accounting Policies
We consider the following policies to be the most critical in understanding the judgments that are involved in preparing our combined and consolidated
financial statements:
(a) Principles of consolidation and combination
We consolidate the entities in which we have a controlling financial interest, after the elimination of intercompany transactions. Investments in common
stock where we have the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting.
(b) Revenue recognition
Revenue from the sale of energy by our regulated utilities is recognized in the period during which the sale occurs. The calculation of revenue earned but not
yet billed is based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average
price per customer class for that month. Differences between actual and estimated unbilled revenue are usually immaterial.
Revenues on sales of wholesale energy and energy related products and natural gas are recognized either when the service is provided or the product is
delivered.
91
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
We also provide natural gas storage services to customers. The natural gas remains the property of these customers at all times. Customers pay a two part rate
that includes (i) a fixed fee reserving the right to store natural gas in our facilities and, (ii) a per unit rate for volumes actually injected into or withdrawn from
storage. The fixed fee component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as
revenue when the volumes are injected into or withdrawn from our storage facilities.
(c) Regulatory accounting
We account for our regulated utilities operations in accordance with the authoritative guidance applicable to entities with regulated operations that meet the
following criteria: (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entitys cost of providing regulated
services or products, and; (iii) there is a reasonable expectation that rates are set at levels that will recover the entitys costs and be collected from customers.
Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates.
Regulatory liabilities represent: (i) the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be
returned to customers through future regulated rates; or (ii) billings in advance of expenditures for approved regulatory programs.
Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the combined and consolidated statements of operations
consistent with the recovery or refund included in customer rates. We believe that it is probable that our currently recorded regulatory assets and liabilities
will be recovered or settled in future rates.
(d) Business combinations
We apply the acquisition method of accounting to account for business combinations. The consideration transferred for an acquisition is the fair value of the
assets transferred, the liabilities incurred by the acquirer to former owners of acquiree and the equity interests issued by the acquirer. Acquisition related costs
are expensed as incurred. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at
their fair values at the acquisition date. The excess of the consideration transferred over the fair value of the identifiable net assets acquired is recorded as
goodwill.
(e) Equity method investments
Joint ventures that do not meet consolidation criteria are accounted for using the equity method. Earnings (losses) recognized under the equity method are
reflected in the combined and consolidated statements of operations as “Earnings (losses) from equity method investments.” Dividends received from joint
ventures are recognized as a reduction in the carrying amount of the investment and are not recognized as dividend income.
(f) Goodwill and other intangible assets
Goodwill represents future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately
recognized. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred, the fair value of any noncontrolling
interest and the acquisition date fair value of any previously held equity interest in the acquiree over the fair value of the net identifiable assets acquired and
liabilities assumed.
Goodwill is not amortized, but is subject to an assessment for impairment at least annually or more frequently if events occur or circumstances change that
will more likely than not reduce the fair value of the reporting unit to which goodwill is assigned below its carrying amount. A reporting unit is an operating
segment or one level below an operating segment and is the level at which goodwill is tested for impairment. In assessing goodwill for impairment we have
the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary (step zero). If it is determined, on the basis
of qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If we
bypass step zero or perform the qualitative assessment, but determine that it is more likely than not that its fair value is less than its carrying amount, a
quantitative two step fair value based test is performed. Step one compares the fair value of the reporting unit to its carrying amount, including goodwill. If
the carrying amount of the reporting unit exceeds its fair value, step two is performed. Step two requires an allocation of fair value to the individual assets and
liabilities using business combination accounting guidance to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than
its carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense.
92
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair
value at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and impairment losses.
The useful lives of intangible assets are assessed as either finite or indefinite.
Intangible assets with finite lives are amortized on a straight-line basis over the useful economic life, which ranges from four to forty years, and assessed for
impairment whenever there is an indication that the intangible asset may be impaired. The amortization expense on intangible assets with finite lives is
recognized in the combined and consolidated statements of operations as the expense category that is consistent with the function of the intangible assets.
(g) Property, plant and equipment
Property, plant and equipment are accounted for at historical cost. In cases where we are required to dismantle installations or to recondition the site on which
they are located, the estimated cost of removal or reconditioning is recorded as an asset retirement obligation (ARO) and an equal amount is added to the
carrying amount of the asset.
Development and construction of our various facilities are carried out in stages. Project costs are expensed during early stage development activities. Once
certain development milestones are achieved and it is probable that we can obtain future economic benefits from a project, salaries and wages for persons
directly involved in the project, and engineering, permits, licenses, wind measurement and insurance costs are capitalized. Development projects in
construction are reviewed periodically for any indications of impairment.
Assets are transferred from “Construction work in progress” to “Property, plant and equipment” when they are available for service.
Wind turbine and related equipment costs, other project construction costs, and interest costs related to the project are capitalized during the construction
period through substantial completion. AROs are recorded at the date projects achieve commercial operation.
The cost of plant, and equipment in use is depreciated on a straight-line basis, less any estimated residual value. The main asset categories are depreciated
over the following estimated useful lives:
Major class Asset Category Estimated Useful Life (years)
Combined cycle plants 30-35
Hydroelectric power stations 40-90
Plant Wind power stations 25
Gas storage 17-119
Transport facilities 33-75
Distribution facilities 15-80
Equipment Conventional meters and measuring devices 17-41
Computer software 3-10
Other Buildings 9-75
Operations offices 5-32
Networks determines depreciation expense using the straight-line method, based on the average service lives of groups of depreciable property, which
include estimated cost of removal, in service at each operating company. Consistent with FERC accounting requirements, Networks charges the original cost
of utility plant retired or otherwise disposed of to accumulated depreciation.
We charge repairs and minor replacements to operating expenses, and capitalize renewals and betterments, including certain indirect costs.
(h) Impairment of long lived assets
We evaluate property, plant, and equipment and other long lived assets for impairment when events or changes in circumstances indicate that the carrying
amount may not be recoverable. An impairment loss is required to be recognized if the carrying amount of the asset exceeds the undiscounted future net cash
flows associated with that asset.
The impairment loss to be recognized is the amount by which the carrying amount of the long lived asset exceeds the assets fair value. Depending on the
asset, fair value may be determined by use of a discounted cash flow model.
93
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
(i) Fair value measurement
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the
measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place in either
the principal market for the asset or liability, or, in the absence of a principal market, in the most advantageous market for the asset or liability.
The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that
market participants act in their economic best interest. A fair value measurement of a non-financial asset takes into account a market participants ability to
generate economic benefits by using the asset according to its highest and best use, or by selling it to another market participant that would use the asset
according to its highest and best use.
We use valuation techniques that are appropriate in the circumstances and for which sufficient data is available to measure fair value, maximizing the use of
relevant observable inputs and minimizing the use of unobservable inputs. All assets and liabilities for which fair value is measured or disclosed in the
combined and consolidated financial statements are categorized within the fair value hierarchy based on the transparency of input to the valuation of an asset
or liability as of the measurement date.
The three input levels of the fair value hierarchy are as follows:
Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable
for the asset or liability either directly or indirectly, for substantially the full term of the contract.
Level 3 - one or more inputs to the valuation methodology are unobservable or cannot be corroborated with market data.
Categorization within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement.
(j) Available for sale securities
Securities that do not qualify as either securities held-to-maturity or trading securities, and which have a readily available fair value, are classified as
securities available-for-sale and reported at fair value, with unrealized gains and losses excluded from earnings and reported, net of taxes, in other
comprehensive income or loss.
(k) Derivatives and hedge accounting
Derivatives are recognized on the balance sheets at their fair value, except for certain electricity commodity purchases and sales contracts for both capacity
and energy (physical contracts) that qualify for, and are elected under, the normal purchases and normal sales exception. To be a derivative under the
accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment
and could be net settled. Changes in the fair value of a derivative contract are recognized in earnings unless specific hedge accounting criteria are met.
Derivatives that qualify and are designated for hedge accounting are classified as cash flow hedges. For cash flow hedges, the portion of the derivative gain or
loss that is effective in offsetting the change in the hedged cash flows of the underlying exposure is deferred in Other Comprehensive Income (OCI) and later
reclassified into earnings when the underlying transaction occurs. For all designated and qualifying hedges, we maintain formal documentation of the hedge
and effectiveness testing in accordance with the accounting standards for derivatives and hedging. If we determine that the derivative is no longer highly
effective as a hedge, hedge accounting will be discontinued prospectively. For cash flow hedges of forecasted transactions, we estimate the future cash flows
of the forecasted transactions and evaluate the probability of the occurrence and timing of such transactions. If we determine it is probable that the forecasted
transaction will not occur, hedge gains and losses previously recorded in OCI are immediately recognized in earnings.
Changes in conditions or the occurrence of unforeseen events could require discontinuance of the hedge accounting or could affect the timing of the
reclassification of gains or losses on cash flow hedges from OCI into earnings. Gains and losses from the ineffective portion of any hedge are recognized in
earnings immediately. Changes in the fair value of electric and natural gas hedge contracts are recorded to derivative assets or liabilities with an offset to
regulatory assets or regulatory liabilities for our regulated operations.
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We offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim cash collateral or the obligation
to return cash collateral arising from derivative instruments recognized at fair value executed with the same counterparty under a master netting arrangement.
(l) Cash and cash equivalents
Cash and cash equivalents comprises cash, bank accounts, and other highly-liquid short-term investments. We consider all highly liquid investments with a
maturity date of three months or less when acquired to be cash equivalents and those investments are included in “Cash and cash equivalents.” Restricted
cash amounts related to AROs are included as other non-current assets in the consolidated balance sheets.
(m) Accounts receivable and unbilled revenue, net
We record accounts receivable at amounts billed to customers. Certain accounts receivable and payable related to our wholesale activities associated with
generation and delivery of electric energy and associated environmental attributes, origination and marketing, natural gas storage, hub services, and energy
management, are subject to master netting agreements with counterparties, whereby we have the legal right to offset the balances, which are settled on a net
basis. Receivables and payables subject to such agreements are presented in our consolidated balance sheets on a net basis.
Accounts receivable include amounts due under Deferred Payment Arrangements (DPA). A DPA allows the account balance to be paid in installments over an
extended period of time without interest, which generally exceeds one year, by negotiating mutually acceptable payment terms. The utility company
generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees
to pay the balance in installments; and (iii) agrees to pay future bills within thirty days until the DPA is paid in full. Failure to make payments on a DPA
results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and are classified as short term.
The allowance for bad debts account is established by using both historical average loss percentages to project future losses, and a specific allowance is
established for known credit issues. Amounts are written off when we believe that a receivable will not be recovered.
(n) Tax equity financing arrangements
We have undertaken several structured institutional partnership investment transactions that bring in external investors in certain of our wind farms in
exchange for cash and notes receivable. Following an analysis of the economic substance of these transactions, we classify the consideration received at the
inception of the arrangement as a liability in the consolidated balance sheets. Subsequently, this liability is amortized based on the cash and tax benefits
provided to the tax equity investors.
(o) Debentures, bonds and bank borrowings
Bonds, debentures and bank borrowings are recorded as a liability equal to the proceeds of the borrowings. The difference between the proceeds and the face
amount of the issued liability is treated as discount or premium and is amortized as interest expense or income over the life of the instrument. Incremental
costs associated with issuance of the debt instruments are deferred and amortized over the same period as debt discount or premium.
(p) Inventory
Inventory comprises fuel and gas in storage and materials and supplies. Through our gas trading operations, we own natural gas that is stored in both self-
owned and third-party owned underground storage facilities. This gas is recorded as inventory. Injections of inventory into storage are priced at the market
purchase cost at the time of injection, and withdrawals of working gas from storage are priced at the weighted-average cost in storage. We continuously
monitor the weighted-average cost of gas value to ensure it remains at, or below market value. Inventories to support gas operations are reported on the
balance sheet within “Fuel and gas in storage.”
We also have materials and supplies inventories that are used for construction of new facilities and repairs of existing facilities. These inventories are carried
and withdrawn at cost and reported on the balance sheet within “Materials and supplies.
Inventory items are combined for the cash flow statement presentation purposes.
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(q) Government grants
Our unregulated subsidiaries record government grants related to depreciable assets within deferred income and subsequently amortize them to earnings
consistent with the useful life of the related asset. Our regulated subsidiaries record government grants as a reduction to utility plant to be recovered through
rate base, in accordance with the prescribed FERC accounting.
In accounting for government grants related to operating and maintenance costs, amounts receivable are recognized as an offset to expenses in the combined
and consolidated statements of operations in the period in which the expenses are incurred.
(r) Deferred income
Apart from government grants, we occasionally receive revenues from transactions in advance of the resulting obligations arising from the transaction. It is
our policy to defer such revenues to the consolidated balance sheets and amortize them to earnings consistent with the obligations.
(s) Asset retirement obligations
The fair value of the liability for an ARO and a conditional ARO is recorded in the period in which it is incurred, capitalizing the cost by increasing the
carrying amount of the related long lived asset. The ARO is associated with our long lived assets and primarily consists of obligations related to removal or
retirement of asbestos, polychlorinated biphenyl-contaminated equipment, gas pipeline, cast iron gas mains, and electricity generation facilities. The liability
is adjusted periodically to reflect revisions to either the timing or amount of the original estimated undiscounted cash flows over time, and to depreciate the
capitalized cost over the useful life of the related asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over
the useful life of the related asset. Upon settlement, the obligation will be either settled at its recorded amount or a gain or a loss will be incurred. Our
regulated utilities defer any timing differences between rate recovery and depreciation expense and accretion as either a regulatory asset or a regulatory
liability.
The term conditional ARO refers to an entity’s legal obligation to perform an asset retirement activity in which the timing or method of settlement are
conditional on a future event that may or may not be within the entity’s control. If an entity has sufficient information to reasonably estimate the fair value of
the liability for a conditional ARO, it must recognize that liability at the time the liability is incurred.
Our regulated utilities meet the requirements concerning accounting for regulated operations and we recognize a regulatory liability for the difference
between removal costs collected in rates and actual costs incurred. These are classified as accrued removal obligations.
(t) Environmental remediation liability
In recording our liabilities for environmental remediation costs the amount of liability for a site is the best estimate, when determinable; otherwise it is based
on the minimum liability or the lower end of the range when there is a range of estimated losses. Our environmental liabilities are recorded on an
undiscounted basis. Our environmental liability accruals are expected to be paid through the year 2048.
(u) Post employment and other employee benefits
We sponsor defined benefit pension plans that cover the majority of our employees. We also provide health care and life insurance benefits through various
postretirement plans for eligible retirees.
We evaluate our actuarial assumptions on an annual basis and consider changes based on market conditions and other factors. All of our qualified defined
benefit plans are funded in amounts calculated by independent actuaries, based on actuarial assumptions proposed by management.
We account for defined benefit pension or other postretirement plans, recognizing an asset or liability for the overfunded or underfunded plan status. For a
pension plan, the asset or liability is the difference between the fair value of the plans assets and the projected benefit obligation. For any other
postretirement benefit plan, the asset or liability is the difference between the fair value of the plans assets and the accumulated postretirement benefit
obligation. Our utility operations reflect all unrecognized prior service costs and credits and unrecognized actuarial gains and losses as regulatory assets
rather than in other comprehensive income, as
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management believes it is probable that such items will be recoverable through the ratemaking process. We use a December 31st measurement date for our
benefits plans.
We amortize prior service costs for both the pension and other postretirement benefits plans on a straight-line basis over the average remaining service period
of participants expected to receive benefits. For NYSEG, RGE and UIL, we amortize unrecognized actuarial gains and losses over ten years from the time they
are incurred as required by the NYPSC, PURA and DPU. For our other companies we use the standard amortization methodology under which amounts in
excess of ten percent of the greater of the projected benefit obligation or market related value are amortized over the plan participants’ average remaining
service to retirement. Our policy is to calculate the expected return on plan assets using the market related value of assets. That value is determined by
recognizing the difference between actual returns and expected returns over a five year period.
(v) Income tax
For the 2015 tax year, AVANGRID will file a consolidated federal income tax return, which will include the UIL taxable income or loss for the period from
December 17, 2015 to December 31, 2015. UIL will file a separate consolidated federal income tax return for the period from January 1, 2015 to December 16,
2015.
AVANGRID filed a consolidated federal income tax return that includes the taxable income or loss of all its subsidiaries (excluding UIL), which are 80% or
more owned for the 2014 tax period. UIL filed separate consolidated federal income tax returns including the income or loss of its subsidiaries for all tax
years including the most recently filed 2014 return.
AVANGRID (excluding ARHI and UIL), and ARHI filed separate consolidated federal income tax returns that included the taxable income or loss of all their
respective subsidiaries, which are 80% or more owned, for all tax periods prior to 2013.
In addition, a consolidated federal income tax return, that included the taxable income or loss of ARHI and all of its subsidiaries for the entire 2013 tax year
and the taxable income or loss of AVANGRID (without UIL) and all of its subsidiaries for the tax period of November 21, 2013 through December 31, 2013,
was filed.
For the period of January 1, 2013 through November 20, 2013, AVANGRID (excluding ARHI and UIL) filed a consolidated federal income tax return that
included the taxable income or loss of all its subsidiaries, which are 80% or more owned.
We use the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities reflect the expected future tax consequences, based
on enacted tax laws, of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts. In accordance with
generally accepted accounting principles for regulated industries, our regulated subsidiaries have established a regulatory asset for the net revenue
requirements to be recovered from customers for the related future tax expense associated with certain of these temporary differences. The investment tax
credits are deferred when used and amortized over the estimated lives of the related assets.
Deferred tax assets and liabilities are measured at the expected tax rate for the period in which the asset or liability will be realized or settled, based on
legislation enacted as of the balance sheet date. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged
or credited directly to OCI. Significant judgment is required in determining income tax provisions and evaluating tax positions. Our tax positions are
evaluated under a more-likely-than-not recognition threshold before they are recognized for financial reporting purposes. Valuation allowances are recorded
to reduce deferred tax assets when it is not more-likely-than-not that all or a portion of a tax benefit will be realized.
The excess of state franchise tax computed as the higher of a tax based on income or a tax based on capital is recorded in “Taxes other than income taxes”
and Taxes accrued” in the accompanying combined and consolidated financial statements.
Positions taken or expected to be taken on tax returns, including the decision to exclude certain income or transactions from a return, are recognized in the
financial statements when it is more likely than not the tax position can be sustained based solely on the technical merits of the position. The amount of a tax
return position that is not recognized in the financial statements is disclosed as an unrecognized tax benefit. Changes in assumptions on tax benefits may also
impact interest expense or interest income and may result in the recognition of tax penalties. Interest and penalties related to unrecognized tax benefits are
recorded within Interest expense, net of capitalization” and “Other income and (expense)” of the combined and consolidated statements of operations.
Uncertain tax positions have been classified as non-current unless expected to be paid within one year. Our policy is to recognize interest and penalties on
uncertain tax positions as a component of interest expense in the combined and consolidated statements of operations.
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Federal production tax credits applicable to our renewable energy facilities, that are not part of a tax equity financing arrangement, are recognized as a
reduction in income tax expense with a corresponding reduction in deferred income tax liabilities.
Our income tax expense, deferred tax assets and liabilities, and liabilities for unrecognized tax benefits reflect managements best assessment of estimated
current and future taxes to be paid. Significant judgments and estimates are required in determining the consolidated income tax components of the financial
statements.
(w) Stock-based compensation
Stock-based compensation represents costs related to stock-based awards granted to employees. We account for stock-based payment transactions based on
the estimated fair value of awards, net of estimated forfeitures at the date of issuance. The recognition period for these costs begin at either the applicable
service inception date or grant date and continues throughout the requisite service period, or for certain share-based awards until the employee becomes
retirement eligible, if earlier. The total stock-based compensation expense, which is included in operations and maintenance of the combined and
consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013 was $6.0 million, $4.8 million and $7.6 million, respectively.
The total liability relating to stock-based compensation, which is included in other non-current liabilities, was $17.5 million and $16.8 million as of
December 31, 2015 and 2014.
The Companys historical stock-based expense and liabilities are based on shares of its parent, Iberdrola S.A, and not on shares of the Company. The
Company has total unrecognized costs for stock-based compensation of approximately $1.0 million as of December 31, 2015. As of December 31, 2015 the
Company maintained unvested performance shares that may be settled through the issuance of additional Company shares in future periods upon the
achievement of certain conditions.
Reclassifications
Certain amounts have been reclassified in the consolidated balance sheet and combined and consolidated statements of operations to conform to the 2015
presentation. Amounts pertaining to sales and use tax of $8 million and $11 million for the years ended December 31, 2014 and 2013, respectively, have
been reclassified from “Taxes other than income taxes” to “Operations and maintenance” in the combined and consolidated statements of
operations. Additionally, current and non-current liabilities amounting to $12 million and $23 million, pertaining to the Rate refund FERC ROE
proceeding have been reclassified from Other current liabilityand “Other non-current liability to current and non-current regulatory liabilities in the
consolidated balance sheet as of December 31, 2014.
New Accounting Standards and Interpretations
(a) Simplifying the presentation of debt issuance costs
The Financial Accounting Standards Board (FASB) issued an amendment in April 2015 that is intended to simplify the presentation of debt issuance costs.
Instead of presenting debt issuance costs as a deferred charge (that is, as an asset), the amendments require debt issuance costs related to a recognized debt
liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with the presentation for debt
discounts. The amendment is effective for public entities for financial statements issued for fiscal years beginning after December 15, 2015, and for interim
periods within those fiscal years. As permitted, we have early adopted the amendment as of the beginning of the fourth quarter of 2015 and have applied it
retrospectively to all periods presented. Accordingly, we reclassified the debt issuance costs from other noncurrent assets to noncurrent debt on our December
31, 2014 consolidated balance sheet, which decreased total assets, noncurrent debt and total liabilities by $27 million.
(b) Balance sheet classification of deferred taxes
The FASB issued an amendment in November 2015 that is intended to simplify the presentation of deferred income taxes by requiring entities that present a
classified statement of financial position to classify deferred tax liabilities and assets as noncurrent in their balance sheet. This aligns the presentation of
deferred income tax liabilities and assets with International Financial Reporting Standards. The amendments do not affect the current requirement that
deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount. The amendments are effective for public
entities for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. As permitted,
we have early adopted the amendments as of the beginning of the fourth quarter of 2015, and have elected retrospective application to all periods presented
in order to simplify the presentation in our balance sheet. Accordingly, we reclassified the current deferred taxes to
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noncurrent on our December 31, 2014 consolidated balance sheet, which decreased noncurrent deferred tax assets and liabilities by $97 million.
(c) Pushdown accounting
In November 2014 the FASB issued an amendment on when and how an acquired entity that is a business or nonprofit activity, whether public or nonpublic,
can apply pushdown accounting in its separate financial statements upon the occurrence of an event in which an acquirer, either an individual or an entity,
obtains control of the acquired entity. The guidance provides an acquired entity with an option to apply pushdown accounting in its separate financial
statements. As a result of the amendment, which was effective when issued, we were not required to apply pushdown accounting to the acquisition of Energy
East by Iberdrola in 2008. Therefore, the net assets of Networks in these combined and consolidated financial statements are recorded at the historical
accounting basis of AVANGRID, which do not include purchase accounting adjustments related to that acquisition.
(d) Discontinued operations and disposals of components of an entity
The FASB issued an amendment in April 2014 that changed the requirements for the reporting of discontinued operations. The new definition of
discontinued operations limits reporting to disposals of components that represent strategic shifts that have, or will have, a major effect on an entitys
operations and financial results. The amendments are effective for public business entities for annual periods beginning on or after December 15, 2014, and
interim periods within those years. The adoption of the amendment did not materially affect our results of operations, financial position or cash flows.
(e) Revenue from contracts with customers
In May 2014 the FASB issued an amendment related to the recognition of revenue from contracts with customers and required disclosures. The core principle
is for an entity to recognize revenue to represent the transfer of goods or services to customers in amounts that reflect the consideration to which the entity
expects to be entitled in exchange for those goods or services. The standard is effective for public entities for annual reporting periods beginning after
December 15, 2016, including interim periods within that reporting period. In August 2015 the FASB issued an accounting standards update that defers by
one year the effective date of the revenue standard for all entities. Thus, the standard is now effective for annual reporting periods beginning after December
15, 2017, and interim periods therein, with early adoption as of the original effective date permitted. In March 2016 the FASB issued an accounting standards
update that amends and clarifies the implementation guidance on principal versus agent considerations for reporting revenue gross rather than net, with the
same deferred effective date. We are currently evaluating how the adoption of the amendment will affect our results of operations, financial position, and cash
flows.
(f) Presentation of an unrecognized tax benefit
In July 2013 the FASB issued guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss (NOL) carryforward,
a similar tax loss, or a tax credit carryforward exists. An unrecognized tax benefit, or a portion of an unrecognized tax benefit, is to be presented as a reduction
to a deferred tax asset for an NOL carryforward, a similar tax loss, or a tax credit carryforward, with certain exceptions. The unrecognized tax benefit is to be
presented as a liability and should not be combined with deferred tax assets to the extent that an NOL carryforward, a similar tax loss, or a tax credit
carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from
the disallowance of a tax position or the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the
deferred tax asset for such purpose. AVANGRID adopted these amendments effective January 1, 2014. The adoption of these amendments did not materially
affect our results of operations, financial position or cash flows.
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(g) Fair value measurement disclosures for certain investments
The FASB issued amendments in May 2015 that affect reporting entities that elect to estimate the fair value of certain investments within scope using the net
asset value (NAV) per share (or its equivalent) practical expedient, as specified. The amendments remove the requirement to categorize within the fair value
hierarchy all investments for which the fair value is measured at NAV using the practical expedient. They also remove certain disclosure requirements for
eligible investments and limit the required disclosures to investments for which the entity has elected to measure the fair value using the practical expedient.
Assets that calculate NAV per share (or its equivalent), but for which the practical expedient is not applied will continue to be included in the fair value
hierarchy. The amendments are effective for public entities for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years.
The amendments permit early application, and require retrospective application to all periods presented. Retrospective application requires investments for
which fair value is measured at NAV using the practical expedient to be removed from the fair value hierarchy in all periods presented. We do not expect our
adoption of the amendments to materially affect our results of operations, financial position, or cash flows.
(h) Simplifying the measurement of inventory
In July 2015 the FASB issued amendments that require entities to measure inventory at the lower of cost and net realizable value, rather than the lower of cost
or market. The amendments do not apply to inventory measured using last-in, first-out or the retail inventory method but apply to all other inventory,
including inventory measured using first-in, first-out or average cost. Prior to this update, market value could be replacement cost, net realizable value, or net
realizable value less an approximately normal profit margin. Net realizable value is the “estimated selling prices in the ordinary course of business, less
reasonably predictable costs of completion, disposal, and transportation.” The amendments do not change the methods of estimating the cost of inventory
under U.S. GAAP. The amendments are effective for public entities for fiscal years beginning after December 15, 2016, including interim periods within those
fiscal years. The amendments require prospective application and permit earlier application. We do not expect our adoption of the amendments to affect our
results of operations, financial position, or cash flows.
(i) Application of the normal purchases and normal sales scope exception
The FASB issued amendments in August 2015 to specify that the use of locational marginal pricing by an independent system operator (ISO) does not
constitute net settlement of a contract for the purchase or sale of electricity on a forward basis that necessitates transmission through, or delivery to a location
within, a nodal energy market, even when legal title to the associated electricity is conveyed to the ISO during transmission. As a result, the use of locational
marginal pricing by the ISO does not cause that contract to fail to meet the physical delivery criterion of the normal purchases and normal sales (NPNS) scope
exception. If the physical delivery criterion is met, along with all of the other criteria of the NPNS scope exception, an entity may elect to designate that
contract as a normal purchase or normal sale. The amendments were effective upon issuance of the accounting standards update, which was August 10, 2015,
and require prospective application. The adoption of these amendments did not materially affect our results of operations, financial position or cash flows.
(j) Classifying and measuring financial instruments
In January 2016 the FASB issued final guidance on the classification and measurement of financial instruments. The new guidance requires that all equity
investments in unconsolidated entities (other than those accounted for using the equity method of accounting) to be measured at fair value through earnings.
There will no longer be an available-for-sale classification (changes in fair value reported in other comprehensive income) for equity securities with readily
determinable fair values. For equity investments without readily determinable fair values, the cost method is also eliminated. However, entities (other than
those following “specializedaccounting models, such as investment companies and broker-dealers) are able to elect to record equity investments without
readily determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes. Changes in the basis of
these equity investments will be reported in current earnings. This election only applies to equity investments that do not qualify for the NAV practical
expedient. When the fair value option has been elected for financial liabilities, changes in fair value due to instrument-specific credit risk will be recognized
separately in other comprehensive income. The accumulated gains and losses due to these changes will be reclassified from accumulated other
comprehensive income to earnings if the financial liability is settled before maturity. Public business entities are required to use the exit price notion when
measuring the fair value of financial instruments measured at amortized cost for disclosure purposes. In addition, the new guidance requires financial assets
and financial liabilities to be presented separately in the notes to the financial statements, grouped by measurement category (e.g., fair value, amortized cost,
lower of cost or market) and form of financial asset (e.g., loans, securities).
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The classification and measurement guidance is effective for public entities in fiscal years beginning after December 15, 2017, including interim periods
within those fiscal years. An entity will record a cumulative-effect adjustment to beginning retained earnings as of the beginning of the first reporting period
in which the guidance is adopted, with two exceptions. The amendments related to equity investments without readily determinable fair values (including
disclosure requirements) will be effective prospectively. The requirement to use the exit price notion to measure the fair value of financial instruments for
disclosure purposes will also be applied prospectively. We do not expect our adoption of the guidance to materially affect our results of operations, financial
position, or cash flows.
(k) Business combinations: simplifying the accounting for measurement-period adjustments
The FASB issued amendments in September 2015 that require an acquirer to recognize adjustments to provisional amounts relating to a business
combination that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. As a result, the
acquirer is required to record, in the same periods financial statements, the effect on earnings of changes in depreciation, amortization, or other income
effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The entity is
required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by
line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition
date. The amendments are effective for public entities for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years.
The amendments require prospective application to provisional amounts that occur after the effective date of the amendment and permit earlier application.
We cannot predict how our adoption of the amendments will affect our results of operation, financial position, or cash flows as it relates to the business
combination with UIL. See Note 4 - “Acquisition of UIL.
(l) Leases
In February 2016 the FASB issued new guidance that affects all companies and organizations that lease assets, and requires them to record on their balance
sheet assets and liabilities for the rights and obligations created by those leases. A lease is an arrangement that conveys the right to control the use of an
identified asset for a period of time in exchange for consideration. Concerning lease expense recognition, after extensive consultation, the FASB has
ultimately concluded that the economics of leases can vary for a lessee, and those economics should be reflected in the financial statements. As a result, the
amendments retain a distinction between finance leases and operating leases, while requiring both types of leases to be recognized on the balance sheet. The
classification criteria for distinguishing between finance leases and operating leases are substantially similar to the criteria for distinguishing between capital
leases and operating leases in current GAAP. By retaining a distinction between finance leases and operating leases, the effect of leases on the statement of
comprehensive income and the statement of cash flows is largely unchanged from previous GAAP. Lessor accounting will remain substantially the same as
current GAAP, but with some targeted improvements to align lessor accounting with the lessee accounting model and with the revised revenue recognition
guidance issued in 2014. The updated guidance is effective for public entities for fiscal years beginning after December 15, 2018, including interim periods
within those fiscal years, and early application is permitted. We expect our adoption of the new guidance will materially affect our results of operations and
financial position.
(m) Derivative contract novations
The FASB issued amendments in March 2016 concerning the effect of derivative contract novations on existing hedge accounting relationships. As it relates
to derivative instruments, novation refers to replacing one of the parties to a derivative instrument with a new party, which may occur for a variety of reasons
such as: financial institution mergers, intercompany transactions, an entity exiting a particular derivatives business or relationship, or because of laws or
regulatory requirements. The amendments clarify that a change in the counterparty to a derivative instrument that has been designated as the hedging
instrument under the guidance for Derivatives and Hedging (Topic 815) does not, in and of itself, require dedesignation of that hedge accounting
relationship provided that all other hedge accounting criteria continue to be met. The amendments are effective for public entities for financial statements
issued for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. The amendments may be applied on either a
prospective basis or a modified retrospective basis and early application is permitted. We do not expect our adoption will materially affect our results of
operations, financial position, and cash flows.
Use of Estimates and Assumptions
The preparation of our combined and consolidated financial statements in conformity with U.S. GAAP requires the use of estimates and assumptions that
affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the combined and consolidated financial
statements, and the reported amounts of revenues and expenses during the reporting
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periods. Significant estimates and assumptions are used for, but not limited to: (1) allowance for doubtful accounts and unbilled revenues; (2) asset
impairments, including goodwill; (3) depreciable lives of assets; (4) income tax valuation allowances; (5) uncertain tax positions; (6) reserves for
professional, workers’ compensation, and comprehensive general insurance liability risks; (7) contingency and litigation reserves; (8) fair value
measurements; (9) earnings sharing mechanisms; (10) environmental remediation liabilities; and (11) AROs. Future events and their effects cannot be
predicted with certainty; accordingly, our accounting estimates require the exercise of judgment. The accounting estimates used in the preparation of our
combined and consolidated financial statements will change as new events occur, as more experience is acquired, as additional information is obtained and
as our operating environment changes. We evaluate and update our assumptions and estimates on an ongoing basis and may employ outside specialists to
assist in our evaluations, as necessary. Actual results could differ from those estimates.
Union bargain agreements
We have approximately 48% of the employees covered by a collective bargaining agreement. Agreements which will expire within the coming year apply to
approximately 1% of our employees.
Note 4. Acquisition of UIL
On December 16, 2015 (acquisition date) we completed our acquisition of UIL, a diversified energy company with its portfolio of regulated utility companies
in Connecticut and Massachusetts that is expected to provide us with a greater flexibility to grow the combined regulated businesses through project
development and create an enhanced platform to develop transmission and distribution projects in the Northeastern United States. In connection with the
acquisition we issued 309,490,839 shares of common stock of AVANGRID, out of which 252,234,989 shares were issued to Iberdrola through a stock
dividend, accounted for as a stock split, with no change to par value, at par value of $0.01 per share and 57,255,850 shares (including those held in trust as
Treasury Stock) were issued to UIL shareowners in addition to payment of $595 million in cash. Following the completion of the acquisition, former UIL
shareowners owned 18.5% of the outstanding shares of common stock of AVANGRID, and Iberdrola owned the remaining shares.
The acquisition was accounted for as a business combination. This method requires, among other things, that assets acquired and liabilities assumed in a
business combination, with certain exceptions, be recognized at their fair values as of the acquisition date.
As UILs common stock was publicly traded in an active market until the acquisition date, we determined that UILs common stock is more reliably
measurable than the common stock of AVANGRID to determine the fair value of the consideration transferred in the transaction.
The purchase consideration for UIL under the acquisition method is based on the stock price of UIL on the acquisition date multiplied by the number of
shares issued by AVANGRID to the UIL shareowners after applying an equity exchange factor to the shares of vested restricted common stock of UIL (other
than those UIL restricted shares that vest by their terms upon the consummation of the acquisition), performance shares and other shares awards under UIL
2008 Stock and Incentive Compensation Plan and the UIL Deferred Compensation Plan. The “equity exchange factor is the sum of one plus a fraction, (i)
the numerator of which is the cash consideration and (ii) the denominator of which is the average of the volume weighted averages of the trading prices of
UIL common stock on each of the ten consecutive trading days ending on (and including) the trading day that immediately precedes the closing date of the
acquisition minus $10.50. The determination of the purchase price is based on a UIL stock price of $50.10 per share, which represents the closing stock price
on the acquisition date.
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AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
The fair value of AVANGRID common stock issued to the UIL shareowners in the business combination represents the purchase consideration in the business
combination, which was computed as follows:
(millions, except
share and unit
data)
Common shares
(1)
56,629,377
Price per share of UIL common stock as of the
acquisition date $ 50.10
Subtotal value of common shares $ 2,837
Restricted stock units
(2)
476,198
Other shares
(3)
12,999
Equity exchange factor 1.2806
Total restricted and other shares(3) after applying
an equity exchange factor 626,473
Price per share used
(5)
$ 39.60
Subtotal value of restricted and other shares $ 25
Total shares of AVANGRID common stock issued to UIL
shareowners (including held in trust as Treasury Stock) 57,255,850
Performance shares
(4)
211,904
Equity exchange factor 1.2806
Total performance shares after applying an equity
exchange factor 271,368
Price per share used
(5)
$ 39.60
Subtotal value of performance shares $ 11
Total consideration $ 2,873
(1) Based on UIL’s common shares outstanding on December 16, 2015
(2) Based on UIL’s shares of vested restricted stock.
(3) Based on UIL’s restricted shares vested upon the change in control.
(4) Based on UIL’s vested performance shares award.
(5) Based on the closing share price of UIL common stock on December 16, 2015 less the cash component of $10.50, which is not applicable to restricted
shares (other than those UIL restricted shares that vest by their terms upon the consummation of the acquisition), performance shares and other awards
under UIL 2008 Stock and Incentive Compensation Plan and the UIL Deferred Compensation Plan.
The following is a summary of the components of the consideration transferred to UIL’s shareowners:
(millions, except
share data)
Cash ($10.50 x number of UIL common shares
outstanding at the acquisition date - 56,629,377) $ 595
Equity 2,278
Total consideration $ 2,873
We also paid $37.5 million for transaction costs incurred in this business combination, which are recorded in “Operations and maintenance” in the combined
and consolidated statements of operations.
The following unaudited pro forma information presents the combined results of operations as if the acquisition had been completed on January 1, 2014, the
beginning of the comparable prior annual reporting period. The unaudited pro forma results include: (i) merger credit adjustments to operating revenue (see
Merger Settlement Agreement below for further details); (ii) elimination of accrued transaction costs representing non-recurring expenses directly related to
the transaction, and (iii) the associated tax impact on these unaudited pro forma adjustments.
The unaudited pro forma results do not reflect any cost saving synergies from operating efficiencies or the effect of the incremental costs incurred in
integrating the two companies. Accordingly, these unaudited pro forma results are presented for informational
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AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
purpose only and are not necessarily indicative of what the actual results of operations of the combined company would have been if the acquisition had
occurred at the beginning of the period presented, nor are they indicative of future results of operations:
Year Ended December 31,
(millions) 2015 2014
Revenue $ 5,958 $ 6,226
Net income $ 468 $ 539
The revenue and net (loss) of UIL since the acquisition date included in the combined and consolidated statements of operations for the year ended December
31, 2015 were $36 million and $(36) million, respectively (see Merger Settlement Agreement below for further details).
The fair value of assets acquired and liabilities assumed from our acquisition of UIL was based on a preliminary valuation and our estimates and assumptions
are subject to change within the measurement period. For the majority of UILs assets and liabilities, primarily property, plant and equipment, fair value was
determined to be the respective carrying amounts of the predecessor entity. UILs operations are conducted in a regulated environment where the regulatory
authority allows an approved rate of return on the carrying amount of the regulated asset base. The primary areas of the purchase price that are not yet
finalized include, but are not limited to contracts, equity method investments, provisions, contingent liabilities related to certain environmental sites, income
taxes and goodwill. We will finalize these amounts no later than December 16, 2016. Under U.S. GAAP, the measurement period shall not exceed one year
from the acquisition date. Measurement period adjustments that we determine to be material will be recognized in future periods in our consolidated financial
statements.
The following is a summary of the preliminary allocation of the purchase price as of the acquisition date:
(millions)
Current assets, including cash of $48 million $ 500
Other investments 114
Property, plant and equipment, net 3,552
Regulatory assets 966
Other assets 52
Current liabilities (493 )
Regulatory liabilities (493 )
Non-current debt (1,878)
Other liabilities (1,201 )
Total net assets acquired at fair value 1,119
Goodwill consideration transferred in excess of fair
value assigned 1,754
Total estimated consideration $ 2,873
Goodwill generated from the acquisition of UIL has been assigned to the reporting units under the Networks reportable segment and is primarily attributable
to expected future growth of the combined regulated businesses and enhanced platform to develop transmission and distribution projects in the Northeastern
United States. The goodwill generated from this acquisition is not deductible for tax purposes. As part of the preliminary allocation of the purchase price we
have determined a fair value of contingent liabilities of approximately $44.0 million relating to certain environmental sites.
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AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Merger Settlement Agreement
As part of the process of seeking and obtaining regulatory approval for the acquisition in Connecticut and Massachusetts, Iberdrola, S.A., AVANGRID and
UIL reached settlement agreements with the Office of Consumer Counsel in Connecticut and with the Attorney General of the Commonwealth of
Massachusetts and the Department of Energy Resources in Massachusetts, which settlement agreements included commitments of actions to be taken after
the transaction closed.
As a result, the following commitments have been made in Connecticut, recognized in the period subsequent to the acquisition in 2015 unless otherwise
noted, each of which is reasonably expected to be at a cost of $500,000 or more:
·
A one-time, $20 million rate credit to customers in 2016, allocated among UI, SCG and CNG customers based on the total number of retail
customers.
·
Additional rate credits of $1.25 million/year for ten years (2018-2027) to CNG customers.
·
Additional rate credits of $0.75 million/year for ten years (2018-2027) to SCG customers.
·
$1.6 million in savings to SCG customers, associated with SCG making additional infrastructure capital investments over a three-year period
without seeking recovery until the next SCG rate case. These amounts will be recorded by the Company as incurred in future periods.
·
Agreement not to seek to increase UI distribution base rates effective before January 1, 2017, and agreement not to seek to increase CNG and
SCG distribution base rates effective before January 1, 2018.
·
Contribution of $2 million/year for three years to the DEEP, to stimulate investment in energy efficiency and clean energy technologies.
·
$5 million in benefits to customers resulting from UI recovering only the debt rate rather than the equity return for two years, on an increased
$50 million of investment in storm resiliency programs. These amounts will be recorded by the Company as incurred in future periods.
·
Contribution of $1 million for disaster relief entities.
·
Maintaining charitable contribution at historical contribution levels (between $500,000 and $800,000) for at least four years.
·
Upon the resolution of all appeals of the PURA decision approving the acquisition, UI will withdraw its appeals of two PURA dockets relating
to PURA’s disallowance of certain reconciliation amounts.
In connection with the acquisition proceeding, UI signed a proposed partial consent order, or consent order that, when approved by the Commissioner of
DEEP, and pursuant to the terms and conditions in the consent order, would require UI to investigate and remediate certain environmental conditions within
the perimeter of the English Station site. To the extent that the investigation and remediation is less than $30 million, UI would remit to the State of
Connecticut the difference between such costs and $30 million for a public purpose as determined in the discretion of the Governor the Attorney General of
Connecticut and the Commissioner of DEEP. Pursuant to the consent order, upon its issuance and subject to its terms and conditions, UI would be obligated
to comply with the consent order, even if the cost of such compliance exceeds $30 million. The State will discuss options with UI on recovering or funding
any cost above $30 million such as through public funding or recovery from third parties, however it is not bound to agree to or support any means of
recovery or funding (See Note 14 – Environmental Liabilities – English Station – for further details).
The following commitments have been made in Massachusetts, recognized in the period subsequent to the acquisition in 2015 unless otherwise noted, each
of which is reasonably expected to be at a cost of $500,000 or more:
·
Customers of Berkshire will receive a total of $4.0 million in rate credits, to be spread over the months of November through April 2016-2017
and November through April 2017-2018.
·
Berkshire will contribute $1 million to alternative heating programs.
·
Berkshire will not seek to increase distribution base rates effective before June 1, 2018.
As a result of the merger settlement agreement we have recorded $44 million as regulatory liabilities relating to the rate credits and an additional $19.8
million as liabilities, which primarily resulted in the net loss for UIL in the period following the acquisition date in 2015.
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AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Note 5. Industry Regulation
Electricity and Natural Gas Distribution Maine and New York
The Maine distribution rate stipulation, the Maine transmission Federal Energy Regulatory Commission (FERC) Return on Equity (ROE) case, the New York
rate plans, Reforming Energy Vision (REV), and the New York Transmission Company (New York Transco) filings are some of the most important specific
regulatory processes that affect Networks.
The revenues of Networks companies are essentially regulated, being based on tariffs established in accordance with administrative procedures set by the
various regulatory bodies. The tariffs applied to regulated activities in the U.S. are approved by the regulatory commissions of the different states and are
based on the cost of providing service. The revenues of each regulated utility are set to be sufficient to cover all its operating costs, including energy costs,
finance costs, and the costs of equity, the last of which reflect our capital ratio and a reasonable ROE.
Energy costs that are set on the New York and New England wholesale markets are passed on to consumers. The difference between energy costs that are
budgeted and those that are actually incurred by the utilities is offset by applying compensation procedures that result in either immediate or deferred tariff
adjustments. These procedures apply to other costs, which are in most cases exceptional, such as the effects of extreme weather conditions, environmental
factors, regulatory and accounting changes, and treatment of vulnerable customers, that are offset in the tariff process. Any New York revenues that allow a
utility to exceed target returns, usually the result of better than expected cost efficiency, are generally shared between the utility and its customers, resulting
in future tariff reductions.
Each of the four Networks’ New York and Maine supply companies must comply with regulatory procedures that differ in form but in all cases conform to the
basic framework outlined above. Generally, tariff reviews cover various years and provide for a reasonable ROE, protection, and automatic adjustments for
exceptional costs incurred and efficiency incentives.
CMP Distribution Rate Stipulation and New Renewable Source Generation
On May 1, 2013, CMP submitted its required distribution rate request with the Maine Public Utilities Commission (MPUC). On July 3, 2014, after a fourteen
month review process, CMP filed a rate stipulation agreement on the majority of the financial matters with the MPUC. The stipulation agreement was
approved by the MPUC on August 25, 2014. The stipulation agreement also noted that certain rate design matters would be litigated, which the MPUC ruled
on October 14, 2014.
The rate stipulation agreement provided for an annual CMP distribution tariff increase of 10.7% or $24.3 million. The rate increase was based on a 9.45%
ROE and 50% equity capital. CMP was authorized to implement a Rate Decoupling Mechanism (RDM) which protects CMP from variations in sales due to
energy efficiency and weather. CMP also adjusted its storm costs recovery mechanism whereby it is allowed to collect in rates a storm allowance and to defer
actual storm costs when such storm event costs exceed $3.5 million. CMP and customers share storm costs that exceed a certain balance on a fifty-fifty basis,
with CMP’s exposure limited to $3.0 million annually.
CMP has made a separate regulatory filing for a new customer billing system replacement. In accordance with the stipulation agreement, a new billing system
is needed and CMP made its filing on February 27, 2015 to request a separate rate recovery mechanism. On October 20, 2015, the MPUC issued an order
approving a stipulation agreement authorizing CMP to proceed with the customer billing system investment. The approved stipulation allows CMP to
recover the system costs effective with its implementation, currently expected in mid-2017.
The rate stipulation does not have a predetermined rate term. CMP has the option to file for new distribution rates at its own discretion. The rate stipulation
does not contain service quality targets or penalties. The rate stipulation also does not contain any earning sharing requirements.
Under Maine law 35-A M.R.S.A §§ 3210-C, 3210-D, the MPUC is authorized to conduct periodic requests for proposals seeking long-term supplies of
energy, capacity or Renewable Energy Certificates, or RECs, from qualifying resources. The MPUC is further authorized to order Maine Transmission and
Distribution Utilities to enter into contracts with sellers selected from the MPUC’s competitive solicitation process. Pursuant to a MPUC Order dated October
8, 2009, CMP entered into a 20-year agreement with Evergreen Wind Power III, LLC, on March 31, 2010, to purchase capacity and energy from Evergreens
60 MW Rollins wind farm in Penobscot County, Maine. CMP’s purchase obligations under the Rollins contract are approximately $7 million per year. In
accordance with subsequent MPUC orders, CMP periodically auctions the purchased Rollins energy to wholesale buyers in the New
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AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
England regional market. Under applicable law, CMP is assured recovery of any differences between power purchase costs and achieved market revenues
through a reconcilable component of its retail distribution rates. Although the MPUC has conducted multiple requests for proposals under M.R.S.A §3210-C
and has tentatively accepted long-term proposals from other sellers, these selections have not yet resulted in additional currently effective contracts with
CMP.
Transmission - FERC ROE Proceeding
See Note 13 - Commitments and Contingent Liabilities for a further discussion.
CMP’s and UI’s transmission rates are determined by a tariff regulated by the FERC and administered by ISO New England, Inc. (ISO-NE). Transmission rates
are set annually pursuant to a FERC authorized formula that allows for recovery of direct and allocated transmission operating and maintenance expenses,
and for a return of and on investment in assets. The FERC currently provides a base ROE of 10.57% and additional ROE incentive adders applicable to assets
based upon vintage, voltage and other factors.
On December 28, 2015, the FERC issued an order instituting section 206 proceedings and establishing hearing and settlement judge procedures. Pursuant to
section 206 of the Federal Power Act (FPA), the FERC finds that ISO-NE Transmission, Markets, and Services Tariff is unjust, unreasonable, and unduly
discriminatory or preferential. The FERC stated that ISO-NE’s Tariff lacks adequate transparency and challenge procedures with regard to the formula rates
for ISO-NE Participating Transmission Owners, including UI. The FERC also found that the current Regional Network Service (RNS) and Local Network
Service (LNS) formula rates appear to be unjust, unreasonable, unduly discriminatory or preferential or otherwise unlawful as the formula rates appear to lack
sufficient detail in order to determine how certain costs are derived and recovered in the formula rates. A settlement judge has been appointed and a
settlement conference has convened. We are unable to predict the outcome of this proceeding at this time.
NYSEG and RGE Rate Plans
On September 16, 2010, the New York Public Service Commission (NYPSC) approved a new rate plan for electric and natural gas service provided by NYSEG
and RGE effective from August 26, 2010 through December 31, 2013. The rate plans contain continuation provisions beyond 2013 if NYSEG and RGE do
not request new rates to go into effect and the current base rates will stay in place.
The revenue requirements were based on a ten-percent allowed ROE applied to an equity ratio of forty-eight-percent. If annual earnings exceed the allowed
return, a tiered Earnings Sharing Mechanism (ESM) will capture a portion of the excess for the ratepayers’ benefit. The ESM is subject to specified downward
adjustments if NYSEG and RGE fail to meet certain reliability and customer service measures. Key components of the rate plan include electric reliability
performance mechanisms, natural gas safety performance measures, customer service quality metrics and targets, and electric distribution vegetation
management programs that establish threshold performance targets. There will be downward revenue adjustments if NYSEG and RGE fail to meet the targets.
The 2010 rate plans established revenue decoupling mechanism (RDM), intended to remove company disincentives to promote increased energy efficiency.
Under RDM, electric revenues are based on revenue per customer class rather than billed revenue, while natural gas revenues are based on revenue per
customer. Any shortfalls or excesses between billed revenues and allowed revenues will be accrued for future recovery or refund.
In August 2010, NYSEG began amortizing $15.2 million per year of its $303.9 million theoretical excess depreciation reserve. On September 1, 2012, RGE
began amortizing $5.3 million per year of its $105 million theoretical excess depreciation reserve. Both amortization amounts reflect a twenty year
amortization period. Theoretical excess depreciation is the difference between actual accumulated depreciation taken to date and a theoretical reserve. The
actual accumulated depreciation is the result of depreciation rates allowed in prior rate orders based on estimates of useful lives and net salvage values as
determined in those cases. The theoretical reserve is the amount that would have accumulated if the depreciation rates in the new rate plan had been in place
for the entire useful lives of the affected assets. Differences between the actual reserve and the theoretical reserve are normal aspects of utility ratemaking. The
usual treatment is to flow any excess or deficiency back as an adjustment to depreciation expense over the remaining life of the property. However, in
accordance with the new rate plan, NYSEG and RGE will moderate electric rates by recording the theoretical reserve amortization as a debit to accumulated
depreciation and a credit to other revenues, and normalize a portion of the amortization from a tax perspective.
On May 20, 2015, NYSEG and RGE filed electric and gas rate cases with the NYPSC. The companies requested rate increases for NYSEG electric, NYSEG gas
and RGE gas. RGE electric proposed a rate decrease.
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AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
On February 19, 2016, NYSEG, RGE and other signatory parties filed a Joint Proposal (Proposal) with the NYPSC for a three-year rate plan for electric and gas
service at NYSEG and RGE commencing May 1, 2016. The Proposal balances the varied interests of the signatory parties including but not limited to
maintaining the companies’ credit quality and mitigating the rate impacts to customers. The Proposal reflects many customer attributes including:
acceleration of the companies’ natural gas leak prone main replacement programs and enhanced electric vegetation management to provide continued safe
and reliable service. The delivery rate increase in the Proposal can be summarized as follows:
May 1, 2016 May 1, 2017 May 1, 2018
Rate
Increase
Delivery
Rate
Increase
Rate
Increase
Delivery
Rate
Increase
Rate
Increase
Delivery
Rate
Increase
Utility (Millions) % (Millions) % (Millions) %
NYSEG Electric $ 29.6 4.10 % $ 29.9 4.10 % $ 30.3 4.10%
NYSEG Gas 13.1 7.30% 13.9 7.30% 14.8 7.30 %
RGE Electric 3.0 0.70% 21.6 5.00% 25.9 5.70 %
RGE Gas 8.8 5.20 % 7.7 4.40 % 9.5 5.20%
The allowed rate of return on common equity for NYSEG Electric, NYSEG Gas, RGE Electric and RGE Gas is 9.00%. The equity ratio for each company is
48%. The Proposal includes an Earnings Sharing Mechanism (ESM) applicable to each company. The customer share of earnings would increase at higher
earnings levels, with customers receiving 50%, 75% and 90% of earnings over 9.5%, 10.0% and 10.5% of ROE, respectively, in the first year. Earnings
thresholds would increase in subsequent years.
The Proposal reflects the recovery of deferred NYSEG Electric storm costs of approximately $262 million, of which $123 million will be amortized over ten
years and the remaining $139 million will be amortized over five years. The Proposal also continues reserve accounting for qualifying Major Storms ($21.4
million annually for NYSEG Electric and $2.5 million annually for RGE Electric). Incremental maintenance costs incurred to restore service in qualifying
divisions will be chargeable to the Major Storm Reserve provided they meet certain thresholds.
The Proposal maintains NYSEG’s and RGE’s current electric reliability performance measures (and associated potential negative revenue adjustments for
failing to meet established performance levels) which include the system average interruption frequency index and the customer average interruption
duration index. The Proposal also modifies certain gas safety performance measures at the companies, including those relating to the replacement of leak
prone main, leak backlog management, emergency response, and damage prevention. The Proposal establishes threshold performance levels for designated
aspects of customer service quality and continues and expands NYSEG’s and RGE’s bill reduction and arrears forgiveness Low Income Programs at the
increased funding levels included in the Proposal. The Proposal provides for the implementation of NYSEG’s Energy Smart Community (“ESC”) Project in
the Ithaca region which will serve as a test-bed for implementation and deployment of Reforming the Energy Vision (REV) initiatives. The ESC Project will
be supported by NYSEG’s planned rollout of Distribution Automation and Advanced Metering Infrastructure (AMI) to customers on circuits in the Ithaca
region. The Companies will also pursue Non-Wires Alternative projects as described in the Proposal. REV-related incremental costs and fees will be
included in the Rate Adjustment Mechanism (RAM) to the extent cost recovery is not provided for elsewhere. Under the Proposal, each company will
implement a RAM, which will be applicable to all customers, to return or collect RAM Eligible Deferrals and Costs, including: (1) property taxes; (2) Major
Storm deferral balances; (3) gas leak prone pipe replacement; (4) REV costs and fees which are not covered by other recovery mechanisms; and (5) NYSEG
Electric Pole Attachment revenues.
The Proposal provides for partial or full reconciliation of certain expenses including, but not limited to: pensions, other postretirement benefits; property
taxes; variable rate debt and new fixed rate debt; gas research and development; environmental remediation costs; Major Storms; nuclear electric insurance
limited credits; economic development; and Low Income Programs. The Proposal also includes a downward-only Net Plant reconciliation. In addition, the
Proposal includes downward-only reconciliations for the costs of: electric distribution and gas vegetation management; pipeline integrity; and incremental
maintenance. The Proposal provides that NYSEG and RGE continue their electric RDMs on a total revenue per class basis and their gas RDMs on a revenue
per customer basis.
The Administrative Law Judges assigned to the New York rate case will issue a procedural schedule establishing the remaining procedure for review and
decision on the Proposal. We expect hearings on the Proposal to be held in April 2016 and a NYPSC decision to be made in May 2016.
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AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Electric and Gas regulated utilities – Connecticut and Massachusetts
The distribution rates and allowed ROEs for Networks’ regulated utilities in Connecticut and Massachusetts are subject to regulation by the Connecticut
Public Utilities Regulatory Authority (PURA) and the Massachusetts Department of Public Utilities (DPU), respectively.
Under Connecticut law, UIs retail electricity customers are able to choose their electricity supplier while UI remains their electric distribution company. UI
purchases power for those of its customers under standard service rates who do not choose a retail electric supplier and have a maximum demand of less than
500 kilowatts and its customers under supplier of last resort service for those who are not eligible for standard service and who do not choose to purchase
electric generation service from a retail electric supplier. The cost of the power is a “pass-through” to those customers through the GSC charge on their bills.
UI has wholesale power supply agreements in place for its entire standard service load for the first half of 2016, 80% of its standard service load for the second
half of 2016 and for 30% of its standard service load for the first half of 2017. Supplier of last resort service is procured on a quarterly basis, however, from
time to time there are no bidders in the procurement process for supplier of last resort service and in such cases UI manages the load directly.
In August 2013, PURA approved new distribution rate schedules for UI for two years which became effective at that time and which, among other things,
increased the UI distribution and CTA allowed ROE from 8.75% to 9.15%, continued UI’s existing earnings sharing mechanism by which UI and customers
share on a 50/50 basis all distribution earnings above the allowed ROE in a calendar year, continued the existing decoupling mechanism, and approved the
establishment of the requested storm reserve. In accordance with the approval by PURA of the acquisition, UI agreed not to initiate a rate case for new rates
effective before at least January 1, 2017.
On January 22, 2014, PURA approved new base delivery rates for CNG, with an effective date of January 10, 2014, which, among other things, approved an
allowed ROE of 9.18%, a decoupling mechanism, and two separate ratemaking mechanisms that reconcile actual revenue requirements related to CNG’s cast
iron and bare steel replacement program and system expansion. Additionally, the final decision requires the establishment of an earnings sharing mechanism
by which CNG and customers share on a 50/50 basis all earnings above the allowed ROE in a calendar year. In accordance with the approval by PURA of the
acquisition, SCG and CNG agreed not to initiate a rate case for new rates effective before at least January 1, 2018.
Berkshire’s rates are established by the DPU. Berkshire’s 10-year rate plan, which was approved by the DPU and included an approved ROE of 10.5%,
expired on January 31, 2012. Berkshire continues to charge the rates that were in effect at the end of the rate plan. In accordance with the approval by the
DPU of the acquisition, Berkshire agreed not to initiate a rate case for new rates effective before at least June 1, 2018.
REV
In April 2014, the NYPSC commenced a proceeding entitled REV which is a wide ranging initiative to reform New York states energy industry and
regulatory practices. REV has been divided into two tracks, Track 1 for Market Design and Technology, and Track 2 for Regulatory Reform. REV proposes
regulatory changes that are intended to promote more efficient use of energy, deeper penetration of renewable energy resources such as wind and solar, and
wider deployment of distributed energy resources, such as micro grids, on-site power supplies and storage.
REV is also intended to promote greater use of advanced energy management products to enhance demand elasticity and efficiencies. Track 1 of this
initiative involves a collaborative process to examine the role of distribution utilities in enabling market based deployment of distributed energy resources to
promote load management and greater system efficiency, including peak load reductions. NYSEG and RGE are participating in the initiative with other New
York utilities and are providing their unique perspective. NYPSC staff is currently conducting public statement hearings regarding REV across New York
state. The NYPSC has issued a 2015 order in Track 1, which acknowledges the utilities’ role as a Distribution System Platform (DSP) provider, and requires
the utilities to file an initial Distribution System Implementation Plan (DSIP) by June 30, 2016. The DSIP will also include information regarding the
potential deployment of Automated Metering Infrastructure (AMI).
Various proceedings have also been initiated by the NYPSC which are REV related, and each proceeding has its own schedule. These proceedings include
the Clean Energy Fund, Demand Response Tariffs, and Community Choice Aggregation.
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AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Track 2 of the REV initiative is also underway, and through a NYPSC Staff Whitepaper review process, is examining potential changes in current regulatory,
tariff, market design and incentive structures which could better align utility interests with achieving New York state and NYPSCs policy objectives. New
York utilities will also be addressing related regulatory issues in their individual rate cases. We expect an Order by the end of the second quarter of 2016.
Ginna Reliability Support Service Agreement
Ginna Nuclear Power Plant, LLC (GNPP), which is a subsidiary of Constellation Energy Nuclear Group, LLC (CENG), owns and operates the R.E. Ginna
Nuclear Power Plant (Ginna Facility and together with GNPP, Ginna), a 581 MW single-unit pressurized water reactor located in Ontario, New York. In May
2014, the New York Independent System Operator (NYISO) produced a Reliability Study, confirming that the Ginna Facility needs to remain in operation to
avoid bulk transmission and non-bulk local distribution system reliability violations in 2015 and 2018.
On July 11, 2014, GNPP filed a petition requesting that the NYPSC initiate a proceeding to examine a proposal for the continued operation of the Ginna
Facility. Ginna asserted that “in the two preceding calendar years, 2012 and 2013, it had sustained cumulative losses at the Facility of nearly $100 million
(including the allocation of CENG corporate overhead)” and that “CENG has not been compensated for any operational risk or an appropriate return on its
investment over this period.” Based on the results of the 2014 Reliability Study, GNPP requested that: 1) the NYPSC determine that the continued operation
of the Ginna Facility is required to preserve system reliability; and 2) the NYPSC issue an Order directing RGE to negotiate and file a Reliability Support
Services Agreement (RSSA) for the continued operation of the Ginna Facility.
In November 2014, the NYPSC ruled that GNPP had demonstrated that the Ginna Facility is required to maintain system reliability and that its actions with
respect to meeting the relevant retirement notice requirements were satisfactory. The NYPSC also accepted the findings of the 2014 Reliability Study and
stated that it established “the reliability need for continued operation of the Ginna Facility that is the essential prerequisite to negotiating an RSSA.” As such,
the NYPSC ordered RGE and GNPP to negotiate an RSSA.
On February 13, 2015, RGE submitted to the NYPSC an executed RSSA between RGE and GNPP. RGE requested that the NYPSC accept the RSSA and
approve cost recovery by RGE from its customers of all amounts payable to GNPP under the RSSA utilizing the cost recovery surcharge mechanism.
On October 21, 2015, RGE, GNPP, New York Department of Public Service, Utility Intervention Unit and Multiple Intervenors filed a Joint Proposal with the
NYPSC for approval of the RSSA, as modified. The Joint Proposal provides a term of the RSSA from April 1, 2015 through March 31, 2017. RGE shall make
monthly payments to Ginna in the amount of $15.4 million. RGE will be entitled to 70% of revenues from Ginna’s sales into the NYISO energy and capacity
markets, while Ginna will be entitled to 30% of such revenues. The signatory parties recommend that the NYPSC authorize RGE to implement a rate
surcharge effective January 1, 2016 to recover amounts paid to Ginna pursuant to the RSSA. RGE's payment obligation to Ginna shall not begin until the rate
surcharge is in effect and FERC has issued an order authorizing the FERC Settlement agreement in the Settlement Docket. RGE will use deferred rate credit
amounts (regulatory liabilities) to offset the full amount of the Deferred Collection Amount (including carrying costs), plus credit amounts to offset all RSSA
costs that exceed $2.3 million per month, not to exceed a total use of credits in the amount of $110 million, applicable through June 30, 2017. To the extent
that the available credits are insufficient to satisfy the final payment from RGE to Ginna then the RSSA surcharge may continue past March 31, 2017 to
recover up to $2.3 million per month until the final payment has been recovered by RGE from ratepayers. In the month following the expiration of the term
on March 31, 2017, Ginna shall prepare and issue an invoice to RGE for, and RGE shall pay to Ginna, a one-time payment in the amount of $11.5 million,
which will be recovered from ratepayers. On February 23, 2016, the NYPSC unanimously adopted the Joint Proposal in the Ginna RSSA proceeding as in the
public interest. On March 1, 2016, FERC issued an Order approving the contested Settlement agreement, subject to conditions.
New York Transco
Affiliates of National Grid, Central Hudson, NYSEG, and RGE, together with an affiliate of Consolidated Edison and Orange and Rockland Utilities, are part
of a new organization, New York Transco. New York Transco is focused on developing electric transmission to meet future electricity needs of all New
Yorkers and will develop New York transmission projects upon receipt of all necessary regulatory approvals.
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AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
New York Transco members (Applicants) are requesting regulatory approval for a group of transmission projects expected to cost $1.7 billion, funded
through debt and equity. NYSEG and RGE allocated twenty-percent equity contribution amounts to approximately $183 million over the period 2015
through 2018. Additional projects may be developed in the future. Equity investments will be expressly contingent on receiving necessary regulatory
approvals and acceptable economic returns. The investment will be made through a Networks affiliate, Networks New York Transco, LLC, formed on
November 3, 2014.
New York Transco filed with FERC in early December 2014. The filing requests a formula base ROE of 10.6%, plus one-hundred fifty basis points ROE
incentives. The filing also requests recognition of construction work in process, abandoned plant, regulatory asset for pre-commercial costs, and sixty-percent
equity for five years. Various parties, including the NYPSC, have protested the filing with FERC.
On April 2, 2015, the FERC issued an order granting, inter alia, Applicants’ request for a 50 basis point adder for NY Transco’s membership in the NYISO
regional transmission organization (RTO), subject to the adder being capped within the zone of reasonableness after a determination of where within that
zone its base level ROE should be set. The FERC also set the formula rate and base ROE issue for hearing and settlement judge procedures. In addition, the
FERC rejected the Applicants’ cost allocation method for the Transmission Owner Transmission Solutions (TOTS) Projects because it would allocate costs to
Power Supply Long Island (LIPA) and New York Power Authority (NYPA) that they did not voluntarily agree to pay.
On November 5, 2015, Applicants, filed the Settlement with the FERC to resolve all outstanding issues associated with the TOTS Projects, including issues
related to the TOTS Projects that were set for hearing and issues pending on rehearing. The issues regarding certain other projects remain pending.
Minimum Equity Requirements for Regulated Subsidiaries
Our regulated utility subsidiaries (NYSEG, RGE, CMP and Maine Natural Gas) of Maine and New York are each subject to a minimum equity ratio
requirement that is tied to the capital structure assumed in establishing revenue requirements. The minimum equity ratio requirement has the effect of
limiting the amount of dividends that may be paid and may, under certain circumstances, require that the parent contribute equity capital. The regulated
utility subsidiaries are prohibited by regulation from lending to unregulated affiliates. The regulated utility subsidiaries have also agreed to minimum equity
ratio requirements in certain borrowing agreements. These requirements are lower than the regulatory requirements. Movement of capital from our wholly
owned unregulated subsidiaries is unrestricted.
Pursuant to agreements with the relevant utility commission, UI, SCG, CNG and BGC are restricted from paying dividends if paying such dividend would
result in a common equity ratio lower than 300 basis points below the equity percentage used to set rates in the most recent distribution rate proceeding as
measured using a trailing 13-month average calculated as of the most recent quarter end. In addition, UI, SCG, CNG and BGC are prohibited from paying
dividend to their parent if the utility’s credit rating as rated by any of the three major credit rating agencies, falls below investment grade, or if the utilitys
credit rating, as determined by two of the three major credit rating agencies falls to the lowest investment grade and there is a negative watch or review
downgrade notice.
New Renewable Source Generation
Under Connecticut law Public Act (PA 11-80), Connecticut electric utilities are required to enter into long-term contracts to purchase Connecticut Class I
Renewable Energy Certificates, or RECs, from renewable generators located on customer premises. Under this program, UI is required to enter into contracts
totaling approximately $200 million in commitments over an approximate 21-year period. The obligations will phase in over a six-year solicitation period,
and are expected to peak at an annual commitment level of about $13.6 million per year after all selected projects are online. Upon purchase, UI accounts for
the RECs as inventory. UI expects to partially mitigate the cost of these contracts through the resale of the RECs. PA 11-80 provides that the remaining costs
(and any benefits) of these contracts, including any gain or loss resulting from the resale of the RECs, are fully recoverable from (or credited to) customers
through electric rates.
On October 23, 2013, PURA approved UI’s renewable connections program filed in accordance with PA 11-80, through which UI will develop up to 10 MW
of renewable generation. The costs for this program will be recovered on a cost of service basis. PURA established a base ROE to be calculated as the greater
of: (A) the current UI authorized distribution ROE (currently 9.15%) plus 25 basis points and (B) the current authorized distribution ROE for CL&P (currently
9.17%), less target equivalent market revenues (reflected as 25 basis points). In addition, UI will retain a percentage of the market revenues from the project,
which percentage is expected to equate to approximately 25 basis points on a levelized basis over the life of the project. UI expects the cost of this
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AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
program, a planned 2.8 MW fuel cell facility in New Haven, solar photovoltaic and fuel cell facilities totaling 5 MW in Bridgeport, and a 2.2 MW fuel cell
facility in Woodbridge to be approximately $47 million.
Pursuant to Section 8 of Public Act 13-303, “An Act Concerning Connecticuts Clean Energy Goals,(PA 13-303), in January 2014, at DEEP’s direction, UI
entered into three contracts for the purchase of RECs associated with an aggregate of 5.7 MW of energy production from biomass plants in New England. The
costs of these agreements will be fully recoverable through electric rates.
New England East-West Solution
Pursuant to an agreement with The Connecticut Light and Power Company, or CL&P (the Agreement), UI has the right to invest in, and own transmission
assets associated with, the Connecticut portion of CL&P’s New England East West Solution (NEEWS) projects to improve regional energy reliability.
NEEWS originally consisted of four inter-related transmission projects being developed by subsidiaries of Northeast Utilities (doing business as Eversource
Energy), the parent company of CL&P, in collaboration with National Grid USA. Three of the original projects have portions located in Connecticut: (1) the
Greater Springfield Reliability Project (GSRP), which was fully energized in November 2013, (2) the Interstate Reliability Project (IRP), which was placed in
service in the fourth quarter 2015 and (3) the Central Connecticut Reliability Project, the need for which is now planned to be addressed by CL&P’s Greater
Hartford Central Connecticut solutions, in which UI does not anticipate making any investments.
Under the Agreement, as of December 31, 2015, UI had made aggregate deposits of approximately $45 million since its inception, with assets valued at
approximately $44.6 million having been transferred to UI. UI does not anticipate making any additional investments in NEEWS under the agreement.
Equity Investment in Peaking Generation
UI is party to a 50-50 joint venture with NRG affiliates in GenConn, which operates two peaking generation plants in Connecticut. The two peaking
generation plants, GenConn Devon and GenConn Middletown, are both participating in the ISO-New England markets. PURA has approved revenue
requirements for the period from January 1, 2015 through December 31, 2015 of $29.5 million and $36.5 million for GenConn Devon and GenConn
Middletown, respectively. In addition, PURA has ruled that GenConn project costs incurred that were in excess of the proposed costs originally submitted in
2008 were prudently incurred and are recoverable. Such costs are included in the determination of the 2015 approved revenue requirements.
Note 6. Regulatory Assets and Liabilities
Pursuant to the requirements concerning accounting for regulated operations, our utilities capitalize, as regulatory assets, incurred and accrued costs that are
probable of recovery in future electric and natural gas rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that
allow for recovery of certain costs over a specific period, or allow for reconciliation or deferral of certain costs. When costs are not treated in a specific order
we use regulatory precedent to determine if recovery is probable. Our operating utilities also record, as regulatory liabilities, obligations to refund previously
collected revenue or to spend revenue collected from customers on future costs. Substantially all assets or liabilities for which funds have been expended or
received are either included in rate base or are accruing a carrying cost until they will be included in rate base. The primary items that are not included in rate
base or accruing carrying costs are the regulatory assets for qualified pension and other postretirement benefits, which reflect unrecognized actuarial gains
and losses, debt premium, environmental remediation costs which is primarily the offset of accrued liabilities for future spending, unfunded future income
taxes, asset retirement obligations, hedge losses and contracts for differences. The total amount of these items is $2,825 million.
Regulatory assets and other regulatory liabilities shown in the tables below result from various regulatory orders that allow for the deferral and or
reconciliation of specific costs. Regulatory assets and regulatory liabilities are classified as current when recovery or refund in the coming year is allowed or
required through a specific order or when the rates related to a specific regulatory asset or regulatory liability are subject to automatic annual adjustment.
Most of the items related to NYSEG for which the amortization period has been characterized as to be determined in a future proceeding have been addressed
in the Proposal. If the Proposal is approved, most of these items would be amortized over a five year period, except the portion of storm costs to be recovered
over ten years and plant related tax items which will be amortized over the life of associated plant. Annual amortization expense for NYSEG would be
approximately $16.5 million per rate year. The RGE items that would begin being amortized are plant related tax items. A majority of the other items related
to RGE, which net to a regulatory liability, will not be amortized until future proceedings or will be used to recover costs of the Ginna RSSA agreement.
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AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Current and non-current regulatory assets as of December 31, 2015 and 2014 consisted of:
As of December 31, 2015 2014
(Millions)
Current
Pension and other postretirement benefits cost
deferrals $ 8 $
Pension and other postretirement benefits 13
Storm costs 8 14
Temporary supplemental assessment surcharge 7 12
Hedges losses 37 34
Contracts for differences 18
Hardship programs 13
Deferred purchased gas 12
Deferred transmission expense 12
Environmental remediation costs 37
Other 54 20
Total Current Regulatory Assets 219 80
Non-current
Pension and other postretirement benefits cost
deferrals 151 125
Pension and other postretirement benefits 1,509 1,101
Storm costs 251 259
Deferred meter replacement costs 34 36
Unamortized losses on reacquired debt 23 25
Environmental remediation costs 271 247
Unfunded future income taxes 549 366
Asset retirement obligation 24 32
Deferred property tax 45 30
Federal tax depreciation normalization adjustment 158 128
Merger capital expense target customer credit 15 10
Debt premium 141
Contracts for differences 50
Hardship programs 29 14
Other 64 26
Total Non-current Regulatory Assets $ 3,314 $ 2,399
“Pension and other postretirement benefits” represent the actuarial losses on the pension and other postretirement plans that will be reflected in customer
rates when they are amortized and recognized in future pension expenses. Pension and other postretirement benefits cost deferrals” include the difference
between actual expense for pension and other postretirement benefits and the amount provided for in rates. The recovery of these amounts will be determined
in future proceedings.
“Storm costs” for CMP, NYSEG, and RGE are allowed in rates based on an estimate of the routine costs of service restoration. The companies are also allowed
to defer unusually high levels of service restoration costs resulting from major storms when they meet certain criteria for severity and duration. Since the
approval of the 2010 rate plan in New York, NYSEG has experienced unusually high levels of restoration costs resulting from various storms including
Hurricane Sandy, Hurricane Irene, and Tropical Storm Lee. NYSEGs deferred storm costs, reflecting the over (under) spending of actual costs compared with
amounts currently allowed in rates, was $(9) million and $5 million for the years ended December 31, 2015 and 2014, respectively. NYSEGs total deferral,
including carrying costs, was $247 million and $241 million as of December 31, 2015 and 2014, respectively. The amortization will be determined in a
future NYPSC proceeding. CMP’s deferred service restoration costs, primarily as a result of an ice storm in late December 2014, reflecting over (under)
spending of actual costs compared with amounts allowed in rates, was $(6) million and $15 million for the years ended December 31, 2015 and 2014,
respectively. CMPs total deferral, including carrying costs, was $12 million and $32 million as of December 31, 2015 and 2014, respectively. Recovery of
CMP’s deferred storm costs in the amount of $28 million began with the effective date of its last rate case and occurs over a twenty-four month period.
Recovery of incremental deferrals will be determined in a future proceeding.
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Notes to Combined and Consolidated Financial Statements (Continued)
“Deferred meter replacement costs” represent the deferral of the value of retired meters which were replaced by advanced metering infrastructure meters. This
amount is being amortized at the related existing depreciation amounts.
“Unamortized losses on reacquired debtrepresent deferred losses on debt reacquisitions that will be recovered over the remaining original amortization
period of the reacquired debt.
“Environmental remediation costs” includes spending that has occurred and is eligible for future recovery in customer rates. Environmental costs are
currently recovered through a reserve mechanism whereby projected spending is included in rates with any variance recorded as a regulatory asset or a
regulatory liability. The amortization period will be established in future proceedings and will depend upon the timing of spending for the remediation costs.
It also includes the anticipated future rate recovery of costs that are recorded as environmental liabilities since these will be recovered when
incurred. Because no funds have yet been expended for the regulatory asset related to future spending, it does not accrue carrying costs and is not included
within rate base.
“Unfunded future income taxes” represent unrecovered federal and state income taxes primarily resulting from regulatory flow through accounting treatment.
The income tax benefits or charges for certain plant related timing differences, such as removal costs, are immediately flowed through to, or collected from,
customers. This amount is being amortized as the amounts related to temporary differences that give rise to the deferrals are recovered in rates.
“Asset retirement obligationrepresents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts
through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability.
“Deferred property taxes” represent the customer portion of the difference between actual expense for property taxes and the amount provided for in rates.
The amortization period is awaiting a future NYPSC rate proceeding.
“Federal tax depreciation normalization adjustment” represents the revenue requirement impact of the difference in the deferred income tax expense required
to be recorded under the IRS normalization rules and the amount of deferred income tax expense that was included in cost of service for rates years covering
2011 forward. The recovery period will be determined in future NYPSC and MPUC rate proceedings.
“Debt premium” represents the regulatory asset recorded to offset the fair value adjustment to the regulatory component of the non-current debt of UIL at the
acquisition date.
“Hardship Programs” represent hardship customer accounts deferred for future recovery to the extent they exceed the amount in rates.
“Deferred Purchased Gas” represents the difference between actual gas costs and gas costs collected in rates.
“Contracts for Differences” represent the deferral of unrealized gains and losses on contracts for differences derivative contracts. The balance fluctuates based
upon quarterly market analysis performed on the related derivatives. The amounts, which do not earn a return, are fully offset by a corresponding derivative
asset/liability.
“Deferred Transmission Expense” represents deferred transmission income or expense and fluctuates based upon actual revenues and revenue requirements.
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AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Current and non-current regulatory liabilities as of December 31, 2015 and 2014 consisted of:
As of December 31, 2015 2014
(Millions)
Current
Reliability support services (Cayuga) $ 16 $ 18
Plant decommissioning 13
Non by-passable charges 7 19
Energy efficiency portfolio standard 33 34
Gas supply charge and deferred natural gas cost 6 6
Transmission revenue reconciliation mechanism 16 23
Yankee DOE Phase I 5 23
Merger related rate credits 20
Revenue decoupling mechanism 14 8
Other 30 21
Total Current Regulatory Liabilities 147 165
Non-current
Accrued removal obligations 1,084 721
Asset sale gain account 8 19
Carrying costs on deferred income tax bonus depreciation 116 81
Economic development 36 33
Merger capital expense target customer credit account 17 17
Pension and other postretirement benefits 90 50
Positive benefit adjustment 51 51
New York state tax rate change 17 16
Post term amortization 25 20
Theoretical reserve flow thru impact 31 24
Deferred property tax 15 51
Net plant reconciliation 10 10
Variable rate debt 32 25
Carrying costs on deferred income tax - Mixed Services 263(a) 31 20
Rate refund – FERC ROE proceeding 21 23
Merger related rate credits 24
Accumulated deferred investment tax credits 10
Asset retirement obligation 13
Middletown/Norwalk local transmission network service collections 19
Excess generation service charge 21
Low income programs 42 10
Unfunded future income taxes 27
Non-firm margin sharing credits 8
Deferred income taxes regulatory 519 433
Other 93 58
Total Non-current Regulatory Liabilities $ 2,360 $ 1,662
“Reliability support services (Cayuga)” represent the difference between actual expenses for reliability support services and the amount provided for in rates.
This will be refunded to customers within the next year.
“Non by-passable charges” represent the non by-passable fixed charge paid by all customers. An asset or liability is recognized resulting from differences
between actual revenues and the underlying cost being recovered. This liability will be refunded to customers within the next year.
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AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
“Energy efficiency portfolio standard” represents the difference between revenue billed to customers through an energy efficiency charge and the costs of our
energy efficiency programs as approved by the state authorities. This may be refunded to customers within the next year.
“Accrued removal obligations” represent the differences between asset removal costs recorded and amounts collected in rates for those costs. The
amortization period is dependent upon the asset removal costs of underlying assets and the life of the utility plant.
“Asset sale gain account” represents the gain on NYSEG’s 2001 sale of its interest in Nine Mile Point 2 nuclear generating station. The net proceeds from the
Nine Mile Point 2 nuclear generating station were placed in this account and will be used to benefit customers. The amortization period is awaiting a future
NYPSC rate proceeding.
“Carrying costs on deferred income tax bonus depreciationrepresent the carrying costs benefit of increased accumulated deferred income taxes created by
the change in tax law allowing bonus depreciation. The amortization period is awaiting a future NYPSC rate proceeding.
“Economic development” represents the economic development program which enables NYSEG and RGE to foster economic development through
attraction, expansion, and retention of businesses within its service territory. If the level of actual expenditures for economic development allocated to
NYSEG and RGE varies in any rate year from the level provided for in rates, the difference is refunded to ratepayers. The amortization period is awaiting a
future NYPSC rate proceeding.
“Merger capital expense target customer credit” account was created as a result of NYSEG and RGE not meeting certain capital expenditure requirements
established in the order approving the purchase of Energy East by Iberdrola. The amortization period is awaiting a future NYPSC rate proceeding.
“Pension and other postretirement benefits” represent the actuarial gains on other postretirement plans that will be reflected in customer rates when they are
amortized and recognized in future expenses. Because no funds have yet been received for this a regulatory liability is not reflected within rate base. It also
represents the difference between actual expense for pension and other postretirement benefits and the amount provided for in rates. Recovery of these
amounts will be determined in future proceedings.
“Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisitions of Energy East. This is being used to moderate increases in rates. The amortization
period is awaiting a future NYPSC rate proceeding.
“New York state tax rate change” represents excess funded accumulated deferred income tax balance caused by the 2014 New York state tax rate change from
7.1% to 6.5%. The amortization period is awaiting a future NYPSC rate proceeding.
“Post term amortizationrepresents the revenue requirement associated with certain expired joint proposal amortization items. The amortization period is
awaiting a future NYPSC rate proceeding.
“Theoretical reserve flow thru impactrepresents the differences from the rate allowance for applicable federal and state flow through impacts related to the
excess depreciation reserve amortization. It also represents the carrying cost on the differences. The amortization period is awaiting a future NYPSC rate
proceeding.
“Merger related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. See Merger Settlement Agreement in Note
4 for further details.
“Excess generation service charge” represents deferred generation-related and non by-passable federally mandated congestion costs or revenues for future
recovery from or return to customers. Amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred.
“Low Income Programs” represent various hardship and payment plan programs approved for recovery.
“Otherincludes cost of removal being amortized through rates and various items subject to reconciliation including variable rate debt, Medicare subsidy
benefits and stray voltage collections.
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AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Note 7. Goodwill and Intangible assets
Goodwill by reportable segment as of December 31, 2015 and 2014 consisted of:
As of December 31, 2015 2014
(Millions)
Networks $ 2,733 $ 979
Renewables 380 380
Gas
Other (a) 2 2
Total $ 3,115 $ 1,361
(a) Does not represent a reportable segment. It mainly includes Corporate and company eliminations.
As of December 31, 2015 and 2014, the gross amounts of goodwill were $2,733 million for Networks reportable segment, $3,340 million for Renewables and
Gas reportable segments and $2 million for Corporation (which does not represent a segment), with accumulated impairment losses of $2,960 million for
Renewables and Gas reporting segments. During the year ended December 31, 2015 goodwill in Networks reportable segment increased $1,754 million due
to acquisition of UIL (See Note 4 Acquisition of UIL – for further details).
Goodwill Impairment Assessment
For impairment testing purposes our reporting units are the same as operating segments, except for Networks, which contained two reporting units, Maine and
New York as of December 31, 2014 and three reporting units, Maine, New York and UIL as of December 31, 2015. The goodwill for the Maine reporting unit
resulted from the purchase of CMP by Energy East in 2000 and amounted to $325 million. Separately, the goodwill for the New York reporting unit resulted
primarily from the purchase of RGE by Energy East in 2002 and amounted to $654 million. The goodwill for the UIL reporting unit was generated from the
acquisition of UIL on December 16, 2015 and amounted to $1,754 million.
Our annual impairment testing takes place as of October 1. Our step zero qualitative assessment involves evaluating key events and circumstances that could
affect the fair value of our reporting units, as well as other factors. Events and circumstances evaluated include macroeconomic conditions, industry,
regulatory and market considerations, cost factors and their effect on earnings and cash flows, overall financial performance as compared with projected
results and actual results of relevant prior periods, other relevant entity specific events, and events affecting a reporting unit.
Our step one impairment testing includes various assumptions, primarily the discount rate, which is based on an estimate of our marginal, weighted average
cost of capital, and forecasted cash flows. We test the reasonableness of the conclusions of our step one impairment testing using a range of discount rates and
a range of assumptions for long term cash flows. In 2015 the impairment testing of goodwill for Networks includes Maine and New York reporting units.
2015
We had no impairment of goodwill in 2015 as a result of our impairment testing.
Networks
As a result of our step zero qualitative assessment, it was not more likely than not that the fair value of each of the Networks reporting units was less than its
carrying amount and it was not necessary to perform the two-step goodwill impairment test. The step zero qualitative assessment was performed in 2015
considering the substantial excess of fair value over the carrying value that was demonstrated in the 2014 impairment test. The qualitative assessment
considered key factors such as the level of interest rates, the regulatory environment including the allowed rate of return, and projections of future sales and
capital spending. None of these factors had changed significantly since 2014.
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AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Renewables
Based on the results of our step 1 impairment test for the Renewables reporting unit conducted in 2015, its estimated fair value exceeds carrying value by
approximately 1.55%. The assumptions used to estimate fair value were based on projections incorporated in our current operating plans as well as other
available information. The current operating plans included significant assumptions and estimates associated with sales growth, profitability and related cash
flows, along with cash flows associated with taxes and capital spending. The discount rate used to estimate fair value was risk adjusted in consideration of the
economic conditions of the reporting unit. We also considered other assumptions that market participants may use. By their nature, projections are uncertain.
Potential events and circumstances, such as declining wind energy output and prices obtained per MWh, changes in incentives established to promote
renewable energies and increases in capital expenditures per MW could have an adverse effect on our assumptions.
2014
We had no impairment of goodwill in 2014 as a result of our impairment testing.
Networks
Based on the results of our step 1 impairment test conducted in 2014, the estimated fair value of each of the Networks reporting units was substantially in
excess of their respective carrying value.
Renewables
Based on the results of our step 1 impairment test for the Renewables reporting unit conducted in 2014, its estimated fair value exceeds carrying value by
approximately 1%. The assumptions used to estimate fair value were based on projections incorporated in our current operating plans as well as other
available information. The current operating plans included significant assumptions and estimates associated with sales growth, profitability and related cash
flows, along with cash flows associated with taxes and capital spending. The discount rate used to estimate fair value was risk adjusted in consideration of the
economic conditions of the reporting unit. We also considered other assumptions that market participants may use. By their nature, projections are uncertain.
Potential events and circumstances, such as declining wind energy output and prices obtained per MWh, changes in incentives established to promote
renewable energies and increases in capital expenditures per MW could have an adverse effect on our assumptions.
2013
Networks
As a result of our step zero qualitative assessment, it was not more likely than not that the fair value of each of the Networks reporting units was less than its
carrying amount, and it was not necessary to perform the two-step goodwill impairment test. The step zero qualitative assessment was performed in 2013
considering the substantial excess of fair value over the carrying value that was demonstrated in the 2011 impairment test. The qualitative assessment
considered key factors such as the level of interest rates, the regulatory environment including the allowed rate of return, and projections of future sales and
capital spending. None of these factors had changed significantly since 2011.
Renewables
Based on the results of our step 1 impairment test for the Renewables reporting unit conducted in 2013, the estimated fair value exceeded the carrying value
by approximately 11%.
Gas
Based on the results of our step 1 impairment test the Gas reporting unit fair value analysis resulted in an implied fair value of goodwill of $0 for this
reporting unit, and consequently, a non-cash impairment charge in the amount of $163 million was recorded for the year ended December 31, 2013. The
inputs used to determine the fair value of the Gas reporting unit were based on forecasted cash flows, which are classified as Level 3 in the fair value
hierarchy. The main reason for the impairment was the projected long-term low margins for natural gas given the impact of shale gas in the North American
energy market. We elected to suspend the gas storage facility construction projects of this reporting unit until this scenario substantially changes.
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AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Intangible assets
Intangible assets include those assets acquired in business acquisitions and intangible assets acquired and developed from external third parties and from
affiliated companies. Following is a summary of intangible assets:
As of December 31, 2015
Gross
Carrying
Amount
Accumulated
Amortization
Net
Carrying
Amount
(Millions)
Gas Storage rights $ 324 $ (116 ) $ 208
Wind development 584 (243 ) 341
Other 15 (8 ) 7
Total Intangible Assets $ 923 $ (367 ) $ 556
As of December 31, 2014
Gross
Carrying
Amount
Accumulated
Amortization
Net
Carrying
Amount
(Millions)
Gas Storage rights $ 325 $ (117 ) $ 208
Wind development 574 (220 ) 354
Other 56 (49 ) 7
Total Intangible Assets $ 955 $ (386 ) $ 569
Gas Storage rights are being amortized on a straight-line basis over a 40-year estimated life. Wind development costs, with the exception of futurepipeline
development costs, are amortized on a straight-line basis in accordance with the life of the related assets. Amortization expense for the years ended December
31, 2015, 2014 and 2013 amounted to $54 million, $66 million and $72 million, respectively. We do not believe our future cash flows will impact the
recoverability of our intangible assets.
We expect amortization expense for the five years subsequent to December 31, 2015, to be as follows:
Year ending December 31,
(Millions)
2016 $ 27
2017 25
2018 24
2019 26
2020 25
As a result of writing off of fully amortized intangibles assets relating to Gas Storage rights, $6.5 million was removed from both cost and accumulated
amortization during 2015.
Wind development costs written off totaled $42 million in 2013. These charges were included in Impairment of non-current assets in the combined and
consolidated statements of operations.
119
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Note 8. Property, Plant and Equipment
Property, plant and equipment as of December 31, 2015 consisted of:
As of December 31, 2015 Regulated Nonregulated Total
(Millions)
Electric generation, distribution, transmission and
other $ 11,506 $ 10,058 $ 21,564
Natural gas transportation, distribution and other 2,673 651 3,324
Other common operating property 817 40 857
Total Property, Plant and Equipment in Service (a) 14,996 10,749 25,745
Total accumulated depreciation (b) (3,727) (2,645 ) (6,372)
Total Net Property, Plant and Equipment in Service 11,269 8,104 19,373
Construction work in progress 1,094 244 1,338
Total Property, Plant and Equipment $ 12,363 $ 8,348 $ 20,711
(a) Includes capitalized leases of $178 million primarily related to electric generation, distribution, transmission and other.
(b) Includes accumulated amortization of capitalized leases of $53 million.
Property, plant and equipment as of December 31, 2014 consisted of:
As of December 31, 2014 Regulated Nonregulated Total
(Millions)
Electric generation, distribution, transmission and
other $ 8,625 $ 9,798 $ 18,423
Natural gas transportation, distribution and other 1,723 648 2,371
Other common operating property 654 51 705
Total Property, Plant and Equipment in Service (a) 11,002 10,497 21,499
Total accumulated depreciation (b) (3,491) (2,271 ) (5,762)
Total Net Property, Plant and Equipment in Service 7,511 8,226 15,737
Construction work in progress 878 518 1,396
Total Property, Plant and Equipment $ 8,389 $ 8,744 $ 17,133
(a) Includes capitalized leases of $158 million primarily related to electric generation, distribution, transmission and other.
(b) Includes accumulated amortization of capitalized leases of $47 million.
Capitalized interest costs were $13 million, $12 million, and $9 million for the years ended December 31, 2015, 2014 and 2013, respectively.
In view of the projected long-term low margins for natural gas as a result of the impact of shale gas in the North American energy market, in 2013 we
abandoned the gas storage facility construction projects assigned to the gas reporting unit. Consequently, we impaired or wrote off certain gas storage
projects and other facilities under construction for an amount of $382 million, included in Impairment of non-current assets” in the combined and
consolidated statements of operations for the year ended December 31, 2013.
We also impaired or wrote off amounts of $12 million, $24 million, and $33 million for the years ended December 31, 2015, 2014 and 2013 respectively,
resulting from reassessment of the economic feasibility of its various Renewables development projects in construction.
Depreciation expense for the years ended December 31, 2015, 2014 and 2013 amounted to $641 million, $563 million and $522 million, respectively.
Note 9. Asset retirement obligations
AROs are intended to meet the costs for dismantling and restoration work that we have committed to carry out at our operational facilities.
120
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
The reconciliation of ARO carrying amounts for the years ended December 31, 2015 and 2014 consisted of:
(Millions)
As of December 31, 2013 $ 209
Liabilities settled during the year (1)
Liabilities incurred during the year 6
Accretion expense 14
Revisions in estimated cash flows 6
As of December 31, 2014 $ 234
Liabilities settled during the year (16)
Liabilities incurred during the year -
Accretion expense 14
Revisions in estimated cash flows (48)
As of December 31, 2015 $ 184
Several of the wind generation facilities have restricted cash for purposes of settling AROs. Restricted cash related to AROs was $1.8 million and $1.7 million
as of December 31, 2015 and 2014, respectively. These amounts have been included as other non-current assets in the consolidated balance sheets. Accretion
expenses are included in “Operations and maintenance” in the combined and consolidated statements of operations.
We have AROs for which a liability has not been recognized because the fair value cannot be reasonably estimated due to indeterminate settlement dates,
including for the removal of hydroelectric dams due to structural inadequacy or for decommissioning; the removal of property upon termination of an
easement, right-of-way or franchise; and costs for abandonment of certain types of gas mains.
In 2015 we revised our model used to estimate the future undiscounted costs for removal of our wind and solar facilities, based upon a study performed by an
independent engineering firm that specializes in such matters. This revision resulted in a lower estimate of future removal costs, which we estimate will result
in a $5 million annual reduction in expense going forward.
Note 10. Debt
Long- term debt as of December 31, 2015 and 2014 consisted of:
As of December 31, 2015 2014
(Millions) Maturity Dates Balances Interest Rates Balances Interest Rates
First mortgage bonds - fixed (a) 2016-2045 $ 1,815 3.07%-10.60% $ 1,405 3.07%-8.00%
Unsecured pollution control notes - fixed 2020 200 2.00%-2.375% 132 2.125%-2.25%
Unsecured pollution control notes –
variable 2032-2034 219 0.195%-1.181% 159 0.03%-0.461%
Other various non-current debt - fixed 2016-2045 2,440 2.89%-10.48% 889 3.24%-10.48%
Total Debt $ 4,674 $ 2,585
Obligations under capital leases 2020-2023 87 4%-4.44% 81 4%-4.44%
Unamortized debt (costs) premium, net (25) (29 )
Less: debt due within one year, included
in current liabilities 206 148
Total Non-current Debt $ 4,530 $ 2,489
(a) The first mortgage bonds have pledged collateral of substantially all the respective utility’s properties of approximately $5,682 million.
In January 2015, CMP issued $150 million of first mortgage bonds in three tranches: $65 million maturing in 2025 bearing a coupon of 3.15%, $20 million
maturing in 2030 bearing a coupon of 3.37%, and $65 million maturing in 2045 bearing a coupon of 4.07%.
In April 2015, NYSEG issued $200 million of fixed rate pollution control notes in four separate series. The notes have mandatory redemption dates in 2020.
$99 million of the notes bear an interest rate of 2.375% and $101 million bear an interest rate of 2.00%.
121
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Non-current debt, including sinking fund obligations and capital lease payments, due over the next five years consists of:
(Millions)
2016 2017 2018 2019 2020 Total
$ 206 $ 302 $ 162 $ 354 $ 721 $ 1,745
We make certain standard covenants to lenders in our third-party debt agreements, including, in certain agreements, covenants regarding the ratio of
indebtedness to total capitalization. A breach of any covenant in the existing credit facilities or the agreements governing our other indebtedness would
result in an event of default. Certain events of default may trigger automatic acceleration. Other events of default may be remedied by the borrower within a
specified period or waived by the lenders and, if not remedied or waived, give the lenders the right to accelerate. Neither we nor any of our subsidiaries were
in breach of covenants or of any obligation that could trigger the early redemption of our debt as of December 31, 2015 and 2014.
Fair Value of Debt
The estimated fair value of debt amounted to $4,985 million and $2,962 million as of December 31, 2015 and 2014, respectively. The estimated fair value
was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rate curve used to make these calculations takes into
account the risks associated with the electricity industry and the credit ratings of the borrowers in each case. The fair value hierarchy pertaining to the fair
value of debt is considered as Level 2, except for unsecured pollution control notes-variable with a fair value of $204 million and $145 million, respectively,
as of December 31, 2015 and 2014, which are considered Level 3. The fair value of these unsecured pollution control notes-variable are determined using
unobservable interest rates as the market for these notes is inactive.
Short-term Debt
(a) AVANGRID Revolving credit facility
In May 2012, we entered into a $300 million revolving credit facility for the purpose of providing for our liquidity needs and those of our unregulated
subsidiaries. The facility has a termination date in May 2019. We pay an annual facility fee of $0.7 million. As of December 31, 2015 and December 31, 2014
the facility was undrawn.
The revolving credit facility contains a covenant that requires us to maintain a ratio of consolidated indebtedness to consolidated total capitalization that
does not exceed 0.65 to 1.00 at any time. For purposes of calculating this maximum ratio of consolidated indebtedness to consolidated total capitalization,
the facility excludes from consolidated net worth the balance of accumulated other comprehensive income (AOCI) as it appears on the consolidated balance
sheets.
(b) Iberdrola Financiación, S.A. credit facility
In August 2011, we entered into a revolving credit facility with Iberdrola Financiación, S.A., a subsidiary of Iberdrola, under which we could borrow up to
$600 million. The facility was terminated by AVANGRID on October 28, 2015. The facility was never utilized.
(c) Joint utility revolving credit facility
In July 2011, NYSEG, RGE and CMP jointly entered into a bank provided revolving credit facility (Joint Utility Facility) that allows maximum aggregate
borrowings of up to $600 million and expires in July 2018. Each subsidiary is currently subject to a $200 million credit limit. Each borrower pays a facility
fee ranging from fifteen to twenty basis points annually depending on the rating of its unsecured debt.
CMP and NYSEG have established commercial paper programs backstopped by the Joint Utility Facility. These companies use commercial paper as an
alternative to revolving credit facilities as a source of short-term credit.
In the Joint Utility Facility each joint borrower covenants not to permit, without the lender’s consent, its ratio of total indebtedness to total capitalization to
exceed 0.65 to 1.00 at any time. For purposes of calculating the maximum ratio of consolidated indebtedness to total capitalization, the facility excludes
from consolidated net worth the balance of AOCI as it appears on the consolidated balance sheets. As of December 31, 2015 and December 31, 2014 there
were no outstanding loans, no outstanding commercial paper and $14 million of outstanding letters of credit at both dates.
122
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
(d) UIL credit facility
In November 2011 UIL, UI, CNG, SCG, and Berkshire became parties to a revolving credit agreement that will expire on November 30, 2016 (the UIL Credit
Facility). The aggregate borrowing limit under the UIL Credit Facility is $400 million, all of which is available to UIL, $250 million of which is available to
UI, $150 million of which is available to each of CNG and SCG, and $25 million of which is available to Berkshire, all subject to the aggregate limit of $400
million. UIL pays a facility fee of twenty basis points annually.
The UIL Credit Facility contains a covenant that requires each borrower to maintain a ratio of consolidated indebtedness to consolidated total capitalization
that does not exceed 0.65 to 1.00 at any time. For purposes of calculating this maximum ratio of consolidated indebtedness to consolidated total
capitalization, the facility excludes from consolidated net worth unrealized gains and losses reflected in other comprehensive income in respect of qualified
and non-qualified defined benefit pension plans, as well as other post-retirement benefit plans of such borrower.
As of December 31, 2015 there were $163 million in outstanding loans bearing interest rate of 1.57%, and there was $4 million in outstanding letters of
credit.
Note 11. Fair Value of Financial Instruments and Fair Value Measurements
We determine the fair value of our derivative assets and liabilities and available for sale noncurrent investments associated with Networks activities utilizing
market approach valuation techniques:
We measure the fair value of our noncurrent investments using quoted market prices in active markets for identical assets and include the
measurements in Level 1. The available for sale investments which are Rabbi Trusts for deferred compensation plans primarily consist of money
market funds and are included in Level 1 fair value measurement.
NYSEG and RGE enter into electric energy derivative contracts to hedge the forecasted purchases required to serve their electric load obligations.
They hedge their electric load obligations using derivative contracts that are settled based upon Locational Based Marginal Pricing published by the
New York Independent System Operator (NYISO). RGE hedges all its electric load obligations using contracts for a NYISO location where an active
market exists. The forward market prices used to value RGE’s open electric energy derivative contracts are based on quoted prices in active markets for
identical assets or liabilities with no adjustment required and therefore we include the fair value in Level 1. NYSEG has a combination of Level 1 and
Level 2 fair values for its electric energy derivative contracts. A portion of its electric load obligations are exchange traded contracts in a NYISO
location where an active market exists. The forward market prices used to value NYSEG’s open electric energy derivative contracts are based on
quoted prices in active markets for identical assets or liabilities with no adjustment required and therefore we include the fair value in Level 1. A
portion of NYSEG’s electric energy derivative contracts are non-exchange traded contracts that are valued using inputs that are directly observable for
the asset or liability, or indirectly observable through corroboration with observable market data and therefore we include the fair value in Level 2.
NYSEG and RGE enter into natural gas derivative contracts to hedge their forecasted purchases required to serve their natural gas load obligations.
The forward market prices used to value open natural gas derivative contracts are exchange-based prices for the identical derivative contracts traded
actively on the New York Mercantile Exchange (NYMEX). Because we use prices quoted in an active market we include the fair value measurements
in Level 1.
NYSEG, RGE and CMP enter into fuel derivative contracts to hedge their unleaded and diesel fuel requirements for their fleet vehicles. Exchange-
based forward market prices are used but because an unobservable basis adjustment is added to the forward prices we include the fair value
measurement for these contracts in Level 3.
Contracts for differences (CfDs) entered into by UI are marked-to-market based on a probability-based expected cash flow analysis that is discounted
at risk-free interest rates and an adjustment for non-performance risk using credit default swap rates. We include the fair value measurement for these
contracts in Level 3 (See Note 12 for further discussion on CfDs).
We determine the fair value of our derivative assets and liabilities associated with Renewables and Gas activities utilizing market approach valuation
techniques. Exchange-traded transactions, such as NYMEX futures contracts, that are based on quoted market prices in active markets for identical product
with no adjustment are included in the Level 1 fair value. Contracts with delivery periods of two years or less which are traded in active markets and are
valued with or derived from observable market data for identical or similar products such as over-the-counter NYMEX, foreign exchange swaps, and fixed
price physical and basis and index trades are included in Level 2 fair value. Contracts with delivery periods exceeding two years or that have unobservable
inputs or inputs that cannot be corroborated with market data for identical or similar products are included in Level 3 fair value. The unobservable inputs
123
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
include historical volatilities and correlations for tolling arrangements and extrapolated values for certain power swaps. The valuation for this category is
based on our judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists.
The financial instruments measured at fair value as of December 31, 2015 and 2014 consisted of:
As of December 31, 2015 Level 1 Level 2 Level 3 Netting Total
(Millions)
Securities portfolio (available for sale) $ 39 $ $ $ $ 39
Derivative assets
Derivative financial instruments - power 10 81 48 (71 ) 68
Derivative financial instruments - gas 267 25 68 (280 ) 80
Contracts for differences (CfDs) 29 29
Total 277 106 145 (351 ) 177
Derivative liabilities
Derivative financial instruments - power (43 ) (12 ) (14 ) 55 (14 )
Derivative financial instruments - gas (193 ) (40 ) (51 ) 212 (72 )
Contracts for differences (CfDs) (96) (96 )
Derivative financial instruments - other (3 ) (3 )
Total $ (236 ) $ (52 ) $ (164 ) $ 267 $ (185 )
As of December 31, 2014 Level 1 Level 2 Level 3 Netting Total
(Millions)
Securities portfolio (available for sale) $ 33 $ $ $ $ 33
Derivative assets
Derivative financial instruments - power 11 83 48 (53 ) 89
Derivative financial instruments - gas 18 638 61 (579 ) 138
Total 29 721 109 (632 ) $ 227
Derivative liabilities
Derivative financial instruments - power (40 ) (42 ) (7 ) 53 (36 )
Derivative financial instruments - gas (25) (614 ) (42) 579 (102 )
Derivative financial instruments - other (3) (3 )
Total $ (65 ) $ (656 ) $ (52 ) $ 632 $ (141 )
124
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
The reconciliations of changes in the fair value of financial instruments based on Level 3 inputs for the years ended December 31, 2015, 2014 and 2013
consisted of:
(Millions) 2015 2014 2013
Fair value as of January 1, $ 57 $ 53 $ 5
Gains for the year recognized in operating revenues 33 11 21
Losses for the year recognized in operating revenues (8) (1) (3)
Total gains or losses for the period recognized in
operating revenues 25 10 18
Gains recognized in OCI 2
Losses recognized in OCI (3) (3)
Total gains or losses recognized in OCI (1) (3)
Purchases (73) 14 47
Settlements (14) (26) (15 )
Transfers out of Level 3 (a) (13) 9 (2)
Fair value as of December 31, $ (19) $ 57 $ 53
Gains for the year included in operating revenues
attributable to the change in unrealized gains
relating to financial instruments still held
at the reporting date $ 25 $ 10 $ 18
(a) Transfers out of Level 3 were the result of increased observability of market data.
For assets and liabilities that are recognized in the combined and consolidated financial statements at fair value on a recurring basis, we determine whether
transfers have occurred between levels in the hierarchy by re-assessing categorization based on the lowest level of input that is significant to the fair value
measurement as a whole at the end of each reporting period. There have been no transfers between Level 1 and Level 2 during the years reported.
Level 3 Fair Value Measurement
The tables below illustrate the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives. They represent the
variability in prices for those transactions that fall into the illiquid period (beyond 2 years), using past and current views of prices for those future periods.
Variability
Instruments
Instrument
Description
Valuation
Technique
Valuation
Inputs Index Avg. Max. Min.
Fixed price power
and gas swaps
Transactions with
delivery periods
Transactions are
valued against
forward
market prices
Observable and
extrapolated
forward gas and
power prices
not all of which
can be NYMEX ($/MMBtu) $ 4.56 $ 7.37 $ 1.76
with delivery exceeding two on a corroborated by SP15 ($/MWh) $ 46.82 $ 80.28 $ 19.75
period > two years discounted market data for Mid C ($/MWh) $ 37.93 $ 83.93 $ 6.75
years basis identical or Cinergy ($/MWh) $ 37.73 $ 77.49 $19.98
similar products
Our Level 3 valuations primarily consist of NYMEX gas and fixed price power swaps with delivery periods extending through 2017. The gas swaps are used
to hedge both gas inventory in firm storage and merchant wind positions. The power swaps are traded at liquid hubs in the West and Midwest and are used to
hedge merchant wind production in those regions.
125
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
We performed a sensitivity analysis around the Level 3 gas and power positions to changes in the valuations inputs and concluded that no material change to
the financial statements is expected given the following: (i) any changes in the fair value of the gas swaps hedging inventory would be expected to be largely
offset by changes in the value of the inventory; (ii) any changes in the fair value of the gas swaps hedging merchant generation would be expected to be
significantly offset by changes in the value of future power generation.
Future commodity prices are the significant unobservable inputs to fair value. Any significant increases in prices would result in a lower fair value of
derivatives. Conversely, significant reductions in prices would result in a higher fair value of derivatives.
Two elements of the analytical infrastructure employed in valuing transactions are the price curves used in calculation of market value and the models
themselves. Authorized trading points and associated forward price curves are maintained and documented by the Middle Office. Models used in valuation of
the various products are developed and documented by the Structuring and Market Analysis group.
Transaction models are valued in part on the basis of forward price, correlation, and volatility curves. Descriptions of these curves and their derivations are
maintained and documented by the Structuring and Market Analysis group. Forward price curves used in valuing the models are applied to the full duration
of transactional models to a maximum of approximately thirty years.
The determination of fair value of the CfDs (see Note 12 for further details on CfDs) was based on a probability-based expected cash flow analysis that was
discounted at the December 31, 2015 risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates. Certain
management assumptions were required, including development of pricing that extended over the term of the contracts. We believe this methodology
provides the most reasonable estimates of the amount of future discounted cash flows associated with the CfDs. Additionally, on a quarterly basis, we perform
analytics to ensure that the fair value of the derivatives is consistent with changes, if any, in the various fair value model inputs. Significant isolated changes
in the risk of non-performance, the discount rate or the contract term pricing would result in an inverse change in the fair value of the CfDs. Additional
quantitative information about Level 3 fair value measurements of the CfDs is as follows:
Unobservable Input
Range at
December 31,
2015
Risk of non-performance 0.06% - 0.88%
Discount rate 1.31% - 2.27%
Forward pricing ($ per MW) $3.15 - $11.19
Note 12. Derivative Instruments and Hedging
Our Networks, Renewables and Gas activities are exposed to certain risks, which are managed by using derivative instruments.
(a) Networks activities
NYSEG and RGE have a non by-passable wires charge adjustment that allows them to pass through any changes in the market price of electricity. They use
electricity contracts, both physical and financial, to manage fluctuations in electricity commodity prices in order to provide price stability to customers. We
include the cost or benefit of those contracts in the amount expensed for electricity purchased when the related electricity is sold. We record changes in the
fair value of electric hedge contracts to derivative assets and or liabilities with an offset to regulatory assets and or regulatory liabilities, in accordance with
the accounting requirements concerning regulated operations.
The loss recognized in regulatory assets for electricity derivatives was $34.3 million and $28.8 million as of December 31, 2015 and 2014, respectively. The
loss reclassified from regulatory assets into income, which is included in electricity purchased, was $46.9 million, $21.3 million, and $2.2 million for the
years ended December 31, 2015, 2014 and 2013, respectively.
NYSEG and RGE have purchased gas adjustment clauses that allow them to recover through rates any changes in the market price of purchased natural gas,
substantially eliminating their exposure to natural gas price risk. NYSEG and RGE use natural gas futures and forwards to manage fluctuations in natural gas
commodity prices to provide price stability to customers. We include the cost or benefit of natural gas futures and forwards in the commodity cost that is
passed on to customers when the related sales commitments are fulfilled. We record changes in the fair value of natural gas hedge contracts to derivative
assets and or liabilities with an offset to regulatory assets and or regulatory liabilities in accordance with the accounting requirements for regulated
operations.
126
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
The loss recognized in regulatory assets for natural gas hedges was $3.1 million as of December 31, 2015. The loss recognized in regulatory assets for natural
gas hedges was $4.7 million as of December 31, 2014. The loss reclassified from regulatory assets into income, which is included in natural gas purchased,
was $6.3 million, $2.2 million, and $1.8 million for the years ended December 31, 2015, 2014 and 2013, respectively.
Contracts for Differences (CfDs)
Pursuant to Connecticuts 2005 Energy Independence Act, the Connecticut Public Utilities Regulatory Authority (PURA) solicited bids to create new or
incremental capacity resources in order to reduce federally mandated congestion charges, and selected four new capacity resources. To facilitate the
transactions between the selected capacity resources and Connecticut electric customers, and provide the commitment necessary for owners of these resources
to obtain necessary financing, PURA required that UI and The Connecticut Light and Power Company (CL&P) execute long-term contracts with the selected
resources. In August 2007, PURA approved four CfDs, each of which specifies a capacity quantity and a monthly settlement that reflects the difference
between a forward market price and the contract price. UI executed two of the contracts and CL&P executed the other two contracts. The costs or benefits of
each contract will be paid by or allocated to customers and will be subject to a cost-sharing agreement between UI and CL&P pursuant to which
approximately 20% of the cost or benefit is borne by or allocated to UI customers and approximately 80% is borne by or allocated to CL&P customers.
PURA has determined that costs associated with these CfDs will be fully recoverable by UI and CL&P through electric rates, and UI has deferred recognition
of costs (a regulatory asset) or obligations (a regulatory liability). For those CfDs signed by CL&P, UI records its approximate 20% portion pursuant to the
cost-sharing agreement noted above. As of December 31, 2015, UI has recorded a gross derivative asset of $29 million ($1 million of which is related to UIs
portion of the CfD signed by CL&P), a regulatory asset of $68 million, a gross derivative liability of $96 million ($61 million of which is related to UI’s
portion of the CfD signed by CL&P) and a regulatory liability of $1 million.
The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets or regulatory liabilities, for the
period from December 17, 2015 to December 31, 2015 were as follows:
(Millions)
Period from
December 17,
2015 to
December 31, 2015
Regulatory Assets - Derivative liabilities $ (1)
Regulatory Liabilities - Derivative assets $
The net notional volumes of the outstanding derivative instruments associated with Networks activities as of December 31, 2015 and 2014 consisted of:
As of December 31, 2015 2014
(Millions)
Wholesale electricity purchase contracts (MWh) 6.7 6.6
Natural gas purchase contracts (Dth) 4.8 3.8
Fleet fuel purchase contracts (Gallons) 3.8 2.8
127
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
The location and amounts of derivatives designated as hedging instruments associated with Networks activities as of December 31, 2015 and 2014 consisted
of:
Asset Derivatives Liability Derivatives
(Millions)
Balance Sheet
Location
Fair
Value
Balance Sheet
Location
Fair
Value
As of December 31, 2015
Commodity contracts:
Electricity derivatives:
Current Current assets $ Current liabilities $
Non-current Other assets Other liabilities
Natural gas derivatives:
Current Current assets Current liabilities
Non-current Other assets Other liabilities
Fleet fuel contracts
Current Current assets Current liabilities (2 )
Non-current Other assets Other liabilities (1)
Total $ $ (3 )
As of December 31, 2014
Commodity contracts:
Electricity derivatives:
Current Current assets $ Current liabilities $ (20 )
Non-current Other assets Other liabilities (9)
Natural gas derivatives:
Current Current assets Current liabilities (4 )
Non-current Other assets Other liabilities (1)
Fleet fuel contracts Current assets Current liabilities (3 )
Total $ $ (37 )
The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2015, 2014 and 2013 consisted of:
Year Ended December 31,
(Loss) Recognized
in OCI on Derivatives
Location of
(Loss) Reclassified
from Accumulated
OCI into Income
(Loss)
Reclassified
from Accumulated
OCI into Income
(Millions) Effective Portion (a) Effective Portion (a)
2015
Interest rate contracts $ Interest expense $ (9 )
Commodity contracts (3) Operating expenses (3)
Total $ (3 ) $ (12)
2014
Interest rate contracts $ Interest expense $ (9 )
Commodity contracts (4) Operating expenses (1)
Total $ (4 ) $ (10)
2013
Interest rate contracts $ Interest expense $ (11 )
Commodity contracts Operating expenses (1)
Total $ $ (12)
(a) Changes in OCI are reported in pre-tax dollars, the reclassified amounts of commodity contracts are included within “Purchase power, natural gas and
fuel used” line item within operating expenses in the combined and consolidated statements of operations.
128
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $84.9 million, $93.5 million, and
$102.5 million for the years ended December 31, 2015, 2014 and 2013, respectively. We recorded $8.6 million, $8.9 million, and $11.2 million in net
derivative losses related to discontinued cash flow hedges for the years ended December 31, 2015, 2014 and 2013, respectively. We will amortize
approximately $8.1 million of discontinued cash flow hedges in 2016.
The unrealized loss of $2.7 million on hedge derivatives is reported in OCI because the forecasted transaction is considered to be probable as of December
31, 2015. We expect that those losses will be reclassified into earnings within the next twenty four months, the maximum length of time over which we are
hedging our exposure to the variability in future cash flows for forecasted energy transactions.
The offsetting of derivative assets as of December 31, 2015 and 2014 consisted of:
Gross Gross
Net Amounts
of Assets
Gross Amounts Not Offset in
the Balance Sheet
As of December 31,
Amounts of
Recognized
Assets
Amounts
Offset in the
Balance Sheet
Presented in
the Balance
Sheet
Financial
Instruments
Cash
Collateral
Pledged Net Amount
(Millions)
2015
Derivatives $ 10 $ (10 ) $ $ $ $
2014
Derivatives 11 (11)
The offsetting of derivative liabilities as of December 31, 2015 and 2014 consisted of:
Gross Gross
Net Amounts
of Liabilities
Gross Amounts Not Offset in
the Balance Sheet
As of December 31,
Amounts of
Recognized
Liabilities
Amounts
Offset in the
Balance Sheet
Presented in
the Balance
Sheet
Financial
Instruments
Cash
Collateral
Pledged Net Amount
(Millions)
2015
Derivatives $ (49) $ 46 $ (3) $ $ $ (3)
2014
Derivatives (48) 11 (37 ) 37
(b) Renewables and Gas activities
We sell fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. We also
purchase fixed-price gas and basis swaps and sell fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal
assets. We also enter into tolling arrangements to sell the output of our thermal generation facilities.
Our gas business purchases and sells both fixed-price gas and basis swaps to hedge the value of contracted storage positions. The intent of entering into these
swaps is to fix the margin of gas injected into storage for subsequent resale in future periods. We also enter into basis swaps to hedge the value of our
contracted transport positions. The intent of buying and selling these basis swaps is to fix the location differential between the price of gas at the receipt and
delivery point of the contracted transport in future periods.
Both Renewables and Gas have proprietary trading operations that enter into fixed-price power and gas forwards in addition to basis swaps. The intent is to
speculate on fixed-price commodity and basis volatility in the U.S. commodity markets.
129
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
The net notional volumes of outstanding derivative instruments associated with Renewables and Gas activities as of December 31, 2015 and 2014 consisted
of:
As of December 31, 2015 2014
(MWh/Dth in Millions)
Wholesale electricity purchase contracts 3 2
Wholesale electricity sales contracts 6 7
Foreign exchange forward purchase contracts 4
Natural gas and other fuel purchase contracts 332 275
Financial power contracts 7 8
Basis swaps - purchases 67 160
Basis swaps - sales 80 161
The fair values of derivative contracts associated with Renewables and Gas activities as of December 31, 2015 and 2014 consisted of:
As of December 31, 2015 2014
(Millions)
Wholesale electricity purchase contracts $ (13) $ (12)
Wholesale electricity sales contracts 35 44
Foreign exchange forward purchase contracts (1) (3 )
Natural gas and other fuel purchase contracts 10 54
Financial power contracts 32 48
Basis swaps- purchases 1 (4)
Basis swaps- sales (2) (4)
Total $ 62 $ 123
The offsetting of derivative assets as of December 31, 2015 and 2014 consisted of:
Gross Gross
Net Amounts
of Assets
Gross Amounts Offset in
the Balance Sheet
As of December 31,
Amounts of
Recognized
Assets
Amounts
Offset in the
Balance Sheet
Presented in
the Balance
Sheet
Financial
Instruments
Cash
Collateral
Pledged Net Amount
(Millions)
2015
Derivatives $ 489 $ (341 ) $ 148 $ (36 ) $ (15 ) $ 97
2014
Derivatives 847 (620 ) 227 (66) (73) 88
The offsetting of derivative liabilities as of December 31, 2015 and 2014 consisted of:
Gross Gross
Net Amounts
of Liabilities
Gross Amounts Not Offset in
the Balance Sheet
As of December 31,
Amounts of
Recognized
Liabilities
Amounts
Offset in the
Balance Sheet
Presented in
the Balance
Sheet
Financial
Instruments
Cash
Collateral
Pledged Net Amount
(Millions)
2015
Derivatives $ (307 ) $ 221 $ (86) $ 36 $ 4 $ (46)
2014
Derivatives (724) 620 (104 ) 66 1 (37)
130
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
The effect of trading derivatives associated with Renewables and Gas activities for the years ended December 31, 2015, 2014 and 2013 consisted of:
Years Ended December 31, 2015 2014 2013
(Millions)
Wholesale electricity purchase contracts $ 6 $ (9 ) $ 2
Wholesale electricity sales contracts (5 ) 9 (1 )
Financial power contracts (2 ) (4)
Financial and natural gas contracts (26) 125 (21 )
Total Gain (Loss) $ (25) $ 123 $ (24)
Such gains and losses are included in revenue in the combined and consolidated statements of operations.
The effect of non-trading derivatives associated with Renewables and Gas activities for the years ended December 31, 2015, 2014 and 2013 consisted of:
Years Ended December 31, 2015 2014 2013
(Millions)
Wholesale electricity purchase contracts $ (8 ) $ (8 ) $ 9
Wholesale electricity sales contracts (5 ) 15 (2)
Financial power contracts 24 30 (19 )
Natural gas and other fuel purchase contracts 18 (1 ) 16
Total Gain (Loss) $ 29 $ 36 $ 4
Such gains and losses are included in revenue and “Purchased power, natural gas and fuel used” operating expenses in the combined and consolidated
statements of operations, depending upon the nature of the transaction.
In 2015 we began designating those derivatives contracts at Renewables and Gas businesses that qualify as hedges. This designation was made prospectively,
and in accordance with all the requirements of hedge accounting. The location and amounts of derivatives designated as hedging instruments associated with
Renewables and Gas activities as of December 31, 2015 consisted of:
Asset Derivatives Liability Derivatives
(Millions)
Balance Sheet
Location
Fair
Value
Balance Sheet
Location
Fair
Value
As of December 31, 2015
Commodity contracts:
Electricity derivatives:
Current Current assets $ 2 Current liabilities $
Non-current Other assets 1 Other liabilities
Natural gas derivatives:
Current Current assets 50 Current liabilities (9)
Non-current Other assets 9 Other liabilities
Total $ 62 $ (9 )
Year Ended December 31,
Gain Recognized
in OCI on Derivatives
Location of
Gain Reclassified
from Accumulated
OCI into Income
Gain
Reclassified
from Accumulated
OCI into Income
(Millions) Effective Portion (a) Effective Portion (a)
2015
Commodity contracts $ 57 Revenues $ (2)
Total $ 57 $ (2 )
(a) Changes in OCI are reported on a pre-tax basis.
131
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Amounts will be reclassified from accumulated OCI into income in the period(s) during which the transaction being hedged affects earnings or when it
becomes probable that a forecasted transaction being hedged would not occur. Notwithstanding future changes in prices, approximately $43.5 million of
gains included in accumulated OCI at December 31, 2015 is expected to be reclassified into earnings within the next 12 months. During the year ended
December 31, 2015 we recorded a net gain of $4.8 million in earnings as a result of ineffectiveness from cash flow hedges. We recorded $2.3 million in net
derivative gain related to discontinued cash flow hedge for the year ended December 31, 2015.
(c) Counterparty credit risk management
NYSEG and RGE face risks related to counterparty performance on hedging contracts due to counterparty credit default. We have developed a matrix of
unsecured credit thresholds that are dependent on the counterpartys or the counterpartys guarantor’s applicable credit rating, normally Moody’s or Standard
& Poor’s. When our exposure to risk for a counterparty exceeds the unsecured credit threshold, the counterparty is required to post additional collateral or we
will no longer transact with the counterparty until the exposure drops below the unsecured credit threshold.
The wholesale power supply agreements of UI contain default provisions that include required performance assurance, including certain collateral
obligations, in the event that UIs credit rating on senior debt were to fall below investment grade. If such an event had occurred as of December 31, 2015, UI
would have had to post an aggregate of approximately $18 million in collateral.
We have various master netting arrangements in the form of multiple contracts with various single counterparties that are subject to contractual agreements
that provide for the net settlement of all contracts through a single payment. Those arrangements reduce our exposure to a counterparty in the event of default
on or termination of any single contract. For financial statement presentation purposes, we offset fair value amounts recognized for derivative instruments and
fair value amounts recognized for the right to reclaim or the obligation to return cash collateral arising from derivative instruments executed with the same
counterparty under a master netting arrangement. The amount of cash collateral used to offset against net derivative positions was $84 million as of
December 31, 2015. Under the master netting arrangements our obligation to return cash collateral was $0.1 million and $0.2 million as of December 31,
2015 and 2014, respectively. Derivate instruments settlements and collateral payments are included in “Other assets” and Other liabilities” of operating
activities in the combined and consolidated statements of cash flows.
Certain of our derivative instruments contain provisions that require us to maintain an investment grade credit rating on our debt from each of the major
credit rating agencies. If our debt were to fall below investment grade, we would be in violation of those provisions and the counterparties to the derivative
instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net
liability positions. The aggregate fair value of all derivative instruments with credit risk related contingent features that are in a liability position as of
December 31, 2015 is $39.7 million, for which we have posted collateral.
Note 13. Commitments and Contingent Liabilities
We are party to various legal disputes arising as part of our normal business activities. We do not provide for accrual of legal costs expected to be incurred in
connection with a loss contingency.
MNG rate case
On March 5, 2015, MNG filed a rate case in order to further recover future investments and provide safe and adequate service. MNG requested a 10.0% ROE
and 50% equity ratio. The MPUC Staff has recommended a separate revenue requirement for MNGs Augusta customers and MNG’s non-Augusta customers.
Staff also recommended a $19.95 million disallowance of the August Expansion investment based upon the Staffs conclusion that MNGs management of
the Augusta Expansion Project was imprudent.
On November 6, 2015, a stipulation was filed with the MPUC, which was executed by MNG, the Office of Public Advocate and the City of Augusta. The
stipulation contained a combined revenue requirement for Augusta and Non-Augusta based on a 9.55% ROE and 50% equity ratio. The stipulation also
provided for an initial Augusta investment disallowance of $6 million and an investment phase-in of $10 million. On December 22, 2015, MPUC rejected the
proposed Stipulation as not in the public interest. In January 2016, the Administrative Law Judge established a new litigation schedule. The litigation was
suspended at the end of January 2016 for settlement discussions. We cannot predict the outcome of the proceeding. We reserved $6 million for this case at the
end of 2015.
132
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Transmission - ROE Complaint CMP and UI
On September 30, 2011, the Massachusetts Attorney General, Massachusetts Department of Public Utilities, Connecticut Public Utilities Regulatory
Authority, New Hampshire Public Utilities Commission, Rhode Island Division of Public Utilities and Carriers, Vermont Department of Public Service,
numerous New England consumer advocate agencies and transmission tariff customers collectively filed a complaint (Complaint I) with the FERC pursuant
to sections 206 and 306 of the Federal Power Act. The filing parties seek an order from the FERC reducing the 11.14% base return on equity used in
calculating formula rates for transmission service under the ISO-New England Open Access Transmission Tariff (OATT) to a just and reasonable level of
9.2%. CMP and UI are New England Transmission Owners (NETOs) with assets and service rates that are governed by the OATT and will thereby be affected
by any FERC order resulting from the filed complaint.
On June 19, 2014, the FERC issued its initial decision in the first complaint, establishing a methodology and setting the issues for a paper hearing. On
October 16, 2014, FERC issued its final decision in the first complaint (Complaint I) setting the base ROE at 10.57%, and a maximum total ROE of 11.74%
for the October 2011 – December 2012 period and ordered the NETOs to file a refund report. On November 17, 2014 the NETOs filed a refund report.
On March 3, 2015, the FERC issued an order on requests for rehearing of its October 16, 2014 decision. The March order upheld the FERCs initial decision
and further clarified that the 11.74% ROE cap will be applied on a project specific basis and not on a transmission owners total average return. In June 2015
the NETOs filed an appeal in the U.S. Court of Appeals for the District of Columbia of the FERC’s final order. We cannot predict the outcome of this appeal.
On December 26, 2012, a second, related, complaint (Complaint II) for a subsequent rate period was filed requesting the ROE be reduced to 8.7%. On June 19,
2014, FERC accepted the second complaint, established a refund effective date of December 27, 2012, and set the matter for hearing using the methodology
established in the first complaint.
On July 31, 2014, the Complainants filed a third, related, complaint (Complaint III) for a subsequent rate period requesting the ROE be reduced to 8.84%. On
November 24, 2014, FERC accepted the third complaint, established a refund effective date of July 31, 2014, and set for consolidated hearing with
Complaint II in June 2015. Hearings were held in June 2015 on Complaints II and III before a FERC Administrative Law Judge, relating to the refund periods
and going forward. On July 29, 2015, post-hearing briefs were filed by parties and on August 26, 2015 reply briefs were filed by parties. On July 13, 2015, the
New England transmission owners filed a petition for review of FERC’s orders establishing hearing and consolidation procedures for Complaints II and III
with the U.S. Court of Appeals. The Administrative Law Judge issued an Initial Decision on March 22, 2016. The Initial Decision determined that, 1) for the
15 month refund period in Complaint II, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and 2) for
the 15 month refund period in Complaint III and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19%. The Initial
Decision is the Administrative Law Judges recommendation to the FERC Commissioners. The FERC is expected to make its final decision in late 2016 or
early 2017.
CMP and UI reserved for refunds for Complaints I, II and III consistent with the FERC’s March 3, 2015 final Complaint I decision. The CMP and UI total
reserve associated with Complaints I, II and III is $23.9 million and $4.2 million, respectively, as of December 31, 2015. If adopted as final, the impact of the
initial decision would be an additional reserve for Complaints II and III of $10.2 million, net of tax, which is based upon currently available information for
these proceedings. We cannot predict the outcome of Complaint II and III proceedings.
Yankee Nuclear Spent Fuel Disposal Claim
CMP has an ownership interest in Maine Yankee, Connecticut Yankee, and Yankee Atomic, (the Yankee Companies), three New England single-unit
decommissioned nuclear reactor sites, and UI has and ownership in Connecticut Yankee. Every six years, pursuant to the statute of limitations, the Yankee
companies need to file a lawsuit to recover damages from the Department of Energy (DOE or Government) for breach of the Nuclear Spent Fuel Disposal
Contract to remove Spent Nuclear Fuel (SNF) and Greater than Class C Waste (GTCC) as required by contract and the Nuclear Waste Policy Act beginning in
1998. The damages are the incremental costs for the government’s failure to take the spent nuclear fuel.
In 2012, the U.S. Court of Appeals issued a favorable decision in the Yankee Companies’ claim for the first six year period (Phase I). Total damages awarded
to the Yankee companies were nearly $160 million. The Yankee Companies won on all appellate points in the U.S. Court of Appeals for the Federal Circuit’s
unanimous decision. The Federal Appeals Court affirmed the September 2010 U.S. Court of Federal Claims award of $40.3 million to Connecticut Yankee
Atomic Power Company; affirmed the Court of Federal Claims award of $65 million to Maine Yankee Atomic Power Company; and increased Yankee
Atomic Electric Companys damages
133
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
award from $21.4 million to $37.8 million. The Phase I damage award became final on December 4, 2012. The Yankee Companies received payment from
DOE in January 2013. CMP’s share of the award was approximately $36.5 million which was credited back to customers. UIs share of the award was $3.8
million which was credited back to customers.
In November 2013 the U.S. Court of Claims issued its decision in the Phase II case (the second 6 year period). The Trial Court decision awards the Yankee
companies a combined $235.4 million (Connecticut Yankee $126.3 million, Maine Yankee $37.7 million, and Yankee Atomic $73.3 million). The Phase II
period covers January 1, 2002 through December 31, 2008 for Connecticut Yankee and Yankee Atomic, and January 1, 2003 through December 31, 2008 for
Maine Yankee. Maine Yankees damage award was lower because it recovered a larger amount in the Phase I case ($82 million) and its decommissioning was
both less expensive and completed sooner than the other Yankee companies. The damage awards flow through the Yankees to shareholders to reduce retail
customer charges. In January 2014 the government informed the Yankee Companies it would not appeal the Trial Court decision, as a result the Yankee
Companies received full payment in April 2014. CMP’s share of the award was approximately $28.2 million which was credited back to customers. UI
received approximately $12 million of such award which was applied, in part, against the remaining storm regulatory asset balance. The remaining regulatory
liability balance was applied to the GSC “working capital allowance” and will be returned to customers through the non-by-passable federally mandated
congestion charge.
In August 2013, the Yankees filed a third round of claims against the government seeking damages for the years 2009-2014 (Phase III). The Phase III trial was
completed in July 2015 and the Court has issued its decision on March 25, 2016 awarding the Yankee companies a combined $76.8 million (Connecticut
Yankee $32.6 million, Maine Yankee $24.6 million and Yankee Atomic $19.6 million). The damage awards will potentially flow through the Yankee
Companies to shareholders, including CMP and UI, upon FERC approval, and will reduce retail customer charges or otherwise as specified by law. CMP and
UI will receive their proportionate share of the awards based on percentage ownership. We cannot predict the timing or amount of damage awards that may
ultimately flow through to shareholders.
NYPSC Staff Review of Earnings Sharing Calculations and Other Regulatory Deferrals
In December 2012, the NYPSC Staff (Staff) informed NYSEG and RGE that the Staff had conducted an audit of the companies’ annual compliance filings
(ACF) for 2009 through August 31, 2010, and the first rate year of the current rate plan, September 1, 2010 through August 31, 2011. The Staffs preliminary
findings indicated adjustments to deferred balances primarily associated with storm costs and the treatment of certain incentive compensation costs for
purposes of the 2011 ACF. The Staffs findings approximate $9.8 million of adjustments to deferral balances and customer earnings sharing accruals. NYSEG
and RGE reviewed the Staffs adjustments and work papers and provided a response in 2013. Staff has not yet replied to NYSEG’s and RGE’s response.
NYSEG and RGE disagreed with certain staff conclusions and as a result have recorded a $3.4 million reserve in December 2012 in anticipation of settling
the Staff issues. In the proposal filed with the NYPSC (see Note 5) the parties agreed that $2.4 million would be added to customer share of Earnings Sharing.
Middletown/Norwalk Transmission Project
The general contractor and two subcontractors responsible for civil construction work in connection with the installation of UI’s portion of the
Middletown/Norwalk Transmission Project’s underground electric cable system filed lawsuits in Connecticut state court on September 22, 2009, March 23,
2009 and January 25, 2010, respectively. The claims, as revised by the general contractor in October 2011, sought payment for change order requests of
approximately $33.3 million, a 10% general contractor mark-up on any approved subcontractor change order claims (approximately $2.3 million), interest,
costs, and attorneys' fees. In December 2011, UI settled the claims brought by the two subcontractors and their respective lawsuits were dismissed, reducing
UIs estimate of the general contractors claims to approximately $7.7 million, exclusive of the contractor’s claims for interest, costs, and attorneys’ fees. UI
also pursued an indemnification claim against the general contractor for the payments made in settlement to the two subcontractors.
On September 3, 2013, the court found for UI on all claims but one related to certain change orders, and ordered UI to pay the Contractor approximately $1.3
million, which has since been paid. The court also found against UI on the indemnification claims. On October 22, 2013, the general contractor filed an
appeal of the Courts ruling. UI expects to recover any amounts paid to resolve the contractor and subcontractor claims through UIs transmission revenue
requirements.
In April 2013, an affiliate of the general contractor for the Middletown/Norwalk Transmission Project, purporting to act as a shareholder on behalf of UIL
Holdings, filed a complaint against the UIL Holdings Board of Directors alleging that the directors breached a fiduciary duty by failing to undertake an
independent investigation in response to a letter from the affiliate asking for an investigation regarding alleged improper practices by UI in connection with
the Middletown/Norwalk Transmission Project. In October 2013, the court granted the defendants’ motion to dismiss the complaint, which dismissal was
affirmed by the Connecticut
134
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Appellate Court in March 2015. The period to file a petition for review by the Connecticut Supreme Court has passed and the case is now concluded.
Leases
Operating lease expense relating to operational facilities, office building leases, and vehicle and equipment leases was $47.7 million, $48.7 million and
$67.6 million for the years ended December 31, 2015, 2014 and 2013, respectively. Amounts related to contingent payments predominantly linked to
electricity generation at the respective facilities was $22.2 million, $20.4 million and $20.6 million for the years ended December 31, 2015, 2014 and 2013,
respectively. Leases for most of the land on which wind farm facilities are located have various renewal and termination clauses.
In April 2013, we concluded a sale and subsequent lease-back transaction on one of our operating facilities for an initial cash receipt of $110 million. Under
the terms of the agreement, we will simultaneously sell and then lease back the facility over a fifteen-year period, with an option to repurchase the facility at
the end of year ten. During the lease period, we will continue to maintain and operate the entire facility. We accounted for this as a capital sale lease-back
transaction, under which a lease payable liability is recognized which is offset by the increase in cash.
On January 16, 2014, as required by its regulator, NYSEG renewed a Reliability Support Services Agreement (RSS Agreement) with Cayuga Operating
Company, LLC (Cayuga) for Cayuga to provide reliability support services to maintain necessary system reliability through June 2017. Cayuga owns and
operates the Cayuga Generating Facility (Facility), a coal-fired generating station that includes two generating units. Cayuga will operate and maintain the
RSS units and manage and comply with scheduling deadlines and requirements for maintaining the Facility and the RSS units as eligible energy and
capacity providers and will comply with dispatch instructions. NYSEG will pay Cayuga a monthly fixed price and will also pay for capital expenditures for
specified capital projects. NYSEG will be entitled to a share of any capacity and energy revenues earned by Cayuga. We account for this arrangement as an
operating lease. The net expense incurred under this operating lease was $25.5 million and $19.8 million for the years ended December 31, 2015 and 2014,
respectively.
On December 31, 2014, we concluded the sale of our ten-percent undivided interest in Unit 1 of the Springerville power plant to Tucson Electric Power for
$19.6 million. We had previously accounted for this plant as an operating lease. This transaction was recorded in “Other income and (expense).
On October 21, 2015, RGE, GNPP and multiple intervenors filed a Joint Proposal with the regulator for approval of the modified RSS Agreement for the
continued operation of the Ginna Facility through March 2017. RGE shall make monthly payments to GNPP in the amount of $15.4 million. RGE will be
entitled to 70% of revenues from GNPPs sales into the energy and capacity markets, while GNPP will be entitled to 30% of such revenues. We account for
this arrangement as an operating lease.
Total future minimum lease payments as of December 31, 2015 consisted of:
(Millions)
Year Operating Leases(a) Capital Leases(a) Total
2016 $ 216 $ 9 $ 225
2017 90 6 96
2018 26 6 32
2019 24 6 30
2020 25 7 32
2021 and thereafter 298 53 351
Total $ 679 $ 87 $ 766
(a) Payments related to the period of remaining useful life of facilities are on an undiscounted basis.
Power, Gas, and Other Arrangements
Power and Gas Supply Arrangements Networks
NYSEG and RGE are the providers of last resort for customers. As a result, the companies buy physical energy and capacity from the NYISO. In accordance
with the NYPSC's February 26, 2008 Order, NYSEG and RGE are required to hedge on behalf of non-demand billed customers. The physical electric capacity
purchases we make from parties other than the NYISO are to comply with the hedge
135
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
requirement for electric capacity. The companies enter into financial swaps to comply with the hedge requirement for physical electric energy
purchases. Other purchases, from some Independent Power Producers (IPPs) and NYPA are from contracts entered into many years ago when the companies
made purchases under contract as part of their supply portfolio to meet their load requirement. More recent IPP purchases are required to comply with the
companies’ Public Utility Regulatory Policies Act (PURPA) purchase obligation.
NYSEG, RGE, SCG, CNG and Berkshire Gas Company (collectively the Regulated Gas Companies) satisfy their natural gas supply requirements through
purchases from various producers and suppliers, withdrawals from natural gas storage, capacity contracts and winter peaking supplies and resources. The
Regulated Gas Companies operate diverse portfolios of gas supply, firm transportation capacity, gas storage and peaking resources. Actual reasonable gas
costs incurred by each of the Regulated Gas Companies are passed through to customers through state regulated purchased gas adjustment mechanisms,
subject to regulatory review.
The Regulated Gas Companies purchase the majority of their natural gas supply at market prices under seasonal, monthly or mid-term supply contracts and
the remainder is acquired on the spot market. The Regulated Gas Companies diversify their sources of supply by amount purchased and location and
primarily acquire gas at various locations in the US Gulf of Mexico region, in the Appalachia region and in Canada.
The Regulated Gas Companies acquire firm transportation capacity on interstate pipelines under long-term contracts and utilize that capacity to transport
both natural gas supply purchased and natural gas withdrawn from storage to the local distribution system.
The Regulated Gas Companies acquire firm underground natural gas storage capacity using long-term contracts and fill the storage facilities with gas in the
summer months for subsequent withdrawal in the winter months.
Winter peaking resources are primarily attached to the local distribution systems and are either owned or are contracted for by the Regulated Gas Companies,
each of which is a Local Distribution Company. Each Regulated Gas Company owns or has rights to the natural gas stored in an LNG facility directly
attached to its distribution system.
Power, Gas, and Other Arrangements Renewables and Gas
Gas purchase commitments include multi-year contracted storage and transport capacity contracts that allow the Gas business to participate in seasonal and
locational gas price differentials. The agreements contain fixed payment obligations for the lease of both storage and transport capacity throughout the
U.S. Power purchase commitments include the following: (i) a 55MW Biomass Power Purchase Agreement (PPA) for 12 years (six years remaining) with a
guaranteed output of 34.4MW flat and a schedule of fixed price rates depending on season and time of day, (ii) long-term firm transmission agreements with
fixed monthly capacity payments that allow the delivery of electricity from wind and thermal generation sources to various customers and (iii) a three year
purchase of hydro capacity and energy to provide balancing services to the NW wind assets that has monthly fixed payments. Power sales commitments
include: (i) a 55MW Biomass off-take agreement for 12 years (six years remaining) with guaranteed annual production of 34.4MW flat with a schedule of
fixed price rates depending on season and time of day, (ii) fixed price, fixed volume power sales off the Klamath Cogen facility in addition to tolling
arrangements that have fixed capacity charges and (iii) fixed price, fixed volume renewable energy credit sales off merchant wind facilities.
Forward purchases and sales commitments under power, gas, and other arrangements as of December 31, 2015 consisted of:
(Millions) Purchases Sales
As of December 31, Gas Power Other Total Gas Power Other Total
2016 $ 232 $ 233 $ 31 $ 496 $ 21 $ 133 $ 3 $ 157
2017 203 123 25 351 3 84 2 89
2018 181 76 14 271 67 2 69
2019 149 54 8 211 48 1 49
2020 124 53 7 184 39 39
Thereafter 579 320 58 957 46 46
Totals $ 1,468 $ 859 $ 143 $ 2,470 $ 24 $ 417 $ 8 $ 449
136
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Guarantee Commitments to Third Parties
As of December 31, 2015, we had approximately $2.4 billion of standby letters of credit, surety bonds, guarantees and indemnifications outstanding. These
instruments provide financial assurance to the business and trading partners of the company and its subsidiaries in their normal course of business. The
instruments only represent liabilities if the company or its subsidiaries fail to deliver on contractual obligations. We therefore believe it is unlikely that any
material liabilities associated with these instruments will be incurred and, accordingly, as of December 31, 2015, neither we nor our subsidiaries have any
liabilities recorded for these instruments.
Property, Plant and Equipment
We have made future commitments to purchase property, plant, and equipment in order to continue to develop and grow our business. The amount of such
future commitments was $616 million as of December 31, 2015.
Note 14. Environmental Liability
Environmental laws, regulations and compliance programs may occasionally require changes in our operations and facilities and may increase the cost of
electric and natural gas service. We do not provide for accruals of legal costs expected to be incurred in connection with loss contingencies.
Waste sites
The Environmental Protection Agency and various state environmental agencies, as appropriate, have notified us that we are among the potentially
responsible parties that may be liable for costs incurred to remediate certain hazardous substances at twenty-four waste sites, which do not include sites where
gas was manufactured in the past. Fifteen of the twenty-four sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; six
sites are included in Maine’s Uncontrolled Sites Program and one site is included on the Massachusetts Non- Priority Confirmed Disposal Site list. The
remaining sites are not included in any registry list. Finally, nine of the twenty-four sites are also included on the National Priorities list. Any liability may be
joint and severable for certain sites.
We have recorded an estimated liability of $6 million related to ten of the twenty-four sites. We have paid remediation costs related to the remaining fourteen
sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $8 million related to another ten sites where we
believe it is probable that we will incur remediation costs and or monitoring costs, although we have not been notified that we are among the potentially
responsible parties or that we are regulated under State Resource Conservation and Recovery Act programs. It is possible the ultimate cost to remediate these
sites may be significantly more than the accrued amount. Factors affecting the estimated remediation amount include the remedial action plan selected, the
extent of site contamination, and the portion of remediation attributed to us.
Manufactured Gas Plants
We have a program to investigate and perform necessary remediation at our fifty-three sites where gas was manufactured in the past (Manufactured Gas Plants,
or MGPs). Eight sites are included in the New York State Registry; eleven sites are included in the New York Voluntary Cleanup Program; three sites are part
of Maines Voluntary Response Action Program and of those two sites are a part of Maines Uncontrolled Sites Program. The remaining sites are not included
in any registry list. We have entered into consent orders with various environmental agencies to investigate and where necessary remediate forty-seven of the
fifty-three sites.
Our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from a minimum of $235 million to $468 million as of
December 31, 2015. Our estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial
actions, changes in technology relating to remedial alternatives, and changes to current laws and regulations. As of December 31, 2015 the liability
associated with other MGP sites, the remediation costs of which could be significant and will be subject to a review by PURA as to whether these costs are
recoverable in rates, was $99 million.
The liability to investigate and perform remediation at the known inactive gas manufacturing sites was $397 million and $312 million as of December 31,
2015 and 2014, respectively. We recorded a corresponding regulatory asset, net of insurance recoveries and the amount collected from FirstEnergy, as
described below, because we expect to recover the net costs in rates. Our environmental liability accruals are recorded on an undiscounted basis and are
expected to be paid through the year 2048.
137
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
The Regulated Gas Companies own or have previously owned properties where MGPs had historically operated. MGP operations have led to contamination
of soil and groundwater with petroleum hydrocarbons, benzene and metals, among other things, at these properties, the regulation and cleanup of which is
regulated by the federal Resource Conservation and Recovery Act as well as other federal and state statutes and regulations. Each of the Regulated Gas
Companies has or had an ownership interest in one or more such properties contaminated as a result of MGP-related activities. Under the existing regulations,
the cleanup of such sites requires state and at times, federal, regulators’ involvement and approval before cleanup can commence. In certain cases, such
contamination has been evaluated, characterized and remediated. In other cases, the sites have been evaluated and characterized, but not yet remediated.
Finally, at some of these sites, the scope of the contamination has not yet been fully characterized; no liability was recorded in respect of these sites as of
December 31, 2015 and no amount of loss, if any, can be reasonably estimated at this time. In the past, the Regulated Gas Companies have received approval
for the recovery of MGP-related remediation expenses from customers through rates and will seek recovery in rates for ongoing MGP-related remediation
expenses for all of their MGP sites.
FirstEnergy
NYSEG sued FirstEnergy under the Comprehensive Environmental Response, Compensation, and Liability Act to recover environmental cleanup costs at
sixteen former manufactured gas sites, which are included in the discussion above. In July 2011, the District Court issued a decision and order in NYSEG’s
favor. Based on past and future clean-up costs at the sixteen sites in dispute, FirstEnergy would be required to pay NYSEG approximately $60 million if the
decision were upheld on appeal. On September 9, 2011, FirstEnergy paid NYSEG $30 million, representing their share of past costs of $27 million and pre-
judgment interest of $3 million.
FirstEnergy appealed the decision to the Second Circuit Court of Appeals. On September 11, 2014, the Second Circuit Court of Appeals affirmed the District
Court’s decision in NYSEG’s favor, but modified the decision for nine sites, reducing NYSEG’s damages for incurred costs from $27 million to $22 million,
excluding interest, and reducing FirstEnergy’s allocable share of future costs at these sites. NYSEG refunded FirstEnergy the excess $5 million in November
2014.
FirstEnergy remains liable for a substantial share of clean up expenses at nine MPG Energy sites. In January 2015, NYSEG sent FirstEnergy a demand for $16
million representing FirstEnergys share of clean-up expenses incurred by NYSEG at the nine sites from January 2010 to November 2014 while the District
Court appeal was pending. This amount has been paid by FirstEnergy. FirstEnergy would also be liable for a share of post 2014 costs, which, based on current
projections, would be $26 million. This amount is being treated as a contingent asset and has not been recorded as either a receivable or a decrease to the
environmental provision.
Century Indemnity and OneBeacon
On August 14, 2013, NYSEG filed suit in federal court against two excess insurers, Century Indemnity and OneBeacon, who provided excess liability
coverage to NYSEG. NYSEG seeks payment for clean-up costs associated with contamination at twenty-two former manufactured gas plants. Based on
estimated clean-up costs of $282 million, the carriers’ allocable share is approximately $89 million, excluding pre-judgment interest. Any recovery will be
flowed through to NYSEG ratepayers.
Century and One Beacon have answered admitting issuance of the excess policies, but contesting coverage and providing documentation proving they
received notice of the claims in the 1990s. We cannot predict the outcome of this matter.
English Station
In January 2012, Evergreen Power, LLC (Evergreen Power) and Asnat Realty LLC (Asnat), then and current owners of a former generation site on the Mill
River in New Haven (the English Station site) that UI sold to Quinnipiac Energy in 2000, filed a lawsuit in federal district court in Connecticut against UI
seeking, among other things: (i) an order directing UI to reimburse the plaintiffs for costs they have incurred and will incur for the testing, investigation and
remediation of hazardous substances at the English Station site and (ii) an order directing UI to investigate and remediate the site. In December 2013,
Evergreen and Asnat filed a subsequent lawsuit in Connecticut state court seeking among other things: (i) remediation of the property; (ii) reimbursement of
remediation costs; (iii) termination of UI’s easement rights; (iv) reimbursement for costs associated with securing the property; and (v) punitive damages.
138
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
On April 8, 2013, DEEP issued an administrative order addressed to UI, Evergreen Power, Asnat and others, ordering the parties to take certain actions related
to investigating and remediating the English Station site. Mediation of the matter began in the fourth quarter of 2013 and concluded unsuccessfully in April
of 2015.
On September 16, 2015, UI signed a Proposed Partial Consent Order that, when issued by the Commissioner of DEEP, and subject to the closing of the merger
between UIL and AVANGRID and other terms and conditions in the Proposed Partial Consent Order, would require UI to investigate and remediate certain
environmental conditions within the perimeter of the English Station site. Under the Proposed Partial Consent Order, to the extent that the cost of this
investigation and remediation is less than $30 million, UI will remit to the State of Connecticut the difference between such cost and $30 million to be used
for a public purpose as determined in the discretion of the Governor of the State of Connecticut, the Attorney General of the State of Connecticut, and the
Commissioner of DEEP. Pursuant to the Proposed Partial Consent Order, upon its issuance and subject to its terms and conditions, UI would be obligated to
comply with the Proposed Partial Consent Order, even if the cost of such compliance exceeds $30 million. The State will discuss options with UI on
recovering or funding any cost above $30 million such as through public funding or recovery from third parties, however it is not bound to agree to or
support any means of recovery or funding. On September 30, 2015, the Hearing Officer in DEEP’s administrative proceeding approved a Motion for Stay of
further proceedings filed by DEEP, staying all proceedings on the administrative order for 120 days. On January 26, 2016 this Stay was extended for an
additional 90 days. A status conference is scheduled for May 11, 2016. We cannot predict the outcome of this matter. As of December 31, 2015 we reserved
$20.5 million for this case and have accrued the remaining $9.5 million in accordance with the settlement with PURA approving the acquisition.
Note 15. Income Taxes
Current and deferred taxes charged to (benefit) expense for the years ended December 31, 2015, 2014 and 2013 consisted of:
Years Ended December 31, 2015 2014 2013
(Millions)
Current
Federal $ (20) $ (10) $ (22 )
State (33 ) 31 (1)
Current taxes charged to (benefit) expense (53) 21 (23)
Deferred
Federal 136 218 60
State (6) 82 42
Deferred taxes charged to expense 130 300 102
Production tax credits (42) (37) (42)
Investment tax credits (1 ) (2) (2)
Total Income Tax Expense $ 34 $ 282 $ 35
The differences between tax expense per the statements of operations and tax expense at the 35% statutory federal tax rate for the years ended December 31,
2015, 2014 and 2013 consisted of:
Years Ended December 31, 2015 2014 2013
(Millions)
Tax expense (benefit) at federal statutory rate $ 105 $ 247 $ (5 )
Depreciation and amortization not normalized 15 15 24
Investment tax credit amortization (1) (2) (2 )
Tax return related adjustments 6 2 7
Production tax credits (42 ) (37) (42)
Tax equity financing arrangements (36) (11) (23)
Change in tax reserves 3 (2)
Impairment of non-deductible goodwill 38
Changes in New York tax law 41
State tax expense (benefit), net of federal benefit (25) 32 27
Non-deductible acquisition costs 9
Other, net 3 (8) 13
Total Income Tax Expense $ 34 $ 282 $ 35
139
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Deferred tax assets and liabilities as of December 31, 2015 and 2014 consisted of:
As of December 31, 2015 2014
(Millions)
Non-current Deferred Income Tax Liabilities (Assets)
Property related $ 4,763 $ 3,778
Unfunded future income taxes 211 146
Federal and state tax credits (367 ) (317 )
Accumulated deferred investment tax credits 15 16
Federal and state NOL’s (1,367 ) (1,266)
Joint ventures/partnerships 655 884
Nontaxable grant revenue (595 ) (622 )
Other (17) 66
Non-current Deferred Income Tax Liabilities 3,298 2,685
Add: Valuation allowance 19 17
Total Non-current Deferred Income Tax Liabilities 3,317 2,702
Less amounts classified as regulatory liabilities
Non-current deferred income taxes 519 433
Non-current Deferred Income Tax Liabilities $ 2,798 $ 2,269
Deferred tax assets $ 2,346 $ 2,205
Deferred tax liabilities 5,663 4,907
Net Accumulated Deferred Income Tax Liabilities $ 3,317 $ 2,702
Valuation allowances are recorded to reduce deferred tax assets when it is not more-likely-than not that all or a portion of a tax benefit will be realized. A
valuation allowance for the entire $9 million (net of federal benefit) carryforward of Maine Research and Development Super credits generated in tax years
2007 through 2012 was established as of December 31, 2012 with no change in this balance as of December 31, 2015 or 2014. A valuation allowance of $8
million, (net of federal benefit) and an additional valuation allowance of $2 million (net of federal benefit) were established on various state NOLs and credits
in 2014 and 2015, respectively.
The reconciliation of unrecognized income tax benefits for the years ended December 31, 2015, 2014 and 2013 consisted of:
Years ended December 31, 2015 2014 2013
(Millions)
Beginning Balance $ 38 $ 41 $ 91
Increases for tax positions related to prior years 1 20 4
Reduction for tax position related to settlements
with taxing authorities (3 ) (23 ) (54)
Ending Balance $ 36 $ 38 $ 41
Unrecognized income tax benefits represent income tax positions taken on income tax returns but not yet recognized in the combined and consolidated
financial statements. The accounting guidance for uncertainty in income taxes provides that the financial effects of a tax position shall initially be
recognized when it is more likely than not based on the technical merits the position will be sustained upon examination, assuming the position will be
audited and the taxing authority has full knowledge of all relevant information.
Accruals for interest and penalties on tax reserves were $2 million, $3 million, and $11 million for the years ended December 31, 2015, 2014 and 2013,
respectively. If recognized, $9 million of the total gross unrecognized tax benefits would affect the effective tax rate.
The total amount of unrecognized tax benefits anticipated to result in a net decrease to unrecognized tax benefits within 12 months of December 31, 2015 is
estimated to be $9 million primarily relating to anticipation of additional guidance to be released by the IRS.
All federal tax returns filed by ARHI from the periods ended March 31, 2004 to December 31, 2009, are closed for adjustment. Generally, the adjustment
period for the individual states we filed in is at least as long as the federal period.
140
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
On December 29, 2014, the Joint Committee on Taxation approved the examination of AVANGRID and its subsidiaries, without ARHI, for the tax years 1998
through 2009. The results of these audits, net of reserves already provided, were immaterial. All New York and Maine state returns, which were filed without
ARHI, are closed through 2011.
As of December 31, 2015, UIL is subject to audit of its federal tax return for years 2013 and 2014. UIL income tax years 2010 through 2014 are open and
subject to Connecticut, and Massachusetts audit.
As of December 31, 2015, we had federal tax net operating losses of $3.5 billion, federal renewable energy credits, federal R&D tax credits and other federal
credits of $338 million, state tax net operating losses of $154 million in several jurisdictions and miscellaneous state tax credits of $30 million available to
carry forward and reduce future income tax liabilities. For state purposes, we recognized a valuation allowance of $19 million. The federal and state net
operating losses begin to expire in 2025, while the federal tax credits begin to expire in 2024.
Note 16. Post-retirement and Similar Obligations
Networks has funded noncontributory defined benefit pension plans that cover substantially all Networks employees. The plans provide defined benefits
based on years of service and final average salary for employees hired before 2002. Employees hired in 2002 or later are covered under a cash balance plan or
formula where their benefit accumulates based on a percentage of annual salary and credited interest. During 2013, Networks announced that they would
discontinue, effective December 31, 2013, the cash balance accruals for all non-union employees covered under the cash balance plans. CMP’s unionized
employees covered under the cash balance plans ceased to receive accruals as of December 31, 2014. NYSEGs unionized employees covered under the cash
balance plans ceased to receive accruals as of December 31, 2015. Their earned balances will continue to accrue interest but will no longer be increased by a
percentage of earnings. Instead, they will receive a minimum contribution to their account under their respective companys defined contribution plan. There
was no change to the defined benefit plans for employees covered under the plans that provide defined benefits based on years of service and final average
salary.
Networks has other postretirement health care benefit plans covering substantially all Networks’ employees. The healthcare plans are contributory and
participants contributions are adjusted annually.
The UI pension plan covers the majority of employees of UIL and UI. UI also has a nonqualified supplemental pension plan for certain employees and a
nonqualified retireeonly pension plan for certain early retirement benefits.
The Regulated Gas Companies have multiple qualified pension plans covering substantially all of their union and management employees. These entities
also have nonqualified supplemental pension plans for certain employees. The qualified pension plans are traditional defined benefit plans or cash balance
plans for those hired on or after specified dates. In some cases, neither of these plans is offered to new employees and have been replaced with enhanced
401(k) plans for those hired on or after specified dates.
In addition to providing pension benefits, UI also provides other postretirement benefits, consisting principally of health care and life insurance benefits, for
retired employees and their dependents. The healthcare plans are contributory and participants contributions are adjusted annually.
SCG and CNG also have plans providing other postretirement benefits for substantially all of their employees. These benefits consist primarily of health care,
prescription drug and life insurance benefits, for retired employees and their dependents.
ARHI has funded defined benefit pension plans for eligible employees hired prior to January 1, 2008. The benefit is based on participant’s age, service, and
five years average pay at the time of the freeze date of April 30, 2011. ARHI has other postretirement health care benefit plans covering eligible retirees and
employees hired prior to January 1, 2008. Health and life insurance rates are based on age and service points at the time of retirement.
141
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Obligations and funded status of Networks and ARHI as of December 31, 2015 and 2014 consisted of:
Pension Benefits Postretirement Benefits
As of December 31, 2015 2014 2015 2014
(Millions)
Change in benefit obligation
Benefit obligation as of January 1, $ 2,620 $ 2,316 $ 435 $ 385
Service cost 35 30 5 5
Interest cost 97 110 16 18
Plan participants’ contributions 4 4
Plan amendments (1)
Actuarial (gain) loss (105) 439 (31) 64
Special termination benefits 2
Benefits paid (158 ) (275) (25 ) (41)
Benefit Obligation as of December 31, 2,491 2,620 403 435
Change in plan assets
Fair value of plan assets as of January 1, 2,143 2,223 129 128
Actual return on plan assets (21) 163 (4) 4
Employer contributions 27 32 21 38
Plan participants’ contributions 4 4
Benefits paid (158 ) (275) (25 ) (41)
Withdrawal from VEBA (2) (4 )
Fair Value of Plan Assets as of December 31, 1,991 2,143 123 129
Funded Status as of December 31, $ (500) $ (477) $ (280 ) $ (306 )
Amounts recognized as of December 31, 2015 and 2014 consisted of:
Pension Benefits Postretirement Benefits
As of December 31, 2015 2014 2015 2014
(Millions)
Non-current assets $ $ $ $
Current liabilities (5) (5 )
Non-current liabilities (500 ) (477 ) (275 ) (301 )
Total $ (500 ) $ (477 ) $ (280 ) $ (306 )
Networks offered terminated vested employees an option to receive their future pension benefit as a lump sum in 2013. Approximately $59.9 million of
payments were made in 2013 as a result of terminated vested employees exercising the lump sum option. An additional $5.8 million was paid in 2014. The
lump sum payments did not trigger settlement accounting.
Networks made a similar offer during 2014 to retired employees who are currently receiving benefits. Approximately $118.5 million of payments were made
in 2014 as a result of retired employees exercising the lump sum option. The lump sum payments did not trigger settlement accounting.
142
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
The following table represents the change in benefit obligation, change in plan assets and the respective funded status of UILs pension and other
postretirement plans as of December 31, 2015, including purchase price allocation balances. Plan assets and obligations have been measured as of December
31, 2015.
Pension
Benefits
Other
Postretirement
Benefits
(Millions) 2015 2015
Change in Benefit Obligation:
Benefit obligation at December 17 $ 1,019 $ 122
Service cost 1
Interest cost 2
Benefits paid (including expenses) (4)
Benefit obligation at December 31 $ 1,018 $ 122
Change in Plan Assets:
Fair value of plan assets at December 17 $ 687 $ 39
Actual return on plan assets (10 )
Benefits paid (including expenses) (4)
Fair value of plan assets at December 31 $ 673 $ 39
Funded Status at December 31:
Projected benefits less than plan assets $ (345 ) $ (83)
Amounts Recognized in the Statement of
Financial Position consist of:
Non-current liabilities $ (345) $ (83)
Amounts recognized in OCI, before income taxes, for ARHI for the years ended December 31, 2015, 2014 and 2013 consisted of:
Pension Benefits Postretirement Benefits
Years Ended December 31, 2015 2014 2013 2015 2014 2013
(Millions)
Net (income) loss $ 25 $ 22 $ 16 $ (1) $ 8 $ 14
We have determined that all Networks’ regulated operating companies are allowed to defer as regulatory assets or regulatory liabilities items that would have
otherwise been recorded in accumulated OCI pursuant to the accounting requirements concerning defined benefit pension and other postretirement plans.
Amounts recognized as regulatory assets or regulatory liabilities for Networks for the years ended December 31, 2015, 2014 and 2013 for Networks consisted
of:
Pension Benefits Postretirement Benefits
Years Ended December 31, 2015 2014 2013 2015 2014 2013
(Millions)
Net loss $ 982 $ 1,045 $ 704 $ 76 $ 96 $ 24
Prior service cost (credit) 9 12 16 (49 ) (57 ) (67)
Amounts recognized as regulatory assets for the period from December 17, 2015 to December 31, 2015 for UIL consisted of:
Pension
Benefits
Other
Postretirement
Benefits
(Millions) 2015 2015
Net loss 12
Our accumulated benefit obligation for all defined benefit pension plans of Networks and ARHI was $2,334 million and $2,436 million as of December 31,
2015 and 2014, respectively. CMP’s and NYSEG’s postretirement benefits were partially funded as of December 31, 2015 and 2014.
143
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
The projected benefit obligation and the accumulated benefit obligation exceeded the fair value of pension plan assets for all plans of Networks and ARHI as
of December 31, 2015 and 2014.
The aggregate projected and accumulated benefit obligations and the fair value of plan assets for underfunded plans of Networks and ARHI as of December
31, 2015 and 2014 consisted of:
Projected Benefit
Obligation Exceeds Fair
Value of Plan Assets
Accumulated Benefit
Obligation Exceeds Fair
Value of Plan Assets
As of December 31, 2015 2014 2015 2014
(Millions)
Projected benefit obligation $ 2,491 $ 2,620 $ 2,491 $ 2,620
Accumulated benefit obligation 2,334 2,436 2,334 2,436
Fair value of plan assets 1,991 2,143 1,991 2,143
The aggregate projected and accumulated benefit obligations and the fair value of plan assets for underfunded plans of UIL as of December 31,
2015consisted of:
Pension Benefits
As of December 31, 2015
(Millions)
Projected benefit obligation $ 1,018
Accumulated benefit obligation 927
Fair value of plan assets 673
Components of Networks’ net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and regulatory assets and
liabilities as of December 31, 2015, 2014 and 2013 consisted of:
(Millions) Pension Benefits Postretirement Benefits
As of December 31, 2015 2014 2013 2015 2014 2013
Net Periodic Benefit Cost:
Service cost $ 35 $ 30 $ 36 $ 4 $ 4 $ 5
Interest cost 95 107 102 15 17 16
Expected return on plan assets (154 ) (161 ) (166 ) (7) (7) (7)
Amortization of prior service cost (benefit) 3 4 4 (9 ) (11) (14)
Amortization of net loss 130 94 120 7 3
Special termination benefit charge 2
Settlement charge 2
Net Periodic Benefit Cost 113 74 96 10 3 3
Other changes in plan assets and benefit
obligations recognized in regulatory assets
and regulatory liabilities:
Settlements $ (2 ) $ $ $ $ $
Net loss (gain) 69 434 (244 ) (12) 72 (50)
Amortization of net (loss) (130 ) (94) (120 ) (7) (3)
Current year prior service cost (1) (2 )
Amortization of prior service (cost) benefit (3) (4 ) (4) 9 11 14
Total Other Changes (66) 336 (368 ) (11) 83 (41)
Total Recognized $ 47 $ 410 $ (272 ) $ (1 ) $ 86 $ (38)
144
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Components of UILs net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and regulatory assets for the
period from December 17, 2015 to December 31, 2015 consisted of:
For the period from December 17, 2015
to December 31, 2015
Pension
Benefits
Other Postretirement
Benefits
(Millions)
Net Periodic Benefit Cost:
Service cost $ 1 $
Interest cost 2
Expected return on plan assets (2)
Net periodic benefit cost
$ 1 $
Other Changes in Plan Assets and Benefit
Obligations Recognized as a Regulatory
Asset:
Net (gain) loss $ $
Total Other Changes
Total Recognized $ 1 $
Components of ARHIs net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and OCI as of December 31,
2015, 2014 and 2013 consisted of:
(Millions) Pension Benefits Postretirement Benefits
As of December 31, 2015 2014 2013 2015 2014 2013
Net Periodic Benefit Cost:
Service cost $ $ $ $ 1 $ 1 $ 1
Interest cost 2 2 2 1 1 1
Expected return on plan assets (2) (3 ) (3 )
Amortization of prior service cost 1 1
Amortization of net loss 1 1 1
Settlement charge 2
Net Periodic Benefit Cost (income) 1 (1 ) 2 2 4 3
Other Changes in plan assets and benefit
obligations recognized in OCI:
Net loss (gain) 4 6 (12) (8 ) (5) 7
Amortization of net (loss) (1) (3) (1 )
Amortization of prior service (cost) (1) (1 )
Total Other Changes 3 6 (15) (8) (7 ) 6
Total Recognized $ 4 $ 5 $ (13 ) $ (6) $ (3) $ 9
The net periodic benefit cost for postretirement benefits represents the amount expensed for providing health care benefits to retirees and their eligible
dependents. We include the net periodic benefit cost in other operating expenses net of capitalized portion.
Amounts expected to be amortized from regulatory assets or liabilities into net periodic benefit cost for the year ending December 31, 2016 consisted of:
Year Ended December 31, 2016 Pension Benefits Postretirement Benefits
(Millions)
Estimated net loss $ 123 $ 7
Estimated prior service cost (benefit) 2 (9 )
145
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Amounts expected to be amortized from OCI into net periodic benefit cost for the year ending December 31, 2016 consisted of:
Year Ended December 31, 2016 Pension Benefits Postretirement Benefits
(Millions)
Estimated net loss $ 1 $
Estimated prior service cost (benefit)
We expect that no pension benefit or postretirement benefit plan assets will be returned to us during the year ending December 31, 2016.
The weighted-average assumptions used to determine benefit obligations for Networks and ARHI as of December 31, 2015 and 2014 consisted of:
Pension Benefits Postretirement Benefits
As of December 31, 2015 2014 2015 2014
Discount rate - Networks 4.10 % 3.80% 4.10% 3.80 %
Discount rate - ARHI 3.90 % 3.90 % 3.90 % 3.90%
Rate of compensation increase - Networks 4.00 % 4.10 %
The weighted-average assumptions used to determine benefit obligations for UIL as of December 31, 2015 consisted of:
Pension
Benefits
Other
Postretirement
Benefits
As of December 31, 2015 2015
Discount rate 4.24 % 4.24%
Average wage increase 3.50-3.80%
Health care trend rate (current year) 7.00%/9.00%
Health care trend rate (2019-2028 forward) 4.50 %
The discount rate is the rate at which the benefit obligations could presently be effectively settled. We determined the discount rates by developing yield
curves derived from a portfolio of high grade noncallable bonds with yields that closely match the duration of the expected cash flows of our benefit
obligations.
The weighted-average assumptions used to determine net periodic benefit cost for Networks and ARHI for the years ended December 31, 2015, 2014 and
2013 consisted of:
Pension Benefits Postretirement Benefits
Years Ended December 31, 2015 2014 2013 2015 2014 2013
Discount rate - Networks 3.80 % 4.90% 4.10% 3.80 % 4.90 % 4.10%
Discount rate - ARHI 3.90% 5.00 % 4.00% 3.90 % 5.00 % 4.00 %
Expected long-term return on plan assets -
Networks 7.50 % 7.50 % 7.50%
Expected long-term return on plan assets - ARHI 5.50% 6.90 % 6.50% 5.75 % 6.50 % 6.25%
Expected long-term return on plan assets -
nontaxable trust - Networks 7.50 % 7.50 % 7.50%
Expected long-term return on plan assets -
taxable trust - Networks 5.00 % 5.00 % 5.00%
Rate of compensation increase - Networks 4.10% 4.20% 4.00%
146
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
The weighted-average assumptions used to determine net periodic benefit cost for UIL for the period from December 17, 2015 to December 31, 2015
consisted of:
For the period from December 17, 2015
to December 31, 2015
Pension
Benefits
Other Postretirement
Benefits
Discount rate 4.24% 4.24%
Average wage increase 3.50-3.80%
Return on plan assets 7.75-8.00% 5.56-8.00%
Health care trend rate (current year) 7.00%
Health care trend rate (2019 forward) 4.50%
We developed our expected long-term rate of return on plan assets assumption based on a review of long-term historical returns for the major asset classes, the
target asset allocations, and the effect of rebalancing of plan assets discussed below. Our analysis considered current capital market conditions and projected
conditions. NYSEG, RGE and UIL amortize unrecognized actuarial gains and losses over ten years from the time they are incurred as required by the NYPSC,
PURA and DPU. Our other companies use the standard amortization methodology under which amounts in excess of ten-percent of the greater of the
projected benefit obligation or market related value are amortized over the plan participants’ average remaining service to retirement.
Assumed health care cost trend rates used to determine benefit obligations as of December 31, 2015 and 2014 consisted of:
As of December 31, 2015 2014
Health care cost trend rate assumed for next year -
Networks 7.50%/7.00% 7.75%/7.25%
Health care cost trend rate assumed for next year -
ARHI 7.00%/9.00% 7.75%/6.75%
Rate to which cost trend rate is assumed to decline
(ultimate trend rate) - Networks 4.5 % 4.5 %
Rate to which cost trend rate is assumed to decline
(ultimate trend rate) - ARHI 4.5 % 4.75%
Year that the rate reaches the ultimate trend rate -
Networks 2027 2027
Year that the rate reaches the ultimate trend rate -
ARHI 2026 2025
The effects of a one-percent change in the assumed health care cost trend rates would have the following effects:
1% Increase 1% Decrease
(Millions)
Effect on total of service and interest cost $ 1 $ (1)
Effect on postretirement benefit obligation 9 (7)
Contributions
We make annual contributions in accordance with our funding policy of not less than the minimum amounts as required by applicable regulations. Networks
and UIL expect to contribute $21 million and $22 million, respectively, to the pension benefit plans during 2016.
147
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Estimated Future Benefit Payments
Expected benefit payments and Medicare Prescription Drug, Improvement and Modernization Act of 2003 subsidy receipts reflecting expected future service
for Networks and ARHI as of December 31, 2015 consisted of:
(Millions)
Pension
Benefits
Postretirement
Benefits
Medicare Act
Subsidy
Receipts
2016 $ 154 $ 26 $
2017 156 27
2018 159 27
2019 161 27
2020 163 27
2021 - 2025 826 135 1
Expected benefit payments and Medicare Prescription Drug, Improvement and Modernization Act of 2003 subsidy receipts reflecting expected future service
for UIL as of December 31, 2015 consisted of:
(Millions)
Pension
Benefits
Other
Postretirement
Benefits
Medicare Act
Subsidy
Receipts
2016 $ 48 $ 7 $
2017 50 7
2018 51 7
2019 53 7
2020 54 7
2021-2025 295 37 1
Non-Qualified Pension Plans
Networks and ARHI also sponsor various unfunded pension plans for certain current employees, former employees and former directors. The total liability for
these plans, which is included in Other Non-current Liabilities, was $39 million and $43 million at December 31, 2015 and 2014, respectively.
UI has established a supplemental retirement benefit trust and, through this trust, purchased life insurance policies on certain officers of UIL and UI to fund
the future liability under the non-qualified supplemental plan. The total liability for these non-qualified plans, which is included in Other Non-current
Liabilities, was $20 million as of December 31, 2015.
Plan Assets
Our pension benefits plan assets for Networks and ARHI are held in two master trusts. This provides for a uniform investment manager lineup and an efficient,
cost effective means of allocating expenses and investment performance to each plan. Our primary investment objective is to ensure that current and future
benefit obligations are adequately funded and with volatility commensurate with our risk tolerance. Preservation of capital and achievement of sufficient
total return to fund accrued and future benefits obligations are of highest concern. Our primary means for achieving capital preservation is through
diversification of the trusts’ investments while avoiding significant concentrations of risk in any one area of the securities markets. Further diversification is
achieved within each asset group through utilizing multiple asset managers and systematic allocation to various asset classes and providing broad exposure
to different segments of the equity, fixed income, and alternative investment markets.
Networks’ asset allocation policy is the most important consideration in achieving our objective of superior investment returns while minimizing risk. We
have established a target asset allocation policy within allowable ranges for our pension benefits plan assets within broad categories of asset classes made up
of Return-Seeking and Liability-Hedging investments. Within the Return-Seeking category, we have targets of thirty-five-percent in equity securities and
twenty-percent in equity alternative investments. The Liability-Hedging asset class has a target allocation percentage of forty-five-percent. Return-Seeking
investments generally consist of domestic, international, global, and emerging market equities invested in companies across all market capitalization ranges.
Return-Seeking assets also include investments in real estate, absolute return, and strategic markets. Liability-Hedging investments generally consist of long-
term corporate bonds, annuity contracts, long-term treasury STRIPS, and opportunistic fixed income investments. Systematic
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Notes to Combined and Consolidated Financial Statements (Continued)
rebalancing within the target ranges increases the probability that the annualized return on the investments will be enhanced, while realizing lower overall
risk, should any asset categories drift outside their specified ranges.
ARHIs investment portfolio contains a diversified blend of equity, fixed income, and other investments. Equity investments are diversified across U.S. and
non-U.S. stocks, investment styles, and market capitalization ranges. Fixed income investments are primarily invested in U.S. bonds and may also include
some non-U.S. bonds. Other asset classes, including real estate, absolute return, and real return, are used to enhance long-term returns while improving
portfolio diversification. We primarily minimize the risk of large losses through diversification but also through monitoring and managing other aspects of
risk through quarterly investment portfolio reviews, annual liability measurements, and periodic asset and liability studies.
The fair values of pension benefits plan assets, by asset category, as of December 31, 2015 consisted of:
As of December 31, 2015 Fair Value Measurements
(Millions) Total Level 1 Level 2 Level 3
Asset Category
Cash and cash equivalents $ 57 $ 3 $ 54 $
U.S. government securities 171 171
Common stocks 314 314
Registered investment companies 114 114
Corporate bonds 324 324
Preferred stocks 5 5
Common collective trusts 511 21 490
Partnerships/joint venture interests 84 84
Real estate investments 89 89
Other, principally annuity, fixed income 322 4 318
Total $ 1,991 $ 602 $ 408 $ 981
The fair values of pension benefits plan assets, by asset category, as of December 31, 2014 consisted of:
As of December 31, 2014 Fair Value Measurements
(Millions) Total Level 1 Level 2 Level 3
Asset Category
Cash and cash equivalents $ 48 $ 4 $ 44 $
U.S. government securities 177 177
Common stocks 447 360 87
Registered investment companies 116 116
Corporate bonds 367 23 344
Preferred stocks 4 4
Common collective trusts 477 28 449
Partnership/joint venture interests 79 79
Real estate investments 77 2 75
Other, principally annuity, fixed income 351 5 4 342
Total $ 2,143 $ 687 $ 511 $ 945
Valuation Techniques
We value our pension benefits plan assets as follows:
Cash and cash equivalents - Level 1: at cost, plus accrued interest, which approximates fair value. Level 2: proprietary cash associated with other
investments, based on yields currently available on comparable securities of issuers with similar credit ratings.
U.S. government securities, common stocks and registered investment companies - at the closing price reported in the active market in which the
security is traded.
Corporate bonds - based on yields currently available on comparable securities of issuers with similar credit ratings.
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Notes to Combined and Consolidated Financial Statements (Continued)
Mutual funds - based upon quoted market prices in active markets, which represent the Net Asset Value (NAV) of the shares held.
Preferred stocks - at the closing price reported in the active market in which the individual investment is traded.
Common/collective trusts and Partnership/joint ventures - using the NAV provided by the administrator of the fund. The NAV is based on the value of
the underlying assets owned by the fund, minus its liabilities, and then divided by the number of shares outstanding. The NAV is classified as Level 2
if the plan has the ability to redeem the investment with the investee at NAV per share at the measurement date. Redemption restrictions or
adjustments to NAV based on unobservable inputs result in the fair value measurement being classified as Level 3 if those inputs are significant to the
overall fair value measurement.
Real estate investments - based on a discounted cash flow approach that includes the projected future rental receipts, expenses and residual values
because the highest and best use of the real estate from a market participant view is as rental property.
Other investments, principally annuity and fixed income - Level 1: at the closing price reported in the active market in which the individual
investment is traded. Level 2: based on yields currently available on comparable securities of issuers with similar credit ratings. Level 3: when quoted
prices are not available for identical or similar instruments, under a discounted cash flows approach that maximizes observable inputs such as current
yields of similar instruments but includes adjustments for certain risks that may not be observable such as credit and liquidity risks.
Fair value measurements using Level 3 inputs as of December 31, 2015, 2014 and 2013 consisted of:
(Millions)
Common
Collective
Trusts
Partnership
Joint Venture
Interests
Real Estate
Investments
Other
Investments Total
As of December 31, 2013 $ 458 $ 57 $ 67 $ 337 $ 919
Actual return on plan assets:
Relating to assets sold during the year 6 6
Relating to assets still held at the reporting date 5 3 6 5 19
Purchases, sales and settlements (20) 19 2 1
As of December 31, 2014 $ 449 $ 79 $ 75 $ 342 $ 945
Actual return on plan assets:
Relating to assets sold during the year (3) (19 ) 1 (21)
Relating to assets still held at the reporting date (5) 19 10 (21 ) 3
Purchases, sales and settlements 49 5 4 (4) 54
As of December 31, 2015 $ 490 $ 84 $ 89 $ 318 $ 981
Our postretirement benefits plan assets are held with trustees in multiple voluntary employees’ beneficiary association (VEBA) and 401(h) arrangements and
are invested among and within various asset classes to achieve sufficient diversification in accordance with our risk tolerance. This is achieved for our
postretirement benefits plan assets through the utilization of multiple institutional mutual and money market funds, providing exposure to different segments
of the fixed income, equity and short-term cash markets. Approximately twenty-five-percent of the postretirement benefits plan assets are invested in VEBA
and 401(h) arrangements that are not subject to income taxes with the remainder being invested in arrangements subject to income taxes.
Networks have established a target asset allocation policy within allowable ranges for postretirement benefits plan assets of forty-seven-percent equity
securities, thirty-eight-percent fixed income, and fifteen-percent for all other investment types. The target allocations within allowable ranges are further
diversified into twenty-percent large cap domestic equities, twelve-percent medium and small cap domestic equities, ten-percent international developed
market, and five-percent emerging market equity securities. Fixed income investment targets and ranges are segregated into core fixed income at thirty-one-
percent, global high yield fixed income at four-percent, and international developed market debt at three-percent. Other alternative investment targets are
five-percent for real estate, five-percent for absolute return, and five-percent for tangible assets. Systematic rebalancing within target ranges increases the
probability that the annualized return on investments will be enhanced, while realizing lower overall risk, should any asset categories drift outside their
specified ranges.
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Notes to Combined and Consolidated Financial Statements (Continued)
The fair value of other postretirement benefits plan assets, by asset category, as of December 31, 2015 consisted of:
As of December 31, 2015 Fair Value Measurements
(Millions) Total Level 1 Level 2 Level 3
Asset Category
Money market funds $ 4 $ 4 $ $
Mutual funds, fixed 36 36
Government and corporate bonds 2 2
Mutual funds, equity 46 46
Common stocks 24 24
Mutual funds, other 11 11
Total $ 123 $ 121 $ 2 $
The fair values of other postretirement benefits plan assets, by asset category, as of December 31, 2014 consisted of:
As of December 31, 2014 Fair Value Measurements
(Millions) Total Level 1 Level 2 Level 3
Asset Category
Money market funds $ 4 $ 4 $ $
Mutual funds, fixed 36 36
Government and corporate bonds 2 2
Mutual funds, equity 45 45
Common stocks 29 29
Mutual funds, other 12 12
Total $ 128 $ 126 $ 2 $
Valuation Techniques
We value our postretirement benefits plan assets as follows:
Money market funds and mutual funds - based upon quoted market prices in active markets, which represent the NAV of shares held.
Government bonds, and common stocks - at the closing price reported in the active market in which the security is traded.
Corporate bonds - based on yields currently available on comparable securities of issuers with similar credit ratings.
Pension and postretirement benefit plan equity securities did not include any Iberdrola common stock as of December 31, 2015.
The following tables set forth the fair values of UIL’s pension and other postretirement benefits plan assets as of December 31, 2015.
Fair Value Measurements
December 31, 2015 Level 1 Level 2 Level 3 Total
(Millions)
Pension assets
Mutual funds $ $ 673 $ $ 673
Other postretirement benefit assets
Mutual funds 32 7 39
Total $ 32 $ 680 $ $ 712
The determination of fair values of the Level 2 co-mingled mutual funds were based on the Net Asset Value (NAV) provided by the managers of the
underlying fund investments and the unrealized gains and losses. The NAV provided by the managers typically reflect the fair value of each underlying fund
investment.
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Notes to Combined and Consolidated Financial Statements (Continued)
Defined contribution plans
We also have defined contribution plans defined as 401(k)s. The annual contributions made through these plans for Networks and ARHI amounted to $17
million, $20 million and $14 million for 2015, 2014, and 2013 respectively.
UIL has several 401(k) plans in which substantially all of its employees are eligible to participate. Employees may defer a portion of the compensation and
invest in various investment alternatives. The matching expense for the period from December 17, 2015 to December 31, 2015, was immaterial.
Note 17. Equity
Our share capital consisted of 500,000,000 shares authorized, 309,491,082 shares issued and 308,864,609 shares outstanding, 81.5% owned by Iberdrola,
each having a par value of $0.01, for a total value of common stock capital of $3 million and additional paid in capital of $13,653 million as of December 31,
2015. Our share capital consisted of 500,000,000 shares authorized, 252,235,232 shares issued and 252,235,232 shares outstanding, wholly owned by
Iberdrola, each having a par value of $0.01, for a total value of common stock capital of $3 million and additional paid in capital of $11,375 million as of
December 31, 2014. On December 15, 2015, the Board of Directors approved our common stock dividend, accounted for as stock split. The stock split,
effected through a stock dividend, resulted in the issuance of 252,234,989 shares, which in addition to the 243 previously existing shares increased the total
shares outstanding to 252,235,232. The stock dividend was effective upon the Boards approval. All share and per share information included in the
combined and consolidated financial statements have been retroactively adjusted to reflect the impact of the stock dividend. As a result, our share capital
consisted of 500,000,000 shares authorized, 252,235,232 shares issued and 252,235,232 shares outstanding, wholly owned by Iberdrola, each having a par
value of $0.01, for a total value of common stock capital of $3 million and additional paid in capital of $11,375 million as of December 31, 2014. All
common shares have the same voting and economic rights. We have 626,473 treasury shares and no convertible preferred shares as of December 31, 2015. We
had no treasury shares or convertible preferred shares as of December 31, 2014.
In February 2013 prior to the reorganization, in which ARHI became a subsidiary of AVANGRID, ARHI issued shares to Iberdrola in return for $153 million
in cash, $550 million in the form of a loan note and the remaining $10 million in accrued interest on the loan note. The loan note was an obligation of
AVANGRID and as a result of the reorganization in November 2013 the ARHI loan receivable and the AVANGRID loan payable have been eliminated in the
combined and consolidated financial statements.
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Notes to Combined and Consolidated Financial Statements (Continued)
Accumulated OCI (Loss)
Accumulated OCI for the years ended December 31, 2015, 2014 and 2013 consisted of:
Accumulated Other
Comprehensive Income
(Loss)
As of
December
31, 2012
2013
Change
As of
December
31, 2013
2014
Change
As of
December
31, 2014
2015
Change
As of
December
31, 2015
(Millions)
Loss on revaluation of defined benefit plans,
net of income tax expense
of $0.5 for 2013, $0.6 for 2014 and $2.2 for 2015 $ (27) $ 1 $ (26) $ 1 $ (25) $ 4 $ (21)
Loss for nonqualified pension plans, net of
income tax expense (benefit) of $1.0 for
2013, ($1.9) for 2014 and $1.7 for 2015 (7) (1) (8 ) (3) (11) 3 (8 )
Unrealized (loss) gain on derivatives
qualifying as cash flow hedges:
Unrealized (loss) gain during period on
derivatives qualifying as cash flow
hedges, net of income tax expense
(benefit) of ($1.4) for 2014 and $20.9 for
2015 (2 ) (2 ) 33 31
Reclassification adjustment for losses on
settled cash flow hedges, net of income
tax expense of $4.6 for 2013, $4.1 for 2014
and $4.9 for 2015 (a) (73) 7 (66) 5 (61) 7 (54 )
Net unrealized (loss) gain on derivatives
qualifying as cash flow hedges (73) 7 (66 ) 3 (63 ) 40 (23 )
Accumulated Other Comprehensive
(Loss) Income $ (107 ) $ 7 $ (100) 1 $ (99 ) $ 47 $ (52)
(a) Reclassification is reflected in the operating expenses line item in the combined and consolidated statements of operations.
Note 18. Net Income (Loss) Per Share
Basic net income (loss) per share is computed by dividing net income (loss) attributable to AVANGRID by the weighted-average number of shares of our
common stock outstanding. In 2015, while we did have securities that were dilutive, these securities did not result in a change on our net income (loss) per
share calculation result for the year ended December 31, 2015. We did not have any potentially-dilutive securities for the years ended December 31, 2014
and 2013. In accordance with ASC Topic 260, Earnings per Share, we retroactively applied the stock split to prior years.
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Notes to Combined and Consolidated Financial Statements (Continued)
We completed a series of reorganizations of entities under common control in November 2013. For purposes of computing net income (loss) per share, it is
assumed that the Reorganization had occurred at the beginning of the earliest period presented consistent with the pooling of interest method. Therefore, the
outstanding shares for the periods preceding the Reorganization reflect the series of reorganizations of entities under common control.
The calculations of basic and diluted earnings (loss) per share attributable to AVANGRID, including a reconciliation of the numerators and denominators for
the years ended December 31, 2015, 2014 and 2013 consisted of:
Years Ended December 31, 2015 2014 2013
(Millions, except for number of shares and per share data)
Numerator:
Net income (loss) attributable to AVANGRID $ 267 $ 424 $ (51)
Denominator:
Weighted average number of shares
outstanding - basic 254,588,212 252,235,232 252,235,232
Weighted average number of shares
outstanding - diluted 254,605,111 252,235,232 252,235,232
Earnings per share attributable to AVANGRID
Earnings (Loss) Per Common Share, Basic $ 1.05 $ 1.68 $ (0.20)
Earnings (Loss) Per Common Share, Diluted $ 1.05 $ 1.68 $ (0.20)
Note 19. Tax equity financing arrangements
The sale of a membership interest in the tax equity financing arrangements (TEFs) represents the sale of an equity interest in a structure that is considered in
substance real estate. Under existing guidance for real estate financings, the membership interests in the TEFs we sold to the third-party investors are reflected
as a financing obligation in the consolidated balance sheets. We continue to fully consolidate the TEFs’ assets and liabilities in the consolidated balance
sheets and to report the results of the TEFs’ operations in the combined and consolidated statements of operations. The presentation reflects revenues and
expenses from the TEFs’ operations on a fully consolidated basis. The liabilities are increased for cash contributed by the third-party investors, interest
accrued, and the federal income tax impact to the third-party investors of the allocation of taxable income. Interest is accrued on the balance using the
effective interest method and the third-party investors’ targeted rate of return. The balance accrued interest at an average rate of 8.5% and 8.7% as of
December 31, 2015 and 2014, respectively. The liabilities are reduced by cash distributions to the third-party investors, the allocation of production tax
credits to the third-party investors, and the federal income tax impact to the third-party investors of the allocation of taxable losses. This treatment is
expected to remain consistent over the terms of the TEFs.
We consider the following five structures to be TEFs: (1) Aeolus Wind Power I LLC, (2) Aeolus Wind Power II LLC, (3) Aeolus Wind Power III LLC, (4)
Aeolus Wind Power IV LLC, and (5) Locust Ridge Wind Farms, LLC, (collectively, Aeolus). We retain a class of membership interest and day-to-day
operational and management control of Aeolus, subject to investor approval of certain major decisions. The third-party investors do not receive a lien on any
Aeolus assets and have no recourse against us for their upfront cash payments.
Wind power generation is subject to certain favorable tax treatments in the U.S. In order to monetize the tax benefits generated by Aeolus, we have entered
into the Aeolus structured institutional partnership investment transactions related to certain wind farms located throughout the U.S. Under the Aeolus
structures, we contribute certain wind assets, relating both to existing wind farms and wind farms that are being placed into operation at the time of the
relevant transaction, and other parties invest in the share equity of the Aeolus limited liability holding company. As consideration for their investment, the
third parties make either an upfront cash payment or a combination of upfront cash and issuance of fixed and contingent notes.
The third party investors receive a disproportionate amount of the profit or loss, cash distributions and tax benefits resulting from the wind farm energy
generation until the investor recovers its investment and achieves a cumulative annual after-tax return. Once this target return is met, the relative sharing of
profit or loss, cash distributions and taxable income or loss between the Company and the third party investor flips, with the company taking a
disproportionate share of such amounts thereafter. We also have a call option to acquire the third party investors’ membership interest within a defined time
period after this target return is met.
Our Aeolus interests are not subject to any rights of investors that may restrict our ability to access or use the assets or to settle any existing liabilities
associated with the interests.
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AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
We repurchased a portion of the holding of one of the third-party investors for $51.4 million in 2013. During 2014, the investor returns on the Aeolus I
structure successfully met the investor requirements, causing the structure to flip back to us and leaving the investor with a ten-percent noncontrolling
interest. In October 2015, AVANGRID purchased this remaining interest from the investor with a gain of $5 million recorded within “Other income and
(expense)” of the combined and consolidated statements of operations.
Note 20. Grants, Government Incentives and Deferred Income
The changes in deferred income as of December 31, 2015 and 2014 consisted of:
(Millions)
Government
grants
Other
deferred
income Total
As of December 31, 2013 1,684 19 1,703
Additions 4 4
Recognized in income (78) (8) (86)
As of December 31, 2014 $ 1,606 $ 15 $ 1,621
Additions
Recognized in income (77) 9 (68 )
As of December 31, 2015 $ 1,529 $ 24 $ 1,553
Within deferred income we classify grants we received under Section 1603 of the American Recovery and Reinvestment Act of 2009, where the United States
Department of Treasury (DOT) provides eligible parties the option of claiming grants for specified energy property in lieu of tax credits, which we claimed for
the majority of our qualifying properties. Deferred income has been recorded for the grant amounts and is amortized as an offset against depreciation expense
using the straight-line method over the estimated useful life of the associated property to which the grants apply. We recognize a net deferred tax asset for the
book to tax basis differences related to the property for income tax purposes.
We are required to comply with certain terms and conditions applicable to each grant and, if a disqualifying event should occur as specified in the grants
terms and conditions, we are required to repay the grant funds to the DOT. We believe we are in compliance with each grants terms and conditions as of
December 31, 2015 and 2014.
Other deferred income relates predominantly to gas storage transactions where revenues are recognized as services are provided.
Government grants related to depreciable assets and contributions in aid of construction treated as credits to property, plant and equipment in accordance
with FERC requirements were $390 million and $323 million as of December 31, 2015 and 2014, respectively.
Note 21. Equity method investments
We have a 50-50 joint venture with Shell Wind Energy, Inc., which owns and operates a 162- megawatt (MW) wind farm located in southeast Colorado
(Colorado Wind Ventures LLC), which commenced operations in January 2004. We account for this venture under the equity method of accounting. Our
maximum exposure to loss is our net investment, of which the carrying amount was $41 million and $66 million as of December 31, 2015 and 2014,
respectively.
We have two 50-50 joint ventures with Horizon Wind Energy, LLC, which own and operate the Flat Rock Windpower LLC and the Flat Rock Wind Power II
LLC wind farms located in upstate New York. Flat Rock Wind Power LLC, which commenced operations in January 2006, has a 231-MW capacity. Flat Rock
Wind Power II LLC commenced operations in September 2007 and has a 91-MW capacity. We account for the Flat Rock joint ventures under the equity
method of accounting. Our maximum exposure to loss is our net investments, of which the carrying amount totaled $143 million and $146 million for Flat
Rock Wind Power LLC, and $69 million and $50 million for Flat Rock Wind Power II LLC, as of December 31, 2015 and 2014, respectively.
Through UI, we are party to a 50-50 joint venture with NRG affiliates in GenConn, which operates two peaking generation plants in Connecticut. The
investment in GenConn is being accounted for as an equity investment, the carrying value of which was $110 million as of December 31, 2015.
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AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Summarized combined financial information for these equity method investments is as follows:
Years ended December 31, 2015 2014 2013
(Millions)
Revenue $ 53 $ 72 $ 60
Loss from operations (14) (15 )
Net loss (10) (15 )
As of December 31, 2015 2014
(Millions)
Current assets $ 45 $ 11
Non-current assets 929 571
Current liabilities 26 10
Non-current liabilities 223 48
Members’ equity 726 524
Ownership share 50% 50 %
Equity method investment $ 363 $ 262
None of our joint ventures have any contingent liabilities or capital commitments. Distributions received from equity method investments amounted to $12
million, $19 million, and $9 million for the years ended December 31, 2015, 2014, and 2013 respectively, which are reflected as either distributions of
earnings or as returns of capital in the operating and investing sections of the consolidated statements of cash flows, respectively.
We have other equity method investments with a carrying value of $22 million as of December 31, 2015.
Note 22. Other Financial Statements Items
Other income and (expense)
Other income and (expense) for the years ended December 31, 2015, 2014 and 2013 consisted of:
Years ended December 31, 2015 2014 2013
(Millions)
Allowance for funds used during construction $ 21 $ 17 $ 14
Carrying costs on regulatory assets 28 29 29
Other 6 6 11
Total Other income and (expense) $ 55 $ 52 $ 54
Accounts Receivable
Accounts receivable as of December 31, 2015 and 2014 consisted of:
As of December 31, 2015 2014
(Millions)
Trade receivables $ 1,036 $ 888
Other receivables - 2
Allowance for bad debts (62 ) (49)
Total Accounts Receivable $ 974 $ 841
The allowance for bad debts relates entirely to gas and electricity consumers and comprises an amount that has been reserved following historical averages of
loss percentages.
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AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
The change in the allowance for bad debts as of December 31, 2015 and 2014 consisted of:
(Millions)
As of January 1, 2013 $ 56
Current period provision 37
Write-off as uncollectible (35)
As of December 31, 2013 58
Current period provision 39
Write-off as uncollectible (48)
As of December 31, 2014 $ 49
Current period provision 46
Write-off as uncollectible (33)
As of December 31, 2015 $ 62
DPA receivable balances were $62 million and $78 million as of December 31, 2015 and 2014, respectively.
Prepayments and Other Current Assets
Prepayments and other current assets as of December 31, 2015 and 2014 consisted of:
As of December 31, 2015 2014
(Millions)
Prepaid other taxes $ 130 $ 93
Broker margin and collateral accounts 46 57
Loans to third parties 3 3
Fixed-term deposits 11 25
Other pledged deposits 24 51
Prepaid expenses 53 32
Other 18 27
Total $ 285 $ 288
Other current liabilities
Other current liabilities as of December 31, 2015 and 2014 consisted of:
As of December 31, 2015 2014
(Millions)
Advances received $ 96 $ 87
Accrued salaries 68 76
Short-term environmental provisions 35 36
Collateral deposits received 59 39
Pension and other postretirement 5 5
Other 22 19
Total $ 285 $ 262
Note 23. Segment Information
Our segment reporting structure uses our management reporting structure as its foundation to reflect how AVANGRID manages the business internally and is
organized by type of business. We report our financial performance based on the following three reportable segments:
Networks: including all the energy transmission and distribution activities, and any other regulated activity originated in New York and Maine, and
upon the acquisition of UIL on December 16, 2015 regulated electric distribution, electric transmission and gas distribution activities originated in
Connecticut and Massachusetts. The Networks reportable segment includes eight rate regulated operating segments. These operating segments
generally offer the same services distributed in similar fashions, have
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AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
the same types of customers, have similar long-term economic characteristics and are subject to similar regulatory requirements, allowing these
operations to be aggregated into one reportable segment.
Renewables: activities relating to renewable energy, mainly wind energy generation and trading related with such activities.
Gas: including gas trading and storage businesses carried on by the Group
Products and services are sold between reportable segments and affiliate companies at cost. The Chief Operating Decision Maker evaluates segment
performance based on segment adjusted EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortization) defined as net income (loss) adding back
net income (loss) attributable to other non-controlling interests, income tax expense, depreciation and amortization, impairment of non-current assets and
interest expense net of capitalization, and then subtracting other income and (expense) and earnings (losses) from equity method investments per segment.
Segment income, expense, and assets presented in the accompanying tables include all intercompany transactions that are eliminated in the combined and
consolidated financial statements.
Segment information as of and for the year ended December 31, 2015 consisted of:
For the year ended December 31, 2015
(Millions) Networks Renewables Gas Other(a)
AVANGRID
Consolidated
Revenue - external $ 3,386 $ 1,051 $ (71 ) $ 1 $ 4,367
Revenue - intersegment - 16 52 (68 )
Impairment of noncurrent assets 12 12
Depreciation and amortization 328 344 23 695
Operating income (loss) from continuing
operations 537 100 (85 ) (39) 513
Adjusted EBITDA 865 456 (62 ) (39) 1,220
Earnings from equity method investments 1 (5 ) 4
Capital expenditures 773 304 5 1,082
As of December 31, 2015
Property, plant and equipment 12,363 7,835 513 20,711
Equity method investments 110 253 22 385
Total assets $ 20,126 $ 10,685 $ 1,265 $ (1,333) $ 30,743
(a) Does not represent a segment. It mainly includes Corporate and intercompany eliminations.
Included in revenue-external for the year ended December 31, 2015 are: $2,779 million from regulated electric operations, $605 million from regulated gas
operations and $2 million from other operations of Networks; $1,051 million from renewable energy generation of Renewables; $21 million from gas storage
services and $(92) million from gas trading operations of Gas.
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AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Segment information as of and for the year ended December 31, 2014 consisted of:
For the year ended December 31, 2014
(Millions) Networks Renewables Gas Other(a)
AVANGRID
Consolidated
Revenue - external $ 3,396 $ 1,180 $ 12 $ 6 $ 4,594
Revenue - intersegment 1 9 72 (82)
Impairment of noncurrent assets 24 1 25
Depreciation and amortization 275 332 22 629
Operating income (loss) from continuing operations 616 257 16 (4) 885
Adjusted EBITDA 891 613 38 (3) 1,539
Earnings from equity method investments 2 10 12
Capital expenditures 775 250 5 1,030
As of December 31, 2014
Property, plant and equipment 8,389 8,219 525 17,133
Equity method investments 262 262
Total assets $ 12,858 $ 12,328 $ 1,393 $ (2,417) $ 24,162
(a) Does not represent a segment. It mainly includes Corporate and intercompany eliminations.
Included in revenue-external for the year ended December 31, 2014 are: $2,726 million from regulated electric operations, $668 million from regulated gas
operations and $2 million from other operations of Networks; $1,180 million from renewable energy generation of Renewables; $8 million from gas storage
services and $4 million from gas trading operations of Gas.
Segment information as of and for the year ended December 31, 2013 consisted of:
For the year ended December 31, 2013
(Millions) Networks Renewables Gas Other(a)
AVANGRID
Consolidated
Revenue - external $ 3,311 $ 1,087 $ (98 ) $ 13 $ 4,313
Revenue - intersegment 8 10 71 (89)
Impairment of noncurrent assets 75 545 620
Depreciation and amortization 257 310 26 1 594
Operating income (loss) from continuing operations 703 122 (647 ) 1 179
Adjusted EBITDA 960 507 (76 ) 2 1,393
Earnings (losses) from equity method investments (7 ) 4 (3 )
Capital expenditures 906 34 4 944
As of December 31, 2013
Property, plant and equipment 7,887 8,302 526 16,715
Equity method investments 278 278
Total assets $ 11,771 $ 11,966 $ 1,495 $ (2,062) $ 23,170
(a) Does not represent a segment. It mainly includes Corporate and intercompany eliminations.
Included in revenue-external for the year ended December 31, 2013 are: $2,665 million from regulated electric operations, $644 million from regulated gas
operations and $2 million from other operations of Networks; $1,087 million from renewable energy generation of Renewables; $36 million from gas storage
services and $(134) million from gas trading operations of Gas.
159
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Reconciliation of consolidated Adjusted EBITDA to the AVANGRID consolidated Income (Loss) Before Income Tax for the years ended December 31, 2015,
2014 and 2013 is as follows:
Years Ended December 31, 2015 2014 2013
(Millions)
Consolidated Adjusted EBITDA $ 1,220 $ 1,539 $ 1,393
Less:
Impairment of non-current assets 12 25 620
Depreciation and amortization 695 629 594
Interest expense, net of capitalization 267 243 245
Add:
Other income and (expense) 55 52 54
Earnings (losses) from equity method investments 12 (3)
Consolidated Income (Loss) Before Income Tax $ 301 $ 706 $ (15 )
Note 24. Related Party Transactions
We engage in related party transactions which are generally billed at cost and in accordance with applicable state and federal commission regulations.
Related party transactions for the years ended December 31, 2015, 2014 and 2013 consisted of:
Years Ended December 31, 2015 2014 2013
(Millions) Sales To
Purchases
From Sales To
Purchases
From Sales To
Purchases
From
Iberdrola Financiacn, S.A. $ (1) $ (2) $ (2)
Iberdrola Renovables Energia, S.L. (9 ) (10) (10)
Iberdrola Canada Energy Services, Ltd (55) (49) 2 (75)
Iberdrola Ingeniería y Construcción, S.A. U. 26
Scottish Power, Ltd (6)
Other 3 (37 ) 12 (30 ) 16 (33 )
In addition to the statements of operations items above we made purchases of turbines for wind farms from Gamesa Corporación Tecnológica, S.A. (Gamesa),
in which our ultimate parent Iberdrola has a 20% ownership. The amounts capitalized for these transactions were $70 million and $226 million as of
December 31, 2015 and 2014, respectively.
In August 2011, we entered into a revolving credit facility with Iberdrola Financiacn, S.A., a subsidiary of Iberdrola. The facility was terminated by
AVANGRID on October 28, 2015. The facility was never utilized.
Related party balances as of December 31, 2015 and 2014 consisted of:
As of December 31, 2015 2014
(Millions) Owed By Owed To Owed By Owed To
Iberdrola Canada Energy Services, Ltd $ 7 $ (5) $ 1 $
Gamesa Corporacn Tecnológica, S.A. 68 (77 ) 33 (223 )
Iberdrola Energy Projects, Inc. 1 (3 ) 15 (15 )
Other (5) 1 (1)
Transactions with our parent company (included in Other), Iberdrola, relate predominantly to allocation of corporate services and management fees. Also
included within the Purchases From category are charges for credit support relating to guarantees Iberdrola has provided to third parties guarantying our
performance. All costs that can be specifically allocated, to extent possible, are charged directly to the company receiving such services. In situations when
Iberdrola corporate services are provided to two or more companies of AVANGRID any costs remaining after direct charge are allocated using agreed upon
cost allocation methods designed to allocate those costs. We believe that the allocation method used is reasonable.
160
AVANGRID, Inc. and Subsidiaries
Notes to Combined and Consolidated Financial Statements (Continued)
Transactions with Iberdrola Canada Energy Services predominantly relate to the purchase of gas for ARHI’s gas-fired generation facility at Klamath.
There have been no guarantees provided or received for any related party receivables or payables. These balances are unsecured and are typically settled in
cash. Interest is not charged on regular business transactions but is charged on outstanding loan balances. There have been no impairments or provisions
made against any affiliated balances, other than a $10 million write-off related to an arrangement to purchase turbines from Gamesa, which was recorded in
impairment of non-current assets in the combined and consolidated statements of operations for the year ended December 31, 2015. The collectability of
amounts receivable from Gamesa are contingent upon other related parties fulfilling certain payments to Gamesa.
AVANGRID manages its overall liquidity position as part of the broader Iberdrola Group and is a party to a cash pooling agreement with Bank Mendes Gans,
N.V., similar to other Iberdrola subsidiaries. Cash surpluses remaining after meeting the liquidity requirements of AVANGRID and its subsidiaries may be
deposited in the cash pooling account where such funds are available to meet the liquidity needs of other affiliates within the Iberdrola Group. Under the cash
pooling agreement, affiliates with credit balances have pledged those balances to cover the debit balances of the other affiliated parties to the agreement.
Note 25. Quarterly financial data (unaudited)
Selected quarterly financial data for 2015 and 2014 are set forth below:
1st
Quarter
2nd
Quarter
3rd
Quarter
4th
Quarter
(Millions, except per share data)
2015
Operating Revenues $ 1,227 $ 939 $ 1,048 $ 1,153
Operating Income $ 196 $ 73 $ 161 $ 83
Net Income $ 106 $ 11 $ 54 $ 96
Net Income attributable to AVANGRID $ 106 $ 11 $ 54 $ 96
Earnings Per Common Share, Basic and Diluted: (1) $ 0.42 $ 0.04 $ 0.22 $ 0.37
2014
Operating Revenues $ 1,556 $ 938 $ 982 $ 1,118
Operating Income $ 414 $ 132 $ 153 $ 186
Net Income $ 201 $ 62 $ 64 $ 97
Net Income attributable to AVANGRID $ 200 $ 63 $ 64 $ 97
Earnings Per Common Share, Basic and Diluted: (1) $ 0.79 $ 0.25 $ 0.25 $ 0.38
(1) Based on weighted average number of 252 million shares outstanding each quarter, except for fourth quarter of 2015, which is based on weighted
average of 262 million shares as a result of the acquisition of UIL.
The first, second, third and fourth quarters of 2015 include $4 million, $8 million, $7 million and $18.5 million of pre-tax merger related expenses,
respectively. Additionally, the fourth quarter of 2015 includes $44 million relating to rate credits, before income taxes, and $63 million tax benefits related
to state income tax matters, including the initial impact of the merger on our consolidated tax filings.
Note 26. Subsequent events
On February 17, 2016, Board of Directors of AVANGRID declared a quarterly dividend of $0.432 per share on its common stock. This dividend is payable
April 1, 2016 to shareholders of record at the close of business on March 10, 2016.
On February 17, 2016, we approved the sale of our interest in Iroquois Gas Transmission System L.P. (Iroquois) to an unaffiliated third party. The sale closed
on March 31, 2016 with a sale price of $53.8 million.
161
Schedule I –Financial Statements of Parent
AVANGRID, INC. (PARENT)
CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
(Millions)
Years Ended December 31, 2015 2014 2013
Operating Revenues $ $ $
Operating Expenses
Operating expense 38 2 17
Taxes other than income taxes 5 2 (15)
Total Operating Expenses 43 4 2
Operating Income (43) (4 ) (2 )
Other Income and (expense)
Other income and (expense) 10 (1 ) 6
Equity earnings (loss) of subsidiaries 44 515 (37 )
Interest expense (14 ) (34) (22)
Income (Loss) Before Income Tax (3 ) 476 (55)
Income tax expense (benefit) (270 ) 52 (4)
Net Income (Loss) $ 267 $ 424 $ (51 )
See accompanying notes to Schedule 1
162
Schedule I –Financial Statements of Parent
AVANGRID, INC. (PARENT)
CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
FOR THE YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
(Millions)
Years Ended December 31, 2015 2014 2013
Net Income (Loss) $ 267 $ 424 $ (51 )
Other comprehensive income of subsidiaries 47 1 7
Comprehensive Income (Loss) $ 314 $ 425 $ (44 )
See accompanying notes to Schedule 1
163
Schedule I –Financial Statements of Parent
AVANGRID, INC. (PARENT)
CONDENSED FINANCIAL INFORMATION OF PARENT
BALANCE SHEETS
AS OF DECEMBER 31, 2015 AND 2014
(Millions)
As of December 31, 2015 2014
Assets
Current Assets
Cash and cash equivalents $ 125 $ 3
Accounts receivable from subsidiaries 602 3
Notes receivable from subsidiaries 453 771
Prepayments and other current assets 16 57
Total current assets 1,196 834
Investments in subsidiaries 14,093 12,792
Other assets
Deferred income taxes 148
Other 4 6
Total other assets 152 6
Total Assets $ 15,441 $ 13,632
Liabilities
Current Liabilities
Notes payable to subsidiaries $ 321 $ 652
Accounts payable and accrued liabilities 12
Accounts payable to subsidiaries 3 3
Interest accrued subsidiaries 1 7
Taxes accrued 44 141
Other current liabilities 4 2
Total current liabilities 385 805
Other non-current liabilities
Deferred income taxes 14
Other 3 2
Total other non-current liabilities 3 16
Non-current debt with subsidiaries 350
Total non-current liabilities 3 366
Total Liabilities 388 1,171
Equity
Stockholder’s Equity:
Common stock 3 3
Additional paid-in capital 13,653 11,375
Retained earnings 1,449 1,182
Accumulated other comprehensive loss (52) (99)
Total Equity 15,053 12,461
Total Liabilities and Equity $ 15,441 $ 13,632
See accompanying notes to Schedule 1
164
Schedule I –Financial Statements of Parent
AVANGRID, INC. (PARENT)
CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
(Millions)
Years Ended December 31, 2015 2014 2013
Cash Flow from Operating Activities
Net income (loss) $ 267 $ 424 $ (51 )
Adjustments to reconcile net income (loss) to net cash provided by
(used in) operating activities:
Amortization of other assets and liabilities 1
Deferred income taxes (151 ) 24 61
Equity (earnings) loss of subsidiaries (44) (515 ) 37
Changes in current operating assets and liabilities:
Accounts receivable from subsidiaries (399 ) (2)
Accounts payable and accrued liabilities 12 1
Accounts payable to subsidiaries 1 2 (6)
Interest accrued to subsidiaries (5) (1) (12)
Taxes accrued (96) 28 (46)
Other current assets and liabilities 35 7 (1)
Net Cash provided by (used in) Operating Activities (380 ) (32) (17)
Cash Flow from Investing Activities
Notes receivable from subsidiaries 317 (478 ) (95)
Acquisition of subsidiary (595 )
Investments in subsidiaries (165 )
Return of capital from investments in subsidiaries 1,111 200 122
Other investments 11 5
Net Cash provided by (used in) Investing Activities 833 (267 ) (133 )
Cash Flow from Financing Activities
Proceeds (repayments) of short-term notes payable from
subsidiaries, net (331 ) 302 150
Non-current debt with subsidiaries (7)
Net Cash provided by (used in) Financing Activities (331 ) 302 143
Net Increase (Decrease) in Cash and Cash Equivalents 122 3 (7 )
Cash and Cash Equivalents, Beginning of Year $ 3 $ 7
Cash and Cash Equivalents, End of Year $ 125 $ 3
Supplemental Cash Flow Information
Cash paid for interest $ 20 $ 25 $ 31
Cash refund for income taxes 6 53
See accompanying notes to Schedule 1
Note 1. Basis of Presentation
AVANGRID, Inc. (AVANGRID), formerly Iberdrola USA, Inc. is a holding company and conducts substantially all of its business through its
subsidiaries. Substantially all of its consolidated assets are held by such subsidiaries. Accordingly, its cash flow and its ability to meet its obligations are
largely dependent upon the earnings of these subsidiaries and the distribution of other payment of such earnings to in the form of dividends, loans or
advances or repayment of loans and advances from it. These condensed financial statements and related footnotes have been prepared in accordance with
regulatory statute 210.12-04 of Regulation S-X. These statements should be read in conjunction with the combined and consolidated financial statements
and notes thereto of AVANGRID, Inc. and subsidiaries (Group).
165
AVANGRID, Inc. indirectly or directly owns all of the ownership interests of its significant subsidiaries. AVANGRID, Inc. relies on dividends or loans from its
subsidiaries to fund dividends to its primary shareholder.
AVANGRID, Inc.’s significant accounting policies are consistent with those of the Group. For the purposes of these condensed financial statements, the
Companys wholly owned and majority owned subsidiaries are recorded based upon its proportionate share of the subsidiaries net assets.
Immaterial corrections to prior periods
During the year ended December 31, 2015, a correction necessary to certain subsidiarys depreciation and amortization expenses that originated in prior
periods was identified. AVANGRID assessed the materiality and determined that the cumulative impact of the amount was not material to the results of
operation, financial position or cash flows in the previously issued financial statements and therefore, amendments of previously filed condensed financial
information of AVANGRID are not required. However, management has determined to revise the prior periods included within these financial statements to
reflect these updated amounts. Accordingly, the correction of these prior period amounts has been reflected in the periods in which they originated and the
statement of operations for the year ended December 31, 2013 and the balance sheet as of December 31, 2014 have been revised. The correction resulted in a
$14 million increase in equity earnings and net income and a $21 million increase in retained earnings and investments in subsidiaries, respectively, in the
statement of operations for the year ended December 31, 2013 and balance sheet as of December 31, 2014. The revision had no net impact on the net cash
provided by operating activities for the year ended December 31, 2013.
Note 2. Acquisition of UIL and Issue of Common Stock
On December 16, 2015 (acquisition date), UIL Holdings Corporation, a Connecticut corporation (UIL), became a wholly-owned subsidiary of AVANGRID as
a result of the merger of Green Merger Sub, Inc., a Connecticut corporation and a wholly-owned subsidiary of AVANGRID (Merger Sub), with UIL, with
Merger Sub surviving as a wholly-owned subsidiary of AVANGRID (the acquisition). The acquisition was effected pursuant to the Agreement and Plan of
Merger, dated as of February 25, 2015, by and among AVANGRID, Merger Sub, and UIL. Following the completion of the acquisition, Merger Sub was
renamed UIL Holdings Corporation. In connection with the acquisition, AVANGRID issued 309,490,839 shares of its common stock, out of which
252,234,989 shares were issued to Iberdrola through a stock dividend, accounted for as a stock split, with no change to par value, at par value of $0.01 per
share and 57,255,850 shares (including held in trust as Treasury Stock) were issued to UIL shareowners in addition to payment of $10.50 in cash per each
share of the common stock of UIL issued and outstanding at the acquisition date. Following the completion of the acquisition, former UIL shareowners
owned 18.5% of the outstanding shares of common stock of AVANGRID and Iberdrola owned the remaining shares.
On February 17, 2016, Board of Directors of AVANGRID declared a quarterly dividend of $0.432 per share on its common stock. This dividend is payable
April 1, 2016 to shareholders of record at the close of business on March 10, 2016.
Note 3. Short-Term Credit Arrangements
AVANGRID Revolving Credit Facility
In May 2012, AVANGRID entered into a $300 million revolving credit facility for the purpose of providing for liquidity needs and those of the unregulated
subsidiaries. The facility has a termination date in May 2019. We pay an annual facility fee of $0.7 million. As of December 31, 2015 and December 31, 2014
the facility was undrawn.
AVANGRID’s revolving credit facility contains a covenant that requires it to maintain a ratio of consolidated indebtedness to consolidated total
capitalization that does not exceed 0.65 to 1.00 at any time. For purposes of calculating this maximum ratio of consolidated indebtedness to consolidated
total capitalization, the credit facility excludes from consolidated net worth the balance of AOCI as it appears in the consolidated balance sheets.
Iberdrola Financiacn, S.A. Credit Facility
In August 2011, AVANGRID entered into a revolving credit facility with Iberdrola Financiacn, S.A., a subsidiary of Iberdrola, under which AVANGRID
may borrow up to $600 million. The facility was terminated by AVANGRID on October 28, 2015. The facility was never utilized.
166
Note 4. Cash dividends paid by subsidiaries
Cash dividends paid by subsidiaries are as follows:
Years ended December 31, 2015 2014 2013
(In millions)
AVANGRID Networks $ 59 $ 200 $ 110
AVANGRID Renewables 750
Other AVANGRID subsidiaries 302 12
$ 1,111 $ 200 $ 122
During 2015, Renewables authorized dividend payments of $1.4 billion to AVANGRID, of which $950 million was in cash ($750 million paid in 2015) and
the remainder in financial instruments. On February 4, 2016, AVANGRID subsidiary, CMP, declared a dividend of $100 million payable to AVANGRID.
167
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our Chief Executive Officer, or CEO, and our Chief Financial Officer, CFO, has evaluated the effectiveness
of our disclosure controls and procedures (as defined in Rules 13a- 15(e) and 15d- 15(e) under the Securities Exchange Act of 1934, as amended, or the
Exchange Act), as of the end of the period covered by this Annual Report on Form 10-K. Based on such evaluation, our CEO and CFO have concluded that as
of such date, our disclosure controls and procedures were effective.
Exemption from Management’s Report on Internal Control over Financial Reporting for the Fiscal Year Ended December 31, 2015
This Annual Report on Form 10-K does not include a report of management’s assessment regarding internal control over financial reporting or an
attestation report of our independent registered public accounting firm due to a transition period established by the rules of the SEC for newly public
companies.
Changes in Internal Control
There were no changes in our internal control over financial reporting identified in managements evaluation pursuant to Rules 13a-15(d) or 15d-
15(d) of the Exchange Act during the period covered by this Annual Report on Form 10-K that materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting.
Limitations on Effectiveness of Controls and Procedures
In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well
designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and
procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible
controls and procedures relative to their costs.
Item 9B. Other Information.
On December 17, 2015, Mr. Daniel Alcain was appointed Senior Vice President and Controller of AVANGRID. There is no family relationship
between Mr. Alcain and any director, executive officer or person nominated to be become a director or executive officer of AVANGRID and there is no
arrangement or understanding between him and any other person pursuant to which he was appointed. For additional biographical information of Mr. Alcain,
see Part I of this Annual Report on Form 10-K.
Mr. Alcain is entitled to participate in AVANGRID’s Annual Incentive Plan and other incentive plans approved for AVANGRID executive officers.
168
PART III
Item 10. Directors, Executive Officers and Corporate Governance.
For information regarding our executive officers, see Part I of this Annual Report on Form 10-K. Additional information required by this item is
incorporated by reference to our Proxy Statement for the 2016 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year
ended December 31, 2015.
Item 11. Executive Compensation.
The information required by this item is incorporated by reference to our Proxy Statement for the 2016 Annual Meeting of Stockholders to be filed
with the SEC within 120 days of the fiscal year ended December 31, 2015.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by this item is incorporated by reference to our Proxy Statement for the 2016 Annual Meeting of Stockholders to be filed
with the SEC within 120 days of the fiscal year ended December 31, 2015.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required by this item is incorporated by reference to our Proxy Statement for the 2016 Annual Meeting of Shareholders to be filed
with the SEC within 120 days of the fiscal year ended December 31, 2015.
Item 14. Principal Accounting Fees and Services.
The information required by this item is incorporated by reference to our Proxy Statement for the 2016 Annual Meeting of Shareholders to be filed
with the SEC within 120 days of the fiscal year ended December 31, 2015.
169
Part IV
Item 15. Exhibits and Financial Statement Schedules.
a) The following documents are made a part of this Annual Report on Form 10-K:
1. Financial Statements—Our consolidated financial statements are set forth under Part II, Item 8 “Financial Statements and Supplementary Data.”
2. Financial Statement Schedules— Our financial statement schedules are set forth under Part II, Item 8 “Financial Statements and Supplementary
Data.”
3. Exhibits—The following instruments and documents are included as exhibits to this report.
170
Exhibit Number Exhibit Description
2.1 Agreement and Plan of Merger, dated as of February 25, 2015, by and among AVANGRID, Inc. (formerly Iberdrola USA, Inc.), Green Merger
Sub, Inc. and UIL Holdings Corporation (incorporated herein by reference to Annex A to the proxy statement/prospectus included as Exhibit
2.1 in our Registration Statement on Form S-4 filed with the Securities and Exchange Commission on July 17, 2015).
3.1 Certificate of Incorporation of AVANGRID, Inc. (incorporated herein by reference to Exhibit 3.2 to Form 8-K filed with the Securities and
Exchange Commission on December 18, 2015).
3.2 Bylaws of AVANGRID, Inc. (incorporated herein by reference to Exhibit 3.4 to Form 8-K filed with the Securities and Exchange Commission
on December 18, 2015).
4.1 Specimen Common Stock Certificate (incorporated herein by reference to Exhibit 4.1 to Form S-4/A filed with the Securities and Exchange
Commission on October 21, 2015).
4.2 Senior Indenture, dated as of October 7, 2010, between UIL Holdings Corporation and The Bank of New York Mellon, as trustee
(incorporated herein by reference to Exhibit 4.1 of UIL Holdings Corporations Current Report on Form 8-K filed with the Securities and
Exchange Commission on October 7, 2010).
4.3
First Supplemental Indenture, dated as of October 7, 2010, between UIL Holdings Corporation and The Bank of New York Mellon, as trustee
(incorporated herein by reference to Exhibit 4.2 of UIL Holdings Corporations Current Report on Form 8-K filed with the Securities and
Exchange Commission on October 7, 2010).
4.4 Second Supplemental Indenture, dated as of December 16, 2015, among UIL Holdings Corporation, Green Merger Sub, Inc. and The Bank of
New York Mellon, as trustee (incorporated herein by reference to Exhibit 4.2 to Form 8-K filed with the Securities and Exchange Commission
on December 18, 2015).
10.1 Shareholder Agreement, dated as of December 16, 2015, by and between AVANGRID, Inc. and Iberdrola, S.A. (incorporated herein by
reference to Exhibit 4.1 to Form 8-K filed with the Securities and Exchange Commission on December 18, 2015).
10.2 Service Agreement, dated January 1, 2014, between Iberdrola USA, Inc. Management Corporation and AVANGRID, Inc. (formerly Iberdrola
USA, Inc.) (incorporated herein by reference to Exhibit 10.2 to Form S-4 filed with the Securities and Exchange Commission on July 17,
2015).
10.3 Lease, dated as of July 7, 2003, between October Corporation and Energy East Management Corporation (incorporated herein by reference to
Exhibit 10.3 to Form S-4 filed with the Securities and Exchange Commission on July 17, 2015).
10.4 First Amendment to Lease, effective as of July 10, 2012, between October Corporation and Iberdrola USA, Inc. Management Corporation
(incorporated herein by reference to Exhibit 10.4 to Form S-4 filed with the Securities and Exchange Commission on July 17, 2015).
10.5 Second Amended and Restated Five-Year Revolving Credit Agreement, dated as of May 30, 2012, among AVANGRID, Inc. (formerly
Iberdrola USA, Inc.), as Borrower, The Several Lenders from Time to Time Parties Hereto, Citibank N.A., as Administrative Agent, and
Sovereign Bank, N.A. and TD Bank N.A., as Syndication Agents (incorporated herein by reference to Exhibit 10.5 to Form S-4 filed with the
Securities and Exchange Commission on July 17, 2015).
10.6 First Amendment to the Second Amended and Restated Five-Year Revolving Credit Agreement, dated as of May 7, 2013, among
AVANGRID, Inc. (formerly Iberdrola USA, Inc.), Citibank N.A. and the other parties named therein (incorporated herein by reference to
Exhibit 10.6 to Form S-4 filed with the Securities and Exchange Commission on July 17, 2015).
10.7 Second Amendment to the Second Amended and Restated Five-Year Revolving Credit Agreement, dated as of November 25, 2013, among
AVANGRID, Inc. (formerly Iberdrola USA, Inc.), Citibank, N.A., and other parties named therein (incorporated herein by reference to Exhibit
10.7 to Form S-4 filed with the Securities and Exchange Commission on July 17, 2015).
10.8 Third Amendment to the Second Amended and Restated Five-Year Revolving Credit Agreement, dated as of April 1, 2015, among
AVANGRID, Inc. (formerly Iberdrola USA, Inc.), Citibank, N.A. and the other parties named therein (incorporated herein by reference to
Exhibit 10.8 to Form S-4 filed with the Securities and Exchange Commission on July 17, 2015).
171
Exhibit Number Exhibit Description
10.9 Five-Year Revolving Credit Agreement, dated July 15, 2011, among New York State Electric & Gas Corporation, Central Maine Power
Company and Rochester Gas and Electric as Borrowers, the Lenders, JPMorgan Chase Bank N.A., as Administrative Agent, Bank of America,
N.A., as Syndication Agent, Banco Bilbao Vizcaya Argentaria S.A., New York Branch, Sovereign Bank, TD Bank, N.A., The Bank of New
York Mellon, and Union Bank, N.A. as Co-Documentation Agents, and J.P. Morgan Securities LLC, and Merrill Lynch, Pierce, Fenner &
Smith Incorporated as Joint Lead Arrangers and Joint Bookrunners (incorporated herein by reference to Exhibit 10.9 to Form S-4 filed with
the Securities and Exchange Commission on July 17, 2015).
10.10 Amendment to Revolving Credit Agreement, dated July 28, 2011, among New York State Electric & Gas Corporation, Rochester Gas &
Electric Corporation, Central Maine Power Company, the Lenders and JPMorgan Chase Bank, N.A. as Administrative Agent (incorporated
herein by reference to Exhibit 10.10 to Form S-4 filed with the Securities and Exchange Commission on July 17, 2015).
10.11 First Amendment and Extension Agreement, dated July 18, 2013, among New York State Electric & Gas Corporation, Rochester Gas and
Electric Corporation, Central Maine Power Company, the Lenders, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America,
N.A., as Syndication Agent, and Banco Bilbao Vizcaya Argentaria S.A., New York Branch, Sovereign Bank (Santander Group), TD Bank,
N.A., The Bank of New York Mellon and Union Bank, N.A., as Co-Documentation Agents (incorporated herein by reference to Exhibit 10.11
to Form S-4 filed with the Securities and Exchange Commission on July 17, 2015).
10.12 Second Amendment and Extension Agreement, dated July 15, 2014, among New York State Electric & Gas Corporation, Rochester Gas and
Electric Corporation, Central Maine Power Company, the Lenders, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of New York
America, N.A., as Syndication Agent, and Banco Bilbao Vizcaya Argentaria S.A., New York Branch, Santander Bank (formerly Sovereign
Bank, N.A.), TD Bank, N.A., The Bank of New York Mellon and Union Bank, N.A., as Co-Documentation Agents (incorporated herein by
reference to Exhibit 10.12 to Form S-4 filed with the Securities and Exchange Commission on July 17, 2015).
10.13 Accession Agreement, dated September 16, 2011, between Iberdrola Renewables Holdings, Inc. and Bank Mendes Gans N.V. (incorporated
herein by reference to Exhibit 10.14 to Form S-4 filed with the Securities and Exchange Commission on July 17, 2015).
10.14 Guarantee and Support Agreement, dated April 3, 2008, between Iberdrola, S.A. and ScottishPower Holdings, Inc. (incorporated herein by
reference to Exhibit 10.15 to Form S-4 filed with the Securities and Exchange Commission on July 17, 2015).
10.15 Amendment No. 1 to Guarantee and Support Agreement, dated May 27, 2010, between Iberdrola, S.A. and Iberdrola Renewables Holdings,
Inc. (formerly known as ScottishPower Holdings, Inc.) (incorporated herein by reference to Exhibit 10.16 to Form S-4 filed with the Securities
and Exchange Commission on July 17, 2015).
10.16 English Translation of Director Remuneration Policy of Iberdrola, S.A., as adopted by AVANGRID, Inc. (incorporated herein by reference to
Exhibit 10.17 to Form S-4/A filed with the Securities and Exchange Commission on September 9, 2015).
10.17 English Translation of Senior Officer Remuneration Policy of Iberdrola, S.A., as adopted by AVANGRID, Inc. (incorporated herein by
reference to Exhibit 10.18 to Form S-4/A filed with the Securities and Exchange Commission on September 9, 2015).
10.18 English Translation of Regulations for the2014-2016 Strategic Bonus” for Senior Officers and Officers of Iberdrola, S.A. and Its Group of
Companies (incorporated herein by reference to Exhibit 10.19 to Form S-4/A filed with the Securities and Exchange Commission on
September 9, 2015).
10.19 Provisions to be Applied to U.S. Participants in Relation to the Regulations for the 2014-2016 Strategic Bonus” for Senior Officers and
Officers of Iberdrola, S.A. and Its Group of Companies (incorporated herein by reference to Exhibit 10.20 to Form S-4/A filed with the
Securities and Exchange Commission on September 9, 2015).
10.20 Iberdrola USA Networks, Inc. Annual Incentive Plan, amended and restated January 1, 2014 (incorporated herein by reference to Exhibit
10.21 to Form S-4/A filed with the Securities and Exchange Commission on September 9, 2015).†
10.21 Iberdrola USA, Inc. Performance Share Plan effective as of January 1, 2009 (incorporated herein by reference to Exhibit 10.22 to Form S-4/A
filed with the Securities and Exchange Commission on September 9, 2015).
172
Exhibit Number Exhibit Description
10.22 Employment Agreement dated October 1, 2010 among Robert Daniel Kump, Iberdrola USA Networks, Inc. (formerly Iberdrola USA, Inc.) and
Iberdrola USA Management Corporation (incorporated herein by reference to Exhibit 10.23 to Form S-4/A filed with the Securities and
Exchange Commission on September 9, 2015).
10.23 Service Contract dated January 16, 2014 between Robert Daniel Kump and AVANGRID, Inc. (incorporated herein by reference to Exhibit
10.24 to Form S-4/A filed with the Securities and Exchange Commission on September 9, 2015).
10.24 Offer letter dated June 16, 2014 between Pablo Canales Abaitua and Iberdrola USA Management Corporation (incorporated herein by
reference to Exhibit 10.25 to Form S-4/A filed with the Securities and Exchange Commission on September 9, 2015).
10.25 Employment Agreement dated March 1, 2008 between R. Scott Mahoney and Iberdrola USA Management Corporation (formerly Energy East
Management Corporation) (incorporated herein by reference to Exhibit 10.27 to Form S-4/A filed with the Securities and Exchange
Commission on September 9, 2015).
10.26 Framework Agreement for the Provision of Corporate Services for Iberdrola and the Companies of its Group, and the Declaration of
Acceptance, dated July 16, 2015 (incorporated herein by reference to Exhibit 10.28 to Form S-4 filed with the Securities and Exchange
Commission on July 17, 2015).
10.27 Equipment Supply Agreement dated December 28, 2014 between Iberdrola Renewables, LLC and Gamesa Wind US, LLC (incorporated
herein by reference to Exhibit 10.29 to Form S-4/A filed with the Securities and Exchange Commission on November 6, 2015).
10.28 Agreement and Release dated September 25, 2009 between Robert Daniel Kump and Iberdrola USA Management Corporation (formerly
Energy East Management Corporation) (incorporated herein by reference to Exhibit 10.31 to Form S-4/A filed with the Securities and
Exchange Commission on September 9, 2015).
10.29 Form of Indemnification Agreement between AVANGRID, Inc. (formerly Iberdrola USA, Inc.) and its directors and officers (incorporated
herein by reference to Exhibit 10.32 to Form S-4/A filed with the Securities and Exchange Commission on October 21, 2015).
10.30 UIL Holdings Corporation 2008 Stock and Incentive Compensation Plan as Amended and Restated May 14, 2013 (incorporated herein by
reference to Exhibit 99.1 to Form S-8 filed with the Securities and Exchange Commission on December 16, 2015).
10.31 UIL Holdings Corporation Deferred Compensation Plan Grandfathered Benefits Provisions, dated August 4, 2008 (incorporated herein by
reference to Exhibit 99.2 to Form S-8 filed with the Securities and Exchange Commission on December 16, 2015).
10.32 UIL Holdings Corporation Deferred Compensation Plan Non-Grandfathered Benefits Provisions, as amended and restated effective dated
January 1, 2013 (incorporated herein by reference to Exhibit 99.3 to Form S-8 filed with the Securities and Exchange Commission on
December 16, 2015).
10.33 Assumption Agreement to $400,000,000 Amended and Restated Credit Agreement, dated as of December 15, 2015, by and between Green
Merger Sub, Inc. and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to Exhibit 99.1 to Form 8-K
filed with the Securities and Exchange Commission on December 18, 2015).
10.34 Employment Agreement, dated as of January 23, 2006, between UIL Holdings Corporation and James P. Torgerson (incorporated herein by
reference to Exhibit 10.1 of UIL Holdings Corporations Current Report on Form 8-K filed with the Securities and Exchange Commission on
January 11, 2006).
10.35 First Amendment, dated August 4, 2008, to Employment Agreement, between UIL Holdings Corporation and James P. Torgerson
(incorporated herein by reference to Exhibit 10.26a of UIL Holdings Corporations Quarterly Report on Form 10-Q for the quarter ended June
30, 2008).
10.36 Employment Agreement, dated as of July 8, 2005, between The United Illuminating Company and Richard J. Nicholas (incorporated herein
by reference to Exhibit 10.4 of UIL Holdings Corporations Current Report on Form 8-K filed with the Securities and Exchange Commission
on July 11, 2005).
10.37 First Amendment, dated August 4, 2008, to Employment Agreement, dated as of July 8, 2005, between The United Illuminating Company
and Richard J. Nicholas (incorporated herein by reference to Exhibit 10.14a of UIL Holdings Corporations Quarterly Report on Form 10-Q
for the quarter ended June 30, 2008).
173
Exhibit Number Exhibit Description
10.38 Amended and Restated UIL Holdings Corporation Change In Control Severance Plan II, dated August 4, 2008 (incorporated herein by
reference to Exhibit 10.28a of UIL Holdings Corporations Quarterly Report on Form 10-Q for the quarter ended June 30, 2008).
21.1 Significant subsidiaries of the Registrant.*
23.1 Consent of Ernst & Young, LLP, independent registered public accounting firm of AVANGRID, Inc.*
23.2 Consent of PricewaterhouseCoopers, LLP, independent accountants of UIL Holdings Corporation.*
31.1 Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.*
31.2 Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.*
32.1 Chief Executive Officer and Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.*
101.INS XBRL Instance Document.*
101.SCH XBRL Taxonomy Extension Schema Document.*
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document.*
101.DEF XBRL Taxonomy Extension Definition Linkbase Document.*
101.LAB XBRL Taxonomy Extension Label Linkbase Document.*
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document.*
* Filed herewith.
Compensatory plan or agreement.
0 Confidential treatment has been requested for portions of this document. The omitted portions of this document have been submitted separately to the
Securities and Exchange Commission.
The foregoing list of exhibits does not include instruments defining the rights of the holders of certain long-term debt of AVANGRID, Inc. and its
subsidiaries where the total amount of securities authorized to be issued under the instrument does not exceed ten percent (10%) of the total assets of
AVANGRID, Inc. and its subsidiaries on a consolidated basis; and AVANGRID, Inc. hereby agrees to furnish a copy of each such instrument to the SEC on
request.
174
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
AVANGRID, Inc.
Date: April 1, 2016 By: /s/ James P. Torgerson
James P. Torgerson
Director and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
/s/ James P. Torgerson
Director and Chief Executive Officer
(Principal Executive Officer)
April 1, 2016
James P. Torgerson
/s/ Richard J. Nicholas
Chief Financial Officer
(Principal Financial Officer)
April 1, 2016
Richard J. Nicholas
/s/ Daniel Alcain
Controller
(Principal Accounting Officer)
April 1, 2016
Daniel Alcain
/s/ Ignacio Sánchez Galán Chairman of the Board April 1, 2016
Ignacio Sánchez Galán
/s/ John E. Baldacci Director April 1, 2016
John E. Baldacci
/s/ Pedro Azagra Blázquez Director April 1, 2016
Pedro Azagra Blázquez
/s/ Arnold L. Chase Director April 1, 2016
Arnold L. Chase
/s/ Alfredo Elías Ayub Director April 1, 2016
Alfredo Elías Ayub
/s/ Carol Lynn Folt Director April 1, 2016
Carol Lynn Folt
/s/ John L. Lahey Director April 1, 2016
John L. Lahey
/s/ Santiago Martinez Garrido Director April 1, 2016
Santiago Martinez Garrido
/s/ Juan Carlos Rebollo Liceaga Director April 1, 2016
Juan Carlos Rebollo Liceaga
/s/ José Sainz Armada Director April 1, 2016
José Sainz Armada
/s/ Alan D. Solomont Director April 1, 2016
Alan D. Solomont
175
EXHIBIT 21.1
LIST OF SUBSIDIARIES OF AVANGRID, INC.
Name of Subsidiary State or Jurisdiction of Incorporation Or Organization
Avangrid Networks, Inc.
(1)*
Maine
New York State Electric and Gas Corporation
(2)
New York
Rochester Gas and Electric Corporation
(2)
New York
Central Maine Power Company
(2)
Maine
Maine Natural Gas Corporation
(2)
Maine
UIL Holdings Corporation.
(1)
Connecticut
The United Illuminating Company
(5)
Connecticut
The Southern Connecticut Gas Company
(5)
Connecticut
Connecticut Natural Gas Corporation
(5)
Connecticut
The Berkshire Gas Company
(5)
Massachusetts
United Resources, Inc.
(5)
Connecticut
Avangrid Renewables Holdings, Inc.
(1)*
Delaware
Avangrid Renewables, LLC
(3)
Oregon
Enstor Gas, LLC
(3)*
Delaware
Enstor Energy Services, LLC
(4)
Delaware
Enstor, Inc.
(4)
Oregon
Avangrid Service Company
(2)
Delaware
(1) Subsidiary of AVANGRID, Inc.
(2) Subsidiary of Avangrid Networks, Inc.
(3) Subsidiary of Avangrid Renewables Holdings, Inc.
(4) Subsidiary of Enstor Gas, LLC
(5) Subsidiary of UIL Holdings Corporation
* Holding Company
EXHIBIT 23.1
Consent of Independent Registered Public Accounting Firm
We consent to the incorporation by reference in the Registration Statement (Form S-8 No. 333-208571) pertaining to Avangrid, Inc.’s common stock to be
available for issuance under the UIL Holdings Corporation 2008 Stock and Incentive Compensation Plan and the UIL Holdings Corporation Deferred
Compensation Plan of our report dated April 1, 2016, with respect to the consolidated financial statements and schedule of Avangrid, Inc. included in this
Annual Report (Form 10-K) for the year ended December 31, 2015.
/s/ Ernst & Young LLP
New York, New York
April 1, 2016
EXHIBIT 23.2
Consent of Independent Accountants
We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (333-208571) of Avangrid, Inc. of our report dated April 1,
2016 relating to the consolidated balance sheet of UIL Holdings Corporation, which appears in this Form 10-K.
/s/ PricewaterhouseCoopers LLP
Boston, MA
April 1, 2016
EXHIBIT 31.1
CERTIFICATION
I, James P. Torgerson, certify that:
1. I have reviewed this annual report on Form 10K of Avangrid, Inc.;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrants other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a15(e) and 15d15(e)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision,
to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most
recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to
materially affect, the registrants internal control over financial reporting; and
5. The registrants other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrants auditors and the audit committee of the registrants board of directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal
control over financial reporting.
Date: April 1, 2016 /s/ James P. Torgerson
James P. Torgerson
Director and Chief Executive Officer
EXHIBIT 31.2
CERTIFICATION
I, Richard J. Nicholas, certify that:
1. I have reviewed this annual report on Form 10K of Avangrid, Inc.;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrants other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a15(e) and 15d15(e)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision,
to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most
recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to
materially affect, the registrants internal control over financial reporting; and
5. The registrants other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrants auditors and the audit committee of the registrants board of directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal
control over financial reporting.
Date: April 1, 2016
/s/ Richard J. Nicholas
Richard J. Nicholas
Chief Financial Officer
EXHIBIT 32.1
CERTIFICATION OF PERIODIC FINANCIAL REPORT
Pursuant to 18 U.S.C. 1350, the undersigned, James P. Torgerson and Richard J. Nicholas, the Chief Executive Officer and Chief Financial Officer,
respectively, of Avangrid, Inc. (the “issuer”), do each hereby certify that the report on Form 10K to which this certification is attached as an exhibit (the
“report”) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)) and that
information contained in the report fairly presents, in all material respects, the financial condition and results of operations of the issuer.
/s/ James P. Torgerson
James P. Torgerson
Director and Chief Executive Officer
Avangrid, Inc.
April 1, 2016
/s/ Richard J. Nicholas
Richard J. Nicholas
Chief Financial Officer
Avangrid, Inc.
April 1, 2016