UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

FORM 10-Q

 

For the quarterly period ended September 30, 2017

Or

For the transition period from                   to                  

Commission File No. 001-37660

 

Avangrid, Inc.

(Exact Name of Registrant as Specified in its Charter)

 

 

 

Registrant’s telephone number, including area code: (207) 629-1200

 

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  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.  

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  ☐    No  ☒

As of November 1, 2017, the registrant had 309,005,272 shares of common stock, par value $0.01, outstanding.

 

 

 

 

 

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Avangrid, Inc.

REPORT ON FORM 10-Q

For the Quarter Ended September 30, 2017

INDEX

 

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GLOSSARY OF TERMS AND ABBREVIATIONS

Unless the context indicates otherwise, the terms “we,” “our” and the “Company” are used to refer to Avangrid, Inc. and its subsidiaries.

Consent order refers to the partial consent order issued by the Connecticut Department of Energy and Environmental Protection in August 2016.

English Station site refers to the former generation site on the Mill River in New Haven, Connecticut.

Form 10-K refers to Avangrid, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2016, filed with the Securities and Exchange Commission on March 10, 2017.

Ginna refers to the Ginna Nuclear Power Plant, LLC and the R.E. Ginna Nuclear Power Plant.

Iberdrola Group refers to the group of companies controlled by Iberdrola, S.A.

Iberdrola refers to Iberdrola, S.A., which owns 81.5% of the outstanding shares of common stock 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.

Joint Proposal refers to the Joint Proposal, filed with the NYPSC on February 19, 2016 by NYSEG, RG&E and certain other signatory parties for a three-year rate plan for electric and gas service at NYSEG and RG&E commencing May 1, 2016.

Klamath Plant refers to the Klamath gas-fired cogeneration facility located in the city of Klamath, Oregon.

Non-GAAP refers to the financial measures that are not prepared in accordance with U.S. GAAP, including adjusted gross margin, adjusted EBITDA, adjusted net income and adjusted earnings per share.

Yankee Companies refers to the Maine Yankee Atomic Power Company, the Connecticut Yankee Power Corporation, and the Yankee Atomic Energy Corporation.

 

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Income

(unaudited)

 

 

The accompanying notes are an integral part of our condensed consolidated financial statements.

 

 

 

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Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income

(unaudited)

 

 

The accompanying notes are an integral part of our condensed consolidated financial statements.

 

 

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Avangrid, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

 

 

The accompanying notes are an integral part of our condensed consolidated financial statements.

 

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Avangrid, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

 

 

The accompanying notes are an integral part of our condensed consolidated financial statements.

 

 

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Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(unaudited)

 

 

The accompanying notes are an integral part of our condensed consolidated financial statements.

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Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Changes in Equity

(unaudited)

 

 

The accompanying notes are an integral part of our condensed consolidated financial statements.

 

 

 

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Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

 

 

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 in the regulated energy distribution business through its principal subsidiary Avangrid Networks, Inc. (Networks) and in the renewable energy generation and gas storage and trading businesses through its principal subsidiary, Avangrid Renewables Holding, Inc. (ARHI). ARHI in turn holds subsidiaries including Avangrid Renewables, LLC (Renewables) and Enstor Gas, LLC (Gas). Iberdrola, S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain, owns 81.5% the outstanding common stock of AVANGRID. The remaining outstanding shares are publicly traded on the New York Stock Exchange and owned by various shareholders. AVANGRID was originally organized in 1997 as NGE Resources, Inc. under the laws of New York as the holding company for the principal operating utility companies.

Note 2. Basis of Presentation

The accompanying notes should be read in conjunction with the notes to the consolidated financial statements of Avangrid, Inc. and subsidiaries as of December 31, 2016 and 2015 and for the three years ended December 31, 2016 included in AVANGRID’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

The accompanying unaudited financial statements are prepared on a consolidated basis and include the accounts of AVANGRID and its consolidated subsidiaries Networks and ARHI. Intercompany accounts and transactions have been eliminated in consolidation. The year-end balance sheet data was derived from audited financial statements. The unaudited condensed consolidated financial statements for the interim periods have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, the interim condensed consolidated financial statements do not include all the information and note disclosures required by U.S. GAAP for complete financial statements.

We believe the disclosures made are adequate to make the information presented not misleading. In the opinion of management, the accompanying condensed consolidated financial statements contain all adjustments necessary to present fairly our condensed consolidated balance sheets, condensed consolidated statements of income, comprehensive income, cash flows and changes in equity for the interim periods described herein. All such adjustments are of a normal and recurring nature, except as otherwise disclosed. The results for the three and nine months ended September 30, 2017, are not necessarily indicative of the results for the entire fiscal year ending December 31, 2017.

Certain amounts have been reclassified in the condensed consolidated statements of cash flows for the prior period to conform to the presentation for the nine months ended September 30, 2017 as well as in connection with retrospective adoption of amendments in the accounting standard related to presentation of restricted cash in the statement of cash flow.

 

Note 3. Significant Accounting Policies and New Accounting Pronouncements

As of September 30, 2017, there have been no material changes to any significant accounting policies described in our consolidated financial statements as of December 31, 2016 and 2015, and for the three years ended December 31, 2016, other than with respect to our early adoption of the amendments relating to the definition of a business described below. The following are new accounting pronouncements issued since December 31, 2016, except for an update on the accounting standard “Revenue from contracts with customers”, that we have evaluated or are evaluating to determine their effect on our consolidated financial statements.

(a) Clarifying the definition of a business

The Financial Accounting Standards Board (FASB) issued amendments in January 2017 to clarify the definition of a business. The revised definition of a business sets out a new framework for a company to apply in classifying transactions as acquisitions (or disposals) of assets versus businesses. According to the revised definition, an integrated set of activities and assets is a business if it has, at a minimum, an input and a substantive process that together significantly contribute to the ability to create outputs. The definition of outputs is narrowed and aligned with how outputs are described in Accounting Standards Codification (ASC), Topic 606, Revenue from Contracts with Customers (ASC 606). The amendments create a two-step method for assessing whether a transaction is an acquisition (disposal) of assets or a business. A set of activities would not be a business when substantially all of the fair value of the gross assets acquired (disposed) is concentrated in a single identifiable asset or group of similar identifiable assets. Fewer transactions are expected to involve acquiring or selling a business as a result of the amendments.

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The amendments are effective for public entities for annual and interim periods in fiscal years beginning after December 15, 2017, with early adoption permitted. We early adopted the amendments in the third quarter of 2017 and, as required, are applying the amendments prospectively as of the beginning of the period of adoption. Other than with respect to the transaction described below, our adoption of the amendments did not affect our results of operations, financial position, cash flows, and disclosures.

In September 2017, we acquired all of the membership interest in Solar Star Oregon II, that is constructing a 56MW solar project in Prineville, Oregon called Gala (Gala transaction), which had a power purchase agreement (PPA) in place. Total purchase price for Gala transaction is $121 million, $106 million of which has been paid at the date of acquisition, and the remaining will be paid upon a substantial completion of the construction of the Gala solar farm. According to the revised guidance on assessing whether a transaction is an acquisition of assets or a business we performed a screening test to determine whether substantially all of the fair value of the gross assets acquired is concentrated in a single asset (in-place lease intangibles and related leased assets) or group of similar assets in the Gala transaction. The Gala solar farm meets the screening test, being a single asset, and constitutes substantially all of the value of the consideration paid to the seller and therefore the Gala transaction is considered an asset acquisition. Additionally, at the acquisition date the Gala project, being at its development stage, would require a workforce that is capable to develop or convert inputs into outputs. As scheduling and balancing services, which will be performed by our workforce, are the primary functions required to convert the solar output into revenues under the PPA, the Gala transaction is not an acquisition of a business. Based on the fair value of assets acquired the purchase price in the Gala transaction was mainly allocated to the Gala solar farm in construction of approximately $124 million. The liability recognized for contingent consideration payable is $13 million, which is based on an amount that is probable and estimable, as of the acquisition date, September 20, 2017.  

(b) Clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets  

The FASB issued amendments in February 2017 concerning asset derecognition and partial sales of nonfinancial assets. The amendments clarify the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets, and also define in-substance nonfinancial assets. Those amendments apply to a company that: sells nonfinancial assets (land, buildings, materials and supplies, intangible assets) to noncustomers; sells nonfinancial assets and financial assets (cash, receivables) when the value is concentrated in the nonfinancial assets; or sells partial ownership interests in nonfinancial assets. The amendments do not apply to sales to customers or to sales of businesses. The new guidance in ASC 610-20 on accounting for derecognition of a nonfinancial asset and an in-substance nonfinancial asset applies only when the asset (or asset group) does not meet the definition of a business and is not a not-for-profit activity.

The amendments are effective for public entities for annual and interim periods in fiscal years beginning after December 15, 2017, with early adoption permitted. We do not plan to early adopt. An entity must apply the amendments at the same time that it applies the new ASC 606 revenue recognition standard and may elect to apply the amendments retrospectively following either a full retrospective approach or a modified retrospective approach, but does not have to apply the same transition method as for ASC 606. Regardless of which transition method an entity applies to contracts with noncustomers, such as transactions within the scope of ASC 610-20, it must apply the amended definition of a business to those contracts. We expect the amendments will affect our accounting for tax equity investments, which we expect to classify as noncontrolling interests. We are currently evaluating how our adoption of the amendments will affect our results of operations, financial position, cash flows, and disclosures.

(c) Improving the presentation of net periodic benefit costs

In March 2017 the FASB issued amendments to improve the presentation of net periodic pension cost and net periodic postretirement benefit cost in the financial statements. The amendments require an entity to present service cost separately from the other components of net benefit cost, and to report the service cost component in the income statement line item(s) where it reports the corresponding compensation cost. An entity is to present all other components of net benefit cost outside of operating cost. The amendments also allow only the service cost component to be eligible for capitalization when applicable (for example, as a cost of a self-constructed asset). The amendments are effective for public entities for annual and interim periods in fiscal years beginning after December 15, 2017, with early adoption permitted. We do not plan to early adopt. An entity is required to apply the amendments retrospectively for the presentation of the service cost component and the other components of net periodic pension cost and net periodic postretirement benefit cost in the income statement and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic pension cost and net periodic postretirement benefit in assets. A practical expedient allows an entity to retrospectively apply the amendments on adoption to net benefit costs for comparative periods by using the amounts disclosed in the notes to financial statements for pension and postretirement benefit plans for those periods. We do not expect our adoption of the amendments will materially affect our results of operations, financial position, cash flows, and disclosures.

(d) Targeted improvements to accounting for hedging activities

In August 2017 the FASB issued targeted amendments with the objective to better align hedge accounting with an entity’s risk management activities in the financial statements, and to simplify the application of hedge accounting. The amendments address concerns of financial statement preparers over difficulties with applying hedge accounting and limitations for hedging both nonfinancial and financial risks and concerns of financial statement users over how hedging activities are reported in financial statements. Changes to the hedge accounting guidance to address those concerns will: 1) expand hedge accounting for nonfinancial

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and financial risk components and amend measurement methodologies to more closely align hedge accounting with an entity’s risk management activities; 2) eliminate the separate measurement and reporting of hedge ineffectiveness, to reduce the complexity of preparing and understanding hedge results; 3) enhance disclosures and change the presentation of hedge results to align the effects of the hedging instrument and the hedged item in order to enhance transparency, comparability, and understandability of hedge results; and 4) simplify the way assessments of hedge effectiveness may be performed to reduce the cost and complexity of applying hedge accounting. The amendments are effective for public entities for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted in any interim period after issuance of the amendments. We do not expect to early adopt. For cash flow and net investment hedges existing at the date of adoption, a company must apply a cumulative-effect adjustment related to the separate measurement of ineffectiveness to accumulated other comprehensive income with a corresponding adjustment to the opening balance of retained earnings as of the beginning of the fiscal year of adoption. The amended presentation and disclosure guidance is required only prospectively. An entity may make certain elections upon adoption to allow for existing hedging relationships to transition to newly allowable alternatives. We expect our adoption of the guidance will not materially affect our results of operations, financial position, or cash flows, but we expect the amendments will ease the administrative burden of hedge documentation requirements and assessing hedge effectiveness.

(e) Revenue from contracts with customers

In May 2014 the FASB issued ASC 606 replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. ASC 606 was further amended through various updates the FASB issued thereafter. 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 new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers. The amended effective date for public entities is for annual reporting periods beginning after December 15, 2017, and interim periods therein, with early adoption as of the original effective date of December 15, 2016 permitted. Entities may apply the standard retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified retrospective method). We will adopt the new standard effective January 1, 2018 and apply the modified retrospective method. Under the new standard, we will recognize revenue from tariff based sales, representing the majority of our revenues, in an amount derived from the commodities delivered, which is equivalent to the amount we have a right to invoice the customer and consistent with our current policies. We continue to evaluate other individual contracts, particularly in our Renewables business, to determine the effects, if any, the new standard will have on our consolidated financial statements. Notably, a number of industry-specific implementation issues were published for public informal comment during the third quarter 2017, including contributions in aid of construction, renewable energy credits, alternative energy programs, and bundled arrangements which are applicable to our business. We will monitor the final resolution of certain of those issues to determine if any changes to our current plan for implementing the new standard are warranted. We are currently finalizing how our adoption of the amendments will affect our results of operations, financial position, and cash flows, if any.

Under the new standard, we plan to disaggregate revenues from contracts with customers in our note disclosure by segment, including Networks, Renewables, and Gas, by regulated and non-regulated operations, and by the source of the commodity sold. We will also disaggregate revenues not accounted for in scope of the new standard, as required.

 

 

Note 4. 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. The primary items that are not included in the 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, which are the offset to the unfunded future deferred income tax liability recorded, asset retirement obligations, hedge losses and contracts for differences. The total net amount of these items is approximately $2,129 million.

The regulatory assets and 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.

On June 15, 2016, the New York State Public Service Commission (NYPSC) approved the Joint Proposal filed with the NYPSC by New York State Electric & Gas Corporation (NYSEG) and Rochester Gas and Electric Corporation (RG&E) and by certain other

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signatory parties on February 19, 2016, in connection with a three-year rate plan for electric and gas service at NYSEG and RG&E effective May 1, 2016. Following the approval of the Joint Proposal most of these items related to NYSEG are amortized over a five-year period, except the portion of storm costs to be recovered over ten years, unfunded deferred taxes being amortized over a period of fifty years and plant related tax items which are amortized over the life of associated plant. Annual amortization expense for NYSEG is approximately $16.5 million per rate year. RG&E items that are being amortized are plant related tax items, which are amortized over the life of associated plant, and unfunded deferred taxes being amortized over a period of fifty years. A majority of the other items related to RG&E, which net to a regulatory liability, remain deferred and will not be amortized until future proceedings.

The approved Joint Proposal provides for annual rate increases and an allowed rate of return on common equity is 9.0% for the NYSEG and RG&E. The equity ratio for each company is 48%; however, the equity ratio is set at 50% for earnings sharing calculation purposes. The customer share of any earnings above allowed levels increases as the return on equity (ROE) increases, with customers receiving 50%, 75% and 90% of earnings over 9.5%, 10.0% and 10.5% ROE, respectively, in the first rate year covering the period May 1, 2016 – April 30, 2017.  The earnings sharing levels increase in rate year two (May 1, 2017 – April 30, 2018) to 9.65%, 10.15% and 10.65% ROE, respectively. The rate plans also include the implementation of a rate adjustment mechanism designed to return or collect certain defined reconciled revenues and costs, new depreciation rates, and continuation of the existing revenue decoupling mechanisms (RDM) for each business.

In December 2016, the Connecticut Public Utilities Regulatory Authority (PURA) approved new distribution rate schedules for The United Illuminating Company (UI) for three years, which became effective January 1, 2017, and which, among other things, provides for annual tariff increases and an ROE of 9.10% based on a 50% equity ratio, continued UI’s existing earnings sharing mechanism (ESM) pursuant to which UI and its 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 continuation of the requested storm reserve. Any dollars due to customers from the ESM continue to be first applied against any storm regulatory asset balance (if one exists at that time) or refunded to customers through a bill credit if such storm regulatory asset balance does not exist.

On June 30, 2017, The Southern Connecticut Gas Company (SCG) filed an application with PURA for new tariffs to become effective January 1, 2018.  SCG is requesting a three-year rate plan for calendar years 2018, 2019 and 2020 and a proposed ROE of 9.95%.  SCG is also requesting to implement a RDM and Distribution Integrity Management Program (DIMP) mechanism similar to the mechanisms authorized for Connecticut Natural Gas Corporation (CNG). On October 16, 2017, SCG, Prosecutorial Staff from PURA, and the Connecticut Office of Consumer Counsel (OCC) filed an amended settlement agreement with PURA for approval, which includes among other items the implementation of an RDM, ESM and the DIMP as proposed by SCG, the amortization of certain regulatory liabilities (most notably accumulated hardship deferral balances and certain accumulated deferred income taxes) and tariff increases based on an ROE of 9.25% and approximately 52% equity level. The parties also agreed on a three-year rate plan with rate increases of $1.5 million, $4.7 million and $5.0 million in 2018, 2019, and 2020, respectively. PURA is reviewing the amended settlement agreement and may approve, modify or reject the agreement. SCG expects a decision on its rate case settlement agreement by the end of December 2017 for new tariffs on January 1, 2018. SCG’s last distribution rates were effective from August 2011 as part of a one year rate plan approved by PURA.

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Current and non-current regulatory assets as of September 30, 2017 and December 31, 2016, respectively, consisted of:

 

 

“Pension and other post-retirement benefits” represent the actuarial losses on the pension and other post-retirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses. “Pension and other post-retirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. The recovery of these amounts will be determined in future proceedings.

“Storm costs” for Central Maine Power (CMP), NYSEG and RG&E 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. Storm costs in the amount of $123 million at NYSEG are being recovered over ten-year period and the remaining portion is being amortized over five years following the approval of the Joint Proposal by the NYPSC. UI is allowed to defer costs associated with any storm totaling $1 million or greater for future recovery. UI’s storm regulatory asset balance was $0 as of September 30, 2017.

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“Deferred meter replacement costs” represent the deferral of the book value of retired meters that were replaced by advanced metering infrastructure meters. This amount is being amortized over the initial depreciation period of related retired meters.

“Unamortized losses on reacquired debt” represent deferred losses on debt reacquisitions that will be recovered over the remaining original amortization period of the reacquired debt.

“Unfunded future income taxes” represent unrecovered federal and state income taxes primarily resulting from regulatory flow through accounting treatment and are the offset to the unfunded future deferred income tax liability recorded. 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. Following the approval of the Joint Proposal by the NYPSC, these amounts will be collected over a fifty-year period, and the NYPSC Staff has initiated an audit, as required, of the unfunded future income taxes and other tax assets to verify the balances.

“Asset retirement obligations” (ARO) represent 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” represents the customer portion of the difference between actual expense for property taxes and the amount provided for in rates. The amount for NYSEG and RG&E is being amortized over a five year period following the approval of the Joint Proposal by the NYPSC.

“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 in New York is from 27 to 39 years and for CMP this will be determined in future Maine Public Utility Commission (MPUC) rate proceedings.

“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.

“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.

“Contracts for Differences” (CfDs) 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.

“Debt premium” represents the regulatory asset recorded to offset the fair value adjustment to the regulatory component of the non-current debt of UIL Holdings Corporation (UIL) at the acquisition date. This amount is being amortized to interest expense over the remaining term of the related outstanding debt instruments.

“Deferred Transmission Expense” represents deferred transmission income or expense and fluctuates based upon actual revenues and revenue requirements.

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Current and non-current regulatory liabilities as of September 30, 2017 and December 31, 2016, respectively, consisted of:

 

 

“Reliability support services (Cayuga)” represents the difference between actual expenses for reliability support services and the amount provided for in rates. The Cayuga reliability support service surcharge applied to NYSEG electric customers concluded in July 2017 with any remaining balance expected to be recovered or returned by the end of 2017.

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“Non by-passable charges” represent the non by-passable 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.

“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 or utilized to recover incentive payments 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 located in Oswego, New York. 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 five years following the approval of the Joint Proposal by the NYPSC.

“Carrying costs on deferred income tax bonus depreciation” represent the carrying costs benefit of increased accumulated deferred income taxes created by the change in tax law allowing bonus depreciation. The amortization period is five years following the approval of the Joint Proposal by the NYPSC.

“Economic development” represents the economic development program which enables NYSEG and RG&E 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 RG&E varies in any rate year from the level provided for in rates, the difference is refunded to ratepayers. The amortization period is five years following the approval of the Joint Proposal by the NYPSC.

“Merger capital expense target customer credit” account was created as a result of NYSEG and RG&E not meeting certain capital expenditure requirements established in the order approving the purchase of AVANGRID (formerly Energy East Corporation) by Iberdrola. The amortization period is five years following the approval of the Joint Proposal by the NYPSC.

“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. They also represent 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 acquisition of AVANGRID (formerly Energy East Corporation). This is being used to moderate increases in rates. The amortization period is five years following the approval of the Joint Proposal by the NYPSC and included in the Ginna RSSA settlement.

“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 five years following the approval of the Joint Proposal by the NYPSC.

“Post term amortization” represents the revenue requirement associated with certain expired joint proposal amortization items. The amortization period is five years following the approval of the Joint Proposal by the NYPSC.

“Theoretical reserve flow thru impact” represents 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 five years following the approval of the Joint Proposal by the NYPSC.

“Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. In the three and nine months ended September 30, 2017, respectively, $0 and $2 million of rate credits was applied against customer bills. In the three and nine months ended September 30, 2016, respectively, $0 and $20 million of rate credits was applied against customer bills

“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. The 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.

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“Other” includes cost of removal being amortized through rates and various items subject to reconciliation including variable rate debt, Medicare subsidy benefits and stray voltage collections.

 

 

Note 5. Fair Value of Financial Instruments and Fair Value Measurements

We determine the fair value of our derivative assets and liabilities and available for sale non-current investments associated with Networks’ activities utilizing market approach valuation techniques:

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 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 carrying amounts for cash and cash equivalents, restricted cash, accounts receivable, accounts payable, notes payable and interest accrued approximate their estimated fair values and are considered as Level 1.

Restricted cash was $7 million and $5 million as of September 30, 2017 and December 31, 2016, respectively, which is included in “Other Assets” on the balance sheet.

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The financial instruments measured at fair value as of September 30, 2017 and December 31, 2016, respectively, consisted of:

 

 

 

The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three and nine months ended September 30, 2017 and 2016, respectively, is as follows:

 

 

(a) Transfers out of Level 3 were the result of increased observability of market data.

For assets and liabilities that are recognized in the condensed 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

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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 periods 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, and the variability in prices for those transactions classified as Level 3 derivatives.

 

 

 

Our Level 3 valuations primarily consist of NYMEX gas and fixed price power swaps with delivery periods extending through 2024 and 2032, respectively. The gas swaps are used to hedge both gas inventory in firm storage and merchant wind positions. The power swaps are used to hedge merchant wind production in the West and Midwest.

We performed a sensitivity analysis around the Level 3 gas and power positions to changes in the valuation inputs. Given the nature of the transactions in Level 3, the only material input to the valuation is the market price of gas or power for transactions with delivery periods exceeding two years. The fixed price power swaps are economic hedges of future power generation, with decreases in power prices resulting in unrealized gains and increases in power prices resulting in unrealized losses. The gas swaps are economic hedges of gas storage inventory and merchant generation, with decreases in gas prices resulting in unrealized gains and increases in gas prices resulting in unrealized losses. As all transactions are economic hedges of the underlying position, any changes in the fair value of these transactions will be offset by changes in the anticipated purchase/sales price of the underlying commodity.

Two elements of the analytical infrastructure employed in valuing transactions are the price curves used in calculation of market value and the models themselves. We maintain and document authorized trading points and associated forward price curves, and we develop and document models used in valuation of the various products.

Transactions are valued in part on the basis of forward price, correlation, and volatility curves. We maintain and document descriptions of these curves and their derivations. Forward price curves used in valuing the transactions are applied to the full duration of the transaction.

The determination of fair value of the CfDs (see Note 6 for further discussion of CfDs) was based on a probability-based expected cash flow analysis that was discounted at 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:

 

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Fair Value of Debt

As of September 30, 2017 and December 31, 2016, debt consisted of first mortgage bonds, fixed and variable unsecured pollution control notes, other various non-current debt securities and obligations under capital leases. The estimated fair value of debt amounted to $5,443 million and $5,204 million as of September 30, 2017 and December 31, 2016, respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rates used to make these calculations take 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 $61 million as of both September 30, 2017 and December 31, 2016, 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.

On May 24, 2017, RG&E issued $300 million in aggregate principal amount of 3.10% First Mortgage Bonds due in 2027.

 

 

Note 6. Derivative Instruments and Hedging

Our Networks, Renewables and Gas activities are exposed to certain risks, which are managed by using derivative instruments. All derivative instruments are recognized as either assets or liabilities at fair value on the condensed consolidated balance sheets in accordance with the accounting requirements concerning derivative instruments and hedging activities.

(a) Networks activities

NYSEG and RG&E each have an electric commodity charge that passes through rates costs for 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 amount recognized in regulatory assets for electricity derivatives was a loss of $18.3 million as of September 30, 2017, and $12.3 million as of December 31, 2016. The amount reclassified from regulatory assets and liabilities into income, which is included in electricity purchased, was a loss of $7.9 million and $29.2 million, and a loss of $3.5 million and $51.4 million for the three and nine months ended September 30, 2017 and 2016, respectively.

NYSEG and RG&E each 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 RG&E 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.

The amount recognized in regulatory assets for natural gas hedges was a loss of $0.9 million as of September 30, 2017, and the amount recognized in regulatory liabilities as of December 31, 2016, was a gain of $3.5 million. The amount reclassified from regulatory assets and liabilities into income, which is included in natural gas purchased, was $0 and a gain of $0.6 million, and $0 and a loss of $3.4 million for the three and nine months ended September 30, 2017 and 2016, respectively.

Pursuant to PURA order, UI and Connecticut’s other electric utility, The Connecticut Light and Power Company (CL&P), each executed two long-term CfDs with certain incremental capacity resources, each of which specifies a capacity quantity and a monthly settlement that reflects the difference between a forward market price and the contract price. 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), including carrying costs. For those CfDs signed by CL&P, UI records its approximate 20% portion pursuant to the cost-sharing agreement noted above. As of September 30, 2017, UI has recorded a gross derivative asset of $14 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $71 million, a gross derivative liability of $85 million ($68 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0. As of December 31, 2016, UI had recorded a gross derivative asset of $19 million

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($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $75 million, a gross derivative liability of $95 million ($70 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0.

The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets or regulatory liabilities, for the three and nine months ended September 30, 2017 and 2016, respectively, were as follows:

 

 

The net notional volumes of the outstanding derivative instruments associated with Networks activities as of September 30, 2017 and December 31, 2016, respectively, consisted of:

 

 

The offsetting of derivatives, location in the condensed consolidated balance sheet and amounts of derivatives associated with Networks activities as of September 30, 2017 and December 31, 2016, respectively, consisted of:

 

 

 

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The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three and nine months ended September 30, 2017 and 2016, respectively, consisted of:

 

 

 

 

(a)Changes in OCI are reported on a pre-tax basis. The reclassified amounts of commodity contracts are included within “Purchase power, natural gas and fuel used” line item within operating expenses in the condensed consolidated statements of income.

The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $70.8 million and $76.7 million as of September 30, 2017 and December 31, 2016, respectively. We recorded $2.0 million and $6.0 million, and $2.0 million and $6.0 million, in net derivative losses related to discontinued cash flow hedges for the three and nine months ended September 30, 2017 and 2016, respectively. We will amortize approximately $8.0 million of discontinued cash flow hedges in 2017. During the three and nine months ended September 30, 2017 and 2016, there was no ineffective portion for cash flow hedges.

The unrealized loss of $0.6 million on hedge activities is reported in OCI because the forecasted transaction is considered to be probable as of September 30, 2017. We expect that $0.6 million of those losses will be reclassified into earnings within the next twelve months. The maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted fleet fuel transactions is twelve months.

(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.

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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.

Renewables will periodically designate derivative contracts as cash flow hedges for both its thermal and wind portfolios. To the extent that the derivative contracts are effective in offsetting the variability of cash flows associated with future power sales and gas purchases, the fair value changes are recorded in OCI. Any hedge ineffectiveness is recorded in current period earnings. For thermal operations, Renewables will periodically designate both fixed price NYMEX gas contracts and natural gas basis swaps that hedge the fuel requirements of its Klamath Plant in Klamath, Oregon. Renewables will also designate fixed price power swaps at various locations in the U.S. market to hedge future power sales from its Klamath facility and various wind farms.

Gas also periodically designates NYMEX fixed price derivative contracts as cash flow hedges related to its firm storage trading activities. To the extent that the derivative contracts are effective in offsetting the variability of cash flows associated with future gas sales and purchases, the fair value changes are recorded in OCI. Any hedge ineffectiveness is recorded in current period earnings. Derivative contracts entered into to hedge the gas transport trading activities are not designated as cash flow hedges, with all changes in fair value of such derivative contracts recorded in current period earnings.

The net notional volumes of outstanding derivative instruments associated with Renewables and Gas activities as of September 30, 2017 and December 31, 2016, respectively, consisted of:

 

 

The fair values of derivative contracts associated with Renewables and Gas activities as of September 30, 2017 and December 31, 2016, respectively, consisted of:

 

 

The effect of trading derivatives associated with Renewables and Gas activities for the three and nine months ended September 30, 2017 and 2016, respectively, consisted of:

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The effect of non-trading derivatives associated with Renewables and Gas activities for the three and nine months ended September 30, 2017 and 2016, respectively, consisted of:

 

 

Such gains and losses are included in “Operating revenues” and in “Purchased power, natural gas and fuel used” operating expenses in the condensed consolidated statements of income, depending upon the nature of the transaction.

The offsetting of derivatives, location in the condensed consolidated balance sheet and amounts of derivatives associated with Renewables and Gas activities as of September 30, 2017 and December 31, 2016, respectively, consisted of:

 

 

 

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The effect of derivatives in cash flow hedging relationships on OCI and income for the three and nine months ended September 30, 2017 and 2016, respectively, consisted of:

 

 

Amounts are reclassified from accumulated OCI into income in the period 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 $8.3 million of gain included in accumulated OCI at September 30, 2017, is expected to be reclassified into earnings within the next twelve months. During the three and nine months ended September 30, 2017 and 2016, we recorded a net gain of $0.5 million and $1.0 million, and a net gain of $0.4 million and net loss $4.4 million, respectively, in earnings as a result of ineffectiveness from cash flow hedges. The net loss in accumulated OCI related to a discontinued cash flow hedge is $0.5 million as of September 30, 2017. This amount will amortize through 2018.

(c) Counterparty credit risk management

NYSEG and RG&E 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 counterparty’s or the counterparty’s 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 UI’s credit rating on senior debt were to fall below investment grade. If such an event had occurred as of September 30, 2017, UI would have had to post an aggregate of approximately $11 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 amounts of cash collateral under master netting arrangements that have not been offset against net derivative positions were $17 million and $20 million as of September 30, 2017 and December 31, 2016, respectively. Derivative instruments settlements and collateral payments are included in “Other assets/liabilities” of operating activities in the condensed 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

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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 September 30, 2017 is $19.4 million, for which we have posted collateral.

 

 

Note 7. Commitments and Contingent Liabilities

We are party to various legal disputes arising as part of our normal business activities. We assess our exposure to these matters and record estimated loss contingencies when a loss is likely and can be reasonably estimated.

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 sought 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 9.2%. CMP and UI are New England Transmission Owners (NETOs) with assets and service rates that are governed by the OATT and therefore are affected by any FERC order resulting from the filed complaint.

On June 19, 2014, the FERC issued its decision in Complaint I, establishing an ROE methodology and setting an issue for a paper hearing.  On October 16, 2014, FERC issued its final decision in Complaint I setting the base ROE at 10.57% and a maximum total ROE of 11.74% (base plus incentive ROEs) for the October 2011 – December 2012 period as well as prospectively from October 16, 2014, and ordered the NETOs to file a refund report. On November 17, 2014, the NETOs filed the requested 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 FERC’s June 19, 2014 decision and further clarified that the 11.74% ROE cap will be applied on a project specific basis and not on a transmission owner’s total average transmission return. In June 2015 the NETOs and complainants both filed an appeal in the U.S. Court of Appeals for the District of Columbia of the FERC’s final order. On April 14, 2017, the Court of Appeals (the Court) vacated FERC’s decision on Complaint I and remanded it back to FERC. The Court held that FERC, as directed by statute, did not determine first that the existing ROE was unjust and unreasonable before determining a new ROE. The Court ruled that FERC should have first determine that the then existing 11.14% base ROE was unjust and unreasonable before selecting the 10.57% as the new base ROE. The Court also found that FERC did not provide reasoned judgment as to why 10.57%, the point ROE at the midpoint of the upper end of the zone of reasonableness, is a just and reasonable ROE. Instead, FERC had only explained in its order that the midpoint of 9.39% was not just and reasonable and a higher base ROE was warranted. On June 5, 2017, the NETOs made a filing with FERC seeking to reinstate transmission rates to the status quo ante (effect of the Court vacating order is to return the parties to the rates in effect prior to FERC Final decision) as of June 8, 2017, the date the Court decision became effective. In that filing, the NETOs stated that they will not begin billing at the higher rates until 60 days after FERC has a quorum of commissioners. On October 6, 2017, FERC issued an order rejecting the NETOs request to collect transmission revenue requirements at the higher ROE of 11.14%, pending FERC order on remand.  In reaching this decision, FERC stated that it has broad remedial authority to make whatever ROE it eventually determines to be just and reasonable effective for the Complaint I refund period and prospectively from October 2014, the effective date of the Complaint I Order. Therefore the NETOs will not be harmed financially by not immediately returning to their pre-Complaint I ROE.  We anticipate FERC to address the Court decision during 2018. We cannot predict the outcome of action by FERC.

On December 26, 2012, a second ROE complaint (Complaint II) for a subsequent rate period was filed requesting the then effective ROE of 11.14% be reduced to 8.7%. On June 19, 2014, FERC accepted Complaint II, established a 15-month refund effective date of December 27, 2012, and set the matter for hearing using the methodology established in Complaint I.

On July 31, 2014, a third ROE complaint (Complaint III) was filed for a subsequent rate period requesting the then effective ROE of 11.14% be reduced to 8.84%. On November 24, 2014, FERC accepted the Complaint III, established a 15-month refund effective date of July 31, 2014, and set this matter consolidated with Complaint II for hearing in June 2015. Hearings relating to the refund periods and going forward period were held in June 2015 on Complaints II and III before a FERC Administrative Law Judge. 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 NETOs 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 FERC 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

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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 2018.

CMP and UI reserved for refunds for Complaints I, II and III consistent with the FERC’s March 3, 2015 final decision in Complaint I. Refunds were provided to customers for Complaint I. The CMP and UI total reserve associated with Complaints II and III is $22.2 million and $4.4 million, respectively, as of September 30, 2017, which has not changed since December 31, 2016, except for the accrual of carrying costs. If adopted as final, the impact of the initial decision would be an additional aggregate reserve for Complaints II and III of $17.1 million, which is based upon currently available information for these proceedings. We cannot predict the outcome of the Complaint II and III proceedings.

On April 29, 2016, a fourth ROE complaint (Complaint IV) was filed for a rate period subsequent to prior complaints requesting the then existing base ROE of 10.57% be reduced to 8.61% and the ROE Cap be set at 11.24%.  The NETOs filed a response to the Complaint IV on June 3, 2016. On September 20, 2016, FERC accepted the Complaint IV, established a 15-month refund effective date of April 29, 2016, and set the matter for hearing and settlement judge procedures. On February 1, 2017, the complainants filed their initial testimony recommending a base ROE of 8.59%. On March 23, 2017, the NETOs filed their answering testimony supporting the continuation of the base ROE from Complaint I of 10.57%. In April 2017, the NETOs filed for a stay in the hearings pending FERC on the Court order described above. That request was denied by the Administrative Law Judge. Hearings are being held later this year with an expected Initial Decision from the Administrative Law Judge in March 2018. A range of possible outcomes is not able to be determined at this time due to the preliminary state of this matter. We cannot predict the outcome of the Complaint IV proceeding.

On October 5, 2017, the NETOs filed a Motion for Dismissal of Pancaked Return on Equity Complaints in light of the decision by the Court in April 2017 that became effective on June 8, 2017.  The NETOs assert that all four complaints should be dismissed because the complainants have not shown that the existing ROE of 11.14% is unjust and unreasonable as the Court decision requires. In addition, the NETOs assert that Complaints II, III and IV should also be dismissed because the Court decision implicitly found that FERC’s acceptance of Pancaked FPA Section 206 complaints was statutorily improper as Congress intended that the 15-month refund period under Section 206 applies whenever FERC does not complete its review of a complaint within the 15-month period. In the event FERC chooses not to dismiss the complaints, the NETOs request that FERC consolidate the complaints for decision as the evidentiary records are either closed or advanced enough for FERC to address the requirements of the Court decision and expeditiously issue a final order. We cannot predict the outcome of action by FERC.

New York State Department of Public Service Investigation of the Preparation for and Response to the March 2017 Windstorm

At the direction of Governor Andrew Cuomo, on March 11, 2017 the New York State Department of Public Service (the “Department”) commenced an investigation of NYSEG’s and RG&E’s preparation for and response to the March 2017 windstorm, which affected more than 219,000 customers. The Department investigation will include a comprehensive review of NYSEG’s and RG&E’s preparation for and response to the windstorm, including all aspects of the companies’ filed and approved emergency plan. The Department held public hearings on April 12 and 13, 2017. We cannot predict the outcome of this investigation.

California Energy Crisis Litigation

Two California agencies brought a complaint in 2001 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 Court’s 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. In 2014 FERC assigned an administrative law judge to conduct evidentiary hearings. 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 was issued on April 12, 2016.  The proposed ruling found no evidence that Renewables had engaged in any unlawful market contract that would justify finding the Renewables power purchase agreements unjust and unreasonable. However, the proposed ruling did conclude that price of the power purchase agreements imposed an excessive burden on customers in the amount of $259 million. Renewables position, as presented at hearings and agreed by FERC Trial Staff, is that Renewables entered into bilateral power purchase contracts appropriately and complied with all applicable legal standards and

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requirements. The parties have submitted to FERC briefs on exceptions to the administrative law judge’s proposed ruling. There is no specific timetable to FERC’s ruling. We cannot predict the outcome of this proceeding.

Guarantee Commitments to Third Parties

As of September 30, 2017, we had approximately $2.5 billion of standby letters of credit, surety bonds, guarantees and indemnifications outstanding. These instruments provide financial assurance to the business and trading partners of AVANGRID and its subsidiaries in their normal course of business.  The instruments only represent liabilities if AVANGRID 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 September 30, 2017, neither we nor our subsidiaries have any liabilities recorded for these instruments.

Contractual Obligations on Operating Lease Payments

During the nine months ended September 30, 2017, contractual obligations have increased as it relates to operating lease future minimum payments as compared to those reported for the fiscal year ended December 31, 2016 in our Form 10-K.  This is primarily due to new leases for land for the new construction of wind power assets and to extended land lease terms in relation to wind power assets.  Total future minimum lease payments have increased by the following amounts since those disclosed in our consolidated financial statements included in the Annual Report on Form 10-K for the fiscal year ended December 31, 2016:

 

 

Note 8. Environmental Liabilities

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-five waste sites, which do not include sites where gas was manufactured in the past. Fifteen of the twenty-five 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-five 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-five sites. We have paid remediation costs related to the remaining fifteen 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. We recorded a corresponding regulatory asset because we expect to recover these costs in rates. It is possible the ultimate cost to remediate these sites may be significantly more than the accrued amount. Our estimate for costs to remediate these sites ranges from $12 million to $22 million as of September 30, 2017. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination, and the allocation of the clean-up costs.

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 Maine’s Voluntary Response Action Program and with two of such sites

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being part of Maine’s 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-nine of the fifty-three sites.

Our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $221 million to $465 million as of September 30, 2017. 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.

Certain Connecticut and Massachusetts 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 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 September 30, 2017 and no amount of loss, if any, can be reasonably estimated at this time. In the past, the 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.

As of September 30, 2017 and December 31, 2016, the liability associated with other MGP sites in Connecticut, 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 and $97 million, respectively.

The total liability to investigate and perform remediation at the known inactive MGP sites and other sites was $390 million and $388 million as of September 30, 2017 and December 31, 2016, 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 2053.

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 MGP sites. Based on current projections, FirstEnergy’s share is estimated at approximately $21 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. Any recovery will be flowed through to NYSEG ratepayers.

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 22 former manufactured gas plants. Based on estimated clean-up costs of $282 million, the carriers’ allocable share could equal or exceed approximately $89 million, excluding pre-judgment interest, although this amount may change substantially depending upon the determination of various factual matters and legal issues during the case.

Century Indemnity 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. On March 31, 2017, the District Court granted motions filed by Century Indemnity and One Beacon dismissing all of NYSEG’s claims against both defendants on the grounds of late notice.  NYSEG filed a motion with the District Court on April 14, 2017 seeking reconsideration of the Court’s decision and is researching

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grounds for further appeal if the reconsideration motion is denied. We cannot predict the outcome of this matter; however, any recovery will be flowed through to NYSEG ratepayers.

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. This proceeding had been stayed in 2014 pending resolutions of other proceedings before the Connecticut Department of Energy and Environmental Protection (DEEP) concerning the English Station site.  In December 2016, the court administratively closed the file without prejudice to reopen upon the filing of a motion to reopen by any party.  In December 2013, Evergreen Power and Asnat filed a subsequent lawsuit in Connecticut state court seeking among other things: (i) remediation of the English Station site; (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. This lawsuit had been stayed in May 2014 pending mediation. Due to lack of activity in the case, the court terminated the stay and scheduled a status conference for July 6, 2017. On July 5, 2017, Asnat filed a pretrial memorandum claiming damages of $10 million for “environmental remediation activities” and lost use of the property; the memorandum also states that Asnat intends to amend its complaint to update allegations and name additional parties, including former UIL officers and employees and other UI officers.

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 2015. This proceeding was stayed while DEEP and UI continue to work through the remediation process pursuant to the consent order described below. Status reports are periodically filed with the DEEP. The last report was filed in September 2017 and the next status report is due in December 2017.

On August 4, 2016, DEEP issued a partial consent order (the consent order), that, subject to its terms and conditions, requires UI to investigate and remediate certain environmental conditions within the perimeter of the English Station site. Under the 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. UI is obligated to comply with the terms of the consent order even if the cost of such compliance exceeds $30 million. Under the terms of the consent order, 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.      

In connection with the consent order, on August 4, 2016, DEEP also issued a consent order to Evergreen Power, Asnat, and certain related parties that provides UI access to investigate and remediate the English Station site consistent with the consent order. UI has initiated its process to investigate and remediate the environmental conditions within the perimeter of the English Station site pursuant to the consent order.

As of December 31, 2016, we reserved $30 million for this matter. As of September 30, 2017, the reserve amount remained unchanged. We cannot predict the outcome of this matter.

 

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Note 9. Post-retirement and Similar Obligations

We made $0 and $32.4 million of pension contributions for the three and nine months ended September 30, 2017, respectively. We do not expect to make additional contributions for the remainder of 2017.

The components of net periodic benefit cost for pension benefits for the three and nine months ended September 30, 2017 and 2016, respectively, consisted of:

 

 

The components of net periodic benefit cost for postretirement benefits for the three and nine months ended September 30, 2017 and 2016, respectively, consisted of:

 

 

 

Note 10. Equity

As of September 30, 2017, our share capital consisted of 500,000,000 shares of common stock authorized, 309,670,932 shares issued and 309,005,272 shares outstanding, 81.5% of which is 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 $13,656 million. As of December 31, 2016, our share capital consisted of 500,000,000 shares of common stock authorized, 309,600,439 shares issued and 308,993,149 shares outstanding, 81.5% of which was 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. We had 485,810 and 491,459 shares of common stock held in trust and no convertible preferred shares outstanding as of September 30, 2017 and December 31, 2016, respectively. During the nine months ended September 30, 2017, we issued 70,493 shares of common stock and released 5,649 shares of common stock held in trust each having a par value of $0.01. During the nine months ended September 30, 2016, we issued 101,538 shares of common stock and released 134,921 shares of common stock held in trust each having a par value of $0.01.

On April 28, 2016, we entered into a repurchase agreement with J.P. Morgan Securities, LLC. (JPM), pursuant to which JPM will, from time to time, acquire, on behalf of AVANGRID, shares of common stock of AVANGRID. The purpose of the stock repurchase program is to allow AVANGRID to maintain the relative ownership percentage by Iberdrola at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. Out of a total of 179,850 treasury shares of common stock of AVANGRID as of September 30, 2017, 115,831 shares were repurchased during 2016 and 64,019 shares were repurchased in May 2017, all in the open market. The total cost of repurchases, including commissions, was $8 million as of September 30, 2017.

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Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Gain (Loss) for the three months ended September 30, 2017 and 2016, respectively, consisted of:

 

 

Accumulated Other Comprehensive Gain (Loss) for the nine months ended September 30, 2017 and 2016, respectively, consisted of:

 

 

 

 

Note 11. Earnings Per Share

Basic earnings per share is computed by dividing net income attributable to AVANGRID by the weighted-average number of shares of our common stock outstanding. During the three and nine months ended September 30, 2017 and 2016, while we did have securities that were dilutive, these securities did not result in a change in our earnings per share calculation for the three and nine months ended September 30, 2017 and 2016.

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The calculations of basic and diluted earnings per share attributable to AVANGRID, for the three and nine months ended September 30, 2017 and 2016, respectively, consisted of:

 

 

 

Note 12. 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:

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 adding back net income attributable to other non-controlling interests, income tax expense, depreciation and amortization and interest expense net of capitalization, and then subtracting other income and (expense) and earnings 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 condensed consolidated financial statements.

Segment information for the three months ended September 30, 2017, consisted of:

 

(a)Does not represent a segment. It mainly includes Corporate and intersegment eliminations.

 

Included in revenue-external for the three months ended September 30, 2017, are: $941 million from regulated electric operations, $181 million from regulated gas operations and $4 million amounts from other operations of Networks; $241 million from renewable energy generation of Renewables; $(23) million from gas storage services and $(1) million from gas trading operations of Gas.

 

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Segment information for the three months ended September 30, 2016, consisted of:

 

(a)Does not represent a segment. It mainly includes Corporate and intersegment eliminations.

 

Included in revenue-external for the three months ended September 30, 2016, are: $964 million from regulated electric operations, $189 million from regulated gas operations and $4 million amounts from other operations of Networks; $270 million from renewable energy generation of Renewables; $17 million from gas storage services and $(25) million from gas trading operations of Gas.

 

Segment information as of and for the nine months ended September 30, 2017, consisted of:

 

Included in revenue-external for the nine months ended September 30, 2017, are: $2,683 million from regulated electric operations, $966 million from regulated gas operations and $2 million amounts from other operations of Networks; $789 million from renewable energy generation of Renewables; $(20) million from gas storage services and $11 million from gas trading operations of Gas.

Segment information for the nine months ended September 30, 2016, consisted of:

 

 

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Included in revenue-external for the nine months ended September 30, 2016, are: $2,826 million from regulated electric operations, $929 million from regulated gas operations and $3 million amounts from other operations of Networks; $788 million from renewable energy generation of Renewables; $29 million from gas storage services and $(48) million from gas trading operations of Gas.

Reconciliation of consolidated Adjusted EBITDA to the AVANGRID consolidated Net Income for the three and nine months ended September 30, 2017 and 2016, respectively, is as follows:

 

 

 

Note 13. Related Party Transactions

We engage in related party transactions that are generally billed at cost and in accordance with applicable state and federal commission regulations.

Related party transactions for the three months ended September 30, 2017 and 2016, respectively, consisted of:

 

Related party transactions for the nine months ended September 30, 2017 and 2016, respectively, consisted of:

 

 

 

In addition to the statements of income items above, we made purchases of turbines for wind farms from Siemens-Gamesa, in which Iberdrola has an 8.1% ownership. The amounts capitalized for these transactions were $233 million and $269 million for the periods ended September 30, 2017 and December 31, 2016, respectively.

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Related party balances as of September 30, 2017 and December 31, 2016, respectively, consisted of:

 

Transactions with Iberdrola, our majority shareholder, relate predominantly to the provision and 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 guaranteeing our performance. All costs that can be specifically allocated, to the 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.

Transactions with Iberdrola Canada Energy Services (ICES) predominantly relate to the purchase of gas for ARHI’s gas-fired cogeneration facility in Klamath, Oregon. Included in the amounts owed to ICES is the balance of notes payable of $20 million and $10 million as of September 30, 2017 and December 31, 2016, respectively.

Transactions with Iberdrola Energia Monterrey predominantly relate to the sale of gas by Enstor Gas for the power generation plant in Monterrey, Mexico.

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.

Networks holds an approximate 20% ownership interest in the regulated New York TransCo, LLC (New York TransCo). Through New York TransCo, Networks has formed a partnership 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, which is 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. As of September 30, 2017 the amount receivable from New York TransCo was $11 million.

AVANGRID manages its overall liquidity position as part of the broader Iberdrola Group and is a party to a notional cash pooling agreement with a financial institution, along with certain members of the Iberdrola Group. Cash surpluses remaining after meeting the liquidity requirements of AVANGRID and its subsidiaries may be deposited at the financial institution. Deposits, or credit balances, serve as collateral against the debit balances of other parties to the notional cash pooling agreement. The balance at both September 30, 2017 and December 31, 2016, was zero.

 

 

Note 14. Accounts Receivable

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, which generally exceeds one year, by negotiating mutually acceptable payment terms and not bearing interest. 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 30 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 current.

We establish provisions for uncollectible accounts for DPAs by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues. Amounts are written off when reasonable collection efforts have been exhausted. DPA receivable balances were $60 million and $54 million at September 30, 2017 and December 31, 2016, respectively. The allowance for doubtful accounts for DPAs at September 30, 2017 and December 31, 2016, was $33 million and $30 million, respectively. Furthermore, the provision for bad debts associated with the DPAs for the three months ended September 30, 2017 and 2016 was $0 and $(2), respectively, and for the nine months ended September 30, 2017 and 2016 was $3 million and $(3) million, respectively.

 

 

Note 15. Income Tax Expense

The effective tax rates, inclusive of federal and state income tax, for the three and nine months ended September 30, 2017, were 24.2% and 28.1%, respectively, which are lower than the 35% statutory federal income tax rate predominantly due to the recognition of production tax credits associated with wind production in both periods. Additionally, a $14 million increase in income tax expense

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is due to unfunded future income tax to reflect the change from a flow through to normalization method, which was recorded as an increase to revenue, with an offsetting and equal increase to income tax expense in the nine months ended September 30, 2017. This increase was offset by other discrete tax adjustments during the period. The effective tax rates, inclusive of federal and state income tax, for the three and nine months ended September 30, 2016, were 32.7% and 43.8%, respectively, which are different than the 35% statutory federal income tax rate predominantly due to the impact of an adjustment of $126 million to unfunded future income tax to reflect the change from a flow through to normalization method following the approval of the Joint Proposal by the NYPSC, which was recorded in the second quarter of 2016 as an increase to income tax expense and an offsetting increase to revenue, and the sale of the Iroquois equity investment in the nine month period ended September 30, 2016, partially offset by the recognition of production tax credits associated with wind production in both periods.

 

Note 16. Stock-Based Compensation Expense

Pursuant to the 2016 Avangrid, Inc. Omnibus Incentive Plan 5,327 additional performance stock units (PSUs) were granted to certain officers and employees of AVANGRID in March 2017. The PSUs will vest upon achievement of certain performance- and market-based metrics related to the 2016 through 2019 plan and will be payable in three equal installments in 2020, 2021 and 2022. The fair value on the grant date was determined based on $31.80 per share.

In connection with the acquisition of UIL, certain PSUs granted under the UIL 2008 Stock and Incentive Compensation Plan are outstanding, which are payable in AVANGRID shares in 2018 and vest based upon the achievement of certain pre-determined performance objectives.

The total stock-based compensation expense, which is included in operations and maintenance of the condensed consolidated statements of income, for the three and nine months ended September 30, 2017 was $1.4 million and $5.3 million, respectively, and for the three and nine months ended September 30, 2016 was $1.1 million and $1.3 million, respectively.

Before 2016, AVANGRID’s historical stock-based compensation expense and liabilities were based on shares of Iberdrola and not on shares of AVANGRID. These Iberdrola shares-based awards were early terminated at the end of 2015, and the remaining liability will be settled in March 2018.The total liability relating to those awards, which is included in other current and non-current liabilities, was $5.7 million and $9.5 million as of September 30, 2017 and December 31, 2016, respectively.

 

Note 17. 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 consolidated statements of income. The presentation reflects revenues and expenses from the TEFs’ operations on a fully consolidated basis. We consolidate the TEF’s based on being the primary beneficiary for these variable interest entities (VIEs). 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 6.6% and 5.4% as of September 30, 2017 and December 31, 2016, 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.  

The assets and liabilities of these VIEs totaled approximately $1,257 million and $171 million, respectively, at September 30, 2017. As of December 31, 2016, the assets and liabilities of VIEs totaled approximately $1,343 million and $244 million, respectively. At September 30, 2017 and December 31, 2016, the assets and liabilities of the VIEs consisted primarily of property, plant and equipment, equity method investments and TEF liabilities. At September 30, 2017 and December 31, 2016, equity method investments of VIEs were approximately $151 million and $161 million, respectively.

At December 31, 2016, we considered the following four structures to be TEFs: (1) Aeolus Wind Power II LLC, (2) Aeolus Wind Power III LLC, (3) Aeolus Wind Power IV LLC, and (4) Locust Ridge Wind Farm, LLC (collectively, Aeolus). In February 2017, we acquired the tax equity investor’s interest in Locust Ridge Wind Farm, LLC for $5 million. This acquisition converted the partnership to a single member limited liability company and it no longer qualifies as a VIE.

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.

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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.

 

Note 18. Restructuring Expenses

In the second and third quarters of 2017, we announced initial targeted voluntary workforce reductions, predominantly within the Networks segment. Those actions primarily include reorganizing our human resources function to substantially consolidate in Connecticut, as well as related costs to vacate a lease, expected in the fourth quarter of 2017, and relocate employees; reducing our information technology (IT) workforce to align with Iberdrola’s global IT model that makes increasing use of external services for operations, support, and development of systems; and reducing our workforce through voluntary programs in various other areas to better align our people resources with business demands and priorities. Those decisions and transactions resulted in restructuring charges recorded in the third quarter of 2017 for: severance expenses of $2.1 million, which are included in “Operations and maintenance”, and approximately $0.5 million of accelerated amortization of leasehold improvements, which are included in “Depreciation and amortization” in the condensed consolidated statements of income. The costs for severance agreements are being accrued ratably over the remaining service periods, which span intermittent periods from July 2017 through April 2018, and the liabilities are to be paid intermittently from November 2017 through May 2018. Accordingly, the Company expects additional costs be incurred in the fourth quarter of 2017 related to voluntary workforce reductions and costs to vacate a lease on the cease-use date. As of September 30, 2017, the severance and lease restructuring charges reserve was $2.1 million, which is recorded in “Other current liabilities”.

 

Note 19. Subsequent Events

On October 31, 2017, the Governor of Connecticut signed legislation into law, which includes changes to existing tax law.  The Company is in the process of evaluating the potential impact to our income and other tax balances.

 

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Item 2. 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 condensed consolidated financial statements and the notes thereto included elsewhere in this Quarterly Report on Form 10-Q and with our audited consolidated financial statements as of December 31, 2016 and 2015, and for the three years ended December 31, 2016, included in our Annual Report on Form 10-K for the year ended December 31, 2016, filed with the Securities and Exchange Commission, or the SEC, on March 10, 2017, which we refer to as our “Form 10-K.” In addition to historical condensed 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. The foregoing and other factors are discussed and should be reviewed in our Form 10-K and other subsequent filings with the SEC.

Overview

AVANGRID is a diversified energy and utility company with approximately $32 billion in assets and operations in 27 states. The company operates regulated utilities and electricity generation through two primary lines of business. Avangrid Networks is comprised of eight electric and natural gas utilities, serving approximately 3.2 million customers in New York and New England. Avangrid Renewables operates 6.6 gigawatts of electricity capacity, primarily through wind power, with presence in 22 states across the United States. AVANGRID employs approximately 6,800 people. AVANGRID was formed by a merger between Iberdrola USA, Inc. and UIL Holdings Corporation in 2015. Iberdrola S.A., or Iberdrola, a corporation (sociedad anónima) organized under the laws of the Kingdom of Spain, a worldwide leader in the energy industry, directly owns 81.5% of the outstanding shares of AVANGRID common stock. Our primary business is ownership of our operating businesses, which are described below.

Our direct, wholly-owned subsidiaries include Avangrid Networks, Inc., or Networks, and Avangrid Renewables Holdings, Inc., or ARHI. ARHI in turn holds subsidiaries including Avangrid Renewables, LLC, or Renewables, and Enstor Gas, LLC, or Gas. Networks, owns and operates our regulated utility businesses through its subsidiaries, 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).

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 1 million natural gas public utility customers as of September 30, 2017.

Networks, a Maine corporation, holds 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:

Through Renewables, we had a combined wind, solar and thermal installed capacity of 6,716 megawatts, or MW, as of September 30, 2017, including Renewables’ share of joint projects, of which 6,031 MW was installed wind capacity. Approximately 66% of the capacity was contracted as of September 30, 2017, for an average period of 8.4 years. Being among the top three largest wind operators in the United States based on installed capacity as of September 30, 2017, Renewables strives to lead the transformation of the U.S. energy industry to a competitive, clean energy future. Renewables currently operates 55 wind farms in 20 states across the United States.

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Through Gas, as of September 30, 2017, we own approximately 67.5 billion cubic feet, or Bcf, of net working gas storage capacity. Gas operates 50.3 Bcf of contracted or managed natural gas storage capacity in North America through Enstor Energy Services LLC, as of September 30, 2017.

Summary of Results of Operations

Our operating revenues decreased by 5%, from $1.4 billion for the three months ended September 30, 2016 to $1.3 billion for the three months ended September 30, 2017.

The Networks revenues decreased due to a decrease in electricity revenue driven by a lower demand in the current period along with a decrease in related regulatory activities, mainly due to decrease in recoveries on the Ginna Reliability Support Services Agreement, or Ginna RSSA. Renewables and Gas business revenues decreased on the impact of decline in production and unfavorable mark-to-market (MtM) changes on derivatives.

Net income decreased by 8% from $109 million for the three months ended September 30, 2016, to $100 million for the three months ended September 30, 2017. Networks net income improved due to impacts from rate case activities in New York and Connecticut. Renewables net income decreased as a result of higher unfavorable MtM changes on energy derivatives and decline in wind production. Gas net loss increased due to unfavorable MtM changes on derivatives along with unfavorable results from the performance in the owned and contracted storage businesses.

Adjusted earnings before interest, tax, depreciation and amortization, or adjusted EBITDA (a non-GAAP financial measure), decreased by 6% from $420 million for the three months ended September 30, 2016, to $394 million for the three months ended September 30, 2017. Adjusted gross margin (a non-GAAP financial measure) decreased by 2%, from $1,033 million for the three months ended September 30, 2016 to $1,013 million for the three months ended September 30, 2017. The decrease in the non-GAAP adjusted EBITDA and non-GAAP adjusted gross margin is primarily due to a decrease in electricity revenue and related regulatory activities, partially offset by average higher rates at Networks, unfavorable prices and decline in wind production at Renewables and unfavorable MtM changes on derivatives along with unfavorable results from the performance in the owned and contracted storage businesses at Gas. For additional information and reconciliation of the non-GAAP adjusted EBITDA to net income and the non-GAAP adjusted gross margin to net income, see “—Non-GAAP Financial Measures”.

See “—Results of Operations” for further analysis of our operating results for the quarter.

Legislative and Regulatory Update

We are subject to complex and stringent energy, environmental and other laws and regulations at the federal, state and local levels as well as rules within the independent system operator, or ISO, markets in which we participate. Federal and state legislative and regulatory actions continue to change how our business is regulated. We are actively participating in these debates at the federal, regional, state and ISO levels. Significant updates are discussed below. For a further discussion of the environmental and other governmental regulations that affect us, see our Form 10-K for the year ended December 31, 2016.

Transmission - ROE Complaint I

On April 14, 2017, the Court of Appeals, or the Court, vacated FERC’s decision on Complaint I and remanded it back to FERC. The Court held that FERC, as directed by statute, did not determine first that the existing ROE was unjust and unreasonable before determining a new ROE. The Court ruled that FERC should have first determine that the then existing 11.14% base ROE was unjust and unreasonable before selecting the 10.57% as the new base ROE. The Court also found that FERC did not provide reasoned judgment as to why 10.57%, the point ROE at the midpoint of the upper end of the zone of reasonableness, is a just and reasonable ROE. Instead, FERC had only explained in its order that the midpoint of 9.39% was not just and reasonable and a higher base ROE was warranted. On June 5, 2017, the NETOs made a filing with FERC seeking to reinstate transmission rates to the status quo ante (effect of the Court vacating order is to return the parties to the rates in effect prior to FERC Final decision) as of June 8, 2017, the date the Court decision became effective. In that filing, the NETOs stated that they will not begin billing at the higher rates until 60 days after FERC has a quorum of commissioners. On October 6, 2017, FERC issued an order rejecting the NETOs request to collect transmission revenue requirements at the higher ROE of 11.14%, pending FERC order on remand.  In reaching this decision, FERC stated that it has broad remedial authority to make whatever ROE it eventually determines to be just and reasonable effective for the Complaint I refund period and prospectively from October 2014, the effective date of the Complaint I Order. Therefore the NETOs will not be harmed financially by not immediately returning to their pre-Complaint I ROE.  We anticipate FERC to address the Court decision during 2018. We cannot predict the outcome of action by FERC.

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New York State Department of Public Service Investigation of the Preparation for and Response to the March 2017 Windstorm

At the direction of Governor Andrew Cuomo, on March 11, 2017 the New York State Department of Public Service (the “Department”) commenced an investigation of NYSEG’s and RG&E’s preparation for and response to the March 2017 windstorm, which affected more than 219,000 customers. The Department investigation will include a comprehensive review of NYSEG’s and RG&E’s preparation for and response to the windstorm, including the all aspects of the companies’ filed and approved emergency plan. The Department held public hearings on April 12 and 13, 2017. We cannot predict the outcome of this investigation.

SCG’s application for new tariffs

On June 30, 2017, SCG filed an application with PURA for new tariffs to become effective January 1, 2018.  SCG is requesting a three-year rate plan for calendar years 2018, 2019 and 2020 and a proposed ROE of 9.95%.  SCG is also requesting to implement a Revenue Decoupling Mechanism, or RDM, and Distribution Integrity Management Program, or DIMP, mechanism similar to the mechanisms authorized for CNG. On October 16, 2017, SCG, Prosecutorial Staff from PURA, and the Connecticut Office of Consumer Counsel (OCC) filed an amended settlement agreement with PURA for approval, which includes among other items the implementation of an RDM, ESM and the DIMP as proposed by SCG, the amortization of certain regulatory liabilities (most notably accumulated hardship deferral balances and certain accumulated deferred income taxes) and tariff increases based on ROE of 9.25% and approximately 52% equity level. The parties also agreed on a three-year rate plan with rate increases of $1.5 million, $4.7 million and $5.0 million in 2018, 2019, and 2020, respectively. PURA is reviewing the amended settlement agreement and may approve, modify or reject the agreement. SCG expects a decision on its rate case settlement agreement by the end of December 2017 for new tariffs on January 1, 2018. SCG’s last distribution rates were effective from August 2011 as part of a one year rate plan approved by PURA.

PURA docket to review the gas supply portfolio

On October 17, 2017, PURA opened a docket to review the gas supply portfolio, asset strategy, and practices of Connecticut’s gas local distribution companies, or LDCs. CNG and SCG are Connecticut LDCs and expect to participate in the docket. CNG and SCG are obligated by regulation and law to provide safe and reliable gas service to homes and businesses under the oversight of state regulators and the pipeline transportation service that CNG and SCG receive from interstate pipelines is regulated by the FERC. In providing service to our customers, we always seek to comply with all state and federal regulatory requirements and we look forward to the opportunity of the PURA proceeding to address the facts and participate in discussions related to continuing to serve our customers in a safe and reliable manner.

Connecticut legislation

On October 31, 2017, the Governor of Connecticut signed legislation into law, which includes changes to existing tax law.  The Company is in the process of evaluating the potential impact to our income and other tax.

 

 

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Results of Operations

The following table sets forth financial information by segment for each of the periods indicated:

 

 

 

(1)Other amounts represent corporate and intersegment eliminations.

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Comparison of Period to Period Results of Operations

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016

The following table sets forth our operating revenues and expenses by segment for each of the periods indicated and as a percentage of the consolidated total of operating revenues and operating expenses, respectively:

 

 

 

(1)Other amounts represent corporate and intersegment eliminations.

Operating Revenues

Our operating revenues decreased by $77 million, or 5%, from $1,418 million for the three months ended September 30, 2016 to $1,341 million for the three months ended September 30, 2017, as detailed by segment below:

Networks

Operating revenues decreased by $31 million, or 3%, from $1,156 million for the three months ended September 30, 2016 to $1,125 million for the three months ended September 30, 2017. Electricity and gas revenues increased by $46 million and $1 million, respectively, due to primarily the impact of higher average rates in the third quarter of 2017 compared to the same period of 2016 from rate case activities in New York and Connecticut, which was offset by $33 million and $7 million decrease in electric and gas revenues, respectively, due to lower volumes largely driven by decrease in cooling degree days for electricity revenue and  due to a migration in customers moving from retail access to full service and unfavorable results from off system sales for gas revenue in the third quarter of 2017 compared to the same period of 2016. Additionally, wholesale electricity revenue decreased by $21 million for the three month period ended September 30, 2017 compared to the same period of 2016 due to a decrease in overall units sold caused by a decrease in cooling degree days. Revenue related regulatory activities decreased by $17 million primarily due to recoveries on the Ginna RSSA of $23 million, offset by increases of $3 million in stranded cost and $3 million in storm costs deferral.

Renewables

Operating revenues decreased by $34 million, or 12%, from $275 million for the three months ended September 30, 2016 to $241 million for the three months ended September 30, 2017. The decrease in operating revenues was mainly due to a decrease of $13 million from wind production with output declining 6%, or 201GWh, and unfavorable MtM changes of $21 million on energy derivative transactions entered into for economic hedging purposes.

Gas

Operating revenues decreased by $17 million from $7 million for the three months ended September 30, 2016 to negative $10 million for the three months ended September 30, 2017. The decrease in operating revenues was mainly due to $12 million of unfavorable MtM change driven by a decrease in gas prices and $5 million of unfavorable results from the performance of the owned and contracted storage businesses.

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Purchased Power, Natural Gas and Fuel Used

Our purchased power, natural gas and fuel used decreased by 20%, from $312 million for the three months ended September 30, 2016 to $250 million for the three months ended September 30, 2017, as detailed by segment below:

Networks

Purchased power, natural gas and fuel used decreased by $67 million, or 25%, from $271 million for the three months ended September 30, 2016 to $204 million for the three months ended September 30, 2017. The decrease is primarily driven by a $15 million decrease in purchases from contracts that expired in December 2016, $56 million decrease in electric purchases driven by a lower demand due to a decrease in cooling degree days, offset by a $4 million increase in gas transportation related activity .    

Renewables

Purchased power, natural gas and fuel used increased by $4 million, or 7%, from $56 million for the three months ended September 30, 2016 to $60 million for the three months ended September 30, 2017. The increase is primarily due to transmission expenses being $4 million higher due to increased capacity in the three months ended September 30, 2017 compared to the same period of 2016.

Gas

The gas business had no purchased power, natural gas and fuel used for the three months ended September 30, 2017 and 2016. As a predominantly trading business, such expenses are required to be netted with revenues.

Operations and Maintenance

Our operations and maintenance increased by 1% from $553 million for the three months ended September 30, 2016 to $560 million for the three months ended September 30, 2017, as detailed by segment below:

Networks

Operations and maintenance increased by $1 million, or less than 1%, from $470 million for the three months ended September 30, 2016 to $471 million for the three months ended September 30, 2017. The increase is primarily due to a $23 million lower capitalized labor costs in the current period, $8 million increase in purchases of renewable and zero-emission energy certificates related to a new program to adopt clean energy standards, offset by a decrease of $30 million in the Ginna RSSA driven by its completion.

Renewables

Operations and maintenance expenses decreased by $3 million or 3% from $91 million for the three months ended September 30, 2016 to $88 million for the three months ended September 30, 2017. Corporate charges were $1 million lower and capitalization of labor from new construction projects were $2 million higher in the three months ended September 30, 2017 compared with the same period of 2016.

Gas

Operations and maintenance decreased by $2 million, or 17%, from $12 million for the three months ended September 30, 2016 to $10 million for the three months ended September 30, 2017. Decrease in corporate charges mainly account for the decrease in the three month period ended September 30, 2017 compared to the same period of 2016.

Depreciation and Amortization

Depreciation and amortization for the three months ended September 30, 2017 was $205 million compared to $203 million for the three months ended September 30, 2016, an increase of $2 million. The increase is primarily due to $7 million from net plant additions in the period at Networks and Renewables, offset by $3 million decrease from relifing and assets lives increase at Renewables driven by new contracts and other $2 million of decreases in various items at Networks.

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Other Income (Expense) and Earnings (Losses) from Equity Method Investments

Other income (expense) and equity earnings (losses) increased by $9 million from $5 million for the three months ended September 30, 2016 to $14 million for the three months ended September 30, 2017 primarily due to $3 million increase in Renewables mainly driven by a write-off of certain development projects recorded in the third quarter of 2016, $4 million for increased allowance for funds used during construction in Networks due to primarily higher construction balances and $2 million from interest income on regulatory deferrals in Networks.

Interest Expense, Net of Capitalization

Interest expense for the three months ended September 30, 2017 and 2016 were $71 million and $60 million, respectively. Networks and Other added $7 million and $6 million of interest expense from new outstanding debt in the period. Renewables was $1 million favorable, as a result of lower tax equity investment obligations and intercompany notes.

Income Tax Expense

The effective tax rate, inclusive of federal and state income tax, for the three months ended September 30, 2017 is 24.2%, which is lower than the 35% statutory federal income tax rate predominately due to the recognition of production tax credits associated with wind production. The effective tax rate, inclusive of federal and state income tax, for the three months ended September 30, 2016 was 32.7%, which is lower than the 35% statutory federal income tax rate primarily due to the recognition of production tax credits associated with wind production.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016

The following table sets forth our operating revenues and expenses by segment for each of the periods indicated and as a percentage of the consolidated total of operating revenues and operating expenses, respectively:

 

 

 

Operating Revenues

Our operating revenues decreased by $97 million, or 2%, from $4,527 million for the nine months ended September 30, 2016 to $4,430 million for the nine months ended September 30, 2017, as detailed by segment below:

Networks

Operating revenues decreased by $108 million, or 3%, from $3.8 billion for the nine months ended September 30, 2016 to $3.7 billion for the nine months ended September 30, 2017. Electricity and gas revenues increased by $118 million and $61 million, respectively, due to primarily the impact of higher average rates in the nine months period ended September 30, 2017 compared to the same period of 2016 from rate case activities in New York and Connecticut. Electricity revenue for the same period decreased by $43 million due to lower volumes largely driven by decrease in cooling degree days for electricity revenue, while gas revenues increased by $20 million in the same period due to a migration in customers moving from retail access to full service and colder weather. Additionally, wholesale electricity revenue decreased by $10 million for the nine months ended September 30, 2017 compared to the same period of 2016 due to a decrease in overall units sold caused by a decrease in cooling degree days. Revenue related regulatory activities decreased by $252 million primarily due to an adjustment of $126 million in the nine month period ended September 30, 2016 and an adjustment of $14 million in the nine month period ended September 30, 2017, to unfunded future income tax to reflect

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the change from a flow through to normalization method, which were recorded as an increase to revenue, with an offsetting and equal increase to income tax expense in both periods, decreases in the energy supply reconciliation of $24 million, amortization of regulatory deferrals from previous rate case of $28 million that ended in 2016, decreases in recoveries on the Ginna RSSA of $47 million, stranded cost of $21 million, property and power tax deferral of $33 million, offset by increases in revenue decoupling mechanism of $3 million and $10 million in transmission true-ups.

Renewables

Operating revenues decreased by $4 million, or 1%, from $797 million for the nine months ended September 30, 2016 to $793 million for the nine months ended September 30, 2017. The decrease in operating revenues was primarily due to an increase of $6 million from wind production with output increasing 89GWh, or 1%, favorable MtM changes of $11 million on energy derivative transactions entered into for economic hedging purposes, offset by a decline in thermal revenue of $8 million and $12 million in other revenues mainly due to sale of transmission rights that occurred in 2016.

Gas

Operating revenues increased by $9 million from $8 million for the nine months ended September 30, 2016 to $17 million for the nine months ended September 30, 2017. The increase in operating revenues was mainly due to $9 million of improved performance in the owned and contracted storage businesses, $3 million favorable MtM change, offset by $3 million unfavorable results from transportation business mainly driven by $3 million loss recorded in the nine months ended September 30, 2017 due to the turn back of Iroquois transport capacity.

Purchased Power, Natural Gas and Fuel Used

Our purchased power, natural gas and fuel used decreased by less than 1%, from $961 million for the nine months ended September 30, 2016 to $957 million for the nine months ended September 30, 2017, as detailed by segment below:

Networks

Purchased power, natural gas and fuel used decreased by $38 million, or 4%, from $870 million for the nine months ended September 30, 2016 to $832 million for the nine months ended September 30, 2017. The decrease is primarily driven by $38 million decrease in purchases from contracts that expired in December 2016 and $35 million decreases in overall units of electricity procured due to a reduction in cooling degree days, offset by $26 million increase in average gas prices and overall units of gas procured combined with $9 million increase in gas transportation related activity.

Renewables

Purchased power, natural gas and fuel used increased by $33 million, or 28%, from $118 million for the nine months ended September 30, 2016 to $151 million for the nine months ended September 30, 2017. The increase is primarily driven by MtM changes on derivatives of $35 million that were unfavorable due to market price changes in the current period.

Gas

The gas business had no purchased power, natural gas and fuel used for the nine months ended September 30, 2017 and 2016. As a predominantly trading business, such expenses are required to be netted with revenues.

Operations and Maintenance

Our operations and maintenance decreased by $29 million, or 2%, from $1,662 million for the nine months ended September 30, 2016 to $1,633 million for the nine months ended September 30, 2017, as detailed by segment below:

Networks

Operations and maintenance decreased by $37 million, or 3% from $1,391 million for the nine months ended September 30, 2016 to $1,354 million for the nine months ended September 30, 2017. The decrease is primarily due to a decrease of $91 million in the Ginna RSSA driven by its completion, offset by $15 million increase in purchases of renewable and zero-emission energy certificates related to a new program to adopt clean energy standards and increase in personnel costs of $37 million driven largely by overtime associated with storms.

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Renewables

Operations and maintenance expenses increased by $1 million or less than 1% from $257 million for the nine months ended September 30, 2016 to $258 million for the nine months ended September 30, 2017. The increase is primarily due to increase in salary costs of $2 million due to headcount increases, offset by $1 million lower maintenance costs in the nine month period ended September 30, 2017 compared with the same period of 2016.

Gas

Operations and maintenance decreased by $4 million, or 11%, from $35 million for the nine months ended September 30, 2016 to $31 million for the nine months ended September 30, 2017. Adjustment in pension costs made in 2016 primarily account for decreases in operation and maintenance in the nine month period ended September 30, 2017.

Depreciation and Amortization

Depreciation and amortization for the nine months ended September 30, 2017 was $608 million compared to $621 million for the nine months ended September 30, 2016, a decrease of $13 million. The decrease is primarily due to decrease of $23 million in Networks depreciation expense as a result of updates to asset lives mainly from the rate case activities, offset by depreciation increase of $10 million due to net plant additions in the period.

Other Income (Expense) and Earnings (Losses) from Equity Method Investments

Other income (expense) and equity earnings (losses) decreased by $38 million from $76 million for the nine months ended September 30, 2016 to $38 million for the nine months ended September 30, 2017, primarily due to the impact of $31 million from the sale of the Iroquois equity investment, $3 million from the sale of an other investment and $6 million decrease due to reversal of the Maine Natural Gas provision all occurring in the nine month period ended September 30, 2016, as well as a $1 million decrease in equity earnings, offset by $3 million for increased allowance for funds used during construction in Networks.

Interest Expense, Net of Capitalization

Interest expense for the nine months ended September 30, 2017 and 2016 were $210 million and $212 million, respectively. Networks and Other added $10 million and $15 million of interest expense from the outstanding debt in the period. Gas was $6 million unfavorable as a result of intercompany notes in the period. Renewables was $24 million favorable, as a result of lower tax equity investment obligations and intercompany notes. In addition, Networks had $10 million of lower interest expense on regulatory deferrals in the current period.

Income Tax Expense

The effective tax rate, inclusive of federal and state income tax, for the nine months ended September 30, 2017 is 28.1%, which is lower than the 35% statutory federal income tax rate predominately due to the recognition of production tax credits associated with wind production. Additionally, a $14 million increase in income tax expense is due to unfunded future income tax to reflect the change from a flow through to normalization method, which was recorded as an increase to revenue, with an offsetting and equal increase to income tax expense in the nine month period ended September 30, 2017. This increase was partially offset by other discrete tax adjustments during the nine month period ended September 30, 2017. The effective tax rate, inclusive of federal and state income tax, for the nine months ended September 30, 2016 was 43.8% which is higher than the 35% statutory federal income tax rate predominantly due to the impact of an adjustment of $126 million to unfunded future income tax to reflect the change from a flow through to normalization method following the approval of the Joint Proposal by the NYPSC, which was recorded in the second quarter of 2016 as an increase to income tax expense and an offsetting increase to revenue, the sale of the Iroquois equity investment in the nine month period ended September 30, 2016, partially offset by the recognition of production tax credits associated with wind production during the same period.

Non-GAAP Financial Measures

To supplement our consolidated financial statements presented in accordance with U.S. GAAP, we consider certain non-GAAP financial measures that are not prepared in accordance with U.S. GAAP, including adjusted gross margin, adjusted EBITDA, adjusted net income and adjusted earnings per share, or adjusted EPS. The non-GAAP financial measures we use are specific to AVANGRID and the non-GAAP financial measures of other companies may not be calculated in the same manner. We use these non-GAAP financial measures, in addition to U.S. GAAP measures, to establish operating budgets and operational goals to manage and monitor our business, evaluate our operating and financial performance and to compare such performance to prior periods and to the performance of our competitors. We believe that presenting such non-GAAP financial measures is useful because such measures can be used to analyze and compare profitability between companies and industries because it eliminates the impact of financing and certain non-cash charges. In addition, we present non-GAAP financial measures because we believe that they and other similar

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measures are widely used by certain investors, securities analysts and other interested parties as supplemental measures of performance.

We define adjusted EBITDA as net income attributable to AVANGRID, adding back net income attributable to noncontrolling interests, income tax expense, depreciation, amortization, impairment of non-current assets and interest expense, net of capitalization, and then subtracting other income and earnings from equity method investments. We define adjusted net income as net income adjusted to exclude, restructuring charges, gain on the sale of equity method and other investment, impairment of investment, mark-to-market adjustments to reflect the effect of mark-to-market changes in the fair value of derivative instruments used by AVANGRID to economically hedge market price fluctuations in related underlying physical transactions for the purchase and sale of electricity and adjustments for the non-core Gas storage business, for which we are exploring strategic options. We believe adjusted net income is more useful in understanding and evaluating actual and projected financial performance and contribution of AVANGRID core lines of business and to more fully compare and explain our results. 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. We define adjusted gross margin as adjusted EBITDA adding back operations and maintenance and taxes other than income taxes and then subtracting transmission wheeling. The most directly comparable U.S. GAAP measure to adjusted EBITDA, adjusted gross margin and adjusted net income is net income. We also define adjusted earnings per share (EPS) as adjusted net income converted to an earnings per share amount.  

The use of non-GAAP financial measures is not intended to be considered in isolation or as a substitute for, or superior to, AVANGRID’s U.S. GAAP financial information, and investors are cautioned that the non-GAAP financial measures are limited in their usefulness, may be unique to AVANGRID, and should be considered only as a supplement to AVANGRID’s U.S. GAAP financial measures. The non-GAAP financial measures may not be comparable to other similarly titled measures of other companies and have limitations as analytical tools.

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, net income or any other performance measures determined in accordance with U.S. GAAP.

Reconciliation of the Net Income attributable to AVANGRID to adjusted EBITDA (non-GAAP) and adjusted gross margin (non-GAAP) before excluding restructuring charges, gain on the sale of equity method and other investment, impairment of investment, impact from mark-to-market activities in Renewables and Gas storage business, and before adjustments to reflect the classification of revenues and expenses by nature for the three and nine months ended September 30, 2017 and 2016, respectively, is as follows:

 

 

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Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016

The following table sets forth our adjusted EBITDA and adjusted gross margin by segment for each of the periods indicated and as a percentage of operating revenues:

 

 

 

Our adjusted gross margin decreased by $20 million, or 2%, from $1,033 million for the three months ended September 30, 2016 to $1,013 million for the three months ended September 30, 2017.

Our adjusted EBITDA decreased by $26 million, or 6%, from $420 million for the three months ended September 30, 2016 to $394 million for the three months ended September 30, 2017.

Details of the period to period comparison are described below at the segment level.

Networks

Adjusted gross margin increased by $32 million from $812 million for the three months ended September 30, 2016 to $844 million for the three months ended September 30, 2017. The increase was primarily driven by a decrease in electric purchases driven by a lower demand in the three months ended September 30, 2017.

Adjusted EBITDA increased by $30 million or 10% from $296 million for the three months ended September 30, 2016 to $326 million for the three months ended September 30, 2017. The increase was due to the same reasons discussed above for adjusted gross margin.

Renewables

Adjusted gross margin decreased by $38 million, or 17%, from $219 million for the three months ended September 30, 2016 to $181 million for the three months ended September 30, 2017. The decrease was due to unfavorable MtM changes on energy derivatives and decline in wind production.

Adjusted EBITDA decreased by $33 million, or 28%, from $116 million for the three months ended September 30, 2016 to $83 million for the three months ended September 30, 2017. The decrease was due to the same reasons discussed above for adjusted gross margin.

Gas

Adjusted gross margin decreased by $17 million, from $6 million for the three months ended September 30, 2016 to negative $11 million for the three months ended September 30, 2017. The decrease is primarily associated unfavorable MtM changes in the

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current period as compared to the same period of 2016 and unfavorable results from the performance of the owned and contracted storage businesses.

Adjusted EBITDA decreased by $16 million from negative $6 million for the three months ended September 30, 2016 to negative $22 million for the three months ended September 30, 2017. The decrease was due primarily to the same reasons discussed above for adjusted gross margin.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016

The following table sets forth our adjusted EBITDA and adjusted gross margin by segment for each of the periods indicated and as a percentage of operating revenues:

 

 

 

Our adjusted gross margin decreased by $105 million, or 3%, from $3,371 million for the nine months ended September 30, 2016 to $3,266 million for the nine months ended September 30, 2017.

Our adjusted EBITDA decreased by $91 million, or 6%, from $1,509 million for the nine months ended September 30, 2016 to $1,418 million for the nine months ended September 30, 2017.

Details of the period to period comparison are described below at the segment level.

Networks

Adjusted gross margin decreased by $83 million, or 3%, from $2,695 million for the nine months ended September 30, 2016 to $2,612 million for the nine months ended September 30, 2017. The decrease is primarily driven by a decrease in revenue related regulatory activities driven by an adjustment of unfunded future income tax in the nine months period ended September 30, 2016, partially offset by average higher rates from rate case activities in New York and Connecticut.

Adjusted EBITDA decreased by $60 million, or 5%, from $1,151 million for the nine months ended September 30, 2016 to $1,091 million for the nine months ended September 30, 2017. The decrease was due to the same reasons discussed above for adjusted gross margin.

Renewables

Adjusted gross margin decreased by $36 million, or 5%, from $679 million for the nine months ended September 30, 2016 to $643 million for the nine months ended September 30, 2017. The decrease was primarily due to unfavorable MtM changes on energy derivatives driven by market price changes in the current period.

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Adjusted EBITDA decreased by $38 million, or 10%, from $384 million for the nine months ended September 30, 2016 to $346 million for the nine months ended September 30, 2017. The decrease was due to the same reasons discussed above for adjusted gross margin.

Gas

Adjusted gross margin increased by $8 million, from $7 million for the nine months ended September 30, 2016 to $15 million for the nine months ended September 30, 2017. The increase is primarily associated with improved performance in the owned and contracted storage businesses and favorable MtM changes in the current period as compared to the same period of 2016.

Adjusted EBITDA increased by $12 million, from negative $31 million for the nine months ended September 30, 2016 to negative $19 million for the nine months ended September 30, 2017. The increase was due primarily to the same reasons discussed above for adjusted gross margin.

The following table provides a reconciliation between Net Income attributable to AVANGRID and adjusted gross margin (non-GAAP) and adjusted EBITDA (non-GAAP) by segment after excluding restructuring charges, gain on the sale of equity method and other investment, impairment of investment, impact of mark-to-market activity in Renewables and Gas storage business, and after adjustments to reflect the classification of revenues and expenses by nature for the three and nine months ended September 30, 2017 and 2016, respectively:

 

 

 

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2016: Adjustments have been made for production tax credit adjustments for the amount of $7 million and $25 million for three and nine months ended September 30, 2016, respectively, as they have been included in operating revenues in Renewables, and $126 million of unfunded future income taxes in Networks have been reclassified from revenues to reflect classification by nature in the nine month period ended September 30, 2016, as discussed above. After reflecting these by nature classification adjustments the calculated effective income tax rates are impacted for both periods presented under this by nature classification presentation.

2016: Adjustments have been made for the inclusion of vehicle depreciation and bad debt provision within depreciation and amortization from operations and maintenance based on the by nature classification. Vehicle depreciation was $5 million and $15 million and bad debt provision was $24 million and $36 million in Networks, for the three and nine months ended September 30, 2016, respectively.  Additionally, government grants and investment tax credits amortization have been presented within other operating income and not within depreciation and amortization based on the by nature classification, as follows: government grants of $1.5 million and $4.9 million in Networks and investment tax credits of $23 million and $68 million in Renewables, for the three and nine month periods ended September 30, 2016, respectively.

 

* Includes corporate and other non-regulated entities as well as intersegment eliminations.

The following tables provides a reconciliations between Net Income attributable to AVANGRID and Adjusted Net Income (non-GAAP), and EPS attributable to AVANGRID and adjusted EPS (non-GAAP) after excluding restructuring charges, gain on the sale of equity method and other investment, impairment of investment, impact from mark-to-market activities in Renewables and Gas storage business for the three and nine months ended September 30, 2017 and 2016, respectively:

 

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Liquidity and Capital Resources

Our operations, capital investment and business development require significant short-term liquidity and long-term capital resources. 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 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.

We and our subsidiaries are required to comply with certain covenants in connection with our respective loan agreements. The covenants are standard and customary in financing agreements, and we and our subsidiaries were in compliance with such covenants as of September 30, 2017.

Liquidity Position

At September 30, 2017 and December 31, 2016, available liquidity was approximately $816 million and $1,441 million, respectively.

We manage our overall liquidity position as part of the group of companies controlled by Iberdrola, or the Iberdrola Group, and are a party to a notional cash pooling agreement with a financial institution, along with certain members of the Iberdrola Group. 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 the financial institution, provided that the net balance of funds deposited or borrowed by all pool participants in the aggregate is not less than zero. Deposits are available for next day withdrawal. In advance of the United Kingdom “BREXIT” vote, we took steps to reposition our liquidity and our deposits were withdrawn and reinvested in money market accounts. The balance at September 30, 2017 was zero. Any deposit amounts would be 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. We also have a bi-lateral demand note agreement with a Canadian affiliate of the Iberdrola Group under which we had notes payable balance outstanding of $20 million at September 30, 2017.

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

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costs and maximize returns on the temporary cash investments of the subsidiaries. We have the capacity to borrow up to $1.5 billion from the lenders committed to the facility.

The following table provides the components of our liquidity position as of September 30, 2017 and December 31, 2016, respectively:

 

AVANGRID Commercial Paper Program

On May 13, 2016, AVANGRID established a commercial paper program with a limit of $1 billion that is backstopped by the AVANGRID Credit Facility (described below). As of September 30, 2017 and November 1, 2017, there was $711 million and $921 million of commercial paper outstanding, respectively.

AVANGRID Credit Facility

On April 5, 2016, AVANGRID and its subsidiaries, NYSEG, RG&E, CMP, UI, CNG, SCG and BGC entered into a revolving credit facility with a syndicate of banks, or the AVANGRID Credit Facility, that provides for maximum borrowings of up to $1.5 billion in the aggregate.  Since the facility is a backstop to the AVANGRID commercial paper program, the amounts available under the facility at September 30, 2017 and November 1, 2017, were $789 million and $579 million, respectively.

RG&E First Mortgage Bonds

On May 24, 2017, RG&E issued $300 million in aggregate principal amount of 3.10% First Mortgage Bonds due in 2027.  Proceeds of the offering were used to reduce short-term debt, to fund capital expenditures and for general corporate purposes.

Capital Requirements

We expect to fund our capital requirements, including, without limitation, any quarterly shareholder dividends and capital investments primarily from the cash provided by operations of our businesses and through the access to the capital markets 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.

We expect to accrue approximately $0.7 billion in capital expenditures in the fourth quarter of 2017.

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 nine months ended September 30, 2017 and 2016, respectively:

 

 

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Operating Activities

For the nine months ended September 30, 2017, net cash provided by operating activities was $1.3 billion. During the nine months ended September 30, 2017, Renewables contributed $340 million of operating cash flow associated with wholesale sales of energy, Networks contributed $725 million of operating cash as the result of regulated transmission and distribution sales of electricity and natural gas, and Gas used $17 million in cash associated with marketing of wholesale gas and gas storage services. Additionally, $6 million in cash was provided associated with corporate operating expenses in support of the operating segments and changes in working capital provided $269 million in cash. The cash from operating activities for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016 increased by $108 million, primarily attributable to increased operating revenues, excluding the impact of a non-cash adjustment of unfunded future income tax discussed above. The $9 million net change in operating assets and liabilities during the nine months ended September 30, 2017 was primarily attributable to a net decrease of $74 million in accounts receivable and payable due to impacts from sales and purchases, cash distribution received from equity method investment of $11 million, offset by increase in taxes accrued of $10 million, increase in inventories and other assets/liabilities of $33 million and $96 million, respectively, and increase of $43 million in regulatory assets/liabilities.

 

For the nine months ended September 30, 2016, net cash provided by operating activities was $1.2 billion. During the nine months ended September 30, 2016, Renewables contributed $357 million of operating cash flow associated with wholesale sales of energy, Networks contributed $681 million of operating cash as the result of regulated transmission and distribution sales of electricity and natural gas, and Gas used $26 million in cash associated with losses on marketing of wholesale gas and gas storage services. Additionally, $28 million in cash was provided in support of the operating segments and changes in working capital provided $177 million in cash. The cash from operating activities for the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015 increased by $253 million, primarily attributable to the increased operating revenues. The $334 million net change in operating assets and liabilities during the nine months ended September 30, 2016 was primarily attributable to a decrease of $72 million in accounts receivable and increase of $52 million in accounts payable due to impacts from sales and purchases, cash distribution received from equity method investment of $10 million, decrease in inventories and regulatory assets/liabilities of $59 million and $201 million, respectively, offset by increase in taxes accrued of $11 million and assets/liabilities of $337 million.

Investing Activities

For the nine months ended September 30, 2017, net cash used in investing activities was $1,667 million, which was comprised of $842 million associated with capital expenditures at Networks and $855 million of capital expenditures at Renewables primarily associated with payments in support of the El Cabo construction project. This was offset by $31 million of contributions in aid of construction, $4 million of cash distributions from equity method investments and proceeds of $9 million from the sale of property, plant and equipment.

For the nine months ended September 30, 2016, net cash used in investing activities was $865 million, which was comprised of $749 million associated with capital expenditures at Networks and $284 million of capital expenditures at Renewables primarily associated with payments in support of the Desert Wind construction project. This was offset by $55 million of contributions in aid of construction, proceeds of $57 million from the sale of our equity method investment in Iroquois and other investment, $43 million from asset sale to the New York TransCo and $7 million from sale of property.

Financing Activities

For the nine months ended September 30, 2017, financing activities provided $283 million in cash reflecting primarily an issuance of First Mortgage Bonds at RG&E with the net proceeds of $294 million, a net increase in non-current debt and current notes payable of $505 million, payments on the tax equity financing arrangements of $84 million, capital lease of $32 million and dividends of $401 million.

For the nine months ended September 30, 2016, financing activities used $596 million in cash reflecting primarily a net decrease in non-current and current notes payable of $242 million, payments on the tax equity financing arrangements of $75 million, repurchase of common stock of $4 million and dividends of $267 million.

Off-Balance Sheet Arrangements

There have been no material changes in the off-balance sheet arrangements during the nine months ended September 30, 2017 as compared to those reported for the fiscal year ended December 31, 2016 in our Form 10-K.

Contractual Obligations

During the nine months ended September 30, 2017, contractual obligations have increased as it relates to operating lease future minimum payments as compared to those reported for the fiscal year ended December 31, 2016 in our Form 10-K. This is primarily

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due to new leases for land for the new construction of wind power assets and to extended land lease terms in relation to wind power assets. For further discussion of minimum lease payments refer to Note 7 of our condensed consolidated financial statements for the three and nine months ended September 30, 2017.

Critical Accounting Policies and Estimates

The accompanying financial statements provided herein have been prepared in accordance with U.S. GAAP. In preparing the accompanying financial statements, our management has applied accounting policies and made certain estimates and assumptions that affect the reported amounts of assets, liabilities, shareholder’s equity, revenues and expenses, and the disclosures thereof. While we believe that these policies and estimates used are appropriate, actual future events can and often do result in outcomes that can be materially different from these estimates. The accounting policies and related risks described in our Form 10-K are those that depend most heavily on these judgments and estimates. As of September 30, 2017, there have been no material changes to any of the policies described therein, other than with respect to our early adoption of the amendments relating to the definition of a business described in the Note 3 of our condensed consolidated financial statements for the three and nine months ended September 30, 2017.

New Accounting Standards

We review new accounting standards to determine the expected financial impact, if any, that the adoption of each such standard will have. The following are new accounting pronouncements issued since December 31, 2016, that we have evaluated or are evaluating to determine their effect on our consolidated financial statements.

Clarifying the definition of a business - In January 2017 the FASB issued amendments to clarify the definition of a business.

Clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets - In February 2017 the FASB issued amendments concerning asset derecognition and partial sales of nonfinancial assets.

Improving the presentation of net periodic benefit costs - In March 2017 the FASB issued amendments to improve the presentation of net periodic pension cost and net periodic postretirement benefit cost in the financial statements.

Targeted improvements to accounting for hedging activities - In August 2017 the FASB issued targeted amendments with the objective to better align hedge accounting with an entity’s risk management activities in the financial statements, and to simplify the application of hedge accounting.

For further discussion of new accounting pronouncements refer to Note 3 of our condensed consolidated financial statements for the three and nine months ended September 30, 2017.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q 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 that” and “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. The foregoing and other factors are discussed and should be reviewed in our Form 10-K and other subsequent filings with the SEC. Specifically, forward-looking statements may include statements relating to:

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.

 

Item 3. Quantitative and Qualitative Disclosures about Market Risk

There have been no material changes in our market risk during the nine months ended September 30, 2017, as compared to those reported for the fiscal year ended December 31, 2016 in our Form 10-K.

 

Item 4. 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, or 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 (Exchange Act)), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on such evaluation, our CEO and CFO have concluded that as of such date, our disclosure controls and procedures were not effective, as a result of the material weaknesses that exist in our internal control over financial reporting as previously described in our Annual Report on Form 10-K for the year ended December 31, 2016.

Previously Identified Material Weaknesses

As of December 31, 2016, management concluded that certain deficiencies rose to the level of a material weakness in controls related to: (1) the accounting for the change in the estimated useful life of certain elements of the wind farms at Renewables and other smaller deficiencies related to documentation of internal controls procedures, and enhancement of review controls at Renewables, (2) the preparation of the consolidated financial statements, specifically the classification and disclosure of financial information, and (3) the measurement and disclosure of income taxes. As a result of these identified material weaknesses, management concluded that, as of December 31, 2016, our internal control over financial reporting was not effective. This material weakness did not result in any restatement of prior-period financial statements.

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

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Notwithstanding such material weaknesses in internal control over financial reporting, our management concluded that our unaudited condensed consolidated financial statements in this report fairly present, in all material respects, the Company’s financial position, results of operations and cash flows as of the dates, and for the periods presented, in conformity with generally accepted accounting principles.

Remediation Plans and Other Information

AVANGRID’s management, with oversight from its Audit and Compliance Committee of the Board of Directors of AVANGRID, is actively engaged in remediation efforts to address the material weakness identified above. Management is in the process of performing a number of actions to remediate the material weakness including the following remediation plans:

Management has increased, during the nine month period ended September 30, 2017, accounting personnel and internal control resources in order to devote additional time to accounting and reporting processes and controls.

These improvements are targeted at strengthening the Company’s internal control over financial reporting and remediating the material weakness. The Company remains committed to an effective internal control environment and management believes that these actions and the improvements management expects to achieve as a result, will remediate the material weakness. However, the material weaknesses in our internal control over financial reporting will not be considered remediated until the controls operate for a sufficient period of time and management has concluded, through testing that these controls operate effectively. We are in the process of implementing our remediation plan and expect to have the remediation of these material weaknesses completed by December 31, 2017.

Changes in Internal Control

Except for the control deficiencies discussed above that have been assessed as material weaknesses as of December 31, 2016, and the remediation as described within “Remediation Plans and Other Information” above, there has been no change in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the period covered by this Quarterly Report on Form 10-Q 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.

 

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

 

Shareholder Derivative Action

On February 27, 2015, a complaint was filed in Connecticut state court, or the 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 generally alleges that UIL’s 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 Board’s 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, additional confirmatory discovery, and plaintiffs’ counsel fees. The parties have agreed on the fees and submitted the unopposed settlement and dismissal to the Court on August 26, 2016. On November 4, 2016, the Court issued its preliminary approval of the settlement, there were no objections to the settlement, and on January 30, 2017, the Court held a final settlement hearing.

On April 10, 2017, the Court issued an order denying the unopposed settlement and petition for plaintiffs’ counsel fees. On May 10, 2017, the parties reached an agreement on a revised settlement that reduced the plaintiffs’ counsel fees and dismissed, with prejudice, the plaintiffs’ claims. On May 16, 2017, the Court entered the final dismissal terminating the litigation.

 

Other Legal Proceedings

Please read “Note 7—Contingencies” and “Note 8—Environmental Liabilities” to the accompanying unaudited condensed consolidated financial statements under Part I, Item 1of this report for a discussion of other legal proceedings that we believe could be material to us.

Item 1A. Risk Factors

Shareholders and prospective investors should carefully consider the risk factors disclosed in our Form 10-K for the fiscal year ended December 31, 2016. There have been no material changes to such risk factors.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

The following documents are included as exhibits to this Form 10-Q:

 

 

*Filed herewith.

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

 

 

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