UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

FORM 10-Q

 

For the quarterly period ended March 31, 2018

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 May 1, 2018, 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 March 31, 2018

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, 2017, filed with the Securities and Exchange Commission on March 26, 2018.

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

Iberdrola refers to Iberdrola, S.A., which owns 81.5% of the outstanding shares of Avangrid, Inc.

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

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.

 

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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 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.

In December 2017, management committed to a plan to sell the gas storage and trading businesses because they represent non-core businesses that were not aligned with our strategic objectives. As a result, we determined that the assets and liabilities associated with our gas trading and storage businesses met the criteria for classification as assets held for sale, but did not meet the criteria for classification as discontinued operations. On March 1, 2018, the Company closed a transaction to sell Enstor Energy Services, LLC, which operated AVANGRID’s gas trading business, to CCI U.S. Asset Holdings LLC, a subsidiary of Castleton Commodities International, LLC (CCI). On May 1, 2018 the Company closed a transaction to sell Enstor Gas, LLC, which operated AVANGRID’s gas storage business, to Amphora Gas Storage USA, LLC. Additional details on held for sale classification are provided in Note 20 to our condensed consolidated financial statements.

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, 2017 and 2016 and for the three years ended December 31, 2017 included in AVANGRID’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017.

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 months ended March 31, 2018, are not necessarily indicative of the results for the entire fiscal year ending December 31, 2018.

 

Note 3. Significant Accounting Policies and New Accounting Pronouncements

As of March 31, 2018, the new accounting pronouncements that we have adopted as of January 1, 2018, and reflected in our consolidated financial statements are described below. There have been no other material changes to the significant accounting policies described in our consolidated financial statements as of December 31, 2017 and 2016, and for the three years ended December 31, 2017.

Adoption of New Accounting Pronouncements

(a) Revenue from contracts with customers

In May 2014 the Financial Accounting Standards Board (FASB) issued Accounting Standards Codification (ASC), Topic 606, Revenue from Contracts with Customers (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. The FASB further amended ASC 606 through various updates issued thereafter. The core principle is for an entity to recognize revenue to represent the transfer of promised 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. We adopted ASC 606 effective January 1, 2018, and applied the modified retrospective method, for which we did not have a cumulative effect adjustment to retained earnings for initial application of the guidance. Upon adoption, we classify production tax credits as income tax expense (benefit) rather than as operating revenue. Refer to Note 4 for further details.

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(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. An entity must apply the amendments at the same time that it applies the new ASC 606 revenue recognition standard. We adopted ASC 610-20 effective January 1, 2018, and applied the modified retrospective method, which affected the accounting for our tax equity investments. As shown in the table below, we recorded a cumulative adjustment that decreased retained earnings. The cumulative adjustment relates to the reclassification of our tax equity investments to noncontrolling interests. As a result, we recorded our tax equity investments based on the Hypothetical Liquidation at Book Value (HLBV) model and we will record changes in the HLBV at each reporting period within net income/loss attributable to noncontrolling interests.

The cumulative effects of the changes to our consolidated balance sheet as of January 1, 2018, for our adoption of ASC 606 and ASC 610-20 were as follows:

 

We also adopted the following standards as of their effective date of January 1, 2018, none of which had a material effect on our consolidated results of operations, financial position, cash flows, and disclosures.

(c) Classifying and measuring financial instruments

In January 2016 the FASB issued final guidance on the classification and measurement of financial instruments. As a result of our adoption we reclassified immaterial amounts from AOCI to retained earnings.

(d) Certain classifications in the statement of cash flows

In August 2016 the FASB issued amendments to address existing diversity in practice concerning the classification of certain cash receipts and payments on the statement of cash flows, which must be applied on a full retrospective basis. Upon adoption, we had no changes to our cash flow classifications and disclosures in our consolidated financial statements.

(e) 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. We retrospectively adopted the amendments that require us to present the service cost component separately from the other (non-service) components of net benefit cost, to report the service cost component in the income statement line item where we report the corresponding compensation cost, and to present all non-service components outside of operating cost. As a result, we have reclassified the non-service components – interest cost, expected return on plan assets, amortization of prior service cost (benefit), amortization of net loss, and settlement charge – from Operations and maintenance to Other income/(expense) within the statement of income. Prospectively, upon adoption, we will capitalize only the service cost component when applicable (for example, as a cost of a self-constructed asset). We elected to apply the practical expedient that allows us to retrospectively apply the amendments on adoption to net benefit costs for comparative periods by using the amounts disclosed in our notes to financial statements for Post-retirement and Similar Obligations as the basis for those periods. In addition to those amounts, we included amortization of net benefit costs recorded as regulatory deferrals as a result of purchase accounting in a prior year. In connection with applying the practical expedient, in periods after adoption we will continue to include in operating income all legacy net benefit costs previously capitalized as a cost of self-constructed assets and other deferred regulatory costs. Our adoption of the amendments did not affect net income attributable to AVANGRID.

The effect of the change in retrospective presentation related to the net periodic cost of our defined benefit pension and other postretirement employee benefits plans on our consolidated statement of income was as follows:

 

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The segment information related to our Networks reportable segment provided in Note 13 for the three months ended March 31, 2017 has also been revised to reflect the change as a result of the adoption of these amendments.

Accounting Pronouncements Issued But Not Yet Adopted

The following are new accounting pronouncements issued since December 31, 2017, that we have evaluated or are evaluating to determine their effect on our consolidated financial statements.

(a) Land easement practical expedient

In January 2018 the FASB issued amendments to clarify the application of the new leases guidance to land easements (also commonly called rights of way) and provide relief concerning adoption efforts for existing land easements that are not accounted for as leases under current GAAP. The updated guidance is effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early application is permitted. We are currently reviewing our contracts and are in the process of determining the proper application of the lease standard, including the land easement practical expedient, in order to determine the impact that the adoption will have on our consolidated financial statements. We expect our adoption of the new guidance will materially affect our financial position through the recording of operating leases on the balance sheet as right-of-use assets, along with the corresponding liabilities.

(b) Reclassification of certain tax effects from accumulated other comprehensive income

In February 2018 the FASB issued amendments to address a narrow-scope financial reporting issue that arose as a consequence of the Tax Cuts and Jobs Act of 2017 (the Tax Act) enacted on December 22, 2017, by the U.S. federal government. Under current guidance, the adjustment of deferred taxes for the effect of a change in tax laws or rates is required to be included in income from continuing operations, thus the associated tax effects of items within AOCI (referred to as stranded tax effects) do not reflect the appropriate tax rate. The amendments allow a reclassification from AOCI to retained earnings for stranded tax effects resulting from the Tax Act. As a result, the amendments eliminate the stranded tax effects resulting from the Tax Act and will improve the usefulness of information reported to financial statement users. The amendments only relate to the reclassification of the income tax effects of the Tax Act, and do not affect the underlying guidance that requires the effect of a change in tax laws or rates to be included in income from continuing operations. The amendments are effective for all entities for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted including, for public entities, adoption in any interim period for which financial statements have not been issued. An entity has the option to apply the amendments either in the period of adoption or retrospectively to each period (or periods) in which it recognizes the effect of the change in the U.S. federal corporate income tax rate in the Tax Act. An entity is required to disclose its accounting policy election, including its policy for reclassifying material stranded tax effects in AOCI to earnings (specific identification or portfolio method). We have not early adopted the amendments as of March 31, 2018. We expect our adoption of the amendments will not materially affect our consolidated results of operations, financial position, cash flows, and disclosures.

 

Note 4. Revenue

On January 1, 2018, we adopted ASC 606 and all related amendments using the modified retrospective method, which we applied only to contracts that were not completed as of January 1, 2018. For reporting periods beginning on January 1, 2018, we present revenue in accordance with ASC 606, and have not adjusted comparative prior period information, which we continue to report under the legacy accounting standards in effect for those prior periods. For the three months ended March 31, 2018, the effect of applying ASC 606 to recognize revenue as compared to applying the legacy accounting standards was not material.

We recognize revenue when we have satisfied our obligations under the terms of a contract with a customer, which generally occurs when the control of promised goods or services transfers to the customer. We measure revenue as the amount of consideration we expect to receive in exchange for providing those goods or services. Contracts with customers may include multiple performance obligations. For such contracts, we allocate revenue to each performance obligation based on its relative standalone selling price. We generally determine standalone selling prices based on the prices charged to customers. Certain revenues are not within the scope of ASC 606, such as revenues from leasing, derivatives, other revenues that are not from contracts with customers and other contractual rights or obligations, and we account for such revenues in accordance with the applicable accounting standards. We exclude from revenue amounts collected on behalf of third parties, including any such taxes collected from customers and remitted to governmental authorities. We do not have any material significant payment terms because we receive payment at or shortly after the point of sale.

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The following describes the principal activities, by reportable segment, from which we generate revenue. For more detailed information about reportable segments, refer to Note 13.

 

Networks Segment

Networks derives its revenue primarily from tariff-based sales of electricity and natural gas service to customers in New York, Connecticut, Maine and Massachusetts, with no defined contractual term. For such revenues, we recognize revenues in an amount derived from the commodities delivered to customers. Other major sources of revenue are electricity transmission and wholesale sales of electricity and natural gas.

Tariff-based sales are subject to the corresponding state regulatory authorities, which determine prices and other terms of service through the ratemaking process. Maine State law prohibits the utility from providing the electricity commodity to customers. In New York, Connecticut and Massachusetts, customers have the option to obtain the electricity or natural gas commodity directly from the utility or from another supplier. For customers that receive their commodity from another supplier, the utility acts as an agent and delivers the electricity or natural gas provided by that supplier. Revenue in those cases is only for providing the service of delivery of the commodity. Networks entities calculate revenue earned but not yet billed based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. Differences between actual and estimated unbilled revenue are immaterial.

Transmission revenue results from others’ use of the utility’s transmission system to transmit electricity and is subject to FERC regulation, which establishes the prices and other terms of service. Long-term wholesale sales of electricity are based on individual bilateral contracts. Short-term wholesale sales of electricity are generally on a daily basis based on market prices and are administered by the NE-ISO, NYISO, or PJM as applicable. Wholesale sales of natural gas are generally short-term based on market prices through contracts with the specific customer.

The performance obligation in all arrangements is satisfied over time because the customer simultaneously receives and consumes the benefits as Networks delivers or sells the electricity or natural gas or provides the transmission service. We record revenue for all of those sales based upon the regulatory-approved tariff and the volume delivered or transmitted, which corresponds to the amount that we have a right to invoice. There are no material initial incremental costs of obtaining a contract in any of the arrangements. Networks does not adjust the promised consideration for the effects of a significant financing component if it expects, at contract inception, that the time between the delivery of promised goods or service and customer payment will be one year or less. Networks does not have any material significant payment terms because it receives payment at or shortly after the point of sale. For its New York utilities, Networks assesses its deferred payment arrangements at each balance sheet date for the existence of significant financing components, but has had no material adjustments as a result.

Certain Networks entities record revenue from Alternative Revenue Programs (ARPs), which is not ASC 606 revenue. Such programs represent contracts between the utilities and their regulators. The Networks ARPs include revenue decoupling mechanisms, other ratemaking mechanisms, annual revenue requirement reconciliations, and other demand side management programs. The Networks entities recognize and record only the initial recognition of “originating” ARP revenues (when the regulatory-specified conditions for recognition have been met). When they subsequently include those amounts in the price of utility service billed to customers, they record such amounts as a recovery of the associated regulatory asset or liability. When they owe amounts to customers in connection with ARPs, they evaluate those amounts on a quarterly basis and include them in the price of utility service billed to customers and do not reduce ARP revenues.

Networks also has various other sources of revenue including billing, collection, other administrative charges, sundry billings, rent of utility property, and miscellaneous revenue. It classifies such revenues as other ASC 606 revenues to the extent they are not related to revenue generating activities from leasing, derivatives, or ARPs.

Renewables Segment

Renewables derives its revenue primarily from the sale of energy, transmission, capacity and other related charges from its renewable wind, solar, and thermal energy generating sources. For such revenues, we will recognize revenues in an amount derived from the commodities delivered and from services as they are made available. Renewables has bundled power purchase agreements consisting of electric energy, transmission, capacity and/or renewable energy credits (RECs). The related contracts are generally long-term with no stated contract amount, that is, the customer is entitled to all of the unit’s output. Renewables also has unbundled sales of electric energy and capacity, RECs and natural gas, which are generally for periods of less than a year. The performance obligations in substantially all of both bundled and unbundled arrangements for electricity and natural gas are satisfied over time, for which we record revenue based on the amount invoiced to the customer for the actual energy delivered. The performance obligation for stand-alone RECs is satisfied at a point in time, for which we record revenue when the performance obligation is satisfied upon delivery of the REC. Renewables does not have any material significant payment terms because it receives payment at or shortly after the point of sale. There are no material initial incremental costs of obtaining a contract or significant financing elements in any of the arrangements.

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Renewables classifies certain contracts for the sale of electricity as either leases or derivatives, in accordance with the applicable accounting standards. Renewables also has revenue from its energy trading operations, which it generally classifies as derivative revenue. However, trading contracts not classified as derivatives are within the scope of ASC 606, with the performance obligation of the delivery of energy (electricity, natural gas) and settlement of the contracts satisfied at a point in time at which time we recognize the revenue. Renewables also has other ASC 606 revenue, which we recognize based on the amount invoiced to the customer.

Certain customers may receive cash credits, which we account for as variable consideration. Renewables estimates those amounts based on the expected amount to be provided to customers and reduces revenues recognized. We believe that there will not be significant changes to our estimates of variable consideration.

Other

Other, which does not represent a segment, derives its revenues primarily from providing natural gas storage services to customers, gas trading operations generally classified as derivative revenue in accordance with the applicable accounting standards, gas trading contracts not classified as derivatives, and other miscellaneous revenues including intersegment eliminations.

Contract Costs and Practical Expedient

We recognize an asset for incremental costs of obtaining a contract with a customer when we expect the benefit of those costs to be longer than one year. Renewables has an origination sharing bonus plan that meets the requirements for capitalization. Costs incurred prior to 2018 were insignificant and not capitalized. Costs capitalized to date in 2018 are also insignificant, with amortization on a straight-line basis over the term of the related contract for which the terms may be from three years to 20 years. We apply a practical expedient to expense as incurred costs to obtain a contract when the amortization period is one year or less. We record costs incurred to obtain a contract within operating expenses, including amortization of capitalized costs.

Revenues disaggregated by major source for our reportable segments are as follows:

 

As of March 31, 2018, accounts receivable balances related to contracts with customers were approximately $1,076 million, which are included in “Accounts receivable and unbilled revenues, net” on our condensed consolidated balance sheets.

As of March 31, 2018, for contracts with durations greater than one year (1) the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied), and (2) when we expect to recognize the revenue, were as follows:

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We did not include disclosures for unsatisfied performance obligations for Gas in the table above due to the expected sale of the Gas business in the second quarter of 2018. We do not disclose information about remaining performance obligations for (i) contracts with an original expected duration of one year or less and (ii) contracts for which we recognize revenue in the amount to which we have the right to invoice (e.g., usage-based pricing terms).

 

Note 5. 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 $1,867 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 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 the actual up to 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 earnings sharing levels further increase in rate year three (May 1, 2018 – April 30, 2019) to 9.75%, 10.25% and 10.75% 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

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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 requested a three-year rate plan for calendar years 2018, 2019 and 2020 and a proposed ROE of 9.95%.  SCG also requested 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 included 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. Any dollars due to customers from the ESM will be first applied against any environmental regulatory asset balance as defined in the settlement agreement (if one exists at that time) or refunded to customers through a bill credit if such environmental regulatory asset balance does not exist. 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 approved the amended rate case settlement agreement on December 13, 2017, and new tariffs became effective on January 1, 2018.

Current and non-current regulatory assets as of March 31, 2018 and December 31, 2017, respectively, consisted of:

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“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 March 31, 2018.

“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.

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“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.

“Reliability support services” represents the difference between actual expenses for reliability support services and the amount provided for in rates.

“Other” includes post term amortization deferrals and various items subject to reconciliation including rate change levelization, loss on re-acquired debt and power tax deferral.

Current and non-current regulatory liabilities as of March 31, 2018 and December 31, 2017, respectively, consisted of:

 

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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.

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“Energy efficiency portfolio standard” represents the difference between revenue billed to customers through an energy efficiency charge and the costs of our energy efficiency programs as approved by the state authorities. This may be refunded to customers within the next year.

“Accrued removal obligations” represent the differences between asset removal costs recorded and amounts collected in rates for those costs. The amortization period is dependent upon the asset removal costs of underlying assets and the life of the utility plant.

“Asset sale gain account” represents the gain on NYSEG’s 2001 sale of its interest in Nine Mile Point 2 nuclear generating station 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.

“Tax Act - remeasurement” represents the impact from remeasurement of deferred income tax balances as a result of the Tax Act enacted by the U.S. federal government on December 22, 2017. Reductions in accumulated deferred income tax balances due to the reduction in the corporate income tax rates from 35% to 21% under the provisions of the Tax Act will result in amounts previously collected from utility customers for these deferred taxes to be refundable to such customers, generally through reductions in future rates. The NYPSC, MPUC, PURA and DPU have instituted separate proceedings in New York, Maine, Connecticut and Massachusetts to review and address the implications associated with the Tax Act on the utilities providing service in those states.

“Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. In the three months ended March 31, 2018 and 2017, respectively, $1 and $2 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.

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“Low Income Programs” represent various hardship and payment plan programs approved for recovery.

“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 6. 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 $5 million as of both March 31, 2018 and December 31, 2017, which is included in “Other Assets” on the balance sheet.

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The financial instruments measured at fair value as of March 31, 2018 and December 31, 2017, respectively, consisted of:

 

 

 

Included in the derivative financial instruments – gas are derivative assets and liabilities of Gas segment classified as held for sale on the condensed consolidated balance sheet as of December 31, 2017. See Note 20 – Assets Held For Sale for further discussion.

The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three months ended March 31, 2018 and 2017, respectively, is as follows:

 

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 7 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 March 31, 2018 and December 31, 2017, 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 $5,625 million and $5,799 million as of March 31, 2018 and December 31, 2017, 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 March 31, 2018 and December 31, 2017, 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.

 

Note 7. 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 $11.5 million and $0.2 million as of March 31, 2018 and December 31, 2017, respectively. The amount reclassified from regulatory assets and liabilities into income, which is included in electricity purchased, was a gain of $5.8 million and a loss of $10.9 million, for the three months ended March 31, 2018 and 2017, 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 $0.2 million and $2.5 million as of March 31, 2018 and December 31, 2017, respectively. The amount reclassified from regulatory assets and liabilities into income, which is included in natural gas purchased, was a loss of $1.7 million and a gain of $0.6 million, for the three months ended March 31, 2018 and 2017, 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 March 31, 2018, UI has recorded a gross derivative asset of $10 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $103 million, a gross derivative liability of $113 million ($100 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, 2017, UI had recorded a gross derivative asset of $12 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $93 million, a gross derivative liability of $104 million ($90 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0.

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The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets or regulatory liabilities, for the three months ended March 31, 2018 and 2017, respectively, were as follows:

 

 

The net notional volumes of the outstanding derivative instruments associated with Networks activities as of March 31, 2018 and December 31, 2017, respectively, consisted of:

 

 

The offsetting of derivatives, location in the condensed consolidated balance sheet and amounts of derivatives associated with Networks activities as of March 31, 2018 and December 31, 2017, respectively, consisted of:

 

 

 

The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three months ended March 31, 2018 and 2017, respectively, consisted of:

 

 

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(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 $66.8 million and $68.8 million as of March 31, 2018 and December 31, 2017, respectively. We recorded $2.0 million and $2.0 million in net derivative losses related to discontinued cash flow hedges for the three months ended March 31, 2018 and 2017, respectively. We will amortize approximately $8.0 million of discontinued cash flow hedges in 2018. During the three months ended March 31, 2018 and 2017, there was no ineffective portion for cash flow hedges.

The unrealized loss of $0.2 million on hedge activities is reported in OCI because the forecasted transaction is considered to be probable as of March 31, 2018. We expect that $0.2 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

The below presented information includes derivative financial instruments associated with Gas activities, which were classified as held for sale in the condensed consolidated balance sheet as of December 31, 2017 (see Note 20 - Assets Held for Sale).

We sell fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. We also purchase fixed-price gas and basis swaps and sell fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets. We also enter into tolling arrangements to sell the output of our thermal generation facilities.

Our gas business purchases and sells both fixed-price gas and basis swaps to hedge the value of contracted storage positions. The intent of entering into these swaps is to fix the margin of gas injected into storage for subsequent resale in future periods. We also enter into basis swaps to hedge the value of our contracted transport positions. The intent of buying and selling these basis swaps is to fix the location differential between the price of gas at the receipt and delivery point of the contracted transport in future periods.

Both Renewables and Gas have proprietary trading operations that enter into fixed-price power and gas forwards in addition to basis swaps. The intent is to speculate on fixed-price commodity and basis volatility in the U.S. commodity markets.

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.

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The net notional volumes of outstanding derivative instruments associated with Renewables and Gas activities as of March 31, 2018 and December 31, 2017, respectively, consisted of:

 

 

The fair values of derivative contracts associated with Renewables and Gas activities as of March 31, 2018 and December 31, 2017, respectively, consisted of:

 

 

The effect of trading derivatives associated with Renewables and Gas activities for the three months ended March 31, 2018 and 2017, respectively, consisted of:

 

The effect of non-trading derivatives associated with Renewables and Gas activities for the three months ended March 31, 2018 and 2017, 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.

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The offsetting of derivatives, location in the condensed consolidated balance sheet and amounts of derivatives associated with Renewables and Gas activities as of March 31, 2018 and December 31, 2017, respectively, consisted of:

 

 

 

The effect of derivatives in cash flow hedging relationships on OCI and income for the three months ended March 31, 2018 and 2017, 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 $3.7 million of gain included in accumulated OCI at March 31, 2018, is expected to be reclassified into earnings within the next twelve months. During the three months ended March 31, 2018 and 2017, we recorded a net gain of $0.1 million and a net loss of $0.3 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 March 31, 2018, out of which $0.2 million will be amortized in 2018.

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(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 March 31, 2018, UI would have had to post an aggregate of approximately $15 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 $2 million and $30 million as of March 31, 2018 and December 31, 2017, 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 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 March 31, 2018 is $11.7 million, for which we have posted collateral.

 

Note 8. Contingencies

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. We do not provide for accrual of legal costs expected to be incurred in connection with a loss contingency.

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, MEPCO and UI are New England Transmission Owners (NETOs) with assets and service rates that are governed by the OATT and will thereby be affected by any FERC order resulting from the filed complaint.

On June 19, 2014, the FERC issued its 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 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 determined 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 ROE of 10.57% 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

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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 FERC reasoned that 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 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 $22.7 million and $4.4 million, respectively, as of March 31, 2018, which has not changed since December 31, 2017, 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. 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. On November 21, 2017, the parties submitted updates to their ROE analyses and recommendations just prior to hearings with the NETOs continuing to advocate that the existing base ROE of 10.57% should remain in effect. Hearings were held in December 2017 and on March 27, 2018, the Administrative Law Judge issued a decision rejecting Complaint IV, finding the currently-filed base ROE of 10.57%, which with incentive adders may reach a maximum ROE of 11.74%, is not unjust and unreasonable, and hence is not unlawful. 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. FERC has not yet ruled on this Motion. 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

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 included 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.

On November 16, 2017, the NYPSC announced that the Department Staff had completed their investigation into the March 2017 Windstorm and the NYPSC issued an Order Instituting Proceeding and to Show Cause. The Staff’s investigation found that RG&E and NYSEG violated certain parts of their emergency response plans, which makes them subject to possible financial penalties.  NYSEG and RG&E responded to the order in a timely manner and have entered into settlement discussions with the Department Staff. We cannot predict the outcome of this regulatory action.

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 requirements. The parties have submitted to FERC briefs on exceptions to the administrative law judge’s proposed ruling. In April 2018 Renewables requested, based on the nearly two years of delay from the preliminary proposed ruling and the Supreme Court precedent, that FERC issue a final decision expeditiously. We cannot predict the outcome of this proceeding.

Class Action Regarding LDC Gas Transportation Service on Algonquin Gas Transmission

On November 16, 2017, a class action lawsuit was filed in the U.S. District Court in Massachusetts on behalf of customers in New England against the Company and Eversource alleging that certain of their respective subsidiaries that take gas transportation service over the Algonquin Gas Transmission, AGT, which for AVANGRID would be its indirect subsidiaries SCG and CNG, engaged in pipeline capacity scheduling practices on AGT that resulted in artificially increased electricity prices in New England. These allegations were based on the conclusions of a White Paper issued by the Environmental Defense Fund (EDF), an environmental advocacy organization, on October 10, 2017, purporting to analyze the relationship between the New England electricity market and the New England local gas distribution companies. The plaintiffs assert claims under federal antitrust law, state antitrust, unfair competition and consumer protection laws, and under the common law of unjust enrichment.  They seek damages, disgorgement, restitution, injunctive relief, and attorney fees and costs. The Company filed a Motion to Dismiss all of the claims on January 29, 2018.  On February 27, 2018, the FERC released the results of a FERC staff inquiry into the pipeline capacity scheduling practices on the AGT. The inquiry arose out of the allegations made by the EDF in its White Paper. FERC announced that, based on an extensive review of public and non-public data, it had determined that the EDF study was flawed and led to incorrect conclusions. FERC also stated that the staff inquiry revealed no evidence of anticompetitive withholding of natural gas pipeline capacity on the AGT and that it would take no further action on the matter. On March 28, 2018, the plaintiffs filed a consolidated amended complaint, repeating the prior claims, except omitting the common law claim of unjust enrichment. On April 27, 2018, the Company filed a Motion to Dismiss all of the claims based on federal preemption and lack of any evidence of antitrust behavior, citing, among other reasons, the results of the FERC staff inquiry conclusion. Nevertheless, we cannot predict the outcome of this class action lawsuit.

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Guarantee Commitments to Third Parties

As of March 31, 2018, we had approximately $2.2 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 March 31, 2018, neither we nor our subsidiaries have any liabilities recorded for these instruments.

 

Note 9. 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 $5 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 $21 million as of March 31, 2018. 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; twelve 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 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 $213 million to $442 million as of March 31, 2018. 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 March 31, 2018 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 March 31, 2018 and December 31, 2017, 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 $100 million, respectively.

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The total liability to investigate and perform remediation at the known inactive MGP sites and other sites was $387 million and $389 million as of March 31, 2018 and December 31, 2017, 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 2054.

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 $22 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 OneBeacon 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, which was denied by an order dated March 27, 2018. NYSEG filed a notice appealing the District Court’s dismissal on April 9, 2018. 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. In December 2017 Plaintiffs filed a Request for Leave to Amend Complaint and Motion to Cite-In Additional Parties, including former UIL officers and employees and other UI officers, which motion was approved in February 2018. We cannot predict the outcome of this matter.

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.

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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. 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, 2017, we reserved $25 million for this matter. As of March 31, 2018, the reserve amount remained unchanged. We cannot predict the outcome of this matter.

 

Note 10. Post-retirement and Similar Obligations

We made $2 million of pension contributions for the three months ended March 31, 2018. We expect to make additional contributions of $46 million for the remainder of 2018.

The components of net periodic benefit cost for pension benefits for the three months ended March 31, 2018 and 2017, respectively, consisted of:

 

 

The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2018 and 2017, respectively, consisted of:

 

 

Beginning in 2018, in the condensed consolidated statement of income, we include the service cost component in other operating expenses net of capitalized portion, and include the components of net periodic benefit cost other than the service cost component in the line item “Other income / (expense).”

 

Note 11. Equity

As of March 31, 2018, our share capital consisted of 500,000,000 shares of common stock authorized, 309,752,140 shares issued and 309,086,480 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 $13,654 million. As of December 31, 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 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

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capital of $13,653 million. We had 485,810 shares of common stock held in trust and no convertible preferred shares outstanding as of both March 31, 2018 and December 31, 2017, respectively. During the three months ended March 31, 2018, we issued 81,208 shares of common stock each having a par value of $0.01 and released no shares of common stock held in trust. During the three months ended March 31, 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.

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 March 31, 2018, 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 March 31, 2018.

Accumulated Other Comprehensive Loss

 

Accumulated Other Comprehensive Gain (Loss) for the three months ended March 31, 2018 and 2017, respectively, consisted of:

 

 

 

 

Note 12. 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 months ended March 31, 2018 and 2017, 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 months ended March 31, 2018 and 2017.

The calculations of basic and diluted earnings per share attributable to AVANGRID, for the three months ended March 31, 2018 and 2017, respectively, consisted of:

 

 

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Note 13. 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 two reportable segments:

Based on the quantitative assessment and due to the disposition of gas trading and storage businesses (see Note 20 – Assets Held For Sale for further discussion) Gas segment no longer meets the reportable segment criteria effective in the first quarter of 2018. As a result, the prior period segment information has been restated to conform to the 2018 presentation.

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 as of and for the three months ended March 31, 2018, consisted of:

 

Included in revenue-external for the three months ended March 31, 2018, are: $955 million from regulated electric operations, $600 million from regulated gas operations and $(6) million amounts from other operations of Networks; $283 million from renewable energy generation of Renewables.

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Segment information for the three months ended March 31, 2017, consisted of:

 

 

Included in revenue-external for the three months ended March 31, 2017, are: $921 million from regulated electric operations, $537 million from regulated gas operations and $2 million amounts from other operations of Networks; $285 million from renewable energy generation of Renewables.

Reconciliation of consolidated Adjusted EBITDA to the AVANGRID consolidated Net Income for the three months ended March 31, 2018 and 2017, respectively, is as follows:

 

 

Note 14. 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 March 31, 2018 and 2017, respectively, consisted of:

 

 

 

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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 $0 and $266 million for the periods ended March 31, 2018 and December 31, 2017, respectively.

Related party balances as of March 31, 2018 and December 31, 2017, respectively, consisted of:

 

Transactions with Iberdrola, our majority shareholder, relate predominantly to the provision and allocation of corporate services and management fees. 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 $31 million and $29 million as of March 31, 2018 and December 31, 2017, 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 both March 31, 2018 and December 31, 2017, the amount receivable from New York TransCo was $6 million.

AVANGRID manages its overall liquidity position as part of the broader Iberdrola Group and is a party to a liquidity 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 liquidity agreement. The balance at both March 31, 2018 and December 31, 2017, was zero.

 

 

Note 15. Supplemental Balance Sheet Information

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 $59 million and $55 million at March 31, 2018 and December 31, 2017, respectively. The allowance for doubtful accounts for DPAs at March 31, 2018 and December 31, 2017, was $31 million and $30 million, respectively. Furthermore, the provision for bad debts associated with the DPAs for the three months ended March 31, 2018 and 2017 was $1 million for both periods.

 

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Prepayments and other current assets

Included in “Prepayments and other current assets” are $151 million and $194 million of prepaid other taxes as of March 31, 2018 and December 31, 2017, respectively.

Property, plant and equipment and intangible assets

The accumulated depreciation and amortization as of March 31, 2018 and December 31, 2017, respectively, were as follows:

 

 

 

Note 16. Income Tax Expense

The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2018, was 23.2%, which is higher than the 21% statutory federal income tax rate, applicable in 2018, predominantly due to discrete tax adjustments recorded during the period offset by 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 March 31, 2017, was 30.1%, which was lower than the 35% statutory federal income tax rate, applicable in 2017, predominantly due to the recognition of production tax credits associated with wind production. Additionally, $14 million in income tax expense for the three months ended March 31, 2017, 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. This was offset by other discrete tax adjustments during the period.

 

Note 17. Stock-Based Compensation Expense

Pursuant to the 2016 Avangrid, Inc. Omnibus Incentive Plan 21,532 additional performance stock units (PSUs) were granted to certain officers and employees of AVANGRID in March 2018. 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.

The total stock-based compensation (credit) expense, which is included in operations and maintenance of the condensed consolidated statements of income, for the three months ended March 31, 2018 and 2017 was $(0.1) 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 was settled in March 2018. The total liability relating to those awards, which was included in other current liabilities, was $5.5 million as of December 31, 2017.

 

Note 18. Variable Interest Entities

We participate in certain partnership arrangement that qualify as variable interest entities (VIEs). These arrangements consist of tax equity financing arrangements (TEFs) and partnerships in which an investor holds a noncontrolling interest and the investor does not have substantive kick-out or participating rights.

The sale of a membership interest in the TEFs represents the sale of an equity interest in a structure that is considered a sale of non-financial assets. Under the sale of non-financial assets, the membership interests in the TEFs we sell to third-party investors are reflected as noncontrolling interest in the condensed consolidated balance sheets valued based on a HLBV model. Earnings from the TEFs are recognized in earnings attributable to noncontrolling interests in the condensed consolidated statements of income. We consolidate the entities that have TEFs based on being the primary beneficiary for these VIEs.

The assets and liabilities of the VIEs totaled approximately $1,432 million and $91 million, respectively, at March 31, 2018. As of December 31, 2017, the assets and liabilities of VIEs totaled approximately $1,441 million and $185 million, respectively. At March 31, 2018 and December 31, 2017, the assets and liabilities of the VIEs consisted primarily of property, plant and equipment, equity method investments and TEF liabilities. At March 31, 2018 and December 31, 2017, equity method investments of VIEs were approximately $106 million and $107 million, respectively.

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At March 31, 2018 we consider Aeolus Wind Power II LLC and Aeolus Wind Power IV LLC, (collectively, Aeolus) to be TEFs and El Cabo Wind, LLC to be 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. 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 19. Restructuring and Severance Related Expenses

In 2017, we announced initial targeted voluntary workforce reductions, predominantly within the Networks segment. Those actions primarily include: reducing our workforce through voluntary programs in various other areas to better align our people resources with business demands and priorities; reorganizing our human resources function to substantially consolidate in Connecticut, as well as related costs to vacate a lease and relocate employees; and reducing our information technology (IT) workforce to make increasing use of external services for operations, support, and development of systems. Those decisions and transactions resulted in restructuring charges recorded in the three months ended March 31, 2018 for severance expenses of $1.2 million, which are included in “Operations and maintenance” in the condensed consolidated statements of income. The remaining costs for severance agreements are being accrued ratably over the remaining service periods, which span intermittent periods through December 2018. Accordingly, the Company expects additional costs to be incurred in 2018 related to the remaining employee service periods under the severance plans. For the three months ended March 31, 2018, the severance and lease restructuring charges reserves, which are recorded in “Other current liabilities” and “Other liabilities”, consisted of:

 

 

Note 20. Assets Held For Sale

In December 2017, our management committed to a plan to sell the gas trading and storage businesses because they represent non-core businesses that were not aligned with our strategic objectives. As a result, we determined that the assets and liabilities associated with our gas trading and storage businesses met the criteria for classification as assets held for sale, but did not meet the criteria for classification as discontinued operations.  On March 1, 2018, the Company closed a transaction to sell Enstor Energy Services, LLC, which operated AVANGRID’s gas trading business, to CCI U.S. Asset Holdings LLC, a subsidiary of Castleton Commodities International, LLC (CCI) for $66 million, subject to working capital, cash, and other adjustments. The transaction price did not differ materially from the estimated fair value of our gas trading business at December 31, 2017, but is subject to adjustment based on closing and other contract provisions, including certain transition services. On May 1, 2018, the Company closed a transaction to sell Enstor Gas, LLC, which operated AVANGRID’s gas storage business, to Amphora Gas Storage USA, LLC for $66 million, subject to working capital, cash, and other adjustments. The transaction price was lower than the estimated fair value of our gas storage business at March 31, 2018 by approximately $9 million due to initial working capital and other adjustments. The agreement to sell Enstor Gas,

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LLC contains, among other things, a transition services agreement which obligates ARHI to provide certain transition services for up to one year after the closing date, along with representations, warranties, and covenants customary for a transaction of this nature. In connection with the held for sale classification, we recorded a loss from held for sale measurement of $5.3 million, which is included in “Loss from assets held for sale” in the condensed consolidated statements of income in the three months ended March 31, 2018. Income before income tax, adjusted for corporate overhead, attributed to the gas businesses was $18.3 million and $2.6 million for the three months ended March 31, 2018 and 2017, respectively. The current assets and current liabilities held for sale relating to our gas trading and storage businesses consisted of the following as of March 31, 2018 and December 31, 2017:

 

 

The fair values of the assets held for sale were determined using Level 3 inputs and were estimated based on recent market analysis studies, recent offers, and management has performed its own fair valuation modeling using discounted cash flows updated for market participant assumptions as completed by third party valuation firms. Unobservable inputs obtained from third parties were adjusted as necessary for the condition and attributes of the specific assets.

 

Note 21. Subsequent Events

On April 25, 2018, the board of directors of AVANGRID declared a quarterly dividend of $0.432 per share on its common stock. This dividend is payable on July 2, 2018 to shareholders of record at the close of business on June 8, 2018.

On May 1, 2018, pursuant to the stock repurchase program, we repurchased 81,208 shares of AVANGRID common stock in the open market. The total cost of repurchase, including commissions, was $4 million.

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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, 2017 and 2016, and for the three years ended December 31, 2017, included in our Annual Report on Form 10-K for the year ended December 31, 2017, filed with the Securities and Exchange Commission, or the SEC, on March 26, 2018, 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 leading sustainable energy company with approximately $31 billion in assets and operations in 26 states. The AVANGRID has two primary lines of business - Avangrid Networks and Avangrid Renewables. Avangrid Networks owns eight electric and natural gas utilities, serving 3.2 million customers in New York and New England. Avangrid Renewables owns and operates 7.1 gigawatts of electricity capacity, primarily through wind power, with a presence in 22 states across the United States. AVANGRID supports the U.N.’s Sustainability Development Goals, received a CDP climate score of “A-”, the top score received in the utilities sector, and has been recognized for two consecutive years by Ethical Boardroom as North American utility with the “best corporate governance practices.” AVANGRID employs approximately 6,600 people. Iberdrola S.A., 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 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 business through Enstor Inc.  

In December 2017, our management committed to a plan to sell the gas storage and trading businesses because they represent non-core businesses that are not aligned with our strategic objectives. As a result, we determined that the assets and liabilities associated with our gas trading and storage businesses met the criteria for classification as assets held for sale, but did not meet the criteria for classification as discontinued operations. On March 1, 2018, the Company closed a transaction to sell Enstor Energy Services, LLC, which operated AVANGRID’s gas trading business, to CCI U.S. Asset Holdings LLC, a subsidiary of Castleton Commodities International, LLC (CCI). On May 1, 2018, the Company closed a transaction to sell Enstor Gas, LLC, which operated the AVANGRID’s gas storage business, to Amphora Gas Storage USA, LLC. The agreement included, among other things, a transition services agreement which obligates ARHI to provide certain transition services for up to one year after the closing date and includes a guarantee the Company will release certain obligations to Amphora Gas Storage USA, LLC. Additional details on held for sale classification are provided in Note 20 to our condensed consolidated financial statements contained in this Quarterly Report on Form 10-Q.

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 March 31, 2018.

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:

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Through Renewables, we had a combined wind, solar and thermal installed capacity of 7,129 megawatts, or MW, as of March 31, 2018, including Renewables’ share of joint projects, of which 6,387 MW was installed wind capacity. Approximately 73% of the capacity was contracted as of March 31, 2018, for an average period of 9.4 years. Being among the top three largest wind operators in the United States based on installed capacity as of March 31, 2018, Renewables strives to lead the transformation of the U.S. energy industry to a competitive, clean energy future. Renewables currently operates 58 wind farms in 21 states across the United States.

Through Gas, as of March 31, 2018, we owned approximately 67.5 billion cubic feet, or Bcf, of net working gas storage capacity.

Summary of Results of Operations

Our operating revenues increased by 6%, from $1.8 billion for the three months ended March 31, 2017 to $1.9 billion for the three months ended March 31, 2018.

The Networks business revenues increased on the impact of higher average rates and increase in degree days from colder weather. Renewables had a slight decrease in revenue mainly due to unfavorable MtM changes on energy derivative transactions and lower average prices.

Net income attributable to Avangrid increased by 2% from $239 million for the three months ended March 31, 2017, to $244 million for the three months ended March 31, 2018. Networks net income improved due to impacts from the implementation of rate plans. Renewables net income decreased as a result of higher unfavorable MtM changes on energy derivatives and decline in average prices which was partially offset by increased production.

Adjusted earnings before interest, tax, depreciation and amortization, or adjusted EBITDA (a non-GAAP financial measure), before adjustments to reflect the classification of revenues and expenses by nature and before excluding restructuring charges, loss from held for sale measurement, the impact from mark-to-market activities in Renewables and Gas storage business, decreased by 2% from $624 million for the three months ended March 31, 2017, to $611 million for the three months ended March 31, 2018. Adjusted gross margin (a non-GAAP financial measure) before adjustments to reflect the classification of revenues and expenses by nature and before excluding restructuring charges, loss from held for sale measurement, the impact from mark-to-market activities in Renewables and Gas storage business, decreased by 1%, from $1,229 million for the three months ended March 31, 2017 to $1,219 million for the three months ended March 31, 2018. The decrease in the non-GAAP adjusted EBITDA and non-GAAP adjusted gross margin is primarily driven by the adverse impact of the tax reform on regulated revenue with an offsetting decrease to income tax expense along with an increase in average prices and overall units of electricity and gas procured in the period at Networks.

Adjusted EBITDA (a non-GAAP financial measure) after adjustments to reflect the classification of revenues and expenses by nature and after excluding restructuring charges, loss from held for sale measurement, the impact from mark-to-market activities in Renewables and Gas storage business, increased by 2% from $598 million for the three months ended March 31, 2017, to $608 million for the three months ended March 31, 2018. Adjusted gross margin (a non-GAAP financial measure) after adjustments to reflect the classification of revenues and expenses by nature and after excluding restructuring charges, loss from held for sale measurement, the impact from mark-to-market activities in Renewables and Gas storage business, increased by 1%, from $1,117 million for the three months ended March 31, 2017 to $1,129 million for the three months ended March 31, 2018. The increase in the non-GAAP adjusted EBITDA and non-GAAP adjusted gross margin is primarily driven by increased capacity and higher production tax credits offset by unfavorable changes in prices in the period at Renewables.

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,

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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, 2017.

Transmission - ROE Complaint IV

On November 21, 2017, the parties to the Complaint IV submitted updates to their ROE analyses and recommendations just prior to hearings with the NETOs continuing to advocate that the existing base ROE of 10.57% should remain in effect. Hearings were held in December 2017 and on March 27, 2018, the Administrative Law Judge issued a decision rejecting Complaint IV, finding the currently-filed base ROE of 10.57%, which with incentive adders may reach a maximum ROE of 11.74%, is not unjust and unreasonable, and hence is not unlawful. We cannot predict the outcome of the Complaint IV proceeding.

Tax Act proceedings

The “Tax Cuts and Jobs Act”, or the Tax Act, changed significantly the federal taxation of business entities, including among other things, a federal corporate tax rate decrease from 35% to 21% for tax years beginning after December 31, 2017. Reductions in accumulated deferred income tax balances due to the reduction in the corporate income tax rates will result in amounts previously collected from utility customers for these deferred taxes to be refundable to such customers, generally through reductions in future rates. The NYPSC, MPUC, PURA, DPU and FERC have instituted separate proceedings in New York, Maine, Connecticut, Massachusetts and FERC to review and address the implications associated with the Tax Act on the utilities providing service in those states.

In New York, the NYPSC Staff issued a proposal on March 29, 2018, whereby the Staff recommends Tax Act benefits be returned to customers beginning October 1, 2018.  Comments on the Staff proposal will be submitted by all parties and our NY utility companies, NYSEG and RG&E, by June 27, 2018. The companies have indicated to the NYPSC that they believe Tax Act benefits should not be entirely immediately flowed back to customers, but utilized for other utility programs for the benefit of customers, including for new projects such as Automated Metering Infrastructure, or AMI, other future resiliency investments and to recover deferred regulatory assets. We expect a NYPSC decision in the third quarter of 2018.  In Connecticut, UI and SCG expect Tax Act savings to be deferred until they are reflected in tariffs in a future rate case unless PURA determines otherwise.  CNG and Berkshire anticipate Tax Act savings to be included in rate cases expected to be filed in the second quarter of 2018. In Maine, CMP has proposed to utilize the income statement Tax Act savings as an offset to the recovery of deferred 2017 storm costs. At FERC, CMP transmission and UI transmission expect the income statement value of Tax Act savings to be reflected in tariffs beginning June 2018. 

 

Results of Operations

The following table sets forth financial information by segment for each of the periods indicated. Based on the quantitative assessment and due to the disposition of gas trading and storage businesses (see Note 20 – Assets Held For Sale for further discussion) Gas segment no longer meets the reportable segment criteria effective in the first quarter of 2018. As a result, the prior period segment information has been restated to conform to the 2018 presentation. Additionally, as a result of the adoption of the amendments issued by the FASB in March 2017 to improve the presentation of net periodic pension cost and net periodic postretirement benefit cost, we have reclassified the non-service components of those costs from Operations and maintenance to Other income/(expense) within the condensed consolidated statement of income and applied these amendment retrospectively to prior periods. For further details, refer to Note 3 of our condensed consolidated financial statements for the three months ended March 31, 2018.

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(1)Other amounts represent Corporate, Gas and intersegment eliminations.

 

Comparison of Period to Period Results of Operations

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

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 increased by $94 million, or 5%, from $1.8 billion for the three months ended March 31, 2017 to $1.9 billion for the three months ended March 31, 2018, as detailed by segment below:

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Networks

Operating revenues increased by $93 million, or 6%, from $1,552 million for the three months ended March 31, 2017 to $1,459 million for the three months ended March 31, 2018. Electricity and gas revenues increased by $18 million and $10 million, respectively, due to primarily the impact of higher average rates in the three months period ended March 31, 2018 compared to the same period of 2017. Electricity and gas revenues for the same period increased by $29 million and $43 million due to higher volumes largely driven by increase in degree days from colder weather. The wholesale electricity revenue increased by $9 million for the three months ended March 31, 2018 compared to the same period of 2017 due to an increase in average prices. In the three months ended March 31, 2018, Networks also had an increase of $18 million from other revenues, including mainly revenue generated from the Puerto Rico mutual aid with offsetting associated costs included in operations and maintenance. Revenue related regulatory activities in the period decreased by $34 million primarily due to an adjustment of $14 million, to unfunded future income tax to reflect the change from a flow through to normalization method, which was recorded in the three month period ended March 31, 2017 as an increase to revenue, with an offsetting and equal increase to income tax expense, decreases in recoveries on the Ginna RSSA of $26 million, non by-passable charges of $14 million, revenue decoupling mechanism of $2 million, property tax of $3 million and a decrease of $42 million from deferrals of excess of deferred income taxes due to the changes in federal tax rates as a result of the tax reform, offset by increases in energy supply reconciliation of $42 million, stranded cost of $12 million and an increase of $13 million in other regulatory adjustments.

Renewables

Operating revenues decreased by $3 million, or 1%, from $287 million for the three months ended March 31, 2017 to $284 million for the three months ended March 31, 2018. The decrease in operating revenues was primarily due to an increase of $36 million from wind production with output increasing 673GWh, increase in thermal revenue of $4 million driven by colder weather, offset by decrease of $12 million in average prices due to large reduction in REC sales and expiry of PTCs in the period and unfavorable MtM changes of $31 million on energy derivative transactions entered into for economic hedging purposes.

Purchased Power, Natural Gas and Fuel Used

Our purchased power, natural gas and fuel used increased by 24%, from $465 million for the three months ended March 31, 2017 to $576 million for the three months ended March 31, 2018, as detailed by segment below:

Networks

Purchased power, natural gas and fuel used increased by $100 million, or 24%, from $418 million for the three months ended March 31, 2017 to $518 million for the three months ended March 31, 2018. The increase is primarily driven by $63 million and $46 million increases in average prices and overall units of electricity and gas, respectively, procured due to increase in degree days and colder weather combined with $4 million increase in other power supply purchases.

Renewables

Purchased power, natural gas and fuel used decreased by $2 million, or 3%, from $58 million for the three months ended March 31, 2017 to $56 million for the three months ended March 31, 2018. The decrease is primarily driven by increase of $7 million in power purchases and $8 million of transmission cost due to mainly addition of new capacities, increase of $1 million in RECs purchases, offset by MtM changes on derivatives of $19 million that were favorable due to market price changes in the current period.

Operations and Maintenance

Our operations and maintenance increased by $5 million, or 1%, from $522 million for the three months ended March 31, 2017 to $527 million for the three months ended March 31, 2018, as detailed by segment below:

Networks

Operations and maintenance increased by $3 million, or 1% from $433 million for the three months ended March 31, 2017 to $436 million for the three months ended March 31, 2018. The increase is primarily due to an increase of $16 million in purchases of external services, $8 million in purchases of renewable and zero-emission energy certificates related to a new program to adopt clean energy standards and $6 million from increase in uncollectibles, offset by a decrease of $27 million in the Ginna RSSA driven by its completion.

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Renewables

Operations and maintenance expenses increased by $4 million, or 5%, from $82 million for the three months ended March 31, 2017 to $86 million for the three months ended March 31, 2018. The increase is primarily due to increased costs from increased capacity, which is driving higher salary costs of $2 million related to headcount increases, $1 million higher maintenance costs and $1 million higher corporate charges in the three month period ended March 31, 2018 compared with the same period of 2017.

Depreciation and Amortization and Loss From Assets Held for Sale

Depreciation and amortization and loss from assets held for sale for the three months ended March 31, 2018 was $208 million compared to $197 million for the three months ended March 31, 2017, an increase of $11 million. The increase is primarily due to a loss of $5 million from remeasurement of assets held for sale, increase of $4 million and $7 million in depreciation expense as a result of net plant additions in Networks and new capacities in Renewables, respectively, in the period, offset by $6 million lower depreciation expense in Other driven by cessation of depreciation for assets held for sale.

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

Other income (expense) and equity earnings (losses) increased by $6 million from $14 million for the three months ended March 31, 2017 to $19 million for the three months ended March 31, 2018, primarily due to increase of $3 million in non-service component of pension and other post-retirement cost and $1 million in allowance for funds used during construction in Networks in the period combined with $1 million lower capitalized interest in renewables due to less construction projects in the period.

Interest Expense, Net of Capitalization

Interest expense for the three months ended March 31, 2018 and 2017 were $74 million and $71 million, respectively. Networks and Other added $3 million and $5 million of interest expense from new debts issued in 2017. In addition, Networks had $5 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 three months ended March 31, 2018, was 23.2%, which is higher than the 21% statutory federal income tax rate, applicable in 2018, predominantly due to discrete tax adjustments recorded during the period offset by 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 March 31, 2017, was 28.1%, which is lower than the 35% statutory federal income tax rate, applicable in 2017, predominately due to the recognition of production tax credits associated with wind production. Additionally, $14 million in income tax expense for the three months ended March 31, 2017, 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. This was partially offset by other discrete tax adjustments during the 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 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 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, 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, loss from held for sale measurement, and adjustments for the non-core Gas storage business. 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

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as opposed to by function. The most directly comparable U.S. GAAP measure to adjusted EBITDA and adjusted net income is net income. We also define adjusted gross margin as adjusted EBITDA adding back operations and maintenance and taxes other than income taxes and then subtracting transmission wheeling. We also define adjusted earnings per share, or adjusted 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 adjustments to reflect the classification of revenues and expenses by nature and before excluding restructuring charges, loss from held for sale measurement, the impact from mark-to-market activities in Renewables and Gas storage business for the three months ended March 31, 2018 and 2017, respectively, is as follows:

 

 

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

The following table sets forth our adjusted EBITDA and adjusted gross margin before adjustments to reflect the classification of revenues and expenses by nature and before excluding restructuring charges, loss from held for sale measurement, the impact from mark-to-market activities in Renewables and Gas storage business by segment for each of the periods indicated and as a percentage of operating revenues:

 

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Our adjusted gross margin decreased by $10 million, or 1%, from $1,229 million for the three months ended March 31, 2017 to $1,219 million for the three months ended March 31, 2018.

Our adjusted EBITDA decreased by $13 million, or 2%, from $624 million for the three months ended March 31, 2017 to $611 million for the three months ended March 31, 2018.

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

Networks

Adjusted gross margin decreased by $13 million, or 1%, from $977 million for the three months ended March 31, 2017 to $964 million for the three months ended March 31, 2018. The decrease is primarily driven by the adverse impact of the tax reform on regulated revenue with an offsetting decrease to income tax expense along with an increase in average prices and overall units of electricity and gas procured in the period.

Adjusted EBITDA decreased by $16 million, or 3%, from $478 million for the three months ended March 31, 2017 to $462 million for the three months ended March 31, 2018. The decrease was due to the same reasons discussed above for adjusted gross margin.

Renewables

Adjusted gross margin stayed at the same level of $228 million for the three month periods ended March 31, 2017 and 2018.

Adjusted EBITDA decreased by $4 million, or 3%, from $133 million for the three months ended March 31, 2017 to $129 million for the three months ended March 31, 2018. The decrease was primarily due to unfavorable MtM changes on energy derivatives driven by market price changes in the current period.

The following tables provide a reconciliation between Net Income attributable to AVANGRID and adjusted gross margin (non-GAAP) and adjusted EBITDA (non-GAAP) by segment after adjustments to reflect the classification of revenues and expenses by nature and after excluding restructuring charges, loss from held for sale measurement, the impact of mark-to-market activity in Renewables and Gas storage business for the three months ended March 31, 2018 and 2017, respectively:

 

 

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

Our adjusted gross margin increased by $12 million, or 1%, from $1,117 million for the three months ended March 31, 2017 to $1,129 million for the three months ended March 31, 2018.

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Our adjusted EBITDA increased by $10 million, or 2%, from $598 million for the three months ended March 31, 2017 to $608 million for the three months ended March 31, 2018.

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

Networks

Adjusted gross margin decreased by $13 million, or 1%, from $893 million for the three months ended March 31, 2017 to $880 million for the three months ended March 31, 2018. The decrease is primarily driven by the adverse impact of the tax reform on regulated revenue with an offsetting decrease to income tax expense along with an increase in average prices and overall units of electricity and gas procured in the period.

Adjusted EBITDA decreased by $10 million, or 2%, from $443 million for the three months ended March 31, 2017 to $433 million for the three months ended March 31, 2018. The decrease was due to the same reasons discussed above for adjusted gross margin.

Renewables

Adjusted gross margin increased by $25 million, or 11%, from $224 million for the three months ended March 31, 2017 to $249 million for the three months ended March 31, 2018. The increase was primarily due to increased capacity and higher production tax credits offset by unfavorable changes in prices in the period.

Adjusted EBITDA increased by $21 million, or 13%, from $155 million for the three months ended March 31, 2017 to $176 million for the three months ended March 31, 2018. The increase was due to the same reasons discussed above for adjusted gross margin.

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, loss from held for sale measurement, the impact from mark-to-market activities in Renewables and Gas storage business for the three months ended March 31, 2018 and 2017, 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 program as our primary sources of liquidity. Our long-term capital requirements have been met primarily through retention of earnings 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 March 31, 2018.

Liquidity Position

At March 31, 2018 and December 31, 2017, available liquidity was approximately $909 million and $784 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 liquidity agreement with Bank of America, N.A. along with certain members of the Iberdrola Group. The liquidity 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. The balance at March 31, 2018 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 $31 million at March 31, 2018.

We optimize our liquidity within the United States through a series of arms-length intercompany lending arrangements with our subsidiaries and among the regulated utilities to provide for lending of surplus cash to subsidiaries with liquidity needs, subject to the limitation that the regulated utilities may not lend to unregulated affiliates. These arrangements minimize overall short-term funding costs and maximize returns on the temporary cash investments of the subsidiaries. We have the capacity to borrow up to $1.5 billion from the lenders committed to the facility.

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The following table provides the components of our liquidity position as of March 31, 2018 and December 31, 2017, 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 March 31, 2018 and May 1, 2018, there was $631 million and $677 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 March 31, 2018 and May 1, 2018, were $869 million and $823 million, respectively.

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 $1.6 billion in capital expenditures through the remainder of 2018.

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 three months ended March 31, 2018 and 2017, respectively:

 

 

Operating Activities

For the three months ended March 31, 2018, net cash provided by operating activities was $597 million. During three months ended March 31, 2018, Renewables contributed $127 million of operating cash flow associated with wholesale sales of energy and Networks contributed $318 million of operating cash as the result of regulated transmission and distribution sales of electricity and natural gas. Additionally, $1 million in cash was used associated with corporate operating expenses in support of the operating segments and changes in working capital provided $153 million in cash. The cash from operating activities for the three months ended March 31, 2018 compared to the three months ended March 31, 2017 increased by $156 million, primarily attributable to increased operating revenues. The $50 million net change in operating assets and liabilities during the three months ended March 31, 2018 was

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primarily attributable to a net increase of $121 million in accounts receivable and payable due to impacts from sales and purchases, decrease in inventories and other assets/liabilities of $36 million and $96 million, respectively, taxes accrued of $29 million, offset by cash distribution received from equity method investment of $3 million and increase of $65 million in regulatory assets/liabilities in the period.

 

For the three months ended March 31, 2017, net cash provided by operating activities was $441 million. During the three months ended March 31, 2017, Renewables contributed $121 million of operating cash flow associated with wholesale sales of energy and Networks contributed $286 million of operating cash as the result of regulated transmission and distribution sales of electricity and natural gas. Additionally, $3 million in cash was provided associated with corporate operating expenses in support of the operating segments and changes in working capital provided $31 million in cash. The cash from operating activities for the three months ended March 31, 2017 compared to the three months ended March 31, 2016 increased by $45 million, primarily attributable to the increased operating revenues. The $102 million net change in operating assets and liabilities during the three months ended March 31, 2017 was primarily attributable to a net decrease of $144 million in accounts receivable and payable due to impacts from sales and purchases, decrease in inventories and other assets of $11 million and $64 million, respectively, offset by $3 million of cash distribution from equity method investments, increase in taxes accrued and regulatory assets/liabilities of $9 million and $45 million, respectively.

Investing Activities

For the three months ended March 31, 2018, net cash used in investing activities was $323 million, which was comprised of $282 million associated with capital expenditures at Networks and $116 million of capital expenditures at Renewables primarily associated with payments in support of the construction projects. This was offset by $7 million of contributions in aid of construction, $2 million of cash distributions from equity method investments and proceeds from sale of assets of $67 primarily related to the sale of assets held for sale.

For the three months ended March 31, 2017, net cash used in investing activities was $514 million, which was comprised of $267 million associated with capital expenditures at Networks and $257 million of capital expenditures at Renewables primarily associated with payments in support of the El Cabo construction project. This was offset by $6 million of contributions in aid of construction and $2 million of cash distributions from equity method investments.

Financing Activities

For the three months ended March 31, 2018, financing activities used $275 million in cash reflecting primarily a net decrease in non-current debt and current notes payable of $126 million, distributions to non-controlling interests of $11 million, payments on capital lease of $8 million and dividends of $134 million.

For the three months ended March 31, 2017, financing activities provided $12 million in cash reflecting primarily a net increase in non-current debt and current notes payable of $201 million, payments on the tax equity financing arrangements of $27 million, capital lease of $27 million and dividends of $134 million.

Off-Balance Sheet Arrangements

There have been no material changes in the off-balance sheet arrangements during the three months ended March 31, 2018 as compared to those reported for the fiscal year ended December 31, 2017 in our Form 10-K.

Contractual Obligations

There have been no material changes in contractual and contingent obligations during the three months ended March 31, 2018  as compared to those reported for the fiscal year ended December 31, 2017 in our Form 10-K.

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 March 31, 2018, the only notable changes to the significant accounting policies described in our consolidated financial statements as of December 31, 2017 and 2016, and for the three years ended December 31, 2017, are with respect to our adoption of the new accounting pronouncements described in the Note 3 of our condensed consolidated financial statements for the three months ended March 31, 2018.

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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. As of March 31, 2018, the new accounting pronouncements that we have adopted as of January 1, 2018, and reflected in our consolidated financial statements are described in Note 3 of our condensed consolidated financial statements for the three months ended March 31, 2018. There have been no other material changes to the significant accounting policies described in our consolidated financial statements as of December 31, 2017 and 2016, and for the three years ended December 31, 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 three months ended March 31, 2018, as compared to those reported for the fiscal year ended December 31, 2017 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 weakness 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, 2017.

Previously Identified Material Weaknesses

As of December 31, 2017, management concluded that certain deficiencies rose to the level of a material weakness in controls related to the measurement and disclosure of income taxes. As a result of the identified material weakness, management concluded that, as of December 31, 2017, our internal control over financial reporting was not effective.

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.

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.

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Remediation Plans and Other Information

Our management, with oversight from the Audit and Compliance Committee of the Board of Directors, is actively engaged in remediation efforts to address the 2017 material weakness. The remediation plans for the 2017 material weakness include the following:

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 weakness 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 currently expect that the remediation of this material weakness will be completed by December 31, 2018.

Changes in Internal Control

Except for the control deficiencies discussed above that have been assessed as a material weakness as of December 31, 2017, 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

Please read “Note 8—Contingencies” and “Note 9—Environmental Liabilities” to the accompanying unaudited condensed consolidated financial statements under Part I, Item 1of this report for a discussion of 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, 2017. 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.

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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