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(Mark One)
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þ
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2018
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OR
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¨
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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FOR THE TRANSITION PERIOD FROM
TO
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Delaware
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76-0511406
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(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.)
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1111 Louisiana
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Houston, Texas 77002
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(713) 207-1111
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(Address and zip code of principal executive offices)
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(Registrant’s telephone number, including area code)
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Large accelerated filer
o
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Accelerated filer
o
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Non-accelerated filer
þ
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Smaller reporting company
o
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Emerging growth company
o
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(Do not check if a smaller reporting company)
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PART I.
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FINANCIAL INFORMATION
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Page
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Item 1.
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Financial Statements
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Condensed Statements of Consolidated Income
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Three Months Ended March 31, 2018 and 2017 (unaudited)
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Condensed Statements of Consolidated Comprehensive Income
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Three Months Ended March 31, 2018 and 2017 (unaudited)
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Condensed Consolidated Balance Sheets
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March 31, 2018 and December 31, 2017 (unaudited)
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Condensed Statements of Consolidated Cash Flows
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Three Months Ended March 31, 2018 and 2017 (unaudited)
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Notes to Unaudited Condensed Consolidated Financial Statements
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Item 2.
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Management’s Narrative Analysis of Results of Operations
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Item 4.
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Controls and Procedures
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PART II.
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OTHER INFORMATION
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Item 1.
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Legal Proceedings
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Item 1A.
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Risk Factors
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Item 5.
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Other Information
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Item 6.
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Exhibits
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GLOSSARY
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AEM
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Atmos Energy Marketing, LLC, previously a wholly-owned subsidiary of Atmos Energy Holdings, Inc., a wholly-owned subsidiary of Atmos Energy Corporation
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AMA
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Asset Management Agreement
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APSC
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Arkansas Public Service Commission
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ARP
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Alternative revenue program
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ASC
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Accounting Standards Codification
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ASU
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Accounting Standards Update
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Bcf
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Billion cubic feet
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CenterPoint Energy
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CenterPoint Energy, Inc., and its subsidiaries
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CERC Corp.
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CenterPoint Energy Resources Corp.
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CERC
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CERC Corp., together with its subsidiaries
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CES
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CenterPoint Energy Services, Inc., a wholly-owned subsidiary of CERC Corp.
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CIP
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Conservation Improvement Program
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Continuum
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The retail energy services business of Continuum Retail Energy Services, LLC, including its wholly-owned subsidiary Lakeshore Energy Services, LLC and the natural gas wholesale assets of Continuum Energy Services, LLC
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EDIT
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Excess deferred income taxes
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EECR
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Energy Efficiency Cost Recovery
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Enable
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Enable Midstream Partners, LP
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EPA
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Environmental Protection Agency
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FERC
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Federal Energy Regulatory Commission
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Fitch
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Fitch, Inc.
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Form 10-Q
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Quarterly Report on Form 10-Q
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FRP
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Formula Rate Plan
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GenOn
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GenOn Energy, Inc.
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GRIP
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Gas Reliability Infrastructure Program
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Houston Electric
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CenterPoint Energy Houston Electric, LLC and its subsidiaries
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Interim Condensed Financial Statements
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Unaudited condensed consolidated interim financial statements and notes
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IRS
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Internal Revenue Service
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LIBOR
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London Interbank Offered Rate
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MGP
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Manufactured gas plant
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MLP
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Master Limited Partnership
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MMBtu
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One million British thermal units
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Moody’s
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Moody’s Investors Service, Inc.
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MPSC
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Mississippi Public Service Commission
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MPUC
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Minnesota Public Utilities Commission
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NGD
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Natural gas distribution business
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NGLs
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Natural gas liquids
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NOPR
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Notice of Proposed Rulemaking
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NRG
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NRG Energy, Inc.
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NYSE
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New York Stock Exchange
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OCC
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Oklahoma Corporation Commission
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OGE
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OGE Energy Corp.
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PBRC
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Performance Based Rate Change
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PRP
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Potentially responsible party
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Railroad Commission
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Railroad Commission of Texas
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Reliant Energy
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Reliant Energy, Incorporated
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GLOSSARY
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Revised Policy Statement
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Revised Policy Statement on Treatment of Income Taxes
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ROE
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Return on equity
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RRA
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Rate Regulation Adjustment
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RRI
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Reliant Resources, Inc.
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RSP
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Rate Stabilization Plan
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SEC
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Securities and Exchange Commission
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S&P
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Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies
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TBD
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To be determined
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TCJA
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Tax reform legislation informally called the Tax Cuts and Jobs Act of 2017
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Transition Agreements
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Services Agreement, Employee Transition Agreement, Transitional Seconding Agreement and other agreements entered into in connection with the formation of Enable
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Vectren
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Vectren Corporation, an Indiana corporation
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VIE
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Variable interest entity
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2017 Form 10-K
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Annual Report on Form 10-K for the year ended December 31, 2017
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•
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the performance of Enable, the amount of cash distributions we receive from Enable, and the value of our interest in Enable, and factors that may have a material impact on such performance, cash distributions and value, including factors such as:
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◦
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competitive conditions in the midstream industry, and actions taken by Enable’s customers and competitors, including the extent and timing of the entry of additional competition in the markets served by Enable;
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◦
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the timing and extent of changes in the supply of natural gas and associated commodity prices, particularly prices of natural gas and NGLs, the competitive effects of the available pipeline capacity in the regions served by Enable, and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity on Enable’s interstate pipelines;
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◦
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the demand for crude oil, natural gas, NGLs and transportation and storage services;
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◦
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environmental and other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing;
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◦
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recording of non-cash goodwill, long-lived asset or other than temporary impairment charges by or related to Enable;
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◦
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changes in tax status;
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◦
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access to debt and equity capital; and
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◦
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the availability and prices of raw materials and services for current and future construction projects;
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•
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industrial, commercial and residential growth in our service territories and changes in market demand, including the effects of energy efficiency measures and demographic patterns;
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•
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timely and appropriate rate actions that allow recovery of costs and a reasonable return on investment;
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•
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future economic conditions in regional and national markets and their effect on sales, prices and costs;
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•
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weather variations and other natural phenomena, including the impact of severe weather events on operations and capital;
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•
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state and federal legislative and regulatory actions or developments affecting various aspects of our businesses (including the businesses of Enable), including, among others, energy deregulation or re-regulation, pipeline integrity and safety and changes in regulation and legislation pertaining to trade, health care, finance and actions regarding the rates charged by our regulated businesses;
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•
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tax reform and legislation, including the effects of the TCJA and uncertainties involving state commissions’ and local municipalities’ regulatory requirements and determinations regarding the treatment of EDIT and our rates;
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•
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our ability to mitigate weather impacts through normalization or rate mechanisms, and the effectiveness of such mechanisms;
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•
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the timing and extent of changes in commodity prices, particularly natural gas, and the effects of geographic and seasonal commodity price differentials;
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•
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actions by credit rating agencies;
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•
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changes in interest rates and their impact on our costs of borrowing;
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•
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problems with regulatory approval, construction, implementation of necessary technology or other issues with respect to major capital projects that result in delays or in cost overruns that cannot be recouped in rates;
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•
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local, state and federal legislative and regulatory actions or developments relating to the environment, including those related to global climate change;
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•
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the impact of unplanned facility outages;
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•
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any direct or indirect effects on our or Enable’s facilities, operations and financial condition resulting from terrorism, cyber-attacks, data security breaches or other attempts to disrupt our businesses or the businesses of third parties, or other catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, pandemic health events or other occurrences;
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•
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our ability to invest planned capital and the timely recovery of our investment in capital;
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•
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our ability to control operation and maintenance costs;
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•
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the sufficiency of our insurance coverage, including availability, cost, coverage and terms;
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•
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the investment performance of CenterPoint Energy, Inc.’s pension and postretirement benefit plans;
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•
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commercial bank and financial market conditions, our access to capital, the cost of such capital, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets;
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•
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changes in rates of inflation;
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•
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inability of various counterparties to meet their obligations to us;
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•
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non-payment for our services due to financial distress of our customers;
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•
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the extent and effectiveness of our risk management and hedging activities, including, but not limited to, our financial and weather hedges;
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•
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timely and appropriate regulatory actions allowing recovery of costs associated with any future hurricanes or natural disasters, including costs associated with Hurricane Harvey;
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•
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our or Enable’s potential business strategies and strategic initiatives, including restructurings, joint ventures and acquisitions or dispositions of assets or businesses (including a reduction of our interests in Enable, if any, whether through our decision to sell all or a portion of the Enable common units we own in the public equity markets or otherwise, subject to certain limitations), which we cannot assure you will be completed or will have the anticipated benefits to us or Enable;
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•
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acquisition and merger activities involving us or our competitors, including the ability to successfully complete merger, acquisition and divestiture plans;
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•
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our or Enable’s ability to recruit, effectively transition and retain management and key employees and maintain good labor relations;
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•
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the outcome of litigation;
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•
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the ability of GenOn (formerly known as RRI Energy, Inc., Reliant Energy and RRI), a wholly-owned subsidiary of NRG, and its subsidiaries, currently the subject of bankruptcy proceedings, to satisfy their obligations to us, including indemnity obligations;
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•
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the timing and outcome of any audits, disputes and other proceedings related to taxes;
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•
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the effect of changes in and application of accounting standards and pronouncements; and
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•
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other factors we discuss in “Risk Factors” in Item 1A of Part I of our
2017
Form 10-K, which is incorporated herein by reference, and other reports we file from time to time with the SEC.
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Three Months Ended March 31,
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||||||
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2018
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2017
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||||
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||||
Revenues:
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||||
Utility revenues
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$
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1,143
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$
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907
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Non-utility revenues
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1,257
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1,186
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Total
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2,400
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2,093
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||||
Expenses:
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Utility natural gas
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637
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450
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Non-utility natural gas
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1,273
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1,129
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Operation and maintenance
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238
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|
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215
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Depreciation and amortization
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73
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66
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Taxes other than income taxes
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48
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34
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Total
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2,269
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1,894
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Operating Income
|
131
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|
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199
|
|
||
|
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|
|
||||
Other Income (Expense):
|
|
|
|
|
|
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Interest and other finance charges
|
(29
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)
|
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(29
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)
|
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Equity in earnings of unconsolidated affiliate, net
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69
|
|
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72
|
|
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Other, net
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(4
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)
|
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(5
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)
|
||
Total
|
36
|
|
|
38
|
|
||
Income Before Income Taxes
|
167
|
|
|
237
|
|
||
Income tax expense
|
37
|
|
|
90
|
|
||
Net Income
|
$
|
130
|
|
|
$
|
147
|
|
|
Three Months Ended
|
||||||
|
March 31,
|
||||||
|
2018
|
|
2017
|
||||
|
|
|
|
||||
Net income
|
$
|
130
|
|
|
$
|
147
|
|
Comprehensive income
|
$
|
130
|
|
|
$
|
147
|
|
|
March 31,
2018 |
|
December 31, 2017
|
||||
Current Assets
:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
27
|
|
|
$
|
12
|
|
Accounts receivable, less bad debt reserve of $22 and $18, respectively
|
780
|
|
|
713
|
|
||
Accrued unbilled revenues
|
179
|
|
|
307
|
|
||
Accounts and notes receivable–affiliated companies
|
8
|
|
|
6
|
|
||
Materials and supplies
|
61
|
|
|
56
|
|
||
Natural gas inventory
|
81
|
|
|
222
|
|
||
Non-trading derivative assets
|
84
|
|
|
110
|
|
||
Prepaid expenses and other current assets
|
94
|
|
|
166
|
|
||
Total current assets
|
1,314
|
|
|
1,592
|
|
||
|
|
|
|
||||
Property, Plant and Equipment:
|
|
|
|
||||
Property, plant and equipment
|
6,978
|
|
|
6,888
|
|
||
Less: accumulated depreciation and amortization
|
2,094
|
|
|
2,036
|
|
||
Property, plant and equipment, net
|
4,884
|
|
|
4,852
|
|
||
|
|
|
|
||||
Other Assets:
|
|
|
|
|
|
||
Goodwill
|
867
|
|
|
867
|
|
||
Non-trading derivative assets
|
52
|
|
|
44
|
|
||
Investment in unconsolidated affiliate
|
2,467
|
|
|
2,472
|
|
||
Other
|
271
|
|
|
285
|
|
||
Total other assets
|
3,657
|
|
|
3,668
|
|
||
|
|
|
|
||||
Total Assets
|
$
|
9,855
|
|
|
$
|
10,112
|
|
|
March 31,
2018 |
|
December 31, 2017
|
||||
Current Liabilities:
|
|
|
|
|
|
||
Short-term borrowings
|
$
|
—
|
|
|
$
|
39
|
|
Accounts payable
|
479
|
|
|
669
|
|
||
Accounts and notes payable–affiliated companies
|
39
|
|
|
611
|
|
||
Taxes accrued
|
75
|
|
|
75
|
|
||
Interest accrued
|
19
|
|
|
32
|
|
||
Customer deposits
|
77
|
|
|
76
|
|
||
Non-trading derivative liabilities
|
21
|
|
|
20
|
|
||
Other
|
137
|
|
|
137
|
|
||
Total current liabilities
|
847
|
|
|
1,659
|
|
||
|
|
|
|
||||
Other Liabilities:
|
|
|
|
|
|
||
Deferred income taxes, net
|
1,323
|
|
|
1,289
|
|
||
Non-trading derivative liabilities
|
12
|
|
|
4
|
|
||
Benefit obligations
|
97
|
|
|
97
|
|
||
Regulatory liabilities
|
1,240
|
|
|
1,201
|
|
||
Other
|
303
|
|
|
297
|
|
||
Total other liabilities
|
2,975
|
|
|
2,888
|
|
||
|
|
|
|
||||
Long-Term Debt
|
2,882
|
|
|
2,457
|
|
||
|
|
|
|
||||
Commitments and Contingencies (Note 12)
|
|
|
|
|
|
||
|
|
|
|
||||
Stockholder’s Equity:
|
|
|
|
||||
Common stock
|
—
|
|
|
—
|
|
||
Paid-in capital
|
2,527
|
|
|
2,528
|
|
||
Retained earnings
|
618
|
|
|
574
|
|
||
Accumulated other comprehensive income
|
6
|
|
|
6
|
|
||
Total stockholder’s equity
|
3,151
|
|
|
3,108
|
|
||
|
|
|
|
||||
Total Liabilities and Stockholder’s Equity
|
$
|
9,855
|
|
|
$
|
10,112
|
|
|
Three Months Ended March 31,
|
||||||
|
2018
|
|
2017
|
||||
Cash Flows from Operating Activities:
|
|
|
|
||||
Net income
|
$
|
130
|
|
|
$
|
147
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
||
Depreciation and amortization
|
73
|
|
|
66
|
|
||
Amortization of deferred financing costs
|
2
|
|
|
2
|
|
||
Deferred income taxes
|
34
|
|
|
88
|
|
||
Write-down of natural gas inventory
|
1
|
|
|
—
|
|
||
Equity in earnings of unconsolidated affiliate, net of distributions
|
(9
|
)
|
|
(72
|
)
|
||
Changes in other assets and liabilities, excluding acquisitions:
|
|
|
|
|
|
||
Accounts receivable and unbilled revenues, net
|
29
|
|
|
94
|
|
||
Accounts receivable/payable–affiliated companies
|
(4
|
)
|
|
(5
|
)
|
||
Inventory
|
135
|
|
|
70
|
|
||
Accounts payable
|
(173
|
)
|
|
(148
|
)
|
||
Fuel cost recovery
|
64
|
|
|
(6
|
)
|
||
Interest and taxes accrued
|
(13
|
)
|
|
(4
|
)
|
||
Non-trading derivatives, net
|
60
|
|
|
(32
|
)
|
||
Margin deposits, net
|
(28
|
)
|
|
(46
|
)
|
||
Net regulatory assets and liabilities
|
55
|
|
|
—
|
|
||
Other current assets
|
3
|
|
|
4
|
|
||
Other current liabilities
|
19
|
|
|
(11
|
)
|
||
Other assets
|
3
|
|
|
13
|
|
||
Other liabilities
|
4
|
|
|
18
|
|
||
Other, net
|
1
|
|
|
2
|
|
||
Net cash provided by operating activities
|
386
|
|
|
180
|
|
||
Cash Flows from Investing Activities:
|
|
|
|
|
|
||
Capital expenditures
|
(114
|
)
|
|
(98
|
)
|
||
Distributions from unconsolidated affiliate in excess of cumulative earnings
|
14
|
|
|
74
|
|
||
Acquisitions, net of cash acquired
|
—
|
|
|
(132
|
)
|
||
Other, net
|
3
|
|
|
—
|
|
||
Net cash used in investing activities
|
(97
|
)
|
|
(156
|
)
|
||
Cash Flows from Financing Activities:
|
|
|
|
|
|
||
Decrease in short-term borrowings, net
|
(39
|
)
|
|
(35
|
)
|
||
Proceeds from (payments of) commercial paper, net
|
(172
|
)
|
|
30
|
|
||
Proceeds from long-term debt
|
599
|
|
|
—
|
|
||
Dividends to parent
|
(86
|
)
|
|
(108
|
)
|
||
Debt issuance costs
|
(4
|
)
|
|
—
|
|
||
Increase (decrease) in notes payable–affiliated companies
|
(570
|
)
|
|
52
|
|
||
Contribution from parent
|
—
|
|
|
38
|
|
||
Other, net
|
(2
|
)
|
|
—
|
|
||
Net cash used in financing activities
|
(274
|
)
|
|
(23
|
)
|
||
Net Increase in Cash and Cash Equivalents
|
15
|
|
|
1
|
|
||
Cash and Cash Equivalents at Beginning of Period
|
12
|
|
|
1
|
|
||
Cash and Cash Equivalents at End of Period
|
$
|
27
|
|
|
$
|
2
|
|
•
|
NGD, which owns and operates natural gas distribution systems in
six
states; and
|
•
|
CES, which obtains and offers competitive variable and fixed-price physical natural gas supplies and services primarily to commercial and industrial customers and electric and natural gas utilities in
33
states.
|
Recently Adopted Accounting Standards
|
||||||
ASU Number and Name
|
|
Description
|
|
Date of Adoption
|
|
Financial Statement Impact
upon Adoption
|
ASU 2016-01
-
Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities
ASU 2018-03-Technical Corrections and Improvements to Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities
|
|
This standard requires equity investments that do not result in consolidation and are not accounted for under the equity method to be measured at fair value and to recognize any changes in fair value in net income unless the investments qualify for the new practicability exception. It does not change the guidance for classifying and measuring investments in debt securities and loans. It also changes certain disclosure requirements and other aspects related to recognition and measurement of financial assets and financial liabilities.
Transition method
: cumulative-effect adjustment to beginning retained earnings, and two features prospective
|
|
January 1, 2018
|
|
The adoption of this standard did not a have an impact on CERC’s financial position, results of operations, cash flows or disclosures. CERC elected the practicability exception for investments without a readily determinable fair value to be measured at cost. See Note 8 for further discussion.
|
ASU 2016-15- Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments
|
|
This standard provides clarifying guidance on the classification of certain cash receipts and payments in the statement of cash flows and eliminates the variation in practice related to such classifications.
Transition method
: retrospective
|
|
January 1, 2018
|
|
The adoption did not have a material impact on CERC’s financial position, results of operations, cash flows or disclosures.
|
ASU 2016-18- Statement of Cash Flows (Topic 230): Restricted Cash
|
|
This standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, restricted cash and restricted cash equivalents. As a result, the statement of cash flows will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents. When cash, cash equivalents, restricted cash and restricted cash equivalents are presented in more than one line item on the balance sheet, the new guidance requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet.
Transition method
: retrospective
|
|
January 1, 2018
|
|
The adoption of this standard did not have an impact on CERC’s financial position, results of operations, cash flows or disclosures.
|
ASU 2017-01- Business Combinations (Topic 805): Clarifying the Definition of a Business
|
|
This standard revises the definition of a business. If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, then under ASU 2017-01, the asset or group of assets is not a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs to be more closely aligned with how outputs are described in ASC 606.
Transition method : prospective |
|
January 1, 2018
|
|
The adoption of this revised definition will reduce the number of transactions that are accounted for as a business combination, and therefore may have a potential impact on CERC’s accounting for future acquisitions.
|
ASU 2017-04- Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment
|
|
This standard eliminates Step 2 of the goodwill impairment test, which required a hypothetical purchase price allocation. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill.
Transition method : prospective |
|
January 1, 2018
|
|
The adoption of this standard will have an impact on CERC’s future calculation of goodwill impairments if an impairment is identified.
|
ASU 2017-07- Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost
|
|
This standard requires an employer to report the service cost component of the net periodic pension cost and postretirement benefit cost in the same line item(s) as other employee compensation costs arising from services rendered during the period; all other components will be presented separately from the line item(s) that includes the service cost and outside of any subtotal of operating income. In addition, only the service cost component will be eligible for capitalization in assets.
Transition method
: retrospective for the presentation of the service cost component and other components; prospective for the capitalization of the service cost component
|
|
January 1, 2018
|
|
The adoption of this standard did not have a material impact on CERC’s financial position, results of operations, cash flows or disclosures; however, it resulted in an increase to operating income and a corresponding decrease to other income of $4 million and $5 million as of March 31, 2018 and 2017, respectively. Other components previously capitalized in assets will be recorded as regulatory assets in CERC’s rate-regulated businesses, prospectively.
|
|
|
Three Months Ended March 31, 2018
|
||||||||||||||
|
|
Natural Gas Distribution
(1)
|
|
Energy
Services
(2)
|
|
Other Operations
(2)
|
|
Total
|
||||||||
|
|
(in millions)
|
||||||||||||||
Revenue from contracts
|
|
$
|
1,186
|
|
|
$
|
178
|
|
|
$
|
—
|
|
|
$
|
1,364
|
|
Derivatives income
|
|
—
|
|
|
1,107
|
|
|
—
|
|
|
1,107
|
|
||||
Other
(3)
|
|
(33
|
)
|
|
—
|
|
|
—
|
|
|
(33
|
)
|
||||
Eliminations
|
|
(10
|
)
|
|
(28
|
)
|
|
—
|
|
|
(38
|
)
|
||||
Total revenues
|
|
$
|
1,143
|
|
|
$
|
1,257
|
|
|
$
|
—
|
|
|
$
|
2,400
|
|
|
|
Three Months Ended March 31, 2017
|
||||||||||||||
|
|
Natural Gas Distribution
(1)
|
|
Energy
Services
(2)
|
|
Other Operations
(2)
|
|
Total
|
||||||||
|
|
(in millions)
|
||||||||||||||
Revenue from contracts
|
|
$
|
925
|
|
|
$
|
142
|
|
|
$
|
—
|
|
|
$
|
1,067
|
|
Derivatives income
|
|
—
|
|
|
1,054
|
|
|
—
|
|
|
1,054
|
|
||||
Other
(3)
|
|
(9
|
)
|
|
—
|
|
|
1
|
|
|
(8
|
)
|
||||
Eliminations
|
|
(9
|
)
|
|
(11
|
)
|
|
—
|
|
|
(20
|
)
|
||||
Total revenues
|
|
$
|
907
|
|
|
$
|
1,185
|
|
|
$
|
1
|
|
|
$
|
2,093
|
|
(1)
|
Reflected in Utility revenues in the Condensed Statements of Consolidated Income.
|
(2)
|
Reflected in Non-utility revenues in the Condensed Statements of Consolidated Income.
|
(3)
|
Primarily consists of income from ARPs and leases. ARPs are contracts between the utility and its regulators, not between the utility and a customer. CERC recognizes ARP revenue as other revenues when the regulator-specified conditions for recognition have been met. Upon recovery of ARP revenue through incorporation in rates charged for utility service to customers, ARP revenue is reversed and recorded as revenue from contracts with customers. The recognition of ARP revenues and the reversal of ARP revenues upon recovery through rates charged for utility service may not occur in the same period.
|
|
Three Months Ended
|
||||||
|
March 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Interest cost
(1)
|
$
|
1
|
|
|
$
|
1
|
|
Net periodic cost
|
$
|
1
|
|
|
$
|
1
|
|
(1)
|
Included in Other, net in the Condensed Statements of Consolidated Income.
|
|
March 31,
2018 |
|
December 31, 2017
|
||||
|
(in millions)
|
||||||
Regulatory Assets:
|
|
|
|
||||
Current regulatory assets
(1)
|
$
|
65
|
|
|
$
|
130
|
|
Non-current regulatory assets:
|
|
|
|
||||
Hurricane Harvey restoration costs
(2)
|
7
|
|
|
6
|
|
||
Regulatory assets related to TCJA
(3)
|
15
|
|
|
15
|
|
||
Other long-term regulatory assets
(4)
|
150
|
|
|
160
|
|
||
Total non-current regulatory assets
(5)
|
172
|
|
|
181
|
|
||
Total regulatory assets
|
237
|
|
|
311
|
|
||
Regulatory Liabilities:
|
|
|
|
||||
Current regulatory liabilities
(6)
|
16
|
|
|
2
|
|
||
Non-current regulatory liabilities:
|
|
|
|
||||
Regulatory liabilities related to TCJA
(3)
|
499
|
|
|
492
|
|
||
Estimated removal costs
|
600
|
|
|
593
|
|
||
Other long-term regulatory liabilities
|
141
|
|
|
116
|
|
||
Total non-current regulatory liabilities
|
1,240
|
|
|
1,201
|
|
||
Total regulatory liabilities
|
1,256
|
|
|
1,203
|
|
||
Total regulatory assets and liabilities, net
|
$
|
(1,019
|
)
|
|
$
|
(892
|
)
|
(1)
|
Current regulatory assets are included in Prepaid expenses and other current assets in CERC’s Condensed Consolidated Balance Sheets.
|
(2)
|
CERC is not earning a return on its Hurricane Harvey restoration costs.
|
(3)
|
The EDIT and deferred revenues will be recovered or refunded to customers as required by tax and regulatory authorities.
|
(4)
|
Includes a portion of NGD’s actuarially determined pension and other postemployment expense in excess of the amount being recovered through rates that is being deferred for rate making purposes. Deferred pension and other postemployment expenses of
$6 million
and
$7 million
as of March 31, 2018 and December 31, 2017, respectively, were not earning a return. Other long-term regulatory assets that are not earning a return were not material as of March 31, 2018 and
December 31, 2017
.
|
(5)
|
Non-current regulatory assets are included in Other assets in CERC’s Condensed Consolidated Balance Sheets.
|
(6)
|
Current regulatory liabilities are included in Other current liabilities in CERC’s Condensed Consolidated Balance Sheets.
|
|
|
|
|
|
|
Three Months Ended March 31,
|
||||||||
Jurisdiction
|
|
Winter Season
|
|
Bilateral Cap
|
|
2018
|
|
2017
|
||||||
|
|
|
|
(in millions)
|
||||||||||
Certain NGD jurisdictions
(1)
|
|
2017 – 2018
|
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
Weather hedge gains (losses) are recorded in Revenues in the Condensed Statements of Consolidated Income.
|
Fair Value of Derivative Instruments
|
||||||||||
|
|
March 31, 2018
|
||||||||
|
|
Balance Sheet Location
|
|
Derivative
Assets
Fair Value
|
|
Derivative
Liabilities
Fair Value
|
||||
Derivatives designated as fair value hedges:
|
|
|
|
(in millions)
|
||||||
Natural gas derivatives
(1) (2) (3)
|
|
Current Liabilities: Non-trading derivative liabilities
|
|
$
|
1
|
|
|
$
|
1
|
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
||||
Natural gas derivatives
(1) (2) (3)
|
|
Current Assets: Non-trading derivative assets
|
|
86
|
|
|
2
|
|
||
Natural gas derivatives
(1) (2) (3)
|
|
Other Assets: Non-trading derivative assets
|
|
52
|
|
|
—
|
|
||
Natural gas derivatives
(1) (2) (3)
|
|
Current Liabilities: Non-trading derivative liabilities
|
|
18
|
|
|
70
|
|
||
Natural gas derivatives
(1) (2) (3)
|
|
Other Liabilities: Non-trading derivative liabilities
|
|
9
|
|
|
42
|
|
||
Total
|
|
$
|
166
|
|
|
$
|
115
|
|
(1)
|
The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling
1,735
Bcf or a net
437
Bcf long position. Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.
|
(2)
|
Natural gas contracts are presented on a net basis in the Condensed Consolidated Balance Sheets as they are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Condensed Consolidated Balance Sheets. The net of total non-trading natural gas derivative assets and liabilities was a
$103 million
asset as shown on CERC’s Condensed Consolidated Balance Sheets (and as detailed in the table below), and was comprised of the natural gas contracts derivative assets and liabilities separately shown above, impacted by collateral netting of
$52 million
.
|
(3)
|
Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.
|
(1)
|
Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.
|
(2)
|
The derivative assets and liabilities on the Condensed Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.
|
Fair Value of Derivative Instruments
|
||||||||||
|
|
December 31, 2017
|
||||||||
|
|
Balance Sheet Location
|
|
Derivative
Assets
Fair Value
|
|
Derivative
Liabilities
Fair Value
|
||||
Derivatives designated as fair value hedges:
|
|
|
|
(in millions)
|
||||||
Natural gas derivatives
(1) (2) (3)
|
|
Current Liabilities: Non-trading derivative liabilities
|
|
$
|
13
|
|
|
$
|
1
|
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
||||
Natural gas derivatives
(1) (2) (3)
|
|
Current Assets: Non-trading derivative assets
|
|
114
|
|
|
4
|
|
||
Natural gas derivatives
(1) (2) (3)
|
|
Other Assets: Non-trading derivative assets
|
|
44
|
|
|
—
|
|
||
Natural gas derivatives
(1) (2) (3)
|
|
Current Liabilities: Non-trading derivative liabilities
|
|
38
|
|
|
78
|
|
||
Natural gas derivatives
(1) (2) (3)
|
|
Other Liabilities: Non-trading derivative liabilities
|
|
9
|
|
|
24
|
|
||
Total
|
|
$
|
218
|
|
|
$
|
107
|
|
(1)
|
The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling
1,795
Bcf or a net
224
Bcf long position. Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.
|
(2)
|
Natural gas contracts are presented on a net basis in the Condensed Consolidated Balance Sheets as they are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Condensed Consolidated Balance Sheets. The net of total non-trading natural gas derivative assets and liabilities was a
$130 million
asset as shown on CERC’s Condensed Consolidated Balance Sheets (and as detailed in the table below), and was comprised of the natural gas contracts derivative assets and liabilities separately shown above, impacted by collateral netting of
$19 million
.
|
(3)
|
Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.
|
Offsetting of Natural Gas Derivative Assets and Liabilities
|
||||||||||||
|
|
December 31, 2017
|
||||||||||
|
|
Gross Amounts
Recognized (1)
|
|
Gross Amounts Offset in the Consolidated Balance Sheets
|
|
Net Amount Presented in the Consolidated Balance Sheets (2)
|
||||||
|
|
(in millions)
|
||||||||||
Current Assets: Non-trading derivative assets
|
|
$
|
165
|
|
|
$
|
(55
|
)
|
|
$
|
110
|
|
Other Assets: Non-trading derivative assets
|
|
53
|
|
|
(9
|
)
|
|
44
|
|
|||
Current Liabilities: Non-trading derivative liabilities
|
|
(83
|
)
|
|
63
|
|
|
(20
|
)
|
|||
Other Liabilities: Non-trading derivative liabilities
|
|
(24
|
)
|
|
20
|
|
|
(4
|
)
|
|||
Total
|
|
$
|
111
|
|
|
$
|
19
|
|
|
$
|
130
|
|
(1)
|
Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.
|
(2)
|
The derivative assets and liabilities on the Condensed Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.
|
|
|
|
|
|
|
|
Income Statement Impact of Derivative Activity
|
||||||||||
|
|
|
|
Three Months Ended March 31,
|
||||||
|
|
Income Statement Location
|
|
2018
|
|
2017
|
||||
Derivatives designated as fair value hedges:
|
|
|
|
(in millions)
|
||||||
Natural gas derivatives
|
|
Gains (Losses) in Expenses: Natural Gas
|
|
$
|
—
|
|
|
$
|
3
|
|
Fair value adjustments for natural gas inventory designated as the hedged item
|
|
Gains (Losses) in Expenses: Natural Gas
|
|
(2
|
)
|
|
(4
|
)
|
||
Total increase in Expenses: Natural Gas
(1)
|
|
$
|
(2
|
)
|
|
$
|
(1
|
)
|
||
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
||||
Natural gas derivatives
|
|
Gains (Losses) in Revenues
|
|
$
|
57
|
|
|
$
|
96
|
|
Natural gas derivatives
|
|
Gains (Losses) in Expenses: Natural Gas
|
|
(69
|
)
|
|
(67
|
)
|
||
Total - derivatives not designated as hedging instruments
|
|
$
|
(12
|
)
|
|
$
|
29
|
|
(1)
|
Hedge ineffectiveness results from the basis ineffectiveness discussed above, and excludes the impact to natural gas expense from timing ineffectiveness. Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity. As the commodity contract nears the settlement date, spot-to-forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on natural gas expense.
|
|
Quoted Prices in
Active Markets
for Identical Assets
(Level 1)
|
|
Significant Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Netting
Adjustments (1)
|
|
Balance as of March 31, 2018
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
||||||||||
Corporate equities
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3
|
|
Investments, including money
market funds
(2)
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|||||
Natural gas derivatives
(3)
|
—
|
|
|
147
|
|
|
19
|
|
|
(30
|
)
|
|
136
|
|
|||||
Total assets
|
$
|
13
|
|
|
$
|
147
|
|
|
$
|
19
|
|
|
$
|
(30
|
)
|
|
$
|
149
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Natural gas derivatives
(3)
|
$
|
—
|
|
|
$
|
108
|
|
|
$
|
7
|
|
|
$
|
(82
|
)
|
|
$
|
33
|
|
Hedged portion of natural gas inventory
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|||||
Total liabilities
|
$
|
8
|
|
|
$
|
108
|
|
|
$
|
7
|
|
|
$
|
(82
|
)
|
|
$
|
41
|
|
(1)
|
Amounts represent the impact of legally enforceable master netting arrangements that allow CERC to settle positive and negative positions and also include cash collateral of
$52 million
posted with the same counterparties.
|
(2)
|
Amounts are included in Other assets in the Condensed Consolidated Balance Sheets.
|
(3)
|
Natural gas derivatives include no material amounts related to physical forward transactions with Enable.
|
|
Quoted Prices in
Active Markets
for Identical Assets
(Level 1)
|
|
Significant Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Netting
Adjustments (1)
|
|
Balance as of December 31, 2017
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
||||||||||
Corporate equities
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3
|
|
Investments, including money
market funds
(2)
|
11
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11
|
|
|||||
Natural gas derivatives
(3)
|
—
|
|
|
161
|
|
|
57
|
|
|
(64
|
)
|
|
154
|
|
|||||
Hedged portion of natural gas inventory
|
14
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14
|
|
|||||
Total assets
|
$
|
28
|
|
|
$
|
161
|
|
|
$
|
57
|
|
|
$
|
(64
|
)
|
|
$
|
182
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Natural gas derivatives
(3)
|
$
|
—
|
|
|
$
|
96
|
|
|
$
|
11
|
|
|
$
|
(83
|
)
|
|
$
|
24
|
|
Total liabilities
|
$
|
—
|
|
|
$
|
96
|
|
|
$
|
11
|
|
|
$
|
(83
|
)
|
|
$
|
24
|
|
(1)
|
Amounts represent the impact of legally enforceable master netting arrangements that allow CERC to settle positive and negative positions and also include cash collateral of
$19 million
posted with the same counterparties.
|
(2)
|
Amounts are included in Other assets in the Condensed Consolidated Balance Sheets.
|
(3)
|
Natural gas derivatives include no material amounts related to physical forward transactions with Enable.
|
|
Fair Value Measurements Using Significant
Unobservable Inputs (Level 3)
|
||||||
|
Derivative assets and liabilities, net
|
||||||
|
Three Months Ended March 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Beginning balance
|
$
|
46
|
|
|
$
|
13
|
|
Total gains
|
2
|
|
|
16
|
|
||
Total settlements
|
(34
|
)
|
|
(4
|
)
|
||
Transfers into Level 3
|
—
|
|
|
1
|
|
||
Transfers out of Level 3
|
(2
|
)
|
|
1
|
|
||
Ending balance
(1)
|
$
|
12
|
|
|
$
|
27
|
|
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date
|
$
|
(4
|
)
|
|
$
|
15
|
|
(1)
|
CERC did not have significant Level 3 sales or purchases during either of the
three
months ended
March 31, 2018
or
2017
.
|
|
March 31, 2018
|
|
December 31, 2017
|
||||||||||||
|
Carrying
Amount |
|
Fair
Value |
|
Carrying
Amount
|
|
Fair
Value
|
||||||||
|
(in millions)
|
||||||||||||||
Financial liabilities:
|
|
|
|
|
|
|
|
||||||||
Long-term debt
|
$
|
2,882
|
|
|
$
|
3,078
|
|
|
$
|
2,457
|
|
|
$
|
2,708
|
|
|
March 31, 2018
|
||||
|
Limited Partner Interest
|
|
Common Units
|
||
CERC Corp.
|
54.0
|
%
|
|
233,856,623
|
|
OGE
|
25.6
|
%
|
|
110,982,805
|
|
Public unitholders
|
20.4
|
%
|
|
88,232,573
|
|
Total units outstanding
|
100.0
|
%
|
|
433,072,001
|
|
|
|
Three Months Ended March 31,
|
||||||
|
|
2018
|
|
2017
|
||||
|
|
(in millions)
|
||||||
Investment in Enable common units
|
|
$
|
74
|
|
|
$
|
74
|
|
|
Three Months Ended March 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Reimbursement of transition services
(1)
|
$
|
2
|
|
|
$
|
2
|
|
Natural gas expenses, including transportation and storage costs
|
37
|
|
|
33
|
|
(1)
|
Represents amounts billed under the Transition Agreements for certain support services provided to Enable. Actual transition services costs are recorded net of reimbursement.
|
|
March 31, 2018
|
|
December 31, 2017
|
||||
|
(in millions)
|
||||||
Accounts receivable for amounts billed for transition services
|
$
|
1
|
|
|
$
|
1
|
|
Accounts payable for natural gas purchases from Enable
|
11
|
|
|
13
|
|
|
|
Three Months Ended March 31,
|
||||||
|
|
2018
|
|
2017
|
||||
|
|
(in millions)
|
||||||
Operating revenues
|
|
$
|
748
|
|
|
$
|
666
|
|
Cost of sales, excluding depreciation and amortization
|
|
375
|
|
|
308
|
|
||
Operating income
|
|
139
|
|
|
140
|
|
||
Net income attributable to Enable
|
|
105
|
|
|
111
|
|
||
Reconciliation of Equity in Earnings, net:
|
|
|
|
|
||||
CERC Corp.’s interest
|
|
$
|
57
|
|
|
$
|
60
|
|
Basis difference amortization
(1)
|
|
12
|
|
|
12
|
|
||
CERC Corp.’s equity in earnings, net
|
|
$
|
69
|
|
|
$
|
72
|
|
(1)
|
Equity in earnings of unconsolidated affiliate includes CERC Corp.’s share of Enable’s earnings adjusted for the amortization of the basis difference of CERC Corp.’s original investment in Enable and its underlying equity in Enable’s net assets. The basis difference is amortized over approximately
31
years, the average life of the assets to which the basis difference is attributed.
|
|
|
March 31,
2018 |
|
December 31, 2017
|
||||
|
|
(in millions)
|
||||||
Current assets
|
|
$
|
413
|
|
|
$
|
416
|
|
Non-current assets
|
|
11,274
|
|
|
11,177
|
|
||
Current liabilities
|
|
1,404
|
|
|
1,279
|
|
||
Non-current liabilities
|
|
2,664
|
|
|
2,660
|
|
||
Non-controlling interest
|
|
11
|
|
|
12
|
|
||
Preferred equity
|
|
362
|
|
|
362
|
|
||
Enable partners’ equity
|
|
7,246
|
|
|
7,280
|
|
||
Reconciliation of Investment in Enable:
|
|
|
|
|
||||
CERC Corp.’s ownership interest in Enable partners’ equity
|
|
$
|
3,913
|
|
|
$
|
3,935
|
|
CERC Corp.’s basis difference
|
|
(1,446
|
)
|
|
(1,463
|
)
|
||
CERC Corp.’s equity method investment in Enable
|
|
$
|
2,467
|
|
|
$
|
2,472
|
|
(1)
|
Amount presented is net of the accumulated goodwill impairment charge of
$252 million
recorded in 2012.
|
|
|
|
March 31, 2018
|
|
December 31, 2017
|
||||||||||||||||||||
|
Useful Lives
|
|
Gross Carrying Amount
|
|
Accumulated Amortization
|
|
Net Balance
|
|
Gross Carrying Amount
|
|
Accumulated Amortization
|
|
Net Balance
|
||||||||||||
|
(in years)
|
|
(in millions)
|
|
|
|
|
|
|
||||||||||||||||
Customer relationships
|
15
|
|
$
|
86
|
|
|
$
|
(23
|
)
|
|
$
|
63
|
|
|
$
|
86
|
|
|
$
|
(21
|
)
|
|
$
|
65
|
|
Covenants not to compete
|
4
|
|
4
|
|
|
(2
|
)
|
|
2
|
|
|
4
|
|
|
(2
|
)
|
|
2
|
|
||||||
Other
|
Various
|
|
15
|
|
|
(9
|
)
|
|
6
|
|
|
15
|
|
|
(8
|
)
|
|
7
|
|
||||||
Total
|
|
|
$
|
105
|
|
|
$
|
(34
|
)
|
|
$
|
71
|
|
|
$
|
105
|
|
|
$
|
(31
|
)
|
|
$
|
74
|
|
|
Three Months Ended March 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Amortization expense of intangible assets
|
$
|
3
|
|
|
$
|
2
|
|
|
March 31, 2018
|
|
December 31, 2017
|
||||
|
(in millions)
|
||||||
Money pool investments (borrowings)
(1)
|
$
|
—
|
|
|
$
|
(570
|
)
|
Weighted average interest rate
|
2.27
|
%
|
|
1.90
|
%
|
(1)
|
Included in Accounts and notes receivable (payable)–affiliated companies in the Condensed Consolidated Balance Sheets.
|
|
Three Months Ended March 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Corporate service charges
|
$
|
34
|
|
|
$
|
31
|
|
Charges from Houston Electric for services provided
|
5
|
|
|
3
|
|
||
Billings to Houston Electric for services provided
|
(3
|
)
|
|
(2
|
)
|
|
|
Three Months Ended March 31,
|
||||||
|
|
2018
|
|
2017
|
||||
|
|
(in millions)
|
||||||
Dividend to parent
|
|
$
|
86
|
|
|
$
|
108
|
|
(b)
|
Long-term Debt
|
Issuance Date
|
|
Aggregate Principal Amount
|
|
Interest Rate
|
|
Maturity Date
|
||
|
|
(in millions)
|
|
|
|
|
||
March 2018
|
|
$
|
300
|
|
|
3.55%
|
|
2023
|
March 2018
|
|
300
|
|
|
4.00%
|
|
2028
|
|
|
March 31, 2018
|
|
December 31, 2017
|
|
||||||||||||||||||||||
Size of
Facility |
|
Loans
|
|
Letters
of Credit |
|
Commercial
Paper |
|
Loans
|
|
Letters
of Credit |
|
Commercial
Paper |
|
||||||||||||||
(in millions)
|
|
||||||||||||||||||||||||||
$
|
900
|
|
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
726
|
|
(1)
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
898
|
|
(1)
|
(1)
|
Weighted average interest rate was
2.34%
and
1.72%
as of
March 31, 2018
and
December 31, 2017
, respectively.
|
Execution Date
|
|
Size of
Facility
|
|
Draw Rate of LIBOR plus
(1)
|
|
Financial Covenant Limit on Debt for Borrowed Money to Capital Ratio
|
|
Debt for Borrowed Money to Capital
Ratio as of March 31, 2018
|
|
Termination Date
|
||||
|
|
(in millions)
|
|
|
|
|
|
|
|
|
||||
March 3, 2016
|
|
$
|
900
|
|
|
1.25
|
%
|
|
65
|
%
|
|
38.7%
|
|
March 3, 2022
|
(1)
|
Based on current credit ratings.
|
|
For the Three Months Ended March 31, 2018
|
|
|
|
|||||||||||
|
Revenues from
External Customers |
|
Inter-segment
Revenues |
|
Operating
Income (Loss) |
|
Total Assets as of March 31, 2018
|
||||||||
|
(in millions)
|
||||||||||||||
Natural Gas Distribution
|
$
|
1,143
|
|
|
$
|
10
|
|
|
$
|
156
|
|
|
$
|
6,438
|
|
Energy Services
|
1,257
|
|
|
28
|
|
|
(26
|
)
|
|
1,329
|
|
||||
Midstream Investments
(1)
|
—
|
|
|
—
|
|
|
—
|
|
|
2,467
|
|
||||
Other Operations
|
—
|
|
|
—
|
|
|
1
|
|
|
81
|
|
||||
Reconciling Eliminations
|
—
|
|
|
(38
|
)
|
|
—
|
|
|
(460
|
)
|
||||
Consolidated
|
$
|
2,400
|
|
|
$
|
—
|
|
|
$
|
131
|
|
|
$
|
9,855
|
|
|
For the Three Months Ended March 31, 2017
|
|
|
|
|||||||||||
|
Revenues from
External Customers |
|
Inter-segment
Revenues |
|
Operating
Income (Loss) (2) |
|
Total Assets as of December 31, 2017
|
||||||||
|
(in millions)
|
||||||||||||||
Natural Gas Distribution
|
$
|
907
|
|
|
$
|
9
|
|
|
$
|
168
|
|
|
$
|
6,608
|
|
Energy Services
|
1,185
|
|
|
11
|
|
|
35
|
|
|
1,521
|
|
||||
Midstream Investments
(1)
|
—
|
|
|
—
|
|
|
—
|
|
|
2,472
|
|
||||
Other Operations
|
1
|
|
|
—
|
|
|
(4
|
)
|
|
70
|
|
||||
Reconciling Eliminations
|
—
|
|
|
(20
|
)
|
|
—
|
|
|
(559
|
)
|
||||
Consolidated
|
$
|
2,093
|
|
|
$
|
—
|
|
|
$
|
199
|
|
|
$
|
10,112
|
|
(1)
|
Midstream Investments’ equity earnings, net are as follows:
|
|
|
Three Months Ended March 31,
|
||||||
|
|
2018
|
|
2017
|
||||
|
|
(in millions)
|
||||||
Enable
|
|
$
|
69
|
|
|
$
|
72
|
|
(2)
|
Amounts for 2017 have been restated to reflect the adoption of ASU 2017-07.
|
|
Three Months Ended March 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Cash Payments:
|
|
|
|
|
|
||
Interest, net of capitalized interest
|
$
|
39
|
|
|
$
|
29
|
|
Non-cash transactions:
|
|
|
|
|
|
||
Accounts payable related to capital expenditures
|
$
|
39
|
|
|
$
|
28
|
|
|
Three Months Ended March 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Revenues
|
$
|
2,400
|
|
|
$
|
2,093
|
|
Expenses:
|
|
|
|
|
|
||
Natural gas
|
1,910
|
|
|
1,579
|
|
||
Operation and maintenance
|
238
|
|
|
215
|
|
||
Depreciation and amortization
|
73
|
|
|
66
|
|
||
Taxes other than income taxes
|
48
|
|
|
34
|
|
||
Total
|
2,269
|
|
|
1,894
|
|
||
Operating Income
|
131
|
|
|
199
|
|
||
Interest and other finance charges
|
(29
|
)
|
|
(29
|
)
|
||
Equity in earnings of unconsolidated affiliate, net
|
69
|
|
|
72
|
|
||
Other expense, net
|
(4
|
)
|
|
(5
|
)
|
||
Income Before Income Taxes
|
167
|
|
|
237
|
|
||
Income tax expense
|
37
|
|
|
90
|
|
||
Net Income
|
$
|
130
|
|
|
$
|
147
|
|
•
|
a $68 million decrease in operating income, discussed below by segment; and
|
•
|
a $3 million decrease in equity earnings from our investment in Enable, discussed further in Note 8 to our Interim Condensed Financial Statements.
|
|
Three Months Ended March 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Natural Gas Distribution
|
$
|
156
|
|
|
$
|
168
|
|
Energy Services
|
(26
|
)
|
|
35
|
|
||
Other Operations
|
1
|
|
|
(4
|
)
|
||
Total Consolidated Operating Income
|
$
|
131
|
|
|
$
|
199
|
|
|
Three Months Ended March 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in millions, except throughput and customer data)
|
||||||
Revenues
|
$
|
1,153
|
|
|
$
|
916
|
|
Expenses:
|
|
|
|
||||
Natural gas
|
667
|
|
|
461
|
|
||
Operation and maintenance
|
213
|
|
|
189
|
|
||
Depreciation and amortization
|
68
|
|
|
63
|
|
||
Taxes other than income taxes
|
49
|
|
|
35
|
|
||
Total expenses
|
997
|
|
|
748
|
|
||
Operating Income
|
$
|
156
|
|
|
$
|
168
|
|
Throughput (in Bcf):
|
|
|
|
|
|||
Residential
|
87
|
|
|
62
|
|
||
Commercial and industrial
|
94
|
|
|
82
|
|
||
Total Throughput
|
181
|
|
|
144
|
|
||
Number of customers at end of period:
|
|
|
|
|
|||
Residential
|
3,220,262
|
|
|
3,190,678
|
|
||
Commercial and industrial
|
257,806
|
|
|
255,869
|
|
||
Total
|
3,478,068
|
|
|
3,446,547
|
|
•
|
higher operation and maintenance expenses of $16 million, primarily due to higher labor and benefits, contract services and support services expense;
|
•
|
lower revenue of $15 million associated with the recording of a regulatory liability and a corresponding decrease to revenue in certain jurisdictions of $7 million reflecting the difference in revenues collected under existing customer rates and the revenues that would have been collected had existing rates been set using the lower corporate tax rate from the TCJA and lower rate filings in Minnesota of $8 million associated with the lower corporate tax rate as a result of the TCJA;
|
•
|
higher other taxes of $10 million, primarily due to the Minnesota property tax refund of $9 million in 2017; and
|
•
|
increased depreciation and amortization expense of $5 million, primarily due to ongoing additions to plant-in-service.
|
•
|
rate increases, exclusive of the TCJA impact discussed above, of $22 million, primarily from Texas rate filings of $11 million, Minnesota interim rates of $5 million and the Arkansas FRP filing of $4 million;
|
•
|
a $5 million increase in usage due to colder weather; and
|
•
|
a $3 million increase associated with customer growth from the addition of over 31,000 new customers.
|
|
Three Months Ended March 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in millions, except throughput and customer data)
|
||||||
Revenues
|
$
|
1,285
|
|
|
$
|
1,196
|
|
Expenses:
|
|
|
|
||||
Natural gas
|
1,281
|
|
|
1,137
|
|
||
Operation and maintenance
|
25
|
|
|
21
|
|
||
Depreciation and amortization
|
5
|
|
|
3
|
|
||
Total expenses
|
1,311
|
|
|
1,161
|
|
||
Operating Income (Loss)
|
$
|
(26
|
)
|
|
$
|
35
|
|
|
|
|
|
||||
Timing impacts related to mark-to-market gain (loss)
(1)
|
$
|
(80
|
)
|
|
$
|
15
|
|
Throughput (in Bcf)
|
375
|
|
|
319
|
|
||
Approximate number of customers at end of period
(2)
|
30,000
|
|
|
31,000
|
|
(1)
|
Includes the change in unrealized mark-to-market value and the impact from derivative assets and liabilities acquired through the purchase of Continuum and AEM.
|
(2)
|
Does not include approximately 71,000 and 59,000 natural gas customers as of
March 31, 2018
and 2017, respectively, that are under residential and small commercial choice programs invoiced by their host utility.
|
•
|
a $95 million decrease from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins;
|
•
|
a $4 million increase in operation and maintenance expense, primarily due to higher contracts and services expense related to pipeline integrity testing, higher bad debt expense and higher support services expense; and
|
•
|
a $2 million increase in depreciation and amortization, primarily due to the amortization of AEM acquired intangibles.
|
|
|
Three Months Ended March 31,
|
||||||
|
|
2018
|
|
2017
|
||||
|
|
(in millions)
|
||||||
Equity earnings from Enable, net
|
|
$
|
69
|
|
|
$
|
72
|
|
Mechanism
|
|
Annual Increase
(1)
(in millions)
|
|
Filing
Date
|
|
Effective Date
|
|
Approval Date
|
|
Additional Information
|
South Texas (Railroad Commission)
|
||||||||||
Rate Case
|
|
$0.5
|
|
November 2017
|
|
TBD
|
|
TBD
|
|
Unanimous settlement agreement filed with the Railroad Commission in April 2018 that recommends a $3 million annual decrease in current revenues, reflecting approximately $2 million decrease in the federal income tax rate and amortization of certain EDIT balances and establishing a 9.8% ROE for future GRIP filings for the South Texas jurisdiction.
|
Beaumont/East Texas and Texas Gulf (Railroad Commission)
|
||||||||||
GRIP
|
|
14.0
|
|
March
2018
|
|
July
2018
|
|
TBD
|
|
Based on net change in invested capital of $72.0 million and reflects approximately $1.1 million decrease in the federal income tax rate.
|
Arkansas (APSC)
|
||||||||||
FRP
|
|
7.8
|
|
April
2018
|
|
October 2018
|
|
TBD
|
|
Based on ROE of 9.5% as approved in the last rate case and reflects approximately $11.2 million decrease in the federal income tax rate and amortization of EDIT balances.
|
Minnesota (MPUC)
|
||||||||||
Rate Case
|
|
56.5
|
|
August 2017
|
|
TBD
|
|
TBD
|
|
Reflects a proposed 10.0% ROE on a 52.18% equity ratio. Includes a proposal to extend decoupling beyond current expiration date of June 2018. Interim rates reflecting an annual increase of $47.8 million were effective October 1, 2017. A unanimous settlement agreement was filed in March 2018, which is subject to MPUC approval. The settlement agreement increases base rates by $3.9 million, makes decoupling a permanent part of the tariff, incorporates the impact of the decrease in the federal income tax rate and amortization of EDIT balances (approximately $20 million) and establishes or continues tracker recovery mechanisms that account for approximately $13.3 million in the initial filing.
|
Mississippi (MPSC)
|
||||||||||
RRA
|
|
4.0
|
|
May
2018
|
|
July
2018
|
|
TBD
|
|
Authorized ROE of 9.144% and a capital structure of 50% debt and 50% equity. Reflects approximately $1.7 million decrease in the federal income tax rate.
|
Oklahoma (OCC)
|
||||||||||
PBRC
|
|
5.6
|
|
March
2018
|
|
TBD
|
|
TBD
|
|
Based on ROE of 10% and reflects approximately $1.2 million decrease in the federal income tax rate and amortization of certain EDIT balances.
|
(1)
|
Represents proposed increases when effective date and/or approval date is not yet determined. Approved rates could differ materially from proposed rates.
|
Execution Date
|
|
Size of
Facility
|
|
Amount
Utilized
|
|
Termination Date
|
||||
(in millions)
|
||||||||||
March 3, 2016
|
|
$
|
900
|
|
|
$
|
430
|
|
(1)
|
March 3, 2022
|
Moody’s
|
|
S&P
|
|
Fitch
|
||||||
Rating
|
|
Outlook (1)
|
|
Rating
|
|
CreditWatch (2)
|
|
Rating
|
|
Outlook (3)
|
Baa2
|
|
Stable
|
|
A-
|
|
Negative
|
|
BBB
|
|
Positive
|
(1)
|
A Moody’s rating outlook is an opinion regarding the likely direction of an issuer’s rating over the medium term.
|
(2)
|
An S&P CreditWatch assesses the potential direction of a short-term or long-term credit rating.
|
(3)
|
A Fitch rating outlook indicates the direction a rating is likely to move over a one- to two-year period.
|
•
|
cash collateral requirements that could exist in connection with certain contracts, including our weather hedging arrangements, and gas purchases, gas price and gas storage activities of our Natural Gas Distribution and Energy Services business segments;
|
•
|
acceleration of payment dates on certain gas supply contracts under certain circumstances, as a result of increased gas prices and concentration of natural gas suppliers;
|
•
|
increased costs related to the acquisition of natural gas;
|
•
|
increases in interest expense in connection with debt refinancings and borrowings under our credit facility;
|
•
|
various legislative or regulatory actions;
|
•
|
incremental collateral, if any, that may be required due to regulation of derivatives;
|
•
|
the ability of GenOn and its subsidiaries, currently the subject of bankruptcy proceedings, to satisfy their obligations in respect of GenOn’s indemnity obligations to CenterPoint Energy and its subsidiaries;
|
•
|
slower customer payments and increased write-offs of receivables due to higher gas prices or changing economic conditions;
|
•
|
the outcome of litigation brought by or against us;
|
•
|
restoration costs and revenue losses resulting from future natural disasters such as hurricanes and the timing of recovery of such restoration costs; and
|
•
|
various other risks identified in “Risk Factors” in Item 1A of Part I of our
2017
Form 10-K.
|
|
CENTERPOINT ENERGY RESOURCES CORP.
|
|
|
|
|
By:
|
/s/ Kristie L. Colvin
|
|
Kristie L. Colvin
|
|
Senior Vice President and Chief Accounting Officer
|
By:
|
/s/ Carla A. Kneipp
|
|
Carla A. Kneipp
|
|
Vice President and Treasurer
|
Attest
|
|
/s/ Vincent A. Mercaldi
|
Vincent A. Mercaldi
|
Corporate Secretary
|
|
|
|
(SEAL)
|
THE BANK OF NEW YORK MELLON TRUST
|
|
COMPANY, N.A.,
|
|
As Trustee
|
|
|
|
|
|
By:
|
/s/ R. Tarnas
|
|
Authorized Signatory
|
Original Interest Accrual Date: March 28, 2018
Stated Maturity: April 1, 2023
Interest Rate: 3.55%
Interest Payment Dates: April 1 and October 1
Initial Interest Payment Date: October 1, 2018
Regular Record Dates: March 15 and September 15 immediately preceding the applicable Interest Payment Date
|
Redeemable: Yes [X] No [ ]
Redemption Date: At any time.
Redemption Price: 1) On any date prior to March 1, 2023 (the “Par Call Date”) at a price equal to the greater of (i) 100% of the principal amount of this Security or the portion hereof to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on this Security, or the portion thereof to be redeemed, that would be due if this Security matured on the Par Call Date but for the redemption (not including any portion of such payments of interest accrued to the Redemption Date) discounted to the Redemption Date on a semiannual basis at the applicable Treasury Rate plus 15 basis points; plus, in each case, accrued and unpaid interest on the principal amount being redeemed to, but excluding, the Redemption Date; or 2) on or after the Par Call Date, at a price equal to 100% of the principal amount of this Security or the portion thereof to be redeemed plus accrued and unpaid interest on the principal amount being redeemed to, but excluding, the Redemption Date.
|
Principal Amount
|
|
Registered No. T-1
|
$_______________
1
|
|
CUSIP 15189W AK6
|
Dated: _____________________________
|
CENTERPOINT ENERGY RESOURCES CORP.
|
By:
|
|
|
Authorized Signatory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Date of
Adjustment
|
|
Decrease in Aggregate
Principal Amount of
Securities
|
|
Increase in Aggregate
Principal Amount of
Securities
|
|
Aggregate Principal
Amount of Securities
Remaining After
Such Decrease or
Increase
|
|
Notation
by Security
Registrar
|
Original Interest Accrual Date: March 28, 2018
Stated Maturity: April 1, 2028
Interest Rate: 4.00%
Interest Payment Dates: April 1 and October 1
Initial Interest Payment Date: October 1, 2018
Regular Record Dates: March 15 and September 15 immediately preceding the applicable Interest Payment Date
|
Redeemable: Yes [X] No [ ]
Redemption Date: At any time.
Redemption Price: 1) On any date prior to January 1, 2028 (the “Par Call Date”) at a price equal to the greater of (i) 100% of the principal amount of this Security or the portion hereof to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on this Security, or the portion thereof to be redeemed, that would be due if this Security matured on the Par Call Date but for the redemption (not including any portion of such payments of interest accrued to the Redemption Date) discounted to the Redemption Date on a semiannual basis at the applicable Treasury Rate plus 20 basis points; plus, in each case, accrued and unpaid interest on the principal amount being redeemed to, but excluding, the Redemption Date; or 2) on or after the Par Call Date, at a price equal to 100% of the principal amount of this Security or the portion thereof to be redeemed plus accrued and unpaid interest on the principal amount being redeemed to, but excluding, the Redemption Date.
|
Principal Amount
|
|
Registered No. T-1
|
$_______________
†
|
|
CUSIP 15189W AL4
|
Dated: _____________________________
|
CENTERPOINT ENERGY RESOURCES CORP.
|
By:
|
|
|
Authorized Signatory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Date of
Adjustment
|
|
Decrease in Aggregate
Principal Amount of
Securities
|
|
Increase in Aggregate
Principal Amount of
Securities
|
|
Aggregate Principal
Amount of
Securities
Remaining After
Such Decrease or
Increase
|
|
Notation
by
Security
Registrar
|
|
Three Months Ended March 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in millions, except ratios)
|
||||||
Net income
|
$
|
130
|
|
|
$
|
147
|
|
Equity in earnings of unconsolidated affiliates, net of distributions
|
5
|
|
|
2
|
|
||
Income tax expense
|
37
|
|
|
90
|
|
||
Capitalized interest
|
—
|
|
|
(1
|
)
|
||
|
172
|
|
|
238
|
|
||
|
|
|
|
|
|
||
Fixed charges, as defined:
|
|
|
|
|
|
||
|
|
|
|
|
|
||
Interest
|
29
|
|
|
29
|
|
||
Capitalized interest
|
—
|
|
|
1
|
|
||
Interest component of rentals charged to operating expense
|
1
|
|
|
1
|
|
||
Total fixed charges
|
30
|
|
|
31
|
|
||
|
|
|
|
|
|
||
Earnings, as defined
|
$
|
202
|
|
|
$
|
269
|
|
|
|
|
|
|
|
||
Ratio of earnings to fixed charges
|
6.73
|
|
|
8.68
|
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
/s/ Scott M. Prochazka
|
Scott M. Prochazka
|
President and Chief Executive Officer
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
/s/ William D. Rogers
|
William D. Rogers
|
Executive Vice President and Chief Financial Officer
|
/s/ Scott M. Prochazka
|
Scott M. Prochazka
|
President and Chief Executive Officer
|
May 4, 2018
|
/s/ William D. Rogers
|
William D. Rogers
|
Executive Vice President and Chief Financial Officer
|
May 4, 2018
|