40-F

U.S. SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 40-F

oREGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934.

xANNUAL REPORT PURSUANT TO SECTION 13(a) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 2018 Commission File Number: 333-225606

ALTAGAS LTD.

(Exact name of Registrant as specified in its charter)

Canada

(Province or other jurisdiction of incorporation or organization)

1311
(Primary Standard Industrial
Classification Code Number) None
(I.R.S. Employer
Identification Number)

1700, 355-4th Avenue SW

Calgary, Alberta T2P 0J1

(403) 691-7575

(Address and telephone number of Registrant’s principal executive offices)

AltaGas Services (U.S.) Inc.

1919 McKinney Ave.

Dallas, Texas 75201

(469) 904-5200

(Name, address (including zip code) and telephone number (including area code)
of agent for service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act.

None

(Title of Class)

Securities registered or to be registered pursuant to Section 12(g) of the Act.

None

(Title of Class)

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.

None

(Title of Class)

For Annual Reports indicate by check mark the information filed with this Form:

x Annual information form x Audited annual financial statements

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report:

There were 275,224,066 Common Shares, of no par value, outstanding as of December 31, 2018.

Indicate by check mark whether the Registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Exchange Act 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 filing requirements for the past 90 days.

Yes x  No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).

Yes x  No o

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 12b-2 of the Exchange Act.

Emerging growth company o

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, 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.   o

This Annual Report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, the registrant’s Registration Statement on Form F-10 (File No. 333-225606) and under the Securities Act of 1933, as amended.

PRINCIPAL DOCUMENTS

The following documents have been filed as part of this Annual Report on Form 40-F as Appendices hereto:

A.Annual Information Form

The Annual Information Form of AltaGas Ltd. (the “Company” or “Registrant”) for the fiscal year ended December 31, 2018 is included as Appendix A of this Annual Report on Form 40-F.

B.Audited Annual Financial Statements

The Company’s audited consolidated financial statements for the fiscal year ended December 31, 2018, including the auditor’s report with respect thereto, are included as Appendix B of this Annual Report on Form 40-F.

C.Management’s Discussion and Analysis

The Company’s Management’s Discussion and Analysis for the year ended December 31, 2018 is included as Appendix C of this Annual Report on Form 40-F.

CERTIFICATIONS AND DISCLOSURE REGARDING CONTROLS AND PROCEDURES

Certifications. See Exhibits 99.2, 99.3, 99.4 and 99.5 to this Annual Report on Form 40-F.

Disclosure Controls and Procedures. The Registrant maintains disclosure controls and procedures and internal control over financial reporting designed to ensure that information required to be disclosed in the Registrant’s filings under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission (the “SEC”). The Registrant’s Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), after having evaluated the effectiveness of the Registrant’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report, have concluded that, as of such date, the Registrant’s disclosure controls and procedures were effective to ensure that information required to be disclosed by the Registrant in reports that the Registrant files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. However, as recommended by the SEC in its adopting release for the rules governing the disclosure and control procedures discussed above, the Registrant will continue to periodically evaluate its disclosure controls and procedures and will make modifications from time to time as deemed necessary to ensure that information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

The Registrant’s disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives, and, as indicated in the preceding paragraph, the CEO and CFO believe that the Registrant’s disclosure controls and procedures are effective at that reasonable assurance level, although the CEO and CFO do not expect that the disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Management Report on Internal Control over Financial Reporting:  This annual report does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the company’s registered public accounting firm due to a transition period established by rules of the Securities and Exchange Commission for newly public companies.

Changes in Internal Control Over Financial Reporting. During the fiscal year ended December 31, 2018, there were no changes in the Registrant’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Registrant’s internal control over financial reporting.

NOTICES PURSUANT TO REGULATION BTR

None.

IDENTIFICATION OF THE AUDIT COMMITTEE

The Registrant has a separately-designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. The members of the audit committee are: Catherine M. Best, Allan L. Edgeworth, Robert B. Hodgins and Pentti Karkkainen.

AUDIT COMMITTEE FINANCIAL EXPERT

The board of directors of the Registrant has determined that each Catherine M. Best, Allan L. Edgeworth, Robert B. Hodgins and Pentti Karkkainen, members of the Registrant’s audit committee, qualify as audit committee financial experts for purposes of paragraph (8) of General Instruction B to Form 40-F. Details of the relevant experience of each member of the audit committee is included under the heading “Audit Committee — Relevant Education and Experience” at page 55 of the Registrant’s Annual Information Form for the fiscal year ended December 31, 2018, filed as part of this Annual Report on Form 40-F in Appendix A. The board of directors has further determined that each of Catherine M. Best, Allan L. Edgeworth, Robert B. Hodgins and Pentti Karkkainen is also independent, as that term is defined in the Corporate Governance Listing Standards of the New York Stock Exchange (the “NYSE”). The Commission has indicated that the designation of each Catherine M. Best, Allan L. Edgeworth, Robert B. Hodgins and Pentti Karkkainen as an audit committee financial

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expert does not make any of them an “expert” for any purpose, impose any duties, obligations or liabilities on them that are greater than those imposed on members of the audit committee and the board of directors who do not carry this designation or affect the duties, obligations or liabilities of any other member of the audit committee or the board of directors.

ADDITIONAL DISCLOSURE

Code of Ethics.

The Registrant has adopted a “code of ethics” (as that term is defined in Form 40-F), entitled the “Code of Business Ethics”, that applies to directors, officers, employees, contractors, consultants, representatives and agents of the Registrant including its principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions. In 2018, there were no waivers, including implicit waivers, or amendments granted from any provision of the Code of Business Ethics.

The Code of Business Ethics is available for viewing on the Registrant’s website at www.altagas.ca.

Principal Accountant Fees and Services.

The required disclosure is included under the heading “Audit Committee - External Auditor Service Fees by Category” of the Registrant’s Annual Information Form for the fiscal year ended December 31, 2018, filed as part of this Annual Report on Form 40-F in Appendix A.

Pre-Approval Policies and Procedures.

The Audit Committee pre-approves all audit services to be provided to us by our independent auditors. The Audit Committee’s policy regarding the pre-approval of non-audit services to be provided to us by our independent auditors is that all such services shall be pre-approved by the Audit Committee. All non-audit services performed by our auditors for the fiscal year ended December 31, 2018 have been pre-approved by our Audit Committee.

Off-Balance Sheet Arrangements.

The Registrant has no off-balance sheet arrangements as defined under Form 40-F.

Tabular Disclosure of Commitments.

The required disclosure is included under the heading “Contractual Obligations” in the registrant’s Management’s Discussion and Analysis for the year ended December 31, 2018, filed as part of this Annual Report on Form 40-F in Appendix C.

Mine Safety Disclosure.

Not applicable.

UNDERTAKING

Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

CONSENT TO SERVICE OF PROCESS

Form F-X signed by the Registrant and its agent for service of process has been filed with the Commission together with Registrant’s Registration Statement on Form 40-F (333-225606) in connection with its securities registered on such form.

Any changes to the name or address of the agent for service of process of the Registrant shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of the Registrant.

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SIGNATURES

Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: February 28, 2019

AltaGas Ltd.
By:	/s/ Randall L. Crawford
Name:	Randall L. Crawford
Title:	President and Chief Executive Officer

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EXHIBIT INDEX

Exhibit	Description
99.1	Consent of Ernst & Young LLP, Independent Registered Public Accountant
99.2	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
99.3	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
99.4	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.5	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101	Interactive Data File

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APPENDIX A

ALTAGAS LTD. ANNUAL INFORMATION FORM FOR THE FISCAL YEAR

ENDED DECEMBER 31, 2018

ALTAGAS LTD.

Annual Information Form

For the year ended December 31, 2018

Dated: February 27, 2019

TABLE OF CONTENTS

GENERAL INFORMATION	2
FORWARD-LOOKING INFORMATION AND STATEMENTS	2
GLOSSARY	4
METRIC CONVERSION	11
CORPORATE STRUCTURE	11
INCORPORATION	11
AMENDED ARTICLES	11
INTERCORPORATE RELATIONSHIPS	12
OVERVIEW OF THE BUSINESS	13
ALTAGAS’ GEOGRAPHIC FOOTPRINT	14
RECENT NOTEWORTHY TRANSACTIONS	16
OUTLOOK	17
GENERAL DEVELOPMENT OF ALTAGAS’ BUSINESS	18
DEVELOPMENT OF THE UTILITIES BUSINESS OF ALTAGAS	18
DEVELOPMENT OF THE MIDSTREAM BUSINESS OF ALTAGAS	19
DEVELOPMENT OF THE POWER BUSINESS OF ALTAGAS	20
BUSINESS OF THE CORPORATION	21
UTILITIES BUSINESS	21
MIDSTREAM BUSINESS	31
POWER BUSINESS	41
CORPORATE SEGMENT	46
CAPITAL STRUCTURE	46
DESCRIPTION OF CAPITAL STRUCTURE	46
GENERAL	48
EMPLOYEES	48
DIRECTORS AND OFFICERS	49
EXECUTIVE OFFICERS	52
AUDIT COMMITTEE	53
RISK FACTORS	54
ENVIRONMENTAL AND SAFETY POLICIES AND SOCIAL RESPONSIBILITY	69
ENVIRONMENTAL REGULATION	69
STAKEHOLDER ENGAGEMENT AND INDIGENOUS PEOPLES POLICY	73
DIVIDENDS	73
MARKET FOR SECURITIES	75
CREDIT RATINGS	78
MATERIAL CONTRACTS	79
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	80
LEGAL PROCEEDINGS	80
REGULATORY ACTIONS	80
INTERESTS OF EXPERTS	80
ADDITIONAL INFORMATION	81
TRANSFER AGENTS AND REGISTRARS	81
SCHEDULE A: AUDIT COMMITTEE MANDATE	A-1

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GENERAL INFORMATION

Unless otherwise noted, the information contained in this AIF is stated as at December 31, 2018 and all dollar amounts in this AIF are in Canadian dollars. Financial information is presented in accordance with United States generally accepted accounting principles. For an explanation of certain terms and abbreviations used in this AIF see the “Glossary” of this AIF.

FORWARD-LOOKING INFORMATION AND STATEMENTS

This AIF contains forward-looking information (forward-looking statements). Words such as “may”, “can”, “would”, “could”, “should”, “will”, “intend”, “plan”, “anticipate”, “believe”, “aim”, “seek”, “propose”, “contemplate”, “estimate”, “focus”, “strive”, “forecast”, “expect”, “project”, “target”, “potential”, “objective”, “continue”, “outlook”, “vision”, “opportunity” and similar expressions suggesting future events or future performance, as they relate to the Corporation or any affiliate of the Corporation, are intended to identify forward-looking statements. In particular, this AIF contains forward-looking statements with respect to, among other things, business objectives, expected growth, results of operations, performance, business projects and opportunities and financial results.

Specifically, such forward-looking statements included in this document include, but are not limited to, statements with respect to the following: the Corporation’s long-term strategy in regard to its Utilities, Midstream and Power segments; provision of certain administrative, corporate and operational services to ACI until June 2020; expected cost of commitments made by the Corporation in relation to the approval of the WGL Acquisition; potential effect of the Ring Fenced Entities being unavailable to the Corporation’s creditors in a bankruptcy; focus on integration activities following completion of the WGL Acquisition; expected operational date of RIPET; expected construction completion schedule, in-service date and date of returns for Marquette Connector Pipeline; additional asset sales of approximately $1.5 to $2.0 billion planned for 2019 and use of funds therefrom; term of WGL transportation and storage contracts; potential and anticipated impacts of the TCJA; filing, hearing and decision dates for pending and future rate cases and matters with PSC of MD, SCC of VA, PSC of DC, MPSC, RCA and D.C. Court of Appeals; timing for expensing and potential recovery of costs associated with regulatory commitments; potential remediation obligations; timing for additional North Pine capacity to be on-stream; timing for Townsend 2B to be on-stream and capacity of the facility; anticipated in-service date for Leidy South; timing of construction of and anticipated investment of WGL in Mountain Valley; estimated operations capacity of RIPET; expected impact of regulation on each of the Corporation’s segments; intention not to use preferred shares as a defensive tactic; and future payment and level of dividends.

These statements involve known and unknown risks, uncertainties and other factors that may cause actual results, events and achievements to differ materially from those expressed or implied by such statements. Such statements reflect AltaGas’ current expectations, estimates and projections based on certain material factors and assumptions at the time the statement was made. Material assumptions include: expected commodity supply, demand and pricing; volumes and rates; exchange rates; inflation; interest rates; credit rating; regulatory approvals and policies; future operating and capital costs; project completion dates; capacity expectations; implications of recent U.S. tax legislation changes; and the outcomes of significant commercial contract negotiation;.

AltaGas’ forward-looking statements are subject to certain risks and uncertainties which could cause results or events to differ from current expectations, including, without limitation: access to capital and increased borrowing costs; condition and overall strength of the global economy; changes in energy consumption by consumers; fluctuations in commodity prices and interest rates; changes in AltaGas’ credit ratings; foreign exchange risk; ability to service debt; market value of AltaGas’ securities; AltaGas’ ability to pay dividends; risks associated with the acquisition of WGL and the underlying business of WGL; risks in AltaGas’ growth strategy; issuance of additional shares; volume throughput and the impacts of commodity pricing, supply, composition and other market risks; counterparty credit risk; dependence on third parties; natural gas supply risk; changes in law; legislative and regulatory environment and decisions; AltaGas’ ability to economically and safely develop, contract and operate assets; potential litigation; cybersecurity risks; AltaGas’ relationships with external stakeholders, including Indigenous stakeholders; available electricity prices; interest rate risk; underinsured losses; weather, hydrology and climate changes; the potential for service interruptions; the Harmattan Rep agreements; availability of supply from Cook Inlet; health and safety risks; AltaGas’ ability to update infrastructure on a timely basis; effects of decommissioning, abandonment and reclamation costs; impact of labour relations and reliance on key personnel; availability of biomass fuel; and the other factors discussed under the heading “Risk Factors” in this AIF.

Many factors could cause AltaGas’ or any particular business segment’s actual results, performance or achievements to vary from those described in this AIF, including, without limitation, those listed above and the assumptions upon which

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they are based proving incorrect. These factors should not be construed as exhaustive. Should one or more of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary materially from those described in this AIF as intended, planned, anticipated, believed, sought, proposed, estimated, forecasted, expected, projected or targeted and such forward-looking statements included in this AIF, should not be unduly relied upon. The impact of any one assumption, risk, uncertainty or other factor on a particular forward-looking statement cannot be determined with certainty because they are interdependent and AltaGas’ future decisions and actions will depend on management’s assessment of all information at the relevant time. Such statements speak only as of the date of this AIF. AltaGas does not intend, and does not assume any obligation, to update these forward-looking statements except as required by law. The forward-looking statements contained in this AIF are expressly qualified by these cautionary statements.

Financial outlook information contained in this AIF about prospective results of operations, financial position or cash flow is based on assumptions about future events, including economic conditions and proposed courses of action, based on management’s assessment of the relevant information currently available. Readers are cautioned that such financial outlook information contained in this AIF should not be used for purposes other than for which it is disclosed herein.

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GLOSSARY

Unless the context otherwise requires, terms used in this AIF have the following meanings and references to agreements include any amendments, restatements, modifications or supplements in effect as of the date hereof:

“ACI” means AltaGas Canada Inc.;

“ACI IPO” means initial public offering of common shares of ACI;

“AESO” means the Alberta Electric System Operator;

“AIF” means this Annual Information Form;

“AIJVLP” means AltaGas Idemitsu Joint Venture Limited Partnership;

“AltaGas” or the “Corporation” means AltaGas Ltd., including, where the context requires, the affiliates of AltaGas Ltd.;

“Alton Natural Gas Storage Project” means the underground gas storage facility and associated pipelines located near Truro, Nova Scotia that is currently under construction and owned by AltaGas’ indirect wholly-owned subsidiary Alton Natural Gas Storage L.P.;

“ASC” means the Alberta Securities Commission;

“Astomos” means Astomos Energy Corporation;

“AUI” means AltaGas Utilities Inc.;

“Bbls” means stock tank barrels of ethane and NGLs, expressed in standard 42 U.S. gallon barrels or 34.972 imperial gallon barrels;

“Bbls/d” means Bbls per day;

“Bcf” means billion cubic feet or 1,000,000 Mcf of natural gas;

“Bcf/d” means Bcf per day;

“BC Hydro” means the British Columbia Hydro and Power Authority;

“BCOGC” means the British Columbia Oil and Gas Commission;

“BCSC” means the British Columbia Securities Commission;

“Black Swan” means Black Swan Energy Ltd.;

“Blair Creek Facility” means the Blair Creek Processing Facility located approximately 140 km northwest of Fort St. John, British Columbia, owned by AltaGas’ indirect wholly-owned subsidiary AltaGas Northwest Processing Limited Partnership;

“Blythe” means Blythe Energy Inc.;

“Blythe Energy Center” means the 507 MW gas-fired generation facility located near Blythe, California, together with the related 67 miles transmission lines, owned by AltaGas’ indirect wholly-owned subsidiary Blythe;

“Board of Directors” means the board of directors of AltaGas, as from time to time constituted;

“Bridge Facility” means the bridge facility of up to US$3.0 billion provided by a syndicate of lenders, including JPMorgan Chase Bank, N.A., The Toronto-Dominion Bank and Royal Bank of Canada;

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“Brush II” means the 70 MW gas-fired generation facility in Colorado, owned by AltaGas’ indirect wholly-owned subsidiary AltaGas Brush Energy Inc.;

“C&I” means commercial and industrial;

“Cabot” means Cabot Oil & Gas Corporation;

“CAISO” means the California Independent System Operator;

“CBCA” means the Canada Business Corporations Act, R.S.C. 1985, c. C 44, as amended from time to time, including the regulations from time to time promulgated thereunder;

“CCAA” means the Companies’ Creditors Arrangement Act, R.S.C. 1985, c. C 36, as amended from time to time, including the regulations from time to time promulgated thereunder;

“CCEMA” means the Climate Change and Emissions Management Act, S.A. 2003, C-16.7, as amended from time to time, including the regulations from time to time promulgated thereunder;

“CCIR” means the Carbon Competitiveness Incentive Regulation, A.R. 255/2017 under the CCEMA, as amended from time to time;

“Central Penn” means the Central Penn pipeline, a 185 mile pipeline originating in Susquehanna County, Pennsylvania and extending to Lancaster County, Pennsylvania;

“CES” means Commercial Energy Systems;

“CINGSA” means Cook Inlet Natural Gas Storage Alaska, LLC;

“CINGSA Storage Facility” means the in-field storage facility in the Cook Inlet area of Alaska owned and operated by CINGSA;

“CN” means Canadian National Railway Company;

“Common Shares” means common shares of AltaGas Ltd.;

“Constitution” means Constitution Pipeline Company, LLC;

“Co-stream Facility” means the connection of Harmattan to the west leg of the NGTL system, and the related NGL extraction equipment, to process up to 250 Mmcf/d of natural gas at Harmattan to recover ethane and NGLs;

“CPI” means the Consumer Price Index;

“DBRS” means DBRS Limited and its successors;

“Dekatherm” means 10 Therms;

“Degree Day” means the amount that the daily mean temperature deviates below 65 degrees Fahrenheit at SEMCO Gas, ENSTAR, and Washington Gas, such that a one degree difference equates to one Degree Day;

“EEEP” means the Edmonton ethane extraction plant and related facilities, AltaGas’ interest being owned by its indirect wholly-owned subsidiary AltaGas Extraction and Transmission Limited Partnership;

“EHS Management System” means AltaGas’ Environmental, Health & Safety Management System;

“ENSTAR” means the natural gas distribution business conducted by SEMCO Energy in Alaska under the name ENSTAR Natural Gas Company;

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“EH&S Committee” means the Environment, Health and Safety Committee of the Board of Directors;

“EPA” means electricity purchase agreement;

“EQM” means EQM Gathering Opco, LLC;

“EQT” means EQT Midstream Partners, LP;

“ESA” means Energy Storage Resource Adequacy Purchase Agreement;

“FERC” means the United States Federal Energy Regulatory Commission;

“Ferndale Terminal” means the storage, distribution and export facility for bulk shipments of propane, butane and iso-butane located on the west coast near Ferndale, Washington, and owned by a subsidiary of Petrogas;

“FID” means final investment decision;

“Fitch” means Fitch Ratings Inc.;

“Forrest Kerr” means the 195 MW run-of-river hydroelectric facility, one of the three run-of-river hydroelectric facilities in northwest British Columbia that forms part of the Northwest Hydro Facilities;

“GHG” means greenhouse gas;

“GJ” means gigajoule or 1,000,000,000 joules;

“Gordondale Facility” means the Gordondale Gas Processing Facility in the Gordondale area of the Montney reserve area approximately 100 km northwest of Grande Prairie, Alberta, owned by AltaGas’ indirect wholly-owned subsidiary AltaGas Northwest Processing Limited Partnership;

“GSAs” means Groundwater Sustainability Agencies;

“GWh” means gigawatt-hour or 1,000,000,000 watt-hours; the watt-hour is equal to one watt of power flowing steadily for one hour;

“Hampshire Gas” means Hampshire Gas Company, a subsidiary of WGL that provides regulated interstate natural gas storage services to Washington Gas under a FERC approved interstate storage service tariff;

“Harmattan” means the combined Harmattan gas processing facility and extraction plant and associated facilities, owned by AltaGas’ indirect wholly-owned subsidiary Harmattan Gas Processing Limited Partnership;

“Heritage Gas” means Heritage Gas Limited;

“HHCs” means heavy hydrocarbons;

“Idemitsu” means Idemitsu Kosan Co., Ltd.;

“JEEP” means the Joffre ethane extraction plant and related facilities;

“Kelt” means Kelt Exploration (LNG) Ltd;

“km” means kilometer;

“Leidy South” means the expansion of Central Penn, which WGL Midstream is participating in;

“LNG” means liquefied natural gas;

“LPG” means liquefied petroleum gas;

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“m3” means a cubic meter of natural gas at standard conditions of measurement;

“Marquette Connector Pipeline” means the proposed new pipeline to be constructed, owned and operated by SEMCO Gas that will connect the Great Lakes Gas Transmission pipeline to the Northern Natural Gas pipeline in Marquette, Michigan;

“Mcf” means a thousand cubic feet of natural gas at standard imperial conditions of measurement;

“Mcf/d” means Mcf per day;

“McLymont Creek” means the 66 MW run-of-river hydroelectric facility, one of the three run-of-river hydroelectric facilities in northwest British Columbia that forms part of the Northwest Hydro Facilities;

“MDth” means millions of Dekatherms;

“Meade” means Meade Pipeline Co LLC;

“Merger Agreement” means the agreement and plan of merger dated as of January 25, 2017 among AltaGas, Merger Sub and WGL;

“Merger Sub” means Wrangler Inc., a Virginia corporation and an indirect wholly-owned subsidiary of AltaGas;

“MGP” means manufactured gas plant;

“Mmcf” means a million cubic feet of natural gas at standard conditions of measurement;

“Mmcf/d” means Mmcf per day;

“Mountain Valley” means Mountain Valley pipeline, an equity investment of WGL Midstream;

“MPSC” means the Michigan Public Service Commission;

“MTN” means medium term notes issued from time to time under either the amended and restated trust indenture dated July 1, 2010 between AltaGas and Computershare Trust Company of Canada, as further amended, restated, supplemented or otherwise modified from time to time or the trust indenture dated September 26, 2017 between AltaGas and Computershare Trust Company of Canada, as amended, restated, supplemented or otherwise modified from time to time, as the case may be;

“MW” means megawatt; one MW is 1,000,000 watts; the watt is the basic electrical unit of power;

“MWh” means megawatt-hour or 1,000,000 watt-hours; the watt-hour is equal to one watt of power flowing steadily for one hour;

“NFA” means No Further Action;

“NGL” or “NGLs” means natural gas liquids, which includes primarily propane, butane and condensate;

“NGTL” means NOVA Gas Transmission Ltd.;

“Non-Ring Fenced Entities” means AltaGas and its affiliates other than Washington Gas and the SPE;

“North Pine Facility” means the NGL separation facility, located approximately 40 km northwest of Fort St. John, British Columbia.

“North Pine Pipelines” means two eight inch diameter NGL supply pipelines, each approximately 40 km in length, which runs from the existing Alaska Highway truck terminal to the North Pine Facility;

“Northwest Hydro Facilities” means the three run-of-river hydroelectric facilities in northwest British Columbia, being Forrest Kerr, McLymont Creek and Volcano Creek;

“Nova Chemicals” means NOVA Chemicals Corporation;

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“NYSDEC” means the New York State Department of Environmental Conservation;

“Painted Pony” means Painted Pony Energy Ltd.;

“PG&E” means Pacific Gas & Electric Company;

“Pembina” means Pembina Infrastructure and Logistics LP;

“Petrogas” means Petrogas Energy Corp., a privately-held leading North American integrated midstream company in which AltaGas Idemitsu Joint Venture Limited Partnership has a two-third ownership interest;

“Plan” means the Premium DividendTM, Dividend Reinvestment and Optional Cash Purchase Plan of the Corporation;

“PNG” means Pacific Northern Gas Ltd.;

“Pool” means the scheme operated by the AESO for (i) exchanges of electric energy, and (ii) financial settlement for the exchange of electric energy;

“Pomona” means the 44.5 MW gas-fired generation facility located in Pomona, California, owned by AltaGas’ indirect wholly-owned subsidiary AltaGas Pomona Energy Inc.;

“Pomona Energy Storage Facility” means the 20 MW lithium ion battery storage facility in Pomona, California, owned by AltaGas’ indirect wholly-owned subsidiary AltaGas Pomona Energy Storage Inc.;

“PPA” means power purchase agreement;

“Preferred Shares” means the preferred shares of AltaGas Ltd. as a class, including, without limitation, the Series A Shares, Series B Shares, Series C Shares, Series D Shares, Series E Shares, Series F Shares, Series G Shares, Series H Shares, Series I Shares, Series J Shares, Series K Shares, and Series L Shares;

“PRPA” means Prince Rupert Port Authority;

“PSC of DC” means the Public Service Commission of the District of Columbia;

“PSC of MD” means the Maryland Public Service Commission;

“RCA” means the Regulatory Commission of Alaska;

“RECs” means Renewable Energy Credits;

“Rep Agreements” mean the Representation, Management and Processing Agreements at Harmattan;

“RILE LP” means Ridley Island LPG Export Limited Partnership, a limited partnership of which AltaGas’ subsidiaries hold a 70 percent interest and Vopak holds a 30 percent interest;

“Ring Fenced Entities” means Washington Gas and the SPE;

“RIPET” means the Ridley Island Propane Export Terminal, the propane export terminal being constructed by AltaGas’ subsidiary, Ridley Island LPG Export Limited Partnership, to ship up to 1.2 million tonnes of propane per annum and to be located on a portion of land leased by Ridley Terminals Inc. from the PRPA, located on Ridley Island, near Prince Rupert, British Columbia;

TM Denotes trademark of Canaccord Genuity Corp

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“Ripon” means the 49.5 MW gas-fired generation facility in Ripon, California, owned by AltaGas’ indirect wholly-owned subsidiary AltaGas Ripon Energy Inc.;

“ROE” means return on equity;

“Royal Vopak” means Koninklijke Vopak N.V., a public company incorporated under the laws of the Netherlands;

“RTI” means Ridley Terminals Inc.;

“S&P” means Standard & Poor’s Ratings Services and its successors;

“Sarbanes-Oxley” means the Sarbanes-Oxley Act of 2002;

“SCC of VA” means the Commonwealth of Virginia State Corporation Commission;

“SCE” means Southern California Edison Company;

“SEDAR” means System for Electronic Document Analysis and Retrieval, at www.sedar.com;

“SEMCO Energy” means SEMCO Energy, Inc.;

“SEMCO Gas” means the Michigan natural gas distribution business conducted by SEMCO Energy in Michigan under the name SEMCO Energy Gas Company;

“Series A Shares” means the cumulative redeemable 5-year fixed rate reset preferred shares, Series A, of AltaGas;

“Series B Shares” means the cumulative redeemable floating rate preferred shares, Series B, of AltaGas

“Series C Shares” means the cumulative redeemable 5-year fixed rate reset preferred shares, Series C, of AltaGas (US dollar);

“Series D Shares” means the cumulative redeemable floating rate preferred shares, Series D, of AltaGas (US dollar);

“Series E Shares” means the cumulative redeemable 5-year fixed rate reset preferred shares, Series E, of AltaGas;

“Series F Shares” means the cumulative redeemable floating rate preferred shares, Series F, of AltaGas;

“Series G Shares” means the cumulative redeemable 5-year fixed rate reset preferred shares, Series G, of AltaGas;

“Series H Shares” means the cumulative redeemable floating rate preferred shares, Series H, of AltaGas;

“Series I Shares” means the cumulative redeemable 5-year minimum fixed rate reset preferred shares, Series I, of AltaGas;

“Series J Shares” means the cumulative redeemable floating rate preferred shares, Series J, of AltaGas;

“Series K Shares” means the cumulative redeemable 5-year minimum fixed rate reset preferred shares, Series K, of AltaGas;

“Series L Shares” means the cumulative redeemable floating rate preferred shares, Series L of AltaGas;

“SGER” means the Specified Gas Emitters Regulation under the CCEMA, which was replaced with the CCIR on January 1, 2018;

“SGMA” means the Sustainable Groundwater Management Act;

“Share Options” means options to acquire Common Shares granted pursuant to AltaGas’ share option plan;

“Shareholders” mean the holders of Common Shares;

“Shell Energy” means Shell Energy North America (US), LP;

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“SPE” means Wrangler SPE LLC, a wholly-owned special purpose entity subsidiary of WGL incorporated as a bankruptcy remote entity;

“Stonewall System” means the Stonewall Gas Gathering System;

“Subscription Receipts” means the subscription receipts of AltaGas that were issued in 2017, and automatically exchanged for Common Shares following the closing of the WGL Acquisition in accordance with the terms of the Subscription Receipt Agreement, and subsequently delisted from the TSX;

“Subscription Receipt Agreement” means the subscription receipt agreement dated February 3, 2017 among AltaGas, TD Securities Inc., RBC Dominion Securities Inc. and J.P. Morgan Securities Canada Inc. and Computershare Trust Company of Canada, as subscription receipt agent, governing the terms of the Subscription Receipts;

“Sundance B PPAs” means the former power purchase arrangements of ASTC Power Partnership with respect to unit 3 and unit 4 of the coal-fired Sundance plant owned by TransAlta Generation Partnership located approximately 70 km west of Edmonton, Alberta;

“TCJA” means the Tax Cuts and Jobs Act of 2017.

“Therm” is a natural gas unit of measurement that includes a standard measure for heating value. A Therm of gas contains 100,000 British thermal units of heat, or the energy equivalent of burning approximately 100 cubic feet of natural gas under normal conditions. Ten million Therms equal approximately one billion cubic feet of natural gas. One Mcf equals approximately 10.32 Therms;

“Tidewater” means Tidewater Midstream and Infrastructure Inc.;

“Townsend 2A” means the first 99 Mmcf/d train of Townsend Phase 2, a 198 Mmcf/d shallow-cut gas processing facility located on the existing Townsend Facility site, adjacent to the currently operating Townsend Facility;

“Townsend 2B” means the proposed 198 Mmcf/d C3+ deep cut gas processing facility to be located on the existing Townsend Facility site, adjacent to the currently operating Townsend Facility and anticipated to be on-stream in the fourth quarter of 2019;

“Townsend Complex” means, collectively, the Townsend Facility, Townsend 2A and Townsend 2B;

“Townsend Facility” means the 198 Mmcf/d Townsend shallow-cut processing facility in northeast British Columbia owned by AltaGas Northwest Processing Limited Partnership;

“Townsend Phase 2” means the initial expansion of the Townsend Facility in two gas processing trains;

“Transco” means Transcontinental Gas Pipeline Company LLC;

“TSX” means the Toronto Stock Exchange;

“United States” or “U.S.” means the United States of America;

“US dollar” or “US$” means currency in the form of United States dollars;

“Volcano Creek” means the 16 MW run-of-river hydroelectric facility, one of the three run-of-river hydroelectric facilities in northwest British Columbia that forms part of the Northwest Hydro Facilities;

“Vopak” means Vopak Development Canada Inc., a wholly-owned subsidiary of Royal Vopak;

“Washington Gas” means Washington Gas Light Company, a subsidiary of WGL that sells and delivers natural gas primarily to retail customers in the District of Columbia, Maryland and Virginia in accordance with tariffs approved by the Public Service Commission of the District of Columbia, the Maryland Public Service Commission and the Commonwealth of Virginia State Corporation Commission;

“Washington Gas $4.25 Shares” means the US$4.25 series cumulative preferred shares of Washington Gas;

“Washington Gas $4.80 Shares” means the US$4.80 series cumulative preferred shares of Washington Gas;

“Washington Gas $5.00 Shares” means the US$5.00 series cumulative preferred shares of Washington Gas;

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“Washington Gas Preferred Shares” means the preferred shares of Washington Gas as a class, including, without limitation, the Washington Gas $4.25 Shares, Washington Gas $4.80 Shares and Washington Gas $5.00 Shares;

“Washington Gas Resources” means Washington Gas Resources Corporation, a subsidiary of WGL that owns the majority of the non-utility subsidiaries;

“WCSB” means Western Canada Sedimentary Basin;

“WGL” means WGL Holdings, Inc., an indirect subsidiary of AltaGas;

“WGL Acquisition” means the acquisition by AltaGas, indirectly through Merger Sub, of WGL through a merger of Merger Sub with and into WGL pursuant to the Merger Agreement, which closed on July 6, 2018;

“WGL Energy Services” means WGL Energy Services, Inc. (formerly Washington Gas Energy Services, Inc.), a subsidiary of Washington Gas Resources that sells natural gas and electricity to retail customers on an unregulated basis;

“WGL Energy Systems” means WGL Energy Systems, Inc. (formerly Washington Gas Energy Systems, Inc.), a subsidiary of Washington Gas Resources which provides commercial energy efficient and sustainable solutions to government and commercial clients;

“WGL Midstream” means WGL Midstream, Inc., a subsidiary of Washington Gas Resources that engages in acquiring and optimizing natural gas storage and transportation assets;

“WGSW” means WGSW, Inc., a subsidiary of Washington Gas Resources that was formed to invest in certain renewable energy projects; and

“Younger” means the Younger extraction plant and related facilities, AltaGas’ interest being owned by its indirect wholly-owned subsidiary AltaGas Extraction and Transmission Limited Partnership.

METRIC CONVERSION

The following table sets forth certain standard conversions between Standard Imperial Units and the International System of Units (or metric units).

To Convert From	To	Multiply by
Mcf	cubic meters	28.174
cubic meters	cubic feet	35.494
Bbls	cubic meters	0.159
cubic meters	Bbls	6.29
tonnes	long tons	0.984
feet	meters	0.305
meters	feet	3.281
miles	km	1.609
km	miles	0.621
acres	hectares	0.405
hectares	acres	2.471
gigajoule	Mcf	0.9482

CORPORATE STRUCTURE

INCORPORATION

AltaGas is a Canadian corporation amalgamated pursuant to the CBCA on July 1, 2010. AltaGas and/or its predecessors began operations in Calgary, Alberta on April 1, 1994 and AltaGas continues to maintain its head, principal and registered office in Calgary, Alberta currently located at 1700, 355 — 4th Avenue SW, Calgary, Alberta T2P 0J1. AltaGas is a public company, the Common Shares of which trade on the TSX under the symbol “ALA”.

AMENDED ARTICLES

On July 1, 2010, AltaGas filed articles of arrangement under the CBCA to effect a corporate arrangement and the amalgamation of AltaGas Ltd., AltaGas Conversion Inc. and AltaGas Conversion #2 Inc. to form AltaGas. Subsequent to the filing of the articles of arrangement, AltaGas has filed articles of amendment on the following dates in connection with the creation of each series of Preferred Shares: (i) August 13, 2010 to create the first series of Preferred Shares, Series A Shares and the second series of Preferred Shares, Series B Shares; (ii) June 1, 2012 to create the third series of

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Preferred Shares, Series C Shares and the fourth series of Preferred Shares, Series D Shares; (iii) December 9, 2013 to create the fifth series of Preferred Shares, Series E Shares and the sixth series of Preferred Shares, Series F Shares; (iv) June 27, 2014 to create the seventh series of Preferred Shares, Series G Shares and the eighth series of Preferred Shares, Series H Shares; (v) November 17, 2015 to create the ninth series of Preferred Shares, Series I Shares and the tenth series of Preferred Shares, Series J Shares; and (vi) February 15, 2017 to create the eleventh series of Preferred Shares, Series K Shares and the twelfth series of Preferred Shares, Series L Shares.

INTERCORPORATE RELATIONSHIPS

The following organization diagram presents the name and the jurisdiction of incorporation of certain of AltaGas’ subsidiaries as at the date of this Annual Information Form. The diagram does not include all of the subsidiaries of AltaGas. The assets and revenues of those subsidiaries omitted from the diagram individually did not exceed 10 percent, and in the aggregate did not exceed 20 percent, of the total consolidated assets or total consolidated revenues of AltaGas as at and for the year ended December 31, 2018.

Notes:

(1) Updated as of the date of this Annual Information Form.

(2) Unless otherwise stated, ownership is 100%

(3) AltaGas owns a direct interest of 36.8% of ACI. The remaining 63.2% interest in ACI is publicly owned.

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OVERVIEW OF THE BUSINESS

AltaGas, a Canadian corporation, is a leading North American clean energy infrastructure company with strong growth opportunities and a focus on owning and operating assets to provide clean and affordable energy to its customers. The Corporation’s long-term strategy is to grow in attractive areas across its Utility, Midstream, and Power business segments seeking optimal capital deployment. In the Midstream business, the Corporation is focused on optimizing the full value chain of energy exports by providing producers with solutions, including global market access off both coasts of North America via the Corporation’s footprint in two of the most prolific gas plays — the Montney and Marcellus. To optimize capital deployment, the Corporation seeks to invest in U.S utilities located in strong growth markets with increasing construction to support customer additions, system improvement and accelerated replacement programs. In the Power business, AltaGas seeks to create innovative solutions with light capital investment utilizing the Corporation’s clean energy expertise. AltaGas has three business segments:

·Utilities, which serves approximately 1.6 million customers with a rate base of approximately US$3.7 billion through ownership of regulated natural gas distribution utilities across 5 jurisdictions in the United States and two regulated natural gas storage utilities in the United States, delivering clean and affordable natural gas to homes and businesses. The Utilities business also includes storage facilities and contracts for interstate natural gas transportation and storage services;

·Midstream, which, subsequent to the sale of non-core midstream assets in Canada which closed in February 2019 (See “Recent Noteworthy Transactions — Sale of Non-Core Assets”), transacts more than 1.5 Bcf/d of natural gas and includes natural gas gathering and processing, natural gas liquids (NGL) extraction and fractionation, transmission, storage, natural gas and NGL marketing, the Corporation’s 50 percent interest in AltaGas Idemitsu Joint Venture Limited Partnership (AIJVLP), an indirectly held one-third ownership investment in Petrogas Energy Corp. (Petrogas), through which AltaGas’ interest in the Ferndale Terminal is held, an interest in four regulated pipelines in the Marcellus/Utica gas formation in the northeastern United States and WGL’s retail gas marketing business; and

·Power, which, subsequent to the sale of non-core power assets in Canada which closed in February 2019 (See “Recent Noteworthy Transactions — Sale of Non-Core Assets”), and the sale of the remaining 55 percent interest in the Northwest Hydro Facilities which closed in January 2019 (See “Recent Noteworthy Transactions — Sale of Northwest Hydro”), includes 1,105 MW of operational gross capacity from natural gas-fired, biomass, solar, other distributed generation and energy storage assets located in Alberta, Canada and 20 states and the District of Columbia in the United States. The Power business also includes energy efficiency contracting and WGL’s retail power marketing business.

The Corporation’s long-term strategy is to leverage and enhance the strength of its asset footprint to provide customers with integrated energy solutions including global market access. Moving forward, AltaGas is targeting opportunities to develop high-quality energy assets that complement its existing integrated infrastructure footprint within these segments, and to grow its position in key markets to deliver optimal growth over the long term. In the Power segment, AltaGas will continue to seek to create innovative solutions with light capital investment utilizing the Corporation’s clean energy expertise.

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ALTAGAS’ GEOGRAPHIC FOOTPRINT

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RECENT NOTEWORTHY TRANSACTIONS

PUBLIC OFFERING OF ALTAGAS CANADA INC.

On September 12, 2018, ACI, then a wholly owned subsidiary of AltaGas, together with AltaGas as a promoter, filed a preliminary prospectus in relation to the ACI IPO. Prior to the completion of the ACI IPO, AltaGas and AltaGas Holdings Inc. sold certain assets, including Canadian rate-regulated natural gas distribution utility assets (including PNG, AUI and Heritage Gas) and contracted wind power in Canada, as well as an approximate 10 percent indirect equity interest in the Northwest Hydro Facilities to ACI. On October 25, 2018, the ACI IPO was successfully completed, reflecting a final price of $14.50 per common share of ACI. The over-allotment option was exercised in full, and as a result, AltaGas holds approximately 37 percent of ACI’s common shares at December 31, 2018. Net proceeds (consisting of cash and debt) to AltaGas after the deduction of underwriting fees and expenses were approximately $892 million. See “Investment in AltaGas Canada Inc.”

AltaGas has agreed to provide certain administrative, corporate and operational services to ACI pursuant to a transition services agreement for a transition period expiring June 30, 2020, unless earlier terminated.

See “Utilities Business - Investment in AltaGas Canada Inc.”

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ACQUISITION OF WGL

Following the receipt of all required federal, state, and local regulatory approvals, on July 6, 2018 the Corporation acquired WGL, creating a North American leader in the clean energy economy and enhancing AltaGas’ position as a leading North American clean energy infrastructure company. The aggregate purchase price was approximately $9.3 billion (US$7.1 billion), including the assumption of approximately $3.3 billion (US$2.5 billion) of debt and $41 million (US$31 million) of preferred shares. A business acquisition report on Form 51-102F4 was filed on SEDAR on August 8, 2018 in respect of the WGL Acquisition.

The net cash consideration was approximately $6.0 billion (US$4.6 billion), which was funded through net proceeds of approximately $2.3 billion from the sale of Subscription Receipts, gross proceeds of approximately $922 million from the sale of 35 percent of AltaGas’ interest in the Northwest Hydro Facilities, draws on the Bridge Facility and existing cash on hand. The total funding included additional amounts for the payment of fees and regulatory commitments related to the WGL Acquisition. The sale of the Subscription Receipts was completed in the first quarter of 2017 and upon closing of the WGL Acquisition, the Subscription Receipts were exchanged into approximately 84.5 million Common Shares.

In connection with the WGL Acquisition, AltaGas and WGL have made commitments pursuant to the terms of the PSC of DC settlement agreement and the conditions of approval from the PSC of MD and the SCC of VA. Among other things, these commitments include rate credits distributable to both residential and non-residential customers, gas expansion and other programs, various public interest commitments, and safety programs. The total amount expensed in 2018 was approximately US$140 million, of which US$111 million has been paid as of December 31, 2018. In addition, there are certain additional regulatory commitments which will be expensed when the costs are incurred in the future, including the hiring of damage prevention trainers, investment of US$70 million over a 10 year period to further extend natural gas service, and US$8 million for leak mitigation.

The Ring Fenced Entities made certain ring fencing commitments to the PSC of DC, the PSC of MD and the SCC of VA. In order to satisfy these ring fencing commitments, the SPE was formed as a bankruptcy remote special purpose entity established for the purposes of owning the common stock of Washington Gas and of ring fencing Washington Gas, with the intention of removing Washington Gas from the bankruptcy estate of AltaGas and its affiliates other than Washington Gas and the SPE (collectively, the “Non-Ring Fenced Entities”) in the event that any Non-Ring Fenced Entity becomes the subject of bankruptcy or insolvency proceedings. The SPE is a wholly-owned subsidiary of WGL. Because of these ring fencing measures, none of the assets of the Ring Fenced Entities would be available to satisfy the debt or contractual obligations of any Non-Ring Fenced Entity, including any indebtedness or other contractual obligations of AltaGas, and the Ring Fenced Entities do not bear any liability for indebtedness or other contractual obligations of the Non-Ring Fenced Entities, and vice versa.

SALE OF NORTHWEST HYDRO

On June 13, 2018, AltaGas announced that it had entered into a definitive agreement to indirectly sell 35 percent of its interest in the Northwest Hydro Facilities for gross proceeds of $922 million. The transaction closed on June 22, 2018. On December 13, 2018, AltaGas announced that it had reached an agreement for the sale of its remaining interest of approximately 55 percent in the Northwest Hydro Facilities for gross proceeds of approximately $1.37 billion. The second closing occurred in January 2019.

SALE OF NON-CORE ASSETS

On September 10, 2018, AltaGas entered into definitive agreements for the sale of non-core midstream and power assets in Canada and power assets in the United States for total gross proceeds of approximately $560 million.  The sale of the power assets in the United States was completed in the fourth quarter of 2018 and the sale of non-core midstream and power assets in Canada was completed in February 2019. AltaGas also sold 43.7 million shares of Tidewater. The sale of Tidewater shares was completed in September 2018.

IMPLEMENTATION OF BALANCED FUNDING PLAN

As part of the balanced funding plan, approximately US$2.2 billion of the Bridge Facility used to finance the WGL Acquisition was repaid in December 2018, approximately US$1.2 billion of which being refinanced with a new revolving credit facility. As of December 31, 2018, the remaining balance on the Bridge Facility was approximately US$83 million. The remaining balance was fully repaid in February 2019. In addition, the Board of Directors approved a reset of the dividend to improve the financial strength of AltaGas and ensure greater funding flexibility. The Board declared a January 2019 dividend of $0.08 per Common Share, representing a 56 percent reduction from 2018.

OUTLOOK

AltaGas made several steps in 2018 to enhance the strength of its balance sheet, create financial flexibility and focus its portfolio on the Midstream and Utilities segments. In 2019, the Corporation has identified several near-term strategic priorities.

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With the acquisition of WGL completed in July 2018, AltaGas has been and remains focused on integration activities. AltaGas has identified near- and long-term integration priorities, including strategy, organizational effectiveness, growth, financial strength and people and culture, while remaining compliant with regulatory commitments. Significant progress has been made integrating the WGL leadership team, its operations, and core processes, and this will remain a priority for AltaGas in 2019.

AltaGas’ strategy is largely focused on two core and complementary business segments: Midstream and Utilities. Moving forward, AltaGas is targeting opportunities to develop high-quality energy assets that complement its existing integrated infrastructure footprint within these segments, and to grow its position in key markets to deliver optimal growth over the long term. In the Power segment, AltaGas will continue to seek to create innovative solutions with light capital investment utilizing the Corporation’s clean energy expertise.

Expanding Market Access with Integrated Midstream Footprint

RIPET is located near Prince Rupert, British Columbia, and is expected to be the first propane export facility off the west coast of Canada. After comprehensive commissioning activities, the facility is scheduled to begin its operational phase in the first quarter of 2019 with the introduction of feedstock propane and filling the refrigerated storage tank with liquefied product. First cargo is expected early in the second quarter of 2019 which aligns with the propane contract year. Once operational, the facility will provide access to new global markets for producers, while also leveraging our natural gas gathering, processing and fractionation assets in B.C. and Alberta.

Enhancing Returns in U.S. Utilities

Within its Utilities segment, AltaGas will continue to focus on strengthening operational excellence, improving the customer experience and achieving timely recovery on invested capital. For example, the Corporation’s Marquette Connector Pipeline in Michigan, which is expected to be in-service in the fourth quarter of 2019, will simultaneously provide clean and reliable natural gas delivery to thousands of homes in SEMCO Gas’ service territory while earning anticipated returns early in 2020. It will also provide additional natural gas capacity to Michigan’s Upper Peninsula to allow for growth.

2019 Planned Asset Sales and Balanced Funding Plan

Including the sale of its remaining interest of approximately 55 percent in the Northwest Hydro Facilities in British Columbia, AltaGas has successfully monetized approximately $3.8 billion of non-core assets since mid-2018, providing an efficient source of capital, reshaping its asset portfolio and prioritizing core focus areas. Additional asset sales of approximately $1.5 to $2.0 billion are planned for 2019, which are expected to further de-lever the Corporation, fund future growth, and minimize the need for any near-term common equity requirements.

GENERAL DEVELOPMENT OF ALTAGAS’ BUSINESS

Below is a summary by business segment of certain acquisitions and dispositions, key development and construction projects and other commercial arrangements not already discussed above, which have influenced the general development of the business segments of the Corporation over the last three completed financial years.

DEVELOPMENT OF THE UTILITIES BUSINESS OF ALTAGAS

In August 2017, the MPSC approved SEMCO’s application to construct, own and operate the Marquette Connector Pipeline. The Marquette Connector Pipeline is a proposed new pipeline that will connect the Great Lakes Gas Transmission pipeline to the Northern Natural Gas pipeline in Marquette, Michigan where it will provide system redundancy and increase deliverability, reliability and diversity of supply to SEMCO Gas’ approximately 35,000 customers in Michigan’s Western Upper Peninsula. The Marquette Connector Pipeline is estimated to cost between US$135 and US$140 million. Construction is expected to begin in 2019, with clearing and mobilization scheduled to begin in the first quarter of 2019 and an anticipated in-service date near the end of the fourth quarter of 2019.

On July 6, 2018, the WGL Acquisition closed and the operations of Washington Gas and Hampshire Gas were added to AltaGas’ Utilities business. For further details, see above under the heading “Recent Noteworthy Transactions”.

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With the close of the ACI IPO on October 25, 2018, the Canadian rate regulated utility assets including PNG, AUI, and Heritage Gas are no longer subsidiaries of AltaGas. AltaGas’ remaining exposure to such Canadian rate regulated utility assets is through its approximate 37 percent interest in ACI.

DEVELOPMENT OF THE MIDSTREAM BUSINESS OF ALTAGAS

In July 2016, AltaGas completed construction of the Townsend Facility, together with a 25 km gas gathering pipeline, two liquids egress pipelines totaling 30 km and a truck terminal. For further details, see below under the heading “Business of the Corporation - Midstream Business — Field Gathering and Processing and Transmission — Significant Operating Areas and Customers”.

In October 2016, AltaGas reached a positive FID for the construction, ownership and operation of the North Pine Facility and the North Pine Pipelines. Commercial operations commenced at the first 10,000 Bbls/d NGL separation train of the North Pine Facility on December 1, 2017. For further details, see below under the heading “Business of the Corporation - Midstream Business — Extraction and Fractionation — Fractionation - North Pine Facility”.

In December 2016, AltaGas received approval from the BCOGC for Townsend Phase 2 and to retrofit the existing shallow-cut Townsend Facility to a deep-cut facility at a future date if AltaGas elects to do so. Commissioning of the Townsend 2A phase of Townsend Phase 2 and the field compression equipment was completed on October 1, 2017. For further details, see below under the heading “Business of the Corporation - Midstream Business — Field Gathering and Processing and Transmission - Townsend 2A”.

In January 2017, AltaGas reached a positive FID on RIPET. RIPET is expected to be the first propane export facility off the west coast of Canada. On May 5, 2017, AltaGas LPG Limited Partnership, a wholly-owned subsidiary of AltaGas, and Vopak, formed RILE LP for the development of RIPET. AltaGas’ subsidiaries hold a 70 percent interest in RILE LP, with Vopak holding the remaining 30 percent interest. Construction of RIPET began in April 2017 and first cargo is expected early in the second quarter of 2019. RIPET is expected to ship 1.2 million tonnes of propane per annum (which is equivalent to approximately 40,000 Bbls/d of export capacity). For further details on this project see below under the heading “Business of the Corporation — Midstream Business — Energy Export”.

In March 2017, AltaGas sold the Ethylene Delivery System and the Joffre Feedstock Pipeline to Nova Chemicals for net proceeds of approximately $67 million.

In June 2017, AltaGas modified its existing take-or-pay agreement with Birchcliff Energy Ltd. to incent increased utilization of the Gordondale Facility until late 2020. The modifications made apply solely to volumes above the existing take-or-pay volume commitments.

On April 3, 2018, AltaGas entered into a long-term natural gas processing arrangement with Birchcliff Energy Ltd. at AltaGas’ deep-cut sour gas processing facility located in Gordondale, Alberta.

As a result of the closing of the WGL Acquisition on July 6, 2018, an interest in four pipelines in the United States as well as the retail gas marketing business of WGL were added to AltaGas’ Midstream Business. For further details, see above under the heading “Recent Noteworthy Transactions” and below under “Midstream Business”.

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On August 27, 2018, AltaGas entered into definitive agreements with Kelt to provide Kelt with firm processing of 75 MMcf/d of raw gas under an initial 10 year take-or-pay agreement at the Townsend Complex.

On September 10, 2018, AltaGas entered into definitive agreements for the sale of non-core midstream and power assets in Canada. The sale was completed in February 2019. For further details see “Recent Noteworthy Transactions — Sale of Non-Core Assets”.

In October 2018, AltaGas acquired 50 percent ownership in certain existing and future natural gas processing plants of Black Swan. The total capital investment by AltaGas is anticipated to be approximately $230 million. AltaGas and Black Swan also entered into long term processing, transportation and marketing agreements that include new AltaGas liquids handling infrastructure.

On October 4, 2018, the FERC issued its authorization to place Central Penn into service. The pipeline began operations on October 6, 2018.

DEVELOPMENT OF THE POWER BUSINESS OF ALTAGAS

Pursuant to the change in law provision of the Sundance B PPAs, ASTC Power Partnership, a joint venture partnership between TransCanada Energy Ltd. and AltaGas’ wholly-owned subsidiary, AltaGas Pipeline Partnership, exercised its right to terminate the Sundance B PPAs effective March 8, 2016. In December 2016, a definitive settlement agreement was reached with the Government of Alberta accepting termination of the Sundance B PPAs effective March 8, 2016. Under the settlement agreement, AltaGas agreed to contribute 391,879 self-generated carbon offsets and to make total cash payments in the aggregate amount of $6 million, payable in equal installments over three years starting in 2018 and the Government of Alberta granted AltaGas a full release from all obligations with respect to the Sundance B PPAs.

On December 31, 2016, AltaGas successfully commissioned the Pomona Energy Storage Facility. For further details see below under the heading “Business of the Corporation — Power Business”.

On June 13, 2018, AltaGas announced that it had entered into a definitive agreement to indirectly sell 35 percent of its interest in the Northwest Hydro Facilities for gross proceeds of $922 million. The transaction closed on June 22, 2018.

On July 6, 2018, as part of the WGL Acquisition, WGL Energy Systems and WGL Energy Services were added to AltaGas’ Power business. For further details, see above under the heading “Recent Noteworthy Transactions”.

On September 10, 2018, AltaGas entered into definitive agreements for the sale of non-core midstream and power assets in Canada. The sale was completed in February 2019. For further details see “Recent Noteworthy Transactions — Sale of Non-Core Assets”.

On October 19, 2018, the Bear Mountain wind facility in British Columbia was sold to ACI. In addition, a 10 percent minority interest in the Northwest Hydro Facilities was sold to ACI. See “Recent Noteworthy Transactions”.

On November 13, 2018, the Tracy, Hanford and Henrietta gas-fired facilities in California were sold to Middle River Power for a gross purchase price of US$299 million.

On December 11, 2018, the Busch Ranch wind asset in the United States was sold for a purchase price of approximately US$16 million.

On December 13, 2018, AltaGas announced that it had reached an agreement for the sale of its remaining interest of approximately 55 percent in the Northwest Hydro Facilities. The sale closed in January 2019.

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BUSINESS OF THE CORPORATION

AltaGas’ revenue for the year ended December 31, 2018 was approximately $4.3 billion compared to $2.6 billion for the year ended December 31, 2017.

Revenue by Business for 2018 (1)	Revenue by Business for 2017 (1)

Note:

(1)Excluding Corporate segment and intersegment eliminations

AltaGas operates its business through three business segments: Utilities, Midstream, and Power, each of which is more particularly described in the respective sections which follow. AltaGas’ business also includes the Corporate segment, which consists primarily of opportunistic investments, certain risk management contract results and revenues and expenses not directly identifiable with the operating businesses.

UTILITIES BUSINESS

The Utilities business contributed revenue of $1.7 billion for the year ended December 31, 2018 (2017 - $1.1 billion), representing approximately 40 percent (2017 — 41 percent) of AltaGas’ total revenue before Corporate segment and intersegment eliminations.

Investment in AltaGas Canada Inc.

In the fourth quarter of 2018, the IPO of ACI, a previously wholly owned subsidiary of AltaGas, was completed. As of December 31, 2018, AltaGas had an approximate 37 percent equity interest in ACI. Subsequent to the IPO close, AltaGas’ interest in ACI is accounted for as an equity investment.

On October 18, 2018, ACI acquired the following assets from AltaGas: (i) rate-regulated natural gas distribution utility assets in Alberta (AUI, serving approximately 80,400 customers), British Columbia (PNG, serving approximately 41,900 customers) and Nova Scotia (Heritage Gas, serving approximately 7,300 customers); (ii) minority interests in entities (Inuvik Gas Ltd. and Ikhil Joint Venture) providing natural gas to the Town of Inuvik, Northwest Territories; (iii) fully contracted 102 MW wind power assets (Bear Mountain) located near Dawson Creek, British Columbia; and (iv) an approximate 10 percent indirect equity interest in the Northwest Hydro Facilities. With the ACI IPO closed, the Utilities segment no longer controls any Canadian utilities.

U.S. Utilities Business

The Utilities segment owns utility assets that deliver natural gas to end-users in the United States. The Utilities segment in the United States is comprised of Washington Gas (in the District of Columbia, Maryland and Virginia), Hampshire Gas in West Virginia, SEMCO Gas in Michigan, ENSTAR in Alaska and a 65 percent interest in CINGSA, a regulated natural gas storage utility in Alaska.

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Regulatory Process

The Utilities business predominantly operates in regulated marketplaces where, as franchise or certificate holders, regulated utilities are allowed by the regulator to charge regulated rates that provide the utilities the opportunity to recover costs and earn a return on capital. The return on capital is to reflect a fair rate of return on approved utility investments (i.e. rate base) based on a regulatory deemed or targeted capital structure. The ability of a regulated utility to recover prudently incurred costs of providing service and earn the regulator-approved rate of return on equity depends on the utility achieving the forecasts established in the rate-setting processes.

SEMCO Gas and Washington Gas have accelerated pipe and infrastructure replacement programs in place in Michigan and the District of Columbia, Maryland and Virginia, respectively. These are long-term programs subject to both changing conditions and regulatory review and approval in five year increments. SEMCO Gas and Washington Gas are accelerating pipe and infrastructure replacement to further enhance the safety and reliability of the natural gas delivery system. SEMCO Gas and Washington Gas are allowed to begin recovering the cost, including a return, for these investments immediately through approved surcharges for each accelerated pipe or infrastructure replacement program. Once new base rates are put into effect in a given jurisdiction, expenditures previously being recovered through the surcharge will be collected through the new base rates.

The Utilities business is subject to regulation over, among other things, rates, accounting procedures and standards of service.

The MPSC has jurisdiction over the regulatory matters related, directly or indirectly, to the services that SEMCO Gas provides to its Michigan customers. The RCA has jurisdiction over the regulatory matters related, directly or indirectly, to ENSTAR’s and CINGSA’s services provided to its Alaska customers. Washington Gas is regulated by the PSC of DC, the PSC of MD and the SCC of VA, which approve its terms of service and the billing rates that it charges to its customers. In all jurisdictions, the regulators approve distribution rates based on a cost-of-service regulatory model. In Alaska, the District of Columbia, Maryland and Virginia, rates are set using the results from a historical test year plus known and measurable changes. In Michigan, rates are set using a projected test year. In all jurisdictions, the rates charged to utility customers are designed to provide the distribution utility with an opportunity to recover all prudently incurred operating, depreciation, income tax, and financing costs, and to earn a reasonable return on its investment in the net assets used in its firm gas sales and delivery service. The regulators attempt to ensure that tariffs are just and reasonable, provide incentives for investments, and are not unduly preferential, arbitrary, or unjustly discriminatory.

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Utilities Business Key Utility Metrics

The following table summarizes the average rate base for the Utilities business for the years ended December 31, 2018 and 2017:

	2018	2017
Rate base ($ millions) (1)
Utilities Canada (2)	—	833
Utilities U.S. (3) (4)	3,684	847

Notes:

(1)Rate base is indicative of the earning potential of each utility over time. Approved revenue requirement for each utility is typically based on the rate base as approved by the regulator for the respective rate application, but may differ from the rate base indicated above.

(2)The Canadian utilities were sold to ACI in 2018.

(3)In U.S. dollars.

(4)Reflects SEMCO Energy’s 65 percent interest in CINGSA.

The following table summarizes the capital expenditures for the years ended December 31, 2018 and 2017.

($ millions)	2018	2017
Utilities Canada (1)
New business	15	14
System betterment and gas supply	34	40
General plant	7	8
Total	56	62
Utilities U.S. (2)
New business	63	9
System betterment and gas supply	234	37
General plant	64	4
Total	361	50

Notes:

(1)For the period prior to the close of the ACI IPO in October 2018.

(2)In U.S. dollars.

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The following table summarizes the nature of regulation applicable to each utility:

Regulated Utility	Regulated Authority	% of AltaGas’ Consolidated Rate Base as at December 31, 2018	Allowed Common Equity (%)	Allowed ROE (%) 2017	Allowed ROE (%) 2018	Significant Features/ Material Regulatory Development
Washington Gas	PSC of MD PSC of DC SCC of VA	77	51.7 – 55.7	9.46	9.25 - 9.7	- Distribution rates approved under cost of service model.  - Rate cases filed in 2018 with the PSC of MD for increase in rates and accelerated pipeline replacement programs with decisions rendered in December 2018.  - Rate case filed in 2018 with the SCC of VA for increase in rates. Rate case hearing and decision expected in 2019.
SEMCO Gas	MPSC	13	49.04	10.35	10.35	- Distribution rates approved under cost of service model.  - Use of projected test year for rate cases with 10 month limit to issue a rate order.  - Rate rider provides recovery relating to the Main Replacement Program which allows the company to accelerate the replacement of older portions of its system.  - Last rate case settled in 2011. Next rate case expected to be filed in 2019.
ENSTAR	RCA	8	51.81	11.875	11.875	- Distribution rates approved under cost of service model using historical test year and allows for known and measurable changes.  - Rate order approving rate increase issued on September 22, 2017. Final rates effective November 1, 2017.  - Required to file another rate case no later than June 1, 2021 based upon 2020 test year.
CINGSA	RCA	2	50	12.55	11.875(1)	- Distribution rates approved under cost of service model using historical test year and allows for known and measurable changes.  - Rate case filed in 2018 based on 2017 historical test year.  - Rate case hearing scheduled for April 2019 with a decision expected in the third quarter of 2019.
Hampshire Gas	FERC	n/a	n/a	n/a	n/a	- Pass through cost of service tariff approved by FERC.

Note:

(1)CINGSA implemented interim rates reflecting an assumed ROE of 11.875% based on a rate case filed in April 2018.

WASHINGTON GAS

Washington Gas has been engaged in the natural gas distribution business since 1848, and provides regulated gas distribution services to end users in District of Columbia, Virginia, and Maryland. The utility has approximately 1.2 million customers across these three jurisdictions: District of Columbia (~165,000; 14 percent), Maryland (~489,000; 41 percent), and Virginia (~531,000; 45 percent). Washington Gas operations are such that the loss of any one customer or group of customers would not have a significant adverse effect on its business.

Operations

Washington Gas obtains natural gas supplies that originate from multiple regions throughout the U.S. As at December 31, 2018, it had service agreements with four pipeline companies that provided firm transportation and storage services, with contract expiration dates ranging from 2019 to 2044. Washington Gas has also contracted with various interstate pipeline and storage companies to add to its storage and transportation capacity starting in 2019.

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The following table sets out, by customer category, Washington Gas’ deliveries for the period since close of the WGL Acquisition to December 31, 2018:

	2018
Deliveries: (MDth)
Residential	27,567
Commercial	8,623
Transport	39,368
Total deliveries	75,558

	2018
Customers at Year End:
Residential	962,003
Commercial	47,772
Transport	175,055
Total customers	1,184,830

Seasonality

The natural gas distribution business in the District of Columbia, Virginia, and Maryland is seasonal, as the majority of natural gas demand occurs during the winter heating season that extends from November to March. Accordingly, annualized individual quarterly revenues and earnings are not indicative of annual results.

Forecasted volumes for Washington Gas are set based on the 30-year rolling average Degree Days expected for the period. In certain of Washington Gas’ jurisdictions (Virginia and Maryland) there are billing mechanisms in place which are designed to eliminate the effects of variance in customer usage caused by weather and other factors such as conservation. In the District of Columbia, there is no weather normalization billing mechanism nor does it hedge to offset the effects of weather. As a result, colder or warmer weather will result in variances to financial results.

Material Regulatory Developments and Approvals

In early 2018, Washington Gas filed applications in all three of its jurisdictions for approval of a reduction of distribution rates to reflect the impact of the TCJA. For the period from close of the WGL Acquisition to December 31, 2018, the impact of these filings and subsequent responses from the regulatory commissions was a reduction in base rates of approximately US$6 million in Maryland, US$3 million in the District of Columbia, and US$6 million in Virginia.

On May 15, 2018, Washington Gas filed an application with the PSC of MD to increase its base rates for natural gas service for approximately US$56 million including approximately US$15 million in annual surcharges currently paid by customers for system upgrades. On December 11, 2018, the PSC of MD approved Washington Gas’ US$29 million in new revenues and increased the return on equity to 9.7 percent. On January 10, 2019, Washington Gas requested rehearing, alleging two errors in the agency’s final order. A PSC of MD decision on the application for rehearing is expected late in the first or second quarter of 2019.

On June 15, 2018, Washington Gas filed an application with the PSC of MD for approval of the second phase of its accelerated natural gas pipeline initiative in Maryland, known as the STRIDE Plan (Strategic Infrastructure Development and Enhancement Plan). The application requested approval of approximately US$394 million in accelerated infrastructure replacements for the 2019 to 2023 period. On December 11, 2018, the PSC of MD approved a US$350 million five-year program. On January 9, 2019, Washington Gas applied to supplement its 2019 project list with an additional annual spend of approximately US$65 million. On January 25, 2019, the PSC of MD approved the 2019 revised project list and affirmed the annual spend of approximately US$65 million.

On July 31, 2018, Washington Gas filed an application with the SCC of VA to increase its base rates for natural gas service. This base rate increase, if granted, would be approximately US$38 million, of which approximately US$15 million

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relates to costs being collected through the monthly SAVE (Steps to Advance Virginia’s Energy Plan) surcharges for accelerated pipeline replacement. The new interim rates are effective, subject to refund, in January 2019. Hearings are scheduled for April 2019 with a decision expected in the second half of 2019.

On August 31, 2018, Washington Gas filed the 2019 SAVE capital expenditure application with the SCC of VA seeking approval for approximately US$70 million of SAVE capital expenditures in 2019. The SAVE application for 2019 was approved and implemented beginning January 2019.

On December 7, 2018, Washington Gas filed an application with the PSC of DC for the phase 2 Projectpipes program requesting approval of approximately US$305 million in accelerated infrastructure replacement in the District of Columbia during the 2019 to 2024 period.

In connection with the WGL Acquisition, AltaGas and WGL have made commitments related to the terms of the PSC of DC settlement agreement and the conditions of approval from the PSC of MD and the SCC of VA. Among other things, these commitments include rate credits distributable to both residential and non-residential customers, gas expansion and other programs, various public interest commitments, and safety programs. The total amount expensed in 2018 was approximately US$140 million, of which US$111 million has been paid as of December 31, 2018. In addition, there are certain additional regulatory commitments which will be expensed when the costs are incurred in the future, including the hiring of damage prevention trainers, the investment of US$70 million over a 10 year period to further extend natural gas service, and the investment of US$8 million for leak mitigation.

HAMPSHIRE GAS

Hampshire Gas owns underground natural gas storage facilities, including pipeline delivery facilities located in and around Hampshire County, West Virginia, and operates these facilities to serve Washington Gas. Hampshire Gas is regulated by FERC. Washington Gas purchases all of the storage services of Hampshire Gas, and includes the cost of the services in its regulated energy bills to customers. Hampshire Gas operates under a “pass-through” cost of service based tariff approved by FERC.

SEMCO ENERGY

SEMCO Energy’s head office is located in Port Huron, Michigan. SEMCO Energy’s primary business is a gas utility business. It operates regulated natural gas transmission and distribution divisions in Michigan, doing business as SEMCO Gas, and in Alaska, doing business as ENSTAR. SEMCO Energy’s gas utility business also includes a 65 percent ownership interest in CINGSA, a regulated natural gas storage utility in Alaska. The gas utility business accounts for approximately 99 percent of SEMCO Energy’s 2018 consolidated revenues. The gas utility business purchases, transports, distributes and sells natural gas and related gas distribution services to residential and C&I customers and is SEMCO Energy’s largest business segment.

SEMCO GAS

In Michigan, SEMCO Gas distributes natural gas to approximately 303,000 regulated customers located in both southern Michigan and Michigan’s Upper Peninsula, approximately 84 percent of which are residential. The remaining customers include power plants, food production facilities, furniture manufacturers and other industrial customers.

The average number of customers at SEMCO Gas has increased by an average of approximately 1.0 percent annually during the past three years (with an increase of 1.1 percent in 2018). While there may occasionally be variations in this pattern, average per customer annual gas consumption in Michigan over the longer-term has been decreasing because of, among other things, the availability of and incentive to invest in more energy efficient homes and appliances.

SEMCO Gas pursues opportunities to develop service areas that are not currently served with natural gas. Expansion opportunities that currently exist represent relatively minor asset growth, but SEMCO Gas remains committed to its strategy of pursuing expansion projects that meet management’s target return on investment.

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Operations

The SEMCO Gas natural gas transmission and delivery system in Michigan includes approximately 151 miles of gas transmission pipelines and 6,175 miles of gas distribution mains. The pipelines and mains are located throughout the southern half of Michigan’s Lower Peninsula (including in and around the cities of Albion, Battle Creek, Holland, Niles, Port Huron and Three Rivers) and also in the central, eastern and western areas of Michigan’s Upper Peninsula.

SEMCO Gas has access to natural gas supplies throughout the United States and Canada via interstate and intrastate pipelines in and near Michigan. To provide gas to SEMCO Gas sales customers, SEMCO Gas has negotiated standard terms and conditions for the purchase of natural gas under the North American Energy Standards Board (NAESB) form of agreement with a variety of suppliers.

The following table sets out, by customer category, SEMCO Gas’ deliveries:

	2018	2017
Deliveries: (MDth)
Residential	27,278	23,713
Commercial	13,595	13,595
Transport	22,248	21,225
Gas Customer Choice(1)	3,394	3,394
Total deliveries	66,515	61,927

	2018	2017
Customers at Year End (2):
Residential	258,300	256,670
Commercial	23,523	23,487
Transport	253	252
Gas Customer Choice(1)	21,102	23,171
Total customers	303,178	303,580

Notes:

(1)In Michigan, the MPSC has a program known as the Gas Customer Choice Program, under which gas sales customers may choose to purchase natural gas from third-party suppliers, while SEMCO Gas continues to charge these customers applicable distribution charges and customer fees, plus a balancing fee.

(2)Excludes customers from SEMCO Gas’ non-regulated business.

Seasonality

The natural gas distribution business in Michigan is seasonal, as the majority of natural gas demand occurs during the winter heating season that extends from November to March. Accordingly, annualized individual quarterly revenues and earnings are not indicative of annual results.

Forecasted volumes for SEMCO Gas are set based on the 15-year rolling average Degree Days expected for the period. Temperature fluctuations impact the operating results of SEMCO Gas.

Material Regulatory Developments and Approvals

As required by an order issued by the MPSC in September 2012, SEMCO Gas filed a depreciation study with the MPSC in September 2017, using 2016 data. On April 9, 2018, the MPSC issued an order approving the settlement agreement and new depreciation rates. The new rates reflect a US$1.9 million upward adjustment to depreciation expense when compared to the current rates and are effective on January 1, 2019. SEMCO Gas is required to file a new depreciation case and updated depreciation study with the MPSC no later than September 30, 2022, using 2021 data.

On December 27, 2017, the MPSC issued an order instructing all regulated utilities in Michigan to track the impact of the TCJA effective January 1, 2018. On February 22, 2018, the MPSC issued an order requiring utilities in Michigan to follow a 3-step approach for computing and implementing bill credits to reflect the reduction in revenue requirements as a result of the TCJA. The first step was to establish a credit (Credit A) through a contested case. Credit A is a forward-looking tax

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credit that will refund the annual tax savings relating to the reduction of the corporate tax rate from 35 percent to 21 percent on a prospective basis. SEMCO Gas submitted its Credit A filing on March 29, 2018, reflecting a revenue reduction of approximately US$5.9 million on an annual basis. On April 20, 2018, SEMCO Gas supplemented its Credit A filing with a proposal to reduce its Main Replacement Program (MRP) surcharges to reflect the impact of the TCJA on its MRP annual revenue requirement. On May 30, 2018, the MPSC issued an order approving a settlement in SEMCO Gas’ Credit A filing reflecting a reduction in revenues of approximately US$5.9 million and a reduction to the annual MRP revenue requirement of approximately US$0.6 million, effective July 1, 2018. Credit A will remain in place until new rates are set in the next general rate case. The second step was to establish another credit (Credit B) through a contested case. Credit B is a backward-looking tax credit to reflect the reduction of the corporate tax rate of 35 percent to 21 percent, for the period January 1, 2018 through the date Credit A is established. On July 27, 2018, SEMCO Gas filed its proposal for Credit B to address the impacts of federal corporate tax reduction arising from the TCJA on its natural gas rates from January 1, 2018 until June 30, 2018. On September 28, 2018, the MPSC issued an order approving the settlement in SEMCO Gas’ Credit B filing. SEMCO Gas will refund approximately US$4.7 million to customers volumetrically via bill credits for three months beginning with the first billing cycle in October 2018. The third and final step was to file an application to establish the calculation for all of the remaining impacts of the TCJA (Calculation C), which is primarily the remeasurement of deferred taxes and how the amounts deferred as regulatory liabilities will flow back to ratepayers. On October 1, 2018, SEMCO Gas filed its application to address the Calculation C effects of the TCJA, which is currently ongoing.

ENSTAR

In Alaska, ENSTAR distributes natural gas to approximately 145,000 customers in the metropolitan Anchorage area and surrounding Cook Inlet area, approximately 91 percent of which are residential. The remaining gas sales customers include hospitals, universities and government buildings. ENSTAR also provides gas transportation service to power plants and a LNG plant. ENSTAR’s service area encompasses over 58 percent of the population of Alaska.

The average number of customers at ENSTAR has increased by an average of approximately 1.3 percent annually during the past three years (with an increase of 1.2 percent in 2018). While there may occasionally be variations in this pattern, average per customer annual gas consumption in Alaska over the longer term has been decreasing due to the availability of and incentive to invest in more energy efficient homes and appliances.

Operations

ENSTAR’s natural gas delivery system (including SEMCO Energy’s Alaska Pipeline Company) includes approximately 446 miles of gas transmission pipelines and 3,125 miles of gas distribution mains. ENSTAR’s pipelines and mains are located in Anchorage and the Cook Inlet area of Alaska.

Historically, ENSTAR has had access to significant natural gas supplies in Cook Inlet, which are within or adjacent to its service territory. ENSTAR’s distribution system, including the Alaska Pipeline Company transmission-level pipeline system, is not linked to major interstate and intrastate pipelines and thus does not have access to natural gas supplies elsewhere in Alaska, Canada, or the lower 48 states. As a result, ENSTAR must procure its natural gas supplies under gas supply agreements from producers in and near the Cook Inlet area. Natural gas production in Cook Inlet has decreased significantly in recent years as has the amount of deliverability available from Cook Inlet producers. The majority of ENSTAR’s gas supply and deliverability needs are provided by long term contracts with Cook Inlet producers into 2023.

In order to better address the seasonal deliverability demands of ENSTAR’s customers, SEMCO Energy developed the CINGSA Storage Facility.

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The following table sets out, by customer category, ENSTAR’s deliveries:

	2018	2017
Deliveries: (Mmcf)
Residential	18,322	19,984
Commercial	12,415	13,464
Transport	25,041	27,344
Total deliveries	55,778	60,792

	2018	2017
Customers at Year End:
Residential	132,270	131,615
Commercial	12,829	12,765
Transport	22	22
Total customers	145,121	144,402

Seasonality

The natural gas distribution business in Alaska is seasonal, as the majority of natural gas demand occurs during the winter heating season that extends from November to March. Accordingly, annualized individual quarterly revenues and earnings are not indicative of annual results.

Forecasted volumes for ENSTAR are set based on the 10-year rolling average Degree Days expected for the period. Temperature fluctuations impact the operating results of ENSTAR.

Material Regulatory Developments and Approvals

On March 23, 2018, the RCA sent a letter to several investor-owned utilities in Alaska, asking for the utilities’ proposed response to the TCJA. On April 26, 2018, ENSTAR filed its proposed reduction in rates with the RCA, reflecting a US$5.1 million decrease from the annual revenue requirement that was determined in October 2017. On May 29, 2018, the RCA approved ENSTAR’s proposed rate decrease and the reduced rates went into effect on June 1, 2018. ENSTAR anticipates addressing excess deferred income taxes in its next rate case, which is required to be filed no later than June 1, 2021, with a test year of 2020.

CINGSA

SEMCO Energy, through a subsidiary, holds a 65 percent interest in CINGSA. CINGSA was formed to construct, own and operate the CINGSA Storage Facility. Natural gas is injected into the CINGSA Storage Facility during each summer and withdrawn as needed for use each winter.

CINGSA provides firm gas storage service to ENSTAR and to three Cook Inlet area electric utilities and provides interruptible gas storage service to ENSTAR and five other customers. ENSTAR has subscribed for approximately 78 percent of CINGSA’s initial capacity and approximately 66 percent of the associated initial gas injection and withdrawal capability, with the remainder of the capacity and injection and withdrawal capability split among the other customers.

Material Regulatory Developments and Approvals

In 2013, CINGSA detected higher than expected pressure during its biannual shut-in. CINGSA determined that it had encountered a pocket of gas that was at or near the initial reservoir pressure. Following extensive analysis, CINGSA determined that the pocket of found gas it discovered totalled approximately 14.5 Bcf. In August 2015, CINGSA entered into a stipulation with most of its customers regarding the disposition of the found gas. Hearings before the RCA were held in September 2015. On December 4, 2015, the RCA issued an order that denied the stipulation, allowed CINGSA to sell up to 2 Bcf of the gas and required that approximately 87 percent of the net proceeds of any such sale be allocated to CINGSA’s firm customers. On January 4, 2016, CINGSA appealed the RCA decision to the Superior Court of Alaska. On

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August 17, 2017, the superior court issued a decision upholding each facet of the RCA’s decision. CINGSA did not exercise its right to appeal the superior court’s decision to the Alaska Supreme Court; the RCA’s decision and allocation of proceeds stands.

In April 2018, CINGSA filed a request for an advanced ruling on a redundancy project for approximately US$41 million of capital expenditures and an annual revenue requirement of approximately US$6 million. Reply testimony was filed in September 2018 and a hearing occurred in October 2018, with a decision expected in the second quarter of 2019.

As provided in the certificate of public convenience and necessity stipulations accepted by the RCA for the CINGSA Storage Facility, the RCA ordered CINGSA to file a revenue requirement study. The rate case was filed in April 2018, with a hearing scheduled for April 2019. A decision is expected in the third quarter of 2019.

Environmental Considerations Impacting the Utilities Business

SEMCO Gas

As of December 31, 2018, SEMCO Gas has completed the investigation and remediation at the two MGP sites it was responsible for and has received NFA letters from the Michigan Department of Environmental Quality for both sites. SEMCO Gas will continue to monitor these sites in the future as required by the NFA letters.

Given the nature of the past operations conducted by SEMCO Gas and others at SEMCO Gas’ properties, particularly those involving former MGP sites, there can be no assurance that all potential instances of soil or groundwater contamination have been identified, even for those properties where environmental site assessments or other investigations have been conducted. Changes in existing laws or policies or their enforcement, future spills or accidents or the discovery of currently unknown contamination also may give rise to environmental liabilities which may be material.

In accordance with an MPSC accounting order, SEMCO Gas’ environmental investigation and remediation costs associated with these MGP sites are deferred and amortized over ten years. Rate recognition of the related amortization expense does not begin until the costs are subject to review by the MPSC in a base rate case. To the extent that any costs are not fully recoverable from customers through regulatory proceedings or from insurance or other potentially responsible persons, these costs would reduce SEMCO Gas’ earnings and results of operations.

As a result of the NFA letters received to date, SEMCO Gas believes that the likelihood of any further liability at either of these sites is remote. However, if applicable environmental laws change that require further investigation and remediation to be performed at the sites in the future, SEMCO Gas could incur a material liability. This liability would be offset by a corresponding regulatory asset.

Environmental, health and safety regulations may also require SEMCO Gas to install pollution control equipment, modify its operations or perform other corrective actions at its facilities.

Washington Gas

Washington Gas is subject to federal, state and local laws and regulations related to environmental matters. These laws and regulations may require expenditures over a long time frame to control environmental effects. Almost all of the environmental liabilities associated with Washington Gas operations are costs expected to be incurred to remediate sites where Washington Gas or a predecessor affiliate operated MGPs. Estimates of liabilities for environmental response costs are difficult to determine with precision because of the various factors that can affect their ultimate level. These factors include, but are not limited to, the following:

·the complexity of the site;

·changes in environmental laws and regulations at the federal, state and local levels;

·the number of regulatory agencies or other parties involved;

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·new technology that renders previous technology obsolete or experience with existing technology that proves ineffective;

·the level of remediation required; and

·variations between the estimated and actual period of time that must be dedicated to respond to an environmentally-contaminated site.

Washington Gas has identified up to ten sites where it or its predecessors may have operated MGPs. Washington Gas last used any such plant in 1984. In connection with these operations, Washington Gas is aware that coal tar and certain other by-products of the gas manufacturing process are present at or near some former sites and may be present at others.

Washington Gas is currently remediating its East Station property, which is adjacent to the Anacostia River, including ground water pump and treat, tar recovery, soil encapsulation and other treatment. Washington Gas is conducting a remedial investigation and feasibility study under a 2012 consent decree with the District of Columbia and the federal government and additional remediation may be required. In addition, manufactured gas waste was discovered at an adjoining property, a parcel of land adjacent to East Station. Washington Gas has agreed to work with the owners of the adjoining property to perform a site investigation, ground water sampling, and report on the contamination at the site pursuant to oversight by Department of Energy and Environment (DOEE).

Washington Gas received a letter in February 2016 from the District of Columbia and National Park Service regarding the Anacostia River Sediment Project, indicating that the District of Columbia is conducting a separate remedial investigation and feasibility study of the river to determine if and what cleanup measures may be required and to prepare a natural resource damage assessment. The sediment project draft remedial investigation report issued on March 30, 2018, identified East Station as one of seventeen potential environmental cleanup sites. During its fiscal year ended September 30, 2017, Washington Gas received a request for information related to three Washington Gas properties. Washington Gas is not able to estimate the total amount of potential damages or timing associated with the District of Columbia’s environmental investigation on the Anacostia River at this time. While an allocation method has not been established, Washington Gas has accrued an amount based on a potential range of estimates.

Regulatory orders issued by the PSC of MD allow Washington Gas to recover the costs associated with the sites applicable to Maryland over the period ending in 2025. Rate orders issued by the PSC of DC allow Washington Gas a three-year recovery of prudently incurred environmental response costs and allow Washington Gas to defer additional costs incurred between rate cases. Regulatory orders from the SCC of VA have generally allowed the recovery of prudent environmental remediation costs to the extent they were included in the underlying financial data supporting an application for rate change.

MIDSTREAM BUSINESS

AltaGas’ Midstream business contributed revenue of $1.4 billion for the year ended December 31, 2018 (2017 - $1.0 billion), representing approximately 33 percent (2017 — 36 percent) of AltaGas’ total revenue before Corporate segment and intersegment eliminations. The Midstream business is primarily comprised of AltaGas’ extraction and fractionation, field gathering and processing business, distribution of natural gas to retail customers, contracted underground natural gas storage facilities and pipeline investments as described below. AltaGas also owns certain non-material transmission assets and transmission pipelines. To support its Midstream business, AltaGas conducts an energy service business mainly focused on natural gas and NGL marketing initiatives. AltaGas is also pursuing energy export initiatives via RIPET and constructing the Alton Natural Gas Storage Project.

Midstream Business — Extraction and Fractionation

Extraction and Fractionation — Plants

Extraction production is a function of natural gas volume processed, natural gas composition, recovery efficiency of the extraction plant and plant on-line time. The following tables are a summary as at December 31, 2018 of AltaGas’ operatorship, capacity and total production associated with extraction and fractionation plants in which AltaGas holds an interest:

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Extraction or Fractionation Plant	Location	Interest (%)	AltaGas’ Inlet Processing Capacity (Mmcf/d)	AltaGas’ Inlet Fractionation Capacity (Bbls/d)	Operated or Non- Operated
Harmattan	Central Alberta	100	490	35,000	Operated
Younger(1)	Taylor, British Columbia	28.33	213	9,750	Non-Operated
JEEP	Joffre, Alberta	100	250	N/A	Operated
EEEP	Edmonton, Alberta	100	390	N/A	Operated
Empress Pembina	Empress, Alberta	11.25	135	N/A	Non-Operated
North Pine	Fort St. John, British Columbia	100	N/A	10,000	Operated
Total			1,478	54,750

Note:

(1)Pembina assumed operatorship of Younger effective April 1, 2018. At that time, AltaGas’ ownership interest was reduced to 28.33 percent of the extraction assets and 50 percent of the fractionation assets, resulting in AltaGas’ inlet processing capacity being reduced to 213 Mmcf/d.

Total Liquids Production (Bbls/d)(1)

	2018	2017
NGLs (2)	25,737	28,316
Ethane	25,448	26,125

Notes:

(1)Average volumes for the fourth quarter.

(2)Excludes field NGLs.

Natural gas supply to Younger is dependent on the amount of raw natural gas processed at the McMahon gas plant, which is based on the robust natural gas producing region of northeastern British Columbia. Harmattan’s raw natural gas supply is based on producer activity in the west-central region of Alberta. Harmattan is the only deep-cut and full fractionation plant in the area.

Extraction and Fractionation — Contractual Arrangements

Extraction facility owners have the right to extract liquids from the natural gas stream, either directly as the owner of the natural gas, or through NGL extraction agreements. The typical commercial arrangement involves the ethane and NGL extraction plant owner contracting with the gas shipper on a natural gas transmission system for the right to extract NGLs from the transporter’s natural gas. Ethane and NGLs are extracted from the energy content of the shipper’s natural gas. Fractionation facilities charge a fee to separate NGL mix into specification propane, butane and condensate.

The value of ethane and NGL extraction is a function of the difference between the value of the ethane, propane, butane and condensate as separate marketable commodities and their heating value as constituents of the natural gas stream. If the components are not extracted and sold at prices that reflect the value for each of the individual commodities, they are sold as part of natural gas and generate revenue for their heating value at the prevailing natural gas price.

Harmattan

AltaGas owns a 100 percent interest in Harmattan located 100 km north of Calgary, Alberta. Harmattan has natural gas processing capacity of 490 Mmcf/d consisting of sour gas treating, co-stream processing, NGL extraction, and 35,000 Bbls/d of NGL fractionation and terminalling. Harmattan also has a 450 Bbls/d capacity frac oil processing facility, a 200 tonnes/d capacity industrial grade carbon dioxide (CO2) facility and a 10,000 Bbls/d capacity NGL truck offload facility. In addition to extraction and fractionation, Harmattan also provides storage and terminalling services.

At Harmattan, natural gas processing services are provided to approximately 70 producers under contracts with a variety of commercial arrangements and terms. Fee-for-service revenues are generated from the raw natural gas processing, NGL extraction, fractionation and terminalling, and custom NGL processing.

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Approximately 30 percent of the natural gas volume processed at Harmattan is done under the terms of the Rep Agreements which have life-of-reserves dedications. The balance of the raw natural gas processed at Harmattan is processed under contracts with terms varying from one month to life-of-reserves. The majority of the contracts provide for fee escalation based on CPI.

The Co-stream Facility allows the extraction of NGLs from gas in the west leg of the NGTL system using unused capacity in the NGL recovery units at Harmattan. AltaGas entered into a 250 Mmcf/d cost of service co-stream processing agreement with Nova Chemicals related to ethane and NGL extraction at Harmattan in 2012 for an initial term of 20 years. AltaGas will deliver all NGLs or co-stream gas products on a full cost-of-service basis to Nova Chemicals.

Management has identified environmental issues associated with the prior activities of Harmattan. An environmental allocation agreement is in place with the former operator which allocates the liability. This agreement significantly reduces soil and groundwater contamination liability to AltaGas. See “Risk Factors - Decommissioning, Abandonment and Reclamation Costs” in this AIF.

Younger

Effective April 1, 2018, AltaGas’ ownership was reduced to a 28.33 percent interest in Younger extraction assets and 50 percent related to the fractionation, storage, loading, treating and terminalling of NGL’s. Younger has a licence capacity to process up to 750 Mmcf/d of natural gas and AltaGas’ share of such capacity is 213 Mmcf/d. The remaining interest is held by Pembina and Pembina has assumed operatorship. Younger processes natural gas transported on the Spectra Energy transmission system and Canadian Natural Resources Limited’s Stoddart transmission system to recover NGLs.

Pembina is responsible for sourcing AltaGas’ gas supply and AltaGas markets its share of NGLs produced.

JEEP

AltaGas owns 100 percent of JEEP which has processing capacity of 250 Mmcf/d of natural gas and is capable of producing up to 10,400 Bbls/d of ethane and NGLs.

The plant is adjacent to Nova Chemicals’ Joffre petrochemical complex and recovers ethane and NGLs from the fuel gas used at the complex. All ethane production from JEEP is sold under a long-term, cost-of-service type contract with Nova Chemicals. AltaGas delivers its NGL production to area fractionators under short to medium term fractionation agreements. AltaGas takes the resulting spec products in kind and sells into markets throughout North America to maximize plant gate netbacks.

EEEP

AltaGas owns 100 percent of EEEP. EEEP is directly connected to the Alberta Ethane Gathering System and to Plains Midstream Canada’s Co-Ed NGL pipeline.

The plant has a licenced gross inlet capacity of 390 Mmcf/d of natural gas and gross production capacity of specification ethane of 23,000 Bbls/d and NGLs of 7,500 Bbls/d.

The processed gas from the facility supplies end-use markets in the city of Edmonton, Alberta. Approximately half of EEEP ethane production capacity is sold to Nova Chemicals under a long-term fee-for-service contract. The remainder is currently used for spot sales. AltaGas delivers its NGL production to area fractionators under medium to long-term fractionation agreements. AltaGas takes the resulting spec products in kind and sells into markets throughout North America to maximize plant gate netbacks.

Gas is supplied to EEEP under a gas supply agreement with NGTL which includes the right for AltaGas to extract liquids from all gas processed at EEEP.

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North Pine Facility

Commissioning of the first train of the North Pine Facility was completed on December 1, 2017. The first train of the North Pine Facility is capable of processing up to 10,000 Bbls/d of propane plus NGL mix and has 6,000 Bbls/d of condensate terminalling capacity. Permitting is in place for the second NGL separation train capable of processing up to an additional 10,000 Bbls/d of propane plus NGL mix following execution of agreements with Black Swan and Kelt in the second half of 2018. The additional North Pine capacity is expected to be on-stream in the fourth quarter of 2019.

The North Pine Facility is connected via the North Pine Pipelines to the truck terminal for the Townsend Facility and is contracted through long-term supply agreements with Black Swan, Kelt and Painted Pony. The North Pine Facility also has access to the CN rail network, allowing for the transportation of propane, butane and condensate to North American markets and propane to RIPET.

Competition

AltaGas’ extraction and fractionation assets are well positioned to operate in a competitive environment and take advantage of their strategic locations and contract terms in order to compete in the NGL industry.

AltaGas’ JEEP and EEEP facilities are strategically located and take advantage of the gas consumption by the petrochemical industry and the City of Edmonton, respectively.

Younger processes natural gas produced in the Montney shale gas formation in British Columbia. This facility is strategically located as the only straddle plant in this area of British Columbia. While Younger is the only straddle plant in the area, the Alliance pipeline competes for local natural gas supply.

Harmattan is well-positioned as the high-volume, low-cost processing facility in its service area. Harmattan is a significant service provider with a large capture area in west central Alberta. Many other facilities in the Harmattan area are currently underutilized, providing AltaGas with opportunities to consolidate and increase asset utilization and profitability. The Co-stream Facility has resulted in increased utilization at the plant, with the added benefit that the equipment installed for the Co-stream Facility increases reliability and efficiency for both gas processing and Co-stream Facility customers.

The North Pine Facility is the only custom fractionation plant in British Columbia, providing area producers with a lower cost, higher netback alternative for their NGLs than fractionating in Edmonton.

Midstream Business — Field Gathering and Processing and Transmission

Subsequent to the closing of the previously discussed non-core midstream asset sales in February 2019 (See “Recent Noteworthy Transactions — Sale of Non-Core Assets”), AltaGas’ Field Gathering and Processing business consists of gathering and processing facilities, all located in the Montney area in Western Canada, and gathering and sales lines upstream of processing facilities that deliver natural gas into downstream pipeline systems that feed North American natural gas markets. AltaGas has a total gross licenced processing capacity of approximately 0.7 Bcf/d, of which 23 percent was capable of processing sour gas. AltaGas operates all but one of its facilities.

The gathering systems move natural gas on behalf of producers from the wellhead to AltaGas processing facilities where impurities and certain hydrocarbon components are removed and the gas is compressed to meet the operating specifications of downstream pipeline systems that deliver gas to domestic and export energy markets.

The main drivers of the field gathering and processing business are throughput, gathering and processing fees and operating costs, with several facilities having the benefit of take-or-pay contracts. Throughput is impacted by new well tie-ins, reactivations, recompletions, well optimizations performed by producers and natural production declines in areas served by AltaGas’ processing facilities.

AltaGas has NGL extraction capability at 5 of its natural gas field processing facilities. See above under the heading “Midstream Business — Extraction and Fractionation”.

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Field Gathering and Processing - Utilization

AltaGas strives for continued improvement, operational excellence, and maximum utilization of all facilities over which it has operational control and to consistently exceed WCSB average utilization rates. Volume additions at facilities, which come from new well tie-ins and from reactivations, re-completions and well optimizations performed by producers, are offset by natural production declines.

Field Gathering and Processing Facility Capacity and Throughput

	2018	2017
Facility
Townsend	396	297
Gordondale	150	150
Blair Creek	120	120
Aitken Creek North	55	—
Other	489	554
Total Licensed capacity (gross Mmcf/d)(1)(2)	1,209	1,121
Throughput (gross fourth quarter Mmcf/d)(2)	466	441
Capacity utilization (%)	41	39
Capacity utilization for core assets (%)	64	46

Notes:

(1)As at December 31, 2018 and 2017.

(2)Gross numbers are not adjusted to reflect AltaGas’ working interest for the operated facilities. Non-operated facilities such as Aitken Creek are reported on a net basis.

Average facility utilization increased to 41 percent in 2018 from 39 percent in 2017 primarily due to the acquisition of the Aitken Creek North (Plant 1) facility in October 2018, partially offset by the disposition of certain non-core assets in the first quarter of 2018. Capacity utilization for core assets increased from 46 percent in 2017 to 64 percent in 2018 mainly due to higher throughput at Townsend.

Field Gathering and Processing - Significant Operating Areas and Customers

Approximately 90 percent of AltaGas’ field gathering and processing volumes are processed through the Townsend Facilities, Blair Creek Facility, Gordondale Facility, and Aitken Creek North Facility located in the liquids rich Montney resource play.

Townsend Complex

Townsend Facility

The Townsend Facility, which is wholly owned by AltaGas, is a 198 Mmcf/d shallow cut gas processing facility located approximately 100 km north of Fort St. John and 20 km southeast of AltaGas’ Blair Creek Facility. Painted Pony has reserved all of the firm capacity at the Townsend Facility under a 20-year take-or-pay agreement which expires in 2036.

A 25 km gas gathering line connects the Blair Creek field gathering area to the Townsend Facility and Painted Pony has reserved all of the firm service on that line under a 20-year take-or-pay agreement. In addition, two liquids egress lines totaling approximately 30 km connect the Townsend Facility to a truck terminal on the Alaska Highway. Painted Pony has reserved all firm liquids capacity on these egress lines under a 20-year take-or-pay agreement which expires in 2036.

Townsend 2A

Townsend 2A, a 99 Mmcf/d shallow cut processing facility, entered service on October 1, 2017 and is wholly owned by AltaGas. Townsend 2A and the field compression equipment are fully contracted with Painted Pony under a 20-year take-or-pay agreement. NGL produced will be transported approximately 70 km to AltaGas’ North Pine Facility via existing NGL pipelines owned by AltaGas.

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Townsend 2B

In August 2018, AltaGas entered into definitive agreements with Kelt to provide an energy infrastructure solution for the liquids-rich Inga Montney development located in British Columbia. Townsend 2B will be a 198 Mmcf/d C3+ deep cut gas processing facility consisting of 99 Mmcf/d of new deep cut gas processing capacity and repurposing 99 Mmcf/d of  the Townsend Facility’s existing shallow cut capacity with deep cut gas processing capabilities. The facility will provide Kelt with firm processing of 75 MMcf per day of raw gas under an initial 10 year take-or-pay agreement. The estimated project cost is approximately $180 million. Long lead equipment has been ordered and the project is on track to be on-stream in the fourth quarter of 2019.

Blair Creek

AltaGas owns 100 percent of the Blair Creek Facility which has licensed capacity of 120 Mmcf/d of natural gas. AltaGas operates the facility which is located approximately 140 km northwest of Fort St. John, British Columbia. The facility processes gas gathered from Painted Pony and Tourmaline Oil Corp. The plant is equipped with liquids extraction facilities to capture the NGLs value for the producer.

Gordondale

AltaGas owns 100 percent of the Gordondale Facility which has licensed capacity of 150 Mmcf/d of natural gas. AltaGas operates the facility which is located in the Gordondale area of the Montney reserve area approximately 100 km northwest of Grande Prairie, Alberta. The Gordondale Facility processes gas gathered from Birchcliff Energy Ltd.’s Gordondale Montney development under a long-term take-or-pay contract. The plant is equipped with liquids extraction facilities to capture the NGLs value for the producer.

Aitken Creek

In October 2018, AltaGas acquired a 50 percent ownership in Black Swan’s Aitken Creek Processing Facilities, including Aitken Creek North (Plant 1) and Nig Creek (Plant 2). Plant 1 is an operating shallow gas plant with current capacity of 110 Mmcf/d (55 Mmcf/d net). Plant 2 is a shallow gas plant with a planned operational capacity of 100Mmcf/d (50Mmcf/d net), and is currently under construction and expected to be on-stream in the fourth quarter of 2019. AltaGas and Black Swan have also entered into long term processing, transportation and marketing agreements that will include new AltaGas liquids handling infrastructure. The Aitken Creek Processing Facilities are located in the liquids rich Montney resource play in northeast British Columbia and are operated by Black Swan.

Field Gathering and Processing - Contracts

AltaGas gathers and processes natural gas under contracts with natural gas producers. Subsequent to the sale of certain non-core midstream assets in February 2019 (See “Recent Noteworthy Transactions — Sale of Non-Core Assets”), there are approximately 90 active gathering and processing contracts. These contracts, in general:

·Establish fees for the gathering and processing services offered by AltaGas;

·Define the producers’ access rights to gathering and processing services;

·Establish minimum throughput commitments with producers and use appropriate fee structures to recover invested capital early in the life of the contract where capital investment is required by AltaGas;

·Define the terms and conditions under which future production is processed at an AltaGas facility; and

·Seek to recover operating costs to mitigate the impact of volume declines.

AltaGas’ Field Gathering and Processing business generates revenue from fees for volumes of natural gas processed at a processing facility or gathered through a gathering system and, at several facilities, such fees are on a take-or-pay basis. The majority of contracts in place at December 31, 2018 were subject to annual price escalation related to changes in CPI.

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Where natural gas reserves have been dedicated under contract, the contract normally extends beyond one year and up to the life of the reserves, depending on the amount of capital AltaGas has invested in the facility. Where reserves have not been dedicated under contract or AltaGas has not made a significant capital investment, the contracts are normally subject to termination by either party upon one to three months’ notice. Producing wells typically remain connected to a gathering and processing system for their entire productive lives.

Field Gathering and Processing - Competition

AltaGas competes with other midstream entities operating in the WCSB. In 2018, AltaGas processed an average of 466 Mmcf/d, which was approximately 3 percent of volumes produced in the WCSB. The majority of processing capacity generally continues to be provided by the upstream natural gas exploration and production companies.

Midstream Business - WGL Midstream

WGL Midstream specializes in the investment, management, development and optimization of natural gas storage and transportation assets. WGL Midstream provides natural gas related solutions to its customers and counterparties, including producers, utilities, local distribution companies, power generators, wholesale energy suppliers, LNG exporters, pipelines and storage facilities. Moreover, WGL Midstream contracts for storage and pipeline capacity in its asset optimization activities through both long term contracts and short term transportation releases. WGL Midstream also contracts for physical natural gas sales and purchases on both a long term and short term basis and has ownership interests in four pipelines.

Stonewall System

WGL Midstream has a 30 percent equity interest in an entity that owns and operates the Stonewall System. The Stonewall System has the capacity to gather up to 1.4 Bcf/d of natural gas from the Marcellus production region in West Virginia, and connects with an interstate pipeline system that serves markets in the mid-Atlantic region.

Central Penn

Central Penn is a new 185 mile pipeline originating in Susquehanna County, Pennsylvania and extending to Lancaster County, Pennsylvania, and is an integral part of the larger Atlantic Sunrise project operated by The Williams Companies through Transco. Central Penn was placed into service early in October 2018 and is regulated by the FERC. The Atlantic Sunrise project is designed to supply enough natural gas to meet the daily needs of more than 7 million American homes in the region. WGL Midstream owns an indirect 21 percent interest in Central Penn, which has the capacity to transport and deliver up to approximately 1.7 Bcf/d of natural gas from the northeastern Marcellus producing area to markets in the mid-Atlantic and Southeastern regions of the United States.

In February 2014, WGL Midstream and certain partners formed Meade. Meade (39 percent) and Transco (61 percent) have joint ownership of Central Penn. WGL Midstream owns a 55 percent interest in Meade (21 percent indirect interest in Central Penn) and on a cash basis, as of December 31, 2018, WGL Midstream’ has spent approximately US$446 million on its share of the construction costs.

In addition to the investment in Meade, WGL Midstream entered into an agreement with Cabot whereby WGL Midstream will purchase 0.5 Bcf/d of natural gas from Cabot over a 15 year term. As part of this agreement, Cabot has acquired 0.5 Bcf/d of firm gas transportation capacity on Transco’s Atlantic Sunrise project. This capacity has been released to WGL Midstream.

In August 2018, Meade executed an agreement with Transco to participate in an expansion of Central Penn with an estimated capital investment of up to US$50 million by WGL Midstream. Leidy South is expected to add an estimated 0.6 Bcf/d of natural gas capacity to Central Penn through the addition of compression at new and existing stations. Meade will own 40 percent of the expanded capacity and WGL Midstream will indirectly own 22 percent of the expanded capacity through its 55 percent ownership interest in Meade. Leidy South is anticipated to be in-service as early as the fourth quarter of 2021 assuming all necessary regulatory approvals are received in a timely manner.

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Mountain Valley

WGL Midstream owns a 10 percent equity interest in Mountain Valley. The proposed pipeline, which will be operated by EQM and developed, constructed, and owned by Mountain Valley (a venture of EQT and other entities), will transport approximately 2.0 Bcf/d and will extend from Equitrans LP’s system in Wetzel County, West Virginia to Transco’s Station 165 in Pittsylvania County, Virginia. The pipeline is estimated to span approximately 300 miles and provide access to the growing Southeast demand markets.

On October 13, 2017, the FERC issued the Certificate of Public Convenience and Necessity for the pipeline. In early 2018, the FERC granted several notices to proceed with certain construction activities on the pipeline. Mountain Valley has submitted additional requests to the FERC for notices to proceed. There are several pending challenges to certain aspects of the Mountain Valley project that must be resolved before the project can be completed. Mountain Valley is working to respond to the court and agency decisions and restore all permits. The pipeline is targeted to be placed in service during the fourth quarter of 2019, subject to litigation and regulatory-related delay. As of December 31, 2018, approximately 70 percent of the project is complete, which includes the welding of approximately 60 percent of the pipeline and ongoing construction work of all compressor stations and interconnects that are expected to be complete by February 2019. Most recently, the Mountain Valley construction team has been focused on stabilizing the right-of-way for the winter season.

WGL Midstream expects to invest approximately US$350 million through the in-service date of the pipeline based on scheduled capital contributions and its contracted share of project costs. On a cash basis, as of December 31, 2018, WGL Midstream has invested approximately US$271 million in the pipeline. In addition, WGL Midstream has gas purchase commitments to buy approximately 0.5 Bcf/d of natural gas, at index-based prices, for a 20-year term, and will also be a shipper on the proposed pipeline.

In April 2018, WGL Midstream entered into a separate agreement with EQM to acquire a 5 percent equity interest in a project to build an interstate natural gas pipeline (the MVP Southgate project). The proposed pipeline will receive gas from the Mountain Valley mainline in Pittsylvania County, Virginia and extend approximately 73 miles south to new delivery points in Rockingham and Alamance counties, North Carolina. The total commitment by WGL Midstream is expected to be approximately US$20 million and the lateral pipeline is expected to be placed into service in late 2020.

Constitution

WGL Midstream owns a 10 percent interest in Constitution. The pipeline project is designed to transport natural gas from the Marcellus region in northern Pennsylvania to major northeastern markets.

In December 2014, Constitution received approval from the FERC to construct and operate the proposed pipeline.  However, on April 22, 2016, the NYSDEC denied Constitution’s application for a Section 401 Certification for the pipeline, which is necessary for the construction and operation of the pipeline. In October 2017, Constitution filed a petition for declaratory order requesting the FERC to find that the Section 401 Certification requirement for the New York state portion of Constitution’s pipeline product was waived. On January 11, 2018, the FERC denied the petition. On January 16, 2018, Constitution petitioned the U.S. Supreme Court to review the judgment of the Second Circuit Court, asserting that the Second Circuit Court’s decision conflicts with the decisions of the U.S. Supreme Court and federal Courts of Appeals on an important question of federal law. On February 12, 2018, Constitution filed a request for rehearing with FERC, which was denied on July 19, 2018. On April 30, 2018, the U.S. Supreme Court denied Constitution’s petition for writ of certiorari.

The project’s sponsors remain committed to the project, and as such, on June 25, 2018, Constitution requested the FERC grant a 24-month extension of the completion date on construction of the pipeline until the fourth quarter of 2020. On September 14, 2018, Constitution filed a petition for review of prior FERC rulings with the DC Court of Appeals. On November 6, 2018, Constitution was granted a two year extension to put the pipeline into service.

WGL Midstream - Competition

WGL Midstream competes with other midstream infrastructure and energy services companies, wholesale energy suppliers, producers and other non-utility affiliates of regulated utilities for the acquisition of natural gas storage and

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transportation assets. WGL Midstream can be positively or negatively affected by significant volatility in the wholesale price of natural gas. WGL Midstream risk management policies and procedures are designed to minimize the risk that purchase commitments and the related sale commitments do not closely match. In general, profit opportunities for trading activities are increased for WGL Midstream with increased volatility in natural gas prices. These opportunities are primarily in short term transportation and storage spreads, seasonal storage spreads and long term supply or basis transactions.

Midstream Business — Energy Services

AltaGas Energy Services

One of the key functions of the marketing business is to support AltaGas’ infrastructure businesses. The marketing group, among other things, contracts supply and shrinkage gas for AltaGas’ extraction facilities, manages storage capacity, contracts and resells capacity on AltaGas’ transmission pipelines and provides natural gas control services to balance natural gas flow. The marketing group also markets natural gas and NGLs for certain field gathering and processing customers.

In addition to supporting the other operating segments within AltaGas, the marketing business identifies opportunities to buy and resell natural gas and NGLs, market natural gas and NGLs for producers and exchange, reallocate or resell pipeline capacity and storage to earn a profit. Net revenues from these activities are derived from low-risk opportunities based on transportation cost differentials between pipeline systems and differences in commodity prices from one period to another. Margins are earned by locking in buy and sell transactions in compliance with AltaGas’ credit and commodity risk policies. AltaGas also provides energy procurement services for utility gas users and manages the third-party pipeline transportation requirements for many of its gas marketing customers.

Retail Energy Marketing - Gas

WGL’s retail energy marketing consists of the operations of WGL Energy Services, a retail energy marketing business which sells natural gas directly to residential, commercial and industrial customers in Maryland, Virginia, Delaware, Pennsylvania and the District of Columbia. As at December 31, 2018, WGL Energy Services served approximately 106,400 residential, commercial and industrial natural gas customers located in Maryland, Virginia, Delaware, Pennsylvania and the District of Columbia. WGL Energy Services is subject to regulation by the public service regulatory commission of the states in which the company is authorized as a competitive service provider. WGL Energy Services contracts for storage and pipeline capacity to meet its customers’ needs primarily through transportation releases and storage services allocated from the utility companies in the various service territories through several interstate natural gas pipelines. To supplement WGL Energy Services’ natural gas supplies during periods of high customer demand, WGL Energy Services maintains gas storage inventory in storage facilities that are assigned by natural gas utilities such as Washington Gas. This storage inventory enables WGL Energy Services to meet daily and monthly fluctuations in demand and to minimize the effect of market price volatility. WGL Energy Services has a secured supply arrangement with Shell Energy. Under this arrangement, WGL Energy Services has the ability to purchase the majority of its power, natural gas and related products from Shell Energy in a structure that reduces WGL Energy Services’ cash flow risk from collateral posting requirements. While Shell Energy is intended to be the majority provider of natural gas and electricity, WGL Energy Services retains the right to purchase supply from other providers. The supply arrangement with Shell Energy expires in 2020.

Midstream Business — Energy Export

RIPET

On October 16, 2015, AltaGas entered into a project agreement with RTI for RIPET. This was followed in December 2015, with a sublease and related agreements between RTI and AltaGas. RIPET is expected to ship up to 1.2 million tonnes of propane per annum. A positive FID was made on RIPET in January 2017. Construction began in April 2017. At December 31, 2018, the LPG tank construction and related infrastructure is advancing as planned and remains on schedule. Construction of rail and marine infrastructure, as well as the balance of plant and operational buildings is also progressing. First cargo is expected early in the second quarter of 2019.

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In May 2017, AltaGas entered into a joint venture agreement with Vopak pursuant to which Vopak acquired a 30 percent interest in RIPET. Based on production from its existing facilities and commercial contracts executed or currently under negotiation, AltaGas anticipates having physical volumes equal to the initial 40,000 Bbls/d target by the project in-service date. AltaGas plans to operate the facility such that a majority of annual capacity will be underpinned by tolling arrangements, and expects to reach this objective over the next several years.

AltaGas LPG Limited Partnership and Astomos have entered into a multi-year agreement for the purchase of at least 50 percent of the 1.2 million tonnes per annum of propane expected to be available to be shipped from RIPET each year. Commercial agreements to secure the remaining capacity commitments are currently under negotiation. Propane from British Columbia and Alberta natural gas producers will be transported to the facility using the existing CN rail network. It is estimated that the facility will offload approximately 50 to 60 rail cars per day and deliver by marine transport approximately 20 to 30 cargos of propane per year to market. With RIPET expected to be the closest North American LPG terminal to Asia, it will allow Western Canadian propane producers to diversify their market access to Asia, a premium market for propane.

Petrogas - Ferndale Terminal

AltaGas, through its ownership in AIJVLP and indirect ownership interest in Petrogas, exports LPG through the Ferndale Terminal, which is owned and operated by Petrogas. The Ferndale Terminal is capable of handling LPG exports in excess of 40,000 Bbls/d with 750,000 Bbls of on-site storage capacity. The Ferndale Terminal has rail, truck and pipeline capability and is connected to two local refineries. In addition, Petrogas has a logistics network consisting of over 2,500 rail cars and 27 rail, storage and truck terminals in Canada and the United States along with access to another nine LPG terminals in the United States and one in Canada. Petrogas’ major terminal and owned and leased storage facilities are located in key energy hubs, including, without limitation, Fort Saskatchewan and Edmonton, Alberta, Sarnia, Ontario, Griffith, Indiana, Conway, Kansas and Mont Belvieu, Texas.

Environmental Considerations Impacting the Midstream Business

The Midstream business is subject to the following environmental regulations:

Alberta

CCIR

On January 1, 2018, the CCIR took effect, as a new regulation under the CCEMA, replacing the SGER in Alberta. The CCIR applies to any facility that has emitted 100,000 tonnes or more of carbon dioxide equivalent in 2003 or any subsequent year. Competitively impacted facilities which would otherwise not be subject to the CCIR may opt-in to the CCIR, in lieu of existing carbon levy obligations. The CCIR requires reductions in GHG emissions intensity from emissions intensity baselines established for a particular product. Where there is only one regulated facility or large emitter producing a specific product, the government will assign a facility-specific benchmark. Regulated emitters are required to reduce their emissions intensity in accordance with established benchmarks under the CCIR, or assigned benchmarks for specific facilities.

Large emitters subject to the CCIR will have the same compliance options available to them, as they did under the SGER. However, the CCIR has introduced expiry dates for emissions performance credits and emissions offsets. Emissions performance credits and emissions offsets generated in 2017, on a go-forward basis, are subject to expiry periods of eight years. Offsets or credits from 2014 and earlier will expire in 2020, and those from 2015 or 2016 will expire in 2021. The CCIR has also introduced limits on a large emitter’s ability usage of emission offsets and emission performance credits towards its emission reduction obligations.

Under the CCIR system, facilities are allowed to emit a certain amount of GHG, free of charge from the carbon levy. This approach protects industries from competitiveness impacts that could shift production to other jurisdictions. These “free” emissions are determined based on a product-specific emissions benchmark. Benchmarks are set relative to high-performing industry peers or competitors who produce the same or similar products. Both AltaGas’ Harmattan and

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Gordondale Facilities are considered large final emitters under the CCIR and as at December 31, 2018, were compliant with the regulation.

Carbon Levy

The Climate Leadership Act (Alberta) was enacted introducing an initial economy-wide carbon levy of $20 per tonne effective January 1, 2017, increasing to $30 per tonne in January 2018. All fuel consumption, including gasoline and natural gas, will be subject to the levy. Generally speaking, on-site combustion of natural gas by AltaGas’ gas processing assets are exempt from the carbon levy until January 1, 2023, while the sector works to reduce methane under the government’s joint initiative on methane reduction and verification. The levy exemption also applies to heating fuels on sites, subject to the CCIR regime.

Methane Reduction Regulation

The Government of Alberta has committed to reduce methane emissions from oil and gas operations by 45 percent relative to 2014 levels by 2025. Execution of the new oil and gas methane standards will be led by the Alberta Energy Regulator, in collaboration with Alberta Energy and the Alberta Climate Change Office. Details with respect to the Alberta Government’s methane reduction program were released on December 13, 2018 and will take effect on January 1, 2020. The AER Directive 060 sets out requirements for flaring, incinerating, and venting in Alberta at all upstream petroleum industry wells and facilities, with specific operational requirements to address fugitive emissions and venting, which are the primary sources of methane emissions from the oil and gas industry. The AER Directive 017 also sets out measurement requirements associated with the requirements under AER Directive 060.

British Columbia (B.C.)

Greenhouse Gas Industrial Reporting and Control Act

On January 1, 2016, the Greenhouse Gas Industrial Reporting and Control Act came into force to, among other things, ensure LNG facilities in B.C. will have an emissions cap. The legislation replaced the previous Greenhouse Gas Reduction (Cap and Trade) Act.

The Blair Creek Facility, Townsend Complex, North Pine Facility and other assets in B.C. are subject to the reporting obligations and as at December 31, 2018, are in compliance with the Greenhouse Gas Emission Reporting Regulation.

POWER BUSINESS

AltaGas’ Power business contributed revenue of $1.2 billion for the year ended December 31, 2018 (2017 - $0.6 billion), representing approximately 27 percent (2017 — 23 percent) of AltaGas’ total revenue before Corporate segment and intersegment eliminations.

The Power business is engaged in the generation and sale of capacity, electricity, ancillary services and related products in Alberta, California, Colorado, Michigan and North Carolina. After the sale of the non-core Canadian power assets which closed in February 2019 and the sale of the remaining 55 percent interest in the Northwest Hydro Facilities which closed in January 2019 (See “Recent Noteworthy Transactions — Sale of Northwest Hydro”), AltaGas had 1,105 MW of installed power capacity from a combination of gas-fired, biomass, distributed generation and energy storage assets, as more particularly set forth in the below table.

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Facility	Interest (%)	Capacity (MW)	Type	Geographic Region	Contracted Expiry Date
Blythe	100	507	Gas-fired	California, U.S.	2020
Brush II	100	70	Gas-fired	Colorado, U.S.	2019
Ripon	100	49.5	Gas-fired	California, U.S.	Merchant
Craven	50	48	Biomass	North Carolina, U.S.	2027
Pomona Energy Storage	100	20	Storage	California, U.S.	2027
Cogeneration I	100	15	Gas-fired	Alberta, Canada	Merchant
Cogeneration II	100	15	Gas-fired	Alberta, Canada	Merchant
Cogeneration III	100	15	Gas-fired	Alberta, Canada	Merchant
Grayling	30	37	Biomass	Michigan, U.S.	2027
Gordondale	100	3.4	Gas-fired	Alberta, Canada	Merchant
Distributed Generation	100	325	Various	Various regions in the U.S.	Various
Total		1,105

AltaGas believes that with a clean power generation footprint that includes, gas, small scale solar, biomass and energy storage, there will be longer term opportunities for the power generation business throughout North America. AltaGas continues to pursue the demand for clean energy sources under a capital-light power strategy.

The following chart provides a summary of the volumes sold, renewable capacity factor and contracted conventional equivalent availability factor for the last two years:

	2018(1)	2017
Renewable power sold (GWh)	1,551	1,629
Conventional power sold (GWh)	3,728	2,844
Renewable capacity factor (%)	29.7	39.6
Contracted conventional equivalent availability factor (%) (2)	97.2	98.1
WGL retail energy marketing — electricity sales volumes (GWh)	5,906	—

Notes:

(1)Actuals for 2018, which includes assets that have since been disposed of. These figures should not be relied upon as indicative of volumes or capacity for future periods.

(2)Calculated as the availability factor contracted under long-term tolling arrangements adjusted for occasions where partial or excess capacity payments have been added or deducted.

Gas-Fired Generation

In southern California, the 507 MW Blythe Energy Center utilizes gas-fired generation to produce power and serves the transmission grid operated by the CAISO to cover periods of high demand primarily driven by the Los Angeles area. Due to the structure of the long-term PPA with SCE, the majority of the revenue from the facility is derived from being available to produce and not from actual production, therefore providing stable cash flow. The current capacity of the Blythe Energy Center is contracted until July 31, 2020. The facility is directly connected to a Southern California Gas Company natural gas pipeline for its supply and has reactivated an El Paso Gas Company connection as a second supply source, and interconnects to SCE and CAISO via a 67-mile transmission line also owned by Blythe and is part of the Blythe Energy Center.

In northern California, AltaGas owns Ripon, which was contracted with PG&E until May 31, 2018. Following the expiry of the PPA at Ripon, AltaGas negotiated resource adequacy contracts for 2018 and the majority of 2019. Concurrently, AltaGas is also continuing to pursue battery storage opportunities at this site.

AltaGas currently has 45 MW of cogeneration capacity in Alberta through three cogeneration facilities, each of which can generate 15 MW of power for delivery of electricity into the Alberta power market. The facilities also have a heat recovery steam generator that is capable of producing all of the steam required to process gas at Harmattan from the waste heat in the exhaust gases from the turbine.

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Battery Storage

AltaGas constructed, owns and operates the Pomona Energy Storage Facility, a lithium-ion battery storage facility. The Pomona Energy Storage Facility is a 20 MW (80 MWh) facility which entered service on December 31, 2016 and is under contract for its capacity with SCE under a 10-year ESA. Under the terms of the ESA, AltaGas provides SCE with 20 MW of resource adequacy capacity for a continuous four hour period, which represents the equivalent of 80 MWh of energy discharging capacity. AltaGas receives fixed monthly resource adequacy payments under the ESA and retains the rights to earn additional revenue from the energy and ancillary services provided by the lithium-ion batteries, which will be sold on a merchant basis into the CAISO.

CES

The CES business consists of the operations of WGL Energy Systems, WGSW and the results of operations of affiliate owned commercial distributed energy projects.

CES focuses on clean and energy efficient solutions for its customers, driving earnings through: (i) upgrading the mechanical, electrical, water and energy-related infrastructure of large governmental and commercial facilities by implementing both traditional and alternative energy technologies; (ii) owning and operating distributed generation assets such as solar photovoltaic (solar PV) systems, combined heat and power plants, and natural gas fuel cells; and (iii) certain investments in residential and commercial retail solar PV companies as well as several tax equity funds which hold distributed generation projects.

WGL currently owns and manages distributed generation projects with approximately 325 MW of gross capacity across 20 states and the District of Columbia in the United States. The power output from these projects is generally contracted directly with end-user customers under long-term service agreements, providing clean energy solutions to a variety of commercial, government, institutional, and residential customers. For certain investments, WGL, along with a tax equity partner, has formed several tax equity funds to acquire, own, and operate distributed generation projects.

Retail Energy Marketing - Power

As at December 31, 2018, WGL Energy Services served approximately 96,800 residential, commercial and industrial electricity customer accounts located in Maryland, Virginia, Delaware, Pennsylvania and the District of Columbia. WGL Energy Services owns solar generating assets which are dedicated to five specific customers. WGL Energy Services does not own or operate any other electric generation, transmission or distribution assets. See “Midstream Business — Energy Services - Retail Energy Marketing — Gas” for further information on WGL Energy Services.

Competition

All of the power produced in Alberta is currently sold into the Pool, which operates an open market for the exchange of electricity and is run by the AESO. The AESO establishes the power price based on offers from Pool participants using a uniform pricing model whereby the marginal unit establishes the price for all generators. AESO system controllers sort the offers by price into a merit order beginning with the lowest priced offer, thereby defining a supply curve for each hour. By matching energy supply with demand, the Pool establishes a uniform hourly market price, which is published on the AESO’s website.

Energy and ancillary services attributes from the Pomona Energy Storage Facility are bid into the CAISO market on a day ahead basis. The CAISO establishes the supply stack based on the bids submitted and matches that to the demand curve based on a full network model which uses the costs of supply and demand for energy at individual nodes across the service area to establish locational marginal pricing. The market is then sorted again in the 15-minute market and on a real time basis to establish the price cleared at the relevant node.

The Blythe Energy Center is contracted by SCE under a long-term PPA until July 31, 2020. Power sold from Grayling and Craven is not exposed to market prices and is sold under PPAs that expire August 2027 (with automatic one year renewals unless terminated) and December 31, 2027, respectively. Ripon was contracted by PG&E under a PPA until May 31, 2018, following which AltaGas was awarded a resource adequacy contract for the remainder of 2018 and the

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majority of 2019. Brush II is contracted by Tri-State Generation and Transmission Association, Inc. until December 31, 2019.

Commercial Energy Systems competes in the renewable energy and distributed generation market and competitors primarily include other developers, tax equity investors, distributed generation asset owner firms and lending institutions. Within the government sector, competitors primarily include companies contracting with customers under Energy Savings Performance Contracting (ESPC) as well as utilities providing services under Utility Energy Saving Contracts (UESC). Commercial Energy Systems competes on the basis of strong customer relationships developed over many years of implementing successful projects, developing and maintaining strong supplier relationships, and focusing in areas where it can bring relevant expertise.

WGL Energy Services competes with regulated electric utilities and other third-party marketers to sell electricity to customers. Marketers of natural gas and electric supply compete largely on price; therefore, gross margins are relatively small. To provide competitive pricing to its retail customers and in adherence to its risk management policies and procedures, WGL Energy Services manages its contract portfolios by attempting to closely match the commitments for deliveries from suppliers with requirements to serve sales customers. WGL Energy Services’ residential and small commercial electric customer growth opportunities are significantly affected by the price for Standard Offer Service (SOS) offered by electric utilities. These rates are periodically reset for each customer class based on the regulatory requirements in each jurisdiction. Customer growth opportunities either expand or contract due to the relationship of these SOS rates to current market prices.

Environmental Considerations Impacting the Power Business

The Power business is subject to the following environmental regulations:

Alberta

Renewable Electricity Act

Pursuant to the Renewable Electricity Act, the Government of Alberta will provide funding support to new renewable electricity projects to replace two thirds of currently produced coal-fired power in the province (all of which will be retired by 2030). The Renewable Electricity Act establishes that 30 percent of Alberta’s electrical generation will come from renewable sources such as wind, hydro and solar by 2030 and the Government of Alberta has publicly announced a commitment to at least 5,000 MW of capacity by 2030. The remaining portion of coal-fired power is to be replaced by new or converted natural-gas fired power plants.

U.S. Federal Air and GHG Regulations

Clean Air Act

Under the Clean Air Act, the United States Environmental Protection Agency (USEPA) has the authority to set federal ambient air quality standards for certain air pollutants which apply throughout the U.S. The Clean Air Act could increase regulatory burdens for AltaGas’ natural gas-fired power plants, which emit volatile organic compounds and nitrogen oxides, by leading to additional control requirements, obligations to obtain emission offsets, or permitting delays.

Individual states must ensure that at a minimum their air quality meets the ambient federal standards set by the USEPA. In general, states may choose to impose stricter performance requirements than does the USEPA.

In addition, the Clean Air Act requires certain facilities to obtain construction and operating permits for their air emissions.

As of December 31, 2018, all of AltaGas’ operating natural gas-fired power generation facilities in California were in material compliance with their air permit requirements, which are issued in accordance with federal and state emissions standards.

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California GHG Regulations

California Renewable Portfolio Standard

In April 2011, the Governor of California signed Senate Bill X1-2, revising the Renewable Energy Resources Program to effectively increase the amount of electricity generated from eligible renewable energy resources to at least 33 percent of retail sales of electricity in California per year by December 31, 2020.

Senate Bill No. 350 (SB 350), the Clean Energy and Pollution Reduction Act of 2015, requires that the amount of electricity generated and sold to retail customers per year from eligible renewable energy resources be increased to 50 percent by December 31, 2030. The bill also provides for a potential expansion of CAISO into a regional organization to promote the development of regional electricity transmission markets in the western states, but does not mandate that transition.

AltaGas expects this legislation will increase demand for highly-responsive generation and energy storage assets such as the Pomona Energy Storage Facility. AltaGas expects to continue to leverage its existing sites as well as identify greenfield development opportunities to capitalize on these opportunities in California.

Cap-and-Trade Program

The California Air Resources Board (ARB) originally designed the California cap-and-trade regulations to meet the requirements of Assembly Bill No. 32 (AB 32). The California cap-and-trade program is a mandatory market-based system designed to reduce GHG emissions over time from multiple sources by setting a declining cap on GHG emissions. The program began in 2013 and has been extended to 2030. The emissions cap declines at approximately 3 percent per annum with the objective of reaching at least a 40 percent reduction in GHG emissions by 2030 compared to 1990 levels. Large GHG emitters must submit compliance instruments to the ARB in proportion to their annual emissions. Compliance instruments include emission allowances purchased at auction or in private sales, emission allowances distributed to certain industry participants, and limited proportions of offset credits.

As of December 31, 2018, all of AltaGas’ operating natural gas-fired power generation facilities in California were in material compliance with cap and trade requirements. Costs associated with meeting AB 32 and California’s cap-and-trade program have been passed through to the utilities pursuant to the applicable PPA.

California Groundwater Regulation

In California, water supply availability can be volatile, particularly as implementation moves forward the Sustainable Groundwater Management Act (SGMA). SGMA will require adoption of new mandatory requirements with the aim of managing groundwater “sustainably” over the long term. SGMA gives primary responsibility for regulating groundwater to local agencies referred to as Groundwater Sustainability Agencies. GSAs must develop plans that allow the maximum quantity of groundwater to be withdrawn without causing the lowering of groundwater levels, reduction of storage, seawater intrusion, degraded water quality, land subsidence or depletions of interconnected surface water. Although SGMA focuses on groundwater supplies, reduced availability of groundwater might increase surface water demands, whether originating from local or imported surface water supply sources. In these early stages of implementation, it is uncertain whether or how SGMA may impact water supplies for AltaGas’ power generation facilities in California.

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CORPORATE SEGMENT

The Corporate segment consists of general corporate investments (including investments in other public companies) and other revenue and expense items, such as general corporate overhead and interest expense, which are not directly attributable to AltaGas’ operating business segments. For the year ended December 31, 2018, the revenue for the Corporate segment was less than $1 million excluding intersegment eliminations and risk management and trading activities (2017 — $3 million). In addition, as at December 31, 2018, AltaGas held approximately 4 percent of the common shares of Painted Pony through the Corporate segment.

CAPITAL STRUCTURE

DESCRIPTION OF CAPITAL STRUCTURE

The authorized share capital of AltaGas consists of an unlimited number of Common Shares and such number of Preferred Shares issuable in series at any time as have aggregate voting rights either directly or on conversion or exchange that in the aggregate represent less than 50 percent of the voting rights attaching to the then issued and outstanding Common Shares. At December 31, 2018, AltaGas had 275,224,066 outstanding Common Shares, 5,511,220 outstanding Series A Shares, 2,488,780 outstanding Series B Shares, 8,000,000 outstanding Series C Shares, 8,000,000 outstanding Series E Shares, 8,000,000 outstanding Series G Shares, 8,000,000 outstanding Series I Shares, and 12,000,000 outstanding Series K Shares.

In addition, Washington Gas has outstanding 70,600 Washington Gas $4.25 Shares, 150,000 Washington Gas $4.80 Shares, and 60,000 Washington Gas $5.00 Shares.

The summary below of the rights, privileges, restrictions and conditions attaching to the Common Shares and the Preferred Shares is subject to, and qualified by reference to, AltaGas’ articles and by-laws.

Common Shares

Holders of Common Shares are entitled to one vote per share at meetings of Shareholders of AltaGas, to receive dividends if, as and when declared by the Board of Directors and to receive the remaining property and assets of AltaGas upon its dissolution or winding-up, subject to the rights of shares having priority over the Common Shares.

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Preferred Shares (1)

	Current Yield		Annual dividend per share(2)				Redemption price per share			Redemption and conversion option date(3)(4)		Right to convert into(4)
AltaGas
Series A Shares (5)	3.38	%	$	0.845			$	25		September 30, 2020		Series B
Series B Shares (6)	Floating	(6)	Floating			(6)	$	25		September 30, 2020	(7)	Series A
Series C Shares (8)	5.29	%	US$		1.3225		US$		25	September 30, 2022		Series D
Series E Shares (5)	5.393	%	$	1.34825			$	25		December 31, 2023		Series F
Series G Shares (5)	4.75	%	$	1.1875			$	25		September 30, 2019		Series H
Series I Shares (9)	5.25	%	$	1.3125			$	25		December 31, 2020		Series J
Series K Shares (10)	5.00	%	$	1.25			$	25		March 31, 2022		Series L
Washington Gas
$4.80 Shares	4.27	%	US$		4.80		US$		101	n/a		n/a
$4.25 Shares	4.27	%	US$		4.25		US$		105	n/a		n/a
$5.00 Shares	4.27	%	US$		5.00		US$		102	n/a		n/a

Notes:

(1)The table above only includes those series of preferred shares that are currently issued and outstanding. The Corporation is authorized to issue up to 8,000,000 of each of Series D Shares, Series F Shares, Series H Shares, and Series J Shares, and up to 12,000,000 of Series L Shares, subject to certain conditions, upon conversion by the holders of the applicable currently issued and outstanding series of preferred shares noted opposite such series in the table on the applicable conversion option date. If issued upon the conversion of the applicable series of preferred shares, Series F Shares, Series H Shares, Series J Shares, and Series L Shares are also redeemable for $25.50, and Series D Shares is redeemable for US$25.50 on any date after the applicable conversion option date, plus all accrued but unpaid dividends to, but excluding, the date fixed for redemption.

(2)The holders of Series A Shares, Series C Shares, Series E Shares, Series G Shares, Series I Shares and Series K Shares are entitled to receive a cumulative quarterly fixed dividend as and when declared by the Board of Directors. The holders of Series B Shares are entitled to receive a quarterly floating dividend as and when declared by the Board of Directors. If issued upon the conversion of the applicable series of Preferred Shares, the holders of Series D Shares, Series F Shares, Series H Shares, Series J Shares and Series L Shares will be entitled to receive a quarterly floating dividend as and when declared by the Board of Directors.

(3)AltaGas may, at its option, redeem all or a portion of the outstanding shares for the redemption price per share, plus all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary thereafter.

(4)The holder will have the right, subject to certain conditions, to convert their preferred shares of a specified series into Preferred Shares of that other specified series as noted in this column of the table on the applicable conversion option date and every fifth anniversary thereafter.

(5)Holders will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at a rate equal to the sum of the then five-year Government of Canada bond yield plus 2.66 percent (Series A Shares), 3.17 percent (Series E Shares), and 3.06 percent (Series G Shares).

(6)Holders of Series B Shares will be entitled to receive cumulative quarterly floating dividends, which will reset each quarter thereafter at a rate equal to the sum of the then 90-day government of Canada Treasury Bill rate plus 2.66 percent. Each quarterly dividend is calculated as the annualized amount multiplied by the number of days in the quarter, divided by the number of days in the year. Commencing December 31, 2018, the floating quarterly dividend rate for Series B Shares is $0.26938 per share for the period starting December 31, 2018 to, but excluding, March 31, 2019.

(7)Series B Shares can be redeemed for $25.50 per share on any date after September 30, 2015 that is not a Series B conversion date, plus all accrued and unpaid dividends to, but excluding, the date fixed for redemption.

(8)Holders of Series C Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the sum of the five-year U.S. Government bond yield plus 3.58 percent.

(9)Holders of Series I Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the then five-year Government of Canada bond yield plus 4.19 percent, provided that, in any event, such rate shall not be less than 5.25 percent per annum.

(10)Holders of Series K Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the then five-year Government of Canada bond yield plus 3.80 percent, provided that, in any event, such rate shall not be less than 5.00 percent per annum.

Preferred Shares may be used by AltaGas for any appropriate corporate purposes, including, without limitation, public or private financing transactions or issuance as a means of obtaining additional capital for use in AltaGas’ business and operations or in connection with acquisitions of other businesses and properties. AltaGas does not intend to use Preferred Shares as a defensive tactic to block take-over bids.

The Board of Directors may divide any unissued Preferred Shares into series and fix the number of shares in each series and the designation, rights, privileges, restrictions and conditions thereof. The Preferred Shares of each series will rank on

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parity with Preferred Shares of every other series with respect to accumulated dividends and return of capital and the holders of Preferred Shares will rank prior to the holders of Common Shares and any other shares of AltaGas ranking junior to the Preferred Shares with respect to the payment of dividends and the distribution of assets in the event of liquidation, dissolution or winding-up of AltaGas, whether voluntary or involuntary.

The rights, privileges, restrictions and conditions attaching to the Preferred Shares as a class may be repealed, altered, modified, amended or amplified or otherwise varied only with the sanction of the holders of the Preferred Shares given in such manner as may then be required by law, subject to a minimum requirement that such approval be given by resolution in writing executed by all holders of Preferred Shares entitled to vote on that resolution or passed by the affirmative vote of at least 662/3 percent of the votes cast at a meeting of holders of Preferred Shares duly called for such purpose.

For the specific rights, privileges, restrictions and conditions attaching to the currently issued and, as applicable, outstanding: (i) Series A Shares and the Series B Shares, reference should be made to the articles of amendment of AltaGas filed August 8, 2010 and the prospectus supplement of AltaGas dated August 11, 2010; (ii) Series C Shares and the Series D Shares, reference should be made to the articles of amendment of AltaGas filed June 1, 2012 and the prospectus supplement of AltaGas dated May 30, 2012; (iii) Series E Shares and Series F Shares, reference should be made to the articles of amendment of AltaGas filed December 9, 2013 and the prospectus supplement of AltaGas dated December 6, 2013; (iv) Series G Shares and Series H Shares, reference should be made to the articles of amendment of AltaGas filed June 27, 2014 and the prospectus supplement of AltaGas dated June 25, 2014; (v) Series I Shares and Series J Shares, reference should be made to the articles of amendment of AltaGas filed November 17, 2015 and the prospectus supplement of AltaGas dated November 16, 2015; and (vi) Series K Shares and Series L Shares, reference should be made to the articles of amendment of AltaGas filed February 15, 2017 and the prospectus supplement of AltaGas dated February 15, 2017. Each of the articles of amendment and prospectus supplements described herein has been filed with, and may be retrieved from, SEDAR at www.sedar.com.

Medium Term Notes

AltaGas has issued senior unsecured notes in the form of MTNs. Details with respect to the issued and outstanding MTNs can be found in Note 15 to AltaGas’ consolidated financial statements as at and for the year ended December 31, 2018 filed on SEDAR at www.sedar.com. The MTNs are not listed or quoted on any exchange.

WGL and Washington Gas Notes

WGL and Washington Gas issue long-term notes with individual terms regarding interest rates, maturities and call or put options. These notes can have maturity dates of one or more years from the date of issuance. For a complete list of such notes currently outstanding please refer to Note 15 in AltaGas’ consolidated financial statements as at and for the year ended December 31, 2018.

GENERAL

EMPLOYEES

At December 31, 2018, there were 2,881 individuals employed by AltaGas.

Utilities	2,160
Midstream	403
Power	116
Corporate	202
Total	2,881

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DIRECTORS AND OFFICERS

As at February 22, 2019, the directors and executive officers of AltaGas Ltd., as a group, owned beneficially, directly or indirectly, or exercised control or direction over 1,792,086 of the outstanding Common Shares, or approximately 0.65 percent of the 275,576,772 Common Shares issued and outstanding.

DIRECTORS

The number of directors of AltaGas is to be determined from time to time by resolution of the Board of Directors. The number of directors is currently twelve, of which nine are independent directors.

The term of office of any director continues until the annual meeting of Shareholders of AltaGas next following the director’s election or appointment or (if an election or appointment of a director is not held at such meeting or if such meeting does not occur) until the date on which the director’s successor is elected or appointed, or earlier if the director dies or resigns or is removed or disqualified, or until the director’s term of office is terminated for any other reason in accordance with the constating documents of AltaGas. The Shareholders are annually entitled to elect the Board of Directors.

The following table sets forth the names of the directors of AltaGas on February 22, 2019, their municipalities of residence and their principal occupations within the last five years.

Name of Director, Municipality of Residence and Position	Principal Occupation During the Past Five Years	Director Since
Catherine M. Best (1) Calgary, Alberta, Canada Director	Ms. Best is a Chartered Accountant and has been a Corporate Director since 2009. Ms. Best was the Executive Vice-President, Risk Management and Chief Financial Officer of the Calgary Health Region from 2000 to March 2009. Before joining the Calgary Health Region she was with Ernst & Young in Calgary for 19 years, the last 10 as Corporate Audit Partner.	November 30, 2011
Victoria A. Calvert (1) Calgary, Alberta, Canada Director	Ms. Calvert is a Corporate Director and Professor Emerita of Entrepreneurship and International Business with Mount Royal University (MRU) in Calgary, where she taught from 1988 until 2018. She also served as MRU’s Community Service Learning facilitator.	November 1, 2015
David W. Cornhill (2) Calgary, Alberta, Canada Chairman of the Board	Mr. Cornhill is Chairman of the Board of Directors of AltaGas, a position he has held since inception of AltaGas’ predecessor in 1994. Mr. Cornhill is a founding shareholder of AltaGas and its predecessors and was Chief Executive Officer from 1994 to 2016. He served as interim Co-CEO from July to December 2018. Prior to forming AltaGas, Mr. Cornhill served in various capacities with Alberta and Southern Gas Co. Ltd., including Vice President, Finance and Administration, Treasurer and President and Chief Executive Officer.	Director of AltaGas (and its predecessors) since April 1, 1994
Randall L. Crawford (2) Calgary, Alberta, Canada Director	Mr. Crawford has been the Chief Executive Officer since December 2018. Refer to the disclosure under “Executive Officers” for further information.	December 10, 2018
Allan L. Edgeworth (1) North Vancouver, B.C., Canada Director	Mr. Edgeworth is a Professional Engineer and Corporate Director. He was the President of ALE Energy Inc., a private consulting company, from January 2005 through December 2015. Prior thereto, Mr. Edgeworth was with Alliance Pipeline Ltd, initially as Executive Vice President and Chief Operating Officer and later as the President and Chief Executive Officer.	Director of AltaGas (and its predecessors) since March 2, 2005

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Name of Director, Municipality of Residence and Position	Principal Occupation During the Past Five Years	Director Since
Daryl H. Gilbert (1)(3) Calgary, Alberta, Canada Director	Mr. Gilbert is a Professional Engineer. He joined JOG Capital Inc. in May 2008 as a Managing Director and Investment Committee Member. Prior to becoming an independent businessman in 2005, Mr. Gilbert was with Gilbert Laustsen Jung Associates Ltd. (now GLJ Petroleum Consultants Ltd.) from 1979 to 2005, serving as President and Chief Executive Officer from 1994 to 2005.	Director of AltaGas (and its predecessors) since May 4, 2000
Robert B. Hodgins (1)(4) Calgary, Alberta, Canada Director	Mr. Hodgins is a Chartered Accountant. Mr. Hodgins has been an independent businessman since November 2004. Mr. Hodgins has been serving as Senior Advisor, Investment Banking for Cannacord Genuity Corp. from September 2018. Mr. Hodgins served as the Chief Financial Officer of Pengrowth Energy Trust (now Pengrowth Corporation) from 2002 to 2004. Mr. Hodgins also held the positions of Vice President and Treasurer of Canadian Pacific Limited and Chief Financial Officer of TransCanada PipeLines Limited.	Director of AltaGas (and its predecessors) since March 2, 2005
Cynthia Johnston (1) Victoria, B.C., Canada Director	Ms. Johnston is a Corporate Director. She was Executive Vice President, Gas, Renewables and Operations Services at TransAlta Corporation from 2015 to 2017. From 2011 to 2015, she held a number of other executive positions with TransAlta, including Chief Operating Officer of TransAlta Renewables Inc., President, TAMA Transmission, and Executive Vice President, Enterprise Risk and Corporate Services.	July 25, 2018
Pentti O. Karkkainen (1) West Vancouver, B.C., Canada Director	Mr. Karkkainen is a Corporate Director. He was a co-founder and General Partner of KERN Partners from 2000 to 2014, and was the firm’s Senior Strategy Advisor from 2014 until 2015. Prior thereto, Mr. Karkkainen was the Managing Director and Head of Oil and Gas Equity Research at RBC Capital Markets.	July 25, 2018
Phillip R. Knoll (1) (2) Kelowna, B.C., Canada Director	Mr. Knoll is a Professional Engineer and has been the President of Knoll Energy Inc. since 2006. Mr. Knoll served as interim Co-CEO of AltaGas Ltd. from July to December 2018. He was CEO of Corridor Resources Inc. from October 2010 to September 2014. Prior thereto, Mr. Knoll has held senior roles with a number of companies, including Duke Energy Gas Transmission, Maritimes & Northeast Pipeline, Westcoast Energy Inc., TransCanada Pipelines Limited and Alberta Natural Gas Company Ltd.	November 1, 2015
Terry D. McCallister (2) Key West, Florida, USA Director	Mr. McCallister is an independent businessman. Mr. McCallister was the Chairman and Chief Executive Officer of WGL and of Washington Gas from October 2009 to July 2018. Prior to this, he served as President and Chief Operating Officer of WGL and Washington Gas, joining Washington Gas in 2000 as Vice President of Operations. He has also held various leadership positions with Southern Natural Gas and Atlantic Richfield Company.	July 25, 2018
M. Neil McCrank (1)(5) Calgary, Alberta, Canada Lead Director	Mr. McCrank is Senior Counsel to the Calgary office of Borden Ladner Gervais LLP and has been since 2008. Mr. McCrank was Chairman of the Alberta Energy and Utilities Board from 1998 until 2007. Prior thereto, Mr. McCrank was with the Alberta Department of Justice, serving in various capacities, including Deputy Minister of Justice.	Director of AltaGas (and its predecessors) since December 10, 2007

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Notes:

(1)Independent director.

(2)Mr. Cornhill and Mr. Knoll acted as interim Co-CEOs from July 24, 2018 to December 9, 2018 until the appointment of Mr. Crawford as CEO. Mr. Cornhill, as CEO of the Corporation until April 15, 2016, is not considered to be an independent director until the expiry of a three year period from that date. Mr. McCallister, as former CEO of a major subsidiary of the Corporation until July 6, 2018, is not considered to be an independent director until the expiry of a three year period from that date. Mr. Crawford, as current CEO of the Corporation is not considered independent.

(3)Mr. Gilbert was a director of LGX Oil + Gas Inc. (LGX) from August 12, 2013 to June 7, 2016. On June 7, 2016, LGX was, on application by LGX’s senior lender, the subject of a consent receivership order under the Bankruptcy and Insolvency Act (Canada) pursuant to which Ernst & Young Inc. was appointed the receiver of all of LGX’s current and future assets, undertakings and properties. LGX was the subject of a cease trade order issued by the ASC on September 6, 2016 for failure to file certain financial statements. On February 9, 2017, approval and vesting orders were granted by the Court of Queen’s Bench of Alberta with respect to the liquidation and sale of assets by the receiver. Mr. Gilbert was a director of Connacher Oil & Gas Limited (Connacher) from October 2014 until February 25, 2019. Mr. Gilbert initially joined the board of directors of Connacher to assist in guiding the corporation through what turned out to be several financial restructurings. On May 17, 2016, Connacher applied for and was granted protection from its creditors pursuant to a Stay of Proceedings Order from the Court of Queen’s Bench of Alberta under the CCAA. On May 20, 2016, the TSX delisted the common shares of Connacher for failure to meet continued listing requirements. On February 16, 2019 Connacher announced that it was proceeding to close on a credit bid transaction with its supporting lenders, which is expected to be consummated in 2019 and will lead to an exit from the CCAA.

(4)Mr. Hodgins was a director of Skope Energy Inc. (Skope) from December 15, 2010 to February 19, 2013. On November 27, 2012, Skope was granted protection from its creditors by the Court of Queen’s Bench of Alberta pursuant to the CCAA to implement a restructuring which was approved by the required majority of Skope’s creditors. The restructuring was sanctioned by the Court of Queen’s Bench of Alberta in February of 2013.

(5)Mr. McCrank was, from July 17, 2008 to April 5, 2011, a director of MegaWest Energy Corp. (MegaWest), a reporting issuer in the provinces of Alberta and British Columbia. In September 2010, a cease trade order was issued by each of the ASC and the BCSC against MegaWest for failure to file certain disclosure documents. Such filings were completed by MegaWest and revocation orders were issued by the ASC and BCSC in October of 2010.

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AltaGas has four standing committees of the Board of Directors: (1) Audit, (2) Governance, (3) Human Resources and Compensation (HRC) and (4) Environment, Health and Safety (EH&S). The members of each of these committees, as of January 1, 2019, are identified below:

Director	Audit Committee	Governance Committee	HRC Committee	EH&S Committee
Catherine M. Best	ü		ü
Victoria A. Calvert		ü		ü
David W. Cornhill
Allan L. Edgeworth	ü		ü
Daryl H. Gilbert			Chair
Cynthia Johnston			ü	ü
Pentti O. Karkkainen	ü	ü
Robert B. Hodgins	Chair	ü
Phillip R. Knoll				Chair
Terry D. McCallister				ü
M. Neil McCrank		Chair

EXECUTIVE OFFICERS

The names, municipality of residence and position of each of the current executive officers of AltaGas and other members of the Executive Committee are as follows:

Name of Officer, Municipality of Residence and Position with AltaGas Ltd.	Principal Occupation During the Past Five Years
Randall L. Crawford Calgary, Alberta, Canada President and Chief Executive Officer Director	Chief Executive Officer of AltaGas since December 2018. Prior to joining AltaGas, Mr. Crawford was with EQT Midstream Partners, LP from 2012 to 2017, most recently as Executive Vice President and Chief Operating Officer and with EQT Corporation as Senior Vice President and President Midstream, Commercial and Distribution from 2007 to 2017.
Timothy W. Watson Calgary, Alberta, Canada Executive Vice President and Chief Financial Officer	Executive Vice President and Chief Financial Officer of AltaGas from November 2015. Executive Vice President of AltaGas from March 2015 to October 2015. Head and Managing Director, Canadian Energy and Power Investment Banking at Merrill Lynch Canada Inc. from September 2010 to January 2015.
Corine R.K. Bushfield Airdrie, Alberta, Canada Executive Vice President, Chief Administrative Officer	Executive Vice President, Chief Administrative Officer of AltaGas from December 2016. Senior Vice President and Chief Financial Officer of Long Run Exploration Ltd. from March 2013 to September 2016. Vice President and Assistant Controller of Encana Corporation from 2010 to March 2013.
Adrian Chapman (1) Washington, DC, U.S.A. President and Chief Executive Officer of Washington Gas Light Company and member of the Executive Committee	President and Chief Executive Officer of WGL and Washington Gas from July 2018. Also, President, U.S. Utilities of AltaGas Services (U.S.) Inc. From October 2009 to July 2018, President and Chief Operating Officer of WGL and Washington Gas.
Fredrick K. Dalena Coraopolis, Pennsylvania Executive Vice President, Commercial Strategy and Business Development	Executive Vice President, Commercial Strategy and Business Development of AltaGas since December 2018. Principal Midstream Business Development of EQT Corporation from 2015 to 2017. Executive Vice President Midstream Commercial Strategy form 2014 to 2015. Various executive commercial roles in EQT’s Distribution, Midstream and Energy Services companies since joining EQT in 2003.

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Name of Officer, Municipality of Residence and Position with AltaGas Ltd.	Principal Occupation During the Past Five Years
Randy W. Toone Calgary, Alberta, Canada Executive Vice President and President, Midstream	Executive Vice President and President, Gas from January 2019. Executive Vice President and Acting President from July to December 2018. Executive Vice President Gas from June 2017. Executive Vice President, Commercial and Business Development from December 2016 to June 2017. Chief Operating Officer of CSV Midstream Solutions from July 2014 to November 2016. Country Manager of TAG Oil Ltd. from May 2013 to June 2014. Other roles with AltaGas prior to 2014 include President Utilities, President Gas, and Co-President Gas.
Bradley B. Grant Calgary, Alberta, Canada Executive Vice President and Chief Legal Officer; Executive Vice President, Strategy and Corporate Development	Executive Vice President, Strategy and Corporate Development since January 2019. Executive Vice President and Chief Legal Officer since July 2018 of AltaGas. Prior thereto, Vice President and General Counsel of AltaGas from May 2015. Partner with the law firm of Stikeman Elliott LLP from January 2004 to May 2015.

Note:

(1)Mr. Chapman was a director of American Solar Direct, Inc. (ASDI) from November 5, 2010 to March 14, 2017. On June 2, 2017, ASDI filed for Chapter 7 bankruptcy in the U.S. Bankruptcy Court, Central District of California (Los Angeles).

AUDIT COMMITTEE

Composition of the Audit Committee

The Committee is currently comprised of four members, Catherine Best, Allan Edgeworth, Robert Hodgins and Pentti Karkkainen. Mr. Hodgins is the chair of the Committee. All of the members of the Committee are independent and financially literate as defined under Canadian securities law.

Relevant Education and Experience

Ms. Best is a Chartered Accountant and was the Executive Vice-President, Risk Management and Chief Financial Officer of the Calgary Health Region from 2000 to March 2009. Before joining the Calgary Health Region she was with Ernst & Young LLP in Calgary for nineteen years, the last ten as Corporate Audit Partner. She has served on the audit committees of a number of public companies.

Mr. Edgeworth was the President of ALE Energy Inc. from January 2005 through December 2015. Mr. Edgeworth was the President and Chief Executive Officer of Alliance Pipeline from 2001 until December 2004. Mr. Edgeworth joined Alliance Pipeline in 1998 as Executive Vice President and Chief Operating Officer. Prior to that, Mr. Edgeworth spent almost 20 years with Westcoast Energy Inc. where he held various positions including Vice President of Pipeline Operations, Senior Vice President of Regulatory Affairs and President Pipeline Division.

Mr. Hodgins was the Chief Financial Officer at Pengrowth Energy Trust (now Pengrowth Corporation) from 2002 to 2004. Mr. Hodgins was Vice President and Treasurer at Canadian Pacific Limited from 1998 to 2002 and Chief Financial Officer of TransCanada PipeLines Limited from 1993 to 1998. Mr. Hodgins has an Honours Degree in Business from the Richard Ivey School of Business at the University of Western Ontario, is a Chartered Professional Accountant, and is a Chartered Accountant in Ontario and Alberta. He has served on a number of public company audit committees.

Mr. Karkkainen co-founded and was General Partner of KERN Partners, a Canadian energy-focused capital markets and private equity firm, from 2000 to 2014, and was the Senior Strategy Advisor from 2014 to 2015. Mr. Karkkainen also serves on the Board of Directors of NuVista Energy Ltd. as Lead Director and has served on a number of audit committees, including acting as Chair of one such committee. Mr. Karkkainen has a Master of Business Administration from Queen’s University.

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Pre-Approval Policies and Procedures

As set forth in the Committee’s charter, the Committee must pre-approve all non-audit services provided by the external auditor and has direct responsibility for overseeing the work of the external auditor.

External Auditor Service Fees by Category

The fees billed by Ernst & Young LLP (E&Y), AltaGas’ external auditors, during 2018 and 2017 were as follows:

Category of External Auditor Service Fee	2018		2017
Audit Fees	$	2,766,074	$	2,452,645
Audit-Related Fees(1)	1,242,606		381,383
Tax Compliance Fees(2)	66,389		44,404
All Other Fees(3)	86,970		206,387
Total	$	4,162,039	$	3,084,819

Notes:

(1)Represent the aggregate fees billed by E&Y for assurance and related services that were reasonably related to the performance of the audit or review of AltaGas’ financial statements and were not reported under “Audit Fees”. During 2018 and 2017, the nature of the services provided included review of prospectuses and security filings, research of accounting and audit-related issues (including those related to the acquisition of WGL), internal controls assessment, and registration costs for the Canadian Public Accountability Board.

(2)During 2018 and 2017, the nature of the services provided was for tax compliance and transfer pricing.

(3)Represent the aggregate fees billed by E&Y for products and services, other than those reported with respect to the other categories of service fees. During 2018 and 2017, the nature of the services provided was for translation services.

RISK FACTORS

Set forth below is a summary of certain risk factors relating to AltaGas and the business of AltaGas. The risks described below are not an exhaustive list of all risks, nor should they be taken as a complete summary of all the risks associated with the applicable business being conducted. Security holders and prospective security holders of AltaGas should carefully review and consider the risk factors set out below as well as all other information contained and incorporated by reference in this AIF before making a decision on investment and should consult their own experts where necessary. Information regarding AltaGas’ risk management activities can be found in AltaGas’ management information circular dated May 1, 2018 and will also be included in AltaGas’ management information circular for its 2019 annual meeting of the Shareholders.

Capital Market and Liquidity Risks

AltaGas may have restricted access to capital and increased borrowing costs. As AltaGas’ future capital expenditures will be financed out of cash generated from operations, borrowings and possible future equity sales, AltaGas’ ability to finance such expenditures is dependent on, among other factors, the overall state of capital markets and investor demand for investments in the energy industry generally and AltaGas’ securities in particular.

To the extent that external sources of capital become unavailable or available on onerous terms or otherwise limited, AltaGas’ ability to make capital investments and maintain existing assets may be impaired, and its assets, liabilities, business, financial condition, results of operations and dividends may be materially and adversely affected as a result.

If cash flow from operations is lower than expected or capital costs for these projects exceed current estimates, or if AltaGas incurs major unanticipated expenses related to construction, development or maintenance of its existing assets, AltaGas may be required to seek additional capital to maintain its capital expenditures at planned levels. Failure to obtain financing necessary for AltaGas’ capital expenditure plans may result in a delay in AltaGas’ capital program or a decrease in dividends.

Washington Gas and the SPE made certain ring fencing commitments, such that the assets of the Ring Fenced Entities will not be available to satisfy the debt or contractual obligations of any Non-Ring Fenced Entity. See “Recent Noteworthy Transactions — Acquisition of WGL”.

General Economic Conditions

AltaGas’ operations are affected by the condition and overall strength of the global economy and, in particular, the economies of Canada and the U.S. During economic downturns, the demand for the products and services that AltaGas

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provides and the supply of or demand for power, natural gas and NGLs may be adversely affected. The occurrence of periods of poor economic conditions or low or negative economic growth could have an adverse impact on AltaGas’ results and restrict AltaGas’ ability to make dividends to Shareholders.

Consumption Risk

Changes in energy consumption by consumers as a result of the availability of and incentive to invest in energy efficient technology have the potential to reduce customer demand. This could negatively impact AltaGas’ results.

Market Risk

AltaGas is exposed to market risks resulting from fluctuations in commodity prices and interest rates, in both North American markets and, with respect to the LNG and LPG export business, offshore markets. In these markets commodity supply and demand is affected by a number of factors including, without limitation, the amount of the commodity available to specific market areas either from the wellhead or from storage facilities, prevailing weather patterns, the U.S., Canadian and Asian economies, the occurrence of natural disasters and pipeline restrictions. In addition, the retail energy marketing business is exposed to pricing of certain ancillary services provided by the power pool in which it operates. The fluctuations in commodity prices are beyond AltaGas’ control and, accordingly, could have a material adverse effect on AltaGas’ business, financial condition, and cash flow.

Internal Credit Risk

Credit ratings affect AltaGas’ ability to obtain short-term and long-term financing and the cost of such financing. Additionally, the ability of AltaGas to engage in ordinary course derivative or hedging transactions and maintain ordinary course contracts with customers and suppliers on acceptable terms depends on AltaGas’ credit ratings.

On December 19, 2018, S&P downgraded AltaGas’ issuer rating and senior unsecured MTN rating from BBB with a Negative Outlook to BBB- with a Negative Outlook. On December 21, 2018, DBRS downgraded the rating from BBB Under Review with Developing Implications to BBB(low) with a Stable Outlook. On July 27, 2018, Fitch assigned a first-time rating of BBB to AltaGas and on December 17, 2018 affirmed the BBB rating.

A further reduction in the current rating on AltaGas’ debt by one or more of its rating agencies would reflect a downgrade below an investment grade rating, which would adversely affect AltaGas’ cost of financing and its access to sources of liquidity and capital.

In addition, a further downgrade in AltaGas’ credit ratings may affect AltaGas’ ability to, and the associated costs of, (i) entering into ordinary course derivative or hedging transactions and may require AltaGas to post additional collateral under certain of our contracts, and (ii) entering into and maintaining ordinary course contracts with customers and suppliers on acceptable terms.

Additionally, with respect to WGL, an increase in borrowing costs without the ability to recover these higher costs in the rates charged to Washington Gas’ customers, which would be impacted by the merger-related commitment that prohibits Washington Gas from recovering any incremental financing costs due to a credit downgrade, could adversely affect earnings or cash flows by limiting Washington Gas’ ability to earn its allowed rate of return. Credit ratings are intended to provide investors with an independent measure of credit quality of any issuer of securities. The credit ratings assigned to AltaGas’ securities by the rating agencies are not recommendations to purchase, hold or sell the securities in as much as such ratings do not comment as to market price or suitability for a particular investor. Any rating may not remain in effect for any given period of time or may be revised or withdrawn entirely by a rating agency in the future if in its judgment circumstances so warrant.

Foreign Exchange Risk

AltaGas is exposed to foreign exchange risk through its investments in the United States, and may in the future be exposed to foreign exchange risk in the LNG and LPG export business. Changes in the Canada/United States exchange rate could impact the earnings of AltaGas, the value of the United States investments and the cash generated from the

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United States businesses. AltaGas operates internationally, with an increasing amount of the Corporation’s net income earned outside of Canada. As a result, AltaGas may experience a discrepancy between the currencies in which liabilities are incurred and the currency in which revenues are generated. This could adversely affect AltaGas’ results due to the imposition of additional taxes and cost of currency exchange.

Debt Service

AltaGas may, from time to time, finance a significant portion of its operations through debt. Amounts paid in respect of interest and principal on debt incurred by AltaGas may impair its ability to satisfy any obligations under its indebtedness held by AltaGas directly or indirectly. Variations in interest rates and scheduled principal repayments could result in significant changes in the amount required to be applied to debt service. Ultimately, this could reduce dividends to Shareholders. Furthermore, loans to AltaGas are subject to customary covenants and financial tests which may in certain circumstances restrict AltaGas’ ability to make dividends to Shareholders.

Financing and Refinancing Risk

Each of AltaGas’ credit facilities has a maturity date, on which date, absent replacement, extension or renewal, the indebtedness under the respective credit facility becomes repayable in its entirety. To the extent any of the credit facilities are not replaced or extended on or before their respective maturity dates or are not replaced, extended or renewed for the same, similar or higher amounts or on the same, similar or better terms, AltaGas’ ability to fund ongoing operations. In addition, such credit facilities typically include covenants, the failure of which could impede AltaGas’ ability to borrow under such facilities, potentially negatively impacting AltaGas’ cash flows and business.

Market Value of Common Shares and Other Securities

AltaGas cannot predict at what price the Common Shares, Preferred Shares or other securities issued by AltaGas will trade in the future. Common Shares, Preferred Shares and other securities of AltaGas will not necessarily trade at values determined solely by reference to the underlying value of the Corporation’s assets. One of the factors that may influence the market price of such securities is the annual yield on such securities. An increase in market interest rates may lead purchasers of securities of AltaGas to demand a higher annual yield and this could adversely affect the market price of such securities. In addition, the market price for securities of AltaGas may be affected by announcements of new developments, changes in AltaGas’ operating results, differences between results and analysts’ expectations, changes in credit ratings, changes in general market conditions, fluctuations in the market for securities and numerous other factors beyond the control of AltaGas.

Variability of Dividends

The declaration and payment of dividends on Common Shares by AltaGas are at the discretion of the Board of Directors. The cash available for dividends to Shareholders is a function of numerous factors, including, without limitation, AltaGas’ financial performance, the impact of interest rates, electricity prices, natural gas, NGL, LNG and LPG prices, debt covenants and obligations, working capital requirements, liquidity and future capital requirements. Dividends may be reduced or suspended entirely depending on the operations of AltaGas and the performance of its assets. The market value of AltaGas’ shares may deteriorate if AltaGas is unable to meet or otherwise chooses to modify its dividend targets, and that deterioration may be material.

On December 13, 2018, AltaGas announced the completion of a comprehensive review of its dividend and the reset of the dividend to $0.08 per share in order to improve financial strength and ensure greater funding flexibility. While AltaGas anticipates that the reset will have a significant impact on its financial flexibility and credit profile, over time providing an efficient source of funding to de-lever and fund growth, there can be no assurance that such reset will achieve the intended objectives and that the Board of Directors of AltaGas will not in the future exercise its discretion to again reset the dividend.

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Commitments Associated with Regulatory Approvals for the Acquisition of WGL

As a result of the process to obtain any consents required of each of the PSC of DC, the PSC of MD, the SCC of VA and FERC, as well as to obtain CFIUS approval for the acquisition of WGL, AltaGas is committed to various programs, contributions and investments in several agreements and regulatory approval orders. It is possible that AltaGas may encounter delays, unexpected difficulties or additional costs in meeting these commitments in compliance with the terms of the relevant agreements and orders. Failure to fulfill the commitments in accordance with their terms could result in increased costs or result in penalties or fines that could materially adversely affect AltaGas’ business, financial condition, operating results and prospects.

Integration of WGL

AltaGas acquired WGL with the expectation that the acquisition will result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the acquisition of WGL is subject to a number of uncertainties, including whether the businesses of WGL and AltaGas can be integrated in an efficient, effective and timely manner and whether AltaGas is able to realize the anticipated growth opportunities and synergies from such integration. The combination of two independent businesses is complex, costly and time-consuming and may divert significant management attention and resources to combining WGL’s and AltaGas’ business practices and operations. This process may disrupt both AltaGas’ and WGL’s businesses.

In addition, it is possible that the integration process could take longer than anticipated and could result in the disruption of AltaGas’ businesses, processes and systems or inconsistencies in standards, controls, procedures, practices and policies, any of which could adversely affect the combined company’s ability to achieve the anticipated benefits of the acquisition as and when expected. The overall combination of the businesses may also result in material unanticipated problems, expenses, liabilities, competitive responses and loss of customer and other business relationships. Failure to achieve these anticipated benefits or the incurrence of unanticipated expenses and liabilities could materially adversely affect AltaGas’ business, financial condition, operating results and prospects.

Growth Strategy Risk

During 2018, AltaGas made significant changes to its business, including the WGL Acquisition, the ACI IPO, asset sales, and a strategic shift in focus to primarily the Utilities and Midstream segments. It is possible that the changes in strategy AltaGas has implemented and plans to continue implementing in 2019 and onwards will not be as successful as projected.

2019 Planned Asset Sales

AltaGas has announced an intention to complete additional asset sales of approximately $1.5 to $2.0 billion in 2019, with the objective of further de-levering the Corporation, funding future growth and minimizing the need for any near-term common equity requirements. See “2019 Planned Asset Sales and Balanced Funding Plan”.

Given the challenges currently facing the energy sector, other issuers may also engage in competitive asset sales as against a more limited suite of potential investors, leading to lower demand for AltaGas’ assets and/or reduced prices relative to AltaGas’ current expectations and the book value of such assets. AltaGas may not be able to sell all or any of its assets identified for sale on favourable terms or at all. If AltaGas is able to sell assets, the timing of the receipt of the asset sale proceeds may not align with the timing of AltaGas’ capital requirements. A failure to raise sufficient capital from asset sales or a misalignment of the timing of capital raised and capital funding needs could have an adverse impact on AltaGas’ business, financial condition, results of operations and cash flows.

Additionally, any such asset monetizations could result in impairments if such assets are sold or otherwise exchanged for amounts less than their carrying value. If management determines that an impairment has occurred, the Corporation would be required to take an immediate non-cash charge to earnings.

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Potential Sales of Additional Shares

AltaGas may issue additional shares in the future to directly or indirectly fund, among other things, capital expenditure requirements of entities now or hereafter owned directly or indirectly by AltaGas, including financing acquisitions by those entities. Such additional shares may be issued without the approval of Shareholders. Shareholders will have no pre-emptive rights in connection with such additional issuances. The Board of Directors has discretion in connection with the price and the other terms of the issue of such additional shares. Any issuance of Common Shares or securities convertible into Common Shares may have a dilutive effect on existing Shareholders.

Volume Throughput

AltaGas’ businesses process, transport and store natural gas, ethane, NGLs and other commodities. Throughput within the business is dependent on a number of factors, including the level of exploration and development activity within the WCSB, the long-term supply and demand dynamics for the applicable commodities and the regulatory environment for market participants. Notably, as a result of the development of non-conventional shale gas supplies in North America the price of natural gas in North America has declined and there has been a shift towards richer, wet gas with higher NGL content. Areas with dryer gas have seen depressed activity. These factors and industry trends may result in AltaGas being unable to maintain throughput in certain areas. Consequently, AltaGas may be exposed to declining cash flow and profitability arising from reduced natural gas, ethane and NGL throughput and from rising operating costs.

Counterparty Credit Risk

AltaGas is exposed to credit-related losses in the event that counterparties to contracts fail to fulfill their present or future obligations to AltaGas. AltaGas has credit risk relating to, among others, counterparties to the sale, purchase and delivery of commodity, transportation capacity, energy system design and construction, investment terms, as well as long-term contracts including PPAs, EPAs and take-or-pay agreements. While a significant number of AltaGas’ counterparties are of investment grade quality, given significant and prolonged deterioration in the financial wellbeing of the Western Canadian energy industry and the challenges to material improvement, AltaGas can provide no assurance as to whether the credit quality of its counterparties will remain at current levels or decline. In addition, for non-wholly owned subsidiaries, AltaGas relies on other investors to fulfill their commitments and obligations in respect of the project or facility. In the event such entities fail to meet their contractual obligations to AltaGas, such failures may have a material adverse effect on AltaGas’ business, financial condition, results of operations and prospects. AltaGas mitigates these increased risks through diversification and a review process of the creditworthiness of their counterparties.

Dependence on Certain Partners

AltaGas does not operate certain facilities and also co-owns certain facilities with joint venture partners. Failure by the operators of these facilities to operate at the cost or in the manner projected by AltaGas could negatively affect AltaGas’ results. In addition, for non-wholly owned subsidiaries, AltaGas relies on other investors to fulfill their commitments and obligations in respect of the project or facility. AltaGas has entered into various types of arrangements with joint venture partners for any or all of the construction, operation or ownership of certain facilities. Certain of these partners may have or develop interests or objectives which are different from or even in conflict with the objectives of AltaGas. AltaGas does not have the sole power to direct the business and operations of such facilities and AltaGas faces the risk of being impacted by partners’ decisions and by potential disagreements regarding operations and other business decisions. Any such differences could have a negative impact on the success of such facilities. AltaGas is sometimes required, through the permitting and approval process of such facilities, to notify and consult with various stakeholder groups, including, without limitation, landowners, Indigenous groups and municipalities. Any unforeseen delays in this process may negatively impact the ability of AltaGas to complete any given facility on time or at all.

Natural Gas Supply Risk

Adequate supplies of natural gas and pipeline and storage capacity may not be available to satisfy committed obligations as a result of economic events, natural occurrences and/or failure of a counterparty to perform under a gas purchase, capacity or storage contracts and, accordingly, could have a material adverse effect on AltaGas’ business, financial conditions and cash flow.

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In addition, Washington Gas must acquire additional interstate pipeline transportation or storage capacity and construct transmission and distribution pipe to deliver additional capacity into growth areas on its system. The specific timing of any larger customer additions to its market may not be forecasted with sufficiently long lead time and the availability of these supply options to serve any of its customer additions may be limited by market supply and demand, the timing of Washington Gas’ participation in new interstate pipeline construction projects, local permitting requirements and the ability to acquire necessary rights of way. These limitations could result in an interruption in Washington Gas’ ability to satisfy the needs of some of its customers.

Operating Risk

AltaGas’ businesses are subject to the risks normally associated with the operation and development of natural gas, NGL, LNG, LPG and power systems and facilities, including, without limitation, mechanical failure, transportation problems, physical degradation, operator error, manufacturer defects, sabotage, terrorism, failure of supply, weather, wind or water resource deviation, catastrophic events and natural disasters, fires, floods, explosions, earthquakes and other similar events. These types of events could result in injuries to personnel, damage to property and the environment, as well as unplanned outages or prolonged downtime for maintenance and repair. Among other things, these events typically increase operation and maintenance expenses and reduce revenues. The occurrence or continuation of any of these events could increase AltaGas’ costs and reduce its ability to process, store, transport, deliver or distribute natural gas, NGLs, LNG and LPG, or generate or deliver power and result in significant losses for which insurance may not be sufficient or available. Environmental damage could also result in increased costs to operate and insure AltaGas’ assets and have a negative impact on AltaGas’ reputation and its ability to work collaboratively with local communities, Indigenous groups and other stakeholders.

As AltaGas continues to grow and diversify its energy infrastructure businesses, the risk profile of AltaGas may change. Operating entities may enter into or expand business segments where there is greater economic exposure and more “at risk” capital.

Changes in Laws

Applicable laws, including, without limitation, environmental laws, policies or government incentive programs may be changed in a manner that adversely affects AltaGas through the imposition of restrictions on its business activities or by the introduction of regulations that increase AltaGas’ operating costs; thereby potentially reducing AltaGas’ ability to pay dividends to shareholders. There can be no assurance that applicable laws, policies or government incentive programs relating to energy infrastructure will not be changed in a manner which adversely affects AltaGas.

Regulatory and environmental laws affecting AltaGas have changed, and will continue to change, over time. The proposed Bill C-69, which would enact the Canadian Energy Regulator Act and the Impact Assessment Act and repeal the existing National Energy Board Act and the Canadian Environmental Assessment Act, proposes sweeping regulatory changes for federally regulated project proponents. These proposed changes include changes to timelines in obtaining project approvals, greater public and Indigenous engagement and participation in regulatory proceedings for projects, expanded factors to be considered by regulatory decision makers in reviewing new projects, greater inspection and enforcement powers and the introduction of strict and absolute liability offences for federally-regulated entities. While the proposed Bill C-69 remains subject to change, if brought into force, it may affect AltaGas’ existing, planned or future projects on federal lands, and interprovincial and international projects in Canada.

Income tax laws relating to AltaGas may be changed in a manner that adversely affects its shareholders. This includes, without limitation, taxation and tax policy changes, tax rate changes, new tax laws, and revised tax law interpretations that may individually or collectively cause an increase in AltaGas’ effective tax rate. AltaGas has made an initial assessment of the impacts of the 2017 changes to the U.S. tax laws, the TCJA, on it and its subsidiaries, however, it remains unknown at this time how the U.S. Treasury Department may interpret certain provisions of the TCJA. These interpretations may have adverse impacts on the effective tax rates for part or all of AltaGas’ U.S. businesses.

Recent political events in the U.S. have led to uncertainty regarding ongoing trade relationships, in particular in relation to the replacement of the North American Free Trade Agreement (NAFTA) with the United States-Mexico-Canada Agreement (USMCA). While NAFTA is still in place, USMCA has been negotiated by the governments of the United

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States, Mexico and Canada, but still must be ratified be certain groups within these governments. As such, at this time AltaGas is unable to predict what impact the USMCA may have.

Washington Gas and WGL Midstream may face regulatory and financial risks related to pipeline safety legislation from a number of proposals to require increased oversight over pipeline operations and increased investment in and inspections of pipeline facilities pending or previously proposed in the United States Congress. Additional operating expenses and capital expenditures may be necessary to remain in compliance with the increased federal oversight resulting from such proposals. While AltaGas cannot predict with certainty the extent of these expenses and expenditures or when they will become effective, the adoption of such proposals could result in significant additional costs to Washington Gas’ and WGL Midstream’s businesses. Washington Gas may be unable to recover from customers through the regulatory process all or some of these costs and may be unable to earn its authorized rate of return on these costs.

Risk Management Costs and Limitations

AltaGas uses derivative financial instruments to manage the risks associated with movements in exchange rates and power, natural gas and NGL prices. AltaGas does not enter into derivatives transactions for speculative purposes.  These transactions cannot mitigate all risk associated with AltaGas’ business nor the risk of unauthorized activities notwithstanding appropriate oversight through AltaGas’ risk management function. Any such unauthorized activities could materially adversely affect our business, operations and financial condition.

In addition, rules implementing the derivatives transaction provisions of the Dodd-Frank Act in the United States could have an adverse impact on AltaGas’ ability to hedge risks associated with the business. The Dodd-Frank Act regulates derivatives transactions, which include certain instruments, such as interest rate swaps, and commodity options, financial and other contracts, used in AltaGas’ risk management activities. The Dodd-Frank Act requires that most swaps be cleared through a registered clearing facility and that they be traded on a designated exchange or swap execution facility, with certain exceptions for entities that use swaps to hedge or mitigate commercial risk. The Dodd-Frank requirements relating to derivative transactions have not been fully implemented by the SEC and the Commodity Futures Trading Commission. When fully implemented, the law and any new regulations could increase the operational and transactional cost of derivatives contracts and affect the number and/or creditworthiness of available counterparties. In addition, commencing in 2016, certain Canadian securities regulatory authorities adopted instruments in relation to the trading, clearing and reporting of derivatives. While the nature of AltaGas’ derivatives activities and the relative rolling monthly notional amounts thereof have thus far entitled AltaGas to exemptions from the obligation to prepare and file reports with a derivatives trade repository in relation to such derivatives, there can be no assurance that AltaGas will be able to continue to rely on such exemptions in the future. If AltaGas is required to report its derivatives trades to a derivatives trade repository it will need to incur the time and financial expense associated with implementing and maintaining the systems necessary to do so, which could increase the operational and transactional cost of derivatives contracts

Further, AltaGas may transact with counterparties based in the European Union or other jurisdictions which, like the U.S., are in the process of implementing regulations to regulate derivatives transactions, some of which are currently in effect and may impose costs on derivatives activities.

Regulatory

AltaGas’ businesses are subject to extensive and complex laws and regulations in the jurisdictions in which they carry on business. Regulations and laws are subject to ongoing policy initiatives, and AltaGas cannot predict the future course of regulations and their respective ultimate effects on AltaGas’ businesses. Changes in the regulatory environment may be beyond AltaGas’ control and may significantly affect AltaGas’ businesses, results of operations and financial conditions. Pipelines and facilities can be subject to common carrier and common processor applications and to rate setting by the regulatory authorities in the event an agreement on fees or tariffs cannot be reached with producers. The export and import of energy is also subject to regulatory approvals. Power facilities are subject to regulatory approvals and regulatory changes in tariffs, market structure and penalties. Washington Gas, SEMCO Gas, ENSTAR and CINGSA operate in regulated marketplaces where regulatory approval is required for the regulated returns that provide for recovery of costs and a return on capital and may limit the ability to make and implement independent management decisions, including,

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without limitation, setting rates charged to customers, determining methods of cost recovery and issuing debt. Earnings of AltaGas’ regulated utilities may be impacted by a number of factors, including, without limitation, (i) changes in the regulator-approved allowed return on equity and common equity component of capital structure; (ii) changes in rate base; (iii) changes in gas delivery volumes; (iv) changes in the number and composition of customers; (v) variances between actual expenses incurred and forecast expenses used to determine revenue requirements and set customer rates; and (vi) recovery of unplanned costs through rate cases.

Climate Change and Carbon Tax

Some of AltaGas’ significant facilities may be subject to future provincial, state or federal climate change regulations or both to manage greenhouse gas emissions. See sections “Environmental Regulation”, “Business of the Corporation — Utilities Business — Environmental Regulations Impacting the Utilities Business”, “Business of the Corporation — Midstream Business — Environmental Regulations Impacting the Midstream Business”, “Business of the Corporation — Power — Business - Environmental Regulations Impacting the Power Business”, and  of this AIF. The direct or indirect costs of compliance with these regulations may have a material adverse effect on AltaGas’ business, financial condition, results of operations and prospects. AltaGas’ business could also be indirectly impacted by laws and regulations that affect its customers or suppliers; to the extent such changes result in reductions in the use of natural gas by its customers or limit the operations of, or increase the costs faced by producers. In addition, concerns about climate change have resulted in a number of environmental activists and members of the public opposing the continued exploitation, development and transportation of fossil fuels. Given the evolving nature of the debate related to climate change and the control of greenhouse gas emissions and resulting requirements, it is difficult to predict the impact on AltaGas and its operations and financial condition.

Construction and Development

The development, construction and future operation of natural gas, natural gas distribution, NGL, LNG, LPG and power facilities can be affected adversely by changes in government policy and regulation, environmental concerns, increases in capital and construction costs, defects in construction, construction delays, increases in interest rates and competition in the industry. In the event that any one of these factors emerges, the actual results may vary materially from projections, including, without limitation, projections of costs, facility utilization or throughput, generation, future revenue and earnings.

The construction and development of AltaGas’ natural gas, natural gas distribution, NGL, LNG, LPG and power projects and their future operations are subject to changes in the policies and laws of both Canadian and U.S. federal, provincial, state and local governments, including, without limitation, regulatory approvals and regulations relating to the environment, land use, health, culture, conflicts of interest with other parties and other matters beyond the direct control of AltaGas.

The construction of AltaGas’ pipeline assets have experienced and may continue to experience legislative and regulatory obstacles, and the construction and operation of these assets are subject to hazards, equipment failures, supply chain disruptions, personnel issues and related risks, which could result in decreased values of these investments, including impairments, and/or delays their in-service dates, which would negatively affect results of operations. For instance, AltaGas is required to test certain assets for impairment on either an annual basis or when events or circumstances occur which indicate that the carrying value of such assets might be impaired. That testing might result in the impairment of assets, including goodwill, property, plant and equipment, intangible assets or certain investments.

Because these assets are interconnected with facilities of third parties, the operation of these facilities could also be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties. These events could further delay the in-service date of WGL Midstream’s projects or disrupt operations on these projects, which could have an adverse effect on AltaGas’ financial results.

RIPET Rail and Marine Transportation

Propane will be transported from natural gas producers to RIPET using the existing CN rail network and will be delivered to customers by marine transport. Rail shipments and marine shipments may be impacted by service delays, inclement weather, railcar availability, railcar derailment or other rail or marine transport incidents and could adversely impact volumes or the price received for product or impact our reputation or result in legal liability, loss of life or personal injury, loss of equipment or property, or environmental damage. Costs for environmental damage, damage to property and/or personal injury in the event of a rail or marine incident involving propane have the potential to be significant. Major Canadian railways have adopted standard contract provisions designed to shift liability for third-party claims to shippers. In the event that AltaGas is ultimately held liable for any damages resulting from its activities at RIPET relating to rail or marine transport of propane, and for which insurance is not available, or increased costs or obligations are imposed on AltaGas as a result of new regulations, AltaGas’ business, operations and financial condition may be adversely impacted.

Litigation

In the course of its business, AltaGas is subject to lawsuits and other claims. Defense and settlement costs associated with such lawsuits and claims can be substantial, even with respect to lawsuits and claims that have no merit. Due to the

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inherent uncertainty of the litigation process, the resolution of any particular legal proceeding could have a material adverse effect on the financial position or operating results of AltaGas.

WGL is currently involved in legal proceedings with Antero Resources Corporation (Antero) relating to a dispute over gas being delivered under natural gas purchase contracts. Washington Gas and WGL Midstream contracted in June 2014 with Antero to buy gas from Antero at invoiced prices based on an index, and at a delivery point, specified in the contracts. Since deliveries began, however, the index price paid has been more than the fair market value at the same physical delivery point, resulting in losses within WGL entities of approximately US$40 million. Accordingly, Washington Gas and WGL Midstream notified Antero that it sought to apply a provision of the contracts that would permit a new index to be established. Antero objected, claiming that the contract provisions permitting re-pricing did not apply, unless Antero itself chose to sell gas at cheaper prices at the delivery point (which Antero claimed it had not). The dispute was arbitrated in January 2017, and the arbitral tribunal ruled in favor of Antero on the applicability of the re-pricing mechanism. However, the tribunal ruled that it lacked authority to determine whether Antero was in breach of its obligation to deliver gas to Washington Gas and WGL Midstream at a point where they could obtain the higher pricing. Accordingly, Washington Gas and WGL Midstream filed suit in state court in Colorado for a determination of this issue. The state court initially granted Antero’s motion to dismiss the case and WGL subsequently filed an appeal. In October 2018, the Court of Appeals reversed the state court’s decision and remanded the lawsuit to the trial court. Separately, Antero has initiated suit against Washington Gas and WGL Midstream, claiming that they have failed to purchase specified daily quantities of gas and seeking alleged cover damages exceeding US$100 million as of April 4, 2018 according to Antero’s complaint. Washington Gas and WGL Midstream oppose both the validity and amount of Antero’s claim. WGL believes the probability that Antero could succeed in collecting these penalties is remote therefore no accrual was made as of December 31, 2018. In December 2017, WGL Midstream amended its purchase contract with Antero and, effective February 1, 2018, is no longer obligated to purchase gas at the delivery point that is the subject of these disputes. These two cases have been consolidated and a jury trial has been scheduled for June 10, 2019.

Washington Gas continues to support the investigation by the National Transportation Safety Board (NTSB) into the August 10, 2016 explosion and fire at an apartment complex on Arliss Street in Silver Spring, Maryland, the cause of which has not been determined.  The NTSB has scheduled a board meeting, open to the public, on April 23, 2019 “to determine the probable cause” of the incident.  A total of 40 civil actions related to the incident have been filed against WGL and Washington Gas in the Circuit Court for Montgomery County, Maryland. All of these suits seek unspecified damages for personal injury and/or property damage. The one action seeking class action status has been amended to assert property damage and loss of use claims. The trial date for the hearings has been scheduled for December 2, 2019. Washington Gas maintains excess liability insurance coverage from highly-rated insurers, subject to a nominal self-insured retention. Washington Gas believes that this coverage will be sufficient to cover any significant liability to it that may result from this incident.

AltaGas participates in a number of joint ventures with regard to the ownership and operation of its assets and facilities. Certain of its joint venture partners may have or develop interests or objectives which are different from or even in conflict with the objectives of AltaGas. AltaGas attempts to reach a negotiated resolution to any disagreements regarding operations and other business decisions with its joint partners. However, where the parties fail to reach such a resolution, litigation between the parties may result. Such litigation, or the circumstances giving rise to such litigation, may have a material adverse effect on the joint ventures, the joint venture partners or their respective assets and businesses, which could have a material adverse effect on AltaGas’ business, financial condition, results of operations and prospects. See also “Risk Factors - Dependence on Certain Partners.”

Infrastructure

As utilities infrastructure matures, several of AltaGas’ utilities have implemented replacement programs to replace aging infrastructure and taken other preventative and remedial measures. If certain pipelines and related infrastructure were to become unexpectedly unavailable for delivery of current or future volumes of natural gas because of repairs, damage, spills or leaks, or any other reason, it could have a material adverse impact on financial conditions and results of operation of the utility business. Although the costs of infrastructure replacement programs are typically recovered in rates, on-going capital is required to fund such programs. In addition, operating issues resulting from maturing infrastructure such as leaks, equipment problems and incidents, including, without limitation, explosions and fire, could result in legal liability, repair and remediation costs, increased operating costs, increased capital expenditures, regulatory fines and penalties and other costs and a loss of customer confidence. Any liabilities resulting from the occurrence of these events may not be fully covered by insurance or rates.

Cyber Security, Information, and Control Systems

AltaGas’ business processes are increasingly reliant upon information systems automation provided by infrastructure, technologies and data. A failure of these information systems could lead to the impairment of business processes, and there is a risk of cascading failure of information systems leading to the impairment of multiple business processes. The risk of cyber-attack targeting information systems is increasing, with strong evidence of the industry being specifically targeted. In addition, AltaGas collects and stores sensitive information in the ordinary course of business, including personal information in respect of our employees and proprietary information in respect of our stakeholders, including customers, suppliers and investors.

Security breaches of AltaGas’ information technology infrastructure, including, without limitation, cyber-attacks and cyber-terrorism, or other failures of AltaGas’ information technology infrastructure could result in disruptions of natural gas distribution operations and other operational outages, ability to operate safely, delays, damage to assets, the environment or to AltaGas’ reputation, diminished customer confidence, lost profits, lost data including, without limitation, the unauthorized release of customer, employee or Company data that is crucial to AltaGas’ operational security or could adversely affect the ability to deliver and collect on customer bills, increased regulation and other adverse outcomes,

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including, without limitation material legal claims and liability or fines or penalties under applicable laws and adversely affect its business operations and financial results.

AltaGas’ cyber security strategy focuses on information technology security risk management which includes, without limitation, continuous monitoring, ongoing cyber security communications and training for staff, conducting third-party vulnerability and security tests, threat detection and an incident response protocol. However, there is no assurance that AltaGas will not suffer a cyber-attack or an information technology failure notwithstanding the implementation of this strategy and the measures taken pursuant to that strategy, including, without limitation, as set forth above and the occurrence of any of these cyber events could adversely affect AltaGas’ financial condition and results of operations.

External Stakeholder Relations

AltaGas places great importance on establishing and maintaining positive relationships with its stakeholders, including, without limitation, within the communities in which AltaGas operates, regulators, and local Indigenous groups. There is an increasing level of public concern relating to the perceived effect of natural resources activities, including, without limitation, exploration, development, production, processing and transportation, on certain environmental and social aspects such as air and water quality, noise, dust, land and ecological disturbance and employment and economic development opportunities. Opposition to natural resources activities by communities, special interest groups (including non-governmental organizations) or Indigenous groups may ultimately impact AltaGas, including its ability to obtain or maintain permits, the anticipated timing and costs associated with capital projects, its operations, and its reputation.  Recent and proposed regulatory changes could increase the ability of special interest groups to object to and/or delay certain capital projects. See “Changes in Laws” above. Publicity adverse to AltaGas’ operations, AltaGas’ partners, or others operating in the energy industry generally, could have an adverse effect on AltaGas and its operations. While AltaGas is committed to operating in a socially responsible manner, there can be no assurance that its efforts in this respect will mitigate this potential risk.

Composition Risk

The extraction business is influenced by the composition of natural gas produced in the WCSB and processed at AltaGas’ facilities. The composition of the gas stream has the potential to vary over time due to factors such as the level of processing done at plants upstream of AltaGas’ facilities and the composition of the natural gas produced from reservoirs upstream of AltaGas’ facilities.

Electricity and Resource Adequacy Prices

AltaGas’ revenue from sales of power, capacity and ancillary services attributes are subject to market factors such as fluctuating supply and demand, which may be affected by weather, customer usage, economic activity and growth factors and this exposure may increase upon termination of existing power purchase arrangements. When a power purchase arrangement expires or is terminated, it is possible that the price received by the power generator or the relevant facility or plant under subsequent selling arrangements may be reduced significantly. It is also possible that power purchase arrangements negotiated after the initial term has expired may not be available at profitable prices that permit the continued operation of the affected facility or plant.

Interest Rates

AltaGas is exposed to interest rate fluctuations on variable rate debt. Interest rates are influenced by Canadian, U.S. and global economic conditions beyond AltaGas’ control and, accordingly, could have a material adverse effect on AltaGas’ business, financial condition and cash flow.

Collateral

AltaGas is able to obtain unsecured credit limits from certain of its counterparties in order to lock in base load electricity margins and also to procure natural gas and NGL supply and services for its energy services business. If counterparties’ credit exposure to AltaGas exceeds the unsecured credit limits granted, AltaGas may have to provide collateral such as letters of credit.

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Indigenous Land and Rights Claims

Indigenous peoples have claimed rights to a substantial portion of the lands in Canada. AltaGas operates in territories in which such claims have been advanced. Such claims, if successful, could have a significant adverse effect on matters, including, without limitation, natural gas production, the construction of natural gas storage infrastructure in Nova Scotia, the development of natural gas and NGL extraction projects in Alberta and British Columbia, the development of RIPET in British Columbia and power development and generation projects in Alberta, which could have a materially adverse effect on AltaGas’ business and operations, including, without limitation, the volume of natural gas processed at AltaGas’ facilities, the power produced by AltaGas’ facilities or on the operation or development of facilities for gathering and processing, energy exports, natural gas distribution, storage, power generation or extraction and transmission.

AltaGas has concluded agreements with many Indigenous communities and other agreements are in development. These agreements support an approach of active engagement with Indigenous communities that serves to ensure the identification of issues and facilitates constructive problem-solving. Further, AltaGas has taken a proactive approach to enhance the economic participation of Indigenous groups in its operations where feasible and reasonable. The agreements and the measures taken by AltaGas strengthen relationships between the parties while respecting the ever evolving regulatory and judicial relationship between Canada’s governments and Indigenous peoples. However, AltaGas cannot predict whether future Indigenous land claims and the assertion of other rights will affect its ability to conduct its business and operations as currently undertaken or as may be undertaken in the future in such regions. Furthermore, any failure to reach an agreement, or a conflict or disagreement, with an Indigenous group could have a material adverse effect on AltaGas’ business, financial condition and results of operations.

Crown Duty to Consult with Indigenous Peoples

The federal and provincial governments in Canada have a duty to consult and, where appropriate, accommodate Indigenous peoples where the interests of the Indigenous peoples may be affected by a Crown action or decision. Accordingly, the Crown’s duty may result in regulatory approvals being delayed or not being obtained, which could have a material adverse effect on AltaGas’ business.

Underinsured and Uninsured Losses

There can be no assurance that AltaGas will be able to obtain or maintain adequate insurance coverage at all or at rates it considers reasonable. Further, there can be no assurance that available insurance will cover all losses or liabilities that might arise in the conduct of AltaGas’ business. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by AltaGas, or a claim that falls within a significant self-insured retention could have a material adverse effect on AltaGas’ business or its results. Further, significant insured claims could lead to an increased cost of operating and insuring AltaGas’ assets in the future.

Weather Data

The utilities and natural gas distribution business is highly seasonal, with the majority of natural gas demand occurring during the winter heating season, the length of which varies in each jurisdiction in which AltaGas’ utilities operate. Natural gas distribution revenue during the winter typically accounts for the largest share of annual revenue in the Utilities business. There can be no assurance that the long-term historical weather patterns will remain unchanged. Annual and seasonal deviations from the long-term average can be significant. In Maryland and Virginia, Washington Gas has in place regulatory mechanisms and rate designs intended to stabilize the level of net revenues that it collects from customers by eliminating the effect of deviations in customer usage caused by variations in weather from normal levels, and other factors such as conservation. If Washington Gas’ rates and tariffs are modified to eliminate these provisions, then Washington Gas would be exposed to significant risk associated with weather.

The operations of AltaGas’ retail energy-marketing business, are weather sensitive and seasonal, with a significant portion of revenues derived from the sale of natural gas to retail customers for space heating during the winter months, and from the sale of electricity to retail customers for cooling during the summer months. Weather conditions directly influence the volume of natural gas and electricity delivered to customers. Weather conditions can also affect the short-term pricing of energy supplies that the retail energy-marketing business may need to procure to meet the needs of its

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customers. Similarly, the business of AltaGas’ Midstream business is seasonal due to the tendency of storage and transportation spreads to increase during the winter. In addition, the distributed generation operations of AltaGas, which derive significant revenues from the sale of electricity to customers from solar generating assets, are weather sensitive because weather conditions directly influence the generation of electricity that is delivered to customers. Deviations from normal weather conditions and the seasonal nature of these businesses can create large fluctuations in short-term cash requirements and earnings for these businesses.

Service Interruptions

Service interruption incidents that may arise through unexpected major power disruptions to facilities or pipeline systems, third-party negligence or unavailability of critical replacement parts could cause AltaGas to be unable to safely and effectively operate its assets. This could adversely affect AltaGas’ business operations and financial results.

Rep Agreements

If AltaGas becomes insolvent or is in material default under the terms of the Rep Agreements for an extended period, effective ownership of the natural gas processing plant within Harmattan can be claimed by the original Harmattan owners for a nominal fee. Accordingly, under these circumstances, AltaGas could lose its investment in the natural gas processing plant, excluding the Caroline Pipeline and various ancillary facilities that are owned 100 percent by AltaGas.

Cook Inlet Gas Supply

ENSTAR’s gas distribution system, including, without limitation, the Alaska Pipeline Company pipeline system, is not linked to major interstate and intrastate pipelines or natural gas supplies in the lower 48 states of the United States or in Canada. As a result, ENSTAR procures natural gas supplies under long-term RCA-approved contracts from producers in and near the Cook Inlet area. Declining production from the Cook Inlet gas fields may result in potential deliverability problems in ENSTAR’s service area. There is ongoing exploration for natural gas in the Cook Inlet area, including, without limitation, producers that have supply contracts with ENSTAR. Activity also continues with respect to the possible construction of a natural gas pipeline that would extend from Alaska’s North Slope, through interior Alaska to a liquefaction facility located in southcentral Alaska. There are no assurances, however, with respect to these gas supply-related matters, including when such pipelines might be constructed and put in service or whether natural gas supplies transported by such pipelines would be available to ENSTAR’s customers and secured by ENSTAR on terms and conditions that would be acceptable to the RCA.

Health and Safety

The ownership and operation of AltaGas’ business is subject to hazards of gathering, processing, transporting, fractionating, storing and marketing hydrocarbon products, including, without limitation, blowouts, fires, explosions, gaseous leaks, releases and migration of harmful substances, hydrocarbon spills, corrosion, and acts of vandalism and terrorism. Any of these hazards can interrupt operations, impact AltaGas’ reputation, cause loss of life or personal injury, result in loss of or damage to equipment, property, information technology systems, related data and control systems, and cause environmental damage that may include polluting water, land or air.

Further, such ownership and operations carries the potential for liability related to worker health and safety, including, without limitation, the risk of any or all of government imposed orders to remedy unsafe conditions, potential penalties for contravention of health and safety laws, licenses, permits and other approvals, and potential civil liability. Compliance with health and safety laws (and any future changes) and the requirements of licenses, permits and other approvals are expected to remain material to AltaGas’ business.

Safety has been and continues to be a core value of AltaGas and is integral to how AltaGas operates. AltaGas actively works with industry groups and communities within which it operates to improve safety. Also, AltaGas has policies, procedures and emergency response plans in place, which AltaGas regularly monitors and evaluates to identify opportunities for improvement in its safety programs. In addition, Washington Gas, with support from each of its regulatory commissions, is accelerating the replacement of aging pipeline infrastructure prioritized on a risk-based approach and has implemented preventive and remedial measures to address increased leak rates in its distribution system caused by an

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increase in the volume of natural gas containing low concentration of halogenated hydrocarbons received from its suppliers.

However, no assurances can be given that the occurrence of any of the above listed events or the additional workers’ health and safety issues relating thereto will not require unanticipated expenditures, or result in fines, penalties or other consequences (including, without limitation, changes to operations) material to AltaGas’ business and operations.

Non-controlling interests in investments

AltaGas owns, and may acquire additional, non-controlling interests in investments. AltaGas may not have the right or power to direct the management of these investments, and other investors may take action that is contrary to AltaGas’ interests. In addition, other participants may become bankrupt or have other economic or business objectives that could negatively impact the value and performance of AltaGas’ investments.

Decommissioning, Abandonment and Reclamation Costs

AltaGas is responsible for compliance with all applicable laws and regulations regarding the decommissioning, abandonment and reclamation of its facilities at the end of their economic life, the costs of which may be substantial. It is not possible to predict these costs with certainty since they are a function of regulatory requirements at the time of decommissioning, abandonment and reclamation and the actual costs may exceed current estimates which are the basis of the asset retirement obligation shown in AltaGas’ financial statements. In particular, management has identified environmental issues associated with the prior activities of Harmattan. There are indications of significant groundwater and soil contamination resulting from Harmattan’s prior activities. There is a risk that the costs of addressing these environmental issues could be significant.

As well, Washington Gas has recorded environmental liabilities for costs expected to be incurred to remediate sites where Washington Gas or a predecessor affiliate operated manufactured gas plants (MGPs). Estimates of liabilities for environmental response costs are difficult to determine with precision because of the various factors that can affect their ultimate level. These factors include, but are not limited to, the following:

·the complexity of the site;

·changes in environmental laws and regulations at the federal, state and local levels;

·the number of regulatory agencies or other parties involved;

·new technology that renders previous technology obsolete or experience with existing technology that proves ineffective;

·the level of remediation required; and

·variation between the estimated and actual period of time required to respond to an environmentally contaminated site.

Washington Gas has identified up to ten sites where it or its predecessors may have operated (MGPs). Washington Gas last used any such plant in 1984. In connection with these operations, Washington Gas is aware that coal tar and certain other by-products of the gas manufacturing process are present at or near some former sites and may be present at others.

Washington Gas is currently remediating its East Station property, which is adjacent to the Anacostia River, including ground water pump and treat, tar recovery, soil encapsulation and other treatment. Washington Gas is conducting a remedial investigation and feasibility study under a 2012 consent decree with the District of Columbia and the federal government and additional remediation may be required. In addition, manufactured gas waste was discovered at an adjoining property, a parcel of land adjacent to East Station. Washington Gas has agreed to work with the owners of the

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adjoining property to perform a site investigation, ground water sampling, and report on the contamination at the site pursuant to oversight by Department of Energy and Environment (DOEE).

Washington Gas received a letter in February 2016 from the District of Columbia and National Park Service regarding the Anacostia River Sediment Project, indicating that the District of Columbia is conducting a separate remedial investigation and feasibility study of the river to determine if and what cleanup measures may be required and to prepare a natural resource damage assessment. The sediment project draft remedial investigation report issued on March 30, 2018 identifies East Station as one of seventeen potential environmental cleanup sites. During the fiscal year ended September 30, 2017, Washington Gas received a request for information related to three Washington Gas properties. The Corporation is not able to estimate the total amount of potential damages or timing associated with the District of Columbia’s environmental investigation on the Anacostia River at this time. While an allocation method has not been established, Washington Gas has accrued an amount based on a potential range of estimates.

Cost of Providing Retirement Plan Benefits

The cost of providing retirement plan benefits to eligible current and former employees is subject to changes in the market value of AltaGas’ retirement plan assets, changing bond yields, changing demographics and changing assumptions. Any sustained declines in equity markets, reductions in bond yields, increases in health care cost trends, or increases in life expectancy of beneficiaries may have an adverse effect on AltaGas’ retirement plan liabilities, assets and benefit costs. Additionally, AltaGas may be required to increase its contributions in future periods in order to preserve the current level of benefits under the plans and/or due to U.S. federal funding requirements.

Labour Relations

The operations and maintenance staff at Ripon, Pomona, the Blythe Energy Center, Younger and some employees of Washington Gas and SEMCO Energy are members of a labour union. Aspects of RIPET’s operations will also be performed by employees that will be members of a labour union. Labour disruptions could restrict the ability of Ripon, Pomona, and the Blythe Energy Center to generate power, the ability of Younger to process natural gas and produce NGLs, operations at RIPET, or could affect Washington Gas, and SEMCO Energy’s operations and therefore could affect AltaGas’ cash flow and net income.

Key Personnel

AltaGas’ success has been largely dependent on the skills and expertise of its key personnel. The continued success of AltaGas will be dependent on its ability to retain such personnel and to attract additional talented personnel to the organization. Access to a sustained labour market from which to attract the required expertise, knowledge and experience is a critical factor to AltaGas’ success. Costs associated with attracting and retaining key personnel could adversely affect AltaGas’ business operations and financial results.

Failure of Service Providers

Certain of AltaGas’ information technology, customer service, supply chain, pipeline and infrastructure installation and maintenance, engineering, payroll and human resources functions that AltaGas relies on are provided by third party vendors. Some of these services may be provided by vendors from centers located outside of Canada or the United States. Services provided pursuant to these agreements could be disrupted due to events and circumstances beyond AltaGas’ control. AltaGas’ reliance on these service providers could have an adverse effect on AltaGas’ business, results of operations and financial condition.

Technical Systems and Processes Incidents

Failure of key technical systems and processes to effectively support information requirements and business processes may lead to AltaGas’ inability to effectively and efficiently measure, record, access, analyze and accurately report key data. This could result in increased costs and missed business opportunities.

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Securities Class Action Suits and Derivative Suits

Securities class action suits and derivative suits are often brought against companies who have entered into mergers and acquisition transactions. There can be no assurance that WGL or AltaGas will not be targets of such suits in the future, and no guarantee that WGL or AltaGas can successfully defend against any such actions. Defending against these claims, even if meritless, could result in substantial costs to WGL and AltaGas and could divert the attention of management.

Returns on AltaGas’ Investments in Renewable Energy Projects

AltaGas’ Power business derives a portion of its revenues from the sale of solar RECs, which are produced as a result of owning and operating commercial distributed energy systems. The value of these solar RECs is determined by markets in the states where the distributed energy systems are installed, which are driven by state laws relating to renewable portfolio standards or alternative compliance payment requirements for renewable energy. Overbuilding of distributed energy systems in these states or legislative changes reducing renewable portfolio standards or alternative compliance payment requirements could negatively impact the price of solar RECs that AltaGas sells and the value of the solar RECs that AltaGas holds in its portfolio. In addition, AltaGas’ investment strategy to own and operate energy assets and sell energy to customers is based on the investment tax credit provision in the U.S. federal tax code, which allowed AltaGas to reduce its tax burden by investing in renewable and alternative energy assets, such as distributed energy, ductless heat pumps and fuel cells. AltaGas’ ability to benefit from the investment tax credit is based on certain assumptions about the level of AltaGas’ income taxes.

Impact of Competition in AltaGas’ Midstream and Power businesses

AltaGas faces strong competition in its Retail Energy Marketing business. It competes with other non-regulated retail suppliers of natural gas and electricity, as well as with the commodity rate offerings of electric and gas utilities. Increases in competition, including utility commodity rate offers that are below prevailing market rates, may result in a loss of sales volumes or a reduction in growth opportunities. AltaGas’ Midstream business competes with other midstream infrastructure and energy services companies, wholesale energy suppliers and other non-utility affiliates of regulated utilities to acquire natural gas storage and transportation assets. AltaGas’ Power business faces many competitors in the commercial energy systems business, including, for government customers, companies that contract with customers under Energy Savings Performance Contracting (ESPC) and other utilities providing services under Utility Energy Saving Contracts (UESC) and, in the renewable energy and distributed generation market, other developers, tax equity investors, distributed generation asset owner firms and lending institutions. These competitors may have diversified energy platforms with multiple marketing approaches; broader geographic coverage, greater access to credit and other financial resources, or lower cost structures, and may make strategic acquisitions or establish alliances among themselves. There can be no assurances that AltaGas can compete successfully, and its failure to do so could have an adverse impact on AltaGas’ results of operations and cash flow.

Compliance with Section 404(a) of Sarbanes-Oxley Act

Beginning in 2019, the Corporation’s internal control over financial reporting are required to be in compliance with the requirements of Section 404(a) of Sarbanes-Oxley, and the related rules of the Securities Exchange Commission and the Public Company Accounting Oversight Board. AltaGas’ failure to satisfy the requirements of Section 404(a) on an ongoing basis, or any failure of its internal controls could adversely affect investor confidence, cause reputational damage and expose AltaGas to monetary penalties. Any such effects of non-compliance could have an adverse effect on AltaGas’ results of operations, financial conditions and cash flows.

Delays in U.S. Federal Government Budget Appropriations

The Energy Efficiency and Energy Management operations of AltaGas’ Power business are sensitive to U.S. federal government agencies’ receipt of funding in a timely manner. A portion of the Power business’ revenues is derived from implementing projects related to energy efficiency and energy conservation measures for federal government agencies in the Washington D.C. metropolitan area. A delay in funding for these federal agencies directly impacts completion of ongoing projects and may harm AltaGas’ ability to obtain new contracts, which may negatively impact earnings.

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Biomass Supply Risk

Adequate supplies of biomass fuel may not be available to satisfy committed obligations as a result of any or all of economic events, natural occurrences or failure of a counterparty to perform under a supply contract. This could adversely affect AltaGas’ business operations and financial results.

ENVIRONMENTAL AND SAFETY POLICIES AND SOCIAL RESPONSIBILITY

Values

AltaGas operates in a safe, reliable manner and maintains positive relationships with its customers and stakeholders in the communities in which it operates, which includes, without limitation, building mutually beneficial working relationships with Indigenous peoples and working closely with governments and regulatory agencies to help meet long term project success.

Safety and environmental stewardship are core values at AltaGas and integral to how AltaGas operates. AltaGas operates all aspects of its business with the highest regard for the safety of its employees, contractors, and others impacted by AltaGas’ operations. AltaGas employees throughout Canada and the United States are responsible for exhibiting safe behaviors and for encouraging the same behaviors in others.

EH&S Committee

The Board of Directors has established the EH&S Committee to review, monitor and make recommendations to the Board of Directors regarding the environment, health and safety policies, practices and procedures of AltaGas and its affiliates.

Policies and Procedures

AltaGas has a number of policies, procedures and practices in place with respect to environmental stewardship, safety and social responsibility. Notably, AltaGas’ Code of Business Ethics, which applies to directors, officers, employees, contractors, consultants, representatives and agents of AltaGas, sets out fundamental principles to guide such individuals, and includes AltaGas’ commitment to environmental responsibility and providing a safe and healthy work environment.

Protecting the environment and minimizing impact are critical for AltaGas to maintain a sustainable business. To help ensure the responsibility and accountability for environmental protection, AltaGas educates all such individuals in environmental safeguarding to ensure those working on AltaGas’ behalf are made aware of their responsibilities. By maintaining an emergency response system and regularly conducting emergency response exercises, AltaGas is prepared to respond and minimize environmental impact if an incident were to occur. Best management practices are employed across all AltaGas businesses to assure compliance with regulatory requirements.

AltaGas’ EHS Management System provides a framework to ensure that safety and environmental performance across the enterprise are effectively monitored and continually improves. The EHS Management System elements, which are modelled after the ISO 14001 and OHSAS 18001 standards, establishes the minimum criteria and components each business must follow. The EHS Management System outlines various actions and accountabilities, all of which flow into a Plan-Do-Check-Act cycle, forming the basis for continual improvement.

ENVIRONMENTAL REGULATION

AltaGas faces uncertainties related to future environmental laws and regulations affecting its business and operations. Existing environmental laws and regulations may be revised or interpreted more strictly, and new laws or regulations may be adopted or become applicable to AltaGas, which may result in increased compliance costs or additional operating restrictions, each of which could reduce AltaGas’ earnings and adversely affect AltaGas’ business.

The natural gas industry, utility industry and the power generation industry are subject to environmental regulation pursuant to local, provincial, state, territorial and federal legislation. Environmental legislation places restrictions and prohibitions on various substances discharged to the air, land, and water in association with certain natural gas and power

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industry operations, as well as restrictions on land and water use in association with certain operations. AltaGas’ operations are required to obtain and comply with a variety of environmental licenses, permits, approvals, and registrations. In addition to the license and permit requirements, provincial, state, territorial and federal legislation may require that end of life assets be abandoned, remediated, and reclaimed to the satisfaction of provincial, state or territorial authorities. Failure to comply with applicable environmental legislation can result in civil or criminal penalties, environmental contamination clean-up requirements, and government orders affecting future operations. It is possible that increasingly strict environmental laws, regulations and enforcement policies, and potential claims for damages and injuries to property, employees, other persons and the environment resulting from current or discontinued operations, could result in substantial costs and liabilities in the future. Environmental risks from AltaGas’ operations can typically include, but is not limited to: air emissions, such as sulphur dioxide, nitrogen oxides, particulate matter and greenhouse gases; potential impacts on land; the use, storage or release of chemicals or hydrocarbons; the generation, handling and disposal of wastes and hazardous wastes; and water impacts. AltaGas assesses its environmental risk on an ongoing basis and strategically manages its liabilities portfolio to meet jurisdictional requirements while reducing risk exposure. AltaGas may also be subject to opposition from special interest groups resulting in regulatory process delays, which can impact schedules and increase cost.

Please also refer to the “Risk Factors — External Stakeholder Relations”, “Risk Factors — Regulatory”, “Risk Factors — Climate Change and Carbon Tax”, and “Risk Factors — Decommissioning, Abandonment and Reclamation Costs” sections of this AIF.

CLIMATE CHANGE

Changes in laws and regulations relating to GHG emissions could require AltaGas, in addition to complying with monitoring and reporting requirements applicable to its operations, to do one or more of the following: (i) comply with stricter emissions standards for internal combustion engines; (ii) take additional steps to control transmission and distribution system leaks; (iii) retrofit existing equipment with pollution controls or replace such equipment; or (iv) reduce AltaGas’ GHG emissions or, depending on the requirements enacted, acquire emissions offsets, credits or allowances or pay taxes on the emissions emitted in connection with its operations. AltaGas’ business could also be indirectly impacted by laws and regulations that affect its customers or suppliers to the extent such changes result in reductions in the use of natural gas by its customers or limit the operations of, or increase the costs of goods and services acquired from AltaGas suppliers.

Certain climate change regulations specific to AltaGas’ business segments are discussed under the sections “Business of the Corporation — Midstream Business — Environmental Regulations Impacting the Midstream Business”, “Business of the Corporation — Power Business — Environmental Regulations Impacting the Power Business”, and “Business of the Corporation — Utilities Business — Environmental Regulations Impacting the Utilities Business” of this AIF.

Canadian Federal Air and GHG Regulations

Multi-Sector Air Pollutants Regulations

The Multi-Sector Air Pollutants Regulations, promulgated under the Canadian Environmental Protection Act, 1999 (the Canadian EPA), was passed on June 17, 2016. The regulation requires owners and operators of specific industrial facilities and equipment types to meet consistent performance standards across the country. The objectives of the regulations are to limit the amount of nitrogen oxides (NOx) emitted from modern (new) and pre-existing (existing), gaseous-fuel-fired non-utility boilers and heaters used in many industrial facilities.

Certain provisions of the Multi-Sector Air Pollutants Regulations came into effect on July 1, 2017, requiring registration and compliance reporting for modern engines. Compliance obligations for pre-existing engines will be introduced in 2019 that will include NOx limits, NOx testing and oxygen (O2) measurements, specified maintenance/operational requirements, and annual reporting and record keeping. Regulated entities will be subject to enforcement and compliance requirements and penalties as specified under the Canadian EPA.

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AltaGas is currently focused on evaluating and implementing emissions reductions opportunities to reduce Nitrogen Oxides (NOx) emission associated with its Engine, Heater, and Boiler fleet. Through a combination of engine modifications, implementation of technology and or changes in operating parameters, AltaGas will achieve a yearly fleet average compliance target of 8g/kWh by 2021.

Federal Carbon Pricing

On December 9, 2016, the Government of Canada formally announced the Pan-Canadian Framework on Clean Growth and Climate Change. As a result, on June 21, 2018 the federal government enacted the Greenhouse Gas Pollution Pricing Act to implement a carbon pollution pricing system that will take effect beginning in 2019, to be applied in provinces and territories that do not have a carbon pricing system that aligns with the federal benchmark. Currently, those provinces and territories are listed in Schedule 2 of the Greenhouse Gas Pollution Pricing Act, and include Ontario, New Brunswick, Manitoba, Prince Edward Island, Saskatchewan, Yukon and Nunavut. The federal government has also proposed regulations setting out requirements for the production of emissions information under the Greenhouse Gas Pollution Pricing Act.

The federal carbon pollution pricing scheme is composed of two elements, both of which may impact AltaGas’ business:

·A carbon levy applied to fossil fuels set at $20 per tonne of carbon emitted, increasing to $50 per tonne in 2022; and

·An output based pricing system for industrial facilities that emit 50,000 tonnes of carbon dioxide equivalent (CO2e) per year or more, with an opt-in capability for smaller facilities with emissions below the threshold.

The output based pricing system applies to all industrial facilities that emit 50,000 tonnes or more of CO2e per year. The output based pricing system will apply to emissions from fuel combustion as well as emissions of synthetically produced GHG’s from industrial processes and products. As of December 31, 2018, AltaGas has three processing facilities that would exceed the 50,000 tonnes of CO2e per year threshold. Two facilities in Alberta and one facility in British Columbia that exceeds the threshold will continue to be regulated by the carbon pricing and reporting systems within those provinces. The carbon pricing scheme in both Alberta and British Columbia are expected to meet equivalency requirements to the federal benchmark.

The output-based pricing system came into effect on January 1, 2019. The carbon levy for provinces that do not meet equivalency requirements is expected to take effect in April 2019.

The impact of a federal carbon pricing structure is expected to be varied across AltaGas’ business segments as the pricing structure catches up with provincial carbon pricing models already in place. The immediate carbon tax impact on AltaGas will mainly impact AltaGas’ Midstream segment.

Federal Greenhouse Gas Reporting Programme (GHGRP)

Environment and Climate Change Canada reduced the reporting threshold for the GHGRP reports for the 2017 operating year. Under this rule the GHGRP will apply to a wider range of GHG emitting operations in Canada. The reporting threshold for industrial facilities will be reduced from 50,000 tonnes CO2e to 10,000 tonnes CO2e.

As of June 1, 2018, ten Midstream segment facilities reported to the GHGRP as a result of the lower reporting threshold.

Canadian Provincial GHG Regulations

For a discussion of the GHG regulations and further discussion of federal and provincial environmental regulations, please see “Business of the Corporation — Midstream Business — Environmental Considerations Impacting the Midstream Business” and “Business of the Corporation — Power Business — Environmental Considerations Impacting the Power Business.”

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British Columbia (B.C.)

Carbon Tax Act

B.C.’s carbon tax is currently set at $35 per tonne of CO2e emissions. In September 2017, the B.C. government announced in its budget update that starting on April 1, 2018, carbon tax rates will increase annually by $5 per tonne of CO2e emissions until rates equal to $50 per tonne in 2021. With these increases, B.C. will exceed the carbon pricing requirements expected in the Pan-Canadian Framework.

Effective Date	BC Carbon Tax Rate ($/tonne CO2e)
Prior to 2018	$	30
April 1, 2018	$	35
April 1, 2019	$	40
April 1, 2020	$	45
April 1, 2021	$	50

AltaGas’ operating facilities in B.C. operate under and comply with requirements set forth by the Carbon Tax Act of B.C.

British Columbia Clean BC Plan

The British Columbia government unveiled the Clean BC Plan in December 2018. The plan identifies key areas where British Columbia can take action to reduce greenhouse gas emissions. Highlights from the plan include, without limitation:

·Strengthening the low carbon fuel standard to a 20 percent reduction in fuel carbon intensity by 2030;

·Supporting ramp up of new renewable fuel production to 650 million liters by 2030;

·Zero-Emission Vehicles to make up 10 percent of new light duty vehicle sales in 2025, 30 percent in 2030, and 100 percent in 2040;

·15 percent minimum renewable content in industrial natural gas consumption, and cleaner industrial operations through electrification, CO2 carbon capture and storage, and reducing methane emissions by 45 percent; and,

·Improved energy efficiency in buildings

AltaGas is actively monitoring developments of the plan to assess how it will impact AltaGas’ businesses in the province.

U.S. Federal Air and GHG Regulations

Greenhouse Gas Reporting Program (US GHGRP)

The US GHGRP requires reporting of GHG data and other relevant information from large GHG emission sources, fuel and industrial gas suppliers, and CO2 injection sites in the United States. A total of 41 categories of reporters are covered by the US GHGRP. Facilities determine whether they are required to report based on the types of industrial operations located at the facility, their emission levels, or other factors. Facilities are generally required to submit annual reports under Part 98 if:

·GHG emissions from covered sources exceed 25,000 metric tons CO2e per year.

·Supply of certain products would result in over 25,000 metric tons CO2e of GHG emissions if those products were released, combusted, or oxidized.

·The facility receives 25,000 metric tons or more of CO2 for underground injection.

All of AltaGas’ operating facilities and certain of its utilities located in the U.S. operate under and comply with requirements set forth by the US GHGRP.

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For further discussion of the U.S. federal and state air emission regulations, please see “Business of the Corporation — Power Business — Environmental Considerations Impacting the Power Business”.

STAKEHOLDER ENGAGEMENT AND INDIGENOUS PEOPLES POLICY

AltaGas works to build long-term collaborative relationships that are based on trust, the willingness to listen and learn, and the desire to involve Indigenous peoples meaningfully in every phase of its developments. AltaGas’ approach is underscored by principles that help to enable strong relationships, including:

·Open and honest communication throughout all aspects of a project.

·A willingness to integrate Indigenous teachings and knowledge to help inform AltaGas’ environmental actions and community solutions as part of the project planning and development.

·A desire to engage with as many community members as possible, and

·A desire to educate, train and build capacity so that Indigenous peoples may participate in the planning, construction and operations of a project.

AltaGas is committed to building long term, mutually beneficial working relationships with Indigenous peoples while recognizing and respecting individual values and traditions. AltaGas is committed to developing these relationships on a foundation of respect for the languages, customs, and political, social and cultural institutions of Indigenous peoples.

AltaGas’ Indigenous Peoples Policy directs mutually beneficial relations with Indigenous communities affected by the Corporation’s operations. It provides direction and a means to clarify how the Corporation will interact with Indigenous communities. It also sets standards for employees and contractors to interact with Indigenous representatives, and ensures a consistent approach for all projects. AltaGas’ policy identifies guiding principles for Indigenous peoples in order to achieve these goals. These guiding principles include:

·Respect for legal rights, cultural values and traditional land use;

·Recognition of the distinct needs of different Indigenous peoples with unique languages, cultures, priorities and protocols and the need to research project-specific issues;

·Acknowledgment that all communities are different. A distinct community specific approach will need to be adopted for consultation and accommodation based on the impact of each project;

·Open dialogue through communication and consultation;

·AltaGas employee education and training on Indigenous Peoples Policy; and

·Community development and partnerships.

This policy promotes the understanding of, and sensitivity to Indigenous peoples and the issues important to them based on the concerns they raise.

DIVIDENDS

Dividends are declared at the discretion of the Board of Directors and dividend levels are reviewed periodically by the Board of Directors, giving consideration to the ongoing sustainable cash flow as impacted by the consolidated net income, maintenance and growth capital and debt repayment requirements of AltaGas. The Corporation targets to pay a portion of its ongoing cash flow through regular monthly dividends made to Shareholders.

AltaGas currently pays cash dividends on the Common Shares on or about the 15th day of each month or, if that date is not a business day, then the following business day to Shareholders of record on the 25th day of the previous month, or if that day is not a business day the following business day. Dividends on the Series A Shares, Series B Shares, Series C Shares, Series E Shares, Series G Shares, Series I Shares, and Series K Shares are paid quarterly.

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AltaGas’ payment of dividends may be limited by covenants under its credit agreements, including, without limitation, in circumstances when a default or event of default exists or would be reasonably expected to exist upon or as a result of making such dividend payment. In the event of liquidation, dissolution or winding-up of AltaGas, the preferred shareholders have priority in the payment of dividends over the common shareholders.

In December 2018, AltaGas’ Board of Directors approved a dividend reset to $0.08 per Common Share effective for the January 2019 dividend.

The table below shows the cash dividends paid by AltaGas on Common Shares and Preferred Shares for the three most recently completed financial years and the cash dividends paid by Washington Gas on Washington Gas Preferred Shares for the most recently completed financial year.

$ per share	2018	2017	2016
Common Shares	2.190000	2.107500	2.020000
Series A Shares	0.845000	0.845000	0.845000
Series B Shares	0.968620	0.806380	0.786920
Series C Shares(1)	1.322500	1.155625	1.100000
Series E Shares	1.250000	1.250000	1.250000
Series G Shares	1.187500	1.187500	1.187500
Series I Shares	1.312500	1.312500	1.448245
Series K Shares	1.250000	1.063400	—
Washington Gas $4.25 Series (1)	2.125000	—	—
Washington Gas $4.80 Series (1)	2.400000	—	—
Washington Gas $5.00 Series (1)	2.500000	—	—

Note:

(1)Amounts disclosed are in U.S. dollars.

PREMIUM DIVIDENDTM, DIVIDEND REINVESTMENT AND OPTIONAL CASH PURCHASE PLAN

Effective May 17, 2016, AltaGas replaced in its entirety, its dividend reinvestment plan with the Premium DividendTM, Dividend Reinvestment and Optional Cash Purchase Plan (the Plan). The Plan consists of three components: a Premium Dividend™ component, a Dividend Reinvestment component and an Optional Cash Payment component.

The Plan provides eligible holders of Common Shares with the opportunity to, at their election, either: (1) reinvest the cash dividends paid by AltaGas on their Common Shares towards the purchase of new Common Shares at a 3 percent discount to the average market price (as defined below) of the Common Shares on the applicable dividend payment date (the Dividend Reinvestment component of the Plan); or (2) reinvest the cash dividends paid by AltaGas on their Common Shares towards the purchase of new Common Shares at a 3 percent discount to the average market price (as defined below) on the applicable dividend payment date and have these additional Common Shares of AltaGas exchanged for a cash payment equal to 101 percent of the reinvested amount (the Premium Dividend™ component of the Plan).

In addition, the Plan provides Shareholders who are enrolled in the Dividend Reinvestment component of the Plan with the opportunity to purchase new Common Shares at the average market price (with no discount) on the applicable dividend payment date (the Optional Cash Payment component of the Plan).

Each of the components of the Plan is subject to prorating and other limitations on availability of new Common Shares in certain events. The “average market price”, in respect of a particular dividend payment date, refers to the arithmetic average (calculated to four decimal places) of the daily volume weighted average trading prices of Common Shares on the TSX for the trading days on which at least one board lot of Common Shares is traded during the 10 business days immediately preceding the applicable dividend payment date. Such trading prices will be appropriately adjusted for certain capital changes (including, without limitation, common share subdivisions, common share consolidations, certain rights

TM Denotes trademark of Canaccord Genuity Corp.

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offerings and certain dividends). Shareholders resident outside of Canada are not entitled to participate in the Premium DividendTM component of the Plan. Shareholders resident outside of Canada (other than the U.S.) may participate in the Dividend Reinvestment component or the Optional Cash Payment Component of the Plan only if their participation is permitted by the laws of the jurisdiction in which they reside and provided that AltaGas is satisfied, in its sole discretion, that such laws do not subject the Plan or AltaGas to additional legal or regulatory requirements.

On October 29, 2018, AltaGas’ Board of Directors suspended, until further notice, the Premium component of the Dividend Reinvestment Plan (PDRIP), effective December 18, 2018. Accordingly, the dividend payable on December 17, 2018 was the last dividend included in the PDRIP. The other components of the Dividend Reinvestment Plan remained unchanged.

MARKET FOR SECURITIES

The following chart provides the reported high and low trading prices and volume of Common Shares, traded on the TSX under the symbol ALA, traded by month from January to December 2018 as reported by the TSX:

Month	High	Low	Volume Traded
January	29.34	27.43	12,434,525
February	27.81	25.42	12,251,092
March	26.34	22.82	19,040,696
April	25.88	23.21	10,418,648
May	26.18	24.37	12,646,849
June	27.29	24.80	15,650,995
July	28.45	26.18	31,832,148
August	26.62	24.14	16,529,098
September	25.33	20.27	41,501,937
October	22.10	15.70	44,264,368
November	16.75	13.75	48,422,553
December	15.93	11.87	45,333,990

The Subscription Receipts commenced trading on the TSX under the symbol ALA.R, on February 3, 2017 and ceased trading following the closing of the WGL Acquisition on July 6, 2018. The following table sets forth the monthly price range and volume traded for Subscription Receipts for the period of January to July 6, 2018 as reported by the TSX:

Month	High	Low	Volume Traded
January	29.16	27.55	2,310,566
February	27.99	25.82	1,847,773
March	26.60	24.57	2,473,014
April	26.66	24.25	1,427,589
May	26.67	24.39	1,949,004
June	27.23	24.77	2,340,080
July	27.86	27.17	482,467

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Series A Shares are traded on the TSX under the symbol ALA.PR.A. The following table sets forth the monthly price range and volume traded for Series A Shares from January to December 2018 as reported by the TSX:

Month	High	Low	Volume Traded
January	22.85	22.60	55,847
February	22.50	22.43	99,632
March	22.05	21.94	87,255
April	21.27	21.25	30,200
May	21.50	21.45	166,432
June	21.30	21.25	42,761
July	21.55	21.49	58,500
August	21.70	21.63	45,327
September	21.82	21.80	187,684
October	20.76	20.57	107,399
November	18.34	18.06	181,912
December	15.16	14.33	264,792

Series B Shares are traded on the TSX under the symbol ALA.PR.B. The following table sets forth the monthly price range and volume traded for Series B Shares for the period from January to December 2018 as reported by the TSX:

Month	High	Low	Volume Traded
January	22.96	21.24	9,824
February	22.70	21.90	9,755
March	22.10	21.19	154,754
April	21.35	19.90	17,900
May	21.55	20.12	47,082
June	21.45	20.85	27,850
July	21.94	21.10	19,682
August	22.12	21.75	68,491
September	22.28	20.30	53,700
October	20.90	18.02	50,250
November	18.71	14.94	67,717
December	15.25	13.26	92,007

Series C Shares are traded on the TSX under the symbol ALA.PR.U. The following table sets forth the monthly price range (in US dollars) and volume traded for Series C Shares from January to December 2018 as reported by the TSX:

Month	High	Low	Volume Traded
January	25.98	25.62	110,598
February	25.85	25.32	185,254
March	25.70	24.60	259,251
April	25.25	24.80	161,780
May	25.50	25.01	136,775
June	25.28	24.90	112,145
July	25.31	24.90	67,275
August	25.32	25.01	81,184
September	25.25	23.50	138,903
October	23.74	20.30	258,151
November	21.50	18.17	188,681
December	18.73	16.01	466,406

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Series E Shares are traded on the TSX under the symbol ALA.PR.E. The following table sets forth the monthly price range and volume traded for Series E Shares from January to December 2018 as reported by the TSX:

Month	High	Low	Volume Traded
January	25.71	24.75	92,237
February	25.23	24.01	194,465
March	24.87	24.21	87,062
April	24.48	23.24	249,032
May	24.56	23.45	160,575
June	24.20	23.48	58,460
July	24.33	23.46	50,947
August	24.57	24.18	53,742
September	24.95	22.85	85,165
October	23.36	20.46	109,837
November	21.25	17.40	227,462
December	18.51	16.38	348,728

Series G Shares are traded on the TSX under the symbol ALA.PR.G. The following table sets forth the monthly price range and volume traded for Series G Shares from January to December 2018 as reported by the TSX:

Month	High	Low	Volume Traded
January	25.36	24.39	76,173
February	25.17	24.05	55,369
March	24.62	23.85	35,146
April	24.40	22.86	43,596
May	24.37	23.23	70,870
June	24.06	23.15	19,560
July	24.05	23.23	416,653
August	24.17	23.75	121,118
September	24.19	22.29	103,360
October	23.14	19.48	65,737
November	20.31	16.08	108,386
December	17.29	14.71	155,255

Series I Shares are traded on the TSX under the symbol ALA.PR.I. The following table sets forth the monthly price range and volume traded for Series I Shares for the period of January to December 2018 as reported by the TSX:

Month	High	Low	Volume Traded
January	26.13	25.55	109,994
February	26.13	25.46	55,131
March	26.14	25.45	237,699
April	25.62	25.09	503,716
May	25.76	25.24	116,837
June	25.69	25.05	131,225
July	25.90	25.25	286,078
August	25.95	25.60	49,180
September	25.93	24.69	151,966
October	25.38	23.38	286,038
November	24.28	20.01	192,476
December	21.07	19.08	814,700

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Series K Shares are traded on the TSX under the symbol ALA.PR.K. The following table sets forth the monthly price range and volume traded for Series K Shares for the period of January to December 2018 as reported by the TSX:

Month	High	Low	Volume Traded
January	25.90	25.32	637,227
February	25.76	25.01	385,855
March	25.59	25.04	109,230
April	25.31	24.74	516,555
May	25.45	25.02	72,031
June	25.35	24.96	46,522
July	25.40	25.09	107,068
August	25.53	25.04	99,182
September	25.47	24.01	122,747
October	24.57	22.00	289,419
November	22.90	18.30	418,826
December	19.00	16.25	603,704

CREDIT RATINGS

Credit ratings are intended to provide investors with an independent measure of credit quality of an issue of securities and are indicators of the likelihood of payment and of the capacity and willingness of a company to meet its financial commitment on an obligation in accordance with the terms of an obligation. This information concerning AltaGas’ credit ratings relates to AltaGas’ financing costs, liquidity and operations. The availability of AltaGas’ funding options may be affected by certain factors, including the global capital markets environment and outlook as well as AltaGas’ financial performance. AltaGas’ access to capital markets at competitive rates is influenced by AltaGas’ credit rating and rating outlook, as determined by credit rating agencies such as S&P, DBRS and Fitch, and if AltaGas’ ratings were downgraded, AltaGas’ financing costs and future debt issuances could be unfavorably impacted.

S&P, DBRS and Fitch are rating agencies that provide credit ratings. These rating agencies’ ratings for debt instruments range from a high of AAA to a low of D. All three rating agencies also provide credit ratings for preferred shares. S&P ratings for preferred shares range from a high of P-1 to a low of D. DBRS ratings for preferred shares range from a high of Pfd-1 to a low of D. Fitch ratings for preferred shares range from a high of AAA to a low of D.

On December 19, 2018, S&P downgraded AltaGas’ issuer rating and senior unsecured MTN rating from BBB with a Negative Outlook to BBB- with a Negative Outlook. On December 21, 2018, DBRS downgraded the rating from BBB Under Review with Developing Implications to BBB(low) with a Stable Outlook. On July 27, 2018, Fitch assigned a first-time rating of BBB to AltaGas and on December 17, 2018 affirmed the BBB rating.

According to the S&P rating system, an obligor rated BBB has adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitments. The ratings from AA to CCC may be modified by the addition of a plus (+) or minus (-) sign to show relative standing within the major rating categories.

According to the DBRS rating system, debt securities rated BBB are of adequate credit quality. The capacity for the payment of financial obligations is considered acceptable, but may be vulnerable to future events. “High” or “Low” grades are used to indicate the relative standing within a particular rating category.

According to the Fitch rating system, ‘BBB’ ratings indicate that expectations of default risk are currently low. The capacity for payment of financial commitments is considered adequate, but adverse business or economic conditions are more likely to impair this capacity.

On August 10, 2010, S&P and DBRS commenced rating of AltaGas’ Preferred Shares with an S&P rating of P-3 (High) and DBRS rating of Pfd-3. On December 19, 2018 S&P downgraded AltaGas’ Preferred Shares from P-3 (High) to P-3.

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On December 21, 2018, DBRS downgraded AltaGas’ Preferred Shares from Pfd-3 to Pfd-3(low). On July 27, 2018, Fitch assigned a first-time rating of BB+ to AltaGas’ Preferred Shares and affirmed the rating of BB+ on December 17, 2018.

A P-3 rating by S&P is the third highest of eight categories granted by S&P under its Canadian preferred share rating scale and a P-3 rating directly corresponds with a BB rating under its global preferred rating scale. The Canadian preferred share rating scale is fully determined by the global preferred rating scale and there are no additional analytical criteria associated with the determination of ratings on the Canadian preferred share rating scale. According to the S&P rating system, while securities rated P-3 are regarded as having significant speculative characteristics, they are less vulnerable to non-payment than other speculative issues. However, it faces major ongoing uncertainties or exposure to adverse business, financial, or economic conditions which could lead to the obligor’s inadequate capacity to meet its financial commitment on the obligation. The ratings from P-1 to P-5 may be modified by “high” and “low” grades which indicate relative standing within the major rating categories.

A Pfd-3 rating by DBRS is the third highest of six categories granted by DBRS. According to the DBRS rating system, preferred shares rated Pfd-3 are of adequate credit quality. While protection of dividends and principal is still considered acceptable, the issuing entity is more susceptible to adverse changes in financial and economic conditions, and there may be other adversities present which detract from debt protection. Pfd-3 ratings normally correspond with companies whose bonds are rated in the higher end of the BBB category. “High” or “Low” grades are used to indicate the relative standing within a rating category. The absence of either a “High” or “Low” designation indicates the rating is in the middle of the category. A ‘BB’ rating by Fitch indicates an elevated vulnerability to default risk, particularly in the event of adverse changes in business or economic conditions over time; however, business or financial flexibility exists that support the servicing of financial commitments.

The credit ratings accorded to the securities by the rating agencies are not recommendations to purchase, hold, or sell the securities in as much as such ratings do not comment as to market price or suitability for a particular investor. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a rating agency in the future if, in its judgment, circumstances so warrant.

Except as set forth above, none of S&P, DBRS nor Fitch has announced that it is reviewing or intends to revise or withdraw the ratings on AltaGas.

AltaGas provides an annual fee to S&P, DBRS and Fitch for credit rating services. AltaGas has paid each of S&P, DBRS and Fitch their respective fees in connection with the provision of the above ratings. Over the past two years, in addition to the aforementioned fees, AltaGas has made payments in respect of certain other services provided to the Corporation by S&P, DBRS and Fitch.

MATERIAL CONTRACTS

Except for contracts entered into in the ordinary course of business, the only material contracts entered into by AltaGas within the most recently completed financial year, or before the most recently completed financial year but which are still material and are still in effect, are the following:

·The US$1.2 billion Extendible Revolving Term Credit Facility Credit Agreement dated December 28, 2018. This is an unsecured extendible revolving credit facility with Royal Bank of Canada, Bank of Montreal, The Toronto-Dominion Bank, The Bank of Nova Scotia, Canadian Imperial Bank of Commerce, JPMorgan Chase Bank, N.A., National Bank of Canada, Bank of America, N.A., Canada Branch, MUFG Bank, Ltd., Canada Branch, ATB Financial, Fédération des caisses Desjardins du Québec, and HSBC Bank Canada and their respective affiliates maturing on December 18, 2021. Borrowings on the facility can be by way of prime loans, U.S. base rate loans, or LIBOR loans. Borrowings on the facility bear fees and interest at rates relevant to the nature of the draw made;

·The Purchase and Sale Agreement between AltaGas Ltd., Northwest Hydro Limited Partnership, Northwest Hydro GP Inc., Northwestern Hydro Acquisition Co II LP and Northwestern Hydro Acquisition Co III LP dated December 12, 2018 in connection with AltaGas’ sale of its remaining 55% interest in the Northwest Hydro Facilities;

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·The Bridge Facility, being the US$3,013,537,853 Term Credit Facility among AltaGas Ltd. and AltaGas Services (U.S.) Inc., as borrowers, and certain financial institutions, as lenders, JPMorgan Chase Bank, N.A., as agent, and JPMorgan Chase Bank, N.A., TD Securities and RBC Capital Markets, as co-lead arrangers and joint bookrunners. AltaGas drew on the Bridge Facility in connection with the financing of the Acquisition of WGL Holdings, Inc. on July 6, 2018. The majority of the Bridge Facility was repaid in December 2018 with a remaining balance of approximately US$83 million as of December 31, 2018;

·The Contribution and Purchase Agreement between AltaGas Ltd., Northwest Hydro Limited Partnership, Northwest Hydro GP Inc. and Northwestern Hydro Acquisition Co Inc., dated June 12, 2018 in connection with AltaGas’ sale of a 35% interest in its Northwest Hydro Facilities;

·Agreement and plan of merger dated as of January 25, 2017, among AltaGas, Merger Sub (Wrangler Inc.) and WGL;

·The trust indenture between AltaGas and Computershare Trust Company of Canada dated July 1, 2010, as supplemented, related to the issuance and sale of MTNs pursuant to AltaGas’ medium term note program; and

·The trust indenture between AltaGas and Computershare Trust Company of Canada dated September 26, 2017, as supplemented, related to the issuance and sale of MTNs pursuant to AltaGas’ medium term note program.

Copies of each of these documents have been filed on SEDAR at www.sedar.com.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

AltaGas is not aware of any material interest, direct or indirect, of any director or officer of AltaGas, any director or officer of a corporation that is an insider or subsidiary of AltaGas, or any other insider of AltaGas, or any associate or affiliate of any such person, in any transaction since the commencement of AltaGas’ last three completed financial years, or in any proposed transaction, that has materially affected or would materially affect AltaGas or any of its subsidiaries.

LEGAL PROCEEDINGS

Other than as set out below, AltaGas is not aware of any material legal proceedings to which the Corporation or its affiliates is a party or to which their property is subject during AltaGas’ most recently completed financial year and AltaGas is not aware of any such material legal proceedings being contemplated.

Antero Resources Corporation (Antero) has initiated suit against Washington Gas and WGL Midstream, claiming that they have failed to purchase specified daily quantities of gas and seeking alleged cover damages exceeding US$100 million as of April 4, 2018 according to Antero’s complaint. Washington Gas and WGL Midstream oppose both the validity and amount of Antero’s claim. WGL believes the probability that Antero could succeed in collecting these penalties is remote therefore no accrual was made as of December 31, 2018. Further information on this claim is set forward in the Corporation’s Management’s Discussion and Analysis (MD&A) dated February 27, 2019 as at and for the year ended December 31, 2018. See “Risk Factors — Litigation”.

REGULATORY ACTIONS

AltaGas is not aware of any (i) penalties or sanctions imposed against it by a court relating to securities legislation or by a securities regulatory authority during its most recently completed financial year, or (ii) other penalties or sanctions imposed by a court or regulatory body against it that would likely be considered important to a reasonable investor in making an investment decision. There were no settlement agreements entered into by AltaGas before a court relating to securities legislation or with a securities regulatory authority during AltaGas’ most recently completed financial year.

INTERESTS OF EXPERTS

The auditors of the Corporation are Ernst & Young LLP, Chartered Accountants, 2200 — 215 2nd Street SW, Calgary, Alberta T2P 1M4. Ernst & Young LLP is independent in accordance with the Rules of Professional Conduct as outlined by the Chartered Professional Accountants of Alberta.

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ADDITIONAL INFORMATION

Additional information, including, without limitation, directors’ and officers’ remuneration and indebtedness, principal holders of AltaGas’ securities, Share Options, and interests of insiders in material transactions, where applicable, is contained in AltaGas’ management information circular for AltaGas’ most recent annual meeting of Shareholders that involved the election of directors.

Additional financial information is contained in AltaGas’ audited consolidated financial statements as at and for the year ended December 31, 2018 and management’s discussion and analysis for the year ended December 31, 2018.

The Corporation routinely files all required documents through the SEDAR system and on its own website. Internet users may retrieve such material through the SEDAR website www.sedar.com. AltaGas’ website is located at www.altagas.ca, but AltaGas’ website is not incorporated by reference into this AIF.

TRANSFER AGENTS AND REGISTRARS

The registrar and transfer agent for the Common Shares and the Preferred Shares is Computershare Investor Services Inc., 600, 530 - 8th Avenue SW, Calgary, Alberta T2P 3S8, Tel: 1-800-564-6253.

The registrar and trustee for AltaGas’ MTNs is Computershare Trust Company of Canada, 600, 530 - 8th Avenue SW, Calgary, Alberta T2P 3S8, Tel: 1-800-564-6253.

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SCHEDULE A: AUDIT COMMITTEE MANDATE

CONSTITUTION

The Board of Directors (the “Board”) of AltaGas Ltd. (“AltaGas” or the “Corporation”) has established an Audit Committee (the “Committee”). The Committee shall be in compliance with the guidelines for corporate governance of the Toronto Stock Exchange (“TSX”), the U.S. Securities and Exchange Commission (“SEC”) and any other regulatory or legal authority having jurisdiction over AltaGas.

The Committee shall assist the Board with its oversight of: the quality and integrity of the Corporation’s financial statements, financial disclosure and internal controls over financial reporting; the Corporation’s compliance with relevant legal and regulatory requirements; the qualifications, independence and performance of the external auditor and internal auditor; certain policies of the Corporation; and other matters set out herein or delegated by the Board from time to time.

MEMBERSHIP

The Board shall elect from its members not less than three (3) Directors to serve on the Committee (the “Members”) and shall appoint one such Member as Chair of the Committee.

Every Member must be:

·independent (in accordance with National Instrument 52-110 — Audit Committees of the Canadian Securities Administrators (“NI 52-110”) and, if AltaGas is at such time an SEC Issuer, the rules of the SEC); and

·financially literate (in accordance with NI 52-110).

For so long as the Corporation has a class of securities registered under section 12 of the United States Securities Exchange Act of 1934 (the “1934 Act”) or is required to file reports under section 15(d) of the 1934 Act (at such time, an “SEC Issuer”), at least one Member shall be an “audit committee financial expert” as such term is defined under applicable SEC rules.

No Member shall be an officer or employee of AltaGas or any subsidiary or affiliate of AltaGas. Any Member may be removed or replaced at any time by the Board and shall cease to be a Member upon ceasing to be a Director of the Corporation.

Each Member shall hold office until the Member resigns or is replaced, whichever first occurs. Where a vacancy occurs at any time in the membership of the Audit Committee, it may be filled by the Board on the recommendation of the Governance Committee, provided that the proposed Member meets the above criteria (and, if applicable in the circumstances where the vacancy was in relation to the sole “audit committee financial expert”, the proposed Member is also an “audit committee financial expert”). Provided the Committee includes three Members, including an “audit committee financial expert” if required, it may continue to act in the event of a vacancy. When appointing a Member to the Committee, the Board shall take into consideration the number of other audit committees upon which the proposed Member sits.

The Corporate Secretary of AltaGas shall be secretary to the Committee unless the Committee directs otherwise.

MEETINGS

The Committee shall convene no less than four times per year at such times and places designated by its Chair or whenever a meeting is requested by a Member, the Board, or an officer of the Corporation. A minimum of twenty-four (24) hours’ notice of each meeting, plus a copy of the proposed agenda, shall be given to each Member. Members of management of the Corporation or any subsidiary or affiliate of the Corporation shall attend whenever requested to do so by a Member.

A meeting of the Committee shall be duly convened if a majority of Members are present. Where the Members consent, and proper notice has been given or waived, Members may participate in a meeting of the Committee by means of such telephonic, electronic or other communication facilities as permits all persons participating in the meeting to communicate

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adequately with each other, and a Member participating in such a meeting by any such means is deemed to be present at that meeting.

In the absence of the Chair of the Committee, the Members may choose one of the Members to be the chair of the meeting.

The external auditor will be given notice of and be provided the opportunity to attend every meeting of the Committee.

The Committee will hold in camera sessions without management present, including with internal and external auditors, as may be deemed appropriate by the Members.

Minutes shall be kept of all meetings of the Committee by the Corporate Secretary or designate of the Corporate Secretary.

DUTIES AND RESPONSIBILITIES OF THE CHAIR

The Chair of the Committee is responsible for:

1.providing leadership to the Committee and assisting the Committee in reviewing and monitoring its responsibilities;

2.duly convening Committee meetings and designating the times and places of those meetings;

3.working with Management, the Chair of the Board and Lead Director on the development of agendas;

4.reviewing material for Committee meetings prior to it being made available to Members;

5.ensuring Committee meetings are conducted in an efficient, effective and focused manner;

6.ensuring the Committee has sufficient information to permit it to properly make decisions when decisions are required;

7.advising the Committee of any finance, accounting or misappropriation matters brought to the Chair’s attention;

8.advising other Committee Chairs or the Chair of the Board of any matters which may affect the organization and influence the Board or Committee’s responsibilities; and

9.reporting to the Board on the activities, decisions and recommendations of the Committee after each meeting.

DUTIES AND RESPONSIBILITIES OF THE COMMITTEE

The Committee shall, as permitted by and in accordance with the requirements of the Canada Business Corporations Act, the Articles and By-Laws of the Corporation and any legal or regulatory authority having jurisdiction, periodically assess the adequacy of procedures for the public disclosure of financial information and review on behalf of the Board and report to the Board the results of its review and its recommendation regarding all material matters of a financial reporting and audit nature including, but not limited to, the following main subject areas:

1.oversight of external auditors, including:

a)appointment, compensation, retention and termination of external auditors, who shall report directly to the Committee, provided that the appointment of the auditor shall be subject to shareholder approval;

b)review and approval of the terms of the external auditors’ annual engagement letter, including the proposed audit fee;

c)regular discussions with external auditors in the absence of management on matters of interest, including matters that the external auditors recommend bringing to the attention of the Board;

d)at least annually, obtain and review reports of external auditors delineating all relationships between the external auditors and the Corporation required by applicable audit professional regulatory standards, discuss with the

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external auditors any relationships or services that may impact the objectivity and independence of the external auditors and determine external auditor independence;

e)review and pre-approve the audit plans (and any changes) of the external audit firm and all non-audit work undertaken by the external audit firm, ensuring that except in exceptional circumstances non-audit related fees represent less than half of the total fees billed by the external audit firm and ensuring that non-audit fees do not include charges for services that are either likely to impair the independence of the auditor or relate to tax services for senior executives of the Corporation;

f)resolution of any disagreements between management and the auditor regarding financial reporting;

g)assessment of the effectiveness and performance of the external audit firm;

h)review and approval of AltaGas’ hiring policies re: current and former partners and employees of the external audit firm; and

i)ensure management provides adequate funding to the Committee so that it may independently engage and remunerate the external auditor and any advisors.

2.oversight of internal auditors, including:

a)at least annually, review the internal audit plan, including the degree of coordination between such plan and the audit plans of the external auditor;

b)obtain and review reports periodically from the head of the internal audit function regarding the activities of the internal audit function, including any significant disagreements between internal auditors and management; and

c)discuss the responsibilities, budget and staffing of the Corporation’s internal audit function and review the performance of the internal audit function.

3.oversight of financial reporting, including

a)financial statements, including management’s discussion and analysis;

b)annual and interim press releases regarding financial results;

c)reports to shareholders and others;

d)filings to securities regulators;

e)public disclosure documents containing audited or unaudited financial information (for example, but not limited to, press releases, prospectuses, annual information form, management information circular);

f)review of the financial aspects of any transactions of the Corporation that involve related parties (other than wholly-owned subsidiaries); and

g)review of litigation, claims and contingencies in consultation with management and legal counsel as appropriate.

4.oversight of financial reporting processes and internal control over financial reporting and disclosure controls, including:

a)review of the adequacy and effectiveness of the accounting and internal control policies, including internal controls over financial reporting, of the Corporation and procedures through inquiry and discussions with the external auditors, management and the internal auditor, including about the extent to which the scope of the internal and external audit plans can be relied upon to detect weakness in internal control policies, fraud or other illegal acts;

b)review of the adequacy and effectiveness of the disclosure control policies and procedures of the Corporation;

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c)review of the effectiveness of procedures for the receipt, retention and resolution of complaints regarding accounting, internal accounting controls or auditing matters, and the confidential, anonymous submission by employees of concerns regarding questionable accounting, internal accounting controls, financial reporting or auditing matters and review and, as necessary, investigate, any reports alleging material violations of federal, provincial or state securities or any similar other law or a material breach of fiduciary duties by directors, officers, employees or agents of the Corporation arising under such laws; and

d)review and discuss with management and the independent auditor the certification and reports of management and the independent auditor required in the Corporation’s periodic SEC reports concerning the Corporation’s internal control over financial reporting and disclosure controls and procedures, the adequacy of such controls and any remedial steps being undertaken to address any material weaknesses or significant deficiencies in internal control over financial reporting.

5.oversight of finance matters, including:

a)review of analyses by management and the external auditor regarding significant financial reporting issues and judgments made in connection with the preparation of the Corporation’s consolidated financial statements;

b)review of Corporation’s policy on dividends;

c)review the issuance of equity or debt securities by the Corporation;

d)review and recommend for approval to the Board the management information circular with respect to matters related to the auditor or affecting the capital of the Corporation; and

e)review and recommend to the Human Resources and Compensation Committee, for further recommendation or approval, the calculations of financial metrics used in the determination of employee incentive compensation plans; monitor finance integration and financial risk management programs associated with major acquisitions.

6.oversight of risk management, including:

a)review of the Corporation’s major risks, a review of the method of risk analysis by the Corporation, review of the strategies, policies and practices in place for risk management; and

b)review of the Corporation’s cyber risk and data security, and insurance program.

7.oversight of policies applicable to the Committee’s mandate, and compliance therewith, including:

·Code of Business Ethics as it relates to the matters covered by this Mandate;

·Accounting and Auditing Irregularity Reporting Policy;

·Disclosure Policy;

·Commodity Risk Management Policy;

·Other policies that may be established from time to time relating to accounting, financial reporting, disclosure controls and procedures, internal controls over financial reporting and audits.

OTHER DUTIES

The Committee shall have the following other duties:

1.meet regularly with management to discuss areas of concern and coordinate its activities with the Chief Financial Officer;

2.review at least annually the succession planning in the accounting and finance groups;

3.meet separately with senior management, the internal auditors, the external auditors and, as is appropriate, internal and external legal counsel and independent advisors in respect of matters not elsewhere listed concerning any other audit, finance and risk matter;

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4.review at least annually the relevance and adequacy of this Mandate and provide recommendations to the Governance Committee of the Board; and

5.such other duties not mentioned herein but otherwise required pursuant to any applicable legal or regulatory authority.

OUTSIDE EXPERTS AND ADVISORS

The Committee is authorized, when deemed necessary or desirable, to engage independent counsel, outside experts and other advisors, at the Corporation’s expense, to advise the Committee on any matter.

RELIANCE

Absent actual knowledge to the contrary (which shall be promptly reported to the Board), each member of the Committee shall be entitled to rely on (i) the integrity of those persons or organizations within and outside the Corporation from which it receives information, (ii) the accuracy of the financial and other information provided to the Committee by such persons or organizations, and (iii) representations made by management and the external auditor, as to any information technology, internal audit and other non-audit services provided by the external auditor to the Corporation and its subsidiaries.

COMMITTEE TIMETABLE

The major activities of the Committee will be outlined in an annual schedule.

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AltaGas Ltd.

1700, 355 - 4th Avenue SW

Calgary, AB  T2P 0J1

Tel: 403-691-7575

Fax: 403-691-7576

www.altagas.ca

APPENDIX B

FINANCIAL STATEMENTS OF ALTAGAS LTD., INCLUDING MANAGEMENT’S REPORT TO

SHAREHOLDERS AND THE AUDITORS’ REPORTS

Management’s Responsibility for Consolidated Financial Statements

The Consolidated Financial Statements and Management’s Discussion and Analysis (MD&A) of AltaGas Ltd. (AltaGas or the Corporation) are the responsibility of Management and have been approved by the Board of Directors of the Corporation. The Consolidated Financial Statements have been prepared by Management in accordance with United States Generally Accepted Accounting Principles (U.S. GAAP) and include amounts that are based on Management’s best estimates and judgments.

Management is responsible for establishing and maintaining adequate internal controls over financial reporting (ICFR) for the Corporation. Management has designed and maintains a system of internal controls over financial reporting, including a program of internal audits to carry out its responsibility. Management believes these controls provide reasonable assurance that financial records are reliable and form a proper basis for the preparation of financial statements. Management undertakes communication to employees of policies that govern ethical business conduct. The Chief Executive Officer and Chief Financial Officer of AltaGas have limited the scope of the design of ICFR evaluation to exclude controls, policies, and procedures of all entities acquired in the WGL Acquisition that closed on July 6, 2018, as it has not been possible to conduct an assessment of WGL’s ICFR between such closing and the date of this report. This limitation of scope is in accordance with section 3.3(1)(b) of National Instrument 52-109 as well as relevant SEC guidance, which allows an issuer to limit its assessment of ICFR to exclude controls, policies and procedures of a business that the issuer acquired for a maximum period of 365 days from the end of the financial period in which the acquisition occurred. Summary financial information of WGL included in the audited Consolidated Financial Statements as at and for the year ended December 31, 2018, includes total assets of approximately $14 billion and revenues of approximately $1 billion.

The MD&A and Consolidated Financial Statements are approved by the Board of Directors after considering the recommendation of the Audit Committee. The Audit Committee of the Board of Directors is composed of independent non-management directors.

The Audit Committee meets with Management regularly and meets independently with internal and external auditors and as a group to review any significant accounting, internal controls and auditing matters in accordance with the terms of the Charter of the Audit Committee, which is set out in the Annual Information Form. The Audit Committee’s responsibilities include overseeing Management’s performance in carrying out its financial reporting responsibilities and reviewing the Consolidated Financial Statements and MD&A, before these documents are submitted to the Board of Directors for approval. The internal and independent external auditors have access to the Audit Committee without obtaining prior Management approval.

The Audit Committee approves the terms of engagement of the independent external auditors and reviews the annual audit plan, the Auditors’ Report and the results of the audit. It also recommends to the Board of Directors the firm of external auditors to be appointed by the shareholders.

The shareholders have appointed Ernst & Young LLP as independent external auditors to express an opinion as to whether the Consolidated Financial Statements present fairly, in all material respects, the Corporation’s consolidated financial position, results of operations and cash flows in accordance with U.S. GAAP. The report of Ernst & Young LLP outlines the scope of its examination and its opinion on the Consolidated Financial Statements.

(signed) “Randall Crawford”	(signed) “Tim Watson”
RANDALL CRAWFORD	TIM WATSON
President and	Executive Vice President and
Chief Executive Officer of	Chief Financial Officer of
AltaGas Ltd.	AltaGas Ltd.

February 27, 2019

AltaGas Ltd. – 2018

1

Report of Independent Registered Public Accounting Firm

To the Shareholders of AltaGas Ltd.

Opinion on the Consolidated Financial Statements

We have audited the accompanying Consolidated Financial Statements of AltaGas Ltd., which comprise the consolidated balance sheets as at December 31, 2018 and 2017, and the consolidated statements of income, comprehensive income (loss), equity and cash flows for each of the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the years then ended, in conformity with United States generally accepted accounting principles.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the US federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

We have served as AltaGas Ltd. auditor since 1997.

Calgary, Canada

February 27, 2019

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Consolidated Balance Sheets

As at ($ millions)	December 31, 2018		December 31, 2017
ASSETS
Current assets
Cash and cash equivalents (note 31)	$	101.6	$	27.3
Accounts receivable, net of allowances (note 22)	1,547.5		382.9
Inventory (note 6)	515.9		201.1
Restricted cash holdings from customers (note 31)	4.1		8.9
Regulatory assets (note 20)	21.0		1.1
Risk management assets (note 22)	114.1		38.6
Prepaid expenses and other current assets (notes 28 and 31)	199.9		36.0
Assets held for sale (note 5)	1,528.9		6.0
	4,033.0		701.9
Property, plant and equipment (note 7)	10,929.6		6,689.8
Intangible assets (note 8)	711.9		588.8
Goodwill (note 9)	4,068.2		817.3
Regulatory assets (note 20)	663.0		328.6
Risk management assets (note 22)	57.7		15.9
Deferred income taxes (note 19)	—		2.8
Restricted cash holdings from customers (note 31)	6.1		7.5
Prepaid post-retirement benefits (note 28)	342.7		—
Long-term investments and other assets (notes 11, 22, 28 and 31)	283.1		312.6
Investments accounted for by the equity method (note 13)	2,392.4		567.0
	$	23,487.7	$	10,032.2
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable and accrued liabilities (notes 17 and 22)	$	1,488.2	$	415.3
Dividends payable (note 22)	22.0		32.0
Short-term debt (notes 14 and 22)	1,209.9		46.8
Current portion of long-term debt (notes 15 and 22)	890.2		188.9
Customer deposits	98.0		30.8
Regulatory liabilities (note 20)	114.9		10.9
Risk management liabilities (note 22)	89.3		57.6
Other current liabilities (note 22)	18.1		32.6
Liabilities associated with assets held for sale (note 5)	171.4		0.3
	4,102.0		815.2
Long-term debt (notes 15 and 22)	8,066.9		3,436.5
Asset retirement obligations (note 16)	500.6		88.3
Unamortized investment tax credits (note 19)	190.1		—
Deferred income taxes (note 19)	957.9		444.2
Regulatory liabilities (note 20)	1,392.8		268.6
Risk management liabilities (note 22)	213.0		13.8
Other long-term liabilities (notes 17, 18 and 22)	122.0		201.9
Future employee obligations (note 28)	302.2		124.5
	$	15,847.5	$	5,393.0

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As at ($ millions)	December 31, 2018			December 31, 2017
Shareholders’ equity
Common shares, no par values, unlimited shares authorized;
2018 - 275.2 million and 2017 - 175.3 million issued and outstanding (note 24)	$	6,653.9		$	4,007.9
Preferred shares (note 24)	1,318.8			1,277.7
Contributed surplus	373.2			22.3
Accumulated deficit	(1,905.3		)	(933.6		)
Accumulated other comprehensive income (AOCI) (note 21)	579.0			199.1
Total shareholders’ equity	7,019.6			4,573.4
Non-controlling interests	620.6			65.8
Total equity	7,640.2			4,639.2
	$	23,487.7		$	10,032.2

Variable interest entities (note 12).

Commitments, contingencies and guarantees (note 29).

Subsequent events (note 33).

See accompanying notes to the Consolidated Financial Statements.

Approved by the Board of Directors of AltaGas Ltd.

(signed) “David W. Cornhill”	(signed) “Robert B. Hodgins”
DAVID W. CORNHILL	ROBERT B. HODGINS
Director	Director

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Consolidated Statements of Income (Loss)

For the year ended December 31 ($ millions except per share amounts)	2018			2017
REVENUE (note 23)	$	4,256.7		$	2,556.2
EXPENSES
Cost of sales, exclusive of items shown separately	2,455.3			1,357.1
Operating and administrative	1,129.0			572.2
Accretion expenses (note 16)	10.9			10.9
Depreciation and amortization (notes 7 and 8)	394.0			282.4
Provisions on assets (note 10)	728.7			139.6
	4,717.9			2,362.2
Income from equity investments (note 13)	47.9			31.4
Other income (note 26)	0.9			9.6
Foreign exchange gains	4.5			1.7
Interest expense
Short-term debt	(14.0		)	(3.7		)
Long-term debt	(295.0		)	(166.6		)
Income (loss) before income taxes	(716.9		)	66.4
Income tax expense (recovery) (note 19)
Current	24.4			30.5
Deferred	(287.6		)	(64.0		)
Net income (loss) after taxes	(453.7		)	99.9
Net income (loss) applicable to non-controlling interests	(18.6		)	8.3
Net income (loss) applicable to controlling interests	(435.1		)	91.6
Preferred share dividends	(66.6		)	(61.3		)
Net income (loss) applicable to common shares	$	(501.7	)	$	30.3
Net income (loss) per common share (note 25)
Basic	$	(2.25	)	$	0.18
Diluted	$	(2.25	)	$	0.18
Weighted average number of common shares outstanding (millions) (note 25)
Basic	222.6			171.0
Diluted	222.7			171.3

See accompanying notes to the Consolidated Financial Statements.

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Consolidated Statements of Comprehensive Income (Loss)

For the year ended December 31 ($ millions)	2018			2017
Net income (loss) after taxes	$	(453.7	)	$	99.9
Other comprehensive income (loss), net of taxes
Gain (loss) on foreign currency translation	458.5			(183.4		)
Unrealized gain (loss) on net investment hedge (note 22)	(80.2		)	6.6
Actuarial loss on pension plans and post-retirement benefit (PRB) plans (note 28)	(10.8		)	(1.0		)
Reclassification of actuarial gains and prior service costs on defined benefit (DB) and post-retirement benefit plans (PRB) to net income (note 28)	0.5			0.7
Settlement of PRB plan (note 28)	—			0.2
Curtailment of DB and PRB plan (note 28)	2.7			—
Unrealized loss on available-for-sale assets	—			(26.9		)
Adoption of ASU 2016-01 (note 2)	7.1			—
Other comprehensive income (loss) from equity investees	2.1			(2.2		)
Total other comprehensive income (loss) (OCI), net of taxes (note 21)	379.9			(206.0		)
Comprehensive loss attributable to controlling interests and non-controlling interests, net of taxes	$	(73.8	)	$	(106.1	)
Comprehensive income (loss) attributable to:
Non-controlling interests	$	(18.6	)	$	8.3
Controlling interests	(55.2		)	(114.4		)
	$	(73.8	)	$	(106.1	)

See accompanying notes to the Consolidated Financial Statements.

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Consolidated Statements of Equity

For the year ended December 31 ($ millions)	2018			2017
Common shares (note 24)
Balance, beginning of year	$	4,007.9		$	3,773.4
Shares issued for cash on exercise of options	1.3			6.5
Shares issued under DRIP (1)	325.8			236.3
Deferred taxes on share issuance costs	13.3			(8.3		)
Shares issued on conversion of subscription receipts, net of issuance costs	2,305.6			—
Balance, end of year	$	6,653.9		$	4,007.9
Preferred shares (note 24)
Balance, beginning of year	$	1,277.7		$	985.1
Series K issued	—			293.4
Preferred shares acquired through WGL Acquisition (note 24)	41.1			—
Deferred taxes on share issuance costs	—			(0.8		)
Balance, end of year	$	1,318.8		$	1,277.7
Contributed surplus
Balance, beginning of year	$	22.3		$	17.4
Share options expense	0.9			1.4
Exercise of share options	(0.1		)	(0.5		)
Forfeiture of share options	(0.1		)	(0.1		)
Adoption of ASU No. 2016-09	—			1.1
Sale of non-controlling interest (notes 4 and 12)	350.2			3.0
Balance, end of year	$	373.2		$	22.3
Accumulated deficit
Balance, beginning of year	$	(933.6	)	$	(600.4	)
Net income (loss) applicable to controlling interests	(435.1		)	91.6
Common share dividends	(462.9		)	(362.4		)
Preferred share dividends	(66.6		)	(61.3		)
Adoption of ASU No. 2016-09	—			(1.1		)
Adoption of ASU No. 2016-01 (note 2)	(7.1		)	—
Balance, end of year	$	(1,905.3	)	$	(933.6	)
AOCI (note 21)
Balance, beginning of year	$	199.1		$	405.1
Other comprehensive income (loss)	379.9			(206.0		)
Balance, end of year	$	579.0		$	199.1
Total shareholders’ equity	$	7,019.6		$	4,573.4
Non-controlling interests
Balance, beginning of year	$	65.8		$	34.8
Net income (loss) applicable to non-controlling interests	(18.6		)	8.3
Sale of non-controlling interest (notes 4 and 12)	498.4			20.0
Contributions from non-controlling interests to subsidiaries	96.3			11.0
Distributions by subsidiaries to non-controlling interests	(30.3		)	(8.3		)
Acquisition of non-controlling interest through WGL Acquisition (note 3)	9.0			—
Balance, end of year	620.6			65.8
Total equity	$	7,640.2		$	4,639.2

(1)Premium Dividend™, Dividend Reinvestment and Optional Cash Purchase Plan.

See accompanying notes to the Consolidated Financial Statements.

7

Consolidated Statements of Cash Flows

For the year ended December 31 ($ millions)	2018			2017
Cash from operations
Net income (loss) after taxes	$	(453.7	)	$	99.9
Items not involving cash:
Depreciation and amortization (notes 7 and 8)	394.0			282.4
Provisions on assets (note 10)	728.7			139.6
Accretion expenses (note 16)	10.9			10.9
Share-based compensation (note 24)	0.8			1.3
Deferred income tax recovery (note 19)	(287.6		)	(64.0		)
Losses on sale of assets (notes 4 and 26)	10.6			2.7
Income from equity investments (note 13)	(47.9		)	(31.4		)
Unrealized losses (gains) on risk management contracts (note 22)	(80.8		)	62.5
Realized loss on expiry of foreign exchange options (note 22)	36.0			—
Losses (gains) on investments (note 26)	10.1			(3.6		)
Amortization of deferred financing costs	29.7			16.9
Provision for doubtful accounts	17.0			—
Net change in pension and other post retirement benefits (note 28)	(3.8		)	—
Other	3.6			(4.1		)
Asset retirement obligations settled (note 16)	(4.2		)	(4.0		)
Distributions from equity investments	44.5			30.2
Changes in operating assets and liabilities (note 31)	(486.5		)	1.9
	$	(78.6	)	$	541.2
Investing activities
Business acquisitions, net of cash acquired (note 3)	(5,931.0		)	—
Acquisition of property, plant and equipment	(990.4		)	(473.0		)
Acquisition of intangible assets	(38.1		)	(20.3		)
Acquisition of investment in a publicly traded entity	—			(7.0		)
Contributions to equity investments	(235.4		)	(16.8		)
Loan to affiliate, net of repayment (note 30)	30.0			(12.5		)
Financing receivable	(8.7		)	—
Proceeds from disposition of investments (note 11)	76.5			—
Proceeds from IPO of ACI (note 4)	858.9			—
Payment for derivative contracts	—			(36.0		)
Proceeds from disposition of assets, net of transaction costs (note 4)	403.8			70.6
	$	(5,834.4	)	$	(495.0	)
Financing activities
Net issuance (repayment) of short-term debt	497.7			(74.2		)
Issuance of long-term debt, net of debt issuance costs	3,595.2			758.1
Repayment of long-term debt	(1,729.5		)	(861.6		)
Net issuance of bankers’ acceptances	553.6			—
Dividends - common shares	(472.9		)	(359.6		)
Dividends - preferred shares	(66.6		)	(61.3		)
Distributions to non-controlling interest	(30.3		)	(8.3		)
Contributions from non-controlling interests	96.3			11.0
Net proceeds from shares issued on exercise of options	1.2			6.0
Net proceeds from issuance of common shares	2,633.7			236.3
Net proceeds from issuance of preferred shares	—			293.4
Net proceeds from sale of non-controlling interest (notes 4 and 12)	908.6			24.1
Other	—			(1.9		)
	$	5,987.0		$	(38.0	)
Change in cash, cash equivalents and restricted cash	74.0			8.2
Effect of exchange rate changes on cash, cash equivalents and restricted cash	7.3			1.4
Net change in cash classified within assets held for sale (note 5)	(4.9		)	—
Restricted cash acquired (note 31)	81.0			—
Cash, cash equivalents, and restricted cash beginning of year	43.7			34.1
Cash, cash equivalents, and restricted cash end of year (note 31)	$	201.1		$	43.7

See accompanying notes to the Consolidated Financial Statements.

8

Notes to the Consolidated Financial Statements

(Tabular amounts and amounts in footnotes to tables are in millions of Canadian dollars unless otherwise indicated.)

1.  ORGANIZATION AND OVERVIEW OF THE BUSINESS

The businesses of AltaGas are operated by AltaGas and a number of its subsidiaries including, without limitation, AltaGas Services (U.S.) Inc., AltaGas Utility Holdings (U.S.) Inc., WGL Holdings Inc. (WGL), Wrangler 1 LLC, Wrangler SPE LLC, Washington Gas Resources Corporation, WGL Energy Services, Inc., and SEMCO Holding Corporation; in regards to the Midstream business, AltaGas Extraction and Transmission Limited Partnership, AltaGas Pipeline Partnership, AltaGas Processing Partnership, AltaGas Northwest Processing Limited Partnership, Harmattan Gas Processing Limited Partnership, and WGL Midstream Inc.; in regards to the Power business, AltaGas Power Holdings (U.S.) Inc., WGSW, Inc., WGL Energy Systems, Inc., and Blythe Energy Inc. (Blythe); and, in regards to the Utility business, Washington Gas Light Company, Hampshire Gas Company, and SEMCO Energy, Inc. (SEMCO). SEMCO conducts its Michigan natural gas distribution business under the name SEMCO Energy Gas Company (SEMCO Gas) and its Alaska natural gas distribution business under the name ENSTAR Natural Gas Company (ENSTAR).

AltaGas, a Canadian corporation, is a leading North American clean energy infrastructure company with strong growth opportunities and a focus on owning and operating assets to provide clean and affordable energy to its customers. The Corporation’s long-term strategy is to grow in attractive areas across its Utility, Midstream, and Power business segments seeking optimal capital deployment. In the Midstream business, the Corporation is focused on optimizing the full value chain of energy exports by providing producers with solutions, including global market access off both coasts of North America via the Corporation’s footprint in two of the most prolific gas plays — the Montney and Marcellus. To optimize capital deployment, the Corporation seeks to invest in U.S utilities located in strong growth markets with increasing construction to support customer additions, system improvement and accelerated replacement programs. In the Power business, AltaGas seeks to create innovative solutions with light capital investment utilizing the Corporation’s clean energy expertise. AltaGas has three business segments:

·Utilities, which serves approximately 1.6 million customers with a rate base of approximately US$3.7 billion through ownership of regulated natural gas distribution utilities across five jurisdictions in the United States, and two regulated natural gas storage utilities in the United States, delivering clean and affordable natural gas to homes and businesses. The Utilities business also includes storage facilities and contracts for interstate natural gas transportation and storage services;

·Midstream, which, subsequent to the sale of non-core midstream assets in Canada that closed in February 2019, transacts more than 1.5 Bcf/d of natural gas and includes natural gas gathering and processing, natural gas liquids (NGL) extraction and fractionation, transmission, storage, natural gas and NGL marketing, the Corporation’s 50 percent interest in AltaGas Idemitsu Joint Venture Limited Partnership (AIJVLP), an indirectly held one-third ownership investment in Petrogas Energy Corp. (Petrogas), through which AltaGas’ interest in the Ferndale Terminal is held, an interest in four regulated pipelines in the Marcellus/Utica gas formation in northeast United States and WGL’s retail gas marketing business; and

·Power, which, subsequent to the sale of non-core power assets in Canada that closed in February 2019, and the sale of the remaining 55 percent interest in the Northwest Hydro facilities which closed in January 2019, includes 1,105 MW of gross capacity from natural gas-fired, biomass, solar, other distributed generation and energy storage assets located in Alberta, Canada and 20 states and the District of Columbia in the United States. The Power business also includes energy efficiency contracting and WGL’s retail power marketing business.

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2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

BASIS OF PRESENTATION

These Consolidated Financial Statements have been prepared by Management in accordance with United States Generally Accepted Accounting Principles (U.S. GAAP).

Pursuant to National Instrument 52-107, “Acceptable Accounting Principles and Auditing Standards” (NI 52-107), financial statements of an “SEC issuer” may be prepared in accordance with U.S. GAAP. On July 13, 2018, AltaGas filed a final short form base shelf prospectus in Alberta and a corresponding registration statement on Form F-10 in the United States, by virtue of which AltaGas is now required to file reports under section 15(d) of the Securities Exchange Act of 1934 with the United States Securities and Exchange Commission. As a result, AltaGas became an SEC issuer at such time and is now entitled to prepare its financial statements in accordance with U.S. GAAP.

PRINCIPLES OF CONSOLIDATION

These Consolidated Financial Statements of AltaGas include the accounts of the Corporation, its subsidiaries, variable interest entities (VIEs) for which the Corporation is the primary beneficiary, and its interest in various partnerships and joint ventures where AltaGas has an undivided interest in the assets and liabilities. Investments in unconsolidated companies that AltaGas has significant influence over, but not control, are accounted for using the equity method.

Hypothetical Liquidation at Book Value (HLBV) methodology is used for certain WGL equity method investments as well as WGL consolidating equity investments with non-controlling interests when the governing structuring agreement over the equity investment results in different liquidation rights and priorities than what is reflected by the underlying ownership interest percentage.

All intercompany balances and transactions are eliminated on consolidation. Where there is a party with a non-controlling interest in a subsidiary that AltaGas controls, that non-controlling interest is reflected as “non-controlling interests” in the Consolidated Financial Statements. The non-controlling interests in net income (or loss) of consolidated subsidiaries are shown as an allocation of the consolidated net income and are presented separately in “net income applicable to non-controlling interests”.

USE OF ESTIMATES AND MEASUREMENT UNCERTAINTY

The preparation of Consolidated Financial Statements in accordance with U.S. GAAP requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenue and expenses during the period. Key areas where Management has made complex or subjective judgments, when matters are inherently uncertain, include but are not limited to: determining the nature and timing of satisfaction of performance obligations and determining the transaction price and amounts allocated to performance obligations for revenue recognition; depreciation and amortization rates, fair value of asset retirement obligations, fair value of property, plant and equipment and goodwill for impairment assessments, fair value of financial instruments, provisions for income taxes, assumptions used to measure employee future benefits, provisions for contingencies, and carrying value of regulatory assets and liabilities. Certain estimates are necessary for the regulatory environment in which AltaGas’ subsidiaries or affiliates operate, which often require amounts to be recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. By their nature, these estimates are subject to measurement uncertainty and may impact the Consolidated Financial Statements of future periods.

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SIGNIFICANT ACCOUNTING POLICIES

Rate-Regulated Operations

SEMCO Gas, ENSTAR, Washington Gas, and Hampshire (collectively Utilities) engage in the delivery, sale, and storage of natural gas. SEMCO Gas and ENSTAR are regulated by the Michigan Public Service Commission (MPSC) and Regulatory Commission of Alaska (RCA), respectively. Washington Gas operates in the District of Columbia, Maryland, and Virginia and is regulated in those jurisdictions by the Public Service Commission of the District of Columbia (PSC of DC), the Maryland Public Service Commission (PSC of MD) and the Commonwealth of Virginia State Corporation Commission (SCC of VA), respectively.

The MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA exercise statutory authority over matters such as tariffs, rates, construction, operations, financing, returns, accounting and certain contracts with customers. In order to recognize the economic effects of the actions and decisions of the MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA, the timing of recognition of certain assets, liabilities, revenues and expenses as a result of regulation may differ from that otherwise expected using U.S. GAAP for entities not subject to rate regulation.

Regulatory assets represent future revenues associated with certain costs incurred in the current period or in prior periods that are expected to be recovered from customers in future periods through the rate setting process. Regulatory liabilities represent future reductions or limitations of increases in revenue associated with amounts that are expected to be refunded to customers through the rate setting process.

Cash and Cash Equivalents

Cash and cash equivalents consist of cash on hand, balances with banks, and investments in money market instruments with original maturities of less than three months.

Restricted Cash Holdings from Customers

Cash deposited, which is restricted and is not available for general use by AltaGas, is separately presented as restricted cash holdings in the Consolidated Balance Sheets. Pursuant to the acquisition of WGL Holdings, Inc. (the WGL Acquisition), rabbi trust funds were funded to satisfy certain WGL executive and outside director retirement benefit plan obligations. As of December 31, 2018, the rabbi trust funds are invested in money market funds which are considered as cash equivalents. These balances are included in prepaid expenses and other current assets and long-term investments and other assets in the Consolidated Balance Sheets.

Accounts Receivable

Receivables are recorded net of the allowance for doubtful accounts in the Consolidated Balance Sheets. AltaGas regularly analyzes and evaluates the collectability of the accounts receivable based on a combination of factors. If circumstances related to the collectability change, the allowance for doubtful accounts is further adjusted. Accounts are written off when collection efforts are complete and future recovery is unlikely.

Inventory

Inventory consists of materials, supplies, natural gas, renewable energy credits, and emission compliance instruments which are valued at the lower of cost or net realizable value. Cost of inventory is assigned using a weighted average cost formula. In general, commodity costs and variable transportation costs are capitalized as gas in underground storage. Fixed costs, primarily pipeline demand charges and storage charges, are expensed as incurred through the cost of gas.

Property, Plant, and Equipment (PP&E), Depreciation and Amortization

Property, plant, and equipment are carried at cost. The Corporation depreciates the cost of capital assets, net of salvage value, on a straight-line basis over the estimated useful life of the assets, with the exception of rate regulated utilities assets, where depreciation is calculated on a straight-line basis or over the contract term of a specific agreement at rates as approved by the regulatory authorities.

11

The U.S. utilities charge maintenance and repairs directly to operating expense and capitalize betterments and renewal costs. In accordance with regulatory requirements, depreciation expense includes an amount allowed for regulatory purposes to be collected in current rates for future removal and site restoration costs.

Interest costs are capitalized on major additions to property, plant, and equipment until the asset is ready for its intended use. The interest rate used for calculating the interest costs to be capitalized is based on AltaGas’ prior quarter actual borrowing long-term interest rate.

Utilities capitalize an imputed carrying cost on assets during construction as authorized by regulatory authorities and the amount so capitalized is an allowance for funds used during construction (AFUDC). AFUDC is the amount that a rate regulated enterprise is allowed to recover for its cost of financing assets under construction. Capitalized overhead, administrative expenses and AFUDC are included in the cost of the related assets and are recovered in rates charged to customers through depreciation expense, as allowed by the regulators.

The range of useful lives for AltaGas’ PP&E is as follows:

Utilities assets	3 - 80 years
Midstream assets	3 - 45 years
Power generation assets	2 - 120 years
Corporate assets	1 - 20 years

As required by the regulatory authority, net additions to SEMCO’s utility assets are amortized for one half year in the year in which they are brought into active service. Net additions to WGL’s assets are amortized in the month they are brought into active service.

Generally, when a regulated asset is retired or disposed of, there is no gain or loss recorded in the Consolidated Statement of Income. Any difference between the cost and accumulated depreciation of the asset, net of salvage proceeds, is charged to accumulated depreciation or another regulatory asset or liability account. It is expected that any gain or loss that is charged to accumulated depreciation or another regulatory account will be reflected in future depreciation expense when it is refunded or collected in rates. When a non-regulated asset is retired or disposed of from PP&E, the original cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in the Consolidated Statement of Income.

Leases are classified as either capital or operating. Leases that transfer substantially all the benefits and risks of ownership of property to AltaGas are accounted for as capital leases.

Intangible Assets

Intangible assets are recorded at cost. Intangible assets which have a finite useful life are amortized on a straight-line basis over their term or estimated useful life. The range of useful lives for intangible assets with a finite life is as follows:

Energy services relationships	5 -19 years
Electricity service agreements	2 - 60 years
Software	3 - 10 years
Land rights	5 - 64 years
Franchises and consents	9 - 25 years
Extraction and Transmission (E&T) Contracts	25 years
Commodity contracts	5 years

The intangible assets recorded in the purchase price allocation for certain WGL commodity contracts are amortized based on the estimated fair value of the deliveries over the term of the contracts, which are over a period of 20 years.

12

Assets Held for Sale

The Corporation classifies assets as held for sale when the carrying amount will be recovered through a sale transaction rather than through continuing use. This condition is met when Management approves and commits to a formal plan to sell the assets, the assets are available for immediate sale in their present condition, and Management expects the sale to close within the next 12 months. Upon classifying an asset as held for sale, an asset is recorded at the lower of its carrying value or the estimated fair value less cost to sell. Assets held for sale are not depreciated or amortized.

Business Acquisitions

Business acquisitions are accounted for using the acquisition method. Under the acquisition method, assets and liabilities of the acquired entity are recorded at fair value at the date of acquisition. Acquisition-related costs are expensed as incurred. Goodwill represents the excess of purchase price over the fair value of the net assets acquired.

Provisions on Assets

If facts and circumstances suggest that a long-lived asset or an intangible asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset is not recoverable, as determined by the projected undiscounted cash flows related to the asset over its remaining life, then the carrying value of the asset is reduced to its estimated fair value and an impairment loss is recognized.

Goodwill is not subject to amortization, but assessed at least annually for impairment, or more often when events or changes in circumstances indicate that goodwill may be impaired. The annual assessment of goodwill is performed at the reporting unit level, which is an operating segment or one level below. The Corporation has the option to first assess qualitative factors to determine whether events or changes in circumstances indicate that the goodwill may be impaired. If a quantitative impairment test is performed, the fair value of the reporting unit will be compared to its carrying value (including goodwill). If the carrying value of the reporting unit exceeds the fair value, goodwill is reduced to its fair value and an impairment loss would be recorded in the Consolidated Statement of Income.

Development Costs

AltaGas expenses development costs as incurred unless such development costs meet certain criteria related to technical, market, regulatory and financial feasibility for capitalization. Development costs are examined annually to ensure capitalization criteria continue to be met. When the criteria that previously justified the deferral of costs are no longer met, the unamortized balance is taken as a charge to income in the period when this determination is made. Development costs are amortized based on the expected period of benefit, beginning at the commencement of commercial operations.

Investments Accounted for by the Equity Method

The equity method of accounting is used for investments in which AltaGas has the ability to exercise significant influence, but does not have a controlling interest. Equity investments are initially measured at cost and are adjusted for the Corporation’s proportionate share of earnings or losses. Equity investments are increased for contributions made and decreased for distributions received. To the extent an investee undertakes activities necessary to commence its planned principal operations, the Corporation will capitalize interest costs associated with its investment during such period.

The HLBV methodology is used to allocate earnings or losses for certain WGL equity method investments when WGL’s ownership interest percentage is different than distribution percentages. When applying HLBV accounting, the Corporation determines the amount that it would receive if an equity investment entity were to liquidate all of its assets at book value (as valued in accordance with U.S. GAAP) and distribute that cash to the investors based on the contractually defined liquidation priorities. The change in the Corporation’s claim on the equity investment entity’s book value at the beginning and end of the reporting period (adjusted for contributions and distributions) is the Corporation’s share of the earnings or losses from the equity investment for the period.

13

An equity method investment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the investment may not be recoverable. When such condition is deemed other than temporary, the carrying value of the investment is written down to its fair value, and an impairment charge is recorded in the Consolidated Statement of Income.

Financial Instruments

Non-Utility Operations

All financial instruments are initially recorded at fair value unless they qualify for, and are designated under, a normal purchase and normal sale (NPNS) exemption. Subsequent measurement of the financial instruments is based on their classification. The financial assets are classified as “held-for-trading”, “held-to-maturity”, or “loans and receivables”. Financial liabilities are classified as “held-for-trading” or other financial liabilities. Subsequent measurement is determined by classification.

A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to AltaGas’ business needs and AltaGas has the ability, and intent, to deliver or take delivery of the underlying item. AltaGas continually assesses the contracts designated under the NPNS exemption and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met.

Held-for-trading instruments include non-derivative financial assets and financial assets and liabilities that may consist of swaps, options, forwards and equity securities. These financial instruments are initially recorded at their fair value, with subsequent changes in fair value recorded in net income. Held-to-maturity, loans and receivables, and other financial liabilities are recognized at amortized cost using the effective interest method unless they are held-for-sale and recognized at the lower of cost or fair value less transaction fees.

Investments in equity instruments not accounted for under the equity method that do not have a quoted market price in an active market are measured at cost. Income earned from these investments is included in the Consolidated Statement of Income under “other income”.

Derivatives embedded in other financial instruments or contracts (the host instrument) are recorded separately and are measured at fair value if the economic characteristics of the embedded derivative are not closely related to the host instrument, the terms of the embedded derivative are the same as those of a standalone derivative and the entire contract is not held-for-trading or accounted for at fair value. Changes in fair value are included in earnings.

The fair values recorded on the Consolidated Balance Sheets reflect netting of the asset and liability positions where counterparty master netting arrangements contain provisions for net settlement.

Transaction costs related to the acquisition of held-for-trading financial assets and liabilities are expensed as incurred.

Transaction costs for obtaining debt financing other than line-of-credit arrangements are recognized as a direct deduction from the related debt liability on the Consolidated Balance Sheets. Transaction costs related to line-of-credit arrangements are capitalized and included under “long-term investments and other assets” on the Consolidated Balance Sheets. Premiums and discounts are netted against long-term debt on the Consolidated Balance Sheets. The deferred charges are amortized over the life of the related debt on an effective interest basis and included in “interest expense” on the Consolidated Statement of Income.

Regulated Utility Operations

All physical and financial derivative contracts are initially recorded at fair value. Changes in the fair value of derivative instruments that are recoverable or refunded to customers when they settle are recorded as regulatory assets or liabilities. Changes in the fair value of derivatives not affected by rate regulation are reflected in net income.

Weather-Related Instruments

WGL purchases certain weather-related instruments, such as heating degree day (HDD) derivatives and cooling degree day (CDD) derivatives to manage weather and price risks related to its natural gas and electricity sales. These derivatives are

14

accounted for in accordance with ASC 815-45, Derivatives and Hedging — Weather Derivatives. For HDD derivatives, gains or losses are recognized when the actual HDD’s falls above or below the contractual HDD’s for each instrument. For CDD derivatives, gains or losses are recognized when the average temperature exceeds or is below a contractually stated level during the contract period. Refer to Note 22 for further discussion on weather-related instruments.

Hedges

As part of its risk management strategy, AltaGas may use derivatives to reduce its exposure to commodity price, interest rate and foreign exchange risk. AltaGas has designated certain U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. No other derivatives have been designated as hedges under ASC Topic 815.

Non-Utility Operations

The change in fair value of cash flow hedges is recognized in OCI. Gains or losses from cash flow hedges are reclassified to net income when the hedged transaction affects earnings, such as when the hedged forecasted transaction occurs.

Regulated Utility Operations

During planned issuances of debt securities, Washington Gas may utilize derivative instruments to manage the risk of interest-rate volatility. Gains and losses associated with these types of derivatives are recorded as regulatory liabilities or assets, and amortized in accordance with regulatory requirements, typically over the life of the related debt.

Asset Retirement Obligations

AltaGas recognizes asset retirement obligations in the period in which the legal obligation is incurred and a reasonable estimate of fair value can be determined. The associated asset retirement costs are capitalized as part of the carrying amount of the asset and are depreciated over the estimated useful life of the asset. The liability is increased due to the passage of time over the estimated period until the settlement of the obligation, with a corresponding charge to accretion expense for asset retirement obligations.

There are timing differences between accretion and depreciation amounts being recorded pursuant to GAAP and the recognition of depreciation expense for legal asset removal costs that are recovered in rates, as allowed by the regulators. These timing differences are recorded as a reduction to “regulatory liabilities” in accordance with ASC 980.

Certain utility assets will have future legal obligations on retirement, but an asset retirement obligation has not been recorded due to its indeterminate life and corresponding indeterminable timing and scope of these asset retirement obligations. The U.S. Utilities recognize asset retirement obligations for some interim retirements, as expected by their regulators.

Revenue Recognition

AltaGas has revenue from various sources, including rate regulated revenue, commodity sales, midstream service contracts, gas sales and transportation services, and gas storage services. For a detailed description of the Corporation’s revenue recognition policy by major source of revenue, please refer to Note 23.

Foreign Currency Translation

Monetary assets and liabilities denominated in a foreign currency are converted to the functional currency using the exchange rate in effect at the balance sheet date. Adjustments resulting from the conversion are recorded in the Consolidated Statement of Income. Non-monetary assets and liabilities are converted at the historical exchange rate in effect at the transaction date. Revenues and expenses are converted at the exchange rate applicable at the transaction date.

For foreign entities with a functional currency other than Canadian dollars, AltaGas’ reporting currency, assets, and liabilities are translated into Canadian dollars at the rate in effect at the reporting date. Revenues and expenses are translated at average exchange rates during the reporting period. All adjustments resulting from the translation of the foreign operations are recorded in OCI.

15

AltaGas may designate some of its U.S. dollar denominated long-term debt as a foreign currency hedge of its investment in foreign operations. Accordingly, foreign exchange gains and losses, from the dates of designation, on the translation of the U.S. dollar denominated long-term debt are included in OCI.

Share Options and Other Compensation Plans

Share options granted are recorded using fair value. Compensation expense is measured at the date of the grant using the Black-Scholes-Merton model and is recognized over the vesting period of the options. Consideration received by AltaGas on exercise of the share options is credited to shareholders’ equity.

AltaGas has a medium-term incentive plan (MTIP) for employees and executive officers which includes two types of awards: restricted units (RUs) and performance units (PUs). A portion of AltaGas’ RUs and PUs are valued based on the dividends declared during the vesting period and the weighted average share price of AltaGas’ common shares multiplied by the units outstanding at the end of the vesting period. Upon vesting, the RUs and PUs are paid in cash or, at the election of AltaGas, its equivalent in common shares purchased from the market. The other portion of RU’s and PSUs are valued at US$1 per unit. Upon vesting, the RUs and PSUs are paid in cash. All PUs are also subject to a performance multiplier ranging from 0 to 2 dependent on the Corporation’s performance relative to performance targets agreed between the Corporation and the employees. Compensation expense is recognized using the liability method and is recorded as operating and administrative expense over the vesting period. A change in value of the RUs or PUs is recognized in the period the change occurs.

In addition, AltaGas has a deferred share unit plan (DSUP) for directors, officers and employees as an additional form of long-term variable compensation incentive. Although the DSUP is available to directors, officers and employees, AltaGas currently only grants deferred share units (DSUs) under the DSUP as a form of director compensation. The DSUs granted are fully vested upon being credited to a participant’s account, and the participant is entitled to payment at his or her termination date, and payment is not subject to satisfaction of any requirements as to any minimum period of membership or employment or other conditions. DSUs are accounted for at fair value. Compensation expense is determined based on the fair value of the DSUs on the date of the grant and fluctuations in fair value are recognized in the period the change occurs.

Pension Plans and Post-Retirement Benefits

AltaGas maintains defined benefit pension plans, defined contribution plans, and other post-retirement benefit plans for eligible employees. Contributions made by the Corporation to the defined contribution plans are expensed in the period in which the contribution occurs.

The cost of defined benefit pension plans and post-retirement benefits is actuarially determined using the projected benefit method prorated based on service and Management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected health care costs. Pension plan assets are measured at fair value. The expected return on plan assets is based on historical and projected rates of return for each asset class in the plan portfolio. The projected benefit obligation is discounted using the market interest rate on high-quality debt instruments with cash flows matching the timing and amount of benefit payments. Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation and the fair value of plan assets or the market-related value of assets along with any unamortized past service costs are amortized on a straight-line basis over the expected average remaining service life of active employees. The expected average remaining service period of the active members covered by the defined benefit pension plans and post-retirement benefit plans is 9.6 years and 14.1 years, respectively.

AltaGas recognizes the overfunded or underfunded status of its pension and post-retirement benefit plans as either assets or liabilities in the Consolidated Balance Sheets. Unrecognized actuarial gains and losses and past service costs and credits that arise during the period are recognized in OCI or a regulatory asset or liability.

For certain regulated utilities, the Corporation expects to recover pension expense in future rates and therefore records unrecognized balances as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the expected average remaining service life of active employees.

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Income Taxes

Income taxes for the Corporation and its subsidiaries are calculated using the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are determined based on differences between the carrying value and the tax basis of assets and liabilities and are measured using the enacted tax rates and laws that are in effect in the periods in which the differences are expected to be settled or realized. Deferred income tax assets are routinely reviewed and a valuation allowance is recorded to reduce the deferred tax assets if it is more likely than not that deferred tax assets will not be realized. The financial statement effects of an uncertain tax position are recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxing authority. The current and deferred tax impact is equal to the largest amount, considering possible settlement outcomes, that is greater than 50 percent likely of being realized upon settlement with the taxing authorities.

Investment tax credits are recognized as reductions to income tax expense over the estimated service lives of the related properties.

The rate-regulated natural gas distribution subsidiaries recognize a separate regulatory asset or liability for the amount of deferred income taxes expected to be recovered from, or paid to, customers in the future.

Net Income per Share

Basic net income per common share is computed using the weighted average number of common shares outstanding during the period. Dilutive net income per common share is calculated using the weighted average number of common shares outstanding adjusted for dilutive common shares related to the Corporation’s share-based compensation awards.

The potentially dilutive impact of the share-based compensation awards is determined using the treasury stock method. Under the treasury stock method, awards are treated as if they had been exercised with any proceeds used to repurchase common stock at the average market price during the period. Any incremental difference between the assumed number of shares issued and purchased is included in the diluted share computation.

Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Any such accruals are adjusted thereafter as additional information becomes available or circumstances change.

ADOPTION OF NEW ACCOUNTING STANDARDS

Effective January 1, 2018, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU):

·ASU No. 2014-09 “Revenue from Contracts with Customers” and all related amendments (collectively “ASC 606”).  AltaGas adopted ASC 606 using the modified retrospective method to contracts that have not been completed as at January 1, 2018. Under the modified retrospective method, the comparative information is not adjusted. The adoption of ASC 606 impacted the timing of revenue recognition in relation to contracts with take-or-pay or minimum volume commitments whereby the customers have make up rights for deficiency quantities. However, on adoption, no cumulative adjustments to opening retained earnings were required for this change in revenue recognition pattern as none of the customers had material deficiency quantities. Please also refer to Note 23 for further details. The application of ASC 606 did not have a material impact on AltaGas’ consolidated financial statements in 2018;

·ASU No. 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” which revised an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. It also amended certain disclosure requirements associated with the fair value of financial instruments. Upon adoption, AltaGas reclassified its equity

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securities with readily determinable fair values from available-for-sale to held for trading. Changes in fair value for equity securities with readily determinable fair values are now recognized through earnings instead of other comprehensive income. As a result, a cumulative-effect adjustment to retained earnings of approximately $7 million was recognized as at January 1, 2018. The remaining provisions of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

·ASU No. 2016-15 “Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments”. The amendments in this ASU clarified the classification of certain cash flow transactions on the statement of cash flow. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

·ASU No. 2016-16 “Income Taxes: Intra-Entity Transfers of Assets Other Than Inventory”. The amendments in this ASU revised the accounting for income tax consequences on intra-entity transfers of assets by requiring an entity to recognize current and deferred tax on intra-entity transfers of assets other than inventory when the transfer occurs. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

·ASU No. 2016-18 “Statement of Cash Flows: Restricted Cash”. The amendments in this ASU required those amounts deemed to be restricted cash and restricted cash equivalents to be included in the cash and cash equivalents balance on the statement of cash flows. The change in presentation of the restricted cash balance on the statement of cash flows was applied on a retrospective basis;

·ASU No. 2017-01 “Business Combinations: Clarifying the Definition of a Business”. The amendments in this ASU changed the definition of a business to assist entities with evaluating when a set of transferred assets and activities is a business. AltaGas will apply the amendments to this ASU prospectively;

·ASU No. 2017-04 “Intangibles — Goodwill and Other: Simplifying the Test for Goodwill Impairment”. The amendments in this ASU removed Step 2 of the goodwill impairment test, eliminating the requirement to determine the fair value of individual assets and liabilities of a reporting unit to measure the goodwill impairment. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

·ASU No. 2017-05 “Other Income — Gains and Losses from the De-recognition of Nonfinancial Assets: Clarifying the Scope of Asset De-recognition Guidance and Accounting for Partial Sales of Nonfinancial Assets”. The amendments in this ASU clarified the scope of ASC 610-20 as well as the accounting for partial sales of nonfinancial assets. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

·ASU No. 2017-07 “Compensation — Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”. The amendments in this ASU revised the presentation of net periodic pension cost and net periodic postretirement benefit cost on the income statement and limited the components that are eligible for capitalization in assets to only the service cost component. AltaGas applied the change in presentation of the current service cost and other components of net benefit cost on the income statement retrospectively. As a result, $1.6 million of net benefit cost associated with other components were reclassified from the line item “operating and administrative” to “other income” on the Consolidated Statements of Income for the year ended December 31, 2017. AltaGas applied the change related to the capitalization of the service cost prospectively. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

·ASU No. 2017-09 “Compensation — Stock Compensation: Scope of Modifications Accounting”. The amendments in this ASU provided guidance on the types of changes to the terms or conditions of share-based payment arrangements to which an entity would be required to apply modification accounting. The guidance was applied prospectively and did not have a material impact on AltaGas’ consolidated financial statements;

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·ASU No. 2017-12 “Derivatives and Hedging — Targeted Improvements to Accounting for Hedging Activities”. The amendments in this ASU improved the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and made certain targeted improvements to simplify the application of hedge accounting. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

·ASU No. 2018-02 “Income Statement — Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”. The amendments in this ASU allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act (TCJA). AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and

·ASU No. 2018-03 “Technical Corrections and Improvements to Financial Instruments — Overall”. The amendments in this ASU clarified certain aspects of the guidance issued in ASU No. 2016-01. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements.

FUTURE CHANGES IN ACCOUNTING PRINCIPLES

In February 2016, FASB issued ASU No. 2016-02 “Leases”, which requires lessees to recognize on the balance sheet a right-of-use asset and a lease liability. Lessor accounting remains substantially unchanged, however, the ASU modifies what qualifies as a sales-type and direct financing lease and eliminates the real estate-specific provisions included in ASC 840. The ASU also requires additional disclosures regarding leasing arrangements. In January 2018, FASB issued ASU 2018-01 “Land Easement Practical Expedient for Transition to Topic 842”, providing entities with an optional election not to evaluate existing and expired land easements not previously accounted for as leases under ASC 840 using the provisions of ASC 842. In July 2018, FASB issued ASU 2018-11 “Targeted Improvements”, allowing entities to report the comparative periods presented in the period of adoption under the previous lease standard (ASC 840), and recognize a cumulative-effect adjustment to the opening balance of retained earnings as of January 1, 2019. The ASU also provides a practical expedient under which lessors are not required to separate out lease and non-lease components of a contract, provided certain conditions are met. In December 2018, FASB issued ASU 2018-20 “Narrow-Scope Improvement for Lessors”, allowing lessors to include and exclude certain costs from variable payments. The ASU also require lessors to allocate certain variable payments to the lease and non-lease components when the changes in facts and circumstances on which the variable payment is based occur. The amendments to the new lease standard are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. AltaGas is in the final stages of evaluating the impact of adopting ASC 842 on its consolidated financial statements. Leases, except as noted below, for which AltaGas is the lessee will be reflected on the balance sheet upon adoption by recording an increase to long-term assets and an increase to long-term liabilities net of the current portion that is recorded in current liabilities. The increases are expected to be less than 1 percent of total assets. AltaGas will utilize the transition practical expedients which allow entities to not have to reassess whether an arrangement contains a lease under the provisions of ASC 842, as well as the transition practical expedients related to land easements and not separating out lease and non-lease components of a contract for certain classes of assets. As a result of the transition practical expedients, AltaGas expects to have primarily operating leases on transition consistent with its current conclusions under ASC 840. AltaGas will also elect to exclude leases with terms of 12 months or less from the calculation of lease liabilities and right of use assets under the short term lease exemption.

In June 2016, FASB issued ASU No. 2016-13 “Financial Instruments — Credit Losses: Measurement of Credit Losses on Financial Instruments”. The amendments in this ASU replace the current “incurred loss” impairment methodology with an “expected loss” model for financial assets measured at amortized cost. The amendments in this ASU are effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted. AltaGas is currently assessing the impact of this ASU on its consolidated financial statements.

In June 2018, FASB issued ASU No. 2018-07 “Compensation — Stock Compensation: Improvements to Nonemployee Share-Based Payment Accounting”. The amendments in this ASU expand the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees, with the objective of making the measurement

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consistent with employee share based payment awards. The amendments in this update are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In June 2018, FASB issued ASU No. 2018-08 “Not-for-Profit-Entities — Clarifying the Scope and the Accounting Guidance for Contributions Received and Contributions Made”. The amendments in this Update clarify whether a transfer of assets is a contribution or an exchange transaction. The amendments in this update are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In August 2018, FASB issued ASU No. 2018-13 “Fair Value Measurement — Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurement”. The amendments in this ASU modify the disclosure requirements on fair value measurements. The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In August 2018, FASB issued ASU No. 2018-14 “Compensation — Retirement Benefits-Defined Benefit Plans — General: Disclosure Framework — Changes to the Disclosure Requirements for the Defined Benefit Plans”. The amendments in this ASU modify the disclosure requirements on defined benefit pension and other postretirement plans. The amendments in this update are effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In August 2018, FASB issued ASU No. 2018-15 “Intangibles — Goodwill and Other — Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement (CCA) that is a Service Contract”. The amendments in this ASU align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal use software license). The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted and AltaGas will early adopt this ASU on January 1, 2019. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In October 2018, FASB issued ASU No. 2018-16 “Derivatives and Hedging: Inclusion of the Second Overnight Financing Rate (SOFR) Overnight Index Swap (OIS) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes”. The amendments in this ASU permit the use of Overhead Index Swap (OIS) rate based on SOFR as a U.S. benchmark interest rate for hedge accounting purposes. The amendments in this update should be adopted concurrently with ASU 2017-12. AltaGas early adopted ASU 2017-12 on January 1, 2018 and therefore will adopt this update on January 1, 2019. An entity should apply the amendments prospectively for any qualifying new or re-designated cash flow hedging relationships. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In October 2018, FASB issued ASU No. 2018-17 “Consolidation: Targeted Improvements to Related Party Guidance for Variable Interest Entities”. The amendments in this Update provide a private-company scope exception to the VIE guidance for certain entities and clarify that indirect interest held through related parties under common control will be considered on a proportional basis when determining whether fees paid to decision makers and service providers are variable interests. The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. An entity should apply the amendments retrospectively with a cumulative-effect adjustment to retained earnings at the beginning of the earliest period presented Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

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3.  ACQUISITION OF WGL HOLDINGS INC.

Following the receipt of all required federal, state, and local regulatory approvals, on July 6, 2018 the Corporation acquired WGL for an aggregate purchase price of approximately $9.3 billion (US$7.1 billion), including the assumption of approximately $3.3 billion (US$2.5 billion) of debt and $41 million (US$31 million) of preferred shares.

Under the terms of the transaction, WGL shareholders received US$88.25 per common share. The net cash consideration was approximately $6.0 billion (US$4.6 billion). The WGL Acquisition was financed through net proceeds of approximately $2.3 billion from the sale of subscription receipts, draws on the fully committed acquisition credit facility of $3.0 billion (US$2.3 billion) and existing cash on hand. The draws on the acquisition credit facility included additional amounts for the payment of fees and regulatory commitments related to the WGL Acquisition. The sale of the subscription receipts was completed in the first quarter of 2017 and upon closing of the WGL Acquisition, the subscription receipts were exchanged into approximately 84.5 million common shares of AltaGas.

The WGL Acquisition is accounted for as a business combination using the acquisition method of accounting whereby the acquired assets and assumed liabilities are recorded at their estimated fair values at the date of acquisition. The excess of purchase price over estimated fair values of assets acquired and liabilities assumed is recognized as goodwill at the acquisition date.

The following table summarizes the purchase price allocation representing the consideration paid and the fair value of the net assets acquired as at July 6, 2018 using an exchange rate of 1.31 to convert U.S. dollars to Canadian dollars. The purchase price allocation is provisional and reflects Management’s current best estimate of the fair value of WGL’s assets and liabilities based on the analysis of information obtained to date. Management is continuing to obtain specific information to support the evaluation of fixed assets, goodwill and deferred income taxes for certain elements of the acquired business. As the additional information becomes available, the purchase price allocation may differ from the preliminary purchase price allocation below. Any adjustments to the purchase price allocation will be made as soon as practicable but no later than one year from the date of acquisition.

The following table summarizes the estimated fair values that were assigned to the net assets of WGL at the date of acquisition:

Purchase consideration	$	5,973
Fair value assigned to net assets
Current assets	$	1,187
Property, plant and equipment	5,943
Intangible assets	637
Regulatory assets	402
Long-term investments	1,411
Other long-term assets	449
Current liabilities	(1,798		)
Long-term debt	(2,548		)
Preferred shares	(41		)
Regulatory liabilities	(1,125		)
Deferred income taxes	(772		)
Other long-term liabilities	(959		)
Non-controlling interest	(9		)
Fair value of net assets acquired	$	2,777
Goodwill	$	3,196

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The fair value of property, plant and equipment was estimated using the valuation methodologies described in ASC 820, Fair Value Measurements and Disclosures, to value the property, plant and equipment purchased. The fair value of WGL’s rate regulated property, plant and equipment is determined using a market participant perspective, which is equal to the carrying amount. The preliminary fair values of the remaining non-regulated property, plant and equipment is determined using both the income and cost approaches and resulted in an estimated fair value decrease relative to carrying value of approximately $92 million related to solar distributed generation assets.

Long-term investments include WGL’s 55 percent equity investment in Meade Pipeline Co. LLC. (Meade), a 10 percent equity interest in Mountain Valley Pipeline LLC, and a 30 percent equity interest in Stonewall Gas Gathering Systems LLC. Meade owns 39 percent of Central Penn, and WGL owns a 21 percent indirect net interest in Central Penn. The preliminary fair value of these investments has been determined using an income approach, resulting in an estimated fair value increase of approximately $464 million.

Intangible assets consist of customer relationships, contracts relating to gas transportation capacity, and natural gas purchase and sale agreements for energy exports. The preliminary fair value of these assets is determined using an income approach, resulting in an estimated fair value of approximately $637 million.

The fair value of current assets and current liabilities approximate their carrying values due to their short-term nature.

The fair value of long-term debt was estimated based on the quoted market prices of the U.S. Treasury issues having a similar term to maturity, adjusted for the credit quality of the debt issuer, WGL or Washington Gas Light Company. This resulted in a fair value increase of approximately $87 million, with a corresponding regulatory offset.

Deferred income tax assets and liabilities have been applied on the cumulative amount of tax applicable to temporary differences between the accounting and tax values of assets and liabilities.

The preliminary purchase price allocation includes goodwill of approximately $3.2 billion. The goodwill is primarily related to the investment in low risk, long-life rate regulated assets, opportunities to grow the gas midstream business, expanded access to capital and greater financial flexibility as a result of increased scale, and earnings diversification. The goodwill recognized as part of this transaction is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to this goodwill.

Pre-tax acquisition expenses and merger commitment costs for the year ended December 31, 2018 of approximately $237.2 million were incurred and included in the Consolidated Statements of Income (2017 — $65.7 million).

Upon completion of the WGL Acquisition, AltaGas began consolidating WGL. Since the closing date through December 31, 2018, WGL has generated approximately $1,406 million in revenues and $113 million in net loss after tax. The loss was primarily due to the payment of various regulatory commitments as well as seasonality in certain of WGL’s operating businesses.

The following supplemental unaudited, pro forma consolidated financial information for the years ended December 31, 2018 and 2017 gives effect to the WGL Acquisition as if it had closed on January 1, 2017. This pro forma information is presented for information purposes only and does not purport to be indicative of the results that would have occurred had the WGL Acquisition taken place at the beginning of 2017, nor is it indicative of the results that may be expected in future periods.

				Year ended December 31
	2018			2017
Pro forma revenue	$	5,962		$	5,704
Pro forma net income (loss) after taxes	$	(304	)	$	450

Pro forma revenue excludes the gains and losses on foreign exchange contracts, as these contracts were used to mitigate the foreign exchange risks associated with the cash purchase price of WGL. As such, the gains and losses on these foreign exchange contracts are directly incremental to the WGL Acquisition and are non-recurring in nature. These adjustments

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increased pro forma revenue by $2 million for the year ended December 31, 2018, and increased pro forma revenue by $34 million for the year ended December 31, 2017.

Pro forma net income (loss) after taxes excludes all non-recurring acquisition-related expenses and merger commitment costs incurred by AltaGas and WGL and AltaGas’ realized and unrealized gains and losses on foreign exchange contracts entered into to mitigate the foreign exchange risk associated with the WGL Acquisition. Pro forma net income (loss) after taxes was also adjusted to exclude financing costs associated with the bridge facility for the WGL Acquisition, and amortization of fair value adjustments relating to property, plant and equipment, intangible assets, and other long-term investments as well as tax impacts of all the previously noted adjustments. For the year ended December 31, 2018, the total after-tax pro forma adjustments increased net income (loss) after taxes by $132 million (2017 — $19 million).

4. SALE OF MINORITY INTEREST AND OTHER DISPOSITIONS

Northwest Hydro Facilities

On June 22, 2018, AltaGas completed the disposition of a 35 percent indirect equity interest in the Northwest Hydro facilities for gross cash proceeds of approximately $921.6 million. The disposition was completed through the sale of 35 percent of Northwest Hydro Limited Partnership (NW Hydro LP), a subsidiary of AltaGas which indirectly holds the Northwest Hydro facilities. At December 31, 2018, AltaGas continues to consolidate NW Hydro LP (Note 12). Upon close of the sale, AltaGas recognized a non-controlling interest of $420.4 million, a deferred income tax liability of $153.3 million and contributed surplus of $335.2 million on the Consolidated Balance Sheets, net of transaction costs. There was no impact to the Consolidated Statements of Income upon closing of this transaction.

On December 13, 2018, AltaGas announced that it reached an agreement for the sale of its remaining interest of approximately 55 percent in the Northwest Hydro facilities. The sale was completed in January 2019 (Notes 5 and 33).

Initial Public Offering of AltaGas Canada Inc.

On October 25, 2018, the initial public offering (IPO) of AltaGas Canada Inc. (ACI) was successfully completed, reflecting a final price of $14.50 per common share of ACI. The over-allotment option was exercised in full, and as a result, AltaGas holds approximately 37 percent of ACI common shares at December 31, 2018. Net proceeds to AltaGas (consisting of cash and debt) to AltaGas after the deduction of underwriting fees and expenses were approximately $892.2 million. ACI holds Canadian rate-regulated natural gas distribution utility assets and contracted wind power in Canada, as well as an approximate 10 percent indirect equity interest in the Northwest Hydro facilities.

In addition to a pre-tax provision of $193.7 million, AltaGas recognized a pre-tax loss on disposition of $0.5 million in the Consolidated Statement of Income under the line item “other income” for the year ended December 31, 2018.

Non-Core San Joaquin Power Assets in California

On November 13, 2018, AltaGas completed the disposition of the San Joaquin facilities for a sale price of approximately US$299.4 million. The assets comprise the Tracy, Hanford and Henrietta plants totaling 523 MW of capacity. In addition to a pre-tax provision of $340.6 million, AltaGas recognized a pre-tax loss on disposition of $14.4 million in the Consolidated Statements of Income under the line item “other income” for the year ended December 31, 2018.

Other U.S. Power Assets

On December 11, 2018, AltaGas completed the disposition of Busch Ranch, a wind asset in the United States, for a sale price of approximately US$16.3 million. AltaGas recognized a pre-tax gain on disposition of $3.2 million in the Consolidated Statements of Income under the line item “other income” for the year ended December 31, 2018.

Other Dispositions

In March 2018, AltaGas completed the disposition of the Acme and Shaunavon gas processing facilities in the Midstream segment for gross proceeds of approximately $7.0 million. As a result, AltaGas recognized a pre-tax gain on disposition of

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approximately $1.3 million in the Consolidated Statements of Income under the line item “other income” for the year ended December 31, 2018.

In March 2017, AltaGas completed the disposition of the Ethylene Delivery Systems (EDS) and the Joffre Feedstock Pipeline (JFP) transmission assets in the Midstream segment to Nova Chemicals Corporation for gross proceeds of approximately $67.0 million. AltaGas recognized a pre-tax loss on disposition of approximately $3.4 million in the Consolidated Statement of Income under the line item “other income” for the year ended December 31, 2017 related to this disposition.

5.  ASSETS HELD FOR SALE

As at	December 31, 2018		December 31, 2017
Assets held for sale
Cash	$	4.9	$	—
Accounts receivable	85.2		0.3
Inventory	0.5		—
Property, plant and equipment	1,189.6		5.3
Intangible assets	248.7		0.1
Goodwill	—		0.3
	$	1,528.9	$	6.0
Liabilities associated with assets held for sale
Accounts payable and accrued liabilities	$	23.8	$	—
Asset retirement obligations	10.8		0.3
Other long-term liabilities	136.8		—
	$	171.4	$	0.3

Non-Core Midstream and Power Assets in Canada

In the third quarter of 2018, AltaGas entered into definitive agreements for the sale of selected non-core smaller scale gas midstream and power assets in Canada, as well as AltaGas’ commercial and industrial customer portfolio in Canada, for an aggregate purchase price of approximately $165.0 million. The transaction is subject to customary closing conditions and approvals, and was completed in February 2019. Accordingly, the carrying value of the assets and liabilities was classified as held for sale, which resulted in the reclassification of assets totaling $102.1 million to assets held for sale and liabilities totaling $10.8 million to liabilities associated with assets held for sale on the Consolidated Balance Sheets. Pre-tax provisions of $121.4 million on property, plant and equipment, $0.5 million on intangible assets, and $5.1 million on goodwill were recognized in 2018 due to the reduction of the carrying value of the assets to fair value less costs to sell. These assets are recorded in the Midstream and Power segments.

The transaction also includes the 43.7 million shares of Tidewater Midstream and Infrastructure Inc. previously held by AltaGas. This portion of the transaction was completed in September 2018 (Note 11).

Northwest Hydro Facilities

On December 13, 2018, AltaGas announced that it has reached an agreement for the sale of its remaining indirect equity interest of approximately 55 percent in the Northwest Hydro facilities for proceeds of approximately $1.37 billion. The transaction was completed in January 2019. Accordingly, the carrying value of the assets and liabilities was classified as held for sale, which resulted in the reclassification of $1,350.2 million of assets to assets held for sale and $160.6 million of liabilities to liabilities associated with assets held for sale on the Consolidated Balance Sheets. These assets are recorded in the Power segment.

Included within liabilities associated with assets held for sale is the Northwest Hydro NTL liability. In 2010, AltaGas entered into a 60-year CPI-indexed Electricity Purchase Agreement (EPA) and other related agreements with BC Hydro for the 195-MW Forrest Kerr run-of-river hydroelectric facility. As part of the related agreements, AltaGas agreed to pay BC Hydro annual

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payments of approximately $11.0 million per year, adjusted for inflation, in support of the construction and operation of the Northwest Transmission Line (NTL) until 2034. With the agreement for the sale of AltaGas’ remaining indirect equity interest in the Northwest Hydro facilities, this liability has been reclassified to liabilities associated with assets held for sale.

Architect of the Capitol (AOC) Project

In the fourth quarter of 2018, WGL Energy Systems reached an agreement for the sale of a financing receivable related to the construction of an energy management services project. The transaction is subject to customary closing conditions, and is expected to be completed in the first quarter of 2019. Accordingly, the carrying value of the asset was classified as held for sale, which resulted in the reclassification of $76.6 million of accounts receivable to assets held for sale on the Consolidated Balance Sheets. A pre-tax provision of $6.0 million was recognized in 2018 due to the reduction of the carrying value of the receivable to fair value less costs to sell. This asset is recorded in the Power segment.

6.  INVENTORY

	December 31,		December 31,
As at	2018		2017
Natural gas held in storage	$	418.0	$	133.9
Materials and supplies	53.3		32.3
Renewable energy credits and emission compliance instruments	38.2		28.4
Other inventory	6.4		6.5
	$	515.9	$	201.1

7.  PROPERTY, PLANT AND EQUIPMENT

	December 31, 2018									December 31, 2017
As at	Cost			Accumulated amortization			Net book value			Cost			Accumulated amortization			Net book value
Utilities	$	7,090.5		$	(89.7	)	$	7,000.8		$	2,245.4		$	(226.1	)	2,019.3
Midstream	3,178.2			(845.7		)	2,332.5			2,801.4			(636.3		)	$	2,165.1
Power	4,633.9			(1,858.3		)	2,775.6			2,874.8			(392.3		)	2,482.5
Corporate	49.4			(39.1		)	10.3			65.9			(37.7		)	28.2
Reclassified to assets held for sale (note 5)	(2,999.3		)	1,809.7			(1,189.6		)	(16.7		)	11.4			(5.3		)
	$	11,952.7		$	(1,023.1	)	$	10,929.6		$	7,970.8		$	(1,281.0	)	$	6,689.8

Interest capitalized on long-term capital construction projects for the year ended December 31, 2018 was $12.6 million (2017 - $10.8 million).

As at December 31, 2018, the Corporation had approximately $872.7 million (December 31, 2017 - $269.5 million) of capital projects under construction that were not yet subject to amortization.

Depreciation expense related to property, plant and equipment (including assets under capital leases) for the year ended December 31, 2018 was $324.3 million (2017 - $239.7 million).

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8.  INTANGIBLE ASSETS

	December 31, 2018									December 31, 2017
As at	Cost			Accumulated amortization			Net book value			Cost			Accumulated amortization			Net book value
E&T contracts	$	26.6		$	(14.3	)	$	12.3		$	26.6		$	(13.4	)	$	13.2
Electricity service agreements	269.5			(25.9		)	243.6			603.1			(108.5		)	494.6
Energy services relationships	176.1			(33.8		)	142.3			10.2			(8.1		)	2.1
Software	293.9			(77.7		)	216.2			126.8			(61.6		)	65.2
Land rights	1.4			(0.2		)	1.2			11.0			(2.4		)	8.6
Commodity contracts	346.3			(6.3		)	340.0			—			—			—
Franchises and consents	5.0			—			5.0			7.4			(2.2		)	5.2
Reclassified to assets held for sale (note 5)	(277.4		)	28.7			(248.7		)	(0.1		)	—			(0.1		)
	$	841.4		$	(129.5	)	$	711.9		$	785.0		$	(196.2	)	$	588.8

Amortization expense related to intangible assets for the year ended December 31, 2018 was $69.7 million (2017 - $42.7 million).

As at December 31, 2018, the Corporation excluded $196.4 million (December 31, 2017 - $11.2 million) from the asset base subject to amortization. Items excluded related to gas transportation capacity contracts, software assets under development, and assets with an indefinite life.

The following table sets forth the estimated amortization expense of intangible assets, excluding any amortization of assets not yet subject to amortization as well as assets with an indefinite life, for the years ended December 31:

2019	$	84.2
2020	$	82.5
2021	$	57.6
2022	$	132.3
2023	$	38.3
Thereafter	$	120.6

9.  GOODWILL

	December 31,			December 31,
As at	2018			2017
Balance, beginning of year	$	817.3		$	856.0
Provisions on assets (notes 5 and 10)	(124.2		)	—
Business acquisition (note 3)	3,196.4			—
Foreign exchange translation	178.7			(38.4		)
Reclassified to assets held for sale	—			(0.3		)
Balance, end of year	$	4,068.2		$	817.3

10.  PROVISIONS ON ASSETS

Year ended December 31	2018		2017
Utilities	$	193.7	$	—
Midstream	153.7		6.6
Power	381.3		133.0
	$	728.7	$	139.6

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Utilities

In 2018, AltaGas recorded pre-tax provisions of $193.7 million related to certain rate-regulated natural gas distribution utility assets that were classified as held for sale in the third quarter of 2018. The pre-tax provision was comprised of $119.1 million on goodwill and $74.6 million on property, plant and equipment. No provisions on assets were recorded in 2017 for the Utilities segment.

Midstream

In 2018, AltaGas recorded pre-tax provisions totaling $153.7 million in the Midstream segment. The pre-tax provisions included $117.2 million related to certain non-core midstream assets that are classified as held for sale at December 31, 2018 (Note 5) and $36.5 million related to shut-in assets in the South, Cold Lake and Northwest operating areas. The total pre-tax provisions of $153.7 million were comprised of $148.1 million on property, plant, and equipment, $0.5 million on intangible assets, and $5.1 million on goodwill.

In 2017, AltaGas recorded a pre-tax provision on assets of $6.6 million on a non-core gas processing facility that was classified as held for sale (Note 5).

Power

In 2018, AltaGas recorded pre-tax provisions totaling $381.3 million in the Power segment. Of this, $340.6 million related to the Tracy, Hanford, and Henrietta gas-fired peaking plants in California that were disposed of in November 2018. The pre-tax provision on the California power assets was comprised of $221.3 million on property, plant, and equipment and $119.3 million on intangible assets. In addition, pre-tax provisions of $9.8 million were recorded on certain non-core power assets in Canada that are classified as held for sale at December 31, 2018 (Note 5), $23.1 million on a development project in the U.S., $1.8 million on the Pomona natural gas-fired co-generation facility in the United States, and $6.0 million on a WGL Energy Systems financing receivable that was classified as held for sale at December 31, 2018 (Note 5).

In 2017, AltaGas recognized pre-tax provisions on assets related to the Hanford and Henrietta gas-fired peaking plants in California, certain non-core development stage gas-fired peaking projects in California, and the Kent development project in Alberta of $133.0 million. The pre-tax provisions of $133.0 million were comprised of $48.5 million on intangible assets and $84.5 million on property, plant and equipment.

11.  LONG-TERM INVESTMENTS AND OTHER ASSETS

As at	December 31, 2018		December 31, 2017
Investments in publicly-traded entities	$	8.4	$	95.0
Loan to affiliate (note 30)	45.0		75.0
Deferred lease receivable	24.4		29.0
Debt issuance costs associated with credit facilities	7.9		20.3
Refundable deposits	16.2		14.9
Prepayment on long-term service agreements	82.5		68.1
Subscription receipts issuance costs	—		1.7
Contract asset (note 23)	11.5		—
Rabbi trust (note 28)	61.7		—
Other	25.5		8.6
	$	283.1	$	312.6

In 2018, as part of the agreement for the sale of non-core midstream and power assets in Canada, AltaGas sold 43.7 million shares of Tidewater Midstream and Infrastructure Inc. for gross proceeds of $63.4 million. For the year ended December 31, 2018, a realized loss of $2.0 million was recognized in the Consolidated Statements of Income under the line item “other income” in relation to the sale of these shares.

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12. VARIABLE INTEREST ENTITIES

Consolidated VIEs

AltaGas consolidates VIEs where the Corporation is deemed the primary beneficiary. The primary beneficiary of a VIE has the power to direct the activities of the entity that most significantly impact its economic performance such as being the provider of construction, operating and marketing services to the entity. In addition, the primary beneficiary of a VIE also has the obligation to absorb losses of the entity or the right to receive benefits that could potentially be significant to the VIE. AltaGas determined that it is the primary beneficiary of the following VIEs:

Northwest Hydro Limited Partnership

On May 4, 2018, NW Hydro LP was formed to indirectly hold the assets of the Northwest Hydro facilities. On June 22, 2018, AltaGas closed the sale of a 35 percent indirect equity interest in its Northwest Hydro facilities through the sale of 35 percent of NW Hydro LP, and its general partner, Northwest Hydro GP Inc. (NW Hydro GP).

AltaGas has determined that NW Hydro LP is a VIE in which it holds variable interests and is the primary beneficiary. In the determination that AltaGas is the primary beneficiary of the VIE, AltaGas noted that it has the power to direct the activities that most significantly impact the VIE’s economic performance through the continued provision of all operational, maintenance and management functions for the Northwest Hydro facilities. In addition, AltaGas has the obligation to absorb the losses and the right to receive the benefits that could potentially be significant to the Northwest Hydro facilities. As such, AltaGas has consolidated NW Hydro LP and has recorded $420.4 million of the $921.6 million proceeds received as a non-controlling interest with the remainder of the proceeds, less deferred tax and transaction costs, recognized as contributed surplus in the amount of $334.6 million.

On December 13, 2018, AltaGas announced that it has reached an agreement for the sale of its remaining indirect equity interest of approximately 55 percent in the Northwest Hydro facilities (including NW Hydro LP) for proceeds of approximately $1.37 billion. The transaction was subject to customary closing conditions and approvals, and closed in January 2019. The assets and liabilities of NW Hydro LP have been classified as held for sale at December 31, 2018 (Note 5).

The assets of NW Hydro LP are the property of NW Hydro LP and are not available to AltaGas for any other purpose. NW Hydro LP’s asset balances can only be used to settle its own obligations. The liabilities of NW Hydro LP do not represent additional claims against AltaGas’ general assets. AltaGas’ exposure to loss as a result of its interest as a limited partner is its net investment.

Ridley Island LPG Export Limited Partnership

On May 5, 2017, AltaGas LPG Limited Partnership (AltaGas LPG), a wholly-owned subsidiary of AltaGas, and Vopak Development Canada Inc. (Vopak), a wholly-owned subsidiary of Koninklijke Vopak N.V. (Royal Vopak), a public company incorporated under the laws of the Netherlands, formed the Ridley Island LPG Export Limited Partnership (RILE LP) to develop, own and operate the Ridley Island Propane Export Terminal (RIPET). AltaGas’ subsidiaries hold a 70 percent interest while Vopak holds a 30 percent interest in RILE LP. The construction cost of RIPET, which is estimated to be $450 to $500 million, will be funded by AltaGas LPG and Vopak in proportion to their respective interests in RILE LP. As part of the arrangements, AltaGas entered into a long-term agreement for the capacity of RIPET with RILE LP, and AltaGas and certain of its subsidiaries will provide construction and operating services to RILE LP.

AltaGas has determined that RILE LP is a VIE in which it holds variable interests and is the primary beneficiary. In the determination that AltaGas is the primary beneficiary of the VIE, AltaGas noted that it has the power to direct the activities that most significantly impact the VIE’s economic performance through the construction, operating and marketing services provided to RILE LP. In addition, AltaGas has the obligation to absorb the losses and the right to receive the benefits that could potentially be significant to RILE LP through the long-term agreement for the capacity of RIPET. As such, AltaGas has consolidated RILE LP and recorded $20.0 million of the $24.1 million proceeds received from Vopak on formation of RILE LP as a non-controlling interest with the remainder of the proceeds less deferred tax recognized as contributed surplus in the amount of $3.0 million.

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The assets of RILE LP are the property of RILE LP and are not available to AltaGas for any other purpose. RILE LP’s asset balances can only be used to settle its own obligations. The liabilities of RILE LP do not represent additional claims against AltaGas’ general assets. AltaGas’ exposure to loss as a result of its interest as a limited partner is its net investment. AltaGas and Royal Vopak have provided limited guarantees for the obligations of their respective subsidiaries for the construction cost of RIPET. Upon commencement of commercial operations at RIPET, the terms of the long-term capacity agreement between AltaGas LPG and RILE LP provide for a return on and of capital and reimbursement of RIPET operating costs by AltaGas LPG in accordance with the terms set out in the agreement.

Variable Interest Entities Acquired in WGL Acquisition

In connection with the WGL Acquisition (Note 3), AltaGas has acquired both consolidated and unconsolidated VIEs:

Consolidated VIE Investments

At December 31, 2018, WGSW Inc. (WGSW) was the primary beneficiary of SFGF LLC (SFGF), SFRC, LLC (SFRC), SFGF II, LLC (SFGF II), SFEE LLC (SFEE), and ASD Solar LP (ASD), because of its ability to direct the activities most significant to the economic performance of those entities plus the right to receive potentially significant benefits or the obligation to absorb potentially significant losses. Accordingly, these VIEs have been consolidated:

SFGF, SFRC, and SFGF II

WGSW, along with its various tax equity partners, formed the tax equity partnerships SFGF, SFRC, and SFGF II to acquire, own, and operate distributed generation solar projects nationwide. WGSW is the managing member of these investments and will provide cash equal to the purchase price of the solar projects less any contributions from the tax-equity partner for projects sold into the partnerships. WGL Energy Systems is the developer of the projects and sells them to the partnerships, and is the operations and maintenance provider. Profits and losses are allocated between the partners under the HLBV method of accounting and the portion allocated to the tax equity partner is included in “net income (loss) attributable to non-controlling interest” on the accompanying Consolidated Statements of Income and is recorded to non-controlling interest on the accompanying Consolidated Balance Sheets.

SFEE

In 2016, WGSW and a tax equity partner formed SFEE to acquire distributed generation solar projects that were to be developed and sold by a third-party developer or WGL Energy Systems. New projects were to be designed and constructed under long-term power purchase agreements. SFEE is considered a VIE and is consolidated by WGSW.

ASD

WGSW is a limited partner in ASD, a limited partnership formed to own and operate a portfolio of residential solar projects, primarily rooftop photovoltaic power generation systems. SF ASD, a wholly-owned subsidiary of WGL Energy Systems, has management rights and control of ASD.

The following table represents amounts included in the Consolidated Balance Sheets attributable to AltaGas’ consolidated VIEs:

	December 31,			December 31,
As at	2018			2017
Current assets	$	1,383.5		$	1.4
Property, plant and equipment	619.2			84.3
Long-term investments and other assets	48.0			48.0
Current liabilities	(161.8		)	—
Asset retirement obligations	(0.9		)	—
Deferred tax credits	(3.0		)	—
Net assets	$	1,885.0		$	133.7

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Unconsolidated VIE Investments

Meade Pipeline Co. LLC (Meade)

In 2014, WGL Midstream and certain partners entered into a limited liability company agreement and formed Meade, a Delaware limited liability company, to develop and own, jointly with Transcontinental Gas Pipe Line Company, LLC, a regulated pipeline, Central Penn Pipeline (Central Penn), a segment of the larger Atlantic Sunrise project. Central Penn is an approximately 185-mile pipeline originating in Susquehanna County, Pennsylvania and extending to Lancaster County, Pennsylvania with the capacity to transport and deliver up to approximately 1.7 Bcf per day of natural gas.

As at December 31, 2018, AltaGas held an equity investment in Meade with a carrying value of $666.9 million, inclusive of fair value adjustments on acquisition date (Note 3). WGL Midstream owns a 55 percent interest in Meade (21 percent indirect interest in Central Penn) and on a cash basis, as of December 31, 2018, WGL Midstream has spent approximately US$446 million as its share of the construction costs. Although WGL Midstream holds greater than a 50 percent interest in Meade, Meade is not consolidated by WGL Midstream and instead is accounted for under the equity method of accounting. WGL Midstream is not the primary beneficiary of Meade as it does not have the power to direct the activities most significant to the economic performance of Meade. WGL Midstream applies the HLBV equity method of accounting and any profits and losses are included in “income from equity investments” in the accompanying Consolidated Statements of Income and are added to or subtracted from the carrying amount of AltaGas’ investment balance.

The maximum financial exposure to loss as a result of the involvement with this VIE is equal to WGL Midstream’s capital contributions.

13. INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD

		Ownership	Carrying value as at December 31				Equity income (loss) for the year ended December 31
Description	Location	Percentage	2018		2017		2018			2017
AltaGas Canada Inc. (ACI)	Canada	36.75	$	112.5	$	—	$	5.4		$	—
AltaGas Idemitsu Joint Venture LP (AIJVLP)	Canada	50	342.9		323.3		2.1			6.6
Constitution Pipeline, LLC (Constitution)	United States	10	—		—		(0.2		)	—
Craven County Wood Energy LP	United States	50	7.8		20.9		(14.1		)	3.3
Eaton Rapids Gas Storage System	United States	50	29.4		26.4		2.0			2.5
Grayling Generating Station LP	United States	50	29.0		27.6		3.6			3.5
Inuvik Gas Ltd. (a)	Canada	33.333	—		—		(0.2		)	—
Meade Pipeline Co. LLC (Meade) (b)	United States	55	757.8		—		12.2			—
Mountain Valley Pipeline, LLC (Mountain Valley)	United States	10	532.5		—		11.5			—
Sarnia Airport Storage Pool LP	Canada	50	18.7		18.8		1.0			1.0
Petrogas Preferred Shares	Canada	n/a	150.0		150.0		12.8			12.8
Tidewater Midstream and Infrastructure Ltd. (c)	Canada	n/a	—		—		—			1.7
Stonewall Gas Gathering Systems LLC	United States	30	411.8		—		11.8			—
			$	2,392.4	$	567.0	$	47.9		$	31.4

(a)Inuvik Gas Ltd. was sold to AltaGas Canada Inc. in October 2018.

(b)Meade is a VIE (Note 12).

(c)AltaGas sold 43.7 million shares of Tidewater Midstream and Infrastructure Inc. in September 2018 (Note 11).

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Summarized combined financial information, assuming a 100 percent ownership interest in AltaGas’ equity investments listed above, is as follows:

Year ended December 31	2018			2017
Revenues	$	351.6		$	110.6
Expenses	(142.7		)	(74.2		)
	$	208.9		$	36.4

As at December 31	2018			2017
Current assets	$	1,204.6		$	24.8
Property, plant and equipment	$	7,602.5		$	82.8
Intangible assets	$	22.9		$	5.6
Long-term investments and other assets	$	1,326.6		$	843.3
Current liabilities	$	(1,015.2	)	$	(41.7	)
Other long-term liabilities	$	(949.6	)	$	(189.1	)

Petrogas Preferred Shares

AltaGas, indirectly through its investment in AIJVLP, holds a one-third equity interest in Petrogas. In 2016, AltaGas directly invested $150.0 million to subscribe for 6,000,000 cumulative redeemable convertible preferred shares of Petrogas. These preferred shares form part of AltaGas’ overall investment in Petrogas and entitle AltaGas to a fixed, cumulative, preferential cash dividend at a rate of 8.5 percent per annum payable quarterly. These preferred shares are, in the normal course, redeemable at any time on or after January 1, 2018 and convertible into a specified number of common shares at the option of either holder at any time on or after April 19, 2018. For the year ended December 31, 2018, AltaGas received dividend income of $12.8 million (2017 - $12.8 million) from the Petrogas preferred shares, which has been included in the Consolidated Statement of Income under the line item “income from equity investments”.

AltaGas Canada Inc.

As at December 31, 2018, AltaGas owns an approximate 37 percent equity interest in ACI. On October 25, 2018, the ACI IPO was successfully completed reflecting a final price of $14.50 per common share of ACI (Note 4). ACI holds Canadian rate-regulated natural gas distribution utility assets and contracted wind power in Canada, as well as an approximate 10 percent interest in the Northwest Hydro facilities.

Equity Method Investments Acquired in WGL Acquisition

In connection with the WGL Acquisition (Note 3), AltaGas acquired the following investments accounted for by the equity method that are not considered VIEs:

Mountain Valley Pipeline, LLC (Mountain Valley)

WGL Midstream owns a 10 percent equity interest in Mountain Valley Pipeline, LLC. The proposed pipeline, which will be operated by EQM Gathering Opco, LLC (EQM) and developed, constructed, and owned by Mountain Valley (a venture of EQT Midstream Partners LP (EQT) and other entities), will transport approximately 2.0 Bcf of natural gas per day and will extend from Equitrans, LP’s system in Wetzel County, West Virginia to Transcontinental Gas Pipe Line Company LLC’s Station 165 in Pittsylvania County, Virginia. The pipeline is expected to span approximately 300 miles.

At December 31, 2018, AltaGas held an equity investment in Mountain Valley with a carrying value of $532.5 million, inclusive of fair value adjustments on acquisition date (Note 3). WGL Midstream expects to invest approximately US$350 million in scheduled capital contributions through the in-service date of the pipeline based on its contracted share of project costs. The equity method is considered appropriate because Mountain Valley is a Limited Liability Company (LLC) with specific ownership accounts and ownership between five and fifty percent resulting in WGL Midstream maintaining a more than minor influence over the partnership operating and financing policies. Profits and losses are allocated under the HLBV method of accounting and are

31

included in income from equity investments in the accompanying Consolidated Statements of Income and are added to or subtracted from the carrying amount of AltaGas’ investment balance.

In April 2018, WGL Midstream entered into a separate agreement with EQM to acquire a 5 percent equity interest in a project to build a lateral interstate natural gas pipeline connecting to the Mountain Valley Pipeline.

Stonewall Gas Gathering System (Stonewall)

WGL Midstream has a 30 percent equity interest in an entity that owns and operates certain assets known as the Stonewall Gas Gathering System. Stonewall has the capacity to gather up to 1.4 Bcf of natural gas per day from the Marcellus production region in West Virginia, and connects with an interstate pipeline system that serves markets in the mid-Atlantic region. As at December 31, 2018, the carrying value of the equity investment in Stonewall was $411.8 million, inclusive of fair value adjustments on acquisition date (Note 3). Profits and losses are allocated under the HLBV method of accounting and are included in income from equity investments in the accompanying Consolidated Statements of Income.

Constitution Pipeline Company, LLC (Constitution)

WGL Midstream has an investment in Constitution, owning a 10 percent equity interest in the proposed pipeline venture. At December 31, 2018, the carrying value of the equity investment in Constitution was $nil, reflecting AltaGas’ fair value on acquisition date (Note 3). This natural gas pipeline venture is proposed to transport natural gas from the Marcellus region in northern Pennsylvania to major northeastern markets.

In addition to the above non-VIE equity investments acquired in the WGL Acquisition, the Company’s investment in Meade (Note 12) is also accounted for using the equity method.

Provisions on investments accounted for by the equity method

During the year ended December 31, 2018, AltaGas recorded a pre-tax provision of $14.5 million against AltaGas’ investment in Craven Wood County Energy LP. No provisions were recorded for the year ended December 31, 2017.

14.  SHORT-TERM DEBT

As at	December 31, 2018		December 31, 2017
Bank indebtedness (a)	$	0.2	$	6.2
US$150 million operating facility (b)	—		31.7
$ 25 million operating facility (c)	—		8.9
Commercial paper (d)	1,145.2		—
Project financing	64.5		—
	$	1,209.9	$	46.8

(a)Bank indebtedness bears interest at the lender’s prime rate or at the interest rate applicable to bankers’ acceptances. The prime lending rate at December 31, 2018 was 3.95 percent (December 31, 2017 — 3.2 percent).

(b)As at December 31, 2018, SEMCO held a US$150 million (December 31, 2017 - US$150.0 million) unsecured revolving operating credit facility with a Canadian chartered bank with a maturity date of December 20, 2023. Draws on the facility can be by way of U.S. base-rate loans, letters of credit and LIBOR loans. Letters of credit outstanding under this facility as at December 31, 2018 were $0.7 million (December 31, 2017 - $0.6 million).

(c)Upon completion of the ACI IPO, the operating facility was transferred to ACI.

(d)WGL and Washington Gas use short-term debt in the form of commercial paper or unsecured short-term bank loans to fund seasonal cash requirements. Revolving committed credit facilities are maintained in an amount equal to or greater than the expected maximum commercial paper position.

Other Credit Facilities

As at December 31, 2018, the Corporation held a $70.0 million (December 31, 2017 - $50.0 million) unsecured demand revolving operating credit facility with a Canadian chartered bank. Draws on the facility bear interest at the lender’s prime rate or at the bankers’ acceptance rate plus a stamping fee. Letters of credit outstanding under this facility as at December 31, 2018 were $nil (December 31, 2017 - $nil).

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As at December 31, 2018, AltaGas held a $150.0 million (December 31, 2017 - $150.0 million) unsecured four-year extendible revolving letter of credit facility. Draws on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers’ acceptances or letters of credit. Letters of credit outstanding under this facility as at December 31, 2018 were $117.0 million (December 31, 2017 - $40.8 million).

As at December 31, 2018, AltaGas held a US$200.0 million (December 31, 2017 - $150.0 million) unsecured bilateral letter of credit demand facility with a Canadian chartered bank. Borrowings on the facility incur fees and interest at rates relevant to the nature of the draws made. Letters of credit outstanding under this facility as at December 31, 2018 were $147.3 million (December 31, 2017 - $71.3 million).

As at December 31, 2018, AltaGas held a $35.0 million (December 31, 2017 - $nil) unsecured demand revolving operating credit facility with a Canadian chartered bank. Draws on the facility bear interest at the lender’s prime rate or at the bankers’ acceptance rate plus a stamping fee. Letters of credit outstanding under this facility as at December 31, 2018 were $6.0 million (December 31, 2017 - $nil).

As at December 31, 2018, AltaGas held a US$300.0 million (December 31, 2017 - $nil) unsecured extendible revolving letter of credit facility. Borrowings on the facility incur fees and interest at rates relevant to the nature of the draws made. Letters of credit outstanding on this facility as at December 31, 2018 were $nil (December 31, 2017 - $nil).

Credit Facilities Acquired in WGL Acquisition

As at December 31, 2018, WGL held a US$650.0 million unsecured revolving credit facility. Draws on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers’ acceptances or letters of credit. There were no outstanding bank loans under this facility as at December 31, 2018.

As at December 31, 2018, Washington Gas held a US$350.0 million (December 31, 2017 - $nil) unsecured revolving credit facility. Draws on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers’ acceptances or letters of credit. There were no outstanding bank loans under this facility as at December 31, 2018.

WGL and Washington Gas use short-term debt in the form of commercial paper or unsecured short-term bank loans to fund seasonal cash requirements. Revolving committed credit facilities are maintained in an amount equal to or greater than the expected maximum commercial paper position. At December 31, 2018, commercial paper outstanding totaled US$839.5 million for WGL and Washington Gas.

Project Financing

Washington Gas previously obtained third-party project financing on behalf of the United States federal government to provide funds during the construction of certain energy management services projects entered into under Washington Gas’ area-wide contract. When these projects are formally accepted by the government and deemed complete, Washington Gas assigns the ownership of the receivable to the third-party lender in satisfaction of the obligation, removing both the receivable and the obligation related to the financing from the Consolidated Financial Statements. At December 31, 2018, draws related to project financing were $64.5 million (December 31, 2017 - $nil).

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15.  LONG-TERM DEBT

		December 31,			December 31,
As at	Maturity date	2018			2017
Credit facilities
$1,400 million unsecured extendible revolving(a)	15-May-2023	$	964.7		$	219.1
US$300 million unsecured extendible revolving(b)	15-May-2022	287.8			—
Acquisition credit facility	6-Jan-2020	113.2			—
US$1,200 million revolving credit facility(g)	28-Dec-2021	1,637.0			—
Medium-term notes (MTNs)
$175 million Senior unsecured - 4.60 percent	15-Jan-2018	—			175.0
$200 million Senior unsecured - 4.55 percent	17-Jan-2019	200.0			200.0
$200 million Senior unsecured - 4.07 percent	1-Jun-2020	200.0			200.0
$350 million Senior unsecured - 3.72 percent	28-Sep-2021	350.0			350.0
$300 million Senior unsecured - 3.57 percent	12-Jun-2023	300.0			300.0
$200 million Senior unsecured - 4.40 percent	15-Mar-2024	200.0			200.0
$300 million Senior unsecured - 3.84 percent	15-Jan-2025	299.9			299.9
$100 million Senior unsecured - 5.16 percent	13-Jan-2044	100.0			100.0
$300 million Senior unsecured - 4.50 percent	15-Aug-2044	299.8			299.8
$350 million Senior unsecured - 4.12 percent	7-Apr-2026	349.8			349.8
$200 million Senior unsecured - 3.98 percent	4-Oct-2027	199.9			199.9
$250 million Senior unsecured - 4.99 percent	4-Oct-2047	250.0			250.0
WGL and Washington Gas medium-term notes
US$500 million Senior unsecured - 2.25 to 4.76 percent	Jan - Nov 2019	682.1			—
US$250 million Senior unsecured - 2.88 percent	12-Mar-2020	341.1			—
US$20 million Senior unsecured - 6.65 percent	20-Mar-2023	27.3			—
US$40.5 million Senior unsecured - 5.44 percent	11-Aug-2025	55.3			—
US$53 million Senior unsecured - 6.62 to 6.82 percent	Oct - 2026	72.3			—
US$72 million Senior unsecured - 6.40 to 6.57 percent	Feb - Sep 2027	98.2			—
US$52 million Senior unsecured - 6.57 to 6.85 percent	Jan - Mar 2028	70.9			—
US$8.5 million Senior unsecured - 7.50 percent	1-Apr-2030	11.6			—
US$50 million Senior unsecured - 5.70 to 5.78 percent	Jan - Mar 2036	68.2			—
US$75 million Senior unsecured - 5.21 percent	3-Dec-2040	102.3			—
US$75 million Senior unsecured - 5.00 percent	15-Dec-2043	102.3			—
US$300 million Senior unsecured - 4.22 to 4.60 percent	Sep - Dec 2044	409.3			—
US$450 million Senior unsecured - 3.80 percent	15-Sep-2046	613.9			—
SEMCO long-term debt
US$300 million SEMCO Senior secured - 5.15 percent(d)	21-Apr-2020	409.3			376.4
US$82 million CINGSA Senior secured - 4.48 percent(e)	2-Mar-2032	86.3			85.2
Debenture notes
PNG 2018 Series Debenture - 8.75 percent (c)(f)	15-Nov-2018	—			7.0
PNG 2025 Series Debenture - 9.30 percent (c)(f)	18-Jul-2025	—			13.0
PNG 2027 Series Debenture - 6.90 percent (c)(f)	2-Dec-2027	—			14.0
CINGSA capital lease - 3.50 percent	1-May-2040	0.6			0.5
CINGSA capital lease - 4.48 percent	4-Jun-2068	0.2			0.2
Fair value adjustment on WGL Acquisition (note 3)		89.0			—
		$	8,992.3		$	3,639.8
Less debt issuance costs		(35.2		)	(14.4		)
		8,957.1			3,625.4
Less current portion		(890.2		)	(188.9		)
		$	8,066.9		$	3,436.5

(a)Borrowings on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers’ acceptances or letters of credit. Borrowings on the facility have fees and interest at rates relevant to the nature of the draw made.

(b)Borrowings on the facility can be by way of U.S. base rate loans, U.S. prime loans, LIBOR loans, or letters of credit.

(c)Collateral for the Secured Debentures and secured extendible revolving credit facility consisted of a specific first mortgage on substantially all of PNG’s property, plant and equipment, and gas purchase and gas sales contracts, and a first floating charge on other property, assets and undertakings.

(d)Collateral for the US$ MTNs is certain SEMCO assets.

(e)Collateral for the CINGSA Senior secured loan is certain CINGSA assets, Alaska Storage Holding Company, LLC, a subsidiary in which AltaGas has a controlling interest, is the non-recourse guarantor of this loan.

(f)PNG debentures totaling $33.3 million have been sold to ACI (Note 4)

(g)Borrowings on the facility can be by way of U.S. base rate loans, U.S. prime loans, or LIBOR loans.

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16.  ASSET RETIREMENT OBLIGATIONS

As at	December 31, 2018			December 31, 2017
Balance, beginning of year	$	88.3		$	81.6
Obligations acquired (note 3)	399.1			—
New obligations	3.3			1.5
Obligations settled	(4.2		)	(4.0		)
Disposals	(1.6		)	—
Revision in estimated cash flow	3.8			6.0
Accretion expense (a)	12.3			4.4
Foreign exchange translation	20.3			(0.9		)
Reclassified to liabilities associated with assets held for sale (note 5)	(10.8		)	(0.3		)
Total	510.5			88.3
Less current portion (included in accounts payable and accrued liabilities)	(9.9		)	—
Balance, end of year	$	500.6		$	88.3

(a)The majority of accretion expense is recorded through the Consolidated Statement of Income. Certain amounts relating to Washington Gas’ Utility asset retirement obligations are recorded through regulatory liabilities on the Consolidated Balance Sheets due to regulatory treatment.

The majority of the asset retirement obligations are associated with distribution and transmission systems in the Utilities segment.

AltaGas estimates the undiscounted cash required to settle the asset retirement obligations, excluding growth for inflation, at December 31, 2018 was $770.0 million (December 31, 2017 - $232.9 million).

The asset retirement obligations have been recorded in the Consolidated Financial Statements at estimated values discounted at rates between 1.5 and 8.5 percent and are expected to be incurred between 2019 and 2064. No assets have been legally restricted for settlement of the estimated liability.

17. ENVIRONMENTAL MATTERS

AltaGas is subject to federal, provincial, state and local laws and regulations related to environmental matters. These laws and regulations may require expenditures over a long time frame to control environmental effects. Almost all of the environmental liabilities AltaGas has recorded are for costs expected to be incurred to remediate sites where AltaGas or a predecessor affiliate operated manufactured gas plants (MGPs). Estimates of liabilities for environmental response costs are difficult to determine with precision because of the various factors that can affect their ultimate level. These factors include, but are not limited to, the following:

·the complexity of the site;

·changes in environmental laws and regulations at the federal, state and local levels;

·the number of regulatory agencies or other parties involved;

·new technology that renders previous technology obsolete or experience with existing technology that proves ineffective;

·the level of remediation required; and

·variations between the estimated and actual period of time that must be dedicated to respond to an environmentally-contaminated site.

AltaGas has identified up to twelve sites where it or its predecessors may have operated MGPs. In connection with these operations, AltaGas is aware that coal tar and certain other by-products of the gas manufacturing process are present at or near some former sites and may be present at others.

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At December 31, 2018, a liability of $15.4 million has been recorded on an undiscounted basis related to future environmental response costs (December 31, 2017 - $nil) in the Consolidated Balance Sheets under the line items “accounts payable and accrued liabilities and other long-term liabilities”. These estimates principally include the minimum liabilities associated with a range of environmental response costs expected to be incurred. At December 31, 2018, AltaGas estimated the maximum liability associated with all of its sites to be approximately $40.1 million (December 31, 2017 - $nil). The estimates were determined by AltaGas’ environmental experts, based on experience in remediating MGP sites and advice from legal counsel and environmental consultants. The variation between the recorded and estimated maximum liability primarily results from differences in the number of years that will be required to perform environmental response processes and the extent of remediation that may be required.

At December 31, 2018, AltaGas reported a regulatory asset of $19.9 million (December 31, 2017 - $13.9 million) for the portion of environmental response costs that are expected to be recoverable in future rates.

18.  OTHER LONG-TERM LIABILITIES

As at	December 31, 2018		December 31, 2017
Deferred lease payable	$	13.1	$	2.4
Deferred revenue	3.9		3.8
Customer advances for construction	58.6		40.9
Sundance B PPA termination expense (a)	2.0		4.0
NTL liability (b)	—		142.0
Lease inducement	2.7		3.1
Merger commitments	21.4		—
Other long-term liabilities	20.3		5.7
	$	122.0	$	201.9

(a)On December 16, 2016, AltaGas Pipeline Partnership and the Government of Alberta reached a definitive settlement agreement regarding the termination of the Sundance B PPAs. Under the settlement agreement, AltaGas has agreed to make a total of $6.0 million in cash payments in equal annual installments over three years starting in 2018, $2.0 million of which has been recorded under “accounts payable and accrued liabilities”.

(b)The NTL liability has been reclassified as liabilities associated with assets held for sale (Note 5).

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19.  INCOME TAXES

Year ended December 31	2018			2017
Income (loss) before income taxes - consolidated	$	(716.9	)	$	66.4
Statutory income tax rate (%)	27.0			27.0
Expected taxes at statutory rates	$	(193.6	)	$	17.9
Add (deduct) the tax effect of:
Permanent differences	(1.0		)	9.5
Statutory and other rate differences	(19.6		)	(30.5		)
Rate adjustment for change in tax rates	1.3			(34.1		)
Deferred income tax recovery on regulated assets	(7.3		)	(7.4		)
Tax differences on divestitures and transactions	(32.3		)	6.9
Non-controlling interests	4.7			—
Change in valuation allowance	(22.3		)	4.2
Other	6.9			—
	$	(263.2	)	$	(33.5	)
Income tax provision
Current
Canada	23.7			18.0
United States	0.7			12.5
	$	24.4		$	30.5
Deferred
Canada	(166.1		)	(7.4		)
United States	(121.5		)	(56.6		)
	$	(287.6	)	$	(64.0	)
Effective income tax rate (%)	36.7			(50.5		)

Net deferred income tax liabilities were composed of the following:

As at	December 31, 2018			December 31, 2017
PP&E and intangible assets	$	1,764.6		$	726.5
Regulatory assets	(166.3		)	22.8
Tax pools, deferred financing and compensation	(453.6		)	(302.3		)
Other	(209.9		)	(59.3		)
Valuation allowance	23.1			53.7
	$	957.9		$	441.4

The amount shown on the Consolidated Balance Sheets as deferred income tax liabilities represents the net differences between the tax basis and book carrying values on the Corporation’s balance sheets at enacted tax rates.

The TCJA in the U.S. became law on December 22, 2017. The law includes significant changes to the U.S. corporate income tax system, including a federal corporate rate reduction from 35 percent to 21 percent beginning in 2018, changes to capital depreciation, limitations on the deductibility of interest expense and executive compensation, and the transition of U.S. international taxation from a worldwide tax system to a territorial tax system.

The B.C. government increased the corporate tax rate to 12 percent from 11 percent beginning in 2018.

As at December 31, 2018, the Corporation had tax-effected non-capital losses of approximately $392.1 million, which will be available to offset future taxable income. If not used, these losses will expire between 2023 and 2038.

Uncertain Tax Positions

The Corporation recognizes the benefit of an uncertain tax position only when it is more likely than not that such a position will be sustained by the taxing authorities based on the technical merits of the position. The current and deferred tax impact is equal to

37

the largest amount, considering possible settlement outcomes, that has greater than 50 percent likelihood of being realized upon settlement with the taxing authorities.

On an annual basis, the Corporation and its subsidiaries file tax returns in Canada and various foreign jurisdictions. In Canada, AltaGas’ federal and provincial tax returns for the years 2012 to 2017 remain subject to examination by taxation authorities. In the United States, both the federal and state tax returns filed for the years 2012 to 2017 remain subject to examination by the taxation authorities.

Management determined that the following provision was required for uncertainty on income taxes during the year:

Year ended December 31	2018			2017
Balance, beginning of year	$	5.9		$	2.2
Net changes during the year	(3.7		)	3.7
Balance, end of year	$	2.2		$	5.9

20.  REGULATORY ASSETS AND LIABILITIES

AltaGas accounts for certain transactions in accordance with ASC 980, Regulated Operations. AltaGas refers to this accounting guidance for regulated entities as “regulatory accounting”. Under regulatory accounting, utilities are permitted to defer expenses and income as regulatory assets and liabilities, respectively, in the Consolidated Balance Sheets when it is probable that those expenses and income will be allowed in the rate-setting process in a period different from the period in which they would have been reflected in the Consolidated Statement of Income by a non-rate-regulated entity. These deferred regulatory assets and liabilities are included in the Consolidated Statement of Income in future periods when the amounts are reflected in customer rates. If an application is filed to modify customer rates with certain regulatory commissions, AltaGas is permitted to charge customers new rates, subject to refund, until the regulatory commission renders a final decision. During this interim period, a provision is recorded for a rate refund regulatory liability based on the difference between the amount collected in rates and the amount expected to be recovered from a final regulatory decision.

Management’s assessment of the probability of recovery or pass-through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory agency orders, rules, and rate-making conventions. The relevant regulatory bodies are the MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA.

If, for any reason, the Corporation ceases to meet the criteria for application of regulatory accounting for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be de-recognized from the Consolidated Balance Sheets and included in the Consolidated Statement of Income for the period in which the discontinuance of regulatory accounting occurs. Criteria that give rise to the discontinuance of regulatory accounting include: (i) increasing competition that restricts the ability of the Corporation to charge prices sufficient to recover specific costs, and (ii) a significant change in the manner in which rates are set by regulatory agencies from cost-based regulation to another form of regulation. The Corporation’s review of these criteria currently supports the continued application of regulatory accounting for all its utilities.

The following table summarizes the regulatory assets and liabilities recorded in the Consolidated Balance Sheets, as well as the remaining period, as of December 31, 2018 and 2017, over which the Corporation expects to realize or settle the assets or liabilities:

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As at	December 31, 2018		December 31, 2017		Recovery Period
Regulatory assets - current
Deferred cost of gas (a)	$	20.4	$	0.5	Less than one year
Deferred property taxes	—		0.3		Less than one year
Other	0.6		0.3		Less than one year
	$	21.0	$	1.1
Regulatory assets - non-current
Deferred regulatory costs and rate stabilization adjustment mechanism (a)(b)	$	215.5	$	20.5	1 - 3 years
Pipeline rehabilitation costs	—		0.3		Various
Future recovery of pension and other retirement benefits (a)	192.9		113.9		Various
Future recovery of non-retirement employee benefits (a)(c)	21.3		—		Various
Deferred pension costs (d)	7.8		—		1 years
Deferred environmental costs (a)(e)	19.9		13.9		1 - 10 years
Deferred loss on reacquired debt (a)(f)	109.3		2.5		1 - 15 years
Deferred depreciation and amortization	—		23.3		Various
Deferred future income taxes (a)(g)	67.0		104.7		Various
Deferred customer retention program amortization	—		16.5		Various
Revenue deficiency account	—		31.0		Various
Other	29.3		2.0		Various
	$	663.0	$	328.6
Regulatory liabilities - current
Deferred cost of gas	$	71.2	$	9.0	Less than one year
Refundable tax credit (h)	3.8		1.9		Less than one year
Federal income tax rate change (i)	26.2		—		Less than one year
Other	13.7		—		Less than one year
	$	114.9	$	10.9
Regulatory liabilities - non-current
Option fees deferral (a)	$	—	$	4.3	Various
Refundable tax credit (h)	6.1		7.5		Various
Future expense of pension and other retirement benefits (a)	166.7		—		Various
Future removal and site restoration costs (j)	514.7		153.3		3 - 56 years
Deferred loss on reacquired debt	1.8		—		Various
Federal income tax rate change (a)(i)	698.4		101.8		Various
Insurance recovery of environmental costs	—		0.3		2 years
Other	5.1		1.4		Various
	$	1,392.8	$	268.6

(a)Washington Gas is not entitled to a rate of return on these assets. Washington Gas is allowed to recover and required to pay, using short-term interest rates, the carrying costs related to billed gas costs due from and to its customers in the District of Columbia and Virginia jurisdictions.

(b)Includes fair value of derivatives, which are not included in customer bills until settled.

(c)Represents the timing difference between the recognition of workers compensation and short-term disability costs in accordance with generally accepted accounting principles and the way these costs are recovered through rates. Certain utilities have recovered pension costs related to regulated operations in rates, and as such the Corporation has recorded a regulatory asset for the unamortized costs associated with the defined benefit and post-retirement benefit plans. Depending on the method utilized by the utility, the recovery period can be either the expected service life of the employees, the benefit period for employees, or a specific recovery period as approved by the respective regulator.

(d)Relates to costs not recoverable through rates in the District of Columbia jurisdiction. However, Washington Gas is allowed to amortize these prior unrecovered pension and other post-retirement benefits through 2019.

(e)This balance represents allowed environmental remediation expenditures at SEMCO Gas and Washington Gas sites to be recovered through rates.

(f)The losses or gains on the issuance and extinguishment of debt and interest-rate derivative instruments include unamortized balances from transactions executed in prior fiscal years. These transactions create gains and losses that are amortized over the remaining life of the debt as prescribed by regulatory accounting requirements. This also includes a fair value adjustment of $89 million recorded on the WGL Acquisition (Note 3).

(g)This regulatory asset reflects the amount of deferred income taxes expected to be refunded, or recovered from, customers in future rates.

(h)On September 18, 2013, CINGSA received a US$15.0 million gas storage facility tax credit from the State of Alaska for the benefit of its firm storage service customers. CINGSA will derive no direct or indirect benefit from the tax credit. Following receipt of the tax credit, CINGSA deposited it in a separate interest-bearing account. CINGSA will act as a custodian of the tax credit and any interest earned for the benefit of CINGSA’s customers. On an annual basis, covering the years 2012 through 2021, CINGSA will disburse to the customers 1/10th of the amount of the tax credit not subject to refund to the State and interest earned. The RCA has approved the disbursement methodology.

(i)The TCJA was enacted on December 22, 2017, and required the Corporation to revalue its U.S. deferred tax assets and liabilities to the lower federal corporate tax rate of 21 percent resulting in excess accumulated deferred income taxes. The tax rate reduction created a reduction in deferred tax liability, which SEMCO Gas and Washington Gas are required to refund to ratepayers.

(j)This amount and timing of draw down is dependent upon the cost of removal of underlying utility property, plant and equipment and the life of property, plant and equipment.

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21.  ACCUMULATED OTHER COMPREHENSIVE INCOME

($ millions)	Available- for-sale			Defined benefit pension and PRB plans			Hedge net investments			Translation foreign operations			Equity investee			Total
Opening balance, January 1, 2018	$	(7.1	)	$	(11.4	)	$	(129.0	)	$	342.9		$	3.7		$	199.1
OCI before reclassification	—			(14.1		)	(90.6		)	458.5			2.1			355.9
Amounts reclassified from OCI	—			0.7			—			—			—			0.7
Adoption of ASU No. 2016-01 (note 2)	7.1			—			—			—			—			7.1
Curtailment of DB and PRB plan	—			4.2			—			—			—			4.2
Current period OCI (pre-tax)	7.1			(9.2		)	(90.6		)	458.5			2.1			367.9
Income tax on amounts retained in    AOCI	—			3.3			10.4			—			—			13.7
Income tax on amounts reclassified    to earnings	—			(0.2		)	—			—			—			(0.2		)
Income tax on amounts related to curtailment of DB and PRB plan	—			(1.5		)	—			—			—			(1.5		)
Net current period OCI	7.1			(7.6		)	(80.2		)	458.5			2.1			379.9
Ending balance, December 31, 2018	$	—		$	(19.0	)	$	(209.2	)	$	801.4		$	5.8		$	579.0
Opening balance, January 1, 2017	$	19.8		$	(11.3	)	$	(135.6	)	$	526.3		$	5.9		$	405.1
OCI before reclassification	(30.3		)	(1.3		)	6.6			(183.4		)	(2.2		)	(210.6		)
Amounts reclassified from AOCI	—			1.3			—			—			—			1.3
Current period OCI (pre-tax)	(30.3		)	—			6.6			(183.4		)	(2.2		)	(209.3		)
Income tax on amounts retained in    AOCI	3.4			0.3			—			—			—			3.7
Income tax on amounts reclassified    to earnings	—			(0.4		)	—			—			—			(0.4		)
Net current period OCI	(26.9		)	(0.1		)	6.6			(183.4		)	(2.2		)	(206.0		)
Ending balance, December 31, 2017	$	(7.1	)	$	(11.4	)	$	(129.0	)	$	342.9		$	3.7		$	199.1

Reclassification From Accumulated Other Comprehensive Income

AOCI components reclassified	Income statement line item	Year ended December 31, 2018			Year ended December 31, 2017
Defined benefit pension and PRB plans	Operating and administrative expense	$	0.7		$	1.3
Deferred income taxes	Income tax expenses — deferred	(0.2		)	(0.4		)
		$	0.5		$	0.9

22.  FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT

The Corporation’s financial instruments consist of cash and cash equivalents, accounts receivable, risk management contracts, certain long-term investments and other assets, accounts payable and accrued liabilities, dividends payable, short-term and long-term debt and certain other current and long-term liabilities.

Fair Value Hierarchy

AltaGas categorizes its financial assets and financial liabilities into one of three levels based on fair value measurements and inputs used to determine the fair value.

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Level 1 - fair values are based on unadjusted quoted prices in active markets for identical assets or liabilities. Fair values are based on direct observations of transactions involving the same assets or liabilities and no assumptions are used. Included in this category are publicly traded shares valued at the closing price as at the balance sheet date.

Level 2 - fair values are determined based on valuation models and techniques where inputs other than quoted prices included within level 1 are observable for the asset or liability either directly or indirectly. AltaGas enters into derivative instruments in the futures, over-the-counter and retail markets to manage fluctuations in commodity prices and foreign exchange rates. The fair values of power, natural gas and NGL derivative contracts were calculated using forward prices based on published sources for the relevant period, adjusted for factors specific to the asset or liability, including basis and location differentials, discount rates, and currency exchange. The fair value of foreign exchange derivative contracts was calculated using quoted market rates. The fair value of foreign exchange option contracts was calculated using a variation of the Black-Scholes pricing model.

Level 3 - fair values are based on inputs for the asset or liability that are not based on observable market data. AltaGas uses valuation techniques when observable market data is not available. A variety of valuation methodologies are used to determine the fair value of Level 3 derivative contracts, including developed valuation inputs and pricing models. The prices used in the valuations are corroborated using multiple pricing sources, and the Corporation periodically conducts assessments to determine whether each valuation model is appropriate for its intended purpose. Level 3 derivatives include physical contracts at illiquid market locations with no observable market data, long-dated positions where observable pricing is not available over the life of the contract, contracts valued using historical spot price volatility assumptions, and valuations using indicative broker quotes for inactive market locations.

The following methods and assumptions were used to estimate the fair value of each significant class of financial instruments:

Other current liabilities - the carrying amounts approximate fair value because of the short maturity of these instruments.

Current portion of long-term debt, Long-term debt and Other long-term liabilities - the fair value of these liabilities was estimated based on discounted future interest and principal payments using the current market interest rates of instruments with similar terms. The fair value of level 3 long term debt was determined by taking the present value of the debt securities’ future cash flows discounted at interest rates that reflect market conditions as of the measurement date. The discount rate is based on the quoted market prices of the U.S. Treasury issues having a similar term to maturity, adjusted for the credit quality of the debt issuer.

Risk management assets and liabilities - the fair values of power, natural gas and NGL derivative contracts were calculated using forward prices from published sources for the relevant period. The fair value of foreign exchange derivative contracts was calculated using quoted market rates. The fair value of level 3 derivative contracts was calculated using internally developed valuation inputs and pricing models.

Equity securities — the fair value of equity securities was calculated using quoted market prices.

Loans and receivables — the fair value of these assets was estimated based on discounted future interest and principal payments using the current market interest rates of instruments with similar terms.

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	December 31, 2018
	Carrying Amount		Level 1		Level 2		Level 3		Total Fair Value
Financial assets
Fair value through net income(a)
Risk management assets - current	$	99.0	$	—	$	68.3	$	30.7	$	99.0
Risk management assets - non-current	49.0		—		18.0		31.0		49.0
Equity securities(b)	8.4		8.4		—		—		8.4
Fair value through regulatory assets/liabilities (a)
Risk management assets - current	15.1		—		2.7		12.4		15.1
Risk management assets - non-current	8.7		—		—		8.7		8.7
Amortized cost
Loans and receivables (b)	45.0		—		45.2		—		45.2
	$	225.2	$	8.4	$	134.2	$	82.8	$	225.4
Financial liabilities
Fair value through net income(a)
Risk management liabilities - current	$	72.0	$	—	$	41.3	$	30.7	$	72.0
Risk management liabilities - non-current	103.4		—		15.3		88.1		103.4
Fair value through regulatory assets/liabilities (a)
Risk management liabilities - current	17.3		—		2.9		14.4		17.3
Risk management liabilities - non-current	109.6		—		0.1		109.5		109.6
Amortized cost
Current portion of long-term debt	890.2		—		884.4		—		884.4
Long-term debt	8,066.9		—		6,027.6		2,012.7		8,040.3
Other current liabilities (c)	11.2		—		11.2		—		11.2
Other long-term liabilities (c)	2.0		—		2.0		—		2.0
	$	9,272.6	$	—	$	6,984.8	$	2,255.4	$	9,240.2

(a)To manage price risk associated with acquiring natural gas supply for Maryland, Virginia, and District of Columbia utility customers, Washington Gas, a subsidiary of the Corporation, enters into physical and financial derivative transactions. Any gains and losses associated with these derivatives are recorded as regulatory liabilities or assets, respectively, to reflect the rate treatment for these economic hedging activities. Additionally, as part of its asset optimization program, Washington Gas enters into derivatives with the primary objective of securing operating margins that Washington Gas will ultimately realize. Regulatory sharing mechanisms provide for the annual realized profit from these transactions to be shared between Washington Gas’ shareholder and customers; therefore, changes in fair value are recorded through earnings, or as regulatory assets or liabilities to the extent that it is probable that realized gains and losses associated with these derivative transactions will be included in the rates charged to customers when they are realized.

(b)Included under the line item “long-term investments and other assets” on the Consolidated Balance Sheets.

(c)Excludes non-financial liabilities.

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	December 31, 2017
	Carrying Amount		Level 1		Level 2		Level 3		Total Fair Value
Financial assets
Fair value through net income
Risk management assets - current	$	38.6	$	—	$	38.6	$	—	$	38.6
Risk management assets - non-current	15.9		—		15.9		—		15.9
Equity securities(a)	95.0		95.0		—		—		95.0
Amortized cost
Loans and receivables (a)	75.0		—		85.6		—		85.6
	$	224.5	$	95.0	$	140.1	$	—	$	235.1
Financial liabilities
Fair value through net income
Risk management liabilities - current	$	57.6	$	—	$	57.6	$	—	$	57.6
Risk management liabilities - non-current	13.8		—		13.8		—		13.8
Amortized cost
Current portion of long-term debt	188.9		—		189.6		—		189.6
Long-term debt	3,436.5		—		3,568.3		—		3,568.3
Other current liabilities (b)	22.4		—		22.4		—		22.4
Other long-term liabilities (b)	146.0		—		147.7		—		147.7
	$	3,865.2	$	—	$	3,999.4	$	—	$	3,999.4

(a)Included under the line item “long-term investments and other assets” on the Consolidated Balance Sheets.

(b)Excludes non-financial liabilities.

The following table includes quantitative information about the significant unobservable inputs used in the fair value measurement of Level 3 financial instruments at December 31, 2018:

	Net Fair Value			Valuation Technique	Unobservable Inputs	Range
Natural gas	$	(144.1	)	Discounted Cash Flow	Natural Gas Basis Price (per dekatherm)	$(1.40) - $7.28
Natural gas	$	(4.4	)	Option Model	Natural Gas Basis Price (per dekatherm)	$(1.37) - $5.07
					Annualized Volatility of Spot Market Natural Gas	37.46% - 900.98%
Electricity	$	(14.7	)	Discounted Cash Flow	Electricity Congestion Price (per megawatt hour)	$(8.28) - $84.44

The following table provides a reconciliation of changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy:

	2018									2017
For the year ended December 31	Natural Gas			Electricity			Total			Natural Gas		Electricity		Total
Balance, beginning of year	$	—		$	—		$	—		$	—	$	—	$	—
Acquired (note 3)	(136.1		)	(10.6		)	(146.7		)	—		—		—
Realized and unrealized losses:										—		—		—
Recorded in income	(8.3		)	(6.5		)	(14.8		)
Recorded in regulatory assets	(5.9		)	—			(5.9		)	—		—		—
Transfers out of Level 3	7.3			—			7.3			—		—		—
Purchases	—			6.4			6.4			—		—		—
Settlements	0.3			(3.4		)	(3.1		)	—		—		—
Foreign exchange translation	(5.8		)	(0.6		)	(6.4		)
Balance, end of year	$	(148.5	)	$	(14.7	)	$	(163.2	)	$	—	$	—	$	—

Transfers between different levels of the fair value hierarchy may occur based on fluctuations in the valuation and on the level of observable inputs used to value the instruments from period to period. Transfers into and out of the different levels of the fair

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value hierarchy are presented at the fair value as of the beginning of the year. Transfers out of Level 3 during the year ended December 31, 2018 were due to an increase in valuations using observable market inputs. Transfers into Level 3 during the year ended December 31, 2018 were due to an increase in unobservable market inputs used in valuations.

Realized and Unrealized Losses Recorded to Income for Level 3 Measurements

For the year ended December 31	2018			2017
Recorded to revenue
Commodity contracts	$	(11.1	)	$	—
Recorded to cost of sales
Commodity contracts	(3.7		)	—
	$	(14.8	)	$	—

Summary of Unrealized Gains (Losses) on Risk Management Contracts Recognized in Net Income

For the year ended December 31	2018			2017
Natural gas	$	(2.2	)	$	2.2
Storage optimization	—			2.7
NGL frac spread	40.0			(11.7		)
Power	9.3			(20.8		)
Foreign exchange	33.7			(34.9		)
	$	80.8		$	(62.5	)

Offsetting of Derivative Assets and Derivative Liabilities

Certain of AltaGas’ risk management contracts are subject to master netting arrangements that create a legally enforceable right for a counterparty to offset the related financial assets and financial liabilities. As part of these master netting agreements, cash, letters of credit and parental guarantees may be required to be posted or obtained from counterparties in order to mitigate credit risk related to both derivative and non-derivative positions. Collateral balances are also offset against the related counterparties’ derivative positions to the extent the application would not result in the over-collateralization of those derivative positions on the balance sheet.

	December 31, 2018
Risk management assets (a)	Gross amounts of recognized assets/liabilities		Gross amounts offset in balance sheet			Netting of collateral			Net amounts presented in balance sheet
Natural gas	$	200.8	$	(82.0	)	$	—		$	118.8
NGL frac spread	18.7		(0.7		)	—			18.0
Power	42.8		(7.8		)	—			35.0
	$	262.3	$	(90.5	)	$	—		$	171.8
Risk management liabilities (b)
Natural gas	$	340.4	$	(82.0	)	$	(3.3	)	$	255.1
NGL frac spread	2.7		(0.7		)	—			2.0
Power	50.6		(7.8		)	1.2			44.0
Foreign exchange	1.2		—			—			1.2
	$	394.9	$	(90.5	)	$	(2.1	)	$	302.3

(a)Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $114.1 million and risk management assets (non-current) balance of $57.7 million.

(b)Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $89.3 million and risk management liabilities (non-current) balance of $213.0 million.

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	December 31, 2017
Risk management assets (a)	Gross amounts of recognized assets/liabilities		Gross amounts offset in balance sheet			Netting of collateral		Net amounts presented in balance sheet
Natural gas	$	41.0	$	(6.2	)	$	—	$	34.8
NGL frac spread	1.3		(0.3		)	—		1.0
Power	17.7		(0.7		)	—		17.0
Foreign exchange	1.7		—			—		1.7
	$	61.7	$	(7.2	)	$	—	$	54.5
Risk management liabilities (b)
Natural gas	$	35.1	$	(6.2	)	$	—	$	28.9
NGL frac spread	25.3		(0.3		)	—		25.0
Power	14.0		(0.7		)	4.2		17.5
	$	74.4	$	(7.2	)	$	4.2	$	71.4

(a)Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $38.6 million and risk management assets (non-current) balance of $15.9 million.

(b)Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $57.6 million and risk management liabilities (non-current) balance of $13.8 million.

Cash Collateral

The following table presents collateral not offset against risk management assets and liabilities:

	December 31, 2018		December 31, 2017
Collateral posted with counterparties	$	27.6	$	—
Cash collateral held representing an obligation	$	0.8	$	—

Any collateral posted that is not offset against risk management assets and liabilities is included in line item “prepaid expenses and other current assets” in the Consolidated Balance Sheets. Collateral received and not offset against risk management assets and liabilities is included in line item “customer deposits” in the Consolidated Balance Sheets.

Certain derivative instruments contain contract provisions that require collateral to be posted if the credit rating of AltaGas or certain of its subsidiaries falls below certain levels. At December 31, 2018 and 2017, AltaGas had not posted any collateral related to its derivative liabilities that contained credit-related contingent features. The following table shows the aggregate fair value of all derivative instruments with credit-related contingent features that are in a liability position, as well as the maximum amount of collateral that would be required if the most intrusive credit-risk-related contingent features underlying these agreements were triggered:

	December 31, 2018		December 31, 2017
Risk management liabilities with credit-risk-contingent features	$	14.7	$	—
Maximum potential collateral requirements	$	7.5	$	—

Risks associated with financial instruments

AltaGas is exposed to various financial risks in the normal course of operations such as market risks resulting from fluctuations in commodity prices, currency exchange rates and interest rates as well as credit risk and liquidity risk.

Commodity Price Risk

AltaGas enters into financial derivative contracts to manage exposure to fluctuations in commodity prices. The use of derivative instruments is governed under formal risk management policies and is subject to parameters set out by AltaGas’ Risk Management Committee and Board of Directors. AltaGas does not make use of derivative instruments for speculative purposes.

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Natural Gas

In the normal course of business, AltaGas purchases and sells natural gas to support its infrastructure business. The fixed price and market price contracts for both the purchase and sale of natural gas extend to 2023. In addition, AltaGas may enter into financial derivative contracts as part of WGL’s asset optimization program. WGL optimized the value of its long-term natural gas transportation and storage capacity resources during periods when these resources are not being used to physically serve utility customers. AltaGas had the following forward contracts and commodity swaps outstanding related to the activities in the energy services business as at December 31, 2018 and 2017:

December 31, 2018	Fixed price (per GJ)	Period (months)	Notional volume (GJ)	Fair Value ($ millions)
Sales	1.07 to 12.19	1-178	858,640,810	19.0
Purchases	0.69 to 16.26	1-179	1,638,207,391	(179.5	)
Swaps	2.56 to 15.37	1-231	621,578,572	20.9

December 31, 2017	Fixed price (per GJ)	Period (months)	Notional volume (GJ)	Fair Value ($ millions)
Sales	0.42 to 6.89	1-60	94,804,039	14.8
Purchases	0.52 to 6.40	1-48	61,980,315	(16.8	)
Swaps	2.86 to 9.38	1-10	6,039,642	7.9

NGL Frac Spread

AltaGas entered into a series of swaps to lock in a portion of the volumes exposed to NGL frac spread. AltaGas had the following contracts outstanding as at December 31, 2018 and 2017:

December 31, 2018	Fixed price	Period (months)	Notional volume	Fair Value ($ millions)
Propane swaps	$38.89 to $47.63/bbl	1-12	1,725,114 Bbl	12.6
Butane swaps	$52.95 to $55.26/bbl	1-12	74,371 Bbl	1.2
Crude oil swaps	$79.64 to $86.28/bbl	1-12	329,230 Bbl	6.0
Natural gas swaps	$1.38 to $1.68/GJ	1-12	9,490,365 GJ	(3.8	)

December 31, 2017	Fixed price	Period (months)	Notional volume	Fair Value ($ millions)
Propane swaps	$28.77 to $49.21 /Bbl	1-12	1,992,927 Bbl	(10.9	)
Butane swaps	$47.83 to $54.67 /Bbl	1-12	130,088 Bbl	(0.3	)
Crude oil swaps	$61.05 to $75.64 /Bbl	1-12	518,665 Bbl	(4.4	)
Natural gas swaps	$0.42 to $2.27 /GJ	1-12	11,428,515 GJ	(8.4	)

Power

AltaGas sells power to the Alberta Electric System Operator at market prices as well as to commercial and industrial users in Alberta at fixed prices. AltaGas also sells power through its WGL Energy Services affiliate, to commercial, industrial and mass market users within the PJM Regional Transmission Organization at fixed and market prices. AltaGas’ strategy is to mitigate the cash flow risk to Alberta power prices to provide predictable earnings. Therefore, AltaGas uses third party swaps and purchase contracts to fix the prices over time on a portion of the volumes to mitigate financial exposure associated with the sale contracts. These power purchase and sale contracts extend to 2023. As at December 31, 2018, AltaGas had no intention to terminate any contracts prior to maturity. AltaGas had the following power commodity forward contracts and commodity swaps outstanding as at December 31, 2018 and 2017:

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December 31, 2018	Fixed price (per MWh)	Period (months)	Notional volume (MWh)	Fair Value ($ millions)
Power sales	26.90 to 95.03	1-60	11,881,575	(1.9	)
Power purchases	25.50 to 50.25	1-42	8,507,874	16.4
Swap purchases	(6.07) to 76.18	1-48	20,957,180	(22.3	)

December 31, 2017	Fixed price (per MWh)	Period (months)	Notional volume (MWh)	Fair Value ($ millions)
Power sales	38.20 to 95.03	1-60	2,169,321	(2.5	)
Power purchases	58.50	1-12	17,520	(4.5	)
Swap purchases	37.50 to 63.50	1-48	1,563,160	6.5

The table below provides the potential impact on pre-tax income due to changes in the fair value of risk management contracts in place as at December 31, 2018:

Factor	Increase or decrease to forward prices	Increase or decrease to income before tax ($ millions)
Alberta power price	$1/MWh	0.3
PJM power price	$1/MWh	1.2
AECO natural gas price	$0.50/GJ	5.9
NYMEX natural gas price	$0.50/GJ	31.5
NGL frac spread:
Propane	$1/Bbl	1.7
Butane	$1/Bbl	0.1
Western Texas Intermediate (WTI) crude oil	$1/Bbl	0.3
Natural gas	$0.50/GJ	4.7

Foreign Exchange Risk

AltaGas is exposed to foreign exchange risk as changes in foreign exchange rates may affect the fair value or future cash flows of the Corporation’s financial instruments. AltaGas has foreign operations whereby the functional currency is the U.S. dollar. As a result, the Corporation’s earnings, cash flows, and OCI are exposed to fluctuations resulting from changes in foreign exchange rates. This risk is partially mitigated to the extent that AltaGas has U.S. dollar-denominated debt and/or preferred shares outstanding. AltaGas may also enter into foreign exchange forward derivatives to manage the risk of fluctuating cash flows due to variations in foreign exchange rates. As at December 31, 2018 and 2017, AltaGas did not have any outstanding foreign exchange forward contracts.

AltaGas may also designate its U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. As at December 31, 2018, AltaGas designated US$1,494.0 million of outstanding debt as a net investment hedge (December 31, 2017 - $nil). For the year ended December 31, 2018, AltaGas incurred an after-tax unrealized loss of $80.2 million arising from the translation of debt in OCI (2017 - after-tax unrealized gain of $6.6 million).

To mitigate the foreign exchange risks associated with the cash purchase price of WGL, AltaGas entered into foreign currency option contracts with an aggregate notional value of approximately US$1.2 billion which expired in May 2018. These foreign currency option contracts do not qualify for hedge accounting. Therefore, all changes in fair value were recognized in net income. For the year ended December 31, 2018, an unrealized gain of $34.3 million and a realized loss of $36.0 million were recognized in revenue in relation to these contracts (2017 — unrealized losses of $34.3 million). During the second quarter of 2018, AltaGas entered into foreign exchange forward contracts with an aggregate notional value of $3.2 billion which settled in July 2018. These foreign currency derivatives do not qualify for hedge accounting. For the year ended December 31, 2018, a realized gain of $1.3 million was recognized in income in relation to these forwards (2017 - $nil).

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Interest Rate Risk

AltaGas is exposed to interest rate risk as changes in interest rates may impact future cash flows and the fair value of its financial instruments. The Corporation manages its interest rate risk by holding a mix of both fixed and floating interest rate debt. As at December 31, 2018, approximately 59 percent of AltaGas’ total outstanding short-term and long-term debt was at fixed rates. In addition, from time to time, AltaGas may enter into interest rate swap agreements to fix the interest rate on a portion of its banker’s acceptances issued under its credit facilities. There were no outstanding interest rate swaps as at December 31, 2018.

Credit Risk

Credit risk results from the possibility that a counterparty to a financial instrument fails to fulfill its obligations in accordance with the terms of the contract.

AltaGas’ credit policy details the parameters used to grant, measure, monitor and report on credit provided to counterparties. AltaGas minimizes counterparty risk by conducting credit reviews on counterparties in order to establish specific credit limits, both prior to providing products or services and on a recurring basis. In addition, most contracts include credit mitigation clauses that allow AltaGas to obtain financial or performance assurances from counterparties under certain circumstances. AltaGas maintains an allowance for doubtful accounts in the normal course of its business.

AltaGas’ maximum credit exposure consists primarily of the carrying value of the non-derivative financial assets and the fair value of derivative financial assets. As at December 31, 2018, AltaGas had no concentration of credit risk with a single counterparty.

Weather Related Instruments

WGL Energy Services utilizes heating degree day (HDD) instruments from time to time to manage weather and price risks related to its natural gas and electricity sales during the winter heating season. WGL Energy Services also utilizes cooling degree day (CDD) instruments and other instruments to manage weather and price risks related to its electricity sales during the summer cooling season. These instruments cover a portion of estimated revenue or energy-related cost exposure to variations in HDDs or CDDs. For the period from close of the WGL Acquisition to December 31, 2018, pre-tax losses of $1 million were recorded related to these instruments (2017 - $nil).

Accounts Receivable Past Due or Impaired

AltaGas had the following past due or impaired accounts receivable (AR):

As at December 31, 2018	Total			AR accruals		Receivables impaired			Less than 30 days		31 to 60 days		61 to 90 days		Over 90 days
Trade receivable	$	1,574.6		$	447.5	$	54.7		$	961.5	$	74.1	$	12.8	$	24.0
Other	27.6			—		—			27.5		—		—		0.1
Allowance for credit losses	(54.7		)	—		(54.7		)	—		—		—		—
	$	1,547.5		$	447.5	$	—		$	989.0	$	74.1	$	12.8	$	24.1

As at December 31, 2017	Total			AR accruals		Receivables impaired			Less than 30 days		31 to 60 days		61 to 90 days		Over 90 days
Trade receivable	$	383.0		$	184.6	$	2.4		$	187.0	$	7.9	$	1.4	$	(0.3	)
Other	2.3			—		—			2.3		—		—		—
Allowance for credit losses	(2.4		)	—		(2.4		)	—		—		—		—
	$	382.9		$	184.6	$	—		$	189.3	$	7.9	$	1.4	$	(0.3	)

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Allowance for credit losses	December 31, 2018			December 31, 2017
Balance, beginning of year	$	2.4		$	2.5
Foreign exchange translation	0.1			(0.1		)
New allowance (a)	53.1			0.4
Change in allowance	(0.9		)	—
Allowance applied to uncollectible customer accounts	—			(0.4		)
Balance, end of year	$	54.7		$	2.4

(a)Upon close of the WGL Acquisition, AltaGas acquired WGL’s allowance for credit losses of approximately $52.9 million.

Liquidity Risk

Liquidity risk is the risk that AltaGas will not be able to meet its financial obligations as they come due. AltaGas manages this risk through its extensive budgeting and monitoring process to ensure it has sufficient cash and credit facilities to meet its obligations. AltaGas’ objective is to maintain its investment-grade ratings to ensure it has access to debt and equity funding as required.

AltaGas had the following contractual maturities with respect to financial liabilities:

	Contractual maturities by period
As at December 31, 2018	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Accounts payable and accrued liabilities	$	1,488.2	$	1,488.2	$	—	$	—	$	—
Dividends payable	22.0		22.0		—		—		—
Short-term debt	1,209.9		1,209.9		—		—		—
Other current liabilities (a)	11.2		11.2		—		—		—
Other long-term liabilities (a)	2.0		—		2.0		—		—
Risk management contract liabilities	302.3		89.3		113.3		33.3		66.4
Current portion of long-term debt (b)	888.5		888.5		—		—		—
Long-term debt (b)	8,014.8		—		3,063.4		1,592.6		3,358.8
	$	11,938.9	$	3,709.1	$	3,178.7	$	1,625.9	$	3,425.2

(a)Excludes non-financial liabilities

(b)Excludes deferred financing costs and discounts

	Contractual maturities by period
			Less than						After
As at December 31, 2017	Total		1 year		1-3 years		4-5 years		5 years
Accounts payable and accrued liabilities	$	415.3	$	415.3	$	—	$	—	$	—
Dividends payable	32.0		32.0		—		—		—
Short-term debt	46.8		46.8		—		—		—
Other current liabilities (a)	22.4		22.4		—		—		—
Other long-term liabilities (a)	146.0		—		25.7		20.8		99.5
Risk management contract liabilities	71.4		57.6		11.1		2.7		—
Current portion of long-term debt (b)	188.9		188.9		—		—		—
Long-term debt (b)	3,450.9		—		1,009.1		363.8		2,078.0
	$	4,373.7	$	763.0	$	1,045.9	$	387.3	$	2,177.5

(a)Excludes non-financial liabilities

(b)Excludes deferred financing costs and discounts

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23. REVENUE

The following table disaggregates revenue by major sources for the year ended December 31, 2018:

	Year ended December 31, 2018
	Utilities			Midstream			Power		Corporate			Total
Revenue from contracts with customers
Commodity sales contracts	$	—		$	665.2		$	497.5	$	—		$	1,162.7
Midstream service contracts	—			205.0			—		—			205.0
Gas sales and transportation services	1,684.3			—			—		—			1,684.3
Storage services	35.4			—			—		—			35.4
Other	10.7			0.6			25.1		—			36.4
Total revenue from contracts with customers	$	1,730.4		$	870.8		$	522.6	$	—		$	3,123.8
Other sources of revenue
Revenue from alternative revenue programs (a)	$	21.7		$	—		$	—	$	—		$	21.7
Leasing revenue (b)	0.6			96.6			354.9		—			452.1
Risk management and trading activities (c)(d)	1.0			377.6			268.5		(2.9		)	644.2
Other	(1.1		)	(0.4		)	16.0		0.4			14.9
Total revenue from other sources	$	22.2		$	473.8		$	639.4	$	(2.5	)	$	1,132.9
Total revenue	$	1,752.6		$	1,344.6		$	1,162.0	$	(2.5	)	$	4,256.7

(a)A large portion of revenue generated from the Utilities segment is subject to rate regulation and accordingly there are circumstances where the revenue recognized is mandated by the applicable regulators in accordance with ASC 980.

(b)Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Power segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases.

(c)Risk management activities involve the use of derivative instruments such as physical and financial swaps, forward contracts, and options. These derivatives are accounted for under ASC 815 and ASC 825. The majority of revenue generated by the Midstream and Power segments is from the physical sale and delivery of natural gas and power to end users, except for WGL Midstream (see footnote d).

(d)WGL Midstream trading margins are reported in risk management and trading activities from the Midstream segment. WGL Midstream enters into derivative contracts for the purpose of optimizing its storage and transportation capacity as well as managing the transportation and storage assets on behalf of third parties. The trading margins of WGL Midstream, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues of $264.2 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract, which are in scope of ASC 606, are reported in the risk management and trading activities. While the GAIL contract is individually not accounted for as a derivative, it is inseparable from the overall trading portfolio of WGL Midstream. Revenue is recognized at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount. The contract has a term of 20 years and began on March 31, 2018.

Revenue Recognition

The following is a description of the Corporation’s revenue recognition policy by major sources of revenue from contracts with customers and segment.

Utilities segment

Gas sales and transportation services

Customers are billed monthly based on regular meter readings. Customer billings are based on two main components: (i) a fixed service fee and (ii) a variable fee based on usage. Revenue is recognized over time when the gas has been delivered or as the service has been performed. As meter readings are performed on a cycle basis, AltaGas recognizes accrued revenue for any services rendered to its customers but not billed at month-end. The vast majority of these contracts are “at-will” as customers may cancel their service at any time, however, there are certain contracts that have terms of one year or longer. For these long-term contracts, there is generally a contract demand specified in the contract whereby the customer has to pay regardless of whether or not gas has been delivered. These contracts generally do not contain any make up rights and revenue is recognized on a monthly basis as service has been performed.

Gas storage services

Gas storage customers are billed monthly for services provided. Customer billings are based on four components: (i) reservation charges; (ii) capacity charges; (iii) injection/withdrawal charges; and (iv) excess charges. Reservation charges are based on the customer’s contract withdrawal quantity, capacity charges are based on the customer’s total contract quantity, and

50

injection/withdrawal charges are based on the volume of gas delivered to or from the customer. Excess charges are applied to each day that the storage quantity exceeds 100 percent of the customer’s maximum storage quantity. Revenue is recognized as the service has been performed over time on a monthly basis, which corresponds to the invoice amount. The majority of these contracts have terms extending beyond one-year.

Midstream segment

Commodity sales

A portion of the NGL production from AltaGas’ extraction facilities is subject to frac spread between NGLs extracted and the natural gas purchased to make up the heating value of the NGLs extracted. For commodity sales contracts that do not meet the definition of a derivative or for contracts whereby AltaGas has elected to apply the normal purchase normal sales scope exception, the sales contract is accounted for under ASC 606. These commodity sales contracts have varying terms but the majority of the contracts have a one-year term which coincides with the NGL year. AltaGas recognizes revenue for commodity sales contracts at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount.

Commodity sales also include gas sales to residential, commercial and industrial customers in certain states where WGL Energy Services is authorized as a competitive service provider. These commodity sales contracts have varying terms that generally range from one to five years. Customers are billed monthly based on the amount of gas delivered to the customer. Revenue is recognized based on the amount the Company is entitled to invoice the customer.

Midstream service contracts

AltaGas earns revenue from its field gathering and processing facilities, extraction facilities, and transmission systems through a variety of contractual arrangements. For arrangements that do not contain a lease, the revenue is accounted for under ASC 606 as follows:

Fee-for-service — The customer is charged a fee for the service provided on a per unit volume basis. Contract terms generally range from one month to up to the life of the reserves. Revenue under this type of arrangement is recognized over time as the service is provided, which corresponds to the customer’s monthly invoice amount.

Take-or-pay — The customer has agreed to a minimum volume commitment whereby the customer must have AltaGas process or deliver a specified volume at a rate per unit that is specified in the contract. Quantities that the customer is unable to deliver are considered deficiency quantities. Certain of AltaGas’ take-or-pay contracts contain provisions whereby the customer can make up deficiency quantities in subsequent periods. Under this type of arrangement, any consideration received relating to the deficiency quantities that will be made up in a future period will be deferred until either: (i) the customer makes up the volumes or (ii) the likelihood that the customer will make up the volumes before the make up period expires becomes remote. If AltaGas does not expect the customer to make up the deficiency quantities (also referred to as breakage amount), AltaGas may recognize the expected breakage amount as revenue before the make up period expires. Significant judgment is required in estimating the breakage amount. For contracts where the customer has no make-up rights, revenue is recognized on a monthly basis based on the higher of (i) the actual quantity delivered times the per unit rate or (ii) the contracted minimum amount.

Power segment

For the Power segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases. In instances where power generation is not sold under a power purchase agreement, the commodity is sold via a merchant market, or via commodity sales agreements which are accounted for as financial instruments. For commodity sales contracts that do not meet the definition of a lease, derivative or for contracts whereby AltaGas has elected to apply the normal purchase normal sales scope exception, the sales contract is accounted for under ASC 606.

Commodity Sales

Energy generated from commercial solar and combined heating and power assets is sold under long term power purchase agreements with a general duration of 20 years. These long term purchase agreements provide stable cash flow by way of contracted prices for the underlying commodities. Commodity sales also include electricity sales to residential, commercial and

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industrial customers in certain states where WGL Energy Services is authorized as a competitive service provider. These commodity sales contracts have varying terms that generally range from one to five years. Customers are billed monthly based on meter readings or the amount of energy delivered to the customer. Revenue is recognized based on the amount the Company is entitled to invoice the customer.

Contract Balances

As at December 31, 2018, a contract asset of $11.5 million has been recorded within long-term investments and other assets on the Consolidated Balance Sheets (December 31, 2017 — $nil). This contract asset represents the difference in revenue recognized under a new rate in a blend-and-extend contract modification with a customer. Revenue from this contract modification will be recognized at the pre-modification rate for the remainder of the original term with the excess revenue recorded as a contract asset. The contract asset will be drawn down over the remaining term of the modified contract.

In addition, at December 31, 2018 there is a contract asset of $47.3 million (December 31, 2017 - $nil) recorded within accounts receivable on the Consolidated Balance Sheets for WGL Energy Systems’ unbilled revenue relating to design-build construction contracts. The contract asset represents unbilled amounts typically resulting from sales under contracts when the cost-to-cost method of revenue recognition is utilized, and revenue recognized exceeds the amount billed to the customer. Right to payment is achieved when the projects are formally “accepted” by the federal government. In the fourth quarter of 2018, WGL Energy Systems reached an agreement for the sale of a financing receivable included in the contract asset. Accordingly, the receivable was reclassified as held for sale (Note 5) and a $6.0 million provision was recorded on the asset (Note 10). Contract liabilities of $2.2 million (2017 - $nil) have been recorded within other current liabilities on the Consolidated Balance Sheets. The contract liabilities consist of advance payments and billings in excess of revenue recognized and deferred revenue. Contract assets and liabilities are reported in a net position on a contract-by-contract basis at the end of each reporting period.

Transaction price allocated to the remaining obligations

The following table includes estimated revenue expected to be recognized in the future related to performance obligations that are unsatisfied as of December 31, 2018:

	2019		2020		2021		2022		2023		> 2023		Total
Midstream service contracts	$	52.2	$	55.7	$	32.3	$	31.9	$	28.0	$	192.4	$	392.5
Gas sales and transportation services	0.6		0.6		0.6		0.6		0.6		3.2		6.2
Storage services	36.7		36.3		36.3		36.3		36.3		299.8		481.7
Other	37.0		10.5		1.6		0.8		0.8		3.2		53.9
Subtotals	$	126.5	$	103.1	$	70.8	$	69.6	$	65.7	$	498.6	$	934.3

AltaGas applies the practical expedient available under ASC 606 and does not disclose information about the remaining performance obligations for (i) contracts with an original expected length of one year or less, (ii) contracts for which revenue is recognized at the amount to which AltaGas has the right to invoice for performance completed, and (iii) contracts with variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation. In addition, the table above does not include any estimated amounts of variable consideration that are constrained. The majority of midstream service contracts, gas sales and transportation service contracts, and storage service contracts contain variable consideration whereby uncertainty related to the associated variable consideration will be resolved (usually on a daily basis) as volumes are processed, gas is delivered or as service is provided.

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24.  SHAREHOLDERS’ EQUITY

Authorization

AltaGas is authorized to issue an unlimited number of voting common shares. AltaGas is also authorized to issue preferred shares not to exceed 50 percent of the voting rights attached to the issued and outstanding common shares.

Premium DividendTM, Dividend Reinvestment and Optional Cash Purchase Plan (DRIP or the Plan)

The Plan consists of three components: a Premium Dividend™ component, a Dividend Reinvestment component and an Optional Cash Purchase component. The Premium Dividend™ component of the plan was suspended effective December 18, 2018.

The Plan provides eligible holders of common shares with the opportunity to, at their election, either: (1) reinvest the cash dividends paid by AltaGas on their common shares towards the purchase of new common shares at a 3 percent discount to the average market price (as defined below) of the common shares on the applicable dividend payment date (the Dividend Reinvestment component of the Plan); or (2) reinvest the cash dividends paid by AltaGas on their common shares towards the purchase of new common shares at a 3 percent discount to the average market price (as defined below) on the applicable dividend payment date and have these additional common shares of AltaGas exchanged for a cash payment equal to 101 percent of the reinvested amount (the Premium DividendTM component of the Plan).

In addition, the Plan provides shareholders who are enrolled in the Dividend Reinvestment component of the Plan with the opportunity to purchase new common shares at the average market price (with no discount) on the applicable dividend payment date (the Optional Cash Purchase component of the Plan).

Each of the components of the Plan are subject to prorating and other limitations on availability of new common shares in certain events. The “average market price”, in respect of a particular dividend payment date, refers to the arithmetic average (calculated to four decimal places) of the daily volume weighted average trading prices of common shares on the Toronto Stock Exchange for the trading days on which at least one board lot of common shares is traded during the 10 business days immediately preceding the applicable dividend payment date. Such trading prices will be appropriately adjusted for certain capital changes (including common share subdivisions, common share consolidations, certain rights offerings and certain dividends). Shareholders resident outside of Canada are not entitled to participate in the Premium DividendTM component of the Plan. Shareholders resident outside of Canada (other than the U.S.) may participate in the Dividend Reinvestment component or the Optional Cash Purchase component of the Plan only if their participation is permitted by the laws of the jurisdiction in which they reside and provided that AltaGas is satisfied, in its sole discretion, that such laws do not subject the Plan or AltaGas to additional legal or regulatory requirements.

Common Shares Issued and Outstanding	Number of shares	Amount
January 1, 2017	166,906,833	$	3,773.4
Shares issued for cash on exercise of options	240,125	6.5
Deferred taxes on share issuance cost	—	(8.3		)
Shares issued under DRIP	8,132,258	236.3
December 31, 2017	175,279,216	4,007.9
Shares issued on conversion of subscription receipts, net of issuance costs	84,510,000	2,305.6
Shares issued for cash on exercise of options	57,275	1.3
Deferred taxes on share issuance costs	—	13.3
Shares issued under DRIP	15,377,575	325.8
Issued and outstanding at December 31, 2018	275,224,066	$	6,653.9

TM Denotes trademark of Canaccord Genuity Corp.

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Preferred Shares

As at	December 31, 2018				December 31, 2017
Issued and Outstanding	Number of shares	Amount			Number of shares	Amount
Series A	5,511,220	$	137.8		5,511,220	$	137.8
Series B	2,488,780	62.2			2,488,780	62.2
Series C	8,000,000	205.6			8,000,000	205.6
Series E	8,000,000	200.0			8,000,000	200.0
Series G	8,000,000	200.0			8,000,000	200.0
Series I	8,000,000	200.0			8,000,000	200.0
Series K	12,000,000	300.0			12,000,000	300.0
Washington Gas
$4.80 series	150,000	19.7			—	—
$4.25 series	70,600	9.4			—	—
$5.00 series	60,000	7.9			—	—
Share issuance costs, net of taxes		(27.9		)		(27.9		)
Fair value adjustment on WGL Acquisition (note 3)		4.1				—
	52,280,600	$	1,318.8		52,000,000	$	1,277.7

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The following table outlines the characteristics of the cumulative redeemable preferred shares (a):

	Current yield		Annual dividend per share(b)				Redemption price per share			Redemption and conversion option date(c)(d)		Right to convert into(d)
AltaGas
Series A (e)	3.38	%	$	0.845			$	25		September 30, 2020		Series B
Series B (f)	Floating	(f)	Floating			(f)	$	25		September 30, 2020	(g)	Series A
Series C (h)	5.29	%	US$		1.3225		US$		25	September 30, 2022		Series D
Series E (e)	5.393	%	$	1.34825			$	25		December 31, 2023		Series F
Series G (e)	4.75	%	$	1.1875			$	25		September 30, 2019		Series H
Series I (i)	5.25	%	$	1.3125			$	25		December 31, 2020		Series J
Series K (j)	5.00	%	$	1.25			$	25		March 31, 2022		Series L
Washington Gas
$4.80 series	4.27	%	US$		4.80		US$		101	n/a		n/a
$4.25 series	4.27	%	US$		4.25		US$		105	n/a		n/a
$5.00 series	4.27	%	US$		5.00		US$		102	n/a		n/a

(a)The table above only includes those series of preferred shares that are currently issued and outstanding. The Corporation is authorized to issue up to 8,000,000 of each of Series D Shares, Series F Shares, Series H Shares, and Series J Shares, and up to 12,000,000 of Series L Shares, subject to certain conditions, upon conversion by the holders of the applicable currently issued and outstanding series of preferred shares noted opposite such series in the table on the applicable conversion option date. If issued upon the conversion of the applicable series of preferred shares, Series F Shares, Series H Shares, Series J Shares, and Series L Shares are also redeemable for $25.50, and Series D Shares are redeemable for US$25.50 on any date after the applicable conversion option date, plus all accrued but unpaid dividends to, but excluding, the date fixed for redemption.

(b)The holders of Series A Shares, Series C Shares, Series E Shares, Series G Shares, Series I Shares and Series K Shares are entitled to receive a cumulative quarterly fixed dividend as and when declared by the Board of Directors. The holders of Series B Shares are entitled to receive a quarterly floating dividend as and when declared by the Board of Directors. If issued upon the conversion of the applicable series of Preferred Shares, the holders of Series D Shares, Series F Shares, Series H Shares, Series J Shares and Series L Shares will be entitled to receive a quarterly floating dividend as and when declared by the Board of Directors.

(c)AltaGas may, at its option, redeem all or a portion of the outstanding shares for the redemption price per share, plus all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary thereafter.

(d)The holder will have the right, subject to certain conditions, to convert their preferred shares of a specified series into Preferred Shares of that other specified series as noted in this column of the table on the applicable conversion option date and every fifth anniversary thereafter.

(e)Holders will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at a rate equal to the sum of the then five-year Government of Canada bond yield plus 2.66 percent (Series A Shares), 3.17 percent (Series E Shares), and 3.06 percent (Series G Shares).

(f)Holders of Series B Shares will be entitled to receive cumulative quarterly floating dividends, which will reset each quarter thereafter at a rate equal to the sum of the then 90-day government of Canada Treasury Bill rate plus 2.66 percent. Each quarterly dividend is calculated as the annualized amount multiplied by the number of days in the quarter, divided by the number of days in the year. Commencing December 31, 2018, the floating quarterly dividend rate for Series B Shares is $0.26938 per share for the period starting December 31, 2018 to, but excluding, March 31, 2019.

(g)Series B Shares can be redeemed for $25.50 per share on any date after September 30, 2015 that is not a Series B conversion date, plus all accrued and unpaid dividends to, but excluding, the date fixed for redemption.

(h)Holders of Series C Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the sum of the five-year U.S. Government bond yield plus 3.58 percent.

(i)Holders of Series I Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the then five-year Government of Canada bond yield plus 4.19 percent, provided that, in any event, such rate shall not be less than 5.25 percent per annum.

(j)Holders of Series K Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the then five-year Government of Canada bond yield plus 3.80 percent, provided that, in any event, such rate shall not be less than 5.00 percent per annum.

Share Option Plan

AltaGas has an employee share option plan under which employees and directors are eligible to receive grants. As at December 31, 2018, 21,213,224 shares were reserved for issuance under the plan. As at December 31, 2018, options granted under the plan have a term between six and ten years until expiry and vest no longer than over a four-year period.

As at December 31, 2018, unexpensed fair value of share option compensation cost associated with future periods was $3.7 million (December 31, 2017 - $1.3 million).

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The following table summarizes information about the Corporation’s share options:

	December 31, 2018				December 31, 2017
	Options outstanding				Options outstanding
	Number of		Exercise		Number of		Exercise
As at	options		price(a)		options		price(a)
Share options outstanding, beginning of year	4,533,761		$	32.35	4,119,386		$	32.39
Granted	2,811,460		16.69		848,000		30.80
Exercised	(57,275	)	20.68		(240,125	)	24.63
Forfeited	(878,013	)	36.47		(193,500	)	36.36
Expired	(100,750	)	14.60		—		—
Share options outstanding, end of year	6,309,183		$	25.18	4,533,761		$	32.35
Share options exercisable, end of year	2,897,723		$	32.01	3,326,197		$	31.93

(a)Weighted average.

As at December 31, 2018, the aggregate intrinsic value of the total options exercisable was $nil (December 31, 2017 - $6.0 million), the total intrinsic value of options outstanding was $nil (December 31, 2017 - $6.0 million) and the total intrinsic value of options exercised was $0.3 million (December 31, 2017 - $1.4 million).

The following table summarizes the employee share option plan as at December 31, 2018:

		Options outstanding				Options exercisable
			Weighted		Weighted average		Weighted		Weighted average
		Number	average		remaining	Number	average		remaining
		outstanding	exercise price		contractual life	exercisable	exercise price		contractual life
$	14.24 to $18.00	2,322,635	$	14.55	5.91	28,000	$	17.10	1.33
$	18.01 to $25.08	425,000	20.76		1.83	425,000	20.76		1.83
$	25.09 to $50.89	3,561,548	32.65		3.48	2,444,723	34.14		2.95
		6,309,183	$	25.18	4.26	2,897,723	$	32.01	2.77

The fair value of each option granted is estimated on the date of grant using the Black-Scholes-Merton option pricing model. The weighted average grant date fair value and assumptions are as follows:

Year ended December 31	2018	2017
Fair value per option ($)	1.27	1.91
Risk-free interest rate (%)	1.99	1.31
Expected life (years)	6	6
Expected volatility (%)	23.23	21.05
Annual dividend per share ($) (a)	1.18	2.12
Forfeiture rate (%)	—	—

(a)Annual dividend per share is calculated based on a weighted average share price and forward dividend yields as of the grant dates.

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MTIP and DSUP

AltaGas has a MTIP for employees and executive officers, which includes RUs and PUs with vesting periods between 36 to 44 months from the grant date. In addition, AltaGas has a DSUP, which allows granting of DSUs to directors, officers and employees. DSUs granted under the DSUP vest immediately but settlement of the DSUs occurs when the individual ceases to be a director.

PUs, RUs, and DSUs
(number of units)	December 31, 2018		December 31, 2017
Balance, beginning of year	564,549		364,839
Acquired (a)	5,291,621		—
Granted	9,502,347		386,126
Additional units added by performance factor	—		24,301
Vested and paid out	(148,154	)	(221,775	)
Forfeited	(66,522	)	(27,279	)
Units in lieu of dividends	55,934		38,337
Outstanding, end of year	15,199,775		564,549

(a)Upon close of the WGL Acquisition, AltaGas acquired WGL’s PUs. These were converted to a fixed cash amount at a value of US$1.00 per unit.

For the year ended December 31, 2018, the compensation expense recorded for the MTIP and DSUP was $16.6 million (2017 - $9.1 million). As at December 31, 2018, the unrecognized compensation expense relating to the remaining vesting period for the MTIP was $26.9 million (December 31, 2017 - $8.4 million) and is expected to be recognized over the vesting period.

25.  NET INCOME PER COMMON SHARE

The following table summarizes the computation of net income per common share:

				Year ended December 31
	2018			2017
Numerator:
Net income (loss) applicable to controlling interests	$	(435.1	)	$	91.6
Less: Preferred share dividends	(66.6		)	(61.3		)
Net income (loss) applicable to common shares	$	(501.7	)	$	30.3
Denominator:
(millions)
Weighted average number of common shares outstanding	222.6			171.0
Dilutive equity instruments(a)	0.1			0.3
Weighted average number of common shares outstanding - diluted	222.7			171.3
Basic net income (loss) per common share	$	(2.25	)	$	0.18
Diluted net income (loss) per common share	$	(2.25	)	$	0.18

(a)Includes all options that have a strike price lower than the share price of AltaGas’ common shares as at December 31, 2018 and 2017.

For the year ended December 31, 2018, 4.0 million of share options (2017 — 2.8 million) were excluded from the diluted net income per share calculation as their effects were anti-dilutive.

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26.  OTHER INCOME

Year ended December 31	2018			2017
Losses from sale of assets	$	(10.6	)	$	(2.7	)
Other components of net benefit cost (note 2)	18.9			—
Interest income and other revenue	2.7			8.7
Gains (losses) on investments	(10.1		)	3.6
	$	0.9		$	9.6

27.  OPERATING LEASES

Certain of AltaGas’ revenues are obtained through power purchase agreements or take-or-pay contracts whereby AltaGas is the lessor in these operating lease arrangements. Minimum lease payments received are amortized over the term of the lease. Contingent rentals are recorded when the condition that created the present obligation to make such payments occurs such as when actual electricity is generated and delivered. The carrying value of property, plant, and equipment associated with these leases was $2.5 billion as at December 31, 2018 (December 31, 2017 - $3.0 billion). For the year ended December 31, 2018, the total revenue earned from minimum lease payments was $285.1 million (2017 - $290.8 million) and from contingent rentals was $167.1 million (2017 - $175.6 million).

The following table sets forth the future fixed minimum revenue related to the operating leases for the years ended December 31:

2019	194.4
2020	155.3
2021	111.9
2022	112.0
2023	104.2

28.  PENSION PLANS AND RETIREE BENEFITS

The costs of the defined benefit and post-retirement benefit plans are based on management’s estimate of the future rate of return on the fair value of pension plan assets, salary escalations, mortality rates and other factors affecting the payment of future benefits.

Defined Contribution Plan

AltaGas has a defined contribution (DC) pension plan for substantially all employees who are not members of defined benefit plans. The pension cost recorded for the DC plan was $15.4 million for the year ended December 31, 2018 (2017 - $8.4 million).

Defined Benefit Plans

AltaGas has several defined benefit pension plans for unionized and non-unionized employees, including five in Canada and six in the United States. These benefit plans are partially funded except for three of the Canadian plans which are fully funded.

Supplemental Executive Retirement Plan (SERP)

AltaGas has non-registered, defined benefit plans that provide defined benefit pension benefits to eligible executives based on average earnings, years of service and age at retirement. The SERP benefits will be paid from the general revenue of the Corporation as payments come due. Security will be provided for the SERP benefits through a letter of credit within a retirement compensation arrangement trust account.

Post-Retirement Benefits

AltaGas has several post-retirement benefit plans for unionized and non-unionized employees, including one in Canada and four in the United States. The post-retirement benefit plan in Canada is limited to the payment of life insurance and health insurance premiums. This benefit plan is not funded. Post-retirement benefit plans in the United States provide certain medical and

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prescription drug benefits to eligible retired employees, their spouses and covered dependents. Benefits are based on a combination of the retiree’s age and years of service at retirement. Two of these benefit plans are partially funded and two of them are fully funded.

AltaGas’ most recent actuarial valuation of the Canadian defined benefit plans for funding purposes was completed in 2016. AltaGas is required to file an actuarial valuation of its Canadian defined benefit plans with the pension regulators at least every three years. The next actuarial valuation for funding purposes is required to be completed as of a date no later than December 31, 2019, and is expected to be filed with the pension regulators in 2020. Actuarial valuations are required annually for AltaGas’ U.S. defined benefit plans.

The following defined benefit and post-retirement benefit plans were acquired in connection with the acquisition of WGL:

Defined Benefit Plans:

·Qualified Pension Plan - Washington Gas maintains a qualified, trusteed, non-contributory defined benefit pension plan covering most active and vested former employees of Washington Gas and certain employees of WGL subsidiaries. The non-contributory defined benefit pension plan is closed to all employees hired on or after January 1, 2010.

·Supplemental Executive Retirement Plan (DB SERP) - several executive officers of Washington Gas participate in the non-funded DB SERP, a nonqualified pension plan. The DB SERP was closed to new entrants beginning January 1, 2010.

·Defined Benefit Restoration Plan (DB Restoration) - a non-funded defined benefit restoration plan for the purpose of providing supplemental pension and pension-related benefits to a select group of management employees of Washington Gas.

Post-retirement Benefit Plans:

·Life Plan - Washington Gas provides life insurance benefits for retired employees of Washington Gas and certain employees of WGL subsidiaries.

·Retiree Medical Plan — under this plan Washington Gas provides medical, prescription drug and dental benefits through Preferred Provider Organization (PPO) or Health Maintenance Organization (HMO) plans for eligible retirees and dependents not yet receiving Medicare benefits.

·Health Reimbursement Account (HRA) Plan — under this plan retirees age 65 and older and dependents receive an annual subsidy to help purchase supplemental medical, prescription drug and dental coverage in the marketplace.

Rabbi trusts have been funded to satisfy the employee benefit obligations associated with WGL’s various pension plans for a total of $89.3 million. These balances are included in prepaid expenses and other current assets and long-term investments and other assets in the Consolidated Balance Sheets.

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The following table summarizes the details of the defined benefit plans, including the SERP and post-retirement plans in Canada and the United States:

	Canada						United States						Total
				Post-						Post-						Post-
	Defined			Retirement			Defined			Retirement			Defined			Retirement
Year ended December 31, 2018	Benefit			Benefits			Benefit			Benefits			Benefit			Benefits
Accrued benefit obligation
Balance, beginning of year	$	165.6		$	15.8		$	303.8		$	82.7		$	469.4		$	98.5
Plans disposed (note 4)	(132.1		)	(13.6		)	—			—			(132.1		)	(13.6		)
Actuarial gain	(0.8		)	(0.1		)	(67.7		)	(33.8		)	(68.5		)	(33.9		)
Current service cost	2.4			0.1			16.2			5.3			18.6			5.4
Member contributions	—			—			—			2.1			—			2.1
Interest cost	1.2			0.1			38.0			10.9			39.2			11.0
Benefits paid	(2.7		)	—			(43.2		)	(13.4		)	(45.9		)	(13.4		)
Expenses paid	—			—			(0.9		)	(0.1		)	(0.9		)	(0.1		)
Plan combinations	0.7			—			1,311.7			382.9			1,312.4			382.9
Plan amendments	—			(0.4		)	—			—			—			(0.4		)
Foreign exchange translation	—			—			77.4			21.4			77.4			21.4
Balance, end of year	$	34.3		$	1.9		$	1,635.3		$	458.0		$	1,669.6		$	459.9
Plan assets
Fair value, beginning of year	$	115.2		$	8.1		$	248.7		$	70.8		$	363.9		$	78.9
Plans disposed (note 4)	(102.1		)	(8.1		)	—			—			(102.1		)	(8.1		)
Actual return on plan assets	(0.3		)	—			(54.7		)	(37.2		)	(55.0		)	(37.2		)
Employer contributions	3.4			—			7.6			2.5			11.0			2.5
Member contributions	—			—			—			2.1			—			2.1
Benefits paid	(2.7		)	—			(43.2		)	(13.4		)	(45.9		)	(13.4		)
Expenses paid	—			—			(0.9		)	(0.1		)	(0.9		)	(0.1		)
Plan combinations	0.3			—			1,133.2			732.7			1,133.5			732.7
Foreign exchange translation	—			—			63.4			33.8			63.4			33.8
Fair value, end of year	$	13.8		$	—		$	1,354.1		$	791.2		$	1,367.9		$	791.2
Net amount recognized	$	(20.5	)	$	(1.9	)	$	(281.2	)	$	333.2		$	(301.7	)	$	331.3

60

	Canada						United States						Total
				Post-						Post-						Post-
	Defined			Retirement			Defined			Retirement			Defined			Retirement
Year ended December 31, 2017	Benefit			Benefits			Benefit			Benefits			Benefit			Benefits
Accrued benefit obligation
Balance, beginning of year	$	150.0		$	16.4		$	290.5		$	72.7		$	440.5		$	89.1
Actuarial loss (gain)	8.3			(1.6		)	23.2			14.4			31.5			12.8
Current service cost	7.9			0.7			8.0			1.8			15.9			2.5
Member contributions	0.2			—			—			—			0.2			—
Interest cost	5.8			0.6			11.7			2.9			17.5			3.5
Benefits paid	(6.3		)	(0.3		)	(8.6		)	(3.2		)	(14.9		)	(3.5		)
Expenses paid	(0.3		)	—			(0.8		)	(0.1		)	(1.1		)	(0.1		)
Plan settlements	—			—			—			(0.5		)	—			(0.5		)
Foreign exchange translation	—			—			(20.2		)	(5.3		)	(20.2		)	(5.3		)
Balance, end of year	$	165.6		$	15.8		$	303.8		$	82.7		$	469.4		$	98.5
Plan assets
Fair value, beginning of year	$	101.5		$	6.8		$	226.9		$	67.2		$	328.4		$	74.0
Actual return on plan assets	8.5			0.4			37.9			11.0			46.4			11.4
Employer contributions	11.6			1.2			9.5			0.6			21.1			1.8
Member contributions	0.2			—			—			—			0.2			—
Benefits paid	(6.3		)	(0.3		)	(8.6		)	(3.2		)	(14.9		)	(3.5		)
Expenses paid	(0.3		)	—			(0.8		)	(0.1		)	(1.1		)	(0.1		)
Foreign exchange translation	—			—			(16.2		)	(4.7		)	(16.2		)	(4.7		)
Fair value, end of year	$	115.2		$	8.1		$	248.7		$	70.8		$	363.9		$	78.9
Net amount recognized	$	(50.4	)	$	(7.7	)	$	(55.1	)	$	(11.9	)	$	(105.5	)	$	(19.6	)

The following amounts were included in the Consolidated Balance Sheets:

	December 31, 2018									December 31, 2017
				Post-									Post-
	Defined			Retirement						Defined			Retirement
	Benefit			Benefits			Total			Benefit			Benefits			Total
Prepaid post-retirement benefits	$	—		$	341.4		$	341.4		$	—		$	—		$	—
Accounts payable and accrued liabilities	(27.6		)	—			(27.6		)	(0.6		)	—			(0.6		)
Future employee obligations	(273.9		)	(10.3		)	(284.2		)	(104.9		)	(19.6		)	(124.5		)
	$	(301.5	)	$	331.1		$	29.6		$	(105.5	)	$	(19.6	)	$	(125.1	)

The funded status based on the accumulated benefit obligation for all defined benefit plans were:

	December 31, 2018						December 31, 2017
	Canada			United States			Canada			United States
Accumulated benefit obligation (a)	$	(32.9	)	$	(1,525.6	)	$	(143.9	)	$	(274.2	)
Fair value of plan assets	13.8			1,354.1			115.2			248.7
Funded status	$	(19.1	)	$	(171.5	)	$	(28.7	)	$	(25.5	)

(a)Accumulated benefit obligation differs from accrued benefit obligation in that it does not include an assumption with respect to future compensation levels.

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The following amounts were not recognized in the net periodic benefit cost and recorded in the other comprehensive Income (losses):

	Canada						United States						Total
				Post-						Post-						Post-
	Defined			Retirement			Defined			Retirement			Defined			Retirement
Year ended December 31, 2018	Benefit			Benefits			Benefit			Benefits			Benefit			Benefits
Past service cost	$	(0.3	)	$	0.4		$	(0.2	)	$	—		$	(0.5	)	$	0.4
Net actuarial loss	(8.7		)	(0.5		)	(10.7		)	(5.0		)	(19.4		)	(5.5		)
Recognized in AOCI pre-tax	$	(9.0	)	$	(0.1	)	$	(10.9	)	$	(5.0	)	$	(19.9	)	$	(5.1	)
Increase by the amount    included in deferred tax liabilities	2.4			—			2.2			1.4			4.6			1.4
Net amount in AOCI after-tax	$	(6.6	)	$	(0.1	)	$	(8.7	)	$	(3.6	)	$	(15.3	)	$	(3.7	)

	Canada						United States					Total
				Post-						Post-					Post-
	Defined			Retirement			Defined			Retirement		Defined			Retirement
Year ended December 31, 2017	Benefit			Benefits			Benefit			Benefits		Benefit			Benefits
Past service cost	$	(0.4	)	$	—		$	—		$	—	$	(0.4	)	$	—
Net actuarial loss	(13.9		)	(1.3		)	—			—		(13.9		)	(1.3		)
Recognized in AOCI pre-tax	$	(14.3	)	$	(1.3	)	$	—		$	—	$	(14.3	)	$	(1.3	)
Increase (decrease) by the amount    included in deferred tax liabilities	4.0			0.3			(0.1		)	—		3.9			0.3
Net amount in AOCI after-tax	$	(10.3	)	$	(1.0	)	$	(0.1	)	$	—	$	(10.4	)	$	(1.0	)

The following amounts were not recognized in the net periodic benefit cost and recorded in a regulatory asset (liability):

	Canada				United States					Total
			Post-				Post-					Post-
	Defined		Retirement		Defined		Retirement			Defined		Retirement
Year ended December 31, 2018	Benefit		Benefits		Benefit		Benefits			Benefit		Benefits
Past service cost	$	—	$	—	$	0.8	$	(110.2	)	$	0.8	$	(110.2	)
Net actuarial gain (loss)	—		—		188.2		(52.6		)	188.2		(52.6		)
Recognized in regulatory asset (liability)	$	—	$	—	$	189.0	$	(162.8	)	$	189.0	$	(162.8	)

	Canada					United States						Total
				Post-					Post-						Post-
	Defined			Retirement		Defined			Retirement			Defined			Retirement
Year ended December 31, 2017	Benefit			Benefits		Benefit			Benefits			Benefit			Benefits
Past service cost	$	—		$	—	$	(1.2	)	$	5.6		$	(1.2	)	$	5.6
Net actuarial gain (loss)	(30.6		)	0.4		(74.0		)	(12.8		)	(104.6		)	(12.4		)
Recognized in regulatory asset (liability)	$	(30.6	)	$	0.4	$	(75.2	)	$	(7.2	)	$	(105.8	)	$	(6.8	)

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The costs of the defined benefit and post-retirement benefit plans are based on Management’s estimate of the future rate of return on the fair value of pension plan assets, salary escalations, mortality rates and other factors affecting the payment of future benefits.

			Post-
	Defined		Retirement
Amounts to be amortized in the next fiscal year from AOCI	Benefit		Benefits
Past service costs	$	0.1	$	0.2
Actuarial losses	0.5		—
Total	$	0.6	$	0.2

			Post-
Amounts to be amortized in the next fiscal year from regulatory	Defined		Retirement
assets (liabilities)	Benefit		Benefits
Past service costs	$	0.2	$	(21.3	)
Actuarial losses	9.1		0.1
Total	$	9.3	$	(21.2	)

The net pension expense by plan for the period was as follows:

	Year ended December 31, 2018
	Canada					United States						Total
				Post-					Post-						Post-
	Defined			retirement		Defined			retirement			Defined			retirement
	Benefit			Benefits		Benefit			Benefits			Benefit			Benefits
Current service cost (a)	$	2.4		$	0.1	$	16.2		$	5.3		$	18.6		$	5.4
Interest cost (b)	1.2			0.1		38.0			10.9			39.2			11.0
Expected return on plan assets (b)	(0.5		)	—		(49.9		)	(21.6		)	(50.4		)	(21.6		)
Amortization of past service cost (b)	0.1			—		—			—			0.1			—
Amortization of net actuarial loss (b)	0.6			—		—			—			0.6			—
Amortization of regulatory asset (b)	—			—		7.8			(11.1		)	7.8			(11.1		)
Net benefit cost (income) recognized	$	3.8		$	0.2	$	12.1		$	(16.5	)	$	15.9		$	(16.3	)

(a)Recorded under the line item “Operating and administrative” expenses on the Consolidated Statements of Income.

(b)Recorded under the line item “Other Income” on the Consolidated Statements of Income.

	Year ended December 31, 2017
	Canada						United States						Total
				Post-						Post-						Post-
	Defined			retirement			Defined			retirement			Defined			retirement
	Benefit			Benefits			Benefit			Benefits			Benefit			Benefits
Current service cost (a)	$	7.9		$	0.7		$	8.0		$	1.8		$	15.9		$	2.5
Interest cost (b)	5.8			0.6			11.7			2.9			17.5			3.5
Expected return on plan assets (b)	(5.9		)	(0.2		)	(16.9		)	(4.7		)	(22.8		)	(4.9		)
Settlement of plan (b)	—			—			—			0.2			—			0.2
Amortization of past service cost (b)	0.2			—			—			—			0.2			—
Amortization of net actuarial loss (b)	0.7			—			—			—			0.7			—
Amortization of regulatory asset/liability (b)	1.3			0.1			6.5			(0.3		)	7.8			(0.2		)
Net benefit cost (income) recognized	$	10.0		$	1.2		$	9.3		$	(0.1	)	$	19.3		$	1.1

(a)Recorded under the line item “Operating and administrative” expenses on the Consolidated Statements of Income.

(b)Recorded under the line item “Other Income” on the Consolidated Statements of Income.

The objective of the Corporation’s investment policy is to maximize long-term total return while protecting the capital value of the fund from major market fluctuations through diversification and selection of investments.

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The objective for fund returns, over three to five-year periods, is the sum of two components - a passive component, which is the benchmark index market returns for the asset mix in effect, plus the added value expected from active management. It is the Corporation’s belief that the potential additional returns justify the additional risk associated with active management. The risk inherent in the investment strategy over a market cycle (a three-to five-year period) is two-fold. There is a risk that the market returns, as measured by the benchmark returns, will not be in line with expectations. The other risk is that the expected added value of active management over passive management will not be realized over the time period prescribed in each fund manager’s mandate. There is also the risk of annual volatility in returns, which means that in any one year the actual return may be very different from the expected return.

Cash and money market investments may be held from time to time as short-term investment decisions at the discretion of the fund manager(s) within the constraints prescribed by their mandate(s).

The Corporation has a target asset mix for the Canadian plans of 45 percent to 55 percent fixed income assets. The target asset mix for SEMCO plans is 33 percent fixed income assets and for WGL plans is 40 percent to 55 percent fixed income assets. These objectives have taken into account the nature of the liabilities and the risk-reward tolerance of the Corporation.

The collective investment mixes for the plans are as follows as at December 31, 2018:

Canada	Fair value		Level 1		Level 2		Percentage of Plan Assets (%)
Cash and short-term equivalents	$	1.7	$	1.7	$	—	12.3
Canadian equities	3.7		3.7		—		26.8
Foreign equities	2.1		2.1		—		15.2
Fixed income	5.5		5.5		—		39.9
Real estate	0.8		—		0.8		5.8
	$	13.8	$	13.0	$	0.8	100.0

United States	Fair value			Level 1		Level 2		Percentage of Plan Assets (%)
Cash and short-term equivalents	$	6.3		$	6.3	$	—	0.3
Canadian equities	2.1			2.1		—		0.1
Foreign equities (a)	273.2			270.6		2.6		12.7
Fixed income	850.1			99.2		750.9		39.6
Derivatives	9.3			—		9.3		0.4
Other	10.9			—		10.9		0.5
Total investments in the fair value hierarchy	$	1,151.9		378.2		773.7		53.6
Investments measured at net asset value using the NAV practical expedient (b)
Commingled funds and pooled separate accounts (c)	945.3							44.2
Private Equity/Limited Partnership (d)	48.2							2.2
Total fair value of plan investments	$	2,145.4						100.0
Net payable (e)	(0.1		)					—
	$	2,145.3						100.0

(a)Investments in foreign equities include U.S. and international securities.

(b)In accordance with ASC Topic 820, these investments are measured at fair value using net asset value (NAV) per share as a practical expedient and, therefore, have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliations of the fair value hierarchy to the statements of net assets available for plan benefits.

(c)As of December 31, 2018, investments in commingled funds and a pooled separate account consisted of approximately 89 percent common stock U.S. companies; 10 percent income producing properties located in the United States; and 1 percent short-term money market investments for WGL’s defined benefit plans and 54 percent of common stock of large-cap U.S. companies, 20 percent of U.S. Government fixed income securities and 26 percent of corporate bonds for WGL’s post-retirement benefit plans.

(d)At December 31, 2018, investments in a private equity/limited partnership consisted of common stock of international companies.

(e)At December 31, 2018, this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable.

64

Total	Fair value			Level 1		Level 2		Percentage of Plan Assets (%)
Cash and short-term equivalents	$	8.0		$	8.0	$	—	0.4
Canadian equities	5.8			5.8		—		0.3
Foreign equities (a)	275.3			272.7		2.6		12.8
Fixed income	855.6			104.7		750.9		39.6
Derivatives	9.3			—		9.3		0.4
Real estate	0.8			—		—		—
Other	10.9			—		11.7		0.5
Total investments in the fair value hierarchy	$	1,165.7		$	391.2	$	774.5	54.0
Investments measured at net asset value using the NAV practical expedient (b)
Commingled funds and pooled separate accounts (c)	945.3							43.8
Private Equity/Limited Partnership (d)	48.2							2.2
Total fair value of plan investments	$	2,159.2						100.0
Net payable (e)	(0.1		)					—
	$	2,159.1						100.0

(a)Investments in foreign equities include U.S. and international securities.

(b)In accordance with ASC Topic 820, these investments are measured at fair value using net asset value (NAV) per share as a practical expedient and, therefore, have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliations of the fair value hierarchy to the statements of net assets available for plan benefits.

(c)As of December 31, 2018, investments in commingled funds and a pooled separate account consisted of approximately 89 percent common stock U.S. companies; 10 percent income producing properties located in the United States; and 1 percent short-term money market investments for WGL’s defined benefit plans and 54 percent of common stock of large-cap U.S. companies, 20 percent of U.S. Government fixed income securities and 26 percent of corporate bonds for WGL’s post-retirement benefit plans.

(d)At December 31, 2018, investments in a private equity/limited partnership consisted of common stock of international companies.

(e)At December 31, 2018, this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable.

		Post-		Post-
Significant actuarial assumptions used in measuring	Defined	Retirement	Defined	Retirement
net benefit plan costs	Benefit	Benefits	Benefit	Benefits
Year ended December 31	2018		2017
Discount rate (%)	3.25 - 4.30	3.60 - 4.30	2.65 - 4.20	4.00 - 4.20
Expected long-term rate of return on plan assets (%) (a)	3.20 - 7.60	3.75 - 7.60	6.18 - 7.30	3.10 - 7.30
Rate of compensation increase (%)	2.75 - 4.10	4.10	2.75 - 4.00	3.25
Average remaining service life of active employees (years)	9.6	14.1	12.7	13.5

(a) Only applicable for funded plans

		Post-		Post-
Significant actuarial assumptions used in measuring	Defined	Retirement	Defined	Retirement
benefit obligations	Benefit	Benefits	Benefit	Benefits
As at December 31	2018		2017
Discount rate (%)	3.60 - 4.40	3.90 - 4.50	2.80 - 3.70	3.60 - 3.70
Rate of compensation increase (%)	2.75 - 4.10	4.10	2.75 - 4.00	3.25

The expected rate of return on assets is based on the current level of expected returns on risk free investments, the historical level of risk premium associated with other asset classes in which the portfolio is invested, and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based on the target asset allocation to develop the expected rate of return on assets assumption for the portfolio.

The discount rate is based on high-quality long-term corporate bonds, with maturities matching the estimated timing and amount of expected benefit payments.

65

The estimates for health care benefits take into consideration increased health care benefits due to aging and cost increases in the future. The assumed health care cost trend rates used to measure the expected cost of benefits for the next year were between 6.4 and 6.5 percent. The health care cost trend rates were assumed to decline to between 2.1 and 5 percent by 2024.

The assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one percentage point change in the assumed health care trend rates would have the following effects for 2018:

	Increase		Decrease
Service and interest costs	$	1.7	$	(1.3	)
Accrued benefit obligation	$	19.8	$	(16.0	)

The following table shows the expected cash flows for defined benefit pension and other-post retirement plans:

			Post-
	Defined		Retirement
	Benefit		Benefits
Expected employer contributions:
2019	$	41.4	$	0.1
Expected benefit payments:
2019	$	109.8	$	25.3
2020	92.2		24.6
2021	95.3		25.0
2022	101.0		25.4
2023	99.4		25.5
2024 - 2028	$	521.9	$	130.9

29.  COMMITMENTS, CONTINGENCIES AND GUARANTEES

Commitments

AltaGas has long-term natural gas purchase and transportation arrangements, electricity purchase arrangements, service agreements, storage contracts, environmental commitments, and operating leases for office space, office equipment, rail cars, and automobile equipment, all of which are transacted at market prices and in the normal course of business.

In connection with the WGL Acquisition, AltaGas and WGL have made commitments related to the terms of the PSC of DC settlement agreement and the conditions of approval from the PSC of MD and the SCC of VA. Among other things, these commitments include rate credits distributable to both residential and non-residential customers, gas expansion and other programs, various public interest commitments, and safety programs. The total amount expensed in 2018 was approximately US$140 million, of which US$111 million has been paid as of December 31, 2018. In addition, there are certain additional regulatory commitments which will be expensed when the costs are incurred in the future, including the hiring of damage prevention trainers, investment of US$70 million over a 10 year period to further extend natural gas service, and US$8 million for leak mitigation.

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Future payments of these commitments at December 31, 2018 are estimated as follows:

	2019		2020		2021		2022		2023		2024 and beyond		Total
Gas purchase(a)	$	3,157.1	$	2,940.5	$	2,639.3	$	2,527.4	$	2,349.9	$	30,309.2	$	43,923.4
Electricity purchase(c)	533.1		368.6		139.2		38.6		5.7		0.4		1,085.6
Service agreements(b)(d)	74.3		48.2		30.9		17.3		14.8		168.0		353.5
Pipeline and storage services(e)	861.6		862.2		818.8		795.6		781.7		4,645.3		8,765.2
Capital projects(f)	119.2		—		—		—		—		—		119.2
Operating leases(g)	23.9		30.9		29.4		28.0		25.8		164.8		302.8
Environmental(h)	6.1		4.7		3.0		0.5		0.4		0.5		15.2
Merger commitments	29.3		30.8		22.8		19.2		19.2		62.1		183.4
	$	4,804.6	$	4,285.9	$	3,683.4	$	3,426.6	$	3,197.5	$	35,350.3	$	54,748.3

(a)AltaGas enters into contracts to purchase natural gas from various suppliers for its utilities. These contracts are used to ensure that there is an adequate supply of natural gas to meet the needs of customers and to minimize exposure to market price fluctuations. Gas purchase commitments are valued based on forward prices, which may fluctuate significantly from period to period.

(b)In 2014, AltaGas’ Blythe facility entered into a Long-Term Service Agreement with Siemens to complete various upgrade and maintenance services on the Combustion Turbines (CT) at the Blythe facility over 124,000 equivalent operating hour per CT, or 25 years, whichever comes first. The LTSA has fixed fees that will be incurred in the five years following December 31, 2014 and variable fees on a per equivalent operating hour basis. As at December 31, 2018, the total commitment was $190.9 million payable over the next 16 years, of which $59.6 million is expected to be paid over the next five years.

(c)AltaGas enters into contracts to purchase electricity from various suppliers for its utilities. Electricity purchase commitments are based on existing fixed price and fixed volume contracts, and include $44.1 million of commitments related to renewable energy credits.

(d)In 2017, AltaGas entered into a 12-year service agreement for tug services to support the marine operations of RIPET. AltaGas is obligated to pay fixed and variable fees of approximately $60.1 million over the term of the contract.

(e)Pipeline and storage commitments include minimum payments for natural gas transportation, storage and peaking contracts that have expiration dates through 2044.

(f)Commitments for capital projects. Estimated amounts are subject to variability depending on the actual construction costs.

(g)Operating leases include lease arrangements for office spaces, vehicles, rail cars, land, office and other equipment.

(h)Environmental commitments relate to future costs associated with sites where AltaGas or its predecessors may have operated manufactured gas plants.

Guarantees

AltaGas has guaranteed payments primarily for certain commitments on behalf of some of its subsidiaries. AltaGas has also guaranteed payments for certain of its external partners. As at December 31, 2018, AltaGas has no guarantees to external parties.

Contingencies

AltaGas and its subsidiaries are subject to various legal claims and actions arising in the normal course of business. While the final outcome of such legal claims and actions cannot be predicted with certainty, the Corporation does not believe that the resolution of such claims and actions will have a material impact on the Corporation’s consolidated financial position or results of operations.

As a result of the WGL Acquisition, AltaGas has the following additional contingencies:

Antero Contract

Washington Gas and WGL Midstream contracted in June 2014 with Antero Resources Corporation (Antero) to buy gas from Antero at invoiced prices based on an index, and at a delivery point, specified in the contracts. Since deliveries began, however, the index price paid has been more than the fair market value at the same physical delivery point, resulting in losses within WGL entities of approximately US$40 million. Accordingly, Washington Gas and WGL Midstream notified Antero that it sought to apply a provision of the contracts that would permit a new index to be established. Antero objected, claiming that the contract provisions permitting re-pricing did not apply, unless Antero itself chose to sell gas at cheaper prices at the delivery point (which Antero claimed it had not). The dispute was arbitrated in January 2017, and the arbitral tribunal ruled in favor of Antero on the applicability of the re-pricing mechanism. However, the tribunal ruled that it lacked authority to determine whether Antero was in breach of its obligation to deliver gas to Washington Gas and WGL Midstream at a point where they could obtain the higher pricing. Accordingly, Washington Gas and WGL Midstream filed suit in state court in Colorado for a determination of this issue.

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The state court initially granted Antero’s motion to dismiss the case and WGL subsequently filed an appeal. In October 2018, the Court of Appeals reversed the state court’s decision and remanded the lawsuit to the trial court.

Separately, Antero has initiated suit against Washington Gas and WGL Midstream, claiming that they have failed to purchase specified daily quantities of gas and seeking alleged cover damages exceeding US$100 million as of April 4, 2018 according to Antero’s complaint. Washington Gas and WGL Midstream oppose both the validity and amount of Antero’s claim. WGL believes the probability that Antero could succeed in collecting these penalties is remote therefore no accrual was made as of December 31, 2018. In December 2017, WGL Midstream amended its purchase contract with Antero and, effective February 1, 2018, is no longer obligated to purchase gas at the delivery point that is the subject of these disputes.

These two cases have been consolidated and a jury trial has been scheduled for June 10, 2019.

Silver Spring, Maryland Incident

Washington Gas has continually worked with the National Transportation and Safety Board (NTSB) to support its investigation of the August 2016 explosion and fire at an apartment complex on Arliss Street in Silver Spring, Maryland, the cause of which has not been determined. Additional information will be made available by the NTSB at the appropriate time. A total of 40 civil actions related to the incident have been filed against WGL and Washington Gas in the Circuit Court for Montgomery County, Maryland. All of these suits seek unspecified damages for personal injury and/or property damage. The one class action suit filed against WGL and Washington Gas was amended to assert property damage and loss of use claims. WGL maintains excess liability insurance coverage from highly-rated insurers, subject to a nominal self-insured retention and expects this coverage will be sufficient to cover any significant liability to it that may result from this incident. Management is unable to determine a range of potential losses that is reasonably possible of occurring and therefore has not recorded a reserve associated with this incident. Washington Gas was invited by the NTSB to be a party to the investigation and in that capacity, continues to work closely with the NTSB. The NTSB has scheduled a hearing for April 23, 2019 to determine the probable cause of the incident.

30.  RELATED PARTY TRANSACTIONS

In the normal course of business, AltaGas transacts with its subsidiaries, affiliates and joint ventures. Amounts due to or from related parties on the Consolidated Balance Sheets were measured at the exchange amount and were as follows:

As at	December 31, 2018		December 31, 2017
Due from related parties
Accounts receivable (a)	$	60.8	$	0.8
Long-term investments and other assets (b)	45.0		75.0
	$	105.8	$	75.8
Due to related parties
Accounts payable (c)	6.3		3.2
Risk management liabilities - current (d)	0.9		—
	$	7.2	$	3.2

(a)Receivables from joint ventures and ACI.

(b)AltaGas has provided a $100.0 million interest bearing secured loan facility to Petrogas of which $50.0 million is committed. The facility is available for Petrogas to draw upon from time to time for general corporate purposes. The facility is subject to annual renewal and has a maturity date of June 27, 2021. As at December 31, 2018, Petrogas had drawn $45.0 million (December 31, 2017 - $75.0 million) under the facility.

(c)Payables to ACI and a joint venture.

(d)Foreign exchange hedge with ACI.

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The following transactions with related parties have been recorded on the Consolidated Statements of Income for the year ended December 31, 2018 and 2017:

Year ended December 31	2018			2017
Revenue (a)	$	68.4		$	15.0
Cost of sales (b)	$	(4.2	)	$	(6.5	)
Operating and administrative expenses (c)	$	1.3		$	—
Other income (d)	$	9.2		$	4.4

(a)In the ordinary course of business, AltaGas sold natural gas and natural gas liquids to a joint venture and ACI. In addition, subsequent to the IPO of ACI, AltaGas is providing certain day-to-day services to ACI under a Transition Services Agreement on a cost recovery basis. The Transition Services Agreement will operate until June 30, 2020, subject to earlier termination in certain circumstances, and is extendable by mutual agreement of the parties. Revenue also includes an unrealized loss on a foreign exchange hedge with ACI of $0.2 million in 2018 (2017 - $nil).

(b)In the ordinary course of business, AltaGas obtained natural gas storage services from a joint venture as well as incurred costs related to the sale of natural gas liquids to affiliates.

(c)Administrative costs recovered from joint ventures. In 2017, amount was offset by the expense associated with the forgiveness of a loan to an executive.

(d)Interest income from loans to Petrogas (secured loan facility) and loans to ACI. Subsequent to the IPO of ACI, AltaGas provided certain loans to ACI for a portion of the year. Loans to ACI were fully repaid by December 31, 2018.

31.  SUPPLEMENTAL CASH FLOW INFORMATION

The following table details the changes in operating assets and liabilities from operating activities:

				Year ended December 31
	2018			2017
Source (use) of cash:
Accounts receivable	$	(526.9	)	$	(55.6	)
Inventory	(100.8		)	4.7
Other current assets	12.5			7.0
Regulatory assets (current)	(15.8		)	(0.2		)
Accounts payable and accrued liabilities	237.9			85.4
Customer deposits	(13.3		)	(2.8		)
Regulatory liabilities (current)	69.2			(4.8		)
Other current liabilities	(5.9		)	13.0
Other operating assets and liabilities	(143.4		)	(44.8		)
Changes in operating assets and liabilities	$	(486.5	)	$	1.9

The following cash payments have been included in the determination of earnings:

			Year ended December 31
	2018		2017
Interest paid (net of capitalized interest)	$	288.9	$	151.1
Income taxes paid	$	36.9	$	36.3

The following table is a reconciliation of cash and restricted cash balances:

As at December 31	2018		2017
Cash and cash equivalents	$	101.6	$	27.3
Restricted cash holdings from customers - current	4.1		8.9
Restricted cash holdings from customers - non-current	6.1		7.5
Restricted cash included in prepaid expenses and other current assets(a)	27.6		—
Restricted cash included in long-term investments and other assets(a)	61.7		—
Cash, cash equivalents and restricted cash per consolidated statement of cash flow	$	201.1	$	43.7

(a)The restricted cash balances included in prepaid expenses and other current assets and long-term investments and other assets relates to Rabbi trusts associated with WGL’s pension plans (Note 28). On the date of the WGL Acquisition, the restricted cash balances related to Rabbi trusts was $81.0 million.

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32.  SEGMENTED INFORMATION

AltaGas owns and operates a portfolio of assets and services used to move energy from the source to the end-user. The following describes the Corporation’s four reporting segments:

Utilities	–	rate-regulated natural gas distribution assets in Michigan, Alaska, the District of Columbia, Maryland, and Virginia;
	–	rate-regulated natural gas storage in the United States; and
	–	equity investment in AltaGas Canada Inc.
Midstream	–	NGL processing and extraction plants;
	–	transmission pipelines to transport natural gas and NGL;
	–	natural gas gathering lines and field processing facilities;
	–	purchase and sale of natural gas;
	–	natural gas storage facilities;
	– –	liquefied petroleum gas (LPG) terminal currently under construction; natural gas and NGL marketing;
	–	equity investment in Petrogas, a North American entity engaged in the marketing, storage and distribution of NGL, drilling fluids, crude oil and condensate diluents;
	–	interests in four regulated gas pipelines in the Marcellus/Utica basins; and
	–	sale of natural gas to residential, commercial and industrial customers in Washington D.C., Maryland, Virginia, Delaware, and Pennsylvania.
Power	–	natural gas-fired, biomass, and solar power generation assets, whereby outputs are generally sold under power purchase agreements, both operational and under development;
	–	energy storage; and
	–	sale of power to residential, commercial and industrial users in Washington D.C., Maryland, Virginia, Delaware, and Pennsylvania.
Corporate	–	the cost of providing corporate services, financing and general corporate overhead, investments in certain public and private entities, corporate assets, financing other segments and the effects of changes in the fair value of certain risk management contracts.

The following table provides a reconciliation of segment revenue to the disaggregated revenue table as disclosed under Note 23:

	Year ended December 31, 2018
	Utilities		Midstream		Power		Corporate			Total
External revenue (note 23)	$	1,752.6	$	1,344.6	$	1,162.0	$	(2.5	)	$	4,256.7
Intersegment revenue	13.0		90.4		9.0		0.1			112.5
Segment revenue	$	1,765.6	$	1,435.0	$	1,171.0	$	(2.4	)	$	4,369.2

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Geographic Information

Year ended December 31	2018		2017
Revenue(a)
Canada	$	1,626.8	$	1,508.8
United States	2,553.0		1,109.9
Total	$	4,179.8	$	2,618.7

(a)Operating revenue from external customers, excluding unrealized gains (losses) on risk management contracts.

As at December 31	2018		2017
Property, plant and equipment
Canada	$	2,348.2	$	4,320.5
United States	8,581.4		2,369.3
Total	$	10,929.6	$	6,689.8

The following tables show the composition by segment:

	Year ended December 31, 2018
	Utilities			Midstream			Power			Corporate			Intersegment Elimination(a)			Total
Segment revenue	$	1,765.6		$	1,435.0		$	1,171.0		$	(2.4	)	$	(112.5	)	$	4,256.7
Cost of sales	(838.3		)	(976.4		)	(743.7		)	—			103.1			(2,455.3		)
Operating and administrative	(727.4		)	(201.7		)	(159.1		)	(50.6		)	9.8			(1,129.0		)
Accretion expenses	(0.1		)	(4.0		)	(6.8		)	—			—			(10.9		)
Depreciation and amortization	(165.8		)	(84.4		)	(130.5		)	(13.3		)	—			(394.0		)
Provisions on assets (note 10)	(193.7		)	(153.7		)	(381.3		)	—			—			(728.7		)
Income from equity investments	7.2			51.1			(10.4		)	—			—			47.9
Other income (loss)	4.5			0.7			(5.9		)	2.0			(0.4		)	0.9
Foreign exchange gains	—			(0.2		)	(0.1		)	4.8			—			4.5
Interest expense	(103.9		)	(10.6		)	(8.9		)	(185.6		)	—			(309.0		)
Loss before income taxes	$	(251.9	)	$	55.8		$	(275.7	)	$	(245.1	)	$	—		$	(716.9	)
Net additions (reductions) to:
Property, plant and equipment(b)	$	507.0		$	383.4		$	(321.9	)	$	4.0		$	—		$	572.5
Intangible assets	$	21.8		$	4.7		$	12.5		$	6.7		$	—		$	45.7

(a)Intersegment transactions are recorded at market value.

(b)Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statement of Cash flow due to classification of business acquisition and foreign exchange changes on U.S. assets.

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	Year ended December 31, 2017
	Utilities			Midstream			Power			Corporate			Intersegment Elimination(a)			Total
Segment revenue	$	1,126.7		$	1,008.0		$	631.7		$	(58.4	)	$	(151.8	)	$	2,556.2
Cost of sales	(610.1		)	(647.0		)	(242.8		)	—			142.8			(1,357.1		)
Operating and administrative	(226.1		)	(165.0		)	(93.1		)	(97.5		)	9.5			(572.2		)
Accretion expenses	(0.1		)	(3.9		)	(6.9		)	—			—			(10.9		)
Depreciation and amortization	(81.8		)	(68.6		)	(118.0		)	(14.0		)	—			(282.4		)
Provision on assets	—			(6.6		)	(133.0		)	—			—			(139.6		)
Income from equity investments	2.6			22.0			6.8			—			—			31.4
Other income (loss)	3.9			(0.9		)	0.8			6.3			(0.5		)	9.6
Foreign exchange gains	—			0.2			—			1.5			—			1.7
Interest expense	—			—			—			(170.3		)	—			(170.3		)
Income (loss) before income taxes	$	215.1		$	138.2		$	45.5		$	(332.4	)	$	—		$	66.4
Net additions (reductions) to:
Property, plant and equipment(b)	$	124.3		$	245.3		$	16.5		$	1.5		$	—		$	387.6
Intangible assets	$	2.1		$	2.8		$	13.2		$	2.2		$	—		$	20.3

(a)Intersegment transactions are recorded at market value.

(b)Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statement of Cash flow due to classification of business acquisition and foreign exchange changes on U.S. assets.

The following table shows goodwill and total assets by segment:

	Utilities		Midstream		Power		Corporate		Total
As at December 31, 2018
Goodwill	$	3,450.8	$	426.4	$	191.0	$	—	$	4,068.2
Segmented assets	$	12,991.3	$	6,398.8	$	3,814.7	$	282.9	$	23,487.7
As at December 31, 2017
Goodwill	$	664.7	$	152.6	$	—	$	—	$	817.3
Segmented assets	$	3,460.2	$	3,096.8	$	3,192.5	$	282.7	$	10,032.2

33.  SUBSEQUENT EVENTS

Subsequent events have been reviewed through February 27, 2019, the date these Consolidated Financial Statements were issued. On January 31, 2019, AltaGas completed the sale of its remaining interest in the Northwest Hydro facilities for net proceeds of approximately $1.37 billion. On February 1, 2019, AltaGas completed the sale of non-core Midstream and Power assets in Canada.

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Supplementary Quarterly Operating Information

	Q4-18		Q3-18		Q2-18		Q1-18		Q4-17
OPERATING HIGHLIGHTS
UTILITIES
U.S. Utilities
Natural gas deliveries end use (Bcf) (1)	58.5		10.9		12.0		31.0		24.3
Natural gas deliveries transportation (Bcf)(1)	52.0		25.7		10.9		13.4		14.2
Service sites(2)	1,642,523		1,759,154		580,526		582,871		581,518
Degree day variance from normal - SEMCO Gas (%)(3)	7.5		(17.8	)	14.8		3.0		4.8
Degree day variance from normal - ENSTAR (%)(3)	(19.6	)	(31.2	)	(6.1	)	(1.7	)	(8.3	)
Degree day variance from normal - Washington Gas (%)(3)(4)	0.4		(4.1	)	n/a		n/a		n/a
MIDSTREAM
Total inlet gas processed (Mmcf/d)(5)	1,413		1,333		1,227		1,553		1,424
Extraction volumes (Bbls/d)(5)(6)	64,522		60,945		49,728		74,786		68,306
Frac spread - realized ($/Bbl)(5)(7)	15.84		15.60		14.98		19.01		18.02
Frac spread - average spot price ($/Bbl)(5)(8)	21.00		25.87		22.19		22.25		30.66
Natural gas optimization inventory (Bcf)	35.9		36.7		1.3		—		2.5
WGL retail energy marketing - gas sales volumes (Mmcf)	20,750		8,155		n/a		n/a		n/a
POWER
Renewable power sold (GWh)	233		690		504		126		301
Conventional power sold (GWh)	985		1,255		642		842		1,059
Renewable capacity factor (%)	14.6		44.6		51.7		8.1		27.5
Contracted conventional availability factor (%)(9)	97.4		98.5		97.7		94.5		96.3
WGL retail energy marketing - electricity sales volumes (GWh)	2,911		3,000		n/a		n/a		n/a

(1)Petajoule (PJ) is one million gigajoules (GJ). Bcf is one billion cubic feet.

(2)Service sites reflect all service sites of the utilities, including transportation and non-regulated business lines.

(3)A degree day for U.S. Utilities is a measure of coldness, determined daily as the number of degrees the average temperature during the day in question is below 65 degrees Fahrenheit. Degree days for a particular period are determined by adding the degree days incurred during each day of the period. Normal degree days for a particular period are the average of degree days during the prior 15 years for SEMCO Energy Gas Company, during the prior 10 years for ENSTAR, and during the prior 30 years for Washington Gas.

(4)In certain of Washington Gas’ jurisdictions (Virginia and Maryland) there are billing mechanisms in place which are designed to eliminate the effects of variance in customer usage caused by weather and other factors such as conservation. In the District of Columbia, there is no weather normalization billing mechanism nor does it hedge to offset the effects of weather. As a result, colder or warmer weather will result in variances to financial results.

(5)Average for the period.

(6)Includes Harmattan NGL processed on behalf of customers.

(7)Realized frac spread or NGL margin, expressed in dollars per barrel of NGL, is derived from sales recorded by the segment during the period for frac exposed volumes plus the settlement value of frac hedges settled in the period less extraction premiums, divided by the total frac exposed volumes produced during the period.

(8)Average spot frac spread or NGL margin, expressed in dollars per barrel of NGL, is indicative of the average sales price that AltaGas receives for propane, butane and condensate less extraction premiums, before accounting for hedges, divided by the respective frac exposed volumes for the period.

(9)Calculated as the availability factor contracted under long-term tolling arrangements adjusted for occasions where partial or excess capacity payments have been added or deducted.

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Other Information

DEFINITIONS

Bbls/d	barrels per day
Bcf	billion cubic feet
GJ	gigajoule
GWh	gigawatt-hour
Mcf	thousand cubic feet
Mmcf/d	million cubic feet per day
MW	megawatt
MWh	megawatt-hour
MMBTU	million British thermal unit
PJ	petajoule
US$	United States dollar

ABOUT ALTAGAS

AltaGas is an energy infrastructure company with a focus on midstream, regulated utilities and power. The Corporation creates value by acquiring, growing and optimizing its energy infrastructure, including a focus on clean energy sources. For more information visit: www.altagas.ca.

For further information contact:

Investment Community

1-877-691-7199

investor.relations@altagas.ca

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APPENDIX C

MANAGEMENT’S DISCUSSION AND ANALYSIS

MANAGEMENT’S DISCUSSION AND ANALYSIS

The Management’s Discussion and Analysis (MD&A) of operations is provided to enable readers to assess the results of operations, liquidity and capital resources of AltaGas Ltd. (AltaGas or the Corporation) as at and for the year ended December 31, 2018. This MD&A, dated February 27, 2019, should be read in conjunction with the accompanying audited Consolidated Financial Statements and notes thereto of AltaGas as at, and for the year ended, December 31, 2018.

The Consolidated Financial Statements and comparative information have been prepared in accordance with United States (U.S.) generally accepted accounting principles (U.S. GAAP) and in Canadian dollars, unless otherwise indicated. Throughout this MD&A, references to GAAP refer to U.S. GAAP.

This MD&A contains forward looking information (forward looking statements). Words such as “may”, “can”, “would”, “could”, “should”, “will”, “intend”, “plan”, “anticipate”, “believe”, “aim”, “seek”, “propose”, “contemplate”, “estimate”, “forecast”, “expect”, “project”, “target”, “potential”, “objective”, “continue”, “outlook”, “vision”, “opportunity” and similar expressions suggesting future events or future performance, as they relate to the Corporation or any affiliate of the Corporation, are intended to identify forward looking statements. In particular, this MD&A contains forward looking statements with respect to, among other things, business objectives, the anticipated benefits of acquisitions and other major projects, the anticipated timing of commercial operations, investment decisions, expenditures and licensing and permitting, expected growth and drivers of growth, capital expenditures (including in respect of the 2019 capital program, expected allocation per business segment and project and anticipated sources of financing thereof), results of operations, operational and financial performance, business projects, opportunities and financial results.

Specifically, such forward looking statements are set forth under the headings: “Recent Developments”, “2018 Financial Highlights”, “Strategy”, “2019 Outlook”, “Sensitivity Analysis”, “Growth Capital”, “Utilities”, “Midstream”, “Power”, “Contractual Obligations” and “Future Changes in Accounting Principles” and under those headings specifically include AltaGas’ expectation of additional asset sales in 2019; expectations regarding the effect of the dividend reset on anticipated retained cash dividends through 2023; expectation that the dividend reset will provide an efficient source of funding for future growth; AltaGas’ belief that it can help to meet the growing global demand for clean energy, while continuing to deliver sustainable benefits to shareholders; expectation regarding consolidated normalized EBITDA that will be achieved in 2019; expectation regarding the normalized funds from operations in 2019; expectation that the WGL Acquisition will drive growth in all three business segments; expectation that growth in the Midstream segment will largely be driven by a full year of WGL results and RIPET coming into service; first scheduled ship expected to RIPET early in the second quarter of 2019; the expectation that the Power segment will be impacted by the non-core power sales and the sale of the remaining interest in the Northwest Hydro facilities; the average exposure to frac spreads prior to hedging activities; exposure to the propane price differential between Mont Belvieu and Far East Index once RIPET is in service; the effect of changes in commodity prices, exchange rates and weather on AltaGas’ expected normalized EBITDA for 2019; expected net invested capital expenditures in 2019; anticipated capital expenditure allocations between the three business segments; expected maintenance capital expenditures; expected funding sources for the 2019 committed capital program; expectation for RIPET to be the first propane export facility off the west coast of Canada; expected construction cost of RIPET; expectation that RIPET will ship 1.2 million tonnes of propane per annum; expectation that RIPET will begin its operational phase in the first quarter of 2019; expectation of having physical volumes equal to the initial 40,000 Bbls/d target by RIPET’s in-service date; expected ownership percentage in the expansion of Leidy South; Leidy South’s anticipated in-service date; expected transport capacity, span, construction completion date and in-service date of the Mountain Valley Pipeline; expectation regarding WGL Midstream’s investment in Mountain Valley; proposed commitment of WGL Midstream in and in-service date of the MVP Southgate project; estimated project cost and on-stream date for Townsend 2B; expected capital investment in and on-stream date for Nig Creek Plant 2; cost and expected on stream timing for North Pine; the timing of judicial appeals regarding, capacity of and commencement date for first phase of the Alton Natural Gas Storage Project; anticipated future expenditures for the Washington Gas accelerated pipe replacement program; timing, magnitude and cost to Washington Gas of PROJECTpipes; estimated cost of the second STRIDE plan; expected 2019 customer growth for Washington Gas, SEMCO and ENSTAR; expected date for PSC of MD and SCC of VA decisions on various Washington Gas applications; anticipated construction completion and in-service dates for the

AltaGas Ltd. – 2018

1

Marquette Connector Pipeline; anticipation that ENSTAR will address excess deferred income taxes in its next rate case to be filed in 2021; anticipated timing of pending CINGSA rulings and rate case hearings; AltaGas’ objectives; expectations regarding the growth of AltaGas’ infrastructure; expected sources of growth and increased volumes in the Midstream segment; expected source of funds to pay contractual obligations; potential impacts of risk mitigation strategies and expected future changes in accounting principles.

These statements involve known and unknown risks, uncertainties and other factors that may cause actual results, events and achievements to differ materially from those expressed or implied by such statements. Such statements reflect AltaGas’ current expectations, estimates and projections at the time the statement was made. Material assumptions include, but are not limited to: expected commodity supply, demand and pricing; volumes and rates; exchange rates; inflation; interest rates; credit rating; regulatory approvals and policies; future operating and capital costs; project completion dates; capacity expectations; weather patterns; counterparty contract compliance; the outcomes of significant commercial contract negotiations and availability of financing.

AltaGas’ forward looking statements are subject to certain risks and uncertainties which could cause results or events to differ from current expectations, including without limitation: access to and use of capital markets; market value of AltaGas’ securities; AltaGas’ ability to pay dividends; AltaGas’ ability to service or refinance its debt and manage its credit rating and risk; prevailing economic conditions; potential litigation; AltaGas’ relationships with external stakeholders, including Indigenous stakeholders; volume throughput and the impacts of commodity pricing, supply, composition and other market risks; available electricity prices; interest rate, exchange rate and counterparty risks; legislative and regulatory environment; underinsured losses; weather, hydrology and climate changes; the potential for service interruptions; availability of supply from Cook Inlet; availability of biomass fuel; AltaGas’ ability to economically and safely develop, contract and operate assets; AltaGas’ ability to update infrastructure on a timely basis; AltaGas’ dependence on certain partners; impacts of climate change and carbon taxing; effects of decommissioning, abandonment and reclamation costs; impact of labour relations and reliance on key personnel; cybersecurity risks; and other factors set forth under the heading “Risk Factors” in AltaGas’ annual information form (AIF) for the year ended December 31, 2018.  AltaGas’ AIF is available under the Corporation’s profile on www.sedar.com.

Many factors could cause AltaGas’ or any of its business segments’ actual results, performance or achievements to vary from those described in this MD&A including, without limitation, those listed above as well as the assumptions upon which they are based proving incorrect. These factors should not be construed as exhaustive. Should one or more of these risks or uncertainties materialize, or should assumptions underlying forward looking statements prove incorrect, actual results may vary materially from those described in this MD&A as intended, planned, anticipated, believed, sought, proposed, estimated, forecasted, expected, projected or targeted and such forward looking statements included in this MD&A should not be unduly relied upon. The impact of any one assumption, risk, uncertainty or other factor on a particular forward looking statement cannot be determined with certainty because they are interdependent and AltaGas’ future decisions and actions will depend on management’s assessment of all information at the relevant time. These statements speak only as of the date of this MD&A. AltaGas does not intend, and does not assume any obligation, to update these forward looking statements except as required by applicable law. The forward looking statements contained in this MD&A are expressly qualified by these cautionary statements.

Financial outlook information contained in this MD&A about prospective financial performance, financial position or cash flows is based on assumptions about future events, including economic conditions and proposed courses of action, based on AltaGas management’s (Management) assessment of the relevant information currently available. Readers are cautioned that such financial outlook information contained in this MD&A should not be used for purposes other than for which it is disclosed herein.

Additional information relating to AltaGas, including its quarterly and annual MD&A and Consolidated Financial Statements, AIF, and press releases are available through AltaGas’ website at www.altagas.ca or through SEDAR at www.sedar.com.

RECENT DEVELOPMENTS

2019 Planned Asset Sales and Balanced Funding Plan

On December 13, 2018, AltaGas announced that it has reached an agreement for the sale of its remaining interest of approximately 55 percent in the Northwest Hydro Electric facilities in British Columbia (Northwest Hydro). Total proceeds are

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approximately $1.37 billion and the sale closed in January 2019. Including this sale, AltaGas has successfully monetized approximately $3.8 billion of non-core assets since mid-2018, providing an efficient source of capital, as well as reshaping the asset portfolio and allowing AltaGas to prioritize core focus areas. Additional asset sales of approximately $1.5 to $2.0 billion are planned for 2019, which are expected to further de-lever the Corporation, fund future growth, and minimize the need for any near-term common equity requirements.

As part of the balanced funding plan, approximately US$2.2 billion of the bridge facility used to finance the acquisition of WGL Holdings, Inc. (the WGL Acquisition) was repaid in December 2018 and refinanced with a new US$1.2 billion revolving credit facility. In addition, the Board of Directors (the Board) approved a reset of the dividend to improve the financial strength of AltaGas and ensure greater funding flexibility. The Board declared a January 2019 dividend of $0.08 per common share, which equates to $0.96 annually and represented a 56 percent reduction from 2018. The dividend reset is expected to result in an additional approximate $1.3 billion in anticipated retained cash dividends through 2023, providing an efficient source of funding for future growth.

Public Offering of AltaGas Canada Inc.

On October 25, 2018, the initial public offering (IPO) of AltaGas Canada Inc. (ACI) was successfully completed, reflecting a final price of $14.50 per common share of ACI. The over-allotment option was exercised in full, and as a result, AltaGas holds approximately 37 percent of ACI common shares at December 31, 2018. Net proceeds (consisting of cash and debt) to AltaGas after the deduction of underwriting fees and expenses were approximately $892 million. ACI holds Canadian rate-regulated natural gas distribution utility assets and contracted wind power in Canada, as well as an approximate 10 percent indirect equity interest in the Northwest Hydro facilities.

Sales of Non-Core Midstream and Power Assets

On September 10, 2018, AltaGas announced that it had entered into definitive agreements for the sale of non-core midstream and power assets in Canada and power assets in the United States, for total gross proceeds of approximately $560 million.

In November 2018, AltaGas completed the sale of gas-fired power assets in California to Middle River Power III (Middle River), a whole owned-subsidiary of Avenue Capital, for a gross purchase price of approximately US$299 million. The assets comprise the Tracy, Hanford and Henrietta plants totaling 523 MW of capacity. The effective date of the transaction was September 1, 2018. In addition, in the fourth quarter of 2018, AltaGas’ 50 percent interest in the Busch Ranch wind asset in the United States was sold for approximately US$16 million.

The sale of non-core midstream and power assets in Canada was to Birch Hill Equity Partners Management Inc., as general partner of Birch Hill Equity Partners Fund V (Birch Hill). Included in the sale was AltaGas’ commercial and industrial customer portfolio in Canada as well as 43.7 million shares of Tidewater Midstream and Infrastructure Inc. (Tidewater). The net proceeds, including approximately $63 million for the Tidewater shares, was approximately $165 million. The sale of the Tidewater shares was completed in September 2018 for proceeds of approximately $63 million, while the remainder of the transaction closed in February 2019.

ALTAGAS ORGANIZATION

The businesses of AltaGas are operated by AltaGas and a number of its subsidiaries including, without limitation, AltaGas Services (U.S.) Inc., AltaGas Utility Holdings (U.S.) Inc., WGL Holdings Inc. (WGL), Wrangler 1 LLC, Wrangler SPE LLC, Washington Gas Resources Corporation, WGL Energy Services, Inc., and SEMCO Holding Corporation; in regards to the Midstream business, AltaGas Extraction and Transmission Limited Partnership, AltaGas Pipeline Partnership, AltaGas Processing Partnership, AltaGas Northwest Processing Limited Partnership, Harmattan Gas Processing Limited Partnership, and WGL Midstream Inc. (WGL Midstream); in regards to the Power business, AltaGas Power Holdings (U.S.) Inc., WGSW, Inc., WGL Energy Systems, Inc., and Blythe Energy Inc. (Blythe); and, in regards to the Utility business, Washington Gas Light Company, Hampshire Gas Company, and SEMCO Energy, Inc. (SEMCO). SEMCO conducts its Michigan natural gas

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distribution business under the name SEMCO Energy Gas Company (SEMCO Gas) and its Alaska natural gas distribution business under the name ENSTAR Natural Gas Company (ENSTAR).

OVERVIEW OF THE BUSINESS

AltaGas, a Canadian corporation, is a leading North American clean energy infrastructure company with strong growth opportunities and a focus on owning and operating assets to provide clean and affordable energy to its customers. The Corporation’s long-term strategy is to grow in attractive areas across its Utility, Midstream, and Power business segments seeking optimal capital deployment. In the Midstream business, the Corporation is focused on optimizing the full value chain of energy exports by providing producers with solutions, including global market access off both coasts of North America via the Corporation’s footprint in two of the most prolific gas plays — the Montney and Marcellus. To optimize capital deployment, the Corporation seeks to invest in U.S utilities located in strong growth markets with increasing construction to support customer additions, system improvement and accelerated replacement programs. In the Power business, AltaGas seeks to create innovative solutions with light capital investment utilizing the Corporation’s clean energy expertise. AltaGas has three business segments:

·Utilities, which serves approximately 1.6 million customers with a rate base of approximately US$3.7 billion through ownership of regulated natural gas distribution utilities across five jurisdictions in the United States and two regulated natural gas storage utilities in the United States, delivering clean and affordable natural gas to homes and businesses. The Utilities business also includes storage facilities and contracts for interstate natural gas transportation and storage services;

·Midstream, which, subsequent to the sale of non-core midstream assets in Canada that closed in February 2019, transacts more than 1.5 Bcf/d of natural gas and includes natural gas gathering and processing, natural gas liquids (NGL) extraction and fractionation, transmission, storage, natural gas and NGL marketing, the Corporation’s 50 percent interest in AltaGas Idemitsu Joint Venture Limited Partnership (AIJVLP), an indirectly held one-third ownership investment in Petrogas Energy Corp. (Petrogas), through which AltaGas’ interest in the Ferndale Terminal is held, an interest in four regulated pipelines in the Marcellus/Utica gas formation in the northeastern United States and WGL’s retail gas marketing business; and

·Power, which, subsequent to the sale of non-core power assets in Canada that closed in February 2019, and the sale of the remaining 55 percent interest in the Northwest Hydro facilities which closed in January 2019, includes 1,105 MW of operational gross capacity from natural gas-fired, biomass, solar, other distributed generation and energy storage assets located in Alberta, Canada and 20 states and the District of Columbia in the United States. The Power business also includes energy efficiency contracting and WGL’s retail power marketing business.

2018 GROWTH AND OPERATIONAL HIGHLIGHTS

·On April 3, 2018, AltaGas entered into a long-term natural gas processing arrangement with Birchcliff Energy Ltd. (Birchcliff) at AltaGas’ deep-cut sour gas processing facility located in Gordondale, Alberta. Under the arrangement, Birchcliff is provided with up to 120 MMcf/d of natural gas processing on a firm-service basis, and Birchcliff’s take-or-pay obligation is 100 MMcf/d;

·On July 6, 2018, following the receipt of all required regulatory approvals, AltaGas completed the acquisition of WGL Holdings, Inc. for an aggregate purchase price of approximately $9.3 billion (US$7.1 billion), including the assumption of debt and preferred shares. Upon closing of the WGL Acquisition, 84.5 million subscription receipts were exchanged for common shares;

·On July 25, 2018, AltaGas announced the resignation of David Harris, President and CEO. David Cornhill, the Founder and Chairman of AltaGas, and Phillip Knoll, an experienced industry executive and Board member, acted as interim co-CEOs from July 25, 2018 to December 9, 2018;

·On July 26, 2018, AltaGas announced the expansion of its Board of Directors (the Board) from nine to twelve seats and the appointment of three new directors. The expansion of the Board reflects AltaGas’ scope and growing complexity and the experience and expertise required by the Board to support AltaGas’ business, operations and strategic objectives;

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·On August 27, 2018, AltaGas announced that it has entered into definitive agreements with Kelt Exploration Ltd. (Kelt) to provide an energy infrastructure solution for the liquids-rich Inga Montney development located in British Columbia. This underpins the expansion of AltaGas’ Townsend complex including the addition of a 198 MMcf per day C3+ deep cut gas processing facility and provides Kelt with firm processing of 75 MMcf per day of raw gas under an initial 10 year take-or-pay agreement;

·On September 26, 2018, AltaGas announced that it had entered into a definitive agreement with Black Swan Energy Ltd. (Black Swan) to acquire 50 percent ownership in certain existing and future natural gas processing plants of Black Swan at Aitken Creek. AltaGas and Black Swan will also enter into long term processing, transportation and marketing agreements that include new AltaGas liquids handling infrastructure, strengthening AltaGas’ Northeast B.C. value proposition and connecting producers with additional options for energy exports. The total capital investment by AltaGas is expected to be approximately $230 million and the transaction closed on October 2, 2018;

·On October 4, 2018, the Federal Energy Regulatory Commission (FERC) issued its authorization to place the Central Penn Pipeline (Central Penn) into service. The pipeline began operations on October 6, 2018; and

·On November 20, 2018, AltaGas announced the appointment of Randall Crawford as Chief Executive Officer and member of the Board of Directors, effective December 10, 2018. Mr. Crawford has extensive experience in AltaGas’ base businesses and will lead and develop AltaGas’ ongoing strategy.

2018 FINANCIAL HIGHLIGHTS

(Normalized EBITDA, normalized funds from operations, normalized net income, net debt, and net debt to total capitalization ratio are non-GAAP financial measures. Please see Non-GAAP Financial Measures section of this MD&A.)

·Normalized EBITDA was $1,009 million, an increase of 27 percent compared to $797 million in 2017;

·Normalized funds from operations were $657 million ($2.95 per share), a 7 percent increase compared to $615 million ($3.60 per share) in 2017;

·Net loss applicable to common shares was $502 million ($2.25 per share) compared to net income of $30 million ($0.18 per share) in 2017;

·Normalized net income was $195 million ($0.88 per share), compared to $204 million ($1.19 per share) in 2017;

·Net debt was $10.1 billion as at December 31, 2018, compared to $3.6 billion as at December 31, 2017;

·Net debt to total capitalization ratio was 57 percent as at December 31, 2018, compared to 44 percent as at December 31, 2017;

·On June 13, 2018, a US$2 billion short form base shelf prospectus for the issuance of both debt securities and preferred shares was filed in both Alberta and the U.S. This will enable AltaGas to access the U.S. capital markets on a timely basis over the following 25 months, subject to market conditions;

·On June 13, 2018, AltaGas announced that it had entered into a definitive agreement to indirectly sell 35 percent of its interest in the Northwest Hydro facilities for gross proceeds of $922 million. The transaction closed on June 22, 2018;

·On September 10, 2018, AltaGas announced that it had entered into definitive agreements for the sale of non-core midstream and power assets in Canada and power assets in the United States for total proceeds of approximately $560 million. The sale of the power assets in the United States was completed in the fourth quarter of 2018, and the sale of non-core midstream and power assets in Canada was completed in February 2019;

·On October 25, 2018, the Initial Public Offering (IPO) of AltaGas Canada Inc. (ACI) was successfully completed. Final pricing was $14.50 per ACI common share. The over-allotment option was exercised in full, and as a result, AltaGas owned approximately 37 percent of ACI common shares at December 31, 2018. Net proceeds (consisting of cash and debt) to AltaGas after the deduction of underwriting fees and expenses were approximately $892 million. A previously wholly owned subsidiary of AltaGas, ACI holds Canadian rate-regulated natural gas distribution utility assets and contracted wind power in Canada, as well as an approximate 10 percent indirect equity interest in the Northwest Hydro facilities in British Columbia;

·On October 29, 2018, the Board suspended, until further notice, its Premium Dividend Reinvestment Plan (PDRIP), effective December 18, 2018. The Dividend Reinvestment Plan remained unchanged;

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·On November 28, 2018, AltaGas announced that it did not intend to exercise its right to redeem all or any of its currently outstanding Cumulative Redeemable Five-Year Reset Preferred Shares, Series E (the Series E Shares) on December 31, 2018. As a result, subject to certain conditions, the holders of the Series E Shares had the right to convert all or part of their Series E Shares on a one-for-one basis into Cumulative Redeemable Floating Rate Preferred Shares, Series F (the Series F Shares) on December 31, 2018. Based on conversion notices received, less than the 1 million Series E Shares required to give effect to conversions to Series F Shares were tendered. As a result, none of AltaGas’ outstanding Series E shares were converted to Series F Shares on December 31, 2018; and

·On December 13, 2018, AltaGas announced its 2019 funding plan, financial outlook, and capital plan. This included the announcement of a dividend reset to $0.96 per common share annually, representing a 56 percent reduction. AltaGas also announced that it has reached an agreement for the sale of its remaining indirect equity interest of approximately 55 percent in the Northwest Hydro facilities for proceeds of approximately $1.37 billion. The transaction closed in January 2019. AltaGas also announced the intention to complete additional asset sales of approximately $1.5 to $2.0 billion in 2019.

HIGHLIGHTS SUBSEQUENT TO YEAR END

·On January 31, 2019, AltaGas completed the sale of its remaining interest in the Northwest Hydro facilities for net proceeds of approximately $1.37 billion, enhancing AltaGas’ financial strength and further sharpening the focus on the Midstream and U.S. Utilities businesses; and

·On February 1, 2019, AltaGas completed the sale of Canadian non-core Midstream and Power assets.

ALTAGAS’ VISION AND OBJECTIVE

AltaGas’ vision is to enhance its position as a leading North American diversified energy infrastructure company. The Corporation’s overall objective is to deliver premium service to customers while achieving superior and timely returns on invested capital in the Midstream and Utilities segments. In the Power segment, AltaGas seeks to create innovative solutions with a capital-light investment strategy.

STRATEGY

AltaGas leverages the strength of its assets and expertise along the energy value chain to connect customers with premier energy solutions — from the wellsites of upstream producers to the doorsteps of homes and businesses, to new markets around the world. This strategy is underpinned by the growing demand for clean, reliable and affordable energy and the mounting need for market optionality for North America’s energy industry.

With infrastructure assets in some of the fastest growing energy markets in North America, including prominent positions in the Montney and Marcellus/Utica basins, and utility operations in five states, AltaGas is developing an integrated footprint capable of delivering sustained value to shareholders and customers alike. AltaGas is focused on developing high-quality energy infrastructure underpinned by strong market fundamentals and long-term commercial agreements that provide stable cash flow. AltaGas’ balanced portfolio, including high-growth assets in the Midstream segment combined with predictable and regulated returns in the Utilities segment, provides a resilient and diversified platform for growth.

AltaGas’ Board of Directors is actively engaged in an annual review of AltaGas’ strategy. The Corporation continually assesses the macro and micro-economic trends impacting the businesses and seeks opportunities to generate value for shareholders. The opportunities AltaGas pursues must meet strategic, operating and financial criteria to ensure they align with the long-term strategy and provide ongoing organic growth potential, favorable risk profiles and strong risk-adjusted returns.

To achieve the overarching strategy, AltaGas is focused on five strategic imperatives:

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Delivering Operational Excellence

AltaGas is focused on continually improving how it operates, in order to deliver products and services as safely, efficiently and reliably as possible. With nearly 25 years of experience developing and operating premier assets throughout the energy value chain, AltaGas has the expertise to deliver high-quality capital projects on time and on budget, in close partnership with Indigenous peoples and community stakeholders, without compromising on safety or environmental performance. The Corporation’s disciplined approach to reliability, cost and safety results in a superior quality of service for customers, ensures the safety of employees and members of nearby communities, and enhances returns to shareholders.

Maximizing the Value of the Asset Footprint

AltaGas’ strategy is focused on two core and complementary business segments, Midstream and Utilities. Specifically, AltaGas is targeting opportunities to develop high-quality energy assets that complement its existing integrated infrastructure footprint, and to consolidate its position in key markets to deliver optimal growth over the long term. With a rich and diverse platform of organic growth opportunities, AltaGas’ capital is allocated to projects with strong organic growth potential, strong expected risk-adjusted returns, and long-term, secure commercial underpinning. This highly disciplined approach to capital allocation ensures that investment dollars are directed in a manner that is consistent with AltaGas’ strategy and drive superior and timely expected returns on invested capital. Further, the Corporation continues to assess opportunities to upgrade its portfolio and further align the business to the core strategy.

Advancing AltaGas’ Transformation

On July 6, 2018, AltaGas announced the closing of the acquisition of WGL Holdings, Inc. With the transaction complete, AltaGas is focused on integration, achieving synergies and moving forward as one company with one vision and one strategy. AltaGas has identified near- and long-term integration priorities, including strategy, organizational effectiveness, growth, financial strength and people and culture. Significant progress has been made integrating the WGL leadership team, its operations and some of its core processes, and this will remain a priority for AltaGas moving forward.

Enhancing Financial Strength

With high-quality assets and numerous attractive opportunities for organic growth, a strong balance sheet is crucial. As a growth-oriented energy infrastructure company, AltaGas creates value for investors through minimizing the cost of capital and maximizing return on invested capital in a timely manner. This contributes to the expected maintenance and growth of operating cash flows. Accordingly, the funding plan is designed to strengthen the balance sheet and optimize per share cash flow and earnings growth by taking advantage of attractive growth opportunities in the Midstream and Utilities segments, with the aim of improving credit metrics and providing greater financial flexibility.

A key element of AltaGas’ business model is mitigating exposure to certain market price risks, as well as volume risk. AltaGas has developed risk management processes that mitigate earnings volatility from commodity price risk and volume risk, and proactively hedge foreign exchange rates and commodity price exposures when it is prudent to do so. As well, AltaGas prioritizes the continued management of counterparty credit risk. The Corporation partially mitigates the foreign exchange exposure on U.S. investments by incorporating U.S. dollar (US$) denominated capital, both debt and preferred shares, into the financing strategy.

Responsibility for People, Communities and Environment

The Corporation adheres to a strong set of core values, which reflect the commitment to corporate responsibility and sustainability. AltaGas recognizes the broad range of stakeholders that are reached through its operations, including its employees, members of nearby communities, Indigenous peoples, governments and regulators. As the Corporation continues to evolve and expand its diversified energy assets, AltaGas is committed to operating in a safe, reliable manner, while working closely with stakeholders to maintain positive relationships. By balancing economic priorities with social and environmental values, AltaGas believes it can help meet the growing global demand for clean energy, while continuing to deliver sustainable benefits to shareholders.

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2019 OUTLOOK

With 2019 being the first full year of operations including WGL, AltaGas expects to achieve consolidated normalized EBITDA of approximately $1.2 to $1.3 billion, and normalized funds from operations of approximately $850 to $950 million. This range is net of anticipated asset sales expected to close in 2019, which includes the remaining 55 percent interest in the Northwest Hydro facilities and additional expected 2019 asset sales of approximately $1.5 to $2.0 billion.

The WGL Acquisition is expected to drive growth in all three business segments. The Utilities segment is expected to have the largest contribution to EBITDA, followed by the Midstream and Power segments. Specifically for Utilities, a full year of WGL results will be the largest contributor to growth, along with new capital and rate base growth. Growth in the Midstream segment will largely be driven by a full year of WGL results and Ridley Island Propane Export Terminal (RIPET) coming into service, with the first scheduled ship expected early in the second quarter of 2019. Recent agreements with Kelt, Black Swan and other producers will see increased use of AltaGas’ integrated infrastructure in Northeastern British Columbia, including the North Pine facility (North Pine). In addition, 2019 will be the first full year of operations for the Central Penn Pipeline and AltaGas’ first full year of results from the Stonewall Gas Gathering System (Stonewall). Finally, the Power segment is expected to be impacted by the non-core power sales completed in 2018, as well as the sale of the remaining 55 percent interest in the Northwest Hydro facilities which was completed in January 2019. This will be partially offset by a full year of contributions from WGL’s existing contracted renewable power business and power marketing business.

The overall forecasted normalized EBITDA and funds from operations include assumptions around asset sales anticipated to close in 2019, the U.S./Canadian dollar exchange rate, and other financing initiatives. Within each segment, the performance of the underlying businesses has the potential to vary. Any variance from AltaGas’ current assumptions could impact the forecasted normalized EBITDA and funds from operations.

AltaGas estimates an average of approximately 9,700 Bbls/d will be exposed to frac spreads prior to hedging activities. For 2019, AltaGas has frac hedges in place for approximately 6,200 Bbls/d at an average price of approximately $40/Bbl excluding basis differentials. Once RIPET is in service, AltaGas will be exposed to the propane price differential between Mont Belvieu and Far East Index. AltaGas plans to actively manage this differential through hedging activities.

SENSITIVITY ANALYSIS

AltaGas’ financial performance is affected by factors such as changes in commodity prices, exchange rates and weather. The following table illustrates the approximate effect of these key variables on AltaGas’ expected normalized EBITDA for 2019.

Factor	Increase or decrease			Approximate impact on normalized EBITDA ($ millions)
Natural gas liquids fractionation spread (1)	$		1/Bbl	1
Degree day variance from normal - U.S. utilities (2)	5 percent			5
Change in CAD per US$ exchange rate	0.05			36
FG&P and extraction inlet volumes	10 percent			16
RIPET Propane Far East Index to Mont Belvieu spread (3)	US$	0.02/gal		8

(1)Based on approximately 60 percent of frac spread exposed NGL volumes being hedged.

(2)Degree days - U.S. utilities relate to SEMCO Gas, ENSTAR, and Washington Gas service areas. For U.S. utilities, degree days are a measure of coldness determined daily as the number of degrees the average temperature during the day in question is below 65 degrees Fahrenheit. Degree days for a particular period are determined by adding the degree days incurred during each day of the period. Normal degree days for a particular period are the average of degree days during the prior 15 years for SEMCO Gas, during the prior 10 years for ENSTAR, and during the prior 30 years for Washington Gas.

(3)Assumes RIPET in-service date of early in the second quarter of 2019.The impact on EBITDA due to changes in the spread will vary and will be mitigated through an active hedging program.

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GROWTH CAPITAL

Based on projects currently under review, development or construction, AltaGas expects net invested capital expenditures of approximately $1.3 billion in 2019. The focused and strategic approach to capital expenditures in 2019 will target projects that provide ongoing growth potential, favorable risk profiles, and the strongest risk-adjusted returns with immediate payback, as AltaGas continues to strengthen its balance sheet. The Utilities segment is expected to account for approximately 60 to 65 percent of total capital expenditures, while the Midstream segment is expected to account for approximately 35 to 40 percent and the Power segment is expected to account for the remainder. Midstream and Power maintenance capital is expected to be approximately $30 to $40 million of the total capital expenditures in 2019. The majority of AltaGas’ capital expenditures for the Utilities segment will focus on approved system betterment across all Utilities, accelerated pipe replacement programs in Virginia, Maryland, the District of Columbia and Michigan, new customer additions, and the construction of the Marquette Connector Pipeline. In the Midstream segment, capital expenditures are anticipated to primarily relate to the completion of RIPET, the Townsend expansion, the Aitken Creek integrated development project, the second train of North Pine, and WGL’s investments in the Mountain Valley gas pipeline development and Central Penn Pipeline expansion. The Power segment remains on a capital-light strategy with expenditures focused on selected smaller investments in distributed generation and potential energy storage projects across the United States. The Corporation continues to focus on enhancing productivity and streamlining businesses.

AltaGas’ 2019 committed capital program is expected to be funded through internally-generated cash flow, asset sales, the Dividend Reinvestment and Optional Cash Purchase Plan (DRIP), proceeds from hybrid securities and preferred share offerings, and normal course borrowings on existing committed credit facilities.

Midstream Projects

Ridley Island Propane Export Terminal

RIPET is located near Prince Rupert, British Columbia, and is expected to be the first propane export facility off the west coast of Canada. The site has a locational advantage given very short shipping distances to markets in Asia, notably a 10-day shipping time compared to 25 days from the U.S. Gulf Coast. The construction cost of RIPET is estimated to be approximately $450 to $500 million and RIPET is expected to ship 1.2 million tonnes of propane per annum (which is equivalent to approximately 40,000 Bbls/d of export capacity). RIPET is a strategic part of AltaGas’ integrated energy value chain in Western Canada, and AltaGas expects to leverage this in pursuing future Midstream growth.

Construction of RIPET commenced during the second quarter of 2017. LPG tank construction and related infrastructure is advancing as planned and remains on schedule. Rail and marine loading infrastructure are also progressing, with construction of the retaining wall complete and rail offloading modules installed. The gangway has been installed and commissioned and jetty module fabrication is ongoing, with the majority of the overland modules in place. The team is simultaneously continuing construction of the balance of plant, with the operational building and warehouse buildings substantially complete. The site construction management team and project support teams have successfully hit all critical milestones to date on the RIPET master schedule and members of the operations team are now permanently on site to initiate a smooth transition. After comprehensive commissioning activities, the facility is scheduled to begin its operational phase in the first quarter of 2019 with the introduction of feedstock propane and filling the refrigerated storage tank with liquefied product. First cargo is expected early in the second quarter of 2019 which aligns with the propane contract year.

Based on production from its existing facilities and commercial contracts executed or currently under negotiation, AltaGas anticipates having physical volumes equal to the initial 40,000 Bbls/d target by the project in-service date. AltaGas plans to operate the facility such that a majority of annual capacity will be underpinned by tolling arrangements, and expects to reach this objective over the next several years.

AltaGas LPG Limited Partnership (AltaGas LPG) and Astomos have entered into a multi-year agreement for the purchase of at least 50 percent of the 1.2 million tonnes per annum of propane expected to be available to be shipped from RIPET each year. Commercial agreements to secure the remaining capacity commitments are currently under negotiation.

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In 2017, AltaGas LPG, a wholly-owned subsidiary of AltaGas, and Vopak Development Canada Inc. (Vopak), a wholly-owned subsidiary of Koninklijke Vopak N.V. (Royal Vopak), a public company incorporated under the laws of the Netherlands, formed Ridley Island LPG Export Limited Partnership (RILE LP) to develop, own, and operate RIPET. AltaGas’ subsidiaries hold a 70 percent interest while Vopak holds a 30 percent interest in RILE LP. The construction cost of RIPET will be funded by AltaGas LPG and Vopak in proportion to their respective interests in RILE LP. RILE LP will be consolidated by AltaGas. AltaGas LPG has the right to 100 percent of the capacity of RIPET.

Central Penn Pipeline

Central Penn is a new 185 mile pipeline originating in Susquehanna County, Pennsylvania and extending to Lancaster County, Pennsylvania, and is an integral part of the larger Atlantic Sunrise project operated by The Williams Companies through Transcontinental Gas Pipeline Company LLC (Transco). Central Penn is regulated by the FERC. The Atlantic Sunrise project is designed to supply enough natural gas to meet the daily needs of more than 7 million American homes in the region. WGL Midstream owns an indirect 21 percent interest in Central Penn, which has the capacity to transport and deliver up to approximately 1.7 Bcf/d of natural gas from the northeastern Marcellus producing area to markets in the mid-Atlantic and Southeastern regions of the United States. Central Penn was placed in service in early October 2018.

In February 2014, WGL Midstream and certain partners formed Meade Pipeline Co LLC (Meade). Meade (39 percent) and Transco (61 percent) have joint ownership of Central Penn. WGL Midstream owns a 55 percent interest in Meade (21 percent indirect interest in Central Penn) and on a cash basis, as of December 31, 2018, WGL Midstream has spent approximately US$446 million on its share of the construction costs.

In addition to the investment in Meade, WGL Midstream entered into an agreement with Cabot Oil & Gas Corporation (Cabot) whereby WGL Midstream will purchase 0.5 Bcf/d of natural gas from Cabot over a 15 year term. As part of this agreement, Cabot has acquired 0.5 Bcf/d of firm gas transportation capacity on Transco’s Atlantic Sunrise project. This capacity has been released to WGL Midstream.

In August 2018, Meade executed an agreement with Transco to participate in an expansion of the Central Penn Pipeline (Leidy South) with an estimated capital investment of up to US$50 million by WGL Midstream. Leidy South is expected to add an estimated 0.6 Bcf/d of natural gas capacity to Central Penn through the addition of compression at new and existing stations. Meade will own 40 percent of the expanded capacity. WGL Midstream will indirectly own 22 percent of the expanded capacity through its 55 percent ownership interest in Meade. Leidy South is anticipated to be in-service as early as the fourth quarter of 2021 assuming all necessary regulatory approvals are received in a timely manner.

Mountain Valley Pipeline, LLC (Mountain Valley)

WGL Midstream owns a 10 percent equity interest in Mountain Valley. The proposed pipeline, which will be operated by EQM Gathering Opco, LLC (EQM) and developed, constructed, and owned by Mountain Valley (a venture of EQT Midstream Partners, LP (EQT) and other entities), will transport approximately 2.0 Bcf/d and will extend from Equitrans, LP’s system in Wetzel County, West Virginia to Transco’s Station 165 in Pittsylvania County, Virginia. The pipeline is estimated to span approximately 300 miles and provide access to the growing Southeast demand markets.

On October 13, 2017, the FERC issued the Certificate of Public Convenience and Necessity for the pipeline. In early 2018, the FERC granted several notices to proceed with certain construction activities on the pipeline. Mountain Valley has submitted additional requests to the FERC for notices to proceed. There are several pending challenges to certain aspects of the Mountain Valley project that must be resolved before the project can be completed. Mountain Valley is working to respond to the court and agency decisions and restore all permits. The pipeline is targeted to be placed in service during the fourth quarter of 2019, subject to litigation and regulatory-related delay. As of December 31, 2018, approximately 70 percent of the project is complete, which includes the welding of approximately 60 percent of the pipeline and ongoing construction work of all compressor stations and interconnects that are expected to be complete by February 2019. Most recently, the Mountain Valley construction team has been focused on stabilizing the right-of-way for the winter season.

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WGL Midstream expects to invest approximately US$350 million through the in-service date of the pipeline based on scheduled capital contributions and its contracted share of project costs. On a cash basis, as of December 31, 2018, WGL Midstream has invested approximately US$271 million in the pipeline. In addition, WGL has gas purchase commitments to buy approximately 0.5 Bcf/day of natural gas, at index-based prices, for a 20-year term, and will also be a shipper on the proposed pipeline.

In April 2018, WGL Midstream entered into a separate agreement with EQM to acquire a 5 percent equity interest in a project to build an interstate natural gas pipeline (the MVP Southgate project). The proposed pipeline will receive gas from the Mountain Valley Pipeline mainline in Pittsylvania County, Virginia and extend approximately 73 miles south to new delivery points in Rockingham and Alamance counties, North Carolina. The total commitment by WGL Midstream is expected to be approximately US$20 million and the lateral pipeline is expected to be placed into service in late 2020.

Northeastern British Columbia Expansion Projects

Townsend 2B

On August 27, 2018, AltaGas announced that it entered into definitive agreements with Kelt to provide an energy infrastructure solution for the liquids-rich Inga Montney development located in Northeast British Columbia. The commercial arrangements underpin the expansion of AltaGas’ Townsend complex including the addition of a 198 MMcf per day C3+ deep cut gas processing facility consisting of 99MMcf per day of new deep cut gas processing capacity and repurposing 99 MMcf per day of the Townsend facility’s existing shallow cut capacity with deep cut gas processing capabilities. The facility will provide Kelt with firm processing of 75 MMcf per day of raw gas under an initial 10 year take-or-pay agreement. The additional natural gas liquids will increase utilization in AltaGas’ existing liquids pipelines, position the Corporation well for an expansion of the North Pine fractionator, and provide additional propane supply to RIPET. The expansion of the Townsend complex coupled with enhanced NGL recovery will provide producers with more options for energy exports. The estimated project cost is approximately $180 million. Long lead equipment has been ordered and the project is on track to be on stream in the fourth quarter of 2019.

Aitken Creek

On September 26, 2018, AltaGas announced that it entered into a definitive agreement with Black Swan to acquire 50 percent ownership in certain existing and future natural gas processing plants of Black Swan, including 50 percent ownership in the Aitken Creek North gas processing facility (Plant 1) currently in operation, and 50 percent ownership in the Nig Creek gas processing facility (Plant 2), which is currently under construction. AltaGas and Black Swan will also enter into long term processing, transportation and marketing agreements that include new AltaGas liquids handling infrastructure, strengthening AltaGas’ Northeast British Columbia value proposition and connecting producers with additional options for energy exports. The total capital investment by AltaGas is expected to be approximately $230 million and the transaction closed on October 2, 2018. Plant 2 is expected to be on stream in the fourth quarter of 2019.

North Pine

The additional natural gas liquids from the Townsend 2B and Aitken Creek expansion projects will increase utilization in AltaGas’ existing liquids pipelines and facilities, resulting in the need for an expansion of the North Pine fractionator, and will provide additional propane supply to RIPET. The North Pine expansion project will add 10,000 Bbl/d of fractionation capacity, optimize the existing 10,000 Bbl/d fractionation train, add rail storage, and optimize the rail yard and rail operation. The project is estimated to cost approximately $58 million and is expected to be on stream in the first quarter of 2020.

Alton Natural Gas Storage Project

Development of the Alton Natural Gas Storage Project, located near Truro, Nova Scotia is focusing on regulatory and construction planning, environmental study, and community engagement. This includes an application to the Nova Scotia Utility and Review Board (NSUARB) to extend the Alton Approval to Construct for the cavern site. The application is currently before the NSUARB for decision. In addition, Alton is progressing the permitting and planning for the natural gas pipeline with provincial authorities. The start-date for solution mining for cavern development is being determined. The Nova Scotia Minister of Environment is expected to make a decision on the Industrial Approval (IA) appeal by Sipekne’katik First Nation in due course. In the meantime, the IA remains in effect for the project. AltaGas continues to work constructively with governments, regulators, and the Mi’kmaq of Nova Scotia. The Alton Natural Gas Storage Project is expected to provide up to 10 Bcf of natural gas storage

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capacity. The first phase of storage service for two caverns, consisting of approximately 4 Bcf of storage capacity, is expected to commence in 2022.

Utility Projects

Accelerated Utility Pipe Replacement Plans

Accelerated pipe replacement programs are in place in all three of Washington Gas’ utility jurisdictions. These are long-term programs with 17 to 35 remaining years, subject to both changing conditions and regulatory review and approval in five year increments. The anticipated expenditures over the next five years are approximately US$1 billion, with future increments projected to include significant expenditures as well. Washington Gas is accelerating pipe replacement in order to further enhance the safety and reliability of the pipeline system. In contrast to the traditional rate-making approach to capital investments, Washington Gas begins recovering the cost, including a return, for these investments immediately through approved surcharges for each accelerated pipe replacement program. Once new base rates are put into effect in a given jurisdiction, expenditures previously being recovered through the accelerated pipe replacement surcharge will be collected through the new base rates.

In the District of Columbia, the construction activities related to an accelerated replacement program targeting vintage mechanically coupled pipe began in 2009 and were completed in January 2017, with restoration and paving continuing into 2017. In 2013, Washington Gas filed PROJECTpipes in which Washington Gas proposed to replace bare and/or unprotected steel services, bare and targeted unprotected steel main, and cast iron main in its distribution system in the District of Columbia. In 2015, the Public Service Commission of the District of Columbia (PSC of DC) approved the settlement agreement for PROJECTpipes, authorizing the recovery, through a surcharge, of total project costs not to exceed US$110 million through the end of September 2019. In December 2018, Washington Gas submitted the next phase of PROJECTpipes to the PSC of DC. The second phase spans the next five years and enables Washington Gas to continue to proactively replace its pipelines on an accelerated basis, proposing to replace approximately 22 miles of pipe and over 8,000 service lines from October 1, 2019 to December 31, 2024. If approved by the PSC of DC, Washington Gas will spend approximately US$305 million on the second phase over five years, which would be recovered through the surcharge billing mechanism previously approved by the PSC of DC.

In 2014, pursuant to the Strategic Infrastructure Development and Enhancement (STRIDE) law in Maryland, the Maryland Public Service Commission (PSC of MD) approved Washington Gas’ initial STRIDE Plan to recover the reasonable and prudent costs associated with qualifying infrastructure replacements through monthly surcharges. The PSC of MD approved replacement of bare and/or unprotected steel services and targeted copper and/or pre-1975 plastic services, bare and targeted unprotected steel main, mechanically coupled pipe main and service, and cast iron main in Washington Gas’ Maryland distribution system at an estimated five-year cost of US$200 million, including cost of removal, through 2018. In 2015, the PSC of MD approved one additional program applicable to gas distribution system replacements and three of the four requested additional programs applicable to gas transmission system replacements at an incremental cost of US$19 million, including cost of removal, in eligible infrastructure replacements over the remaining four years of the initial STRIDE Plan. In June 2018, Washington Gas filed a request for a second five-year plan (STRIDE 2.0) with the PSC of MD at an estimated cost of approximately US$394 million starting January 2019. In December 2018, the PSC of MD approved the request but lowered the authorized budget from US$394 million to US$350 million.

On April 21, 2011, the Commonwealth of Virginia State Corporation Commission (SCC of VA), pursuant to a new law to advance Virginia’s Steps to Advance Virginia’s Energy Plan (SAVE), approved Washington Gas’ initial SAVE plan for accelerated replacement of infrastructure facilities and a SAVE rider to recover eligible costs associated with those replacement programs. Subsequently, the SCC of VA approved three amendments to Washington Gas’ SAVE plan, increasing the overall investment, the scope of approved programs and new facilities replacement programs. Washington Gas’ approved SAVE plan encompasses eight ongoing programs: (i) bare and/or unprotected steel service replacement program, (ii) bare and unprotected steel main replacement program, (iii) mechanically coupled pipe replacement, (iv) copper services replacement program, (v) black plastic services replacement program, (vi) cast iron mains replacement program, (vii) meter set and piping remediation/replacement program and (viii) transmission programs. Washington Gas was authorized to invest US$256 million, including cost of removal,

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over the five-year calendar period through 2017. In November 2017, the SCC of VA approved Washington Gas’ application to amend and extend its SAVE plan (SAVE 2.0). SAVE 2.0 authorizes Washington Gas to invest approximately US$500 million over a five-year period, to continue work on both previously approved and new distribution and transmission system accelerated replacement programs.

Marquette Connector Pipeline

On August 23, 2017, the Michigan Public Service Commission (MPSC) approved SEMCO Gas’ application to construct, own, and operate the MCP. The MCP is a proposed new pipeline that will connect the Great Lakes Gas Transmission Pipeline to the Northern Natural Gas Pipeline in Marquette, Michigan, which will provide system redundancy and increase deliverability, reliability and diversity of supply to SEMCO Gas’ approximately 35,000 customers in Michigan’s Western Upper Peninsula.

The Company received approval for all environmental permits in September 2018 and the completed Archeological Assessment has been submitted to the state’s Historical Preservation Officer. The construction bid package has been tentatively awarded. Construction is expected to begin in 2019, with clearing and mobilization scheduled to begin in the first quarter of 2019 and an anticipated in-service date near the end of the fourth quarter of 2019.

New Customer Growth

The Utility business actively markets and adds new customers through both capital expenditures and different rate mechanisms aimed at bringing the benefits of natural gas, including lower energy bills and reduced carbon emissions, to more residents in its territories. In 2019, Washington Gas, SEMCO and ENSTAR expect new customer growth of 1.0 percent, 0.8 percent, and 0.9 percent, respectively, supported by additional capital and rate base. Adding new customers directly drives earnings growth through additional distribution revenues.

Power Projects

Distributed Generation Investments

WGL currently owns and manages distributed generation projects with approximately 325 MW of gross capacity across 20 states and the District of Columbia in the United States. The power output from these projects is generally contracted directly with end-user customers under long-term service agreements, providing clean energy solutions to a variety of commercial, government, institutional, and residential customers. For certain investments, WGL, along with a tax equity partner, has formed several tax equity funds to acquire, own, and operate distributed generation projects. These funds have invested approximately US$223 million in distributed generation projects since 2016, of which WGL’s share was approximately US$145 million. WGL is the managing member of these funds and invested cash equal to the purchase price of the distributed generation projects less any contributions from the tax-equity partner for projects sold by WGL into the funds. WGL is the operations and maintenance provider, and was the developer of these projects.

One of the tax equity partnerships, SFGF II, LLC, remains open to acquire new solar projects. To date, SFGF II, LLC has invested a total of US$122 million in new projects since June 30, 2017 and there is US$28 million remaining for additional acquisitions through March 31, 2019. As of December 31, 2018, WGL has contributed US$74 million into SFGF II, LLC. The estimated total contribution by WGL to this fund is expected to be approximately US$95 million by the end of the commitment period.

The Company continues to consider additional energy storage and renewables opportunities.

UTILITIES

Description of Assets

AltaGas owns and operates utility assets that store and deliver natural gas to end-users in the District of Columbia, Virginia, Maryland, Michigan and Alaska. AltaGas’ previously owned Canadian utilities, which served end-users in Alberta, British Columbia, Nova Scotia and Inuvik, were sold to AltaGas Canada Inc. in 2018. AltaGas’ remaining utility businesses in the United States serve over 1.6 million customers and have a rate base of approximately US$3.7 billion.

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The utilities are underpinned by regulated returns and regulatory regimes that generally provide stable earnings and cash flows. The Utilities segment enhances the diversification of AltaGas’ portfolio of energy infrastructure assets and strengthens the Corporation’s business profile, thus allowing the Corporation to meet its objective of generating economic returns by investing in regulated, long-life assets with stable earnings.

The Utilities segment includes:

·Washington Gas in Virginia, Maryland, and the District of Columbia;

·Hampshire, providing regulated interstate natural gas storage to Washington Gas;

·SEMCO Gas in Michigan;

·ENSTAR in Alaska;

·65 percent interest in Cook Inlet Natural Gas Storage Alaska LLC (CINGSA) in Alaska; and

·An approximate 37 percent interest in AltaGas Canada Inc.

All of the utilities are allowed the opportunity to earn regulated returns. This return on rate base is composed of regulator-allowed financing costs and return on equity (ROE). If actual costs are different from those recoverable through approved rates, the utility bears the risk of this difference other than for certain costs that are subject to deferral treatment.

Earnings in the Utilities segment are seasonal, as revenues are primarily based on the demand for space heating in the winter months, mainly from November to March. Costs, on the other hand, are generally incurred more uniformly over the year. This typically results in stronger first and fourth quarters and weaker second and third quarters. In Michigan, Alaska, and the District of Columbia, earnings can be impacted by variations from normal weather resulting in delivered volumes being different than anticipated. Increases in the number of customers or changes in customer usage are other factors that might typically affect delivered volumes, and hence actual earned returns for the Utilities segment. In Virginia and Maryland, Washington Gas has billing mechanisms in place which are designed to eliminate the effects of variance in customer usage caused by weather and other factors such as conservation.

Washington Gas

Washington Gas is a regulated public utility acquired as part of the WGL Acquisition that has been engaged in the natural gas distribution business since 1848, and provides regulated gas distribution services to end users in the District of Columbia,

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Virginia, and Maryland. At the end of 2018, Washington Gas had approximately 1.2 million customers. Of these customers, approximately 94 percent are residential. The rate base at year end was approximately US$2.8 billion. At the end of 2018, the approved regulated ROE for Washington Gas in its various jurisdictions ranged from 9.25 percent to 9.7 percent based on an equity ratio ranging from 51.7 percent to 55.7 percent.

Washington Gas is regulated by the PSC of DC, the PSC of MD and the SCC of VA, which approve its terms of service and the billing rates that it charges to customers. The rates charged to utility customers are designed to recover Washington Gas’ operating expenses and natural gas commodity costs and to provide a return on its investment in the net assets used in its firm gas sales and delivery service.

Washington Gas’ customers are eligible to purchase their natural gas from unregulated third-party marketers through natural gas unbundling. As at December 31, 2018, approximately 15 percent of its customers have chosen to purchase gas from marketers. This does not negatively impact Washington Gas’ net income as the Corporation does not earn a margin on the sale of natural gas to firm customers, but only from the delivery and distribution of the gas.

Washington Gas obtains natural gas supplies that originate from multiple regions throughout the United States. At December 31, 2018, it had service agreements with four pipeline companies that provided firm transportation and storage services with contract expiration dates ranging from 2019 to 2044. Washington Gas has also contracted with various interstate pipeline and storage companies to add to its storage and transportation capacity.

In early 2018, Washington Gas filed applications in all three of its jurisdictions for approval of a reduction of distribution rates to reflect the impact of the Tax Cuts and Jobs Act (TCJA). For the period from close of the WGL Acquisition to December 31, 2018, the impact of these filings and subsequent responses from the regulatory commissions was a reduction in base rates of approximately US$6 million in Maryland, US$3 million in the District of Columbia, and US$6 million in Virginia.

On May 15, 2018, Washington Gas filed an application with the PSC of MD to increase its base rates for natural gas service for approximately US$56 million including approximately US$15 million in annual surcharges currently paid by customers for system upgrades. On December 11, 2018, the PSC of MD approved Washington Gas’ US$29 million in new revenues and increased the return on equity to 9.7 percent. On January 10, 2019, Washington Gas requested a rehearing, alleging two errors in the agency’s final order. A PSC of MD decision on the application for rehearing is expected late in first or second quarter of 2019.

On June 15, 2018, Washington Gas filed an application with the PSC of MD for approval of the second phase of its accelerated natural gas pipeline initiative. The application requested approval of approximately US$394 million in accelerated infrastructure replacements for the 2019 to 2023 period. On December 11, 2018, the PSC of MD approved a US$350 million five-year program. On January 9, 2019, Washington Gas applied to supplement its 2019 project list with an additional annual spend of approximately US$65 million. On January 25, 2019, the PSC of MD approved the 2019 revised project list and affirmed the annual spend of approximately US$65 million.

On July 31, 2018, Washington Gas filed an application with the SCC of VA to increase its base rates for natural gas service. This base rate increase, if granted, would be approximately US$38 million, of which approximately US$15 million relates to costs being collected through the monthly SAVE surcharges for accelerated pipeline replacement. The new interim rates are effective, subject to refund, in January 2019. Hearings are scheduled for April 2019 with a decision expected in the second half of 2019.

On August 31, 2018, Washington Gas filed the 2019 SAVE capital expenditure application with the SCC of VA seeking approval for approximately US$70 million of SAVE capital expenditures in 2019. The SAVE application for 2019 was approved and implemented beginning January 2019.

On December 7, 2018, Washington Gas filed an application with the PSC of DC for the phase 2 PROJECTpipes program requesting approval of approximately US$305 million in accelerated infrastructure replacement in the District of Columbia during the 2019 to 2024 period.

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Hampshire

Hampshire owns underground natural gas storage facilities, including pipeline delivery facilities located in and around Hampshire County, West Virginia, and operates these facilities to serve Washington Gas. Hampshire is regulated by FERC. Washington Gas purchases all of the storage services of Hampshire, and includes the cost of the services in its regulated energy bills to customers. Hampshire operates under a “pass-through” cost of service based tariff approved by FERC.

SEMCO Gas

SEMCO owns and operates a regulated natural gas distribution utility in Michigan under the name SEMCO Gas and has an interest in a regulated natural gas storage facility in Michigan. At the end of 2018, SEMCO Gas had approximately 303,000 customers. Of these customers, approximately 84 percent are residential. In 2018, SEMCO Gas experienced customer growth of approximately 1 percent reflecting growth in the franchise areas and customer conversions with the favorable price of natural gas. The rate base at year end was approximately US$472 million. In 2018, the approved regulated ROE for SEMCO Gas was 10.35 percent with an approved capital structure based on 49 percent equity.

SEMCO Gas is regulated by the MPSC. It operates under cost-of-service regulation and utilizes actual results from the most recently completed fiscal year along with known and measurable changes in its application for new rates.

SEMCO Gas has a Main Replacement Program (MRP) surcharge to recover a stated amount of accelerated main replacement capital expenditures in excess of what is authorized in its current base rates. The MRP began in 2011, was expanded in 2013 and renewed for an additional five years in 2015. The anticipated annual average capital spending over the final five year period is approximately US$10 million.

SEMCO Gas is required by Michigan law to establish an Energy Optimization Program (an EO plan) for their customers and to implement and fund various energy efficiency and conservation matters. The costs of the measures offered through the EO program are recovered through surcharges imposed on all customers of SEMCO Gas. EO plans and reconciliations are subject to review and approval by the MPSC. SEMCO Gas also has the ability to earn a performance incentive if certain EO goals and objectives are met annually. During 2018, the MPSC issued an order for SEMCO Gas to collect US$1 million for the 2017 EO plan year performance incentive.

In December 2016, SEMCO Gas filed an application with the MPSC seeking approval to construct, own, and operate the Marquette Connector Pipeline. In August 2017, the MPSC approved SEMCO’s application. Construction is expected to be completed in 2019, with an in-service date during the fourth quarter of 2019. Please refer to the Growth Capital section of this MD&A for further information.

As required by an order issued by the MPSC in September 2012, SEMCO Gas filed a depreciation study with the MPSC in September 2017, using 2016 data. On April 9, 2018, the MPSC issued an order approving the settlement agreement and new depreciation rates. The new rates reflect a US$1.9 million upward adjustment to depreciation expense when compared to the current rates and are effective on January 1, 2019. SEMCO Gas is required to file a new depreciation case and updated depreciation study with the MPSC no later than September 30, 2022, using 2021 data.

On December 27, 2017, the MPSC issued an order instructing all regulated utilities in Michigan to track the impact of the TCJA effective January 1, 2018. On February 22, 2018, the MPSC issued an order requiring utilities in Michigan to follow a 3-step approach for computing and implementing bill credits to reflect the reduction in revenue requirements as a result of the TCJA. The first step was to establish a credit (Credit A) through a contested case. Credit A is a forward looking tax credit that will refund the annual tax savings relating to the reduction of the corporate tax rate from 35 percent to 21 percent on a prospective basis. SEMCO Gas submitted its Credit A filing on March 29, 2018, reflecting a revenue reduction of approximately US$5.9 million on an annual basis. On April 20, 2018, SEMCO Gas supplemented its Credit A filing with a proposal to reduce its Main Replacement Program (MRP) surcharges to reflect the impact of the TCJA on its MRP annual revenue requirement. On May 30, 2018, the MPSC issued an order approving a settlement in SEMCO Gas’ Credit A filing reflecting a reduction in revenues of approximately US$5.9 million and a reduction to the annual MRP revenue requirement of approximately US$0.6 million, effective July 1, 2018. Credit A will remain in place until new rates are set in the next general rate case. The second step was to establish another credit

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(Credit B) through a contested case. Credit B is a backward-looking tax credit to reflect the reduction of the corporate tax rate of 35 percent to 21 percent, for the period January 1, 2018 through the date Credit A is established. On July 27, 2018, SEMCO Gas filed its proposal for Credit B to address the impacts of federal corporate tax reduction arising from the TCJA on its natural gas rates from January 1, 2018 until June 30, 2018. On September 28, 2018, the MPSC issued an order approving the settlement in SEMCO Gas’ Credit B filing. SEMCO Gas will refund approximately US$4.7 million to customers volumetrically via bill credits for three months beginning with the first billing cycle in October 2018. The third and final step was to file an application to establish the calculation for all of the remaining impacts of the TCJA (Calculation C), which is primarily the remeasurement of deferred taxes and how the amounts deferred as regulatory liabilities will flow back to ratepayers. On October 1, 2018, SEMCO Gas filed its application to address the Calculation C effects of the TCJA, which is currently ongoing.

ENSTAR and CINGSA

SEMCO owns and operates a regulated natural gas distribution utility in Alaska under the name ENSTAR. SEMCO, through a subsidiary, holds a 65 percent interest in CINGSA, a regulated natural gas storage utility in Alaska. At the end of 2018, ENSTAR had approximately 145,000 customers including residential, commercial and transportation and of these customers, approximately 91 percent are residential. In 2018, ENSTAR experienced customer growth of approximately 1 percent reflecting growth in the franchise areas and customer conversions with the favorable price of natural gas. The rate base at year end was approximately US$291 million for ENSTAR and US$77 million for CINGSA (SEMCO’s 65 percent share).

ENSTAR and CINGSA are regulated by the Regulatory Commission of Alaska (RCA) and operate under cost-of-service regulation utilizing actual results from the most recently completed fiscal year along with known and measureable changes in their application for new rates.

On March 23, 2018, the RCA sent a letter to several investor-owned utilities in Alaska, asking for the utilities’ proposed response to the 2017 Tax Cut and Jobs Act. On April 26, 2018, ENSTAR filed its proposed reduction in rates with the RCA, reflecting a US$5.1 million decrease from the annual revenue requirement that was determined in October 2017. On May 29, 2018, the RCA approved ENSTAR’s proposed rate decrease and the reduced rates went into effect on June 1, 2018. ENSTAR anticipates addressing excess deferred income taxes in its next rate case, which is required to be filed no later than June 1, 2021, with a test year of 2020.

In April 2018, CINGSA filed a request for an advanced ruling on a redundancy project for approximately US$41 million of capital expenditures and an annual revenue requirement of approximately US$6 million. Reply testimony was filed in September 2018 and a hearing occurred in October 2018, with a decision expected in the second quarter of 2019.

The CINGSA rate case was filed in April 2018 based on a 2017 historical test year, reducing rates by US$4 million due to a lower rate base, lower returns on equity (ROE) and lower federal income tax. The rate case hearing is scheduled for April 2019 with a decision expected in the third quarter of 2019.

AltaGas Canada Inc.

In the fourth quarter of 2018, the IPO of ACI, a previously wholly owned subsidiary of AltaGas, was completed. As of December 31, 2018, AltaGas had an approximate 37 percent equity interest in ACI. ACI holds certain assets formerly held by AltaGas, including rate regulated distribution utility assets in British Columbia, Alberta and Nova Scotia, minority interests in entities providing natural gas to the Town of Inuvik, a fully contracted 102 MW wind park located in British Columbia and an approximate 10 percent equity interest in the Northwest Hydro facilities. ACI’s utilities purchased from AltaGas include AltaGas Utilities Inc. (AUI), serving approximately 80,400 customers in Alberta, Pacific Northern Gas Ltd. (PNG), serving approximately 41,900 customers in British Columbia, and Heritage Gas Ltd. (HGL), serving approximately 7,300 customers in Nova Scotia. For the period prior to IPO close on October 25, 2018, the results of all ACI entities were consolidated within AltaGas’ results. Subsequent to the IPO close, AltaGas’ interest in ACI is accounted for as an equity investment.

Capitalize on Opportunities

While providing safe and reliable service, AltaGas pursues opportunities in the Utilities segment to deliver value to its customers and enhance long-term shareholder value. The Corporation’s objectives are to:

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·Maximize use of existing infrastructure and increase market penetration in order to maintain cost-effective rates;

·Invest in the safety and reliability of existing infrastructure, including delivery system upgrade programs;

·Expand infrastructure to new markets to bring the economic and environmental benefits of gas to new customers, without unduly burdening existing customers;

·Maintain strong relationships with local communities, Indigenous peoples, governments, and regulatory bodies;

·Maintain strong community and regulatory relationships while ensuring fair returns to shareholders; and

·Acquire new franchises when the opportunities arise.

AltaGas expects to grow its existing utility infrastructure through continued investment and capital improvements in franchise areas, which will result in rate base growth and continued customer growth including the conversion of users of alternative energy sources to natural gas. AltaGas’ U.S. utilities have 168 percent rate base growth over the past three years including the addition of WGL’s rate base and after adjusting for the impact of foreign exchange translation. The growth in rate base is a direct result of the WGL Acquisition, prudent investments in current areas of operations, and the addition of new customers. Customer growth rates for AltaGas’ U.S. utilities are moderate, as is typical with mature utilities, with growth rates generally tied closely to the economic growth of the respective franchise regions.

MIDSTREAM

Description of Assets

AltaGas’ Midstream segment serves customers primarily in the Western Canada Sedimentary Basin (WCSB) and, subsequent to the disposition of the non-core midstream assets in Canada which closed in February 2019, transacts more than 1.5 Bcf/d of natural gas including natural gas gathering and processing, NGL extraction and fractionation, transmission, storage and natural gas and NGL marketing. Gas gathering systems move natural gas from producing wells to processing facilities where impurities and certain hydrocarbon components are removed. The gas is then compressed to meet downstream pipelines’ operating specifications for transportation. Extraction and fractionation facilities reprocess natural gas to extract and recover ethane and NGL. Subsequent to the sale of the non-core midstream assets in Canada, AltaGas owns approximately 1.5 Bcf/d of extraction processing capacity and approximately 0.7 Bcf/d of raw field gas processing capacity. The Midstream segment also includes an equity investment in Petrogas through AltaGas Idemitsu Joint Venture Limited Partnership (AIJVLP).

Transmission pipelines deliver natural gas to distribution systems, end-users or other downstream pipelines. AltaGas uses its market knowledge and expertise to create value by buying and reselling natural gas; providing gas transportation, storage, and gas and NGL marketing for producers; and sourcing gas supply for some of the Corporation’s processing assets. The Midstream segment also includes expansion and greenfield projects under development or construction, including RIPET and the Alton Natural Gas Storage Project discussed under the Growth Capital section of this MD&A.

With the acquisition of WGL, the Midstream segment also includes WGL’s investments in four pipelines in the northeastern United States, including Stonewall, Central Penn, Mountain Valley, and the proposed Constitution Pipeline (Constitution), as well as the retail gas marketing business of WGL Energy Services, Inc. (WGL Energy Services).

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Specifically, subsequent to the sale of non-core midstream assets in Canada, the Midstream segment includes:

·Interests in five NGL extraction plants with net licensed inlet capacity of 1.5 Bcf/d. The extraction assets provide stable fixed-fee or cost-of-service type revenues and margin based revenues. The natural gas supply to AltaGas’ extraction plants, with the exception of the Younger extraction plant (Younger), depends on natural gas demand pull from residential, commercial and industrial usage inside and outside of Western Canada, and gas liquids demand pull from the Alberta petrochemical market and propane heating. Natural gas supply to Younger is dependent on the amount of raw natural gas processed at the McMahon gas plant, which is based on the robust natural gas producing region of northeastern British Columbia;

·The first train of the North Pine facility near Fort St. John, British Columbia with capacity to fractionate 10,000 Bbls/d of propane plus NGL mix, and 6,000 Bbls/d of condensate terminaling capacity and two eight inch diameter NGL supply pipelines, each approximately 40 km in length;

·Gathering and processing facilities in Western Canada and a network of gathering and sales lines that gather natural gas upstream of processing facilities and deliver natural gas into downstream pipeline systems that feed North American natural gas markets. The field facilities provide fee-for-service revenues based on volumes processed as well as revenues based on take-or-pay contracts. A significant portion of contracts flow through operating costs to the producers;

·A 15-year strategic alliance between AltaGas and Painted Pony Energy Ltd. (Painted Pony) for the development of processing infrastructure and marketing services for natural gas and NGL. Since the formation of the strategic alliance in 2014, AltaGas completed the 198 Mmcf/d shallow-cut gas processing facility (the Townsend facility) including the related egress pipelines and truck terminal, and the 99 Mmcf/d Townsend 2A facility (collectively the Townsend facilities). AltaGas is the operator of these facilities and is also the marketer for Painted Pony’s gas and NGL;

·50 percent ownership of the 5.3 Bcf Sarnia natural gas storage facility connected to the Dawn Hub in Eastern Canada;

·The Alton Natural Gas Storage Project under construction;

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·Natural gas and NGL marketing and gas transportation services to optimize the value of the infrastructure assets and meet customer needs. WGL Midstream provides natural gas related solutions to its customers and counterparties including producers, utilities, local distribution companies, power generators, wholesale energy suppliers, LNG exporters, pipelines, and storage facilities. WGL Midstream also contracts for storage and pipeline capacity in its trading activities through both long term contracts and short term transportation releases;

·50 percent ownership in AIJVLP, with the remaining 50 percent owned by Idemitsu Kosan Co., Ltd.;

·AIJVLP holds a two-thirds ownership interest in Petrogas, a leading North American integrated midstream company, with an extensive logistics network consisting of over 2,500 rail cars and 27 rail, truck and storage terminals providing key infrastructure, supply logistics and marketing expertise. Petrogas also owns and operates the Ferndale Terminal;

·The Ridley Island Propane Export Terminal in British Columbia under construction, which has an expected in-service date of early in the second quarter of 2019;

·WGL’s retail gas marketing business, which sells natural gas directly to residential, commercial and industrial customers in Maryland, Virginia, Delaware, Pennsylvania and the District of Columbia;

·A 21 percent net equity interest in Central Penn, a regulated 185 mile pipeline that has the capacity to transport and deliver up to approximately 1.7 Bcf/d of natural gas. Central Penn began operations on October 6, 2018;

·A 10 percent equity interest in Mountain Valley. The proposed pipeline will transport approximately 2.0 Bcf/d of natural gas. Mountain Valley is expected to be placed in service in the fourth quarter of 2019. In April 2018, WGL Midstream entered into a separate agreement to acquire a 5 percent equity interest in a lateral project to build an interstate natural gas pipeline (MVP Southgate) which will receive natural gas from Mountain Valley. The MVP Southgate pipeline is expected to be placed in service in late 2020;

·A 30 percent equity interest in Stonewall, which has the capacity to gather up to 1.4 billion cubic feet of natural gas per day from the Marcellus production region in West Virginia and connects with an interstate pipeline system that serves markets in the mid-Atlantic region; and

·A 10 percent interest in the proposed Constitution Pipeline through a 10 percent equity investment in Constitution Pipeline Company, LLC. The natural gas pipeline venture is proposed to transport natural gas from the Marcellus region in northern Pennsylvania to major northeastern markets.

Capitalize on Opportunities

AltaGas plans to grow its Midstream business by expanding and optimizing strategically-located assets and by adding new assets to serve customers by providing access to new markets, including Asia. New infrastructure is expected to be larger scale facilities supporting the vast reserves in North America. While providing safe and reliable service, AltaGas pursues opportunities in the Midstream segment to deliver value to its customers and enhance long-term shareholder value. The Corporation’s objectives are to:

·Develop high quality assets that enhance the integrated midstream offering and connect producers to market;

·Consolidate its position in key markets to deliver optimal growth over the long-term;

·Provide a fully-integrated midstream service offering including gas and NGL gathering and processing, fractionation, and transportation facilities, and logistics and marketing services to its customers across the energy value chain, with higher producer netbacks resulting from export access to higher value markets, including Asia;

·Maintain strong relationships with local communities, Indigenous peoples, governments, and regulatory bodies;

·Maximize profitability of existing facilities by increasing capacity, utilization and efficiency;

·Mitigate volume risk through contractual structures, redeployment of equipment and expansion of geographic reach;

·Coordinate between facilities, business segments and product lines to improve efficiencies and maximize profits; and

·Continue to develop the Northeast U.S. natural gas value chain strategy which complements AltaGas’ existing business and investments.

In recent years, the WCSB has changed from a maturing basin to one capable of sustainable long-term growth through new low cost gas formations such as the Montney. The emergence of unconventional gas plays in the WCSB such as the Montney, as well as increased focus on horizontal multi-fracturing and completions technology, have resulted in abundant natural gas supply and associated liquids. Market demand, including the demand generated from the LPG and potential LNG export projects on the

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west coast of North America, provides significant long-term growth opportunities for the Corporation’s Midstream segment. AltaGas expects to capitalize on these opportunities by increasing throughput at facilities, by increasing working interests in existing plants, and by acquiring and constructing new facilities such as liquefaction, refrigeration, natural gas processing, extraction, fractionation, storage and transmission pipelines. AltaGas’ 15-year strategic alliance with Painted Pony, and, more recently, the agreements with Black Swan and Kelt, are examples of the Corporation’s ability to partner with producers to provide a fully-integrated service offering.

The Corporation also expects there to be opportunities to increase volumes by tying in new wells and building or purchasing adjoining facilities and systems to create larger integrated processing infrastructure to capture operating synergies and enhance its competitive advantage. The strategic location of some of its existing gas processing infrastructure is expected to benefit from growing natural gas production in northeastern British Columbia and western Alberta, in response to the development of unconventional sources of gas, such as the Montney Deep Basin and Duvernay resource plays. The Townsend facilities and the related infrastructure, as well as the recent agreements with Kelt and Black Swan are examples of AltaGas’ ability to capitalize on energy infrastructure growth opportunities. The first train of the North Pine facility entered commercial operation in 2017, which provides NGL processing capacity to producers in the area and is connected to the Townsend facilities through pipelines. The combined commitments from Black Swan and Kelt will trigger the expansion of the North Pine C3+ fractionation capacity from the current 10,000 Bbl/d to the permitted and approved 20,000 Bbl/d. The North Pine facility is well connected by rail to Canada’s west coast including RIPET. Through the Townsend facilities, the North Pine facility and RIPET currently under construction, AltaGas is well positioned to provide a fully integrated midstream service offering while also providing access to higher netback markets for producer NGL. The Gordondale facility and the Blair Creek facility are also meeting liquids extraction needs in the Montney area as producers seek to increase netbacks by capitalizing on liquids-rich gas in this prolific area. Overall, the diverse nature of AltaGas’ natural gas and NGL infrastructure is expected to provide ongoing opportunities for AltaGas to increase throughput, utilization and profitability.

Due to the integrated nature of AltaGas’ gas gathering and processing assets, transmission services are often offered in combination with gathering and processing, natural gas marketing and extraction services. AltaGas is uniquely positioned to work with producers providing services across the integrated value chain, from wellhead to the coast and on to export markets. This is particularly the case with producers in the vast Montney, Deep Basin, and Duvernay resource plays under development in northeastern British Columbia and western Alberta. With RIPET near Prince Rupert, British Columbia currently under construction and the Petrogas Ferndale Terminal in the state of Washington, AltaGas can provide multiple outlets for producers to deliver their products to the highest value markets, including Asia. AltaGas also pursues additional opportunities to enhance the value of its infrastructure through services ancillary to its infrastructure based businesses. These include maintaining the cost effective flow of gas through extraction plants and increasing services provided to producers. AltaGas is also reviewing plant optimization opportunities which will generate another source of cash flow and improve customer netbacks. AltaGas has significant gas market knowledge, which it employs across all its assets to enhance returns along the energy value chain and more effectively serve customers’ needs.

POWER

Description of Assets

AltaGas’ Power segment is engaged in the generation and sale of capacity, electricity, and ancillary services and related products through power facilities in Alberta, California, Colorado, Michigan, and North Carolina, as well as distributed generation assets including solar photovoltaic (PV) and fuel cells across the United States. AltaGas continues to pursue the demand for clean energy sources, while increasing earnings, cash flow stability, and predictability under a capital-light power strategy.

Subsequent to the sale of the non-core Canadian power assets which closed in February 2019, and the sale of the remaining 55 percent interest in the Northwest Hydro facilities which closed in January 2019, the Power segment includes 1,105 MW of operational gross power generation capacity from gas-fired, distributed energy, solar, biomass, and energy storage, as well as a number of opportunities for additional energy storage assets currently under development.

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Specifically, subsequent to the sale of non-core power assets in Canada and the remaining 55 percent interest in the Northwest Hydro facilities, the Power segment includes:

·Three natural gas-fired plants with 627 MW of generating capacity in the United States, including the 507 MW Blythe Energy Center (Blythe) and the 50 MW Ripon facility, located in California, and the 70 MW Brush II facility (Brush) in Colorado. Blythe and Brush are under Power Purchase Arrangements (PPAs) with creditworthy utilities;

·45 MW of cogeneration and 3 MW of gas-fired peaking plant capacity in Alberta;

·85 MW of gross biomass generation in the United States. The Grayling facility is under a long-term PPA with CMS Energy through 2027 while the Craven facility is contracted through 2027 with Duke Energy;

·20 MW of lithium ion battery storage in Pomona, California, with a 10 year agreement for capacity under contract with SCE;

·WGL’s retail power marketing business, which sells natural gas directly to residential, commercial and industrial customers in Maryland, Virginia, Delaware, Pennsylvania and the District of Columbia; and

·325 MW of distributed generation capacity acquired in the WGL Acquisition, including solar PV and natural gas fuel cells across the United States. Generation is sold under long-term power purchase agreements with customers.

On November 13, 2018, AltaGas sold three northern California natural gas-fired power assets (Tracy, Hanford and Henrietta) with total generating capacity of 523 MW, located in the San Joaquin Valley (the San Joaquin facilities). Also, in December 2018, AltaGas sold the Busch Ranch 15 MW wind generation facility in Colorado.

Ripon, a natural gas-fired power asset, was acquired in early 2015. The PPA contract expired May 31, 2018, following which AltaGas negotiated bilateral Resource Adequacy (RA) contracts through 2018 and for the majority of 2019. AltaGas retains the rights to the energy and ancillary service attributes of the facility, which are sold on a merchant basis into the California Independent System Operator (CAISO).

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In southern California, the existing 507 MW Blythe Energy Center is currently operating under a PPA with SCE until July 31, 2020, serving the CAISO market. The facility is directly connected to a Southern California Gas Company natural gas pipeline for its supply and has reactivated an El Paso Gas Company pipeline connection as a second supply source, and interconnects to SCE and CAISO via its 67-mile transmission line.

In early 2015, AltaGas acquired Pomona, which is strategically located in the east Los Angeles basin load pocket. AltaGas constructed, owns and operates a 20 MW (80 MWh) lithium-ion battery storage facility at the Pomona site (the Pomona Energy Storage facility) which entered service in December of 2016 and is under contract for 20 MW of resource adequacy capacity with SCE under a 10-year energy services agreement. AltaGas retains the rights to the energy and ancillary service attributes of the facility, which are sold on a merchant basis into the CAISO.

At December 31, 2018, AltaGas operated the Northwest Hydro facilities in northwest British Columbia with total generation capacity of 277 MW. In the second quarter of 2018, AltaGas sold an indirect 35 percent of its interest in these facilities to a third party, and in the fourth quarter of 2018, AltaGas sold an additional 10 percent interest to ACI. On December 13, 2018, AltaGas announced that it had reached an agreement for the sale of its remaining indirect equity interest of approximately 55 percent in these facilities for expected proceeds of approximately $1.37 billion. The sale closed in January 2019.

With the close of the WGL Acquisition, the Power segment now includes WGL’s Power assets with commercial energy systems and U.S. electricity retail. The commercial energy systems include 325 MW of distributed generation assets (solar PV systems and natural gas fuel cells). Through WGL, AltaGas also operates as general contractor to upgrade mechanical, electrical, water and energy-related infrastructure of large governmental and commercial facilities by implementing both traditional and alternative energy technologies. The sale of energy is under long term power purchase agreements with a general duration of 20 years.

The U.S. power retail business sells power to end users in Maryland, Virginia, Delaware, Pennsylvania and the District of Columbia. This area is served by the PJM Interconnection (PJM), a regional transmission organization that regulates and coordinates generation supply and the wholesale delivery of electricity in the states and jurisdictions where WGL operates. Electricity is purchased with the objective of earning a profit through competitively priced sales contracts with end users. Requirements to serve retail customers is closely matched with commitments for electricity deliveries, and thus, a secured power supply arrangement expiring in 2020 has been entered into with Shell Energy North America (US) LP for the majority of electricity requirements to service end users, which also reduces credit requirements.

AltaGas also owns biomass assets including a 30 percent working interest in a 37 MW wood biomass power facility in Grayling, Michigan and a 50 percent working interest in a 48 MW wood biomass power facility in Craven County, North Carolina. The Grayling facility is contracted under a long term PPA through 2027 with CMS Energy and the Craven facility is contracted through 2027 with Duke Energy.

Capitalize on Opportunities

AltaGas’ strategy is to develop, build, own and operate long-life, low-risk infrastructure assets to deliver strong, stable returns for investors. Growth in the Power business involves a capital-light strategy that is focused on strong and stable returns from renewable sources of clean energy and energy storage, as the Corporation seeks to capitalize on the increasing demand for clean power while reducing its carbon footprint.

The demand for clean energy continues to be strong across North America as the industry addresses climate change legislation and utilities are faced with the renewable portfolio standards. Utilities’ reliance on coal is lessening as its market share continues to decrease for environmental and economic reasons, with low cost natural gas and increasing renewables providing a cost competitive option for fuel on a marginal cost basis in many parts of North America.

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CONSOLIDATED FINANCIAL REVIEW

	Three Months Ended December 31			Year Ended December 31
($ millions)	2018	2017		2018		2017
Revenue	1,727	745		4,257		2,556
Normalized EBITDA(1)	394	213		1,009		797
Net income (loss) applicable to common shares	174	(11	)	(502	)	30
Normalized net income(1)	120	63		195		204
Total assets	23,488	10,032		23,488		10,032
Total long-term liabilities	11,746	4,578		11,746		4,578
Net additions to property, plant and equipment	16	114		573		388
Dividends declared(2)	121	94		463		362
Normalized funds from operations(1)	255	179		657		615

	Three Months Ended December 31			Year Ended December 31
($ per share, except shares outstanding)	2018	2017		2018		2017
Net income (loss) per common share - basic	0.64	(0.06	)	(2.25	)	0.18
Net income (loss) per common share - diluted	0.64	(0.06	)	(2.25	)	0.18
Normalized net income - basic(1)	0.44	0.36		0.88		1.19
Dividends declared(2)	0.45	0.54		2.09		2.12
Normalized funds from operations(1)	0.94	1.03		2.95		3.60
Shares outstanding - basic (millions)
During the period(3)	272	174		223		171
End of period	275	175		275		175

(1)Non-GAAP financial measure; see discussion in Non-GAAP Financial Measures section of this MD&A.

(2)Dividends declared per common share per month: $0.175 beginning on August 25, 2016, $0.1825 beginning on November 27, 2017, and $0.08 beginning on December 27, 2018.

(3)Weighted average.

Three Months Ended December 31

Normalized EBITDA for the fourth quarter of 2018 was $394 million, compared to $213 million for the same quarter in 2017. The increase was primarily due to contributions from WGL, AltaGas’ share of ACI earnings subsequent to IPO close on October 25, 2018, the impact from the stronger U.S. dollar on reported results from U.S. assets, contributions from the acquisition of a 50 percent interest in the Black Swan gas processing facilities, higher SEMCO rates and growth, and higher Harmattan fee for service revenue. These were partially offset by the impact of the ACI IPO, the impact of the sale of the San Joaquin facilities, lower river flows at the Northwest Hydro facilities, and decreased revenue from SEMCO due to the TCJA. For the three months ended December 31, 2018, the average Canadian/U.S. dollar exchange rate increased to 1.32 from an average of 1.27 in the same quarter of 2017, resulting in an increase in normalized EBITDA of approximately $5 million.

Normalized funds from operations for the fourth quarter of 2018 were $255 million ($0.94 per share), compared to $179 million ($1.03 per share) for the same quarter in 2017, reflecting the same drivers as normalized EBITDA, partially offset by lower income tax recoveries and higher interest expense. The decrease in per share amounts is due to a higher number of shares outstanding in 2018 compared to 2017. In the fourth quarter of 2018, AltaGas received $3 million of dividend income from the Petrogas Preferred Shares (2017 - $3 million) and $2 million of common share dividends from Petrogas (2017 - $1 million).

Operating and administrative expenses for the fourth quarter of 2018 were $346 million, compared to $151 million for the same quarter in 2017. The increase was mainly due to the inclusion of WGL’s operating and administrative expenses, partially offset by the exclusion of ACI’s operating and administrative expenses subsequent to IPO close on October 25, 2018, and lower transaction costs of $12 million in the fourth quarter of 2018 compared to $15 million in the same quarter in 2017.

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Depreciation and amortization expense for the fourth quarter of 2018 was $126 million, compared to $71 million for the same quarter in 2017. The increase was mainly due to depreciation and amortization expense for assets acquired in the WGL Acquisition, partially offset by the exclusion of depreciation and amortization expense for assets sold to ACI subsequent to the IPO close on October 25, 2018 and the sale of the San Joaquin facilities on November 13, 2018. Interest expense for the fourth quarter of 2018 was $110 million, compared to $44 million for the same quarter in 2017. The increase was mainly due to interest on the bridge facility, interest on debt assumed in the WGL Acquisition and higher average debt balances.

AltaGas recorded an income tax recovery of $63 million for the fourth quarter of 2018 compared to an income tax recovery of $76 million in the same quarter of 2017. The lower income tax recovery was mainly due to the absence of tax recoveries related to the TCJA and provisions on assets in the fourth quarter of 2017, partially offset by a tax recovery on assets classified as held for sale in the fourth quarter of 2018.

Net income applicable to common shares for the fourth quarter of 2018 was $174 million ($0.64 per share) compared to a net loss applicable to common shares of $11 million ($0.06 per share) for the same quarter in 2017. The increase was mainly due to the same previously referenced factors resulting in the increase in normalized EBITDA, lower provisions on assets, higher unrealized gains on risk management contracts, lower transaction costs related to the WGL Acquisition, and changes in the fair value of natural gas optimization inventory. These increases were partially offset by lower income tax recovery, higher interest expense, higher depreciation and amortization expense, higher net income applicable to non-controlling interests, provisions on equity investments, higher losses on sale of assets, and higher losses on investments.

Normalized net income was $120 million ($0.44 per share) for the fourth quarter of 2018, compared to $63 million ($0.36 per share) reported for the same quarter in 2017. The increase was mainly due to the same previously referenced factors resulting in the increase in normalized EBITDA, partially offset by lower income tax recoveries, higher interest expense and higher depreciation and amortization expense. Normalizing items in the fourth quarter of 2018 included after-tax amounts related to change in fair value of natural gas optimization inventory, unrealized gains on risk management contracts, losses on sale of assets, losses on investments, transaction costs related to acquisitions and dispositions, tax adjustments as a result of the Northwest Hydro facilities being held for sale, provisions on assets, provisions on equity investments, and financing costs associated with the bridge facility for the WGL Acquisition of $3 million. In the fourth quarter of 2017, normalizing items included after-tax amounts related to transaction costs on acquisitions, unrealized losses on risk management contracts, gains on long-term investments, provisions on assets, development costs, financing costs associated with the bridge facility for the WGL Acquisition of $3 million, and the impact of the TCJA.

Year Ended December 31

Normalized EBITDA for the year ended December 31, 2018 was $1,009 million, compared to $797 million in 2017. The increase was primarily due to contributions from WGL for the period subsequent to transaction close on July 6, 2018, higher commodity margins as a result of higher realized frac spread and higher frac exposed volumes, contributions from the Townsend 2A and North Pine facilities which commenced operations in the fourth quarter of 2017, AltaGas’ share of ACI earnings subsequent to the IPO close on October 25, 2018, higher rates and customer growth at certain utilities, colder weather primarily at SEMCO, and higher interest income. These increases were partially offset by the impact of the ACI IPO, lower river flows at the Northwest Hydro facilities, decreased revenue from SEMCO due to the TCJA, the impact of the sale of the San Joaquin facilities, the expiry of the PPA at the Ripon gas-fired electricity generation facility in May 2018 (partially offset by the new RA contract which began in the second quarter of 2018 and was in place for the remainder of 2018), lower natural gas storage margins, and the impact of the weaker U.S. dollar on reported results from U.S. assets. For the years ended December 31, 2018 and 2017, the average Canadian/U.S. dollar exchange rate was approximately 1.30. Fluctuations in the rate throughout the year resulted in a decrease in normalized EBITDA of approximately $2 million for the year ended December 31, 2018.

Normalized funds from operations for the year ended December 31, 2018 were $657 million ($2.95 per share), compared to $615 million ($3.60 per share) in 2017 reflecting the same drivers as normalized EBITDA and higher tax recoveries, partially offset by higher interest expense. The decrease in per share amounts is due to a higher number of shares outstanding in 2018 compared to 2017. Previously, AltaGas estimated that normalized funds from operations for the year would increase by

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approximately 10 percent in 2018 compared to 2017. The actual increase in normalized funds from operations in 2018 of 7 percent was lower than expected, due to lower Northwest Hydro river flows and the delay of cash distribution receipts from equity investments to early 2019. For the year ended December 31, 2018, AltaGas received $13 million of dividend income from Petrogas Preferred Shares (2017 - $13 million) and $5 million in common share dividends from Petrogas (2017 - $5 million).

In 2018, AltaGas recorded pre-tax provisions of approximately $729 million (after-tax $562 million). These provisions were primarily related to the San Joaquin Power assets in California comprised of the Tracy, Hanford and Henrietta plants, non-core Midstream and Power assets in Canada which are currently classified as held for sale, certain assets included in the IPO of ACI, and certain Power assets in the United States. In addition, pre-tax provisions of $37 million and $2 million were recorded on certain remaining gas assets and the Pomona Gas Repowering project respectively, and $6 million was recorded on a WGL Energy Systems financing receivable that was classified as held for sale at December 31, 2018. In 2017, AltaGas recorded pre-tax provisions on assets of $133 million (after-tax $80 million) related to the Hanford and Henrietta gas-fired peaking facilities in California and certain non-core development stage projects in the Power segment. In addition, in 2017, AltaGas recorded a pre-tax provision of $7 million (after-tax $5 million) related to a non-core gas processing facility that has been classified as held for sale in the Midstream segment.

Operating and administrative expenses for the year ended December 31, 2018 were $1,129 million, compared to $572 million in 2017. The increase was mainly due to WGL merger commitment costs of $182 million and the inclusion of WGL’s operating and administrative expenses for the period since transaction close on July 6, 2018, partially offset by the exclusion of ACI’s operating and administrative expenses subsequent to transaction close on October 25, 2018 and lower transaction costs (primarily related to the WGL Acquisition) of $63 million in 2018 compared to $66 million in 2017. Depreciation and amortization expense for the year ended December 31, 2018 was $394 million, compared to $282 million in 2017. The increase was mainly due to depreciation and amortization expense on assets acquired in the WGL Acquisition, partially offset by the exclusion of depreciation and amortization expense on assets sold to ACI subsequent to transaction close on October 25, 2018 and the sale of the San Joaquin facilities as of November 13, 2018. Interest expense for the year ended December 31, 2018 was $309 million, compared to $170 million in 2017. The increase was mainly due to interest on the bridge facility, interest on debt assumed in the WGL Acquisition and higher average debt balances.

AltaGas recorded an income tax recovery of $263 million for the year ended December 31, 2018 compared to $34 million in 2017. The increase in income tax recovery was primarily due to tax recoveries booked on asset provisions and WGL transaction and merger commitment costs, as well as a tax recovery on assets classified as held for sale.

Net loss applicable to common shares for the year ended December 31, 2018 was $502 million ($2.25 per share) compared to net income of $30 million ($0.18 per share) in 2017. The decrease was mainly due to provisions on assets recognized during 2018 as discussed above, merger commitment costs related to the WGL Acquisition, higher depreciation and amortization expense, higher interest expense, realized losses on foreign exchange derivatives, higher net income applicable to non-controlling interests, provisions on equity investments, and higher losses on the sale of assets, partially offset by the same previously referenced factors impacting normalized EBITDA, higher income tax recoveries, changes in the fair value of natural gas optimization inventory, higher unrealized gains on risk management contracts, and lower transaction costs related to the WGL Acquisition.

Normalized net income for the year ended December 31, 2018 was $195 million ($0.88 per share), compared to $204 million ($1.19 per share) in 2017. The decrease was due to higher depreciation and amortization expense, higher interest expense and higher preferred share dividends, partially offset by higher income tax recoveries and the same previously referenced factors impacting normalized EBITDA. Normalizing items for the year ended December 31, 2018 included after-tax amounts related to provisions on assets, provisions on equity investments, merger commitment costs associated with the WGL Acquisition, transaction costs related to acquisitions and dispositions, change in fair value of natural gas optimization inventory, realized losses on foreign exchange derivatives, unrealized gains on risk management contracts, a tax recovery as a result of the Northwest Hydro facilities being held for sale, financing costs of $21 million associated with the bridge facility for the WGL Acquisition, losses on sale of assets, and losses on investments. For the year ended December 31, 2017, normalizing items included after-tax amounts related to unrealized losses on risk management contracts, the impact of the TCJA, transaction costs

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on acquisitions and dispositions, financing costs of $14 million associated with the bridge facility for the WGL Acquisition, losses on sale of assets, provisions on assets, gains on investments, and development costs.

Total assets and total long-term liabilities as at December 31, 2018 have both increased significantly compared to December 31, 2017, primarily due to the WGL Acquisition. Total assets increased by approximately $13.5 billion during 2018, mainly due to the addition of WGL’s assets as well as goodwill of approximately $3.2 billion recorded upon acquisition. Long-term liabilities increased by approximately $7.2 billion during 2018, mainly due to the addition of WGL’s long-term liabilities as well as additional debt used to finance the WGL Acquisition.

NON-GAAP FINANCIAL MEASURES

This MD&A contains references to certain financial measures used by AltaGas that do not have a standardized meaning prescribed by GAAP and may not be comparable to similar measures presented by other entities. Readers are cautioned that these non-GAAP measures should not be construed as alternatives to other measures of financial performance calculated in accordance with GAAP. The non-GAAP measures and their reconciliation to GAAP financial measures are shown below. These non-GAAP measures provide additional information that Management believes is meaningful in describing AltaGas’ operational performance, liquidity and capacity to fund dividends, capital expenditures, and other investing activities. The specific rationale for, and incremental information associated with, each non-GAAP measure is discussed below.

References to normalized EBITDA, normalized net income, normalized funds from operations, net debt, and net debt to total capitalization throughout this MD&A have the meanings as set out in this section.

Normalized EBITDA

	Three Months Ended December 31						Year Ended December 31
($ millions)	2018			2017			2018			2017
Normalized EBITDA	$	394		$	213		$	1,009		$	797
Add (deduct):
Transaction costs related to acquisitions and dispositions	(12		)	(15		)	(63		)	(66		)
Merger commitment costs	—			—			(182		)	—
Unrealized gains (losses) on risk management contracts	44			(16		)	56			(63		)
Changes in fair value of natural gas optimization inventory	12			—			15			—
Non-controlling interest related to HLBV investments	(22		)	—			(39		)	—
Realized losses on foreign exchange derivatives	—			—			(35		)	—
Gains (losses) on investments	(10		)	7			(10		)	4
Losses on sale of assets	(12		)	—			(10		)	(3		)
Provisions on assets	(31		)	(138		)	(729		)	(140		)
Provisions on investments accounted for by the equity method	(15		)	—			(15		)	—
Development costs	—			(1		)	—			(2		)
Investment tax credits related to distributed generation assets	(2		)	—			(5		)	—
Accretion expenses	(3		)	(3		)	(11		)	(11		)
Foreign exchange gains	1			—			5			2
EBITDA	$	344		$	47		$	(14	)	$	518
Add (deduct):
Depreciation and amortization	(126		)	(71		)	(394		)	(282		)
Interest expense	(110		)	(44		)	(309		)	(170		)
Income tax recovery	63			76			263			34
Net income (loss) after taxes (GAAP financial measure)	$	171		$	8		$	(454	)	$	100

EBITDA is a measure of AltaGas’ operating profitability prior to how business activities are financed, assets are amortized, or earnings are taxed. EBITDA is calculated from the Consolidated Statement of Income using net income adjusted for pre-tax depreciation and amortization, interest expense, and income tax recovery.

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Normalized EBITDA includes additional adjustments for unrealized gains (losses) on certain risk management contracts, realized losses on foreign exchange derivatives, gains (losses) on investments, transaction costs related to acquisitions and dispositions, merger commitment costs, losses on the sale of assets, provisions on assets, provisions on equity investments, accretion expenses related to asset retirement obligations and the Northwest Transmission Line liability, foreign exchange gains, development costs, distributed generation asset related investment tax credits, non-controlling interest of certain investments to which Hypothetical Liquidation at Book Value (HLBV) accounting is applied, and changes in fair value of natural gas optimization inventory. AltaGas presents normalized EBITDA as a supplemental measure. Normalized EBITDA is frequently used by analysts and investors in the evaluation of entities within the industry as it excludes items that can vary substantially between entities depending on the accounting policies chosen, the book value of assets and the capital structure.

Normalized Net Income

	Three Months Ended December 31						Year Ended December 31
($ millions)	2018			2017			2018			2017
Normalized net income	$	120		$	63		$	195		$	204
Add (deduct) after-tax:
Transaction costs related to acquisitions and dispositions	(9		)	(14		)	(50		)	(53		)
Merger commitment costs	—			—			(135		)	—
Unrealized gains (losses) on risk management contracts	30			(12		)	34			(55		)
Changes in fair value of natural gas optimization inventory	12			—			15			—
Realized loss on foreign exchange derivatives	—			—			(35		)	—
Gains (losses) on investments	(10		)	6			(1		)	3
Losses on sale of assets	(36		)	—			(35		)	(3		)
Provisions on investments accounted for by the equity method	(11		)	—			(11		)	—
Provisions on assets	(23		)	(84		)	(562		)	(85		)
Tax adjustment on assets held for sale	104			—			104			—
Development costs	—			(1		)	—			(1		)
Impact of the TCJA	—			34			—			34
Financing costs associated with the bridge facility	(3		)	(3		)	(21		)	(14		)
Net income (loss) applicable to common shares (GAAP financial measure)	$	174		$	(11	)	$	(502	)	$	30

Normalized net income represents net income (loss) applicable to common shares adjusted for the after-tax impact of unrealized gains (losses) on certain risk management contracts, realized loss on foreign exchange derivatives, gains (losses) on investments, merger commitment costs, transaction costs related to acquisitions and dispositions, losses on the sale of assets, provisions on assets, provisions on equity investments, a tax recovery as a result of the Northwest Hydro facilities being held for sale, financing costs associated with the bridge facility for the WGL Acquisition, development costs, the impact of the TCJA, and changes in fair value of natural gas optimization inventory. This measure is presented in order to enhance the comparability of AltaGas’ earnings, as it reflects the underlying performance of AltaGas’ business activities.

Normalized Funds from Operations

	Three Months Ended December 31						Year Ended December 31
($ millions)	2018			2017			2018			2017
Normalized funds from operations	$	255		$	180		$	657		$	615
Add (deduct):
Development costs	—			(1		)	—			(1		)
Transaction and financing costs related to acquisitions and dispositions	(12		)	(17		)	(63		)	(71		)
Merger commitment costs	—			—			(182		)	—
Funds from operations	243			162			412			543
Add (deduct):
Net change in operating assets and liabilities	(301		)	(10		)	(487		)	2
Asset retirement obligations settled	(2		)	(1		)	(4		)	(4		)
Cash from (used by) operations (GAAP financial measure)	$	(60	)	$	151		$	(79	)	$	541

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Normalized funds from operations is used to assist management and investors in analyzing the liquidity of the Corporation without regard to changes in operating assets and liabilities in the period and non-operating related expenses (net of current taxes) such as development costs and transaction and financing costs related to acquisitions and dispositions.

Funds from operations are calculated from the Consolidated Statement of Cash Flows and are defined as cash from operations before net changes in operating assets and liabilities and expenditures incurred to settle asset retirement obligations. Management uses this measure to understand the ability to generate funds for capital investments, debt repayment, dividend payments and other investing activities.

Funds from operations and normalized funds from operations as presented should not be viewed as an alternative to cash from operations or other cash flow measures calculated in accordance with GAAP.

Net Debt and Net Debt to Total Capitalization

Net debt and net debt to total capitalization are used by the Corporation to monitor its capital structure and financing requirements. It is also used as a measure of the Corporation’s overall financial strength. Net debt is defined as short-term debt, plus current and long-term portions of long-term debt, less cash and cash equivalents. Total capitalization is defined as net debt plus shareholders’ equity and non-controlling interests. Additional information regarding these non-GAAP measures can be found under the section Capital Resources of this MD&A.

RESULTS OF OPERATIONS BY REPORTING SEGMENT

Normalized EBITDA (1)

	Three Months Ended December 31						Year Ended December 31
($ millions)	2018			2017			2018			2017
Utilities	$	232		$	90		$	426		$	298
Midstream	93			61			277			221
Power	76			72			320			303
Sub-total: Operating Segments	401			223			1,023			822
Corporate	(7		)	(10		)	(14		)	(25		)
	$	394		$	213		$	1,009		$	797

(1)Non-GAAP financial measure; See discussion in Non-GAAP Financial Measures section of this MD&A.

Revenue

	Three Months Ended December 31						Year Ended December 31
($ millions)	2018			2017			2018			2017
Utilities	$	818		$	353		$	1,766		$	1,127
Midstream	489			267			1,435			1,008
Power	412			164			1,171			632
Sub-total: Operating Segments	1,719			784			4,372			2,767
Corporate	28			(14		)	(2		)	(58		)
Intersegment eliminations	(20		)	(25		)	(113		)	(153		)
	$	1,727		$	745		$	4,257		$	2,556

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UTILITIES

OPERATING STATISTICS

	Three Months Ended December 31				Year Ended December 31
	2018		2017		2018		2017
U.S. utilities
Natural gas deliveries - end-use (Bcf)(1)	58.5		24.3		107.3		70.8
Natural gas deliveries - transportation (Bcf)(1)	52.0		14.2		89.2		52.0
Service sites (2)	1,642,523		581,518		1,642,523		581,518
Degree day variance from normal - SEMCO Gas (%) (3)	7.5		4.8		5.6		(5.3	)
Degree day variance from normal - ENSTAR (%) (3)	(19.6	)	(8.3	)	(11.5	)	(1.6	)
Degree day variance from normal - Washington Gas (%) (3) (4)	0.4		—		(0.7	)	—

(1)Petajoule (PJ) is one million gigajoules. Bcf is one billion cubic feet.

(2)Service sites reflect all of the service sites of the U.S. utilities, including transportation and non-regulated business lines.

(3)A degree day for U.S. utilities is a measure of coldness determined daily as the number of degrees the average temperature during the day in question is below 65 degrees Fahrenheit. Degree days for a particular period are determined by adding the degree days incurred during each day of the period. Normal degree days for a particular period are the average of degree days during the prior 15 years for SEMCO Gas, during the prior 10 years for ENSTAR, and during the prior 30 years for Washington Gas.

(4)In certain of Washington Gas’ jurisdictions (Virginia and Maryland) there are billing mechanisms in place which are designed to eliminate the effects of variance in customer usage caused by weather and other factors such as conservation. In the District of Columbia, there is no weather normalization billing mechanism nor does it hedge to offset the effects of weather. As a result, colder or warmer weather will result in variances to financial results.

REGULATORY METRICS

Year Ended December 31	2018	2017
Approved ROE (%)
Canadian utilities (average) (4)	—	9.7
U.S. utilities (average)	10.6	11.6
Approved return on debt (%)
Canadian utilities (average) (4)	—	5.0
U.S. utilities (average)	5.4	6.0
Rate base ($ millions)(1)
Canadian utilities (4)	—	833
U.S. utilities(2)(3)	3,684	847

(1)Rate base is indicative of the earning potential of each utility over time. Approved revenue requirement for each utility is typically based on the rate base as approved by the regulator for the respective rate application, but may differ from the rate base indicated above.

(2)In U.S. dollars.

(3)Reflects AltaGas’ 65 percent interest in Cook Inlet Natural Gas Storage Alaska LLC.

(4)The Canadian utilities were sold to ACI in the fourth quarter of 2018.

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During the fourth quarter of 2018, AltaGas’ Utilities segment experienced colder weather, primarily at SEMCO, compared to the same quarter of 2017. The 2018 increase in customers and transportation represents the addition of WGL natural gas deliveries.

For the year ended December 31, 2018, AltaGas’ Utilities segment experienced overall colder weather compared to 2017. This was mainly driven by 6 percent colder than normal weather at SEMCO and 13 percent colder than normal weather at AUI (for the period prior to the ACI IPO), partially offset by 12 percent warmer than normal weather at ENSTAR. Overall colder weather resulted in increased natural gas deliveries to end-use customers. The 2018 increase in customers and transportation represents the addition of WGL natural gas deliveries.

Service sites increased by approximately 1.1 million sites in 2018 compared to 2017 due to the addition of WGL customers and growth in customer base, partially offset by decreases due to the sale of the Canadian utilities to ACI.

Three Months Ended December 31

The Utilities segment reported normalized EBITDA of $232 million in the fourth quarter of 2018, compared to $90 million in the same quarter in 2017. The increase was mainly due to the impact of the WGL Acquisition of $159 million, the favorable impact of the stronger U.S. dollar, higher rates, growth in customer base, higher customer usage, and colder weather in Michigan. The increase was partially offset by the impact of the ACI IPO in the fourth quarter of 2018, the 2018 impact related to the federal tax reduction at the U.S. utilities, and warmer weather in Alaska.

Year Ended December 31

The Utilities segment reported normalized EBITDA of $426 million for the year ended December 31, 2018, compared to $298 million in 2017. The increase was mainly due to the impact of the WGL Acquisition for the period since transaction close of $153 million, colder weather in Michigan, higher rates, and growth in customer base. The increase was partially offset by the impact of the ACI IPO, the 2018 revenue impact related to the federal tax reduction at the U.S. utilities, one-time impacts in 2017 related to insurance proceeds received by SEMCO’s non-regulated operations of approximately $2 million and an early termination payment of approximately $2 million from one of SEMCO’s non-regulated customers moving from a fixed fee to a volumetric based contract, the impact of the stronger Canadian dollar, and warmer weather in Alaska.

MIDSTREAM

OPERATING STATISTICS

	Three Months Ended December 31		Year Ended December 31
	2018	2017	2018	2017
Extraction inlet gas processed (Mmcf/d)(1)	934	983	912	970
FG&P inlet gas processed (Mmcf/d)(1)	479	441	466	392
Total inlet gas processed (Mmcf/d)(1)	1,413	1,424	1,378	1,362
Extraction ethane volumes (Bbls/d)(1)	25,448	26,125	24,346	27,493
Extraction NGL volumes (Bbls/d)(1) (2)	39,074	42,181	38,128	37,850
Total extraction volumes (Bbls/d)(1) (3)	64,522	68,306	62,474	65,343
Frac spread - realized ($/Bbl)(1) (4)	15.84	18.02	16.49	13.40
Frac spread - average spot price ($/Bbl)(1) (5)	21.00	30.66	22.79	20.50
Natural gas optimization inventory (Bcf)	35.9	2.7	35.9	2.7
WGL retail energy marketing - gas sales volumes (Mmcf)	20,750	—	28,906	—

(1)Average for the period.

(2)NGL volumes refer to propane, butane and condensate.

(3)Includes Harmattan NGL processed on behalf of customers.

(4)Realized frac spread or NGL margin, expressed in dollars per barrel of NGL, is derived from sales recorded by the segment during the period for frac exposed volumes plus the settlement value of frac hedges settled in the period less extraction premiums, divided by the total frac exposed volumes produced during the period.

(5)Average spot frac spread or NGL margin, expressed in dollars per barrel of NGL, is indicative of the average sales price that AltaGas receives for propane, butane and condensate less extraction premiums, before accounting for hedges, divided by the respective frac exposed volumes for the period.

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Inlet gas volumes processed at the extraction facilities for the three months ended December 31, 2018 decreased by 49 Mmcf/d, compared to the same period in 2017. The decrease was primarily due to reduced ownership at Younger effective April 2018, partially offset by higher inlet volumes at the Joffre Ethane Extraction Plant (JEEP) and Harmattan due to higher available gas flows. Inlet gas volumes processed at the field gathering and processing (FG&P) facilities for the three months ended December 31, 2018 increased by 38 Mmcf/d primarily due to volumes received at the Townsend facilities and the recently acquired Aitken Creek North facility, partially offset by the disposition of certain non-core facilities in the first quarter of 2018.

Inlet gas volumes processed at the extraction facilities for the year ended December 31, 2018 decreased by 58 Mmcf/d, compared to the same period in 2017. The decrease was mainly due to reduced ownership at Younger effective April 2018, partially offset by higher inlet volumes at JEEP and Edmonton Ethane Extraction Plant (EEEP) due to higher available gas flows. Inlet gas volumes processed at the FG&P facilities for the year ended December 31, 2018 increased by 74 Mmcf/d primarily due to volumes received at the Townsend facilities and higher volumes at Gordondale, partially offset by the disposition of certain non-core assets in the first quarter of 2018.

Average ethane volumes for the three months ended December 31, 2018 decreased by 677 Bbls/d, while average NGL volumes decreased by 3,107 Bbls/d compared to the same period in 2017. Lower ethane volumes were a result of rejecting production at Younger due to uneconomic pricing, partially offset by higher ethane production at Pembina Empress Extraction Plant (PEEP), EEEP and Harmattan. Lower NGL volumes were a result of a lower ownership interest at Younger and lower volumes at Gordondale, partially offset by higher NGL production at the North Pine facility due to additional volumes available from the Townsend facilities.

Average ethane volumes for the year ended December 31, 2018 decreased by 3,147 Bbls/d compared to the same period in 2017. Lower ethane volumes were primarily due to rejecting production due to uneconomic pricing at Younger in the second, third and fourth quarters of 2018, and lower ethane volumes at Harmattan due to a planned turnaround in the second quarter, partially offset by higher production at EEEP, JEEP and PEEP. Average NGL volumes for the year ended December 31, 2018 increased by 278 Bbls/d compared to the same period in 2017. Higher NGL volumes were primarily due to increased volumes produced at the Townsend, North Pine and Gordondale facilities partially offset by reduced ownership at Younger and the planned turnaround at Harmattan.

With the addition of WGL, for the period from transaction close to December 31, 2018, U.S. retail sales volumes were 28,906 Mmcf.

Three Months Ended December 31

The Midstream segment reported normalized EBITDA of $93 million in the fourth quarter of 2018, compared to $61 million for the same quarter of 2017. The increase was mainly due to contributions from WGL Midstream assets of $31 million, the acquisition of 50 percent ownership in Black Swan’s Aitken Creek North gas processing facility in the fourth quarter of 2018, and higher revenues at Harmattan due to increased NGL activities, partly offset by lower frac exposed volumes at Younger due to reduced ownership and lower frac spreads, and lower NGL marketing margins.

During the fourth quarter of 2018, AltaGas recorded equity earnings of $6 million from Petrogas, comparable to the same quarter of 2017.

During the fourth quarter of 2018, AltaGas hedged approximately 7,500 Bbls/d of NGL volumes at an average price of $33/Bbl excluding basis differentials. During the fourth quarter of 2017, AltaGas hedged 6,500Bbls/d of NGL at an average price of $24/Bbl, excluding basis differentials. The average indicative spot NGL frac spread for the fourth quarter of 2018 was approximately $21/Bbl, compared to $31/Bbl in the same quarter of 2017 inclusive of basis differentials. The realized frac spread of approximately $16/Bbl in the fourth quarter of 2018 (2017 - $18/Bbl) was comparable to the same period in 2017.

During the fourth quarter of 2018, the Midstream segment recognized an additional pre-tax provision of $2 million on certain non-core midstream assets classified as held for sale. In the fourth quarter of 2017, the Midstream segment recognized a pre-tax

32

provision on assets of $7 million related to a non-core gas processing facility in Alberta which was classified as held for sale at December 31, 2017.

Year Ended December 31

The Midstream segment reported normalized EBITDA of $277 million for the year ended December 31, 2018, compared to $221 million in 2017. The increase was mainly due to contributions from WGL for the period after transaction close on July 6, 2018 of $38 million, higher realized frac spread and frac exposed volumes primarily at EEEP, contributions from the North Pine and Townsend 2A facilities which commenced commercial operations in the fourth quarter of 2017, impacts from the acquisition of 50 percent ownership in the Aitken Creek North facility in the fourth quarter of 2018, higher revenues at Harmattan due to increased NGL activities and higher ethane revenues at EEEP, partially offset by lower natural gas storage and marketing margins, the impact of the sale of the EDS and JFP transmission assets in the first quarter of 2017, and the planned turnaround at the Harmattan facility.

For the year ended December 31, 2018, AltaGas recorded equity earnings of $19 million from Petrogas as compared to $25 million in 2017. The decrease in Petrogas earnings was due to a planned turnaround at the Ferndale Terminal in the first quarter of 2018 and unrealized mark to market losses on hedges. In addition, AltaGas had lower Tidewater dividends from Tidewater due to the sale of the shares in the third quarter of 2018.

During the year-ended December 31, 2018, AltaGas recognized pre-tax provisions of $117 million on certain non-core midstream assets classified as held for sale, and a pre-tax impairment of $37 million related to shut-in assets in the South, Cold Lake, and Northwest operating areas. During the year ended December 31, 2017, AltaGas recognized a pre-tax provision of $7 million related to a non-core gas processing facility that was classified as held for sale at December 31, 2017.

During the year ended December 31, 2018, AltaGas recognized a pre-tax gain of $1 million on the sale of a non-core gas processing facility, while in the same period of 2017, AltaGas recognized a pre-tax loss of $3 million on the sale of the EDS and JFP transmission assets.

During the year ended December 31, 2018, AltaGas sold 43.7 million shares of Tidewater Midstream and Infrastructure Inc. For the year ended December 31, 2018, AltaGas recorded an unrealized loss of $1 million and a realized loss of $2 million relating to the sale of these shares.

For the year ended December 31, 2018, AltaGas hedged approximately 7,500 Bbls/d of NGL volumes at an average price of $33/Bbl, excluding basis differentials. For the year ended December 31, 2017 AltaGas hedged 5,800 Bbls/d of NGL at an average price of $23/Bbl, excluding basis differentials. The average indicative spot NGL frac spread for the year ended December 31, 2018 was approximately $23/Bbl compared to $21/Bbl in the same period of 2017. The realized frac spread of $16/Bbl for the year ended December 31, 2018 (2017 - $13/Bbl) was higher than the same period in 2017 due to improved commodity prices.

On April 3, 2018, AltaGas entered into a long-term natural gas processing arrangement (the Processing Arrangement) with Birchcliff Energy Ltd. at AltaGas’ deep-cut sour gas processing facility located in Gordondale, Alberta (the Gordondale facility). Under the Processing Arrangement, Birchcliff is provided with up to 120 MMcf/d of natural gas processing on a firm-service basis, and Birchcliff’s take-or-pay obligation is 100 MMcf/d. The Processing Arrangement provides stable long-term cash flow by filling the existing operational capacity of 120 Mmcf/d at the Gordondale facility and significantly enhances the potential to flow third-party volumes through the facility and to grow those volumes to bring the operating capacity up to 150 Mmcf/d. Growing propane volumes from Gordondale will be dedicated to RIPET as part of the commercial arrangements. The new Processing Arrangement was effective as of January 1, 2018 and replaces the parties’ existing Gordondale processing arrangement.

On August 27, 2018, AltaGas announced that it entered into definitive agreements with Kelt to provide an energy infrastructure solution for the liquids-rich Inga Montney development located in British Columbia. These agreements underpin the expansion of AltaGas’ Townsend complex including the addition of a 198 MMcf per day C3+ deep cut gas processing facility and provides Kelt with firm processing of 75 MMcf per day of raw gas under an initial 10 year take-or-pay agreement. Under the terms of the

33

agreement, Kelt has the option during the first three years of the initial take-or-pay term to commit to additional firm processing up to a total of 198 MMcf per day for a term of its choice, with an additional minimum take-or-pay commitment of ten years.

On September 26, 2018, AltaGas announced that it has entered into a definitive agreement with Black Swan to acquire 50 percent ownership in certain existing and future natural gas processing plants of Black Swan in British Columbia. As part of the arrangement, AltaGas and Black Swan have also entered into long term processing, transportation and marketing agreements that include new integrated AltaGas liquids handling infrastructure, thereby strengthening AltaGas’ Northeast B.C. value proposition and connecting producers with additional options for energy exports. The total capital investment by AltaGas will be approximately $230 million and the transaction closed on October 2, 2018.

POWER

OPERATING STATISTICS

	Three Months Ended December 31		Year Ended December 31
	2018	2017	2018	2017
Renewable power sold (GWh)	233	301	1,551	1,629
Conventional power sold (GWh)	985	1,059	3,728	2,844
Renewable capacity factor (%)	14.6	27.5	29.7	39.6
Contracted conventional equivalent availability factor (%) (1)	97.4	96.3	97.2	98.1
WGL retail energy marketing - electricity sales volumes (GWh)	2,911	—	5,906	—

(1)Calculated as the availability factor contracted under long-term tolling arrangements adjusted for occasions where partial or excess capacity payments have been added or deducted.

During the fourth quarter of 2018, the volume of renewable power sold decreased by 68 GWh and the volume of conventional power sold decreased by 74 GWh, compared to the same quarter in 2017. The decrease in renewable volumes was due to continued dry and cool weather at the Northwest Hydro facilities, the October 2018 sale of the Bear Mountain wind facility to ACI, and decreased generation at the Craven facility due to an extended planned outage, partially offset by the addition of WGL power generation. The decrease in conventional volumes sold was due to the November 2018 sale of the San Joaquin facilities, partially offset by increased dispatch at Blythe under its power purchase agreement due to greater operational and fuel flexibility.

For the year ended December 31, 2018, the volume of renewable power sold decreased by 78 GWh and the volume of conventional power sold increased by 884 GWh compared to 2017. The decrease in renewable volumes was due to lower generation at the Northwest Hydro facilities, lower wind generation at the Bear Mountain wind facility and the October 2018 sale to ACI, and lower generation at Craven, partially offset by the addition of WGL power generation for the period since transaction close. The increase in conventional volumes was due to higher dispatch at Blythe due to greater operational and fuel flexibility, partially offset by the November 2018 sale of the San Joaquin facilities.

The contracted conventional equivalent availability factor was higher for the three months ended December 31, 2018 as a result of Blythe requiring maintenance in the fourth quarter of 2017 due to increased dispatch. The contracted conventional equivalent availability factor was lower for the year ended December 31, 2018 due to a longer planned outage and increased unplanned outages at Blythe.

The renewable capacity factor during the fourth quarter of 2018 was lower due to lower generation at the Northwest Hydro facilities and lower Bear Mountain wind generation due to the sale of Bear Mountain to ACI in October 2018. The renewable capacity factor for the year ended December 31, 2018 was lower than 2017 due to the same factors impacting the fourth quarter of 2018.

With the addition of WGL, for the period from transaction close to December 31, 2018, U.S. retail sales volumes were 5,906 GWh.

34

Three Months Ended December 31

The Power segment reported normalized EBITDA of $76 million in the fourth quarter of 2018, compared to $72 million in the same quarter of 2017. Normalized EBITDA increased as a result of earnings from WGL’s power assets of $33 million, partially offset by lower river flows at the Northwest Hydro facilities, the impact of the sale of the San Joaquin facilities in November 2018, the impact of the ACI IPO, expiry of the Ripon PPA on May 31, 2018, and lower contributions from Craven due to an extended planned outage and new contract terms.

In the fourth quarter of 2018, AltaGas sold the Bear Mountain wind facility as well as an approximate 10 percent interest in the Northwest Hydro facilities to AltaGas Canada Inc. Subsequent to the IPO, AltaGas has retained an equity interest in ACI of approximately 37 percent. In addition, on November 13, 2018, the Power segment closed the sale of the San Joaquin facilities to Middle River Power III for a gross purchase price of approximately US$299 million resulting in a pre-tax loss of $14 million, and on December 11, 2018, the Busch Ranch wind asset in the United States was sold for a purchase price of approximately US$16 million resulting in a pre-tax gain of $3 million.

During the fourth quarter of 2018, the Power segment recorded pre-tax provisions on assets of $6 million related to a WGL Energy Systems financing receivable that was classified as held for sale at December 31, 2018, and $23 million related to a development project in the U.S. During the fourth quarter of 2017, the Power segment recorded pre-tax provisions on assets of $131 million related to the Hanford and Henrietta gas-fired peaking facilities and a non-core development stage peaking project in California. In addition, during the fourth quarter of 2018, a provision on equity investments of $15 million was recorded related to investments in biomass assets in the U.S.

Year Ended December 31

The Power segment reported normalized EBITDA of $320 million for the year ended December 31, 2018, compared to $303 million in 2017. Normalized EBITDA increased as compared to the same period in 2017 as a result of earnings from WGL’s power assets for the period since transaction close of $64 million, and higher energy sales at the Pomona Energy Storage facility, partially offset by lower 2018 river flows and higher operating costs at the Northwest Hydro facilities, the impact of the sale of the San Joaquin facilities in November 2018, the expiry of the Ripon PPA on May 31, 2018, the impact of the ACI IPO, and lower contributions from Craven due to unplanned outages and new contract terms.

In June 2018, the Power segment closed the sale of a 35 percent indirect equity interest in the Northwest Hydro facilities for cash proceeds of approximately $922 million. The sale of the minority interest in the Northwest Hydro facilities is to a joint venture company that is indirectly owned by Axium Infrastructure Inc., as manager of Axium Infrastructure Canada II Limited Partnership, and Manulife Financial Corporation. On December 13, 2018, AltaGas announced that it reached an agreement for the sale of its remaining interest of approximately 55 percent in these facilities for total proceeds of approximately $1.37 billion. The assets were classified as held for sale at December 31, 2018 and the sale closed in January 2019.

During the year ended December 31, 2018, the Power segment recorded pre-tax provisions on assets of $381 million including approximately $340 million for the Tracy, Hanford and Henrietta gas-fired power assets in California, $10 million for certain gas-fired peaking plants in Alberta to be sold to Birch Hill, $6 million related to a WGL Energy Systems financing receivable that was classified as held for sale at December 31, 2018, and $23 million related to a development project in the U.S. In addition, a pre-tax provision of $2 million was recorded relating to the Pomona Repowering project. During the year ended December 31, 2018, the Power segment also recorded a provision on equity investments of $15 million related to investments in biomass assets in the U.S. During the year ended December 31, 2017, the Power segment recorded pre-tax provisions on assets of approximately $133 million related to the Hanford and Henrietta gas-fired peaking facilities and certain non-core development stage gas-fired peaking assets in California and Alberta.

For the year ended December 31, 2018, the Power segment was also impacted by the previously mentioned asset sales recorded in the fourth quarter of 2018. During the year ended December 31, 2017, the Power segment disposed of certain non-core development stage wind assets for a pre-tax gain of $1 million.

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CORPORATE

Three Months Ended December 31

In the Corporate segment, normalized EBITDA for the fourth quarter of 2018 was a loss of $7 million, compared to a loss of $10 million in the same period of 2017. The decreased loss was mainly due to higher interest income and lower employee benefit expenses.

Year Ended December 31

In the Corporate segment, normalized EBITDA for the year ended December 31, 2018 was a loss of $14 million, compared to a loss of $25 million for the year ended December 31, 2017. The decreased loss was mainly due to interest income earned on funds that were held in escrow for the WGL Acquisition and lower employee benefit expenses, partly offset by increases to professional and consulting fees and information technology related costs.

INVESTED CAPITAL

	Three Months Ended December 31, 2018
($ millions)	Utilities		Midstream			Power			Corporate		Total
Invested capital:
Property, plant and equipment	$	177	$	217		$	14		$	2	$	410
Intangible assets	18		1			—			4		23
Long-term investments	—		150			—			—		150
Contributions from non-controlling interest	—		(14		)	—			—		(14		)
Invested capital	195		354			14			6		569
Disposals:
Property, plant and equipment	—		—			(394		)	—		(394		)
Net invested capital	$	195	$	354		$	(380	)	$	6	$	175

	Three Months Ended December 31, 2017
($ millions)	Utilities		Midstream			Power		Corporate		Total
Invested capital:
Property, plant and equipment	$	46	$	65		$	3	$	—	$	114
Intangible assets	1		2			—		1		4
Contributions from non-controlling interest	—		(5		)	—		—		(5		)
Invested capital	47		62			3		1		113
Disposals:
Property, plant and equipment	—		—			—		—		—
Net invested capital	$	47	$	62		$	3	$	1	$	113

During the fourth quarter of 2018, AltaGas’ invested capital was $569 million, compared to $113 million in the same quarter of 2017. The increase in expenditures was primarily due to capital spending at Washington Gas of approximately $150 million, expenditures related to the construction of RIPET, and contributions to WGL’s investment in the Mountain Valley Pipeline.

The invested capital in the fourth quarter of 2018 included maintenance capital of $2 million (2017 - $2 million) in the Midstream segment and $2 million (2017 - $2 million) in the Power segment.

36

	Year Ended December 31, 2018
($ millions)	Utilities		Midstream			Power			Corporate			Total
Invested capital:
Property, plant and equipment	$	507	$	391		$	74		$	4		$	976
Intangible assets	22		5			12			7			46
Long-term investments	—		228			—			—			228
Business acquisition	4,682		1,525			892			(1,168		)	5,931
Contributions from non-controlling interest	—		(49		)	—			—			(49		)
Invested capital	5,211		2,100			978			(1,157		)	7,132
Disposals:
Property, plant and equipment	—		(8		)	(395		)	—			(403		)
Net invested capital	$	5,211	$	2,092		$	583		$	(1,157	)	$	6,729

	Year Ended December 31, 2017
($ millions)	Utilities			Midstream			Power			Corporate		Total
Invested capital:
Property, plant and equipment	$	125		$	312		$	19		$	2	$	458
Intangible assets	2			3			13			2		20
Long-term investments	—			17			—			—		17
Contributions from non-controlling interest	—			(17		)	—			—		(17		)
Invested capital	127			315			32			4		478
Disposals:
Property, plant and equipment	(1		)	(67		)	(2		)	—		(70		)
Net invested capital	$	126		$	248		$	30		$	4	$	408

For the year ended December 31, 2018, AltaGas’ invested capital was approximately $7.1 billion, compared to $478 million in 2017. The increase in invested capital in 2018 was primarily due to cash paid for the WGL Acquisition of $5.9 billion, higher additions to property, plant and equipment, higher contributions to AIJVLP, and contributions to WGL’s investments in the Central Penn Pipeline and Mountain Valley Pipeline, partially offset by higher contributions from non-controlling interest (representing Vopak’s share of construction costs related to RIPET).

The increase in additions to property, plant and equipment in 2018 was mainly due to capital expenditures related to system betterment and accelerated pipeline replacement programs at Washington Gas, construction costs at RIPET, capital expenditures related to WGL’s distributed generation projects, and the purchase of an office building at SEMCO. The disposals of property, plant and equipment in 2018 primarily related to the San Joaquin facilities in California, the Busch Ranch wind farm in Colorado, a development stage wind asset in the Power segment, and certain other non-core facilities in the Midstream segment. In 2017, the disposals of property, plant and equipment related to the sale of the EDS and JFP transmission assets.

The invested capital for the year ended December 31, 2018 included maintenance capital of $17 million (2017 - $10 million) in the Midstream segment and $13 million (2017 - $9 million) in the Power segment. The maintenance capital for the Midstream segment was mainly related to the costs incurred for the Harmattan facility turnaround, while the maintenance capital for the Power segment mainly related to maintenance at the Northwest Hydro facilities.

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RISK MANAGEMENT

AltaGas is exposed to various market risks in the normal course of operations that could impact earnings and cash flows. AltaGas enters into physical and financial derivative contracts to manage exposure to fluctuations in commodity prices and foreign exchange rates, as well as to optimize certain owned and managed natural gas assets. The Board of Directors of AltaGas has established a risk management policy for the Corporation establishing AltaGas’ risk management control framework. Derivative instruments are governed under, and subject to, this policy. As at December 31, 2018 and December 31, 2017, the fair values of the Corporation’s derivatives were as follows:

($ millions)	December 31,  2018			December 31,  2017
Natural gas	$	(137	)	$	6
NGL frac spread	16			(24		)
Power	(9		)	(1		)
Foreign exchange	(1		)	2
Net derivative liability	$	(131	)	$	(17	)

Commodity Price Contracts

The Corporation executes gas, power, and other physical and financial commodity contracts to serve its customers as well as manage and optimize its asset portfolio. A portion of these physical contracts are not recorded at fair value because they are either i) designated as “normal purchases and normal sales”, ii) do not qualify as derivative instruments due to the significance of their notional amount relative to the applicable liquid markets, or iii) are weather derivatives, which are not exchanged or traded and the underlying variables relate to a climactic, geological or other physical variable. The fair value of power, natural gas, and NGL contracts that qualify as derivatives was calculated using estimated forward prices based on published sources for the relevant period. AltaGas has not elected hedge accounting for any of its derivative contracts currently in place. For AltaGas’ Midstream and Power segments, changes in the fair value of these derivative contracts are recorded in the Consolidated Statements of Income in the period in which the change occurs. For the Utility segment, changes in the fair value of derivative instruments recoverable or refundable to customers are recorded to regulatory assets or regulatory liabilities on the Consolidated Balance Sheets, while changes in the fair value of derivative instruments not affected by rate regulation are recorded in the Consolidated Statements of Income in the period in which the change occurs.

The Midstream segment also executes fixed-for-floating NGL frac spread swaps to manage exposure to frac spreads as the financial results of several extraction plants are affected by fluctuations in NGL frac spreads. The average indicative spot NGL frac spread for the year ended December 31, 2018 was approximately $23/Bbl (2017 - $21/bbl), inclusive of basis differentials. The average NGL frac spread realized by AltaGas (based on average spot price and realized hedge price inclusive of basis differentials) for the year ended December 31, 2018 was approximately $16/Bbl (2017 - $13/Bbl). For 2019, AltaGas currently has frac hedges in place to hedge approximately 6,200 Bbls/d at an average price of $40/Bbl, excluding basis differentials. Additionally, AltaGas uses physical and financial derivatives for the purchase and sale of natural gas in order to optimize owned storage and transportation capacity as well as managed transportation and storage assets on behalf of third parties. To serve retail gas customers, AltaGas enters into retail sales contracts that contain optionality as well as physical and financial contracts which qualify as derivative instruments.

The Utility segment enters into hedging contracts and other contracts that may qualify as derivative instruments related to the purchase of natural gas to manage price risk for its ratepayers. Additionally, Washington Gas executes commodity-related physical and financial contracts in the form of forward, futures, and option contracts as part of an asset optimization program. Under this program, Washington Gas realizes value from its long-term natural gas transportation and storage capacity resources when they are not being fully used to serve utility customers.

The Power segment has various fixed-for-floating power purchase and sale contracts in the Alberta market, which are expected to be settled over the next five years. Additionally, to serve retail electric customers, AltaGas enters into both physical and financial contracts for the purchase and sale of electricity.

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Foreign Exchange

AltaGas has foreign operations whereby the functional currency is the U.S. dollar. As a result, the Corporation’s earnings, cash flows, and other comprehensive income are exposed to fluctuations resulting from changes in foreign exchange rates. This risk is partially mitigated to the extent that AltaGas has U.S. dollar-denominated debt and/or preferred shares outstanding. AltaGas may also enter into foreign exchange forward derivatives to manage the risk of fluctuating cash flows due to variations in foreign exchange rates.

As at December 31, 2018, Management designated $1.5 billion of outstanding U.S. denominated long-term debt to hedge against the currency translation effect of its foreign investments (December 31, 2017 - $nil). This designation has the effect of mitigating volatility on net income by offsetting foreign exchange gains and losses on U.S. dollar denominated long-term debt and foreign net investment. For the year ended December 31, 2018, AltaGas incurred an after-tax unrealized loss of $80 million arising from the translation of debt in other comprehensive income (2017 — after-tax unrealized gain of $7 million).

To mitigate the foreign exchange risks associated with the cash purchase price of WGL, AltaGas entered into foreign currency option contracts with an aggregate notional value of approximately US$1.2 billion which expired in May 2018. These foreign currency option contracts did not qualify for hedge accounting. Therefore, all changes in fair value were recognized in net income. For the year ended December 31, 2018, an unrealized gain of $35 million and a realized loss of $36 million were recognized in revenue in relation to these contracts (2017 - unrealized losses of $34 million). In the second quarter of 2018, AltaGas entered into foreign exchange forward contracts with an aggregate notional value of $3.2 billion intended to minimize the foreign exchange risk of the WGL Acquisition, which settled in the third quarter of 2018. These foreign exchange derivatives did not qualify for hedge accounting. Therefore, all changes in fair value were recognized in net income. For the year ended December 31, 2018, a realized gain of $1 million was recognized in income in relation to these forward contracts (2017 - $nil).

Weather

WGL Energy Services utilizes heating degree day (HDD) instruments from time to time to manage weather and price risks related to its natural gas and electricity sales during the winter heating season. WGL Energy Services also utilizes cooling degree day (CDD) instruments and other instruments to manage weather and price risks related to its electricity sales during the summer cooling season. These instruments cover a portion of estimated revenue or energy-related cost exposure to variations in HDDs or CDDs. For the period from close of the WGL Acquisition to December 31, 2018, pre-tax losses of $1 million were recorded related to these instruments (2017 - $nil).

The Effects of Derivative Instruments on the Consolidated Statements of Income

The following table presents the unrealized gains (losses) on derivative instruments as recorded in the Corporation’s Consolidated Statements of Income:

	Three Months Ended December 31						Year Ended December 31
($ millions)	2018			2017			2018			2017
Natural gas	$	13		$	6		$	(2	)	$	2
Storage optimization	—			—			—			3
NGL frac spread	45			(11		)	40			(12		)
Power	12			(9		)	9			(21		)
Foreign exchange	(1		)	(2		)	34			(35		)
	$	69		$	(16	)	$	81		$	(63	)

Please refer to Note 22 of the 2018 Annual Consolidated Financial Statements for further details regarding AltaGas’ risk management activities.

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Corporation Risks

AltaGas manages its exposure to risks using the strategies outlined in the following table:

Risks	Strategies and Organizational Capability to Mitigate Risks
Operational	·Accelerated replacement of aging pipeline and infrastructure within Washington Gas’ system
	·Acquire large working interests to control and optimize operations and maximize efficiencies
	·Contractual provisions often provide for recovery of operating costs
	·      Centralized procurement strategy to reduce costs
	·Maintain control over operational decisions, operating costs and capital expenditures by operating certain jointly-owned facilities
	·Maintain standard operating practices, assess and document employee competency, and maintain formal inspection, maintenance, safety and environmental programs
	·Purchase property and business interruption insurance
	·Fixed price operating and maintenance contracts with equipment manufacturers
	·Hedging strategy used to balance price and operating risk
Construction	·Major projects group manages and monitors significant construction projects
	·Strong in-house project control and management framework
	·Appropriate internal management structure and processes
	·Engage specialists in designing and building major projects
	·Contractual arrangements to mitigate cost and schedule risks
Liquidity	·Forecast cash flow on a continuous basis to maintain adequate cash balances to fund financial obligations as they come due and to support business operations
	·Maintain financial flexibility and liquidity needs through a variety of sources including internally- generated cash flows, asset sales, DRIP, access to credit facilities, and long-term debt and equity issuances
	·Execute financing plans and strategies to maintain and improve credit ratings to minimize financing costs and support ready access to capital markets
Foreign exchange	·Issue long term debt and preferred shares in U.S. dollars which hedge the Corporation’s net investment in U.S. subsidiaries
	·Employ hedging practices when appropriate, such as entering foreign exchange forward contracts
Interest rates	·Optimize financing plans to maintain and improve credit ratings to minimize interest costs
	·Monitor and proactively manage the Corporation’s debt maturity profile
	·Employ hedging practices such as entering into interest rate swaps
	·Maintain financial flexibility and access to multiple credit facilities and continually monitor covenant compliance ·Monitor and manage the mix of fixed versus floating rate debt exposures
Credit ratings	·Maintain open dialogue with credit rating agencies and request feedback to understand any potential implications to the Corporation’s credit rating

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Risks	Strategies and Organizational Capability to Mitigate Risks
Long-term natural gas volume declines	·Long-term contracts such as take-or-pay, area of mutual interest, geographic franchise with economic out
	·Increase market share by expanding existing facilities or acquiring or constructing new facilities in productive resource play regions
	·Increase geographic and customer diversity to reduce exposure to any one individual customer or area of the WCSB
	·Strategically locate facilities to provide secure access to gas supply
	·Capitalize on integrated aspects of AltaGas’ business to increase volumes through its processing facilities
Volume of power generated	·PPAs for the Blythe and Brush facilities include specified target availability levels and pay fixed capacity payments upon achieving target availability, and as a result, volumes of power sold have a minimal impact on the Corporation
	·Diversification of fuel sources and geography
	·Hedging strategy to balance price and operating risk
	·Undertake extensive studies to support investment decisions
Commodity price	·Contracting terms, processing, storage and transportation fees independent of commodity prices through fee-for-service, take-or-pay, fixed-fee or cost-of-service provisions
	·Hedging strategy with hedge targets approved by the Board of Directors
	·Matching natural gas and electricity purchase obligations with sales commitments in terms of volume and pricing
	·Regulatory recovery mechanisms for gas purchases to serve utility customers
	·Monitor hedge transactions through Risk Management Committee
	·AltaGas’ Commodity Risk Policy prohibits transactions for speculative purposes
	·Employ hedging practices to reduce exposure to commodity prices and volatility and lock in margins when the opportunity arises to increase profitability and reduce earnings volatility
	·Employ strong systems and processes for monitoring and reporting compliance with the Commodity Risk Policy
	·Use a system designed to manage and provide controls for marketing and risk management processes for the NGL business
	·In-depth knowledge and experience of transportation systems, natural gas, NGL and power markets where AltaGas operates
	·Hedge power costs
	·Direct marketing to end-use commercial and industrial customers
	·Execute long-term inflation adjusted electricity purchase arrangements with power buyers
Counterparty	·Strong credit policies and procedures
	·Continuous review of counterparty creditworthiness
	·Establish credit thresholds using appropriate credit metrics
	·Closely monitor exposures and impact of price shocks on liquidity
	·Build a diverse customer and supplier base
	·Active accounts receivable monitoring and collections processes in place
	·Credit terms, netting arrangements and margining provisions included in contractual agreements
Weather	·Anticipated volumes for SEMCO Gas and ENSTAR are determined based on the 15-year and 10-year rolling average for weather, respectively
	·In Maryland and Virginia, Washington Gas has in place regulatory mechanisms and rate designs that eliminate deviations in customer usage caused by variations in weather from normal levels
	·Use of weather derivative instruments by WGL Energy Services
Regulatory and Stakeholder	·Regulatory and commercial personnel monitor and manage regulatory issues
	·Utilities seek rate recovery through rate cases with regulatory commissions and agencies
	·Proactive regulatory and government relations group, strong working relationships with regulators, Indigenous peoples, and other stakeholders
	·Build risk mitigation into contracts where appropriate
	·Skilled regulatory department retained
	·Use of expert third parties when needed

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Risks	Strategies and Organizational Capability to Mitigate Risks
Environment and safety	·Strong safety and environmental management systems
	·Accelerated replacement of mature pipeline infrastructure within Washington Gas’ system
	·Preventative and remedial measures to address increased leak rates within Washington Gas’ distribution system
	·Continuous process improvement strategy employed
	·Focus on mitigating the impact of climate change regulations
	·Zero tolerance safety policies for staff and contractors and reviews of past safety practices for contractors
	·Purchase and maintain general liability and business interruption insurance
	·Pipeline and asset integrity programs are in place
Labour relations	·Maintain access to strong labour markets to attract qualified talent
	·Positive employee relations to retain existing talent and maintain strong relations with unions
Information security	·Strong identity and access management controls
	·Improved information management and control of electronic and physical information, in accordance with data classification, data handling, privacy regulations and data retention requirements
	·Ongoing cybersecurity communication and phishing tests, including targeted training to higher risk teams and individuals
	·Implementation of new information security standards and policies
	·Procedures to ensure regulatory compliance
	·Enhanced penetration and vulnerability testing
	·Incident response protocols
Litigation	·Proactive management of lawsuits and other claims
	·Continuous monitoring of defense and settlement costs of lawsuits and claims
	·Experienced in-house legal department
	·Use of expert third parties when needed
Adequate natural gas supply and storage capacity to meet customer demand	·Maintain diverse capacity portfolio of firm transportation, storage and peaking services across different transmission lines for supply flexibility ·Capacity reserve portfolio maintained for maximum forecasted load under extreme conditions plus a reserve margin approved by regulators
Natural disasters and catastrophic events, including terrorist acts	·Maintain a comprehensive insurance program that covers losses from natural disasters and catastrophic events such as fires, earthquakes, explosions, floods, tornados, terrorist acts, and other similar occurrences. This program provides a risk transfer mechanism that facilitates timely recovery from losses and mitigates financial impact
Legislative	·Ongoing identification of public policy issues to determine risks to corporation
	·Development of advocacy strategies to address risks
	·Where appropriate, engagement in advocacy at the state/provincial and federal level including joint participation with trade associations
Government trade policy	·Supply chain personnel monitor potential impacts of government trade policy and tariffs on costs for goods used in the normal course of business
Non-controlling interest in pipeline investments	·Invest in pipeline projects where the developer/builder/operator of the projects are experienced companies with a history of successful project completion
	·Engage specialists in reviewing project assumptions
	·Structure investment agreements to provide mitigation for cost overruns
	·Ensure the structure of the project governance requires timely information flow regarding project status
	·In-house regulatory affairs and public policy resources to validate the information from the developer/builder/operator
	·Appropriate internal management structure and processes
External stakeholder relations	·Proactive stakeholder relations and communications groups, strong working relationships with Indigenous peoples, stakeholders, and regulators
	·Strong commitment to creating social value
	·Comprehensive safety and environmental management systems
Risks related to the integration of WGL	·AltaGas has established a cross-functional WGL integration team focused on effectively integrating WGL into AltaGas operations, while eliminating duplicative costs and realizing other efficiencies

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LIQUIDITY

As a result of certain commitments made to the PSC of DC, the PSC of MD, and the SCC of VA in respect of the WGL Acquisition, Washington Gas is subject to certain restrictions when paying dividends to AltaGas. However, AltaGas does not expect that this will have an impact on AltaGas’ ability to meet its obligations.

				Year Ended December 31
($ millions)	2018			2017
Cash from (used in) operations	$	(79	)	$	541
Investing activities	(5,834		)	(495		)
Financing activities	5,987			(38		)
Increase in cash and cash equivalents	$	74		$	8

Cash from Operations

Cash from operations decreased by $620 million for the year ended December 31, 2018 compared to 2017 primarily due to lower net income after taxes and an unfavorable variance in net change in operating assets and liabilities. The unfavorable variance in net change in operating assets and liabilities was primarily due to the addition of WGL’s operating assets and liabilities.

Working Capital

	December 31,			December 31,
($ millions except current ratio)	2018			2017
Current assets	$	4,033		$	702
Current liabilities	4,102			815
Working deficiency	$	(69	)	$	(113	)
Working capital ratio	0.98			0.86

The increase in the working capital ratio was primarily due to an increase in assets held for sale, accounts receivable, inventory, and prepaid expenses, partially offset by an increase in the current portion of long-term debt, increased short-term debt, an increase in accounts payable and accrued liabilities, and an increase in liabilities held for sale of $171 million. AltaGas’ working capital will fluctuate in the normal course of business.

Investing Activities

Cash used in investing activities for the year ended December 31, 2018 was $5.8 billion, compared to cash used in investing activities of $495 million in 2017. Investing activities for the year ended December 31, 2018 primarily included the cash payment of $5.9 billion for the WGL Acquisition, expenditures of approximately $990 million for property, plant and equipment and $38 million for intangible assets, and contributions to equity investments of $235 million, partially offset by proceeds of approximately $859 million from the IPO of ACI, proceeds from the disposition of assets (primarily relating to the San Joaquin facilities) of $404 million, and proceeds of $77 million from the disposition of investments (primarily related to the Tidewater shares). Investing activities for the year ended December 31, 2017 primarily included expenditures of approximately $473 million for property, plant, and equipment and $20 million for intangible assets, approximately $36 million for derivative contracts, approximately $17 million of contributions to AltaGas’ equity investments, and a $13 million loan to Petrogas under the $100 million interest bearing secured loan facility provided to Petrogas, partially offset by cash proceeds of approximately $71 million, net of transaction costs, primarily from the sale of the EDS and JFP transmission assets.

Financing Activities

Cash from financing activities for the year ended December 31, 2018 was $6.0 billion, compared to cash used in financing activities of $38 million in 2017. Financing activities for the year ended December 31, 2018 were primarily comprised of net short and long-term debt issuances of $2.4 billion, net proceeds from the issuance of common shares of $2.6 billion, net borrowings under bankers’ acceptances of $554 million, the proceeds from the sale of the non-controlling interest in the Northwest Hydro facilities of $909 million (net of transaction costs) and contributions from non-controlling interests of $96 million, partially offset by dividends of $540 million. Financing activities for the year ended December 31, 2017 were primarily comprised of repayments of

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long-term debt and short-term debt of $862 million and $74 million, respectively, and dividends of $421 million, partially offset by net proceeds from the issuance of preferred shares of $293 million and common shares of $242 million (mainly from common shares issued through DRIP), net proceeds from the issuance of medium term notes (MTNs) of $447 million, borrowings under the credit facilities of $311 million, and proceeds from the sale of a non-controlling interest in RIPET to Vopak of $24 million. Total dividends paid to common and preferred shareholders of AltaGas for the year ended December 31, 2018 were $540 million (2017 - $421 million), of which $326 million was reinvested through the DRIP (2017 - $236 million). The increase in dividends paid was due to more common shares and preferred shares outstanding and dividend increases on common shares declared in the fourth quarter of 2017.

CAPITAL RESOURCES

AltaGas’ objective for managing capital is to maintain its investment grade credit ratings, ensure adequate liquidity, optimize the profitability of its existing assets and grow its energy infrastructure to create long-term value and enhance returns for its investors. AltaGas’ capital structure is comprised of shareholders’ equity (including non-controlling interests), short-term and long-term debt (including current portion) less cash and cash equivalents.

The use of debt or equity funding is based on AltaGas’ capital structure, which is determined by considering the norms and risks associated with operations and cash flow stability and sustainability.

($ millions)	December 31, 2018			December 31, 2017
Short-term debt	$	1,210		$	47
Current portion of long-term debt	890			189
Long-term debt(1)	8,067			3,437
Total debt	10,167			3,673
Less: cash and cash equivalents	(102		)	(27		)
Net debt	$	10,065		$	3,646
Shareholders’ equity	7,020			4,573
Non-controlling interests	621			66
Total capitalization	$	17,706		$	8,285
Net debt-to-total capitalization (%)	57			44

(1)Net of debt issuance costs of $35 million as at December 31, 2018 (December 31, 2017 - $14 million).

As at December 31, 2018, AltaGas’ total debt primarily consisted of outstanding MTNs of $2.7 billion (December 31, 2017 - $2.9 billion), WGL and Washington Gas long-term debt of $2.7 billion, reflecting fair value adjustments on acquisition (December 31, 2017 - $nil), SEMCO long-term debt of $496 million (December 31, 2017 - $462 million) and $3.0 billion drawn under the bank credit facilities (December 31, 2017 - $260 million). In addition, AltaGas had $271 million of letters of credit (December 31, 2017 - $120 million) outstanding.

As at December 31, 2018, AltaGas’ total market capitalization was approximately $3.8 billion based on approximately 275 million common shares outstanding and a closing trading price on December 31, 2018 of $13.90 per common share.

AltaGas’ earnings interest coverage for the rolling 12 months ended December 31, 2018 was (1.2) times (12 months ended December 31, 2017 — 1.3 times).

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Credit Facilities

			Drawn at		Drawn at
($ millions)	Borrowing capacity		December 31, 2018		December 31, 2017
Demand credit facilities (1) (2)	$	378	$	153	$	75
Extendible revolving letter of credit facilities (2)	559		117		41
PNG operating facility	—		—		13
AltaGas Ltd. revolving credit facility (1)	1,400		965		219
AltaGas Ltd. revolving US$300 million credit facility (1) (2)	409		288		—
Bridge facility (1) (2) (3)	113		113		—
Syndicated US$1,200 million facility (1) (2)	1,637		1,637		—
SEMCO Energy US$150 million unsecured credit facility (1) (2)	205		1		32
WGL US$650 million unsecured revolving credit facility (2)	887		—		—
Washington Gas US$350 million unsecured revolving credit facility (2) (4)	477		—		—
	$	6,065	$	3,274	$	380

(1)Amount drawn at December 31, 2018 converted at the month-end rate of 1 U.S. dollar = 1.3642 Canadian dollar (December 31, 2017 - 1 U.S. dollar = 1.2545 Canadian dollar).

(2)Borrowing capacity was converted at the December 31, 2018 U.S./Canadian dollar month-end exchange rate.

(3)The acquisition credit facility was mostly repaid in the fourth quarter of 2018.

(4)Washington Gas has the right to request additional borrowings of up to US$100 million with the bank’s approval, for a total of US$450 million.

WGL and Washington Gas use short-term debt in the form of commercial paper or unsecured short-term bank loans to fund seasonal cash requirements. Revolving committed credit facilities are maintained in an amount equal to or greater than the expected maximum commercial paper position. At December 31, 2018, commercial paper outstanding totaled US$840 million for WGL and Washington Gas.

All of the borrowing facilities have covenants customary for these types of facilities, which must be met at each quarter end. AltaGas and its subsidiaries have been in compliance with all financial covenants each quarter since the establishment of the facilities.

The following table summarizes the Corporation’s primary financial covenants as defined by the credit facility agreements:

Ratios	Debt covenant requirements	As at December 31, 2018
Bank debt-to-capitalization(1)	not greater than 65 percent	56.5	%
Bank EBITDA-to-interest expense (1) (2)	not less than 2.5x	2.9
Bank debt-to-capitalization (SEMCO)(3)	not greater than 60 percent	36.1	%
Bank EBITDA-to-interest expense (SEMCO)(3)	not less than 2.25x	7.3
Bank debt-to-capitalization (WGL)(4)	not greater than 65 percent	59.4	%
Bank debt-to-capitalization (Washington Gas)(4)	not greater than 65 percent	46.6	%

(1)Calculated in accordance with the Corporation’s US$1.2 billion credit facility agreement, which is available on SEDAR at www.sedar.com. The covenants are equivalent and applicable to all the Corporation’s committed credit facilities.

(2)Estimated, subject to final adjustments.

(3)Bank EBITDA-to-interest expense (SEMCO) and Bank debt-to-capitalization (SEMCO) are calculated based on SEMCO’s consolidated financial statements and are calculated similar to Bank debt-to-capitalization and Bank EBITDA-to-interest expense.

(4)WGL’s bank debt-to-capitalization ratio is calculated based on WGL’s consolidated financial statements.

On September 7, 2017, a $5 billion base shelf prospectus was filed. The purpose of the base shelf prospectus is to facilitate timely offerings of certain types of future public debt and/or equity issuances during the 25-month period that the base shelf prospectus remains effective. As at December 31, 2018, approximately $4.6 billion was available under the base shelf prospectus.

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On June 4, 2018, a US$2 billion preliminary short form prospectus for the issuance of both debt securities and preferred shares was filed in Alberta. AltaGas filed a final short form base shelf prospectus on June 13, 2018 both in Alberta and the U.S. This will enable AltaGas to access the U.S. capital markets during the 25-month period that the base shelf prospectus remains effective. As at December 31, 2018, US$2.0 billion was available under the base shelf prospectus.

CONTRACTUAL OBLIGATIONS

December 31, 2018

	Payments Due by Period
($ millions)	Total		Less than 1 year		1 - 3 years		4 - 5 years		After 5 years
Short-term debt (1)	$	1,210	$	1,210	$	—	$	—	$	—
Long-term debt (1)	8,904		889		3,063		1,593		3,359
Operating leases	302		24		59		54		165
Purchase obligations	54,127		4,626		7,847		6,531		35,123
Capital project commitments	119		119		—		—		—
Pension plan and retiree benefits (2)	42		42		—		—		—
Merger commitments (3)	183		29		54		38		62
Other liabilities	13		11		2		—		—
Total contractual obligations (4)	$	64,900	$	6,950	$	11,025	$	8,216	$	38,709

(1)Excludes interest payments and deferred financing costs.

(2)Assumes only required payments will be made into the pension plans in 2019. Contributions are made in accordance with independent actuarial valuations.

(3)Relates to merger commitments arising from the WGL Acquisition.

(4)U.S. dollar commitments have been converted to Canadian dollar using the December 31, 2018 exchange rate.

AltaGas expects to fund its obligations through internally-generated cash flow, asset sales, the Dividend Reinvestment and Optional Cash Purchase Plan, proceeds from hybrid securities and preferred share offerings, and normal course borrowings on existing committed credit facilities.

RELATED PARTY TRANSACTIONS

In the normal course of business, AltaGas transacts with its subsidiaries, affiliates and joint ventures. Refer to Note 30 of the 2018 Annual Consolidated Financial Statements for the amounts due to or from related parties on the Consolidated Balance Sheets and the classification of revenue, income, and expenses in the Consolidated Statements of Income.

CREDIT RATINGS

On December 19, 2018, Standard & Poor’s (S&P) downgraded AltaGas’ issuer rating and senior unsecured MTN rating from BBB with a Negative Outlook to BBB- with a Negative Outlook and downgraded AltaGas’ Preferred Shares rating from P-3(high) to P-3. On December 21, 2018, DBRS Limited (DBRS) downgraded AltaGas’ rating from BBB Under Review with Developing Implications to BBB(low) with a Stable Outlook and downgraded AltaGas’ Preferred Shares from Pfd-3 to Pfd-3(low). On July 27, 2018, Fitch assigned a first time rating of BBB to AltaGas and a first time rating of BB+ to AltaGas’ Preferred Shares. On December 17, 2018, Fitch affirmed the rating of BBB for AltaGas and BB+ for AltaGas’ Preferred Shares.

According to the S&P rating system, an obligor rated BBB has adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitments. The ratings from AA to CCC may be modified by the addition of a plus (+) or minus (-) sign to show relative standing within the major rating categories. A P-3 rating by S&P is the third highest of eight categories granted by S&P under its Canadian preferred share rating scale and a P-3 rating directly corresponds with a BB rating under its global preferred rating scale. The Canadian preferred share rating scale is fully determined by the global preferred rating scale and there are no additional analytical criteria associated with the determination of ratings on the Canadian preferred share rating scale. According to the S&P rating system, while securities rated P-3 are regarded as having significant speculative characteristics, they are less

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vulnerable to non-payment than other speculative issues. However, it faces major ongoing uncertainties or exposure to adverse business, financial, or economic conditions which could lead to the obligor’s inadequate capacity to meet its financial commitment on the obligation. The ratings from P-1 to P-5 may be modified by “high” and “low” grades which indicate relative standing within the major rating categories.

According to the DBRS rating system, debt securities rated BBB are of adequate credit quality. The capacity for the payment of financial obligations is considered acceptable, but may be vulnerable to future events. “High” or “Low” grades are used to indicate the relative standing within a particular rating category. A Pfd-3 rating by DBRS is the third highest of six categories granted by DBRS. According to the DBRS rating system, preferred shares rated Pfd-3 are of adequate credit quality. While protection of dividends and principal is still considered acceptable, the issuing entity is more susceptible to adverse changes in financial and economic conditions, and there may be other adversities present which detract from debt protection. Pfd-3 ratings normally correspond with companies whose bonds are rated in the higher end of the BBB category. “High” or “Low” grades are used to indicate the relative standing within a rating category. The absence of either a “High” or “Low” designation indicates the rating is in the middle of the category.

According to the Fitch rating system, ‘BBB’ ratings indicate that expectations of default risk are currently low. The capacity for payment of financial commitments is considered adequate, but adverse business or economic conditions are more likely to impair this capacity. A ‘BB’ rating by Fitch indicates an elevated vulnerability to default risk, particularly in the event of adverse changes in business or economic conditions over time; however, business or financial flexibility exists that support the servicing of financial commitments.

The credit ratings accorded to the securities by the rating agencies are not recommendations to purchase, hold, or sell the securities in as much as such ratings do not comment as to market price or suitability for a particular investor. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a rating agency in the future if, in its judgment, circumstances so warrant.

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SHARE INFORMATION

Subscription Receipts

In 2017, the Corporation issued approximately 84.5 million subscription receipts pursuant to a private placement and public offering to partially fund the WGL Acquisition at a price of $31 each for total gross proceeds of approximately $2.6 billion. Each subscription receipt entitled the holder to automatically receive one common share upon closing of the WGL Acquisition. During the time the subscription receipts were outstanding, holders received cash payments (Dividend Equivalent Payments) per subscription receipt that were equal to dividends declared on each common share. The funds were released from escrow on July 5, 2018. Upon closing, the subscription receipts were automatically exchanged for AltaGas common shares in accordance with the terms of the subscription receipt agreement and have been delisted from the TSX.

	As at February 22, 2019
Issued and outstanding
Common shares	275,576,772
Preferred Shares
Series A	5,511,220
Series B	2,488,780
Series C	8,000,000
Series E	8,000,000
Series G	8,000,000
Series I	8,000,000
Series K	12,000,000
WGL $4.25 series	150,000
WGL $4.80 series	70,600
WGL $5.00 series	60,000
Issued
Share options	5,964,758
Share options exercisable	2,593,473

DIVIDENDS

AltaGas declares and pays a monthly dividend to its common shareholders. Dividends on preferred shares are paid quarterly. Dividends are at the discretion of the Board of Directors and dividend levels are reviewed periodically, giving consideration to the ongoing sustainable cash flow from operating activities, maintenance and growth capital expenditures, and debt repayment requirements of AltaGas.

On December 12, 2018, the Board of Directors approved a decrease in the monthly dividend by $0.1025 per common share to $0.08 per common share ($0.96 per common share annualized) effective for the January 2019 dividend.

The following table summarizes AltaGas’ dividend declaration history:

Dividends

Year ended December 31
($ per common share)	2018		2017
First quarter	$	0.547500	$	0.525000
Second quarter	0.547500		0.525000
Third quarter	0.547500		0.525000
Fourth quarter	0.445000		0.540000
Total	$	2.087500	$	2.115000

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Series A Preferred Share Dividends

Year ended December 31
($ per preferred share)	2018		2017
First quarter	$	0.211250	$	0.211250
Second quarter	0.211250		0.211250
Third quarter	0.211250		0.211250
Fourth quarter	0.211250		0.211250
Total	$	0.845000	$	0.845000

Series B Preferred Share Dividends

Year ended December 31
($ per preferred share)	2018		2017
First quarter	$	0.217600	$	0.195410
Second quarter	0.238720		0.195710
Third quarter	0.249530		0.201010
Fourth quarter	0.262770		0.214250
Total	$	0.968620	$	0.806380

Series C Preferred Share Dividends

Year ended December 31
(US$ per preferred share)	2018		2017
First quarter	$	0.330625	$	0.275000
Second quarter	0.330625		0.275000
Third quarter	0.330625		0.275000
Fourth quarter	0.330625		0.330625
Total	$	1.322500	$	1.155625

Series E Preferred Share Dividends

Year ended December 31
($ per preferred share)	2018		2017
First quarter	$	0.312500	$	0.312500
Second quarter	0.312500		0.312500
Third quarter	0.312500		0.312500
Fourth quarter	0.312500		0.312500
Total	$	1.250000	$	1.250000

Series G Preferred Share Dividends

Year ended December 31
($ per preferred share)	2018		2017
First quarter	$	0.296875	$	0.296875
Second quarter	0.296875		0.296875
Third quarter	0.296875		0.296875
Fourth quarter	0.296875		0.296875
Total	$	1.187500	$	1.187500

Series I Preferred Share Dividends

Year ended December 31
($ per preferred share)	2018		2017
First quarter	$	0.328125	$	0.328125
Second quarter	0.328125		0.328125
Third quarter	0.328125		0.328125
Fourth quarter	0.328125		0.328125
Total	$	1.312500	$	1.312500

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Series K Preferred Share Dividends

Year ended December 31
($ per preferred share)	2018		2017
First quarter	$	0.312500	$	—
Second quarter	0.312500		0.438400
Third quarter	0.312500		0.312500
Fourth quarter	0.312500		0.312500
Total	$	1.250000	$	1.063400

In connection with the WGL Acquisition, AltaGas assumed Washington Gas’ preferred stock. Washington Gas has three series of cumulative preferred stock outstanding. Dividends declared from the period from closing of the WGL Acquisition to December 31, 2018 were as follows:

$4.25 series Preferred Share Dividends

Year ended December 31
(US$ per preferred share)	2018		2017
First quarter	$	—	$	—
Second quarter	—		—
Third quarter	1.062500		—
Fourth quarter	1.062500		—
Total	$	2.125000	$	—

$4.80 series Preferred Share Dividends

Year ended December 31
(US$ per preferred share)	2018		2017
First quarter	$	—	$	—
Second quarter	—		—
Third quarter	1.200000		—
Fourth quarter	1.200000		—
Total	$	2.400000	$	—

$5.00 series Preferred Share Dividends

Year ended December 31
(US$ per preferred share)	2018		2017
First quarter	$	—	$	—
Second quarter	—		—
Third quarter	1.250000		—
Fourth quarter	1.250000		—
Total	$	2.500000	$	—

CRITICAL ACCOUNTING ESTIMATES

Since a determination of the value of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of AltaGas’ Consolidated Financial Statements requires the use of estimates and assumptions that have been made using careful judgment. AltaGas’ significant accounting policies are contained in the notes to the 2018 Annual Consolidated Financial Statements. Certain of these policies involve critical accounting estimates as a result of the requirement to make particularly subjective or complex judgments about matters that are inherently uncertain, and because of the likelihood that materially different amounts could be reported under different conditions or using different assumptions.

Significant estimates and judgments made by Management in the preparation of the Consolidated Financial Statements are outlined below:

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Regulatory Assets and Liabilities

SEMCO Gas, ENSTAR and Washington Gas engage in the delivery and sale of natural gas. SEMCO Gas and ENSTAR are regulated by the MPSC and RCA, respectively. Washington Gas is regulated by the PSC of DC in the District of Columbia, the PSC of MD in Maryland, and the SCC of VA in Virginia.

The regulatory agencies exercise statutory authority over matters such as tariffs, rates, construction, operations, financing, returns and certain contracts with customers. In order to recognize the economic effects of the actions and decisions of the regulators, the timing of recognition of certain assets, liabilities, revenues and expenses as a result of regulation may differ from that otherwise expected using U.S. GAAP for entities not subject to rate regulation.

Regulatory assets represent future revenues associated with certain costs incurred in the current period or in prior periods that are expected to be recovered from customers in future periods through the rate-setting process. Regulatory liabilities represent future reductions or limitations of increases in revenue associated with amounts that are expected to be refunded to customers through the rate-setting process.

Asset Impairment

AltaGas reviews long-lived assets and intangible assets with finite lives whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Recoverability is determined based on an estimate of undiscounted cash flows, and measurement of an impairment loss is determined based on the fair value of the assets. The determination of fair value requires Management to make assumptions about future cash inflows and outflows over the life of an asset. Any changes to the assumptions used for the future cash flow could result in revisions to the evaluation of the recoverability of the long-lived assets or intangible assets and the recognition of an impairment loss in the Consolidated Financial Statements.

AltaGas also tests goodwill for impairment annually or more frequently if events or changes in circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying value. The Corporation has the option to first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment test. If the quantitative goodwill impairment test is performed, the fair value of the Corporation’s reporting units is compared to the carrying values. If the carrying value of a reporting unit, including allocated goodwill exceeds its fair value, goodwill impairment is measured as the excess of the carrying value amount of the reporting unit’s allocated goodwill over the implied fair value of the goodwill. The fair value used in the quantitative impairment test of goodwill requires estimating future cash flows as well as appropriate discount rates. AltaGas has assessed goodwill for impairment as at December 31, 2018 and determined that no write-down was required, with the exception of certain goodwill impairments recorded in the third quarter of 2018 as a result of assets held for sale.

Asset Retirement Obligations

AltaGas records liabilities relating to asset retirement obligations when there is a legal obligation. In estimating the obligations, Management is required to make assumptions regarding inflation and discount rates, ultimate amounts and timing of settlements, and expected changes in environmental laws and regulation. A change in any of these estimates could have a material impact on AltaGas’ Consolidated Financial Statements.

Income Taxes

The Corporation is subject to the provisions of the Income Tax Act (Canada) for purposes of determining the amount of income that will be subject to tax in Canada and the Internal Revenue Code (U.S.) for the purposes of determining the amount of income that will be subject to tax in the United States. The determination of AltaGas’ and its subsidiaries’ provision for income taxes requires the application of these complex rules.

Substantial deferred income tax assets and liabilities are recognized in the Consolidated Financial Statements. The recognition of deferred tax assets depends on the assumption that future earnings will be sufficient to realize the deferred benefit. A valuation allowance is recorded against deferred tax assets where all or a portion of that asset is not expected to be realized. The

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amount of the deferred tax asset or liability recorded is based on Management’s best estimate of the timing of the realization of the assets or liabilities.

If Management’s interpretation of tax legislation differs from that of tax authorities, or if timing of reversals is not as anticipated, the provision for income taxes could increase or decrease in future periods. See Note 19 of the 2018 Annual Consolidated Financial Statements.

Pension Plans and Post-Retirement Benefits

The determination of pension plan obligations and expense is based on a number of actuarial assumptions. Critical assumptions include the expected long-term rate-of-return on plan assets, the discount rate applied to pension plan obligations, and the expected rate of compensation increase. For post-retirement benefit plans, which provide for certain health care premiums and life insurance benefits for qualifying retired employees and which are not funded, critical assumptions in determining post-retirement obligations and expense are the discount rate and the assumed health care cost trend rates. Notes 2 and 28 of the 2018 Annual Consolidated Financial Statements include information on the assumptions used for the purposes of recording the funding status of the plans and the associated expenses.

Depreciation and Amortization

Depreciation and amortization of property, plant, and equipment and intangible assets are based on Management’s judgment of the estimated useful life of the assets. When it is determined that assigned asset lives do not reflect the estimated remaining period of benefit, prospective changes are made to the depreciable lives of those assets. For regulated entities, amortization rates are generally prescribed by the applicable regulatory authority. There are a number of uncertainties inherent in estimating the remaining useful life of certain assets and changes in assumptions could result in material adjustments to the amount of amortization that AltaGas recognizes from period to period.

Loss Contingencies

AltaGas and its subsidiaries are subject to various legal claims and actions arising in the normal course of business. Liabilities for loss contingencies are determined on a case-by-case basis and are accrued for when it is probable that a liability has been incurred and the amount can be reasonably estimated. Significant judgement is required to determine the probability of having incurred the liability and the estimated amount. Estimates are reviewed regularly and updated as new information is received.  As at December 31, 2018, no provisions on loss contingencies have been recorded by the Corporation. However, due to the inherent uncertainty of the litigation process, the resolution of any particular contingencies could have a material adverse effect on the Corporation’s results of operations or financial position.

Fair Value of Financial Instruments

Fair value is defined as the amount of consideration that would be agreed upon in an arms-length transaction, other than a forced sale or liquidation, between knowledgeable, willing parties who are under no compulsion to act. The best evidence of fair value is a quoted bid or ask price, as appropriate, in an active market. Fair value based on unadjusted quoted prices in an active market requires minimal judgment by Management. Where bid or ask prices in an active market are not available, Management’s judgment on valuation inputs is necessary to determine fair value. AltaGas enters into physical and financial derivative contracts to manage exposure to fluctuations in commodity prices and foreign exchange rates, as well as to optimize certain owned and managed natural gas assets. AltaGas estimates forward prices based on published sources adjusted for factors specific to the asset or liability, including basis and location differentials, discount rates, and currency exchange. The forward curves used to mark these derivative instruments to market are vetted against public sources. Where observable market data is not available, AltaGas uses valuation techniques which require significant judgment by Management. Changes in estimates and assumptions about these inputs could affect the reported fair value.

ADOPTION OF NEW ACCOUNTING STANDARDS

Effective January 1, 2018, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU):

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·ASU No. 2014-09 “Revenue from Contracts with Customers” and all related amendments (collectively “ASC 606”). AltaGas adopted ASC 606 using the modified retrospective method to contracts that have not been completed as at January 1, 2018. Under the modified retrospective method, the comparative information is not adjusted. The adoption of ASC 606 impacted the timing of revenue recognition in relation to contracts with take-or-pay or minimum volume commitments whereby the customers have make up rights for deficiency quantities. However, on adoption, no cumulative adjustments to opening retained earnings were required for this change in revenue recognition pattern as none of the customers had material deficiency quantities. Please also refer to Note 23 of the Consolidated Financial Statements as at and for the year ended December 31, 2018 for further details. The application of ASC 606 did not have a material impact on AltaGas’ consolidated financial statements in 2018;

·ASU No. 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” which revised an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. It also amended certain disclosure requirements associated with the fair value of financial instruments. Upon adoption, AltaGas reclassified its equity securities with readily determinable fair values from available-for-sale to held for trading. Changes in fair value for equity securities with readily determinable fair values are now recognized through earnings instead of other comprehensive income. As a result, a cumulative-effect adjustment to retained earnings of approximately $7 million was recognized as at January 1, 2018. The remaining provisions of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

·ASU No. 2016-15 “Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments”. The amendments in this ASU clarified the classification of certain cash flow transactions on the statement of cash flow. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

·ASU No. 2016-16 “Income Taxes: Intra-Entity Transfers of Assets Other Than Inventory”. The amendments in this ASU revised the accounting for income tax consequences on intra-entity transfers of assets by requiring an entity to recognize current and deferred tax on intra-entity transfers of assets other than inventory when the transfer occurs. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

·ASU No. 2016-18 “Statement of Cash Flows: Restricted Cash”. The amendments in this ASU required those amounts deemed to be restricted cash and restricted cash equivalents to be included in the cash and cash equivalents balance on the statement of cash flows. The change in presentation of the restricted cash balance on the statement of cash flows was applied on a retrospective basis;

·ASU No. 2017-01 “Business Combinations: Clarifying the Definition of a Business”. The amendments in this ASU changed the definition of a business to assist entities with evaluating when a set of transferred assets and activities is a business. AltaGas will apply the amendments to this ASU prospectively;

·ASU No. 2017-04 “Intangibles — Goodwill and Other: Simplifying the Test for Goodwill Impairment”. The amendments in this ASU removed Step 2 of the goodwill impairment test, eliminating the requirement to determine the fair value of individual assets and liabilities of a reporting unit to measure the goodwill impairment. AltaGas early adopted this ASU and will apply the amendments to this ASU prospectively. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

·ASU No. 2017-05 “Other Income — Gains and Losses from the De-recognition of Nonfinancial Assets: Clarifying the Scope of Asset De-recognition Guidance and Accounting for Partial Sales of Nonfinancial Assets”. The amendments in this ASU clarified the scope of ASC 610-20 as well as the accounting for partial sales of nonfinancial assets. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

·ASU No. 2017-07 “Compensation — Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”. The amendments in this ASU revised the presentation of net periodic

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pension cost and net periodic postretirement benefit cost on the income statement and limited the components that are eligible for capitalization in assets to only the service cost component. AltaGas applied the change in presentation of the current service cost and other components of net benefit cost on the income statement retrospectively. As a result, $1.6 million of net benefit cost associated with other components was reclassified from the line item “Operating and administrative” to “other income” on the Consolidated Statements of Income for the year ended December 31, 2017. AltaGas applied the change related to the capitalization of the service cost prospectively. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

·ASU No. 2017-09 “Compensation — Stock Compensation: Scope of Modifications Accounting”. The amendments in this ASU provided guidance on the types of changes to the terms or conditions of share-based payment arrangements to which an entity would be required to apply modification accounting. The guidance was applied prospectively and did not have a material impact on AltaGas’ consolidated financial statements;

·ASU No. 2017-12 “Derivatives and Hedging — Targeted Improvements to Accounting for Hedging Activities”. The amendments in this ASU improved the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and made certain targeted improvements to simplify the application of hedge accounting. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

·ASU No. 2018-02 “Income Statement — Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”. The amendments in this ASU allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and

·ASU No. 2018-03 “Technical Corrections and Improvements to Financial Instruments — Overall”. The amendments in this ASU clarified certain aspects of the guidance issued in ASU No. 2016-01. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements.

FUTURE CHANGES IN ACCOUNTING PRINCIPLES

In February 2016, FASB issued ASU No. 2016-02 “Leases”, which requires lessees to recognize on the balance sheet a right-of-use asset and a lease liability. Lessor accounting remains substantially unchanged, however, the ASU modifies what qualifies as a sales-type and direct financing lease and eliminates the real estate-specific provisions included in ASC 840. The ASU also requires additional disclosures regarding leasing arrangements. In January 2018, FASB issued ASU 2018-01 “Land Easement Practical Expedient for Transition to Topic 842”, providing entities with an optional election not to evaluate existing and expired land easements not previously accounted for as leases under ASC 840 using the provisions of ASC 842. In July 2018, FASB issued ASU 2018-11 “Targeted Improvements”, allowing entities to report the comparative periods presented in the period of adoption under the previous lease standard (ASC 840), and recognize a cumulative-effect adjustment to the opening balance of retained earnings as of January 1, 2019. The ASU also provides a practical expedient under which lessors are not required to separate out lease and non-lease components of a contract, provided certain conditions are met. In December 2018, FASB issued ASU 2018-20 “Narrow-Scope Improvement for Lessors”, allowing lessors to include and exclude certain costs from variable payments. The ASU also require lessors to allocate certain variable payments to the lease and non-lease components when the changes in facts and circumstances on which the variable payment is based occur. The amendments to the new lease standard are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. AltaGas is in the final stages of evaluating the impact of adopting ASC 842 on its consolidated financial statements. Leases, except as noted below, for which AltaGas is the lessee will be reflected on the balance sheet upon adoption by recording an increase to long-term assets and an increase to long-term liabilities net of the current portion that is recorded in current liabilities. The increases are expected to be less than 1 percent of total assets. AltaGas will utilize the transition practical expedients which allow entities to not have to reassess whether an arrangement contains a lease under the provisions of ASC 842, as well as the transition practical expedients related to land easements and not separating out lease and non-lease components of a contract

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for certain classes of assets. As a result of the transition practical expedients, AltaGas expects to have primarily operating leases on transition consistent with its current conclusions under ASC 840. AltaGas will also elect to exclude leases with terms of 12 months or less from the calculation of lease liabilities and right of use assets under the short term lease exemption.

In June 2016, FASB issued ASU No. 2016-13 “Financial Instruments — Credit Losses: Measurement of Credit Losses on Financial Instruments”. The amendments in this ASU replace the current “incurred loss” impairment methodology with an “expected loss” model for financial assets measured at amortized cost. The amendments in this ASU are effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted. In November 2018, FASB issued ASU No. 2018-19 “Codification Improvements to Topic 326 — Financial Instruments: Credit Losses”. The amendments in the Update align the implementation date for nonpublic entities annual financial statements with the implementation date for their interim financial statements and clarify the scope of the guidance in the amendments in Update 2016-13. The effective date for the amendments in this Update is the same as the effective date in Update 2016-13. AltaGas is currently assessing the impact of this ASU on its consolidated financial statements.

In June 2018, FASB issued ASU No. 2018-07 “Compensation — Stock Compensation: Improvements to Nonemployee Share-Based Payment Accounting”. The amendments in this ASU expand the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees, with the objective of making the measurement consistent with employee share based payment awards. The amendments in this update are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In June 2018, FASB issued ASU No. 2018-08 “Not-for-Profit-Entities — Clarifying the Scope and the Accounting Guidance for Contributions Received and Contributions Made”. The amendments in this Update clarify whether a transfer of assets is a contribution or an exchange transaction. The amendments in this update are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In August 2018, FASB issued ASU No. 2018-13 “Fair Value Measurement — Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurement”. The amendments in this ASU modify the disclosure requirements on fair value measurements. The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In August 2018, FASB issued ASU No. 2018-14 “Compensation — Retirement Benefits-Defined Benefit Plans — General: Disclosure Framework — Changes to the Disclosure Requirements for the Defined Benefit Plans”. The amendments in this ASU modify the disclosure requirements on defined benefit pension and other postretirement plans. The amendments in this update are effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In August 2018, FASB issued ASU No. 2018-15 “Intangibles — Goodwill and Other — Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement (CCA) that is a Service Contract”. The amendments in this ASU align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal use software license). The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted and AltaGas will early adopt this ASU on January 1, 2019. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In October 2018, FASB issued ASU No. 2018-16 “Derivatives and Hedging: Inclusion of the Second Overnight Financing Rate (SOFR) Overnight Index Swap (OIS) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes”. The amendments in this ASU permit the use of Overhead Index Swap (OIS) rate based on SOFR as a U.S. benchmark interest rate for hedge

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accounting purposes. The amendments in this update should be adopted concurrently with ASU 2017-12. AltaGas early adopted ASU 2017-12 on January 1, 2018 and therefore will adopt this update on January 1, 2019. An entity should apply the amendments prospectively for any qualifying new or re-designated cash flow hedging relationships. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In October 2018, FASB issued ASU No. 2018-17 “Consolidation: Targeted Improvements to Related Party Guidance for Variable Interest Entities”. The amendments in this Update provide a private-company scope exception to the VIE guidance for certain entities and clarify that indirect interest held through related parties under common control will be considered on a proportional basis when determining whether fees paid to decision makers and service providers are variable interests. The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. An entity should apply the amendments retrospectively with a cumulative-effect adjustment to retained earnings at the beginning of the earliest period presented. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

OFF-BALANCE SHEET ARRANGEMENTS

AltaGas is not party to any contractual arrangements with unconsolidated entities that have, or are reasonably likely to have, a current or future material effect on the Corporation’s financial performance or financial condition including liquidity and capital resources.

DISCLOSURE CONTROLS AND PROCEDURES (DCP) AND INTERNAL CONTROL OVER FINANCIAL REPORTING (ICFR)

Management, including the Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining DCP and ICFR, as those terms are defined in National Instrument 52-109 “Certification of Disclosure in Issuers’ Annual and Interim Filings”. The objective of this instrument is to improve the quality, reliability, and transparency of information that is filed or submitted under securities legislation.

Management, including the Chief Executive Officer and the Chief Financial Officer, have designed, or caused to be designed under their supervision, DCP and ICFR to provide reasonable assurance that information required to be disclosed by AltaGas in its annual filings, interim filings or other reports to be filed or submitted by it under securities legislation is made known to them, is reported on a timely basis, financial reporting is reliable, and financial statements prepared for external purposes are in accordance with U.S. GAAP.  The Chief Executive Officer and the Chief Financial Officer have evaluated, with the assistance of AltaGas’ employees, the effectiveness of AltaGas’ DCP and ICFR as at December 31, 2018 and concluded that as at December 31, 2018, AltaGas’ DCP and ICFR were effective.

The ICFR has been designed based on the framework established in the 2013 Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

The Chief Executive Officer and Chief Financial Officer of AltaGas have limited the scope of the design of ICFR evaluation to exclude controls, policies, and procedures of all entities acquired in the WGL Acquisition that closed on July 6, 2018, as it has not been possible to conduct an assessment of WGL’s ICFR between such closing and the date of this report. This limitation of scope is in accordance with section 3.3(1)(b) of National Instrument 52-109 as well as relevant SEC guidance, which allows an issuer to limit its assessment of ICFR to exclude controls, policies and procedures of a business that the issuer acquired for a maximum period of 365 days from the end of the financial period in which the acquisition occurred. Summary financial information of WGL included in the audited Consolidated Financial Statements as at and for the year ended December 31, 2018, includes total assets of approximately $14 billion and revenues of approximately $1 billion.

It should be noted that a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues, including instances of fraud, if any, have been

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detected. The design of any system of controls is also based in part on certain assumptions about the likelihood of future events, and there can be no assurances that any design will succeed in achieving its stated goals under all potential conditions.

SUMMARY OF CONSOLIDATED RESULTS FOR THE EIGHT MOST RECENT QUARTERS (1)

($ millions)	Q4-18	Q3-18		Q2-18	Q1-18	Q4-17		Q3-17	Q2-17		Q1-17
Total revenue	1,727	1,041		610	878	745		502	539		771
Normalized EBITDA(2)	394	226		166	223	213		190	166		228
Net income (loss) applicable to common shares	174	(726	)	1	49	(11	)	18	(8	)	32

($ per share)	Q4-18	Q3-18		Q2-18	Q1-18	Q4-17		Q3-17	Q2-17		Q1-17
Net income (loss) per common share
Basic	0.64	(2.78	)	0.01	0.28	(0.06	)	0.10	(0.05	)	0.19
Diluted	0.64	(2.78	)	0.01	0.28	(0.06	)	0.10	(0.05	)	0.19
Dividends declared	0.45	0.55		0.55	0.55	0.54		0.53	0.53		0.53

(1)Amounts may not add due to rounding.

(2)Non-GAAP financial measure. See discussion in the “Non-GAAP Financial Measures” section of this MD&A.

AltaGas’ quarter-over-quarter financial results are impacted by seasonality, fluctuations in commodity prices, weather, the U.S./Canadian dollar exchange rate, planned and unplanned plant outages, timing of in-service dates of new projects, and acquisition and divestiture activities.

Revenue for the Utilities is generally the highest in the first and fourth quarters of any given year as the majority of natural gas demand occurs during the winter heating season, which typically extends from November to March.

Other significant items that impacted quarter-over-quarter revenue during the periods noted include:

·The improved NGL commodity prices in 2017 and 2018;

·The weak Alberta power pool prices throughout 2017;

·The weaker U.S. dollar in the second half of 2017 and the first half of 2018 on translated results of the U.S. assets;

·The seasonally colder weather experienced at several of the utilities in the fourth quarter of 2017 and during 2018;

·The closing of the sale of the EDS and the JFP transmission assets to Nova Chemicals in March of 2017;

·The commencement of commercial operations on October 1, 2017 at Townsend 2A;

·The commencement of commercial operations at the first train of the North Pine Facility on December 1, 2017;

·Losses on risk management contracts recorded in 2017 and the first half of 2018 related to the foreign currency option contracts entered into to mitigate the foreign exchange risks associated with the cash purchase price of WGL;

·The negative impact on revenue of the TCJA at the U.S. utilities throughout 2018;

·Revenue from WGL after the acquisition closed in the third quarter of 2018;

·Revenue from AltaGas’ 50 percent ownership in Black Swan’s Aitken Creek North gas processing facility beginning in the fourth quarter of 2018;

·Lower volumes at the Northwest Hydro facilities during 2018;

·The impact of the sale of non-core U.S. power assets in the fourth quarter of 2018; and

·The impact of the sale of the Canadian utilities to ACI in the fourth quarter of 2018.

57

Net income (loss) applicable to common shares is also affected by non-cash items such as deferred income tax, depreciation and amortization expense, accretion expense, provision on assets, gains or losses on long-term investments, and gains or losses on the sale of assets. In addition, net income (loss) applicable to common shares is also impacted by preferred share dividends. For these reasons, the net income (loss) may not necessarily reflect the same trends as revenue. Net income (loss) applicable to common shares during the periods noted was impacted by:

·Higher depreciation and amortization expense due to new assets placed into service;

·Higher interest expense since the first quarter of 2017 mainly due to higher financing costs associated with the bridge facility;

·The unrealized loss of approximately $8 million recognized upon ceasing to account for the Tidewater investment using the equity method in the second quarter of 2017;

·After-tax provisions totaling $84 million recognized in the fourth quarter of 2017 related to the Hanford and Henrietta gas-fired peaking facilities, a non-core gas processing facility in Alberta, and a non-core development stage peaking project in California;

·Impact of the TCJA resulting in a decrease in tax expense of approximately $34 million in the fourth quarter of 2017;

·After-tax transaction costs incurred throughout 2017 (totaling $53 million) and 2018 ($50 million) predominantly due to the WGL Acquisition;

·After-tax merger commitment costs of $135 million associated with the WGL Acquisition recorded in the second half of 2018;

·The impact of WGL income for the period after the close of the acquisition on July 6, 2018;

·After-tax provisions of approximately $562 million recognized in 2018 primarily related to assets held for sale;

·An income tax recovery of approximately $104 million related to the Northwest Hydro facilities held for sale classification at December 31, 2018;

·The impact of the sale of non-core U.S. power assets in the fourth quarter of 2018; and

·The impact of the sale of the Canadian utilities to ACI in the fourth quarter of 2018.

SELECTED ANNUAL FINANCIAL INFORMATION

($ millions, except where noted)	2018		2017	2016
Revenue	4,257		2,556	2,190
Net income (loss) applicable to common shares	(502	)	30	155
Basic ($ per share)	(2.25	)	0.18	0.99
Diluted ($ per share)	(2.25	)	0.18	0.99
Total assets	23,488		10,032	10,201
Total long-term financial liabilities	8,282		3,596	3,532
Weighted average number of common shares outstanding (millions)	223		171	157
Dividends declared per common share ($ per share)	2.087500		2.115000	2.030000
Preferred share dividends declared ($ per share)
Series A	0.845000		0.845000	0.845000
Series B	0.968620		0.806380	0.786920
Series C	1.322500		1.155625	1.100000
Series E	1.250000		1.250000	1.250000
Series G	1.187500		1.187500	1.187500
Series I	1.312500		1.312500	1.448245
Series K	1.250000		1.063400	—
Washington Gas $4.80 series (US$)	2.400000		—	—
Washington Gas $4.25 series (US$)	2.125000		—	—
Washington Gas $5.00 series (US$)	2.500000		—	—

58

EX-99.1

Exhibit 99.1

Ernst & Young LLP 2200, 215 2nd St SW Calgary, AB T2P 1M4 Tel: +1 403 206 5000 Fax: +1 403 290 4265 ey.com/ca

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the use of our report dated February 27, 2019 with respect to the consolidated financial statements of AltaGas Ltd. as at and for the years ended December 31, 2018 and 2017, included as an appendix in the Annual Report on Form 40-F of AltaGas Ltd. for the year ended December 31, 2018, as filed with the United States Securities Exchange Commission (“SEC”).

We also consent to the incorporation by reference in the Registration Statement on Form F-10 (No. 333-225606) pertaining to the registration of Preferred Shares and Debt Securities of AltaGas Ltd., of our report dated February 27, 2019, with respect to the consolidated financial statements of AltaGas Ltd. as at and for the years ended December 31, 2018 and 2017, included as an appendix in the Annual Report on Form 40-F of AltaGas Ltd. for the year ended December 31, 2018, as filed with the SEC.

We also consent to the reference to us under the heading, “Interest of Experts”, which appears in the annual information form of AltaGas Ltd. for the year ended December 31, 2018 and is included as an appendix in the Annual Report on Form 40-F of AltaGas Ltd. for the year ended December 31, 2018, as filed with the SEC.

Calgary, Alberta	/s/ Ernst & Young LLP
February 27, 2019	Chartered Professional Accountants

A member firm of Ernst & Young Global Limited

EX-99.2

Exhibit 99.2

CERTIFICATION PURSUANT TO RULE 13a-14 OR 15d-14 OF THE

SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Randall L. Crawford, certify that:

1.I have reviewed this annual report on Form 40-F of AltaGas Ltd.

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4.The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, 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 issuer’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 issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5.The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’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 issuer’s internal control over financial reporting.

Date: February 28, 2019

	/s/ Randall L. Crawford
Name:	Randall L. Crawford
Title:	President and Chief Executive Officer

EX-99.3

Exhibit 99.3

CERTIFICATION PURSUANT TO RULE 13a-14 OR 15d-14 OF THE

SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Timothy W. Watson, certify that:

1.I have reviewed this annual report on Form 40-F of AltaGas Ltd.

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4.The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, 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 issuer’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 issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5.The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’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 issuer’s internal control over financial reporting.

Date: February 28, 2019

	/s/ Timothy W. Watson
Name:	Timothy W. Watson
Title:	Executive Vice President and Chief Financial Officer

EX-99.4

Exhibit 99.4

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED
PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of AltaGas Ltd. (the “Company”) on Form 40-F for the fiscal year ended December 31, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Randall L. Crawford, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1.              The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.              The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: February 28, 2019

/s/ Randall L. Crawford
Name:	Randall L. Crawford
Title:	President and Chief Executive Officer

EX-99.5

Exhibit 99.5

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED
PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of AltaGas Ltd. (the “Company”) on Form 40-F for the fiscal year ended December 31, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Timothy W. Watson, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1.              The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.              The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: February 28, 2019

/s/ Timothy W. Watson
Name:	Timothy W. Watson
Title:	Executive Vice President and Chief Financial Officer

XML

Document and Entity Information	12 Months Ended
	Dec. 31, 2018 shares
Document And Entity Information [Abstract]
Document Type	40-F
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Entity Registrant Name	AltaGas Ltd.
Entity Central Index Key	0001695519
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding	275,224,066

XML

Consolidated Balance Sheets - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents (note 31)	$ 101.6	$ 27.3
Accounts receivable, net of allowances (note 22)	1,547.5	382.9
Inventory (note 6)	515.9	201.1
Restricted cash holdings from customers (note 31)	4.1	8.9
Regulatory assets (note 20)	21.0	1.1
Risk management assets (note 22)	114.1	38.6
Prepaid expenses and other current assets (notes 28 and 31)	199.9	36.0
Assets held for sale (note 5)	1,528.9	6.0
Total current assets	4,033.0	701.9
Property, plant and equipment (note 7)	10,929.6	6,689.8
Intangible assets (note 8)	711.9	588.8
Goodwill (notes 9)	4,068.2	817.3
Regulatory assets (note 20)	663.0	328.6
Risk management assets (note 22)	57.7	15.9
Deferred income taxes (note 19)		2.8
Restricted cash holdings from customers (note 31)	6.1	7.5
Prepaid post-retirement benefits (note 28)	342.7
Long-term investments and other assets (notes 11, 22, 28 and 31)	283.1	312.6
Investments accounted for by the equity method (note 13)	2,392.4	567.0
Total assets	23,487.7	10,032.2
Current liabilities
Accounts payable and accrued liabilities (notes 17 and 22)	1,488.2	415.3
Dividends payable (note 22)	22.0	32.0
Short-term debt (notes 14 and 22)	1,209.9	46.8
Current portion of long-term debt (notes 15 and 22)	890.2	188.9
Customer deposits	98.0	30.8
Regulatory liabilities (note 20)	114.9	10.9
Risk management liabilities (note 22)	89.3	57.6
Other current liabilities (note 22)	18.1	32.6
Liabilities associated with assets held for sale (note 5)	171.4	0.3
Total current liabilities	4,102.0	815.2
Long-term debt (notes 15 and 22)	8,066.9	3,436.5
Asset retirement obligations (note 16)	500.6	88.3
Unamortized investment tax credits (note 19)	190.1
Deferred income taxes (note 19)	957.9	444.2
Regulatory liabilities (note 20)	1,392.8	268.6
Risk management liabilities (note 22)	213.0	13.8
Other long-term liabilities (note 17,18 and 22)	122.0	201.9
Future employee obligations (note 28)	302.2	124.5
Total liabilities	15,847.5	5,393.0
Shareholders' equity
Common shares, no par values, unlimited shares authorized; 2018 - 275.2 million and 2017 - 175.3 million issued and outstanding (note 24)	6,653.9	4,007.9
Preferred shares (note 24)	1,318.8	1,277.7
Contributed surplus	373.2	22.3
Accumulated deficit	(1,905.3)	(933.6)
Accumulated other comprehensive income (AOCI) (note 21)	579.0	199.1
Total shareholders' equity	7,019.6	4,573.4
Non-controlling interests	620.6	65.8
Total equity	7,640.2	4,639.2
Total liabilities and shareholders' equity	$ 23,487.7	$ 10,032.2

XML

Consolidated Balance Sheets (Parenthetical) - $ / shares shares in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Consolidated Balance Sheets [Abstract]
Common shares, no par values
Common shares, shares authorized	Unlimited	Unlimited
Common shares issued	275.2	175.3
Common shares outstanding	275.2	175.3

XML

Consolidated Statements of Income (Loss) - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Consolidated Statements of Income (Loss) [Abstract]
Revenue	$ 4,256.7	$ 2,556.2
EXPENSES
Cost of sales, exclusive of items shown separately	2,455.3	1,357.1
Operating and administrative	1,129.0	572.2
Accretion expenses (note 16)	10.9	10.9
Depreciation and amortization (note 7 and 8)	394.0	282.4
Provisions on assets (note 10)	728.7	139.6
Total expenses	4,717.9	2,362.2
Income from equity investments (note 13)	47.9	31.4
Other income (note 26)	0.9	9.6
Foreign exchange gains	4.5	1.7
Interest expense
Short-term debt	(14.0)	(3.7)
Long-term debt	(295.0)	(166.6)
Income (loss) before income taxes	(716.9)	66.4
Income tax expense (recovery) (note 19)
Current	24.4	30.5
Deferred	(287.6)	(64.0)
Net income (loss) after taxes	(453.7)	99.9
Net income (loss) applicable to non-controlling interests	(18.6)	8.3
Net income (loss) applicable to controlling interests	(435.1)	91.6
Preferred share dividends	(66.6)	(61.3)
Net income (loss) applicable to common shares	$ (501.7)	$ 30.3
Net income (loss) per common share (note 25)
Basic	$ (2.25)	$ 0.18
Diluted	$ (2.25)	$ 0.18
Weighted average number of common shares outstanding (millions) (note 25)
Basic	222.6	171.0
Diluted	222.7	171.3

XML

Consolidated Statements of Comprehensive Income (Loss) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Consolidated Statements of Comprehensive Income (Loss) [Abstract]
Net income (loss) after taxes	$ (453.7)	$ 99.9
Other comprehensive income (loss), net of taxes
Gain (loss) on foreign currency translation	458.5	(183.4)
Unrealized gain (loss) on net investment hedge (note 22)	(80.2)	6.6
Actuarial losses on pension plans and post-retirement benefit (PRB) plans (note 28)	(10.8)	(1.0)
Reclassification of actuarial gains and prior service costs on defined benefit (DB) and post-retirement benefit plans (PRB) to net income (note 28)	0.5	0.7
Settlement of PRB plan (note 28)		0.2
Curtailment of DB and PRB plan (note 28)	2.7
Unrealized loss on available-for-sale assets		(26.9)
Adoption of ASU 2016-01 (note 2)	7.1
Other comprehensive income (loss) from equity investees	2.1	(2.2)
Total other comprehensive income (loss) (OCI), net of taxes (note 21)	379.9	(206.0)
Comprehensive loss attributable to controlling interests and non-controlling interests, net of taxes	(73.8)	(106.1)
Comprehensive income (loss) attributable to:
Non-controlling interests	(18.6)	8.3
Controlling interests	$ (55.2)	$ (114.4)

XML

Consolidated Statements of Equity - CAD ($) $ in Millions	Common Stock [Member]	Cumulative Preferred Stock [Member]	Capital In Excess Of Par Value [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Non-controlling Interests [Member]	Total
Balance, beginning of year at Dec. 31, 2016	$ 3,773.4	$ 985.1	$ 17.4	$ (600.4)	$ 405.1	$ 34.8
Adoption of ASU No. 2016-09 | Accounting Standards Update 2016-09 [Member]			1.1
Balance, beginning of year at Dec. 31, 2016	3,773.4	985.1	17.4	(600.4)	405.1	34.8
Shares issued under DRIP	236.3
Shares issued, net		293.4
Deferred taxes on share issuance costs	(8.3)	(0.8)
Share options expense			1.4
Exercise of share options	6.5		(0.5)
Forfeiture of share options			(0.1)
Foreign currency translation gain, net of income taxes							$ (183.4)
Net income (loss) applicable to controlling interests				91.6		8.3	91.6
Common share dividends				(362.4)
Preferred share dividends				(61.3)
Other comprehensive income (loss)					(206.0)		(206.0)
Sale of non-controlling interest (note 4 and 12)			3.0			20.0
Contributions from non-controlling interests to subsidiaries						11.0
Distribution by subsidiaries to non-controlling interests						(8.3)
Balance at end of year at Dec. 31, 2017	4,007.9	1,277.7	22.3	(933.6)	199.1	65.8	4,573.4
Adoption of ASU | Accounting Standards Update 2016-09 [Member]				(1.1)
Total equity							4,639.2
Shares issued under DRIP	325.8
Shares issued, net	2,305.6
Preferred shares acquired through WGL Acquisition (note 24)		41.1
Deferred taxes on share issuance costs	13.3
Shares issued on conversion of subscription receipts, net of issuance costs	2,305.6
Share options expense			0.9
Exercise of share options	1.3		(0.1)
Forfeiture of share options			(0.1)
Foreign currency translation gain, net of income taxes							458.5
Net income (loss) applicable to controlling interests				(435.1)		(18.6)	(435.1)
Common share dividends				(462.9)
Preferred share dividends				(66.6)
Other comprehensive income (loss)					379.9		379.9
Sale of non-controlling interest (note 4 and 12)			350.2			498.4
Contributions from non-controlling interests to subsidiaries						96.3
Distribution by subsidiaries to non-controlling interests						(30.3)
Acquisition of non-controlling interest through WGL Acquistion (note 3)						9.0
Balance at end of year at Dec. 31, 2018	$ 6,653.9	$ 1,318.8	$ 373.2	$ (1,905.3)	$ 579.0	$ 620.6	7,019.6
Total equity							$ 7,640.2

XML

Consolidated Statements of Cash Flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Cash from operations
Net income (loss) after taxes	$ (453.7)	$ 99.9
Items not involving cash:
Depreciation and amortization (note 7 and 8)	394.0	282.4
Provisions on assets (note 10)	728.7	139.6
Accretion expenses (note 16)	10.9	10.9
Share-based compensation (note 24)	0.8	1.3
Deferred income tax recovery (note 19)	(287.6)	(64.0)
Losses on sale of assets (note 4 and 26)	10.6	2.7
Income from equity investments (note 13)	(47.9)	(31.4)
Unrealized losses (gains) on risk management contracts (note 22)	(80.8)	62.5
Realized loss on expiry of foreign exchange options (note 22)	36.0
Losses (gains) on investments (note 26)	10.1	(3.6)
Amortization of deferred financing costs	29.7	16.9
Provision of doubtful accounts	17.0
Net change in pension and other post retirement benefits (note 28)	(3.8)
Other	3.6	(4.1)
Asset retirement obligations settled (note 16)	(4.2)	(4.0)
Distributions from equity investments	44.5	30.2
Changes in operating assets and liabilities (note 31)	(486.5)	1.9
Net cash provided (required) by operating activities	(78.6)	541.2
Investing activities
Business acquisitions, net of cash acquired (note 3)	(5,931.0)
Acquisition of property, plant and equipment	(990.4)	(473.0)
Acquisition of intangible assets	(38.1)	(20.3)
Acquisition of investment in a publicly traded entity		(7.0)
Contributions to equity investments	(235.4)	(16.8)
Loan to affiliate, net of repayment (note 30)	30.0	(12.5)
Financing receivable	(8.7)
Proceeds from disposition of investments (note 11)	76.5
Proceeds from IPO of ACI (note 4)	858.9
Payment for derivative contracts		(36.0)
Proceeds from disposition of assets, net of transaction costs (note 4)	403.8	70.6
Net cash provided (required) by investing activities	(5,834.4)	(495.0)
Financing activities
Net issuance (repayment) of short-term debt	497.7	(74.2)
Issuance of long-term debt, net of debt issuance costs	3,595.2	758.1
Repayment of long-term debt	(1,729.5)	(861.6)
Net issuance of bankers' acceptances	553.6
Dividends - common shares	(472.9)	(359.6)
Dividends - preferred shares	(66.6)	(61.3)
Distributions to non-controlling interest	(30.3)	(8.3)
Contributions from non-controlling interests	96.3	11.0
Net proceeds from shares issued on exercise of options	1.2	6.0
Net proceeds from issuance of common shares	2,633.7	236.3
Net proceeds from issuance of preferred shares		293.4
Net proceeds from sale of non-controlling interest (notes 4 and 12)	908.6	24.1
Other		(1.9)
Net cash provided (required) by financing activities	5,987.0	(38.0)
Change in cash, cash equivalents and restricted cash	74.0	8.2
Effect of exchange rate changes on cash, cash equivalents and restricted cash	7.3	1.4
Net change in cash classified within assets held for sale (note 5)	(4.9)
Restricted cash acquired (note 31)	81.0
Cash, cash equivalents and restricted cash beginning of year	43.7	34.1
Cash, cash equivalents and restricted cash end of year (note 31)	$ 201.1	$ 43.7

XML

ORGANIZATION AND OVERVIEW OF THE BUSINESS

12 Months Ended

Dec. 31, 2018

ORGANIZATION AND OVERVIEW OF THE BUSINESS [Abstract]

ORGANIZATION AND OVERVIEW OF THE BUSINESS

1.  ORGANIZATION AND OVERVIEW OF THE BUSINESS

The businesses of AltaGas are operated by AltaGas and a number of its subsidiaries including, without limitation, AltaGas Services (U.S.) Inc., AltaGas Utility Holdings (U.S.) Inc., WGL Holdings Inc. (WGL), Wrangler 1 LLC, Wrangler SPE LLC, Washington Gas Resources Corporation, WGL Energy Services, Inc., and SEMCO Holding Corporation; in regards to the Midstream business, AltaGas Extraction and Transmission Limited Partnership, AltaGas Pipeline Partnership, AltaGas Processing Partnership, AltaGas Northwest Processing Limited Partnership, Harmattan Gas Processing Limited Partnership, and WGL Midstream Inc.; in regards to the Power business, AltaGas Power Holdings (U.S.) Inc., WGSW, Inc., WGL Energy Systems, Inc., and Blythe Energy Inc. (Blythe); and, in regards to the Utility business, Washington Gas Light Company, Hampshire Gas Company, and SEMCO Energy, Inc. (SEMCO). SEMCO conducts its Michigan natural gas distribution business under the name SEMCO Energy Gas Company (SEMCO Gas) and its Alaska natural gas distribution business under the name ENSTAR Natural Gas Company (ENSTAR).

AltaGas, a Canadian corporation, is a leading North American clean energy infrastructure company with strong growth opportunities and a focus on owning and operating assets to provide clean and affordable energy to its customers. The Corporation’s long-term strategy is to grow in attractive areas across its Utility, Midstream, and Power business segments seeking optimal capital deployment. In the Midstream business, the Corporation is focused on optimizing the full value chain of energy exports by providing producers with solutions, including global market access off both coasts of North America via the Corporation’s footprint in two of the most prolific gas plays – the Montney and Marcellus. To optimize capital deployment, the Corporation seeks to invest in U.S utilities located in strong growth markets with increasing construction to support customer additions, system improvement and accelerated replacement programs. In the Power business, AltaGas seeks to create innovative solutions with light capital investment utilizing the Corporation’s clean energy expertise. AltaGas has three business segments:

· Utilities, which serves approximately 1.6 million customers with a rate base of approximately US$3.7billion through ownership of regulated natural gas distribution utilities across five jurisdictionsin the United States, and two regulated natural gas storage utilities in the United States, delivering clean and affordable natural gas to homes and businesses. The Utilities business also includes storage facilities and contracts for interstate natural gas transportation and storage services;

· Midstream, which, subsequent to the sale of non-core midstream assets in Canada that closed in February 2019, transacts more than 1.5 Bcf/d of natural gas and includes natural gas gathering and processing, natural gas liquids (NGL) extraction and fractionation, transmission, storage, natural gas and NGL marketing, the Corporation’s 50 percent interest in AltaGas Idemitsu Joint Venture Limited Partnership (AIJVLP), an indirectly held one-third ownership investment in Petrogas Energy Corp. (Petrogas), through which AltaGas’ interest in the Ferndale Terminal is held, an interest in four regulated pipelines in the Marcellus/Utica gas formation in northeast United States and WGL’s retail gas marketing business; and

· Power, which, subsequent to the sale of non-core power assets in Canada that closed in February 2019, and the sale of the remaining 55 percent interest in the Northwest Hydro facilities which closed in January 2019, includes 1,105MW of gross capacity from natural gas-fired, biomass, solar, other distributed generation and energy storage assets located in Alberta, Canada and 20 states and the District of Columbia in the United States. The Power business also includes energy efficiency contracting and WGL’s retail power marketing business.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2018

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

BASIS OF PRESENTATION

These Consolidated Financial Statements have been prepared by Management in accordance with United States Generally Accepted Accounting Principles (U.S. GAAP).

Pursuant to National Instrument 52-107, "Acceptable Accounting Principles and Auditing Standards" (NI 52-107), financial statements of an “SEC issuer” may be prepared in accordance with U.S. GAAP. On July 13, 2018, AltaGas filed a final short form base shelf prospectus in Alberta and a corresponding registration statement on Form F-10 in the United States, by virtue of which AltaGas is now required to file reports under section 15(d) of the Securities Exchange Act of 1934 with the United States Securities and Exchange Commission. As a result, AltaGas became an SEC issuer at such time and is now entitled to prepare its financial statements in accordance with U.S. GAAP.

PRINCIPLES OF CONSOLIDATION

These Consolidated Financial Statements of AltaGas include the accounts of the Corporation, its subsidiaries, variable interest entities (VIEs) for which the Corporation is the primary beneficiary, and its interest in various partnerships and joint ventures where AltaGas has an undivided interest in the assets and liabilities. Investments in unconsolidated companies that AltaGas has significant influence over, but not control, are accounted for using the equity method.

Hypothetical Liquidation at Book Value (HLBV) methodology is used for certain WGL equity method investments as well as WGL consolidating equity investments with non-controlling interests when the governing structuring agreement over the equity investment results in different liquidation rights and priorities than what is reflected by the underlying ownership interest percentage.

All intercompany balances and transactions are eliminated on consolidation. Where there is a party with a non-controlling interest in a subsidiary that AltaGas controls, that non-controlling interest is reflected as “non-controlling interests” in the Consolidated Financial Statements. The non-controlling interests in net income (or loss) of consolidated subsidiaries are shown as an allocation of the consolidated net income and are presented separately in "net income applicable to non-controlling interests".

USE OF ESTIMATES AND MEASUREMENT UNCERTAINTY

The preparation of Consolidated Financial Statements in accordance with U.S. GAAP requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenue and expenses during the period. Key areas where Management has made complex or subjective judgments, when matters are inherently uncertain, include but are not limited to: determining the nature and timing of satisfaction of performance obligations and determining the transaction price and amounts allocated to performance obligations for revenue recognition; depreciation and amortization rates, fair value of asset retirement obligations, fair value of property, plant and equipment and goodwill for impairment assessments, fair value of financial instruments, provisions for income taxes, assumptions used to measure employee future benefits, provisions for contingencies, and carrying value of regulatory assets and liabilities. Certain estimates are necessary for the regulatory environment in which AltaGas' subsidiaries or affiliates operate, which often require amounts to be recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. By their nature, these estimates are subject to measurement uncertainty and may impact the Consolidated Financial Statements of future periods.

SIGNIFICANT ACCOUNTING POLICIES

Rate-Regulated Operations

SEMCO Gas, ENSTAR, Washington Gas, and Hampshire (collectively Utilities) engage in the delivery, sale, and storage of natural gas. SEMCO Gas and ENSTAR are regulated by the Michigan Public Service Commission (MPSC) and Regulatory Commission of Alaska (RCA), respectively. Washington Gas operates in the District of Columbia, Maryland, and Virginia and is regulated in those jurisdictions by the Public Service Commission of the District of Columbia (PSC of DC), the Maryland Public Service Commission (PSC of MD) and the Commonwealth of Virginia State Corporation Commission (SCC of VA), respectively.  

The MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA exercise statutory authority over matters such as tariffs, rates, construction, operations, financing, returns, accounting and certain contracts with customers. In order to recognize the economic effects of the actions and decisions of the MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA, the timing of recognition of certain assets, liabilities, revenues and expenses as a result of regulation may differ from that otherwise expected using U.S. GAAP for entities not subject to rate regulation. 

Regulatory assets represent future revenues associated with certain costs incurred in the current period or in prior periods that are expected to be recovered from customers in future periods through the rate setting process. Regulatory liabilities represent future reductions or limitations of increases in revenue associated with amounts that are expected to be refunded to customers through the rate setting process.

Cash and Cash Equivalents

Cash and cash equivalents consist of cash on hand, balances with banks, and investments in money market instruments with original maturities of less than three months.

Restricted Cash Holdings from Customers

Cash deposited, which is restricted and is not available for general use by AltaGas, is separately presented as restricted cash holdings in the Consolidated Balance Sheets. Pursuant to the acquisition of WGL Holdings, Inc. (the WGL Acquisition), rabbi trust funds were funded to satisfy certain WGL executive and outside director retirement benefit plan obligations. As of December 31, 2018, the rabbi trust funds are invested in money market funds which are considered as cash equivalents. These balances are included in prepaid expenses and other current assets and long-term investments and other assets in the Consolidated Balance Sheets.    

Accounts Receivable

Receivables are recorded net of the allowance for doubtful accounts in the Consolidated Balance Sheets. AltaGas regularly analyzes and evaluates the collectability of the accounts receivable based on a combination of factors. If circumstances related to the collectability change, the allowance for doubtful accounts is further adjusted. Accounts are written off when collection efforts are complete and future recovery is unlikely.

Inventory

Inventory consists of materials, supplies, natural gas, renewable energy credits, and emission compliance instruments which are valued at the lower of cost or net realizable value. Cost of inventory is assigned using a weighted average cost formula. In general, commodity costs and variable transportation costs are capitalized as gas in underground storage. Fixed costs, primarily pipeline demand charges and storage charges, are expensed as incurred through the cost of gas.

Property, Plant, and Equipment (PP&E), Depreciation and Amortization

Property, plant, and equipment are carried at cost. The Corporation depreciates the cost of capital assets, net of salvage value, on a straight-line basis over the estimated useful life of the assets, with the exception of rate regulated utilities assets, where depreciation is calculated on a straight-line basis or over the contract term of a specific agreement at rates as approved by the regulatory authorities. 

The U.S. utilities charge maintenance and repairs directly to operating expense and capitalize betterments and renewal costs. In accordance with regulatory requirements, depreciation expense includes an amount allowed for regulatory purposes to be collected in current rates for future removal and site restoration costs.

Interest costs are capitalized on major additions to property, plant, and equipment until the asset is ready for its intended use. The interest rate used for calculating the interest costs to be capitalized is based on AltaGas' prior quarter actual borrowing long-term interest rate.

Utilities capitalize an imputed carrying cost on assets during construction as authorized by regulatory authorities and the amount so capitalized is an allowance for funds used during construction (AFUDC). AFUDC is the amount that a rate regulated enterprise is allowed to recover for its cost of financing assets under construction. Capitalized overhead, administrative expenses and AFUDC are included in the cost of the related assets and are recovered in rates charged to customers through depreciation expense, as allowed by the regulators.

The range of useful lives for AltaGas’ PP&E is as follows:

Utilities assets	3-80 years
Midstream assets	3-45 years
Power generation assets	2-120 years
Corporate assets	1 - 20 years

As required by the regulatory authority, net additions to SEMCO's utility assets are amortized for one half year in the year in which they are brought into active service. Net additions to WGL’s assets are amortized in the month they are brought into active service.

Generally, when a regulated asset is retired or disposed of, there is no gain or loss recorded in the Consolidated Statement of Income. Any difference between the cost and accumulated depreciation of the asset, net of salvage proceeds, is charged to accumulated depreciation or another regulatory asset or liability account. It is expected that any gain or loss that is charged to accumulated depreciation or another regulatory account will be reflected in future depreciation expense when it is refunded or collected in rates. When a non-regulated asset is retired or disposed of from PP&E, the original cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in the Consolidated Statement of Income.

Leases are classified as either capital or operating. Leases that transfer substantially all the benefits and risks of ownership of property to AltaGas are accounted for as capital leases.

Intangible Assets

Intangible assets are recorded at cost. Intangible assets which have a finite useful life are amortized on a straight-line basis over their term or estimated useful life. The range of useful lives for intangible assets with a finite life is as follows:

Energy services relationships	5-19 years
Electricity service agreements	2 - 60 years
Software	3-10 years
Land rights	5-64 years
Franchises and consents	9-25 years
Extraction and Transmission (E&T) Contracts	25 years
Commodity contracts	5 years

The intangible assets recorded in the purchase price allocation for certain WGL commodity contracts are amortized based on the estimated fair value of the deliveries over the term of the contracts, which are over a period of 20 years. 

Assets Held for Sale

The Corporation classifies assets as held for sale when the carrying amount will be recovered through a sale transaction rather than through continuing use. This condition is met when Management approves and commits to a formal plan to sell the assets, the assets are available for immediate sale in their present condition, and Management expects the sale to close within the next 12 months. Upon classifying an asset as held for sale, an asset is recorded at the lower of its carrying value or the estimated fair value less cost to sell. Assets held for sale are not depreciated or amortized.

Business Acquisitions

Business acquisitions are accounted for using the acquisition method. Under the acquisition method, assets and liabilities of the acquired entity are recorded at fair value at the date of acquisition. Acquisition-related costs are expensed as incurred. Goodwill represents the excess of purchase price over the fair value of the net assets acquired.

Provisions on Assets

If facts and circumstances suggest that a long-lived asset or an intangible asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset is not recoverable, as determined by the projected undiscounted cash flows related to the asset over its remaining life, then the carrying value of the asset is reduced to its estimated fair value and an impairment loss is recognized.

Goodwill is not subject to amortization, but assessed at least annually for impairment, or more often when events or changes in circumstances indicate that goodwill may be impaired. The annual assessment of goodwill is performed at the reporting unit level, which is an operating segment or one level below. The Corporation has the option to first assess qualitative factors to determine whether events or changes in circumstances indicate that the goodwill may be impaired. If a quantitative impairment test is performed, the fair value of the reporting unit will be compared to its carrying value (including goodwill). If the carrying value of the reporting unit exceeds the fair value, goodwill is reduced to its fair value and an impairment loss would be recorded in the Consolidated Statement of Income.

Development Costs

AltaGas expenses development costs as incurred unless such development costs meet certain criteria related to technical, market, regulatory and financial feasibility for capitalization. Development costs are examined annually to ensure capitalization criteria continue to be met. When the criteria that previously justified the deferral of costs are no longer met, the unamortized balance is taken as a charge to income in the period when this determination is made. Development costs are amortized based on the expected period of benefit, beginning at the commencement of commercial operations.

Investments Accounted for by the Equity Method

The equity method of accounting is used for investments in which AltaGas has the ability to exercise significant influence, but does not have a controlling interest. Equity investments are initially measured at cost and are adjusted for the Corporation’s proportionate share of earnings or losses. Equity investments are increased for contributions made and decreased for distributions received. To the extent an investee undertakes activities necessary to commence its planned principal operations, the Corporation will capitalize interest costs associated with its investment during such period.

The HLBV methodology is used to allocate earnings or losses for certain WGL equity method investments when WGL’s ownership interest percentage is different than distribution percentages. When applying HLBV accounting, the Corporation determines the amount that it would receive if an equity investment entity were to liquidate all of its assets at book value (as valued in accordance with U.S. GAAP) and distribute that cash to the investors based on the contractually defined liquidation priorities. The change in the Corporation’s claim on the equity investment entity's book value at the beginning and end of the reporting period (adjusted for contributions and distributions) is the Corporation’s share of the earnings or losses from the equity investment for the period.

An equity method investment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the investment may not be recoverable. When such condition is deemed other than temporary, the carrying value of the investment is written down to its fair value, and an impairment charge is recorded in the Consolidated Statement of Income.

Financial Instruments

Non-Utility Operations

All financial instruments are initially recorded at fair value unless they qualify for, and are designated under, a normal purchase and normal sale (NPNS) exemption. Subsequent measurement of the financial instruments is based on their classification. The financial assets are classified as "held-for-trading", "held-to-maturity", or "loans and receivables". Financial liabilities are classified as "held-for-trading" or other financial liabilities. Subsequent measurement is determined by classification. 

A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to AltaGas’ business needs and AltaGas has the ability, and intent, to deliver or take delivery of the underlying item. AltaGas continually assesses the contracts designated under the NPNS exemption and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met.

Held-for-trading instruments include non-derivative financial assets and financial assets and liabilities that may consist of swaps, options, forwards and equity securities. These financial instruments are initially recorded at their fair value, with subsequent changes in fair value recorded in net income. Held-to-maturity, loans and receivables, and other financial liabilities are recognized at amortized cost using the effective interest method unless they are held-for-sale and recognized at the lower of cost or fair value less transaction fees. 

Investments in equity instruments not accounted for under the equity method that do not have a quoted market price in an active market are measured at cost. Income earned from these investments is included in the Consolidated Statement of Income under "other income".

Derivatives embedded in other financial instruments or contracts (the host instrument) are recorded separately and are measured at fair value if the economic characteristics of the embedded derivative are not closely related to the host instrument, the terms of the embedded derivative are the same as those of a standalone derivative and the entire contract is not held-for-trading or accounted for at fair value. Changes in fair value are included in earnings.

The fair values recorded on the Consolidated Balance Sheets reflect netting of the asset and liability positions where counterparty master netting arrangements contain provisions for net settlement.

Transaction costs related to the acquisition of held-for-trading financial assets and liabilities are expensed as incurred. 

Transaction costs for obtaining debt financing other than line-of-credit arrangements are recognized as a direct deduction from the related debt liability on the Consolidated Balance Sheets. Transaction costs related to line-of-credit arrangements are capitalized and included under "long-term investments and other assets" on the Consolidated Balance Sheets. Premiums and discounts are netted against long-term debt on the Consolidated Balance Sheets. The deferred charges are amortized over the life of the related debt on an effective interest basis and included in “interest expense” on the Consolidated Statement of Income.

Regulated Utility Operations

All physical and financial derivative contracts are initially recorded at fair value. Changes in the fair value of derivative instruments that are recoverable or refunded to customers when they settle are recorded as regulatory assets or liabilities. Changes in the fair value of derivatives not affected by rate regulation are reflected in net income.

Weather-Related Instruments

WGL purchases certain weather-related instruments, such as heating degree day (HDD) derivatives and cooling degree day (CDD) derivatives to manage weather and price risks related to its natural gas and electricity sales. These derivatives are accounted for in accordance with ASC 815-45, Derivatives and Hedging – Weather Derivatives. For HDD derivatives, gains or losses are recognized when the actual HDD’s falls above or below the contractual HDD’s for each instrument. For CDD derivatives, gains or losses are recognized when the average temperature exceeds or is below a contractually stated level during the contract period. Refer to Note 22for further discussion on weather-related instruments.  

Hedges

As part of its risk management strategy, AltaGas may use derivatives to reduce its exposure to commodity price, interest rate and foreign exchange risk. AltaGas has designated certain U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. No other derivatives have been designated as hedges under ASC Topic 815.

Non-Utility Operations

The change in fair value of cash flow hedges is recognized in OCI. Gains or losses from cash flow hedges are reclassified to net income when the hedged transaction affects earnings, such as when the hedged forecasted transaction occurs.

Regulated Utility Operations

During planned issuances of debt securities, Washington Gas may utilize derivative instruments to manage the risk of interest-rate volatility. Gains and losses associated with these types of derivatives are recorded as regulatory liabilities or assets, and amortized in accordance with regulatory requirements, typically over the life of the related debt.  

Asset Retirement Obligations

AltaGas recognizes asset retirement obligations in the period in which the legal obligation is incurred and a reasonable estimate of fair value can be determined. The associated asset retirement costs are capitalized as part of the carrying amount of the asset and are depreciated over the estimated useful life of the asset. The liability is increased due to the passage of time over the estimated period until the settlement of the obligation, with a corresponding charge to accretion expense for asset retirement obligations.

There are timing differences between accretion and depreciation amounts being recorded pursuant to GAAP and the recognition of depreciation expense for legal asset removal costs that are recovered in rates, as allowed by the regulators. These timing differences are recorded as a reduction to “regulatory liabilities” in accordance with ASC 980.

Certain utility assets will have future legal obligations on retirement, but an asset retirement obligation has not been recorded due to its indeterminate life and corresponding indeterminable timing and scope of these asset retirement obligations. The U.S. Utilities recognize asset retirement obligations for some interim retirements, as expected by their regulators.

Revenue Recognition

AltaGas has revenue from various sources, including rate regulated revenue, commodity sales, midstream service contracts, gas sales and transportation services, and gas storage services. For a detailed description of the Corporation’s revenue recognition policy by major source of revenue, please refer to Note 23.

Foreign Currency Translation

Monetary assets and liabilities denominated in a foreign currency are converted to the functional currency using the exchange rate in effect at the balance sheet date. Adjustments resulting from the conversion are recorded in the Consolidated Statement of Income. Non-monetary assets and liabilities are converted at the historical exchange rate in effect at the transaction date. Revenues and expenses are converted at the exchange rate applicable at the transaction date.

For foreign entities with a functional currency other than Canadian dollars, AltaGas’ reporting currency, assets, and liabilities are translated into Canadian dollars at the rate in effect at the reporting date. Revenues and expenses are translated at average exchange rates during the reporting period. All adjustments resulting from the translation of the foreign operations are recorded in OCI.

AltaGas may designate some of its U.S. dollar denominated long-term debt as a foreign currency hedge of its investment in foreign operations. Accordingly, foreign exchange gains and losses, from the dates of designation, on the translation of the U.S. dollar denominated long-term debt are included in OCI.

Share Options and Other Compensation Plans

Share options granted are recorded using fair value. Compensation expense is measured at the date of the grant using the Black-Scholes-Merton model and is recognized over the vesting period of the options. Consideration received by AltaGas on exercise of the share options is credited to shareholders’ equity.

AltaGas has a medium-term incentive plan (MTIP) for employees and executive officers which includes two types of awards: restricted units (RUs) and performance units (PUs). A portion of AltaGas’ RUs and PUs are valued based on the dividends declared during the vesting period and the weighted average share price of AltaGas' common shares multiplied by the units outstanding at the end of the vesting period. Upon vesting, the RUs and PUs are paid in cash or, at the election of AltaGas, its equivalent in common shares purchased from the market. The other portion of RU’s and PSUs are valued at US$1 per unit. Upon vesting, the RUs and PSUs are paid in cash. All PUs are also subject to a performance multiplier ranging from 0 to 2 dependent on the Corporation's performance relative to performance targets agreed between the Corporation and the employees. Compensation expense is recognized using the liability method and is recorded as operating and administrative expense over the vesting period. A change in value of the RUs or PUs is recognized in the period the change occurs.

In addition, AltaGas has a deferred share unit plan (DSUP) for directors, officers and employees as an additional form of long-term variable compensation incentive. Although the DSUP is available to directors, officers and employees, AltaGas currently only grants deferred share units (DSUs) under the DSUP as a form of director compensation. The DSUs granted are fully vested upon being credited to a participant’s account, and the participant is entitled to payment at his or her termination date, and payment is not subject to satisfaction of any requirements as to any minimum period of membership or employment or other conditions. DSUs are accounted for at fair value. Compensation expense is determined based on the fair value of the DSUs on the date of the grant and fluctuations in fair value are recognized in the period the change occurs.

Pension Plans and Post-Retirement Benefits

AltaGas maintains defined benefit pension plans, defined contribution plans, and other post-retirement benefit plans for eligible employees. Contributions made by the Corporation to the defined contribution plans are expensed in the period in which the contribution occurs.

The cost of defined benefit pension plans and post-retirement benefits is actuarially determined using the projected benefit method prorated based on service and Management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected health care costs. Pension plan assets are measured at fair value. The expected return on plan assets is based on historical and projected rates of return for each asset class in the plan portfolio. The projected benefit obligation is discounted using the market interest rate on high-quality debt instruments with cash flows matching the timing and amount of benefit payments. Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation and the fair value of plan assets or the market-related value of assets along with any unamortized past service costs are amortized on a straight-line basis over the expected average remaining service life of active employees. The expected average remaining service period of the active members covered by the defined benefit pension plans and post-retirement benefit plans is 9.6 years and 14.1 years, respectively.

AltaGas recognizes the overfunded or underfunded status of its pension and post-retirement benefit plans as either assets or liabilities in the Consolidated Balance Sheets. Unrecognized actuarial gains and losses and past service costs and credits that arise during the period are recognized in OCI or a regulatory asset or liability.

For certain regulated utilities, the Corporation expects to recover pension expense in future rates and therefore records unrecognized balances as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the expected average remaining service life of active employees.

Income Taxes

Income taxes for the Corporation and its subsidiaries are calculated using the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are determined based on differences between the carrying value and the tax basis of assets and liabilities and are measured using the enacted tax rates and laws that are in effect in the periods in which the differences are expected to be settled or realized. Deferred income tax assets are routinely reviewed and a valuation allowance is recorded to reduce the deferred tax assets if it is more likely than not that deferred tax assets will not be realized. The financial statement effects of an uncertain tax position are recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxing authority. The current and deferred tax impact is equal to the largest amount, considering possible settlement outcomes, that is greater than 50 percent likely of being realized upon settlement with the taxing authorities.

Investment tax credits are recognized as reductions to income tax expense over the estimated service lives of the related properties.

The rate-regulated natural gas distribution subsidiaries recognize a separate regulatory asset or liability for the amount of deferred income taxes expected to be recovered from, or paid to, customers in the future. 

Net Income per Share

Basic net income per common share is computed using the weighted average number of common shares outstanding during the period. Dilutive net income per common share is calculated using the weighted average number of common shares outstanding adjusted for dilutive common shares related to the Corporation’s share-based compensation awards.

The potentially dilutive impact of the share-based compensation awards is determined using the treasury stock method. Under the treasury stock method, awards are treated as if they had been exercised with any proceeds used to repurchase common stock at the average market price during the period. Any incremental difference between the assumed number of shares issued and purchased is included in the diluted share computation. 

Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Any such accruals are adjusted thereafter as additional information becomes available or circumstances change.

ADOPTION OF NEW ACCOUNTING STANDARDS

Effective January 1, 2018, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU):

· ASU No. 2014-09 “Revenue from Contracts with Customers” and all related amendments (collectively “ASC 606”).  AltaGas adopted ASC 606 using the modified retrospective method to contracts that have not been completed as at January 1, 2018. Under the modified retrospective method, the comparative information is not adjusted. The adoption of ASC 606 impacted the timing of revenue recognition in relation to contracts with take-or-pay or minimum volume commitments whereby the customers have make up rights for deficiency quantities. However, on adoption, no cumulative adjustments to opening retained earnings were required for this change in revenue recognition pattern as none of the customers had material deficiency quantities. Please also refer to Note 23 for further details. The application of ASC 606 did not have a material impact on AltaGas’ consolidated financial statements in 2018;

· ASU No. 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” which revised an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. It also amended certain disclosure requirements associated with the fair value of financial instruments. Upon adoption, AltaGas reclassified its equity securities with readily determinable fair values from available-for-sale to held for trading. Changes in fair value for equity securities with readily determinable fair values are now recognized through earnings instead of other comprehensive income. As a result, a cumulative-effect adjustment to retained earnings of approximately $7 million was recognized as at January 1, 2018. The remaining provisions of this ASU did not have a material impact on AltaGas’ consolidated financial statements; 

· ASU No. 2016-15 “Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments”. The amendments in this ASU clarified the classification of certain cash flow transactions on the statement of cash flow.  The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

· ASU No. 2016-16 “Income Taxes: Intra-Entity Transfers of Assets Other Than Inventory”. The amendments in this ASU revised the accounting for income tax consequences on intra-entity transfers of assets by requiring an entity to recognize current and deferred tax on intra-entity transfers of assets other than inventory when the transfer occurs. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

· ASU No. 2016-18 “Statement of Cash Flows: Restricted Cash”. The amendments in this ASU required those amounts deemed to be restricted cash and restricted cash equivalents to be included in the cash and cash equivalents balance on the statement of cash flows. The change in presentation of the restricted cash balance on the statement of cash flows was applied on a retrospective basis;

· ASU No. 2017-01 “Business Combinations: Clarifying the Definition of a Business”. The amendments in this ASU changed the definition of a business to assist entities with evaluating when a set of transferred assets and activities is a business. AltaGas will apply the amendments to this ASU prospectively;

· ASU No. 2017-04 “Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment”. The amendments in this ASU removed Step 2 of the goodwill impairment test, eliminating the requirement to determine the fair value of individual assets and liabilities of a reporting unit to measure the goodwill impairment. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

· ASU No. 2017-05 “Other Income – Gains and Losses from the De-recognition of Nonfinancial Assets: Clarifying the Scope of Asset De-recognition Guidance and Accounting for Partial Sales of Nonfinancial Assets”. The amendments in this ASU clarified the scope of ASC 610-20 as well as the accounting for partial sales of nonfinancial assets. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

· ASU No. 2017-07 “Compensation – Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”. The amendments in this ASU revised the presentation of net periodic pension cost and net periodic postretirement benefit cost on the income statement and limited the components that are eligible for capitalization in assets to only the service cost component. AltaGas applied the change in presentation of the current service cost and other components of net benefit cost on the income statement retrospectively. As a result, $1.6 million of net benefit cost associated with other components were reclassified from the line item “operating and administrative” to “other income” on the Consolidated Statements of Income for the year ended December 31, 2017. AltaGas applied the change related to the capitalization of the service cost prospectively. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

· ASU No. 2017-09 “Compensation – Stock Compensation: Scope of Modifications Accounting”. The amendments in this ASU provided guidance on the types of changes to the terms or conditions of share-based payment arrangements to which an entity would be required to apply modification accounting. The guidance was applied prospectively and did not have a material impact on AltaGas’ consolidated financial statements;

· ASU No. 2017-12 “Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities”. The amendments in this ASU improved the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and made certain targeted improvements to simplify the application of hedge accounting. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

· ASU No. 2018-02 “Income Statement – Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”. The amendments in this ASU allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act (TCJA). AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and

· ASU No. 2018-03 “Technical Corrections and Improvements to Financial Instruments – Overall”. The amendments in this ASU clarified certain aspects of the guidance issued in ASU No. 2016-01. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements.

FUTURE CHANGES IN ACCOUNTING PRINCIPLES

In February 2016, FASB issued ASU No. 2016-02 “Leases”, which requires lessees to recognize on the balance sheet a right-of-use asset and a lease liability. Lessor accounting remains substantially unchanged, however, the ASU modifies what qualifies as a sales-type and direct financing lease and eliminates the real estate-specific provisions included in ASC 840. The ASU also requires additional disclosures regarding leasing arrangements. In January 2018, FASB issued ASU 2018-01 “Land Easement Practical Expedient for Transition to Topic 842”, providing entities with an optional election not to evaluate existing and expired land easements not previously accounted for as leases under ASC 840 using the provisions of ASC 842. In July 2018, FASB issued ASU 2018-11 “Targeted Improvements”, allowing entities to report the comparative periods presented in the period of adoption under the previous lease standard (ASC 840), and recognize a cumulative-effect adjustment to the opening balance of retained earnings as of January 1, 2019. The ASU also provides a practical expedient under which lessors are not required to separate out lease and non-lease components of a contract, provided certain conditions are met. In December 2018, FASB issued ASU 2018-20 “Narrow-Scope Improvement for Lessors”, allowing lessors to include and exclude certain costs from variable payments. The ASU also require lessors to allocate certain variable payments to the lease and non-lease components when the changes in facts and circumstances on which the variable payment is based occur. The amendments to the new lease standard are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. AltaGas is in the final stages of evaluating the impact of adopting ASC 842 on its consolidated financial statements. Leases, except as noted below, for which AltaGas is the lessee will be reflected on the balance sheet upon adoption by recording an increase to long-term assets and an increase to long-term liabilities net of the current portion that is recorded in current liabilities. The increases are expected to be less than 1 percent of total assets. AltaGas will utilize the transition practical expedients which allow entities to not have to reassess whether an arrangement contains a lease under the provisions of ASC 842, as well as the transition practical expedients related to land easements and not separating out lease and non-lease components of a contract for certain classes of assets. As a result of the transition practical expedients, AltaGas expects to have primarily operating leases on transition consistent with its current conclusions under ASC 840. AltaGas will also elect to exclude leases with terms of 12 months or less from the calculation of lease liabilities and right of use assets under the short term lease exemption.

In June 2016, FASB issued ASU No. 2016-13 “Financial Instruments – Credit Losses: Measurement of Credit Losses on Financial Instruments”. The amendments in this ASU replace the current “incurred loss” impairment methodology with an “expected loss” model for financial assets measured at amortized cost. The amendments in this ASU are effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted. AltaGas is currently assessing the impact of this ASU on its consolidated financial statements.

In June 2018, FASB issued ASU No. 2018-07 “Compensation – Stock Compensation: Improvements to Nonemployee Share-Based Payment Accounting”. The amendments in this ASU expand the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees, with the objective of making the measurement consistent with employee share based payment awards. The amendments in this update are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In June 2018, FASB issued ASU No. 2018-08 “Not-for-Profit-Entities – Clarifying the Scope and the Accounting Guidance for Contributions Received and Contributions Made”. The amendments in this Update clarify whether a transfer of assets is a contribution or an exchange transaction. The amendments in this update are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In August 2018, FASB issued ASU No. 2018-13 “Fair Value Measurement – Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurement”. The amendments in this ASU modify the disclosure requirements on fair value measurements. The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In August 2018, FASB issued ASU No. 2018-14 “Compensation – Retirement Benefits-Defined Benefit Plans – General: Disclosure Framework – Changes to the Disclosure Requirements for the Defined Benefit Plans”. The amendments in this ASU modify the disclosure requirements on defined benefit pension and other postretirement plans. The amendments in this update are effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In August 2018, FASB issued ASU No. 2018-15 “Intangibles – Goodwill and Other – Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement (CCA) that is a Service Contract”. The amendments in this ASU align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal use software license). The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted and AltaGas will early adopt this ASU on January 1, 2019. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In October 2018, FASB issued ASU No. 2018-16 “Derivatives and Hedging: Inclusion of the Second Overnight Financing Rate (SOFR) Overnight Index Swap (OIS) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes”. The amendments in this ASU permit the use of Overhead Index Swap (OIS) rate based on SOFR as a U.S. benchmark interest rate for hedge accounting purposes. The amendments in this update should be adopted concurrently with ASU 2017-12. AltaGas early adopted ASU 2017-12 on January 1, 2018 and therefore will adopt this update on January 1, 2019. An entity should apply the amendments prospectively for any qualifying new or re-designated cash flow hedging relationships. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In October 2018, FASB issued ASU No. 2018-17 “Consolidation: Targeted Improvements to Related Party Guidance for Variable Interest Entities”. The amendments in this Update provide a private-company scope exception to the VIE guidance for certain entities and clarify that indirect interest held through related parties under common control will be considered on a proportional basis when determining whether fees paid to decision makers and service providers are variable interests. The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. AN entity should apply the amendments retrospectively with a cumulative-effect adjustment to retained earnings at the beginning of the earliest period presented Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements

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ACQUISITION OF WGL HOLDINGS INC.

12 Months Ended

Dec. 31, 2018

ACQUISITION OF WGL HOLDINGS INC. [Abstract]

ACQUISITION OF WGL HOLDINGS INC.

3.  ACQUISITION OF WGL HOLDINGS INC.

Following the receipt of all required federal, state, and local regulatory approvals, on July 6, 2018 the Corporation acquired WGL for an aggregate purchase price of approximately $9.3 billion (US$7.1 billion), including the assumption of approximately $3.3 billion (US$2.5 billion) of debt and $41 million (US$31 million) of preferred shares.

Under the terms of the transaction, WGL shareholders received US$88.25 per common share. The net cash consideration was approximately $6.0 billion (US$4.6 billion). The WGL Acquisition was financed through net proceeds of approximately $2.3 billion from the sale of subscription receipts, draws on the fully committed acquisition credit facility of $3.0 billion (US$2.3 billion) and existing cash on hand. The draws on the acquisition credit facility included additional amounts for the payment of fees and regulatory commitments related to the WGL Acquisition. The sale of the subscription receipts was completed in the first quarter of 2017 and upon closing of the WGL Acquisition, the subscription receipts were exchanged into approximately 84.5 million common shares of AltaGas.

The WGL Acquisition is accounted for as a business combination using the acquisition method of accounting whereby the acquired assets and assumed liabilities are recorded at their estimated fair values at the date of acquisition. The excess of purchase price over estimated fair values of assets acquired and liabilities assumed is recognized as goodwill at the acquisition date.

The following table summarizes the purchase price allocation representing the consideration paid and the fair value of the net assets acquired as at July 6, 2018 using an exchange rate of 1.31 to convert U.S. dollars to Canadian dollars. The purchase price allocation is provisional and reflects Management’s current best estimate of the fair value of WGL’s assets and liabilities based on the analysis of information obtained to date. Management is continuing to obtain specific information to support the evaluation of fixed assets, goodwill and deferred income taxes for certain elements of the acquired business. As the additional information becomes available, the purchase price allocation may differ from the preliminary purchase price allocation below. Any adjustments to the purchase price allocation will be made as soon as practicable but no later than one year from the date of acquisition.

The following table summarizes the estimated fair values that were assigned to the net assets of WGL at the date of acquisition:

Purchase consideration	$	5,973
Fair value assigned to net assets
Current assets	$	1,187
Property, plant and equipment		5,943
Intangible assets		637
Regulatory assets		402
Long-term investments		1,411
Other long-term assets		449
Current liabilities		(1,798)
Long-term debt		(2,548)
Preferred shares		(41)
Regulatory liabilities		(1,125)
Deferred income taxes		(772)
Other long-term liabilities		(959)
Non-controlling interest		(9)
Fair value of net assets acquired	$	2,777
Goodwill	$	3,196

The fair value of property, plant and equipment was estimated using the valuation methodologies described in ASC 820, Fair Value Measurements and Disclosures, to value the property, plant and equipment purchased. The fair value of WGL’s rate regulated property, plant and equipment is determined using a market participant perspective, which is equal to the carrying amount. The preliminary fair values of the remaining non-regulated property, plant and equipment is determined using both the income and cost approaches and resulted in an estimated fair value decrease relative to carrying value of approximately $92million related to solar distributed generation assets.

Long-term investments include WGL’s 55 percent equity investment in Meade Pipeline Co. LLC. (Meade), a 10 percent equity interest in Mountain Valley Pipeline LLC, and a 30 percent equity interest in Stonewall Gas Gathering Systems LLC. Meade owns 39 percent of Central Penn, and WGL owns a 21 percent indirect net interest in Central Penn. The preliminary fair value of these investments has been determined using an income approach, resulting in an estimated fair value increase of approximately $464 million.

Intangible assets consist of customer relationships, contracts relating to gas transportation capacity, and natural gas purchase and sale agreements for energy exports. The preliminary fair value of these assets is determined using an income approach, resulting in an estimated fair value of approximately $637 million.

The fair value of current assets and current liabilities approximate their carrying values due to their short-term nature.

The fair value of long-term debt was estimated based on the quoted market prices of the U.S. Treasury issues having a similar term to maturity, adjusted for the credit quality of the debt issuer, WGL or Washington Gas Light Company. This resulted in a fair value increase of approximately $87 million, with a corresponding regulatory offset.

Deferred income tax assets and liabilities have been applied on the cumulative amount of tax applicable to temporary differences between the accounting and tax values of assets and liabilities.

The preliminary purchase price allocation includes goodwill of approximately $3.2 billion. The goodwill is primarily related to the investment in low risk, long-life rate regulated assets, opportunities to grow the gas midstream business, expanded access to capital and greater financial flexibility as a result of increased scale, and earnings diversification. The goodwill recognized as part of this transaction is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to this goodwill.

Pre-tax acquisition expenses and merger commitment costs for the year ended December 31, 2018 of approximately $237.2 million were incurred and included in the Consolidated Statements of Income (2017 – $65.7 million).

Upon completion of the WGL Acquisition, AltaGas began consolidating WGL. Since the closing date through December 31, 2018, WGL has generated approximately $1,406 million in revenues and $113 million in net loss after tax. The loss was primarily due to the payment of various regulatory commitments as well as seasonality in certain of WGL’s operating businesses.

The following supplemental unaudited, pro forma consolidated financial information for the years ended December 31, 2018 and 2017 gives effect to the WGL Acquisition as if it had closed on January 1, 2017. This pro forma information is presented for information purposes only and does not purport to be indicative of the results that would have occurred had the WGL Acquisition taken place at the beginning of 2017, nor is it indicative of the results that may be expected in future periods.

	Year ended December 31
	2018		2017
Pro forma revenue	$	5,962	$	5,704
Pro forma net income (loss) after taxes	$	(304)	$	450

Pro forma revenue excludes the gains and losses on foreign exchange contracts, as these contracts were used to mitigate the foreign exchange risks associated with the cash purchase price of WGL. As such, the gains and losses on these foreign exchange contracts are directly incremental to the WGL Acquisition and are non-recurring in nature. These adjustments increased pro forma revenue by $2 million for the year ended December 31, 2018, and increased pro forma revenue by $34 million for the year ended December 31, 2017.

Pro forma net income (loss) after taxes excludes all non-recurring acquisition-related expenses and merger commitment costs incurred by AltaGas and WGL and AltaGas’ realized and unrealized gains and losses on foreign exchange contracts entered into to mitigate the foreign exchange risk associated with the WGL Acquisition. Pro forma net income (loss) after taxes was also adjusted to exclude financing costs associated with the bridge facility for the WGL Acquisition, and amortization of fair value adjustments relating to property, plant and equipment, intangible assets, and other long-term investments as well as tax impacts of all the previously noted adjustments. For the year ended December 31, 2018, the total after-tax pro forma adjustments increased net income (loss) after taxes by $132 million (2017 – $19million).

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SALE OF MINORITY INTEREST AND OTHER DISPOSITIONS

12 Months Ended

Dec. 31, 2018

Sale of Minority Interest and Other Dispositions [Member]

Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]

SALE OF MINORITY INTEREST AND OTHER DISPOSITIONS AND ASSETS HELD FOR SALE

4. SALE OF MINORITY INTEREST AND OTHER DISPOSITIONS

Northwest Hydro Facilities

On June 22, 2018, AltaGas completed the disposition of a 35 percent indirect equity interest in the Northwest Hydro facilities for gross cash proceeds of approximately $921.6 million. The disposition was completed through the sale of 35 percent of Northwest Hydro Limited Partnership (NW Hydro LP), a subsidiary of AltaGas which indirectly holds the Northwest Hydro facilities. At December 31, 2018, AltaGas continues to consolidate NW Hydro LP (Note 12). Upon close of the sale, AltaGas recognized a non-controlling interest of $420.4 million, a deferred income tax liability of $153.3 million and contributed surplus of $335.2 million on the Consolidated Balance Sheets, net of transaction costs. There was no impact to the Consolidated Statements of Income upon closing of this transaction. 

On December 13, 2018, AltaGas announced that it reached an agreement for the sale of its remaining interest of approximately 55 percent in the Northwest Hydro facilities. The sale was completed in January 2019 (Notes5 and 33).

Initial Public Offering of AltaGas Canada Inc.

On October 25, 2018, the initial public offering (IPO) of AltaGas Canada Inc. (ACI) was successfully completed, reflecting a final price of $14.50 per common share of ACI. The over-allotment option was exercised in full, and as a result, AltaGas holds approximately 37 percent of ACI common shares at December 31, 2018. Net proceeds to AltaGas (consisting of cash and debt) to AltaGas after the deduction of underwriting fees and expenses were approximately $892.2million. ACI holds Canadian rate-regulated natural gas distribution utility assets and contracted wind power in Canada, as well as an approximate 10 percent indirect equity interest in the Northwest Hydro facilities.

In addition to a pre-tax provision of $193.7 million, AltaGas recognized a pre-tax loss on disposition of $0.5 million in the Consolidated Statement of Income under the line item “other income”  for the year ended December 31, 2018.

Non-Core San Joaquin Power Assets in California

On November 13, 2018, AltaGas completed the disposition of the San Joaquin facilities for a sale price of approximately US$299.4 million. The assets comprise the Tracy, Hanford and Henrietta plants totaling 523 MW of capacity. In addition to a pre-tax provision of $340.6 million, AltaGas recognized a pre-tax loss on disposition of $14.4 million in the Consolidated Statements of Income under the line item “other income” for the year ended December 31, 2018.

Other U.S. Power Assets

On December 11, 2018, AltaGas completed the disposition of Busch Ranch, a wind asset in the United States, for a sale price of approximately US$16.3 million. AltaGas recognized a pre-tax gain on disposition of $3.2 million in the Consolidated Statements of Income under the line item “other income”  for the year ended December 31, 2018.

Other Dispositions

In March 2018, AltaGas completed the disposition of the Acme and Shaunavon gas processing facilities in the Midstream segment for gross proceeds of approximately $7.0 million. As a result, AltaGas recognized a pre-tax gain on disposition of approximately $1.3 million in the Consolidated Statements of Income under the line item “other income” for the year ended December 31, 2018.

In March 2017, AltaGas completed the disposition of the Ethylene Delivery Systems (EDS) and the Joffre Feedstock Pipeline (JFP) transmission assets in the Midstream segment to Nova Chemicals Corporation for gross proceeds of approximately $67.0 million. AltaGas recognized a pre-tax loss on disposition of approximately $3.4 million in the Consolidated Statement of Income under the line item “other income” for the year ended December 31, 2017 related to this disposition.

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ASSETS HELD FOR SALE

12 Months Ended

Dec. 31, 2018

Assets Held for Sale [Member]

Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]

SALE OF MINORITY INTEREST AND OTHER DISPOSITIONS AND ASSETS HELD FOR SALE

5.  ASSETS HELD FOR SALE

As at	December 31, 2018		December 31, 2017
Assets held for sale
Cash	$	4.9	$	—
Accounts receivable		85.2		0.3
Inventory		0.5		—
Property, plant and equipment		1,189.6		5.3
Intangible assets		248.7		0.1
Goodwill		—		0.3
	$	1,528.9	$	6.0
Liabilities associated with assets held for sale
Accounts payable and accrued liabilities	$	23.8	$	—
Asset retirement obligations		10.8		0.3
Other long-term liabilities		136.8		—
	$	171.4	$	0.3

Non-Core Midstream and Power Assets in Canada

In the third quarter of 2018, AltaGas entered into definitive agreements for the sale of selected non-core smaller scale gas midstream and power assets in Canada, as well as AltaGas’ commercial and industrial customer portfolio in Canada, for an aggregate purchase price of approximately $165.0 million. The transaction is subject to customary closing conditions and approvals, and was completed in February 2019. Accordingly, the carrying value of the assets and liabilities was classified as held for sale, which resulted in the reclassification of assets totaling $102.1 million to assets held for sale and liabilities totaling $10.8 million to liabilities associated with assets held for sale on the Consolidated Balance Sheets. Pre-tax provisions of $121.4 million on property, plant and equipment, $0.5 million on intangible assets, and $5.1 million on goodwillwere recognized in 2018 due to the reduction of the carrying value of the assets to fair value less costs to sell. These assets are recorded in the Midstream and Power segments.

The transaction also includes the 43.7 million shares of Tidewater Midstream and Infrastructure Inc. previously held by AltaGas. This portion of the transaction was completed in September 2018 (Note 11).

Northwest Hydro Facilities

On December 13, 2018, AltaGas announced that it has reached an agreement for the sale of its remaining indirect equity interest of approximately 55 percent in the Northwest Hydro facilities for proceeds of approximately $1.37 billion. The transaction was completed in January 2019. Accordingly, the carrying value of the assets and liabilities was classified as held for sale, which resulted in the reclassification of $1,350.2 million of assets to assets held for sale and $160.6 million of liabilities to liabilities associated with assets held for sale on the Consolidated Balance Sheets. These assets are recorded in the Power segment.

Included within liabilities associated with assets held for sale is the Northwest Hydro NTL liability. In 2010, AltaGas entered into a 60-year CPI-indexed Electricity Purchase Agreement (EPA) and other related agreements with BC Hydro for the 195-MW Forrest Kerr run-of-river hydroelectric facility. As part of the related agreements, AltaGas agreed to pay BC Hydro annual payments of approximately $11.0 million per year, adjusted for inflation, in support of the construction and operation of the Northwest Transmission Line (NTL) until 2034. With the agreement for the sale of AltaGas’ remaining indirect equity interest in the Northwest Hydro facilities, this liability has been reclassified to liabilities associated with assets held for sale.

Architect of the Capitol (AOC) Project

In the fourth quarter of 2018, WGL Energy Systems reached an agreement for the sale of a financing receivable related to the construction of an energy management services project. The transaction is subject to customary closing conditions, and is expected to be completed in the first quarter of 2019. Accordingly, the carrying value of the asset was classified as held for sale, which resulted in the reclassification of $76.6 million of accounts receivable to assets held for sale on the Consolidated Balance Sheets. A pre-tax provision of $6.0 million was recognized in 2018 due to the reduction of the carrying value of the receivable to fair value less costs to sell. This asset is recorded in the Power segment.    

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INVENTORY

12 Months Ended

Dec. 31, 2018

INVENTORY [Abstract]

INVENTORY

6.  INVENTORY

	December 31,		December 31,
As at	2018		2017
Natural gas held in storage	$	418.0	$	133.9
Materials and supplies		53.3		32.3
Renewable energy credits and emission compliance instruments		38.2		28.4
Other inventory		6.4		6.5
	$	515.9	$	201.1

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PROPERTY, PLANT AND EQUIPMENT

12 Months Ended

Dec. 31, 2018

PROPERTY, PLANT AND EQUIPMENT [Abstract]

PROPERTY, PLANT AND EQUIPMENT

7.  PROPERTY, PLANT AND EQUIPMENT

As at	December 31, 2018						December 31, 2017
	Cost		Accumulated amortization		Net book value		Cost		Accumulated amortization		Net book value
Utilities	$	7,090.5	$	(89.7)	$	7,000.8	$	2,245.4	$	(226.1)		2,019.3
Midstream		3,178.2		(845.7)		2,332.5		2,801.4		(636.3)	$	2,165.1
Power		4,633.9		(1,858.3)		2,775.6		2,874.8		(392.3)		2,482.5
Corporate		49.4		(39.1)		10.3		65.9		(37.7)		28.2
Reclassified to assets held for sale (note 5)		(2,999.3)		1,809.7		(1,189.6)		(16.7)		11.4		(5.3)
	$	11,952.7	$	(1,023.1)	$	10,929.6	$	7,970.8	$	(1,281.0)	$	6,689.8

Interest capitalized on long-term capital construction projects for the year ended December 31, 2018was $12.6 million (2017 - $10.8 million). 

As at December 31, 2018, the Corporation had approximately $872.7million (December 31, 2017 - $269.5 million) of capital projects under construction that were not yet subject to amortization.

Depreciation expense related to property, plant and equipment (including assets under capital leases) for the year ended December 31, 2018 was $324.3 million (2017 - $239.7 million).

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INTANGIBLE ASSETS

12 Months Ended

Dec. 31, 2018

PROVISIONS ON ASSETS, INTANGIBLE ASSETS AND GOODWILL [Abstract]

INTANGIBLE ASSETS

8.  INTANGIBLE ASSETS

As at	December 31, 2018						December 31, 2017
	Cost		Accumulated amortization		Net book value		Cost		Accumulated amortization		Net book value
E&T contracts	$	26.6	$	(14.3)	$	12.3	$	26.6	$	(13.4)	$	13.2
Electricity service agreements		269.5		(25.9)		243.6		603.1		(108.5)		494.6
Energy services relationships		176.1		(33.8)		142.3		10.2		(8.1)		2.1
Software		293.9		(77.7)		216.2		126.8		(61.6)		65.2
Land rights		1.4		(0.2)		1.2		11.0		(2.4)		8.6
Commodity contracts		346.3		(6.3)		340.0		—		—		—
Franchises and consents		5.0		—		5.0		7.4		(2.2)		5.2
Reclassified to assets held for sale (note 5)		(277.4)		28.7		(248.7)		(0.1)		—		(0.1)
	$	841.4	$	(129.5)	$	711.9	$	785.0	$	(196.2)	$	588.8

Amortization expense related to intangible assets for the year ended December 31, 2018was $69.7 million (2017 - $42.7 million).

As at December 31, 2018, the Corporation excluded $196.4 million (December 31, 2017 - $11.2 million) from the asset base subject to amortization. Items excluded related to gas transportation capacity contracts, software assets under development, and assets with an indefinite life.

The following table sets forth the estimated amortization expense of intangible assets, excluding any amortization of assets not yet subject to amortization as well as assets with an indefinite life, for the years ended December 31:

2019	$	84.2
2020	$	82.5
2021	$	57.6
2022	$	132.3
2023	$	38.3
Thereafter	$	120.6

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GOODWILL

12 Months Ended

Dec. 31, 2018

PROVISIONS ON ASSETS, INTANGIBLE ASSETS AND GOODWILL [Abstract]

GOODWILL

9.  GOODWILL

	December 31,		December 31,
As at	2018		2017
Balance, beginning of year	$	817.3	$	856.0
Provisions on assets (notes 5 and 10)		(124.2)		—
Business acquisition (note 3)		3,196.4		—
Foreign exchange translation		178.7		(38.4)
Reclassified to assets held for sale		—		(0.3)
Balance, end of year	$	4,068.2	$	817.3

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PROVISIONS ON ASSETS

12 Months Ended

Dec. 31, 2018

PROVISIONS ON ASSETS, INTANGIBLE ASSETS AND GOODWILL [Abstract]

PROVISIONS ON ASSETS

10.  PROVISIONS ON ASSETS

Year ended December 31	2018		2017
Utilities	$	193.7	$	—
Midstream		153.7		6.6
Power		381.3		133.0
	$	728.7	$	139.6

Utilities

In 2018, AltaGas recorded pre-tax provisions of $193.7 million related to certain rate-regulated natural gas distribution utility assets that were classified as held for sale in the third quarter of 2018. The pre-tax provision was comprised of $119.1 million on goodwill and $74.6 million on property, plant and equipment. No provisions on assets were recorded in 2017 for the Utilities segment.

Midstream

In 2018, AltaGas recorded pre-tax provisions totaling $153.7 million in the Midstream segment. The pre-tax provisions included $117.2 million related to certain non-core midstream assets that are classified as held for sale at December 31, 2018 (Note 5) and $36.5 million related to shut-in assets in the South, Cold Lake and Northwest operating areas. The total pre-tax provisions of $153.7 million were comprised of $148.1 million on property, plant, and equipment, $0.5 million on intangible assets, and $5.1 million on goodwill.

In 2017, AltaGas recorded a pre-tax provision on assets of $6.6 million on a non-core gas processing facility that was classified as held for sale (Note 5).

Power

In 2018, AltaGas recorded pre-tax provisions totaling $381.3 million in the Power segment. Of this, $340.6 million related to the Tracy, Hanford, and Henrietta gas-fired peaking plants in California that were disposed of in November 2018. The pre-tax provision on the California power assets was comprised of $221.3 million on property, plant, and equipment and $119.3 million on intangible assets. In addition, pre-tax provisions of $9.8 million were recorded on certain non-core power assets in Canada that are classified as held for sale at December 31, 2018 (Note 5),  $23.1 million on a development project in the U.S., $1.8 million on the Pomona natural gas-fired co-generation facility in the United States, and $6.0 million on a WGL Energy Systems financing receivable that was classified as held for sale at December 31, 2018 (Note 5).

In 2017, AltaGas recognized pre-tax provisions on assets related to the Hanford and Henrietta gas-fired peaking plants in California, certain non-core development stage gas-fired peaking projects in California, and the Kent development project in Alberta of $133.0 million. The pre-tax provisions of $133.0 million were comprised of $48.5 million on intangible assets and $84.5 million on property, plant and equipment.

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LONG-TERM INVESTMENTS AND OTHER ASSETS

12 Months Ended

Dec. 31, 2018

LONG-TERM INVESTMENTS AND OTHER ASSETS [Abstract]

LONG-TERM INVESTMENTS AND OTHER ASSETS

11.  LONG-TERM INVESTMENTS AND OTHER ASSETS

As at	December 31, 2018		December 31, 2017
Investments in publicly-traded entities	$	8.4	$	95.0
Loan to affiliate (note 30)		45.0		75.0
Deferred lease receivable		24.4		29.0
Debt issuance costs associated with credit facilities		7.9		20.3
Refundable deposits		16.2		14.9
Prepayment on long-term service agreements		82.5		68.1
Subscription receipts issuance costs		—		1.7
Contract asset (note 23)		11.5		—
Rabbi trust (note 28)		61.7		—
Other		25.5		8.6
	$	283.1	$	312.6

In 2018, as part of the agreement for the sale of non-core midstream and power assets in Canada, AltaGas sold 43.7 million shares of Tidewater Midstream and Infrastructure Inc. for gross proceeds of $63.4 million. For the year ended December 31, 2018, a realized loss of $2.0 million was recognized in the Consolidated Statements of Income under the line item “other income” in relation to the sale of these shares.

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VARIABLE INTEREST ENTITIES

12 Months Ended

Dec. 31, 2018

VARIABLE INTEREST ENTITIES [Abstract]

VARIABLE INTEREST ENTITIES

12. VARIABLE INTEREST ENTITIES

Consolidated VIEs

AltaGas consolidates VIEs where the Corporation is deemed the primary beneficiary. The primary beneficiary of a VIE has the power to direct the activities of the entity that most significantly impact its economic performance such as being the provider of construction, operating and marketing services to the entity. In addition, the primary beneficiary of a VIE also has the obligation to absorb losses of the entity or the right to receive benefits that could potentially be significant to the VIE. AltaGas determined that it is the primary beneficiary of the following VIEs:

Northwest Hydro Limited Partnership

On May 4, 2018, NW Hydro LP was formed to indirectly hold the assets of the Northwest Hydro facilities. On June 22, 2018, AltaGas closed the sale of a 35 percent indirect equity interest in its Northwest Hydro facilities through the sale of 35 percent of NW Hydro LP, and its general partner, Northwest Hydro GP Inc. (NW Hydro GP).

AltaGas has determined that NW Hydro LP is a VIE in which it holds variable interests and is the primary beneficiary. In the determination that AltaGas is the primary beneficiary of the VIE, AltaGas noted that it has the power to direct the activities that most significantly impact the VIE’s economic performance through the continued provision of all operational, maintenance and management functions for the Northwest Hydro facilities. In addition, AltaGas has the obligation to absorb the losses and the right to receive the benefits that could potentially be significant to the Northwest Hydro facilities. As such, AltaGas has consolidated NW Hydro LP and has recorded $420.4 million of the $921.6 million proceeds received as a non-controlling interest with the remainder of the proceeds, less deferred tax and transaction costs, recognized as contributed surplus in the amount of $334.6 million.

On December 13, 2018, AltaGas announced that it has reached an agreement for the sale of its remaining indirect equity interest of approximately 55 percent in the Northwest Hydro facilities (including NW Hydro LP) for proceeds of approximately $1.37 billion. The transaction was subject to customary closing conditions and approvals, and closed in January 2019. The assets and liabilities of NW Hydro LP have been classified as held for sale at December 31, 2018 (Note 5).

The assets of NW Hydro LP are the property of NW Hydro LP and are not available to AltaGas for any other purpose. NW Hydro LP’s asset balances can only be used to settle its own obligations. The liabilities of NW Hydro LP do not represent additional claims against AltaGas’ general assets. AltaGas’ exposure to loss as a result of its interest as a limited partner is its net investment.

Ridley Island LPG Export Limited Partnership

On May 5, 2017, AltaGas LPG Limited Partnership (AltaGas LPG), a wholly-owned subsidiary of AltaGas, and Vopak Development Canada Inc. (Vopak), a wholly-owned subsidiary of Koninklijke VopakN.V. (Royal Vopak), a public company incorporated under the laws of the Netherlands, formed the Ridley Island LPG Export Limited Partnership (RILE LP) to develop, own and operate the Ridley Island Propane Export Terminal (RIPET). AltaGas’ subsidiaries hold a 70 percent interest while Vopak holds a 30 percent interest in RILE LP. The construction cost of RIPET, which is estimated to be $450 to $500 million, will be funded by AltaGas LPG and Vopak in proportion to their respective interests in RILE LP. As part of the arrangements, AltaGas entered into a long-term agreement for the capacity of RIPET with RILE LP, and AltaGas and certain of its subsidiaries will provide construction and operating services to RILE LP.  

AltaGas has determined that RILE LP is a VIE in which it holds variable interests and is the primary beneficiary. In the determination that AltaGas is the primary beneficiary of the VIE, AltaGas noted that it has the power to direct the activities that most significantly impact the VIE’s economic performance through the construction, operating and marketing services provided to RILE LP. In addition, AltaGas has the obligation to absorb the losses and the right to receive the benefits that could potentially be significant to RILE LP through the long-term agreement for the capacity of RIPET. As such, AltaGas has consolidated RILE LP and recorded $20.0 million of the $24.1 million proceeds received from Vopak on formation of RILE LP as a non-controlling interest with the remainder of the proceeds less deferred tax recognized as contributed surplus in the amount of $3.0 million.

The assets of RILE LP are the property of RILE LP and are not available to AltaGas for any other purpose. RILE LP’s asset balances can only be used to settle its own obligations. The liabilities of RILE LP do not represent additional claims against AltaGas’ general assets. AltaGas’ exposure to loss as a result of its interest as a limited partner is its net investment. AltaGas and Royal Vopak have provided limited guarantees for the obligations of their respective subsidiaries for the construction cost of RIPET. Upon commencement of commercial operations at RIPET, the terms of the long-term capacity agreement between AltaGas LPG and RILE LP provide for a return on and of capital and reimbursement of RIPET operating costs by AltaGas LPG in accordance with the terms set out in the agreement.

Variable Interest Entities Acquired in WGL Acquisition

In connection with the WGL Acquisition (Note 3), AltaGas has acquired both consolidated and unconsolidated VIEs:

Consolidated VIE Investments

At December 31, 2018, WGSW Inc. (WGSW) was the primary beneficiary of SFGF LLC (SFGF), SFRC, LLC (SFRC), SFGF II, LLC (SFGF II), SFEE LLC (SFEE), and ASD Solar LP (ASD), because of its ability to direct the activities most significant to the economic performance of those entities plus the right to receive potentially significant benefits or the obligation to absorb potentially significant losses. Accordingly, these VIEs have been consolidated: 

SFGF, SFRC, and SFGF II

WGSW, along with its various tax equity partners, formed the tax equity partnerships SFGF, SFRC, and SFGF II to acquire, own, and operate distributed generation solar projects nationwide. WGSW is the managing member of these investments and will provide cash equal to the purchase price of the solar projects less any contributions from the tax-equity partner for projects sold into the partnerships. WGL Energy Systems is the developer of the projects and sells them to the partnerships, and is the operations and maintenance provider.Profits and losses are allocated between the partners under the HLBV method of accounting and the portion allocated to the tax equity partner is included in “net income (loss) attributable to non-controlling interest” on the accompanying Consolidated Statements of Income and is recorded to non-controlling interest on the accompanying Consolidated Balance Sheets.

SFEE

In 2016, WGSW and a tax equity partner formed SFEE to acquire distributed generation solar projects that were to be developed and sold by a third-party developer or WGL Energy Systems. New projects were to be designed and constructed under long-term power purchase agreements. SFEE is considered a VIE and is consolidated by WGSW.

ASD

WGSW is a limited partner in ASD, a limited partnership formed to own and operate a portfolio of residential solar projects, primarily rooftop photovoltaic power generation systems. SF ASD, a wholly-owned subsidiary of WGL Energy Systems, has management rights and control of ASD.

The following table represents amounts included in the Consolidated Balance Sheets attributable to AltaGas’ consolidated VIEs:

As at	December 31,		December 31,
		2018		2017
Current assets	$	1,383.5	$	1.4
Property, plant and equipment		619.2		84.3
Long-term investments and other assets		48.0		48.0
Current liabilities		(161.8)		—
Asset retirement obligations		(0.9)		—
Deferred tax credits		(3.0)		—
Net assets	$	1,885.0	$	133.7

Unconsolidated VIE Investments

Meade Pipeline Co. LLC (Meade)

In 2014, WGL Midstream and certain partners entered into a limited liability company agreement and formed Meade, a Delaware limited liability company, to develop and own, jointly with Transcontinental Gas Pipe Line Company, LLC, a regulated pipeline, Central Penn Pipeline (Central Penn), a segment of the larger Atlantic Sunrise project. Central Penn is an approximately 185-mile pipeline originating in Susquehanna County, Pennsylvania and extending to Lancaster County, Pennsylvania with the capacity to transport and deliver up to approximately 1.7 Bcf per day of natural gas.

As at December 31, 2018, AltaGas held an equity investment in Meade with a carrying value of$666.9million,inclusive of fair value adjustments on acquisition date  (Note 3).  WGL Midstream owns a 55 percent interest in Meade (21 percent indirect interest in Central Penn) and on a cash basis, as of December 31, 2018, WGL Midstream has spent approximately US$446million as its share of the construction costs. Although WGL Midstream holds greater than a 50 percent interest in Meade, Meade is not consolidated by WGL Midstream and instead is accounted for under the equity method of accounting. WGL Midstream is not the primary beneficiary of Meade as it does not have the power to direct the activities most significant to the economic performance of Meade. WGL Midstream applies the HLBV equity method of accounting and any profits and losses are included in “income from equity investments” in the accompanying Consolidated Statements of Income and are added to or subtracted from the carrying amount of AltaGas’ investment balance.

The maximum financial exposure to loss as a result of the involvement with this VIE is equal to WGL Midstream's capital contributions.

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INVESTMENTS ACCOUNTED FOR BY EQUITY METHOD

12 Months Ended

Dec. 31, 2018

INVESTMENTS ACCOUNTED FOR BY EQUITY METHOD [Abstract]

INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD

13. INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD

				Carrying value as at December 31				Equity income (loss) for the year ended December 31
Description	Location	Ownership Percentage		2018		2017		2018		2017
AltaGas Canada Inc. (ACI)	Canada	36.75	$	112.5	$	—	$	5.4	$	—
AltaGas Idemitsu Joint Venture LP (AIJVLP)	Canada	50		342.9		323.3		2.1		6.6
Constitution Pipeline, LLC (Constitution)	United States	10		—		—		(0.2)		—
Craven County Wood Energy LP	United States	50		7.8		20.9		(14.1)		3.3
Eaton Rapids Gas Storage System	United States	50		29.4		26.4		2.0		2.5
Grayling Generating Station LP	United States	50		29.0		27.6		3.6		3.5
Inuvik Gas Ltd. (a)	Canada	33.333		—		—		(0.2)		—
Meade Pipeline Co. LLC (Meade) (b)	United States	55		757.8		—		12.2		—
Mountain Valley Pipeline, LLC (Mountain Valley)	United States	10		532.5		—		11.5		—
Sarnia Airport Storage Pool LP	Canada	50		18.7		18.8		1.0		1.0
Petrogas Preferred Shares	Canada	n/a		150.0		150.0		12.8		12.8
Tidewater Midstream and Infrastructure Ltd. (c)	Canada	n/a		—		—		—		1.7
Stonewall Gas Gathering Systems LLC	United States	30		411.8		—		11.8		—
			$	2,392.4	$	567.0	$	47.9	$	31.4

(a) Inuvik Gas Ltd. was sold to AltaGas Canada Inc. in October 2018.

(b) Meade is a VIE (Note 12).

(c) AltaGas sold 43.7 million shares of Tidewater Midstream and Infrastructure Inc. in September 2018 (Note 11).

Summarized combined financial information, assuming a 100 percent ownership interest in AltaGas’ equity investments listed above, is as follows:

Year ended December 31	2018			2017
Revenues	$	351.6	$	110.6
Expenses		(142.7)		(74.2)
	$	208.9	$	36.4
As at December 31		2018		2017
Current assets	$	1,204.6	$	24.8
Property, plant and equipment	$	7,602.5	$	82.8
Intangible assets	$	22.9	$	5.6
Long-term investments and other assets	$	1,326.6	$	843.3
Current liabilities	$	(1,015.2)	$	(41.7)
Other long-term liabilities	$	(949.6)	$	(189.1)

Petrogas Preferred Shares

AltaGas, indirectly through its investment in AIJVLP, holds a one-third equity interest in Petrogas. In 2016, AltaGas directly invested $150.0 million to subscribe for 6,000,000 cumulative redeemable convertible preferred shares of Petrogas. These preferred shares form part of AltaGas’ overall investment in Petrogas and entitle AltaGas to a fixed, cumulative, preferential cash dividend at a rate of 8.5 percent per annum payable quarterly. These preferred shares are, in the normal course, redeemable at any time on or after January 1, 2018 and convertible into a specified number of common shares at the option of either holder at any time on or after April 19, 2018. For the year ended December 31, 2018, AltaGas received dividend income of $12.8million (2017 - $12.8 million) from the Petrogas preferred shares, which has been included in the Consolidated Statement of Income under the line item “income from equity investments”.

AltaGas Canada Inc.

As at December 31, 2018, AltaGas owns an approximate 37 percent equity interest in ACI. On October 25, 2018, the ACI IPO was successfully completed reflecting a final price of $14.50 per common share of ACI (Note 4). ACI holds Canadian rate-regulated natural gas distribution utility assets and contracted wind power in Canada, as well as an approximate 10 percent interest in the Northwest Hydro facilities.

Equity Method Investments Acquired in WGL Acquisition

In connection with the WGL Acquisition (Note 3), AltaGas acquired the following investments accounted for by the equity method that are not considered VIEs:

Mountain Valley Pipeline, LLC (Mountain Valley)

WGL Midstream owns a 10 percent equity interest in Mountain Valley Pipeline, LLC. The proposed pipeline, which will be operated by EQM Gathering Opco, LLC (EQM) and developed, constructed, and owned by Mountain Valley (a venture of EQT Midstream Partners LP (EQT) and other entities), will transport approximately2.0 Bcf of natural gas per day and will extend from Equitrans, LP’s system in Wetzel County, West Virginia to Transcontinental Gas Pipe Line Company LLC's Station 165 in Pittsylvania County, Virginia. The pipeline is expected to span approximately 300 miles.

AtDecember 31, 2018, AltaGas held an equity investment in Mountain Valley with a carrying value of $532.5million, inclusive of fair value adjustments on acquisition date (Note 3). WGL Midstream expects to invest approximatelyUS$350 millionin scheduled capital contributions through the in-service date of the pipeline based on its contracted share of project costs. The equity method is considered appropriate because Mountain Valley is a Limited Liability Company (LLC) with specific ownership accounts and ownership between five and fifty percent resulting in WGL Midstream maintaining a more than minor influence over the partnership operating and financing policies. Profits and losses are allocated under the HLBV method of accounting and are included in income from equity investments in the accompanying Consolidated Statements of Income and are added to or subtracted from the carrying amount of AltaGas’ investment balance.

In April 2018, WGL Midstream entered into a separate agreement with EQM to acquire a5 percentequity interest in a project to build a lateral interstate natural gas pipeline connecting to the Mountain Valley Pipeline.

Stonewall Gas Gathering System (Stonewall)

WGL Midstream has a 30 percent equity interest in an entity that owns and operates certain assets known as the Stonewall Gas Gathering System. Stonewall has the capacity to gather up to 1.4 Bcf of natural gas per day from the Marcellus production region in West Virginia, and connects with an interstate pipeline system that serves markets in the mid-Atlantic region. As at December 31, 2018, the carrying value of the equity investment in Stonewall was $411.8 million, inclusive of fair value adjustments on acquisition date (Note 3). Profits and losses are allocated under the HLBV method of accounting and are included in income from equity investments in the accompanying Consolidated Statements of Income.

Constitution Pipeline Company, LLC (Constitution)

WGL Midstream has an investment in Constitution, owning a 10 percent equity interest in the proposed pipeline venture. At December 31, 2018, the carrying value of the equity investment in Constitution was $nil, reflecting AltaGas’ fair value on acquisition date (Note 3). This natural gas pipeline venture is proposed to transport natural gas from the Marcellus region in northern Pennsylvania to major northeastern markets.

In addition to the above non-VIE equity investments acquired in the WGL Acquisition, the Company’s investment in Meade (Note 12) is also accounted for using the equity method.

Provisions on investments accounted for by the equity method

During the year ended December 31, 2018, AltaGas recorded a pre-tax provision of $14.5 million against AltaGas’ investment in Craven Wood County Energy LP. Noprovisions were recorded for the year ended December 31, 2017.

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SHORT-TERM DEBT

12 Months Ended

Dec. 31, 2018

SHORT-TERM AND LONG-TERM DEBT [Abstract]

SHORT-TERM DEBT

14.  SHORT-TERM DEBT

As at	December 31, 2018		December 31, 2017
Bank indebtedness (a)	$	0.2	$	6.2
US$150 million operating facility (b)		—		31.7
$25 million operating facility (c)		—		8.9
Commercial paper (d)		1,145.2		—
Project financing		64.5		—
	$	1,209.9	$	46.8

(a) Bank indebtedness bears interest at the lender's prime rate or at the interest rate applicable to bankers' acceptances. The prime lending rate at December 31, 2018was 3.95percent (December 31, 2017 – 3.2 percent).

(b) As at December 31, 2018, SEMCO held a US$150 million (December 31, 2017-US$150.0 million) unsecured revolving operating credit facility with a Canadian chartered bank with a maturity date of December 20, 2023. Draws on the facility can be by way of U.S. base-rate loans, letters of credit and LIBOR loans. Letters of credit outstanding under this facility as at December 31, 2018 were $0.7 million (December 31, 2017-$0.6 million).

(c) Upon completion of the ACI IPO, the operating facility was transferred to ACI.

(d) WGL and Washington Gas use short-term debt in the form of commercial paper or unsecured short-term bank loans to fund seasonal cash requirements. Revolving committed credit facilities are maintained in an amount equal to or greater than the expected maximum commercial paper position.

Other Credit Facilities

As at December 31, 2018, the Corporation held a $70.0 million (December 31, 2017-$50.0 million) unsecured demand revolving operating credit facility with a Canadian chartered bank. Draws on the facility bear interest at the lender's prime rate or at the bankers' acceptance rate plus a stamping fee. Letters of credit outstanding under this facility as at December 31, 2018 were $nil  (December 31, 2017-$nil).

As at December 31, 2018, AltaGas held a $150.0 million (December 31, 2017-$150.0 million) unsecured four-year extendible revolving letter of credit facility. Draws on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers’ acceptances or letters of credit. Letters of credit outstanding under this facility as at December 31, 2018 were $117.0 million (December 31, 2017-$40.8 million).

As at December 31, 2018, AltaGas held a US$200.0 million (December 31, 2017 - $150.0 million) unsecured bilateral letter of credit demand facility with a Canadian chartered bank. Borrowings on the facility incur fees and interest at rates relevant to the nature of the draws made. Letters of credit outstanding under this facility as at December 31, 2018 were $147.3 million (December 31, 2017 - $71.3 million).

As at December 31, 2018, AltaGas held a $35.0 million (December 31, 2017 - $nil)  unsecured demand revolving operating credit facility with a Canadian chartered bank. Draws on the facility bear interest at the lender’s prime rate or at the bankers’ acceptance rate plus a stamping fee. Letters of credit outstanding under this facility as at December 31, 2018 were $6.0 million (December 31, 2017 - $nil).

As at December 31, 2018, AltaGas held a US$300.0 million (December 31, 2017 - $nil) unsecured extendible revolving letter of credit facility. Borrowings on the facility incur fees and interest at rates relevant to the nature of the draws made. Letters of credit outstanding on this facility as at December 31, 2018 were $nil (December 31, 2017 - $nil).

Credit Facilities Acquired in WGL Acquisition

As at December 31, 2018, WGL held a US$650.0 million unsecured revolving credit facility. Draws on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers’ acceptances or letters of credit. There were nooutstanding bank loansunder this facility as at December 31, 2018.

As at December 31, 2018, Washington Gas held a US$350.0 million (December 31, 2017 - $nil) unsecured revolving credit facility. Draws on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers’ acceptances or letters of credit. There were no outstanding bank loans under this facility as at December 31, 2018.

WGL and Washington Gas use short-term debt in the form of commercial paper or unsecured short-term bank loans to fund seasonal cash requirements. Revolving committed credit facilities are maintained in an amount equal to or greater than the expected maximum commercial paper position. At December 31, 2018, commercial paper outstanding totaled US$839.5million for WGL and Washington Gas.

Project Financing

Washington Gas previously obtained third-party project financing on behalf of the United States federal government to provide funds during the construction of certain energy management services projects entered into under Washington Gas' area-wide contract. When theseprojects are formally accepted by the government anddeemed complete, Washington Gas assigns the ownership of the receivable to the third-party lender in satisfaction of the obligation, removing both thereceivable and the obligation related to the financing from the Consolidated Financial Statements. At December 31, 2018, draws related to project financing were $64.5 million (December 31, 2017 - $nil).  

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LONG-TERM DEBT

12 Months Ended

Dec. 31, 2018

SHORT-TERM AND LONG-TERM DEBT [Abstract]

LONG-TERM DEBT

15.  LONG-TERM DEBT

			December 31,		December 31,
As at	Maturity date	2018		2017
Credit facilities
$1,400 million unsecured extendible revolving(a)	15-May-2023	$	964.7	$	219.1
US$300 million unsecured extendible revolving(b)	15-May-2022		287.8		—
Acquisition credit facility	6-Jan-2020		113.2		—
US$1,200 million revolving credit facility(g)	28-Dec-2021		1,637.0		—
Medium-term notes (MTNs)
$175 million Senior unsecured - 4.60 percent	15-Jan-2018		—		175.0
$200 million Senior unsecured - 4.55 percent	17-Jan-2019		200.0		200.0
$200 million Senior unsecured - 4.07 percent	1-Jun-2020		200.0		200.0
$350 million Senior unsecured - 3.72 percent	28-Sep-2021		350.0		350.0
$300 million Senior unsecured - 3.57 percent	12-Jun-2023		300.0		300.0
$200 million Senior unsecured - 4.40 percent	15-Mar-2024		200.0		200.0
$300 million Senior unsecured - 3.84 percent	15-Jan-2025		299.9		299.9
$100 million Senior unsecured - 5.16 percent	13-Jan-2044		100.0		100.0
$300 million Senior unsecured - 4.50 percent	15-Aug-2044		299.8		299.8
$350 million Senior unsecured - 4.12 percent	7-Apr-2026		349.8		349.8
$200 million Senior unsecured - 3.98 percent	4-Oct-2027		199.9		199.9
$250 million Senior unsecured - 4.99 percent	4-Oct-2047		250.0		250.0
WGL and Washington Gas medium-term notes
US$500 million Senior unsecured - 2.25 to 4.76 percent	Jan - Nov 2019		682.1		—
US$250 million Senior unsecured - 2.88 percent	12-Mar-2020		341.1		—
US$20 million Senior unsecured - 6.65 percent	20-Mar-2023		27.3		—
US$40.5 million Senior unsecured - 5.44 percent	11-Aug-2025		55.3		—
US$53 million Senior unsecured - 6.62 to 6.82 percent	Oct - 2026		72.3		—
US$72 million Senior unsecured - 6.40 to 6.57 percent	Feb - Sep 2027		98.2		—
US$52 million Senior unsecured - 6.57 to 6.85 percent	Jan - Mar 2028		70.9		—
US$8.5 million Senior unsecured - 7.50 percent	1-Apr-2030		11.6		—
US$50 million Senior unsecured - 5.70 to 5.78 percent	Jan - Mar 2036		68.2		—
US$75 million Senior unsecured - 5.21 percent	3-Dec-2040		102.3		—
US$75 million Senior unsecured - 5.00 percent	15-Dec-2043		102.3		—
US$300 million Senior unsecured - 4.22 to 4.60 percent	Sep - Dec 2044		409.3		—
US$450 million Senior unsecured - 3.80 percent	15-Sep-2046		613.9		—
SEMCO long-term debt
US$300 million SEMCO Senior secured - 5.15 percent(d)	21-Apr-2020		409.3		376.4
US$82 million CINGSA Senior secured - 4.48 percent(e)	2-Mar-2032		86.3		85.2
Debenture notes
PNG 2018 Series Debenture - 8.75 percent (c)(f)	15-Nov-2018		—		7.0
PNG 2025 Series Debenture - 9.30 percent (c)(f)	18-Jul-2025		—		13.0
PNG 2027 Series Debenture - 6.90 percent (c)(f)	2-Dec-2027		—		14.0
CINGSA capital lease - 3.50 percent	1-May-2040		0.6		0.5
CINGSA capital lease - 4.48 percent	4-Jun-2068		0.2		0.2
Fair value adjustment on WGL Acquisition (note 3)			89.0		—
		$	8,992.3	$	3,639.8
Less debt issuance costs			(35.2)		(14.4)
			8,957.1		3,625.4
Less current portion			(890.2)		(188.9)
		$	8,066.9	$	3,436.5

(a) Borrowings on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers' acceptances or letters of credit. Borrowings on the facility have fees and interest at rates relevant to the nature of the draw made.

(b) Borrowings on the facility can be by way of U.S. base rate loans, U.S. prime loans, LIBOR loans, or letters of credit.

(c) Collateral for the Secured Debentures and secured extendible revolving credit facility consisted of a specific first mortgage on substantially all of PNG's property, plant and equipment, and gas purchase and gas sales contracts, and a first floating charge on other property, assets and undertakings.

(d) Collateral for the US$ MTNs is certain SEMCO assets.

(e) Collateral for the CINGSA Senior secured loan is certain CINGSA assets, Alaska Storage Holding Company, LLC, a subsidiary in which AltaGas has a controlling interest, is the non-recourse guarantor of this loan.

(f) PNG debentures totaling $33.3 million have been sold toACI (Note 4)

(g) Borrowings on the facility can be by way of U.S. base rate loans, U.S. prime loans, or LIBOR loans.

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ASSET RETIREMENT OBLIGATIONS

12 Months Ended

Dec. 31, 2018

ASSET RETIREMENT OBLIGATIONS [Abstract]

ASSET RETIREMENT OBLIGATIONS

16.  ASSET RETIREMENT OBLIGATIONS

As at	December 31, 2018		December 31, 2017
Balance, beginning of year	$	88.3	$	81.6
Obligations acquired (note 3)		399.1		—
New obligations		3.3		1.5
Obligations settled		(4.2)		(4.0)
Disposals		(1.6)		—
Revision in estimated cash flow		3.8		6.0
Accretion expense (a)		12.3		4.4
Foreign exchange translation		20.3		(0.9)
Reclassified to liabilities associated with assets held for sale (note 5)		(10.8)		(0.3)
Total		510.5		88.3
Less current portion (included in accounts payable and accrued liabilities)		(9.9)		—
Balance, end of year	$	500.6	$	88.3

(a) The majority of accretion expense is recorded through the Consolidated Statement of Income. Certain amounts relating to Washington Gas’ Utility asset retirement obligations are recorded through regulatory liabilities on the Consolidated Balance Sheets due to regulatory treatment.

The majority of the asset retirement obligations are associated with distribution and transmission systems in the Utilities segment.  

AltaGas estimates the undiscounted cash required to settle the asset retirement obligations, excluding growth for inflation, at December 31, 2018 was $770.0 million (December 31, 2017-$232.9 million).

The asset retirement obligations have been recorded in the Consolidated Financial Statements at estimated values discounted at rates between 1.5and 8.5 percent and are expected to be incurred between 2019 and 2064.  No assets have been legally restricted for settlement of the estimated liability.

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ENVIRONMENTAL MATTERS

12 Months Ended

Dec. 31, 2018

ENVIRONMENTAL MATTERS [Abstract]

ENVIRONMENTAL MATTERS

17. ENVIRONMENTAL MATTERS

AltaGas is subject to federal, provincial, state and local laws and regulations related to environmental matters. These laws and regulations may require expenditures over a long time frame to control environmental effects. Almost all of the environmental liabilities AltaGas has recorded are for costs expected to be incurred to remediate sites where AltaGas or a predecessor affiliate operated manufactured gas plants (MGPs). Estimates of liabilities for environmental response costs are difficult to determine with precision because of the various factors that can affect their ultimate level. These factors include, but are not limited to, the following:

· the complexity of the site;

· changes in environmental laws and regulations at the federal, state and local levels;

· the number of regulatory agencies or other parties involved;

· new technology that renders previous technology obsolete or experience with existing technology that proves ineffective;

· the level of remediation required; and

· variations between the estimated and actual period of time that must be dedicated to respond to an environmentally-contaminated site.

AltaGas has identified up to twelve sites where it or its predecessors may have operated MGPs. In connection with these operations, AltaGas is aware that coal tar and certain other by-products of the gas manufacturing process are present at or near some former sites and may be present at others.

At December 31, 2018, a liability of $15.4 million has been recorded on an undiscounted basis related to future environmental response costs (December 31, 2017 -  $nil)  in the Consolidated Balance Sheets under the line items “accounts payable and accrued liabilitiesand other long-term liabilities”. These estimates principally include the minimum liabilities associated with a range of environmental response costs expected to be incurred. At December 31, 2018, AltaGas estimated the maximum liability associated with all of its sites to be approximately $40.1 million (December 31, 2017 - $nil). The estimates were determined by AltaGas’ environmental experts, based on experience in remediating MGP sites and advice from legal counsel and environmental consultants. The variation between the recorded and estimated maximum liability primarily results from differences in the number of years that will be required to perform environmental response processes and the extent of remediation that may be required.

At December 31, 2018, AltaGas reported a regulatory asset of $19.9 million (December 31, 2017 - $13.9 million) for the portion of environmental response costs that are expected to be recoverable in future rates.

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OTHER LONG-TERM LIABILITIES

12 Months Ended

Dec. 31, 2018

OTHER LONG-TERM LIABILITIES [Abstract]

OTHER LONG-TERM LIABILITIES

18.  OTHER LONG-TERM LIABILITIES

As at	December 31, 2018		December 31, 2017
Deferred lease payable	$	13.1	$	2.4
Deferred revenue		3.9		3.8
Customer advances for construction		58.6		40.9
Sundance B PPA termination expense (a)		2.0		4.0
NTL liability (b)		—		142.0
Lease inducement		2.7		3.1
Merger commitments		21.4		—
Other long-term liabilities		20.3		5.7
	$	122.0	$	201.9

(a) On December 16, 2016, AltaGas Pipeline Partnership and the Government of Alberta reached a definitive settlement agreement regarding the termination of the Sundance B PPAs. Under the settlement agreement, AltaGas has agreed to make a total of $6.0 million in cash payments in equal annual installments over three years starting in 2018, $2.0 million of which has been recorded under “accounts payable and accrued liabilities”.

(b) The NTL liability has been reclassified as liabilities associated with assets held for sale (Note 5).

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INCOME TAXES

12 Months Ended

Dec. 31, 2018

INCOME TAXES [Abstract]

INCOME TAXES

19.  INCOME TAXES

Year ended December 31		2018		2017
Income (loss) before income taxes - consolidated	$	(716.9)	$	66.4
Statutory income tax rate (%)		27.0		27.0
Expected taxes at statutory rates	$	(193.6)	$	17.9
Add (deduct) the tax effect of:
Permanent differences		(1.0)		9.5
Statutory and other rate differences		(19.6)		(30.5)
Rate adjustment for change in tax rates		1.3		(34.1)
Deferred income tax recovery on regulated assets		(7.3)		(7.4)
Tax differences on divestitures and transactions		(32.3)		6.9
Non-controlling interests		4.7		—
Change in valuation allowance		(22.3)		4.2
Other		6.9		—
	$	(263.2)	$	(33.5)
Income tax provision
Current
Canada		23.7		18.0
United States		0.7		12.5
	$	24.4	$	30.5
Deferred
Canada		(166.1)		(7.4)
United States		(121.5)		(56.6)
	$	(287.6)	$	(64.0)
Effective income tax rate (%)		36.7		(50.5)

Net deferred income tax liabilities were composed of the following:

As at	December 31, 2018		December 31, 2017
PP&E and intangible assets	$	1,764.6	$	726.5
Regulatory assets		(166.3)		22.8
Tax pools, deferred financing and compensation		(453.6)		(302.3)
Other		(209.9)		(59.3)
Valuation allowance		23.1		53.7
	$	957.9	$	441.4

The amount shown on the Consolidated Balance Sheets as deferred income tax liabilities represents the net differences between the tax basis and book carrying values on the Corporation's balance sheets at enacted tax rates.

The TCJA in the U.S. became law on December 22, 2017. The law includes significant changes to the U.S. corporate income tax system, including a federal corporate rate reduction from 35 percent to 21 percent beginning in 2018, changes to capital depreciation, limitations on the deductibility of interest expense and executive compensation, and the transition of U.S. international taxation from a worldwide tax system to a territorial tax system.

The B.C. government increased the corporate tax rate to 12 percent from 11 percent beginning in 2018.

As at December 31, 2018, the Corporation had tax-effected non-capital losses of approximately $392.1 million, which will be available to offset future taxable income. If not used, these losses will expire between 2023 and 2038.

Uncertain Tax Positions

The Corporation recognizes the benefit of an uncertain tax position only when it is more likely than not that such a position will be sustained by the taxing authorities based on the technical merits of the position. The current and deferred tax impact is equal to the largest amount, considering possible settlement outcomes, that has greater than 50 percent likelihood of being realized upon settlement with the taxing authorities.

On an annual basis, the Corporation and its subsidiaries file tax returns in Canada and various foreign jurisdictions. In Canada, AltaGas' federal and provincial tax returns for the years 2012 to 2017 remain subject to examination by taxation authorities. In the United States, both the federal and state tax returns filed for the years 2012 to 2017 remain subject to examination by the taxation authorities.

Management determined that the following provision was required for uncertainty on income taxes during the year:

Year ended December 31		2018		2017
Balance, beginning of year	$	5.9	$	2.2
Net changes during the year		(3.7)		3.7
Balance, end of year	$	2.2	$	5.9

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REGULATORY ASSETS AND LIABILITIES

12 Months Ended

Dec. 31, 2018

REGULATORY ASSETS AND LIABILITIES [Abstract]

REGULATORY ASSETS AND LIABILITIES

20.  REGULATORY ASSETS AND LIABILITIES

AltaGas accounts for certain transactions in accordance with ASC 980, Regulated Operations. AltaGas refers to this accounting guidance for regulated entities as “regulatory accounting”. Under regulatory accounting, utilities are permitted to defer expenses and income as regulatory assets and liabilities, respectively, in the Consolidated Balance Sheets when it is probable that those expenses and income will be allowed in the rate-setting process in a period different from the period in which they would have been reflected in the Consolidated Statement of Income by a non-rate-regulated entity. These deferred regulatory assets and liabilities are included in the Consolidated Statement of Income in future periods when the amounts are reflected in customer rates. If an application is filed to modify customer rates with certain regulatory commissions, AltaGas is permitted to charge customers new rates, subject to refund, until the regulatory commission renders a final decision. During this interim period, a provision is recorded for a rate refund regulatory liability based on the difference between the amount collected in rates and the amount expected to be recovered from a final regulatory decision. 

Management’s assessment of the probability of recovery or pass-through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory agency orders, rules, and rate-making conventions. The relevant regulatory bodies are the MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA.

If, for any reason, the Corporation ceases to meet the criteria for application of regulatory accounting for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be de-recognized from the Consolidated Balance Sheets and included in the Consolidated Statement of Income for the period in which the discontinuance of regulatory accounting occurs. Criteria that give rise to the discontinuance of regulatory accounting include: (i) increasing competition that restricts the ability of the Corporation to charge prices sufficient to recover specific costs, and (ii) a significant change in the manner in which rates are set by regulatory agencies from cost-based regulation to another form of regulation. The Corporation’s review of these criteria currently supports the continued application of regulatory accounting for all its utilities. 

The following table summarizes the regulatory assets and liabilities recorded in the Consolidated Balance Sheets, as well as the remaining period, as of December 31, 2018 and 2017, over which the Corporation expects to realize or settle the assets or liabilities:

As at	December 31, 2018		December 31, 2017		Recovery Period
Regulatory assets - current
Deferred cost of gas (a)	$	20.4	$	0.5	Less than one year
Deferred property taxes		—		0.3	Less than one year
Other		0.6		0.3	Less than one year
	$	21.0	$	1.1
Regulatory assets - non-current
Deferred regulatory costs and rate stabilization adjustment mechanism (a)(b)	$	215.5	$	20.5	1 - 3 years
Pipeline rehabilitation costs		—		0.3	Various
Future recovery of pension and other retirement benefits (a)		192.9		113.9	Various
Future recovery of non-retirement employee benefits (a)(c)		21.3		—	Various
Deferred pension costs (d)		7.8		—		1 years
Deferred environmental costs (a)(e)		19.9		13.9	1 - 10 years
Deferred loss on reacquired debt (a)(f)		109.3		2.5	1 - 15 years
Deferred depreciation and amortization		—		23.3	Various
Deferred future income taxes (a)(g)		67.0		104.7	Various
Deferred customer retention program amortization		—		16.5		Various
Revenue deficiency account		—		31.0	Various
Other		29.3		2.0	Various
	$	663.0	$	328.6
Regulatory liabilities - current
Deferred cost of gas	$	71.2	$	9.0	Less than one year
Refundable tax credit (h)		3.8		1.9	Less than one year
Federal income tax rate change (i)		26.2		—	Less than one year
Other		13.7		—	Less than one year
	$	114.9	$	10.9
Regulatory liabilities - non-current
Option fees deferral (a)	$	—	$	4.3	Various
Refundable tax credit (h)		6.1		7.5	Various
Future expense of pension and other retirement benefits (a)		166.7		—		Various
Future removal and site restoration costs (j)		514.7		153.3	3 - 56 years
Deferred loss on reacquired debt		1.8		—		Various
Federal income tax rate change (a)(i)		698.4		101.8	Various
Insurance recovery of environmental costs		—		0.3	2 years
Other		5.1		1.4	Various
	$	1,392.8	$	268.6

(a) Washington Gas is not entitled to a rate of return on these assets. Washington Gas is allowed to recover and required to pay, using short-term interest rates, the carrying costs related to billed gas costs due from and to its customers in the District of Columbia and Virginia jurisdictions.

(b) Includes fair value of derivatives, which are not included in customer bills until settled.

(c) Represents the timing difference between the recognition of workers compensation and short-term disability costs in accordance with generally accepted accounting principles and the way these costs are recovered through rates.Certain utilities have recovered pension costs related to regulated operations in rates, and as such the Corporation has recorded a regulatory asset for the unamortized costs associated with the defined benefit and post-retirement benefit plans. Depending on the method utilized by the utility, the recovery period can be either the expected service life of the employees, the benefit period for employees, or a specific recovery period as approved by the respective regulator.

(d) Relates to costs not recoverable through rates in the District of Columbia jurisdiction. However, Washington Gas is allowed to amortize these prior unrecovered pension and other post-retirement benefits through 2019.

(e) This balance represents allowed environmental remediation expenditures at SEMCO Gas and Washington Gas sites to be recovered through rates.

(f) The losses or gains on the issuance and extinguishment of debt and interest-rate derivative instruments include unamortized balances from transactions executed in prior fiscal years. These transactions create gains and losses that are amortized over the remaining life of the debt as prescribed by regulatory accounting requirements. This also includes a fair value adjustment of $89 million recorded on the WGL Acquisition (Note 3).

(g) This regulatory asset reflects the amount of deferred income taxes expected to be refunded, or recovered from, customers in future rates.

(h) On September 18, 2013, CINGSA received a US$15.0 million gas storage facility tax credit from the State of Alaska for the benefit of its firm storage service customers. CINGSA will derive no direct or indirect benefit from the tax credit. Following receipt of the tax credit, CINGSA deposited it in a separate interest-bearing account. CINGSA will act as a custodian of the tax credit and any interest earned for the benefit of CINGSA's customers. On an annual basis, covering the years 2012 through 2021, CINGSA will disburse to the customers 1/10th of the amount of the tax credit not subject to refund to the State and interest earned. The RCA has approved the disbursement methodology.

(i) The TCJA was enacted on December 22, 2017, and required the Corporation to revalue its U.S. deferred tax assets and liabilities to the lower federal corporate tax rate of 21 percent resulting in excess accumulated deferred income taxes. The tax rate reduction created a reduction in deferred tax liability, which SEMCO Gas and Washington Gas are required to refund to ratepayers.

(j) This amount and timing of draw down is dependent upon the cost of removal of underlying utility property, plant and equipment and the life of property, plant and equipment.

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ACCUMULATED OTHER COMPREHENSIVE INCOME

12 Months Ended

Dec. 31, 2018

ACCUMULATED OTHER COMPREHENSIVE INCOME [Abstract]

ACCUMULATED OTHER COMPREHENSIVE INCOME

21.  ACCUMULATED OTHER COMPREHENSIVE INCOME

($ millions)	Available- for-sale		Defined benefit pension and PRB plans		Hedge net investments		Translation foreign operations		Equity investee		Total
Opening balance, January 1, 2018	$	(7.1)	$	(11.4)	$	(129.0)	$	342.9	$	3.7	$	199.1
OCI before reclassification		—		(14.1)		(90.6)		458.5		2.1		355.9
Amounts reclassified from OCI		—		0.7		—		—		—		0.7
Adoption of ASU No. 2016-01 (note 2)		7.1		—		—		—		—		7.1
Curtailment of DB and PRB plan		—		4.2		—		—		—		4.2
Current period OCI (pre-tax)		7.1		(9.2)		(90.6)		458.5		2.1		367.9
Income tax on amounts retained in    AOCI		—		3.3		10.4		—		—		13.7
Income tax on amounts reclassified    to earnings		—		(0.2)		—		—		—		(0.2)
Income tax on amounts related to curtailment of DB and PRB plan		—		(1.5)		—		—		—		(1.5)
Net current period OCI		7.1		(7.6)		(80.2)		458.5		2.1		379.9
Ending balance, December 31, 2018	$	—	$	(19.0)	$	(209.2)	$	801.4	$	5.8	$	579.0
Opening balance, January 1, 2017	$	19.8	$	(11.3)	$	(135.6)	$	526.3	$	5.9	$	405.1
OCI before reclassification		(30.3)		(1.3)		6.6		(183.4)		(2.2)		(210.6)
Amounts reclassified from AOCI		—		1.3		—		—		—		1.3
Current period OCI (pre-tax)		(30.3)		—		6.6		(183.4)		(2.2)		(209.3)
Income tax on amounts retained in    AOCI		3.4		0.3		—		—		—		3.7
Income tax on amounts reclassified    to earnings		—		(0.4)		—		—		—		(0.4)
Net current period OCI		(26.9)		(0.1)		6.6		(183.4)		(2.2)		(206.0)
Ending balance, December 31, 2017	$	(7.1)	$	(11.4)	$	(129.0)	$	342.9	$	3.7	$	199.1

Reclassification From Accumulated Other Comprehensive Income 

AOCI components reclassified	Income statement line item		Year ended December 31, 2018		Year ended December 31, 2017
Defined benefit pension and PRB plans	Operating and administrative expense	$	0.7	$	1.3
Deferred income taxes	Income tax expenses – deferred		(0.2)		(0.4)
		$	0.5	$	0.9

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FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT

12 Months Ended

Dec. 31, 2018

FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT [Abstract]

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

22.  FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT

The Corporation’s financial instruments consist of cash and cash equivalents, accounts receivable, risk management contracts, certain long-term investments and other assets, accounts payable and accrued liabilities, dividends payable, short-term and long-term debt and certain other current and long-term liabilities. 

Fair Value Hierarchy

AltaGas categorizes its financial assets and financial liabilities into one of three levels based on fair value measurements and inputs used to determine the fair value.

Level 1 - fair values are based on unadjusted quoted prices in active markets for identical assets or liabilities. Fair values are based on direct observations of transactions involving the same assets or liabilities and no assumptions are used. Included in this category are publicly traded shares valued at the closing price as at the balance sheet date.

Level 2 - fair values are determined based on valuation models and techniques where inputs other than quoted prices included within level 1 are observable for the asset or liability either directly or indirectly. AltaGas enters into derivative instruments in the futures, over-the-counter and retail markets to manage fluctuations in commodity prices and foreign exchange rates. The fair values of power, natural gas and NGL derivative contracts were calculated using forward prices based on published sources for the relevant period, adjusted for factors specific to the asset or liability, including basis and location differentials, discount rates, and currency exchange. The fair value of foreign exchange derivative contracts was calculated using quoted market rates. The fair value of foreign exchange option contracts was calculated using a variation of the Black-Scholes pricing model.

Level 3 - fair values are based on inputs for the asset or liability that are not based on observable market data. AltaGas uses valuation techniques when observable market data is not available. A variety of valuation methodologies are used to determine the fair value of Level 3 derivative contracts, including developed valuation inputs and pricing models. The prices used in the valuations are corroborated using multiple pricing sources, and the Corporation periodically conducts assessments to determine whether each valuation model is appropriate for its intended purpose. Level 3 derivatives include physical contracts at illiquid market locations with no observable market data, long-dated positions where observable pricing is not available over the life of the contract, contracts valued using historical spot price volatility assumptions, and valuations using indicative broker quotes for inactive market locations.

The following methods and assumptions were used to estimate the fair value of each significant classof financial instruments:

Other current liabilities - the carrying amounts approximate fair value because of the short maturity of these instruments.

Current portion of long-term debt, Long-term debt and Other long-term liabilities - the fair value of these liabilities was estimated based on discounted future interest and principal payments using the current market interest rates of instruments with similar terms. The fair value of level 3 long term debt was determined by taking the present value of the debt securities’ future cash flows discounted at interest rates that reflect market conditions as of the measurement date. The discount rate is based on the quoted market prices of the U.S. Treasury issues having a similar term to maturity, adjusted for the credit quality of the debt issuer.

Risk management assets and liabilities - the fair values of power, natural gas and NGL derivative contracts were calculated using forward prices from published sources for the relevant period. The fair value of foreign exchange derivative contracts was calculated using quoted market rates. The fair value of level 3 derivative contracts was calculated using internally developed valuation inputs and pricing models.

Equity securities – the fair value of equity securities was calculated using quoted market prices.

Loans and receivables – the fair value of these assets was estimated based on discounted future interest and principal payments using the current market interest rates of instruments with similar terms.

	December 31, 2018
	Carrying Amount		Level 1		Level 2		Level 3		Total Fair Value
Financial assets
Fair value through net income(a)
Risk management assets - current	$	99.0	$	—	$	68.3	$	30.7	$	99.0
Risk management assets - non-current		49.0		—		18.0		31.0		49.0
Equity securities(b)		8.4		8.4		—		—		8.4
Fair value through regulatory assets/liabilities (a)
Risk management assets - current		15.1		—		2.7		12.4		15.1
Risk management assets - non-current		8.7		—		—		8.7		8.7
Amortized cost
Loans and receivables (b)		45.0		—		45.2		—		45.2
	$	225.2	$	8.4	$	134.2	$	82.8	$	225.4
Financial liabilities
Fair value through net income(a)
Risk management liabilities - current	$	72.0	$	—	$	41.3	$	30.7	$	72.0
Risk management liabilities - non-current		103.4		—		15.3		88.1		103.4
Fair value through regulatory assets/liabilities (a)
Risk management liabilities - current		17.3		—		2.9		14.4		17.3
Risk management liabilities - non-current		109.6		—		0.1		109.5		109.6
Amortized cost
Current portion of long-term debt		890.2		—		884.4		—		884.4
Long-term debt		8,066.9		—		6,027.6		2,012.7		8,040.3
Other current liabilities (c)		11.2		—		11.2		—		11.2
Other long-term liabilities (c)		2.0		—		2.0		—		2.0
	$	9,272.6	$	—	$	6,984.8	$	2,255.4	$	9,240.2

(a) To manage price risk associated with acquiring natural gas supply for Maryland, Virginia, and District of Columbia utility customers, Washington Gas, a subsidiary of the Corporation, enters into physical and financial derivative transactions. Any gains and losses associated with these derivatives are recorded as regulatory liabilities or assets, respectively, to reflect the rate treatment for these economic hedging activities. Additionally, as part of its asset optimization program, Washington Gas enters into derivatives with the primary objective of securing operating margins that Washington Gas will ultimately realize. Regulatory sharing mechanisms provide for the annual realized profit from these transactions to be shared between Washington Gas' shareholder and customers; therefore, changes in fair value are recorded through earnings, or as regulatory assets or liabilities to the extent that it is probable that realized gains and losses associated with these derivative transactions will be included in the rates charged to customers when they are realized.

(b) Included under the line item "long-term investments and other assets" on the Consolidated Balance Sheets.

(c) Excludes non-financial liabilities.

	December 31, 2017
	Carrying Amount		Level 1		Level 2		Level 3		Total Fair Value
Financial assets
Fair value through net income
Risk management assets - current	$	38.6	$	—	$	38.6	$	—	$	38.6
Risk management assets - non-current		15.9		—		15.9		—		15.9
Equity securities(a)		95.0		95.0		—		—		95.0
Amortized cost
Loans and receivables (a)		75.0		—		85.6		—		85.6
	$	224.5	$	95.0	$	140.1	$	—	$	235.1
Financial liabilities
Fair value through net income
Risk management liabilities - current	$	57.6	$	—	$	57.6	$	—	$	57.6
Risk management liabilities - non-current		13.8		—		13.8		—		13.8
Amortized cost
Current portion of long-term debt		188.9		—		189.6		—		189.6
Long-term debt		3,436.5		—		3,568.3		—		3,568.3
Other current liabilities (b)		22.4		—		22.4		—		22.4
Other long-term liabilities (b)		146.0		—		147.7		—		147.7
	$	3,865.2	$	—	$	3,999.4	$	—	$	3,999.4

(a) Included under the line item "long-term investments and other assets" on the Consolidated Balance Sheets.

(b) Excludes non-financial liabilities.

The following table includes quantitative information about the significant unobservable inputs used in the fair value measurement of Level 3 financial instruments at December 31, 2018:

		Net Fair Value	Valuation Technique	Unobservable Inputs	Range
Natural gas	$	(144.1)	Discounted Cash Flow	Natural Gas Basis Price (per dekatherm)	($1.40) - $7.28
Natural gas	$	(4.4)	Option Model	Natural Gas Basis Price (per dekatherm)	($1.37) - $5.07
				Annualized Volatility of Spot Market Natural Gas	37.46% - 900.98%
Electricity	$	(14.7)	Discounted Cash Flow	Electricity Congestion Price (per megawatt hour)	($8.28) - $84.44

The following table provides a reconciliation of changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy:

For the year ended December 31	2018						2017
		Natural Gas		Electricity		Total		Natural Gas		Electricity		Total
Balance, beginning of year	$	—	$	—	$	—	$	—	$	—	$	—
Acquired (note 3)		(136.1)		(10.6)		(146.7)		—		—		—
Realized and unrealized losses:								—		—		—
Recorded in income		(8.3)		(6.5)		(14.8)
Recorded in regulatory assets		(5.9)		—		(5.9)		—		—		—
Transfers out of Level 3		7.3		—		7.3		—		—		—
Purchases		—		6.4		6.4		—		—		—
Settlements		0.3		(3.4)		(3.1)		—		—		—
Foreign exchange translation		(5.8)		(0.6)		(6.4)
Balance, end of year	$	(148.5)	$	(14.7)	$	(163.2)	$	—	$	—	$	—

Transfers between different levels of the fair value hierarchy may occur based on fluctuations in the valuation and on the level of observable inputs used to value the instruments from period to period. Transfers into and out of the different levels of the fair value hierarchy are presented at the fair value as of the beginning of the year. Transfers out of Level 3 during the year ended December 31, 2018 were due to an increase in valuations using observable market inputs. Transfers into Level 3 during the year ended December 31, 2018 were due to an increase in unobservable market inputs used in valuations.

Realized and Unrealized Losses Recorded to Income for Level 3 Measurements

For the year ended December 31	2018		2017
Recorded to revenue
Commodity contracts	$	(11.1)	$	—
Recorded to cost of sales
Commodity contracts		(3.7)		—
	$	(14.8)	$	—

Summary of Unrealized Gains (Losses) on Risk Management Contracts Recognized in Net Income

For the year ended December 31	2018		2017
Natural gas	$	(2.2)	$	2.2
Storage optimization		—		2.7
NGL frac spread		40.0		(11.7)
Power		9.3		(20.8)
Foreign exchange		33.7		(34.9)
	$	80.8	$	(62.5)

Offsetting of Derivative Assets and Derivative Liabilities

Certain of AltaGas’ risk management contracts are subject to master netting arrangements that create a legally enforceable right for a counterparty to offset the related financial assets and financial liabilities. As part of these master netting agreements, cash, letters of credit and parental guarantees may be required to be posted or obtained from counterparties in order to mitigate credit risk related to both derivative and non-derivative positions. Collateral balances are also offset against the related counterparties’ derivative positions to the extent the application would not result in the over-collateralization of those derivative positions on the balance sheet.

	December 31, 2018
Risk management assets (a)	Gross amounts of recognized assets/liabilities		Gross amounts offset in balance sheet		Netting of collateral		Net amounts presented in balance sheet
Natural gas	$	200.8	$	(82.0)	$	—	$	118.8
NGL frac spread		18.7		(0.7)		—		18.0
Power		42.8		(7.8)		—		35.0
	$	262.3	$	(90.5)	$	—	$	171.8
Risk management liabilities (b)
Natural gas	$	340.4	$	(82.0)	$	(3.3)	$	255.1
NGL frac spread		2.7		(0.7)		—		2.0
Power		50.6		(7.8)		1.2		44.0
Foreign exchange		1.2		—		—		1.2
	$	394.9	$	(90.5)	$	(2.1)	$	302.3

(a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $114.1 million and risk management assets (non-current) balance of $57.7 million.

(b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $89.3 million and risk management liabilities (non-current) balance of $213.0 million.

	December 31, 2017
Risk management assets (a)	Gross amounts of recognized assets/liabilities		Gross amounts offset in balance sheet		Netting of collateral		Net amounts presented in balance sheet
Natural gas	$	41.0	$	(6.2)	$	—	$	34.8
NGL frac spread		1.3		(0.3)		—		1.0
Power		17.7		(0.7)		—		17.0
Foreign exchange		1.7		—		—		1.7
	$	61.7	$	(7.2)	$	—	$	54.5
Risk management liabilities (b)
Natural gas	$	35.1	$	(6.2)	$	—	$	28.9
NGL frac spread		25.3		(0.3)		—		25.0
Power		14.0		(0.7)		4.2		17.5
	$	74.4	$	(7.2)	$	4.2	$	71.4

(a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $38.6 million and risk management assets (non-current) balance of $15.9 million.

(b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $57.6 million and risk management liabilities (non-current) balance of $13.8 million.

Cash Collateral

The following table presents collateral not offset against risk management assets and liabilities:

		December 31, 2018		December 31, 2017
Collateral posted with counterparties	$	27.6	$	—
Cash collateral held representing an obligation	$	0.8	$	—

Any collateral posted that is not offset against risk management assets and liabilities is included in line item “prepaid expenses and other current assets” in the Consolidated Balance Sheets. Collateral received and not offset against risk management assets and liabilities is included in line item “customer deposits” in the Consolidated Balance Sheets.

Certain derivative instruments contain contract provisions that require collateral to be posted if the credit rating of AltaGas or certain of its subsidiaries falls below certain levels. At December 31, 2018 and 2017, AltaGas had not posted any collateral related to its derivative liabilities that contained credit-related contingent features. The following table shows the aggregate fair value of all derivative instruments with credit-related contingent features that are in a liability position, as well as the maximum amount of collateral that would be required if the most intrusive credit-risk-related contingent features underlying these agreements were triggered:

		December 31, 2018		December 31, 2017
Risk management liabilities with credit-risk-contingent features	$	14.7	$	—
Maximum potential collateral requirements	$	7.5	$	—

Risks associated with financial instruments

AltaGas is exposed to various financial risks in the normal course of operations such as market risks resulting from fluctuations in commodity prices, currency exchange rates and interest rates as well as credit risk and liquidity risk.

Commodity Price Risk

AltaGas enters into financial derivative contracts to manage exposure to fluctuations in commodity prices. The use of derivative instruments is governed under formal risk management policies and is subject to parameters set out by AltaGas’ Risk Management Committee and Board of Directors. AltaGas does not make use of derivative instruments for speculative purposes.

Natural Gas

In the normal course of business, AltaGas purchases and sells natural gas to support its infrastructure business. The fixed price and market price contracts for both the purchase and sale of natural gas extend to 2023. In addition, AltaGas may enter into financial derivative contracts as part of WGL’s asset optimization program. WGL optimized the value of its long-term natural gas transportation and storage capacity resources during periods when these resources are not being used to physically serve utility customers. AltaGas had the following forward contracts and commodity swaps outstanding related to the activities in the energy services business as at December 31, 2018 and 2017:

December 31, 2018	Fixed price (per GJ)	Period (months)	Notional volume (GJ)	Fair Value ($ millions)
Sales	1.07 to 12.19	1-178	858,640,810	19.0
Purchases	0.69 to 16.26	1-179	1,638,207,391	(179.5)
Swaps	2.56 to 15.37	1-231	621,578,572	20.9
December 31, 2017	Fixed price (per GJ)	Period (months)	Notional volume (GJ)	Fair Value ($ millions)
Sales	0.42 to 6.89	1-60	94,804,039	14.8
Purchases	0.52 to 6.40	1-48	61,980,315	(16.8)
Swaps	2.86 to 9.38	1-10	6,039,642	7.9

NGL Frac Spread

AltaGas entered into a series of swaps to lock in a portion of the volumes exposed to NGL frac spread. AltaGas had the following contracts outstanding as at December 31, 2018 and 2017:

December 31, 2018	Fixed price	Period (months)	Notional volume	Fair Value ($ millions)
Propane swaps	$38.89 to $47.63/bbl	1-12	1,725,114 Bbl	12.6
Butane swaps	$52.95 to $55.26/bbl	1-12	74,371 Bbl	1.2
Crude oil swaps	$79.64 to $86.28/bbl	1-12	329,230 Bbl	6.0
Natural gas swaps	$1.38 to $1.68/GJ	1-12	9,490,365 GJ	(3.8)
December 31, 2017	Fixed price	Period (months)	Notional volume	Fair Value ($ millions)
Propane swaps	$28.77 to $49.21 /Bbl	1-12	1,992,927 Bbl	(10.9)
Butane swaps	$47.83 to $54.67 /Bbl	1-12	130,088 Bbl	(0.3)
Crude oil swaps	$61.05 to $75.64 /Bbl	1-12	518,665 Bbl	(4.4)
Natural gas swaps	$0.42 to $2.27 /GJ	1-12	11,428,515 GJ	(8.4)

Power

AltaGas sells power to the Alberta Electric System Operator at market prices as well as to commercial and industrial users in Alberta at fixed prices. AltaGas also sells power through its WGL Energy Services affiliate, to commercial, industrial and mass market users within the PJM Regional Transmission Organization at fixed and market prices.AltaGas' strategy is to mitigate the cash flow risk to Alberta power prices to provide predictable earnings. Therefore, AltaGas uses third party swaps and purchase contracts to fix the prices over time on a portion of the volumes to mitigate financial exposure associated with the sale contracts. These power purchase and sale contracts extend to 2023.  As at December 31, 2018, AltaGas had no intention to terminate any contracts prior to maturity. AltaGas had the following power commodity forward contracts and commodity swaps outstanding as at December 31, 2018 and 2017:

December 31, 2018	Fixed price (per MWh)	Period (months)	Notional volume (MWh)	Fair Value ($ millions)
Power sales	26.90 to 95.03	1-60	11,881,575	(1.9)
Power purchases	25.50 to 50.25	1-42	8,507,874	16.4
Swap purchases	(6.07) to 76.18	1-48	20,957,180	(22.3)
December 31, 2017	Fixed price (per MWh)	Period (months)	Notional volume (MWh)	Fair Value ($ millions)
Power sales	38.20 to 95.03	1-60	2,169,321	(2.5)
Power purchases	58.50	1-12	17,520	(4.5)
Swap purchases	37.50 to 63.50	1-48	1,563,160	6.5

The table below provides the potential impact on pre-tax income due to changes in the fair value of risk management contracts in place as at December 31, 2018: 

Factor	Increase or decrease to forward prices	Increase or decrease to income before tax ($ millions)
Alberta power price	$1/MWh	0.3
PJM power price	$1/MWh	1.2
AECO natural gas price	$0.50/GJ	5.9
NYMEX natural gas price	$0.50/GJ	31.5
NGL frac spread:
Propane	$1/Bbl	1.7
Butane	$1/Bbl	0.1
Western Texas Intermediate (WTI) crude oil	$1/Bbl	0.3
Natural gas	$0.50/GJ	4.7

Foreign Exchange Risk

AltaGas is exposed to foreign exchange risk as changes in foreign exchange rates may affect the fair value or future cash flows of the Corporation’s financial instruments. AltaGas has foreign operations whereby the functional currency is the U.S. dollar. As a result, the Corporation’s earnings, cash flows, and OCI are exposed to fluctuations resulting from changes in foreign exchange rates. This risk is partially mitigated to the extent that AltaGas has U.S. dollar-denominated debt and/or preferred shares outstanding. AltaGas may also enter into foreign exchange forward derivatives to manage the risk of fluctuating cash flows due to variations in foreign exchange rates. As at December 31, 2018 and 2017, AltaGas did not have any outstanding foreign exchange forward contracts.

AltaGas may also designate its U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. As at December 31, 2018, AltaGas designated US$1,494.0 million of outstanding debt as a net investment hedge (December 31, 2017-  $nil). For the year ended December 31, 2018, AltaGas incurred an after-tax unrealized loss of $80.2 million arising from the translation of debt in OCI (2017 - after-tax unrealized gain of $6.6million).

To mitigate the foreign exchange risks associated with the cash purchase price of WGL, AltaGas entered into foreign currency option contracts with an aggregate notional value of approximately US$1.2 billion which expired in May 2018. These foreign currency option contracts do not qualify for hedge accounting. Therefore, all changes in fair value were recognized in net income. For the year ended December 31, 2018, an unrealized gain of $34.3 million and a realized loss of $36.0 million were recognized in revenue in relation to these contracts (2017 – unrealized losses of $34.3 million). During the second quarter of 2018, AltaGas entered into foreign exchange forward contracts with an aggregate notional value of $3.2 billion which settled in July 2018. These foreign currency derivatives do not qualify for hedge accounting. For the year ended December 31, 2018, a realized gain of$1.3 million was recognized in income in relation to these forwards (2017 -  $nil).

Interest Rate Risk

AltaGas is exposed to interest rate risk as changes in interest rates may impact future cash flows and the fair value of its financial instruments. The Corporation manages its interest rate risk by holding a mix of both fixed and floating interest rate debt. As at December 31, 2018, approximately 59 percent of AltaGas’ total outstanding short-term and long-term debt was at fixed rates. In addition, from time to time, AltaGas may enter into interest rate swap agreements to fix the interest rate on a portion of its banker’s acceptances issued under its credit facilities. There were no outstanding interest rate swaps as at December 31, 2018.

Credit Risk

Credit risk results from the possibility that a counterparty to a financial instrument fails to fulfill its obligations in accordance with the terms of the contract.

AltaGas' credit policy details the parameters used to grant, measure, monitor and report on credit provided to counterparties. AltaGas minimizes counterparty risk by conducting credit reviews on counterparties in order to establish specific credit limits, both prior to providing products or services and on a recurring basis. In addition, most contracts include credit mitigation clauses that allow AltaGas to obtain financial or performance assurances from counterparties under certain circumstances. AltaGas maintains an allowance for doubtful accounts in the normal course of its business.

AltaGas' maximum credit exposure consists primarily of the carrying value of the non-derivative financial assets and the fair value of derivative financial assets. As at December 31, 2018, AltaGas had no concentration of credit risk with a single counterparty.

Weather Related Instruments

WGL Energy Services utilizes heating degree day (HDD) instruments from time to time to manage weather and price risks related to its natural gas and electricity sales during the winter heating season. WGL Energy Services also utilizes cooling degree day (CDD) instruments and other instruments to manage weather and price risks related to its electricity sales during the summer cooling season. These instruments cover a portion of estimated revenue or energy-related cost exposure to variations in HDDs or CDDs. For the period from close of the WGL Acquisition to December 31, 2018, pre-tax losses of $1 million were recorded related to these instruments (2017 - $nil).

Accounts Receivable Past Due or Impaired

AltaGas had the following past due or impaired accounts receivable (AR):

As at December 31, 2018	Total		AR accruals		Receivables impaired		Less than 30 days		31 to 60 days		61 to 90 days		Over 90 days
Trade receivable	$	1,574.6	$	447.5	$	54.7	$	961.5	$	74.1	$	12.8	$	24.0
Other		27.6		—		—		27.5		—		—		0.1
Allowance for credit losses		(54.7)		—		(54.7)		—		—		—		—
	$	1,547.5	$	447.5	$	—	$	989.0	$	74.1	$	12.8	$	24.1

As at December 31, 2017	Total		AR accruals		Receivables impaired		Less than 30 days		31 to 60 days		61 to 90 days		Over 90 days
Trade receivable	$	383.0	$	184.6	$	2.4	$	187.0	$	7.9	$	1.4	$	(0.3)
Other		2.3		—		—		2.3		—		—		—
Allowance for credit losses		(2.4)		—		(2.4)		—		—		—		—
	$	382.9	$	184.6	$	—	$	189.3	$	7.9	$	1.4	$	(0.3)

Allowance for credit losses	December 31, 2018		December 31, 2017
Balance, beginning of year	$	2.4	$	2.5
Foreign exchange translation		0.1		(0.1)
New allowance (a)		53.1		0.4
Change in allowance		(0.9)		—
Allowance applied to uncollectible customer accounts		—		(0.4)
Balance, end of year	$	54.7	$	2.4

(a) Upon close of the WGL Acquisition, AltaGas acquired WGL’s allowance for credit losses of approximately $52.9 million. 

Liquidity Risk

Liquidity risk is the risk that AltaGas will not be able to meet its financial obligations as they come due. AltaGas manages this risk through its extensive budgeting and monitoring process to ensure it has sufficient cash and credit facilities to meet its obligations. AltaGas' objective is to maintain its investment-grade ratings to ensure it has access to debt and equity funding as required.

AltaGas had the following contractual maturities with respect to financial liabilities:

	Contractual maturities by period
As at December 31, 2018	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Accounts payable and accrued liabilities	$	1,488.2	$	1,488.2	$	—	$	—	$	—
Dividends payable		22.0		22.0		—		—		—
Short-term debt		1,209.9		1,209.9		—		—		—
Other current liabilities (a)		11.2		11.2		—		—		—
Other long-term liabilities (a)		2.0		—		2.0		—		—
Risk management contract liabilities		302.3		89.3		113.3		33.3		66.4
Current portion of long-term debt (b)		888.5		888.5		—		—		—
Long-term debt (b)		8,014.8		—		3,063.4		1,592.6		3,358.8
	$	11,938.9	$	3,709.1	$	3,178.7	$	1,625.9	$	3,425.2

(a) Excludes non-financial liabilities

(b) Excludes deferred financing costs and discounts

	Contractual maturities by period
As at December 31, 2017	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Accounts payable and accrued liabilities	$	415.3	$	415.3	$	—	$	—	$	—
Dividends payable		32.0		32.0		—		—		—
Short-term debt		46.8		46.8		—		—		—
Other current liabilities (a)		22.4		22.4		—		—		—
Other long-term liabilities (a)		146.0		—		25.7		20.8		99.5
Risk management contract liabilities		71.4		57.6		11.1		2.7		—
Current portion of long-term debt (b)		188.9		188.9		—		—		—
Long-term debt (b)		3,450.9		—		1,009.1		363.8		2,078.0
	$	4,373.7	$	763.0	$	1,045.9	$	387.3	$	2,177.5

(a) Excludes non-financial liabilities

(b) Excludes deferred financing costs and discounts

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REVENUE

12 Months Ended

Dec. 31, 2018

REVENUE [Abstract]

Revenue

23. REVENUE

The following table disaggregates revenue by major sources for the year ended December 31, 2018:

	Year ended December 31, 2018
		Utilities		Midstream		Power		Corporate		Total
Revenue from contracts with customers
Commodity sales contracts	$	—	$	665.2	$	497.5	$	—	$	1,162.7
Midstream service contracts		—		205.0		—		—		205.0
Gas sales and transportation services		1,684.3		—		—		—		1,684.3
Storage services		35.4		—		—		—		35.4
Other		10.7		0.6		25.1		—		36.4
Total revenue from contracts with customers	$	1,730.4	$	870.8	$	522.6	$	—	$	3,123.8
Other sources of revenue
Revenue from alternative revenue programs (a)	$	21.7	$	—	$	—	$	—	$	21.7
Leasing revenue (b)		0.6		96.6		354.9		—		452.1
Risk management and trading activities (c)(d)		1.0		377.6		268.5		(2.9)		644.2
Other		(1.1)		(0.4)		16.0		0.4		14.9
Total revenue from other sources	$	22.2	$	473.8	$	639.4	$	(2.5)	$	1,132.9
Total revenue	$	1,752.6	$	1,344.6	$	1,162.0	$	(2.5)	$	4,256.7

(a) A large portion of revenue generated from the Utilities segment is subject to rate regulation and accordingly there are circumstances where the revenue recognized is mandated by the applicable regulators in accordance with ASC 980.

(b) Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Power segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases.

(c) Risk management activities involve the use of derivative instruments such as physical and financial swaps, forward contracts, and options. These derivatives are accounted for under ASC 815 and ASC 825. The majority of revenue generated by the Midstream and Power segments is from the physical sale and delivery of natural gas and power to end users, except for WGL Midstream (see footnote d).

(d) WGL Midstream trading margins are reported in risk management and trading activities from the Midstream segment. WGL Midstream enters into derivative contracts for the purpose of optimizing its storage and transportation capacity as well as managing the transportation and storage assets on behalf of third parties. The trading margins of WGL Midstream, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues of $264.2 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract, which are in scope of ASC 606, are reported in the risk management and trading activities. While the GAIL contract is individually not accounted for as a derivative, it is inseparable from the overall trading portfolio of WGL Midstream. Revenue is recognized at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount. The contract has a term of 20 years and began on March 31, 2018.

Revenue Recognition

The following is a description of the Corporation’s revenue recognition policy by major sources of revenue from contracts with customers and segment.

Utilities segment

Gas sales and transportation services

Customers are billed monthly based on regular meter readings. Customer billings are based on two main components: (i) a fixed service fee and (ii) a variable fee based on usage. Revenue is recognized over time when the gas has been delivered or as the service has been performed. As meter readings are performed on a cycle basis, AltaGas recognizes accrued revenue for any services rendered to its customers but not billed at month-end. The vast majority of these contracts are “at-will” as customers may cancel their service at any time, however, there are certain contracts that have terms of one year or longer. For these long-term contracts, there is generally a contract demand specified in the contract whereby the customer has to pay regardless of whether or not gas has been delivered. These contracts generally do not contain any make up rights and revenue is recognized on a monthly basis as service has been performed.

Gas storage services

Gas storage customers are billed monthly for services provided. Customer billings are based on four components: (i) reservation charges; (ii) capacity charges; (iii) injection/withdrawal charges; and (iv) excess charges. Reservation charges are based on the customer’s contract withdrawal quantity, capacity charges are based on the customer’s total contract quantity, and injection/withdrawal charges are based on the volume of gas delivered to or from the customer. Excess charges are applied to each day that the storage quantity exceeds 100 percent of the customer’s maximum storage quantity. Revenue is recognized as the service has been performed over time on a monthly basis, which corresponds to the invoice amount. The majority of these contracts have terms extending beyond one-year.

Midstream segment

Commodity sales

A portion of the NGL production from AltaGas’ extraction facilities is subject to frac spread between NGLs extracted and the natural gas purchased to make up the heating value of the NGLs extracted. For commodity sales contracts that do not meet the definition of a derivative or for contracts whereby AltaGas has elected to apply the normal purchase normal sales scope exception, the sales contract is accounted for under ASC 606. These commodity sales contracts have varying terms but the majority of the contracts have a one-year term which coincides with the NGL year. AltaGas recognizes revenue for commodity sales contracts at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount.

Commodity sales also include gas sales to residential, commercial and industrial customers in certain states where WGL Energy Services is authorized as a competitive service provider. These commodity sales contracts have varying terms that generally range from one to five years. Customers are billed monthly based on the amount of gas delivered to the customer. Revenue is recognized based on the amount the Company is entitled to invoice the customer. 

Midstream service contracts

AltaGas earns revenue from its field gathering and processing facilities, extraction facilities, and transmission systems through a variety of contractual arrangements. For arrangements that do not contain a lease, the revenue is accounted for under ASC 606 as follows:

Fee-for-service – The customer is charged a fee for the service provided on a per unit volume basis. Contract terms generally range from one month to up to the life of the reserves. Revenue under this type of arrangement is recognized over time as the service is provided, which corresponds to the customer’s monthly invoice amount.

Take-or-pay – The customer has agreed to a minimum volume commitment whereby the customer must have AltaGas process or deliver a specified volume at a rate per unit that is specified in the contract. Quantities that the customer is unable to deliver are considered deficiency quantities. Certain of AltaGas’ take-or-pay contracts contain provisions whereby the customer can make up deficiency quantities in subsequent periods. Under this type of arrangement, any consideration received relating to the deficiency quantities that will be made up in a future period will be deferred until either: (i) the customer makes up the volumes or (ii) the likelihood that the customer will make up the volumes before the make up period expires becomes remote. If AltaGas does not expect the customer to make up the deficiency quantities (also referred to as breakage amount), AltaGas may recognize the expected breakage amount as revenue before the make up period expires. Significant judgment is required in estimating the breakage amount. For contracts where the customer has no make-up rights, revenue is recognized on a monthly basis based on the higher of (i) the actual quantity delivered times the per unit rate or (ii) the contracted minimum amount.

Power segment

For the Power segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases. In instances where power generation is not sold under a power purchase agreement, the commodity is sold via a merchant market, or via commodity sales agreements which are accounted for as financial instruments. For commodity sales contracts that do not meet the definition of a lease, derivative or for contracts whereby AltaGas has elected to apply the normal purchase normal sales scope exception, the sales contract is accounted for under ASC 606. 

Commodity Sales

Energy generated from commercial solar and combined heating and power assets is sold under long term power purchase agreements with a general duration of 20 years. These long term purchase agreements provide stable cash flow by way of contracted prices for the underlying commodities. Commodity sales also include electricity sales to residential, commercial and industrial customers in certain states where WGL Energy Services is authorized as a competitive service provider. These commodity sales contracts have varying terms that generally range from one to five years. Customers are billed monthly based on meter readings or the amount of energy delivered to the customer. Revenue is recognized based on the amount the Company is entitled to invoice the customer.

Contract Balances

As at December 31, 2018, a contract asset of $11.5 million has been recorded within long-term investments and other assetson the Consolidated Balance Sheets (December 31, 2017 – $nil). This contract asset represents the difference in revenue recognized under a new rate in a blend-and-extend contract modification with a customer. Revenue from this contract modification will be recognized at the pre-modification rate for the remainder of the original term with the excess revenue recorded as a contract asset. The contract asset will be drawn down over the remaining term of the modified contract.

In addition, at December 31, 2018 there is a contract asset of $47.3 million (December 31, 2017 - $nil) recorded within accounts receivable on the Consolidated Balance Sheets for WGL Energy Systems’ unbilled revenue relating to design-build construction contracts. The contract asset represents unbilled amounts typically resulting from sales under contracts when the cost-to-cost method of revenue recognition is utilized, and revenue recognized exceeds the amount billed to the customer. Right to payment is achieved when the projects are formally “accepted” by the federal government. In the fourth quarter of 2018, WGL Energy Systems reached an agreement for the sale of a financing receivable included in the contract asset. Accordingly, the receivable was reclassified as held for sale (Note 5) and a $6.0 million provision was recorded on the asset (Note 10).Contract liabilities of $2.2 million (2017 -  $nil) have been recorded within other current liabilities on the Consolidated Balance Sheets. The contract liabilities consist of advance payments and billings in excess of revenue recognized and deferred revenue. Contract assets and liabilities are reported in a net position on a contract-by-contract basis at the end of each reporting period.

Transaction price allocated to the remaining obligations

The following table includes estimated revenue expected to be recognized in the future related to performance obligations that are unsatisfied as of December 31, 2018:

		2019		2020		2021		2022		2023		> 2023		Total
Midstream service contracts	$	52.2	$	55.7	$	32.3	$	31.9	$	28.0	$	192.4	$	392.5
Gas sales and transportation services		0.6		0.6		0.6		0.6		0.6		3.2		6.2
Storage services		36.7		36.3		36.3		36.3		36.3		299.8		481.7
Other		37.0		10.5		1.6		0.8		0.8		3.2		53.9
Subtotals	$	126.5	$	103.1	$	70.8	$	69.6	$	65.7	$	498.6	$	934.3

AltaGas applies the practical expedient available under ASC 606 and does not disclose information about the remaining performance obligations for (i) contracts with an original expected length of one year or less, (ii) contracts for which revenue is recognized at the amount to which AltaGas has the right to invoice for performance completed, and (iii) contracts with variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation. In addition, the table above does not include any estimated amounts of variable consideration that are constrained. The majority of midstream service contracts, gas sales and transportation service contracts, and storage service contracts contain variable consideration whereby uncertainty related to the associated variable consideration will be resolved (usually on a daily basis) as volumes are processed, gas is delivered or as service is provided.

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SHAREHOLDERS' EQUITY

12 Months Ended

Dec. 31, 2018

SHAREHOLDERS' EQUITY [Abstract]

SHAREHOLDERS' EQUITY

24.  SHAREHOLDERS’ EQUITY

Authorization

AltaGas is authorized to issue an unlimited number of voting common shares. AltaGas is also authorized to issue preferred shares not to exceed 50 percent of the voting rights attached to the issued and outstanding common shares.

Premium DividendTM, Dividend Reinvestment and Optional Cash Purchase Plan (DRIP or the Plan)

The Plan consists of three components: a Premium Dividend™ component, a Dividend Reinvestment component and an Optional Cash Purchase component. The Premium Dividend™ component of the plan was suspended effective December 18, 2018.

The Plan provides eligible holders of common shares with the opportunity to, at their election, either: (1) reinvest the cash dividends paid by AltaGas on their common shares towards the purchase of new common shares at a 3 percent discount to the average market price (as defined below) of the common shares on the applicable dividend payment date (the Dividend Reinvestment component of the Plan); or (2) reinvest the cash dividends paid by AltaGas on their common shares towards the purchase of new common shares at a 3 percent discount to the average market price (as defined below) on the applicable dividend payment date and have these additional common shares of AltaGas exchanged for a cash payment equal to 101 percent of the reinvested amount (the Premium DividendTM component of the Plan).

In addition, the Plan provides shareholders who are enrolled in the Dividend Reinvestment component of the Plan with the opportunity to purchase new common shares at the average market price (with no discount) on the applicable dividend payment date (the Optional Cash Purchase component of the Plan).

Each of the components of the Plan are subject to prorating and other limitations on availability of new common shares in certain events. The "average market price", in respect of a particular dividend payment date, refers to the arithmetic average (calculated to four decimal places) of the daily volume weighted average trading prices of common shares on the Toronto Stock Exchange for the trading days on which at least one board lot of common shares is traded during the 10 business days immediately preceding the applicable dividend payment date. Such trading prices will be appropriately adjusted for certain capital changes (including common share subdivisions, common share consolidations, certain rights offerings and certain dividends). Shareholders resident outside of Canada are not entitled to participate in the Premium DividendTM component of the Plan. Shareholders resident outside of Canada (other than the U.S.) may participate in the Dividend Reinvestment component or the Optional Cash Purchase component of the Plan only if their participation is permitted by the laws of the jurisdiction in which they reside and provided that AltaGas is satisfied, in its sole discretion, that such laws do not subject the Plan or AltaGas to additional legal or regulatory requirements.

Common Shares Issued and Outstanding	Number of  shares		Amount
January 1, 2017	166,906,833	$	3,773.4
Shares issued for cash on exercise of options	240,125		6.5
Deferred taxes on share issuance cost	—		(8.3)
Shares issued under DRIP	8,132,258		236.3
December 31, 2017	175,279,216		4,007.9
Shares issued on conversion of subscription receipts, net of issuance costs	84,510,000		2,305.6
Shares issued for cash on exercise of options	57,275		1.3
Deferred taxes on share issuance costs	—		13.3
Shares issued under DRIP	15,377,575		325.8
Issued and outstanding at December 31, 2018	275,224,066	$	6,653.9

Preferred Shares

As at	December 31, 2018			December 31, 2017
Issued and Outstanding	Number of shares		Amount	Number of shares		Amount
Series A	5,511,220	$	137.8	5,511,220	$	137.8
Series B	2,488,780		62.2	2,488,780		62.2
Series C	8,000,000		205.6	8,000,000		205.6
Series E	8,000,000		200.0	8,000,000		200.0
Series G	8,000,000		200.0	8,000,000		200.0
Series I	8,000,000		200.0	8,000,000		200.0
Series K	12,000,000		300.0	12,000,000		300.0
Washington Gas
$4.80 series	150,000		19.7	—		—
$4.25 series	70,600		9.4	—		—
$5.00 series	60,000		7.9	—		—
Share issuance costs, net of taxes			(27.9)			(27.9)
Fair value adjustment on WGL Acquisition (note 3)			4.1			—
	52,280,600	$	1,318.8	52,000,000	$	1,277.7

The following table outlines the characteristics of the cumulative redeemable preferred shares (a):

	Current yield	Annual dividend per share(b)	Redemption price per share	Redemption and conversion option date(c)(d)	Right to convert into(d)
AltaGas
Series A (e)	3.38%	$0.845	$25	September 30, 2020	Series B
Series B (f)	Floating (f)	Floating (f)	$25	September 30, 2020 (g)	Series A
Series C (h)	5.29%	US$1.3225	US$25	September 30, 2022	Series D
Series E (e)	5.393%	$1.34825	$25	December 31, 2023	Series F
Series G (e)	4.75%	$1.1875	$25	September 30, 2019	Series H
Series I (i)	5.25%	$1.3125	$25	December 31, 2020	Series J
Series K (j)	5.00%	$1.25	$25	March 31, 2022	Series L
Washington Gas
$4.80 series	4.27%	US$4.80	US$101	n/a	n/a
$4.25 series	4.27%	US$4.25	US$105	n/a	n/a
$5.00 series	4.27%	US$5.00	US$102	n/a	n/a

(a) The table above only includes those series of preferred shares that are currently issued and outstanding. The Corporation is authorized to issue up to 8,000,000 of each of Series D Shares,  Series F Shares,  Series H Shares, and Series J Shares, and up to 12,000,000 of Series L Shares, subject to certain conditions, upon conversion by the holders of the applicable currently issued and outstanding series of preferred shares noted opposite such series in the table on the applicable conversion option date. If issued upon the conversion of the applicable series of preferred shares, Series F Shares,  Series H Shares,  Series J Shares, and Series L Shares are also redeemable for $25.50, and Series D Shares are redeemable for US$25.50 on any date after the applicable conversion option date, plus all accrued but unpaid dividends to, but excluding, the date fixed for redemption. 

(b) The holders of Series A Shares, Series C Shares, Series E Shares, Series G Shares, Series I Shares and Series K Shares are entitled to receive a cumulative quarterly fixed dividend as and when declared by the Board of Directors. The holders of Series B Shares are entitled to receive a quarterly floating dividend as and when declared by the Board of Directors. If issued upon the conversion of the applicable series of Preferred Shares, the holders of Series D Shares, Series F Shares, Series H Shares, Series J Shares and Series L Shares will be entitled to receive a quarterly floating dividend as and when declared by the Board of Directors.

(c) AltaGas may, at its option, redeem all or a portion of the outstanding shares for the redemption price per share, plus all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary thereafter.

(d) The holder will have the right, subject to certain conditions, to convert their preferred shares of a specified series into Preferred Shares of that other specified series as noted in this column of the table on the applicable conversion option date and every fifth anniversary thereafter.

(e) Holders will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at a rate equal to the sum of the then five-year Government of Canada bond yield plus 2.66 percent (Series A Shares), 3.17 percent (Series E Shares), and 3.06 percent (Series G Shares). 

(f) Holders of Series B Shares will be entitled to receive cumulative quarterly floating dividends, which will reset each quarter thereafter at a rate equal to the sum of the then 90-day government of Canada Treasury Bill rate plus 2.66 percent. Each quarterly dividend is calculated as the annualized amount multiplied by the number of days in the quarter, divided by the number of days in the year. Commencing December 31, 2018, the floating quarterly dividend rate for Series B Shares is $0.26938 per share for the period starting December 31, 2018 to, but excluding, March 31, 2019.

(g) Series B Shares can be redeemed for $25.50 per share on any date after September 30, 2015 that is not a Series B conversion date, plus all accrued and unpaid dividends to, but excluding, the date fixed for redemption.

(h) Holders of Series C Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the sum of the five-year U.S. Government bond yield plus 3.58 percent.

(i) Holders of Series I Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the then five-year Government of Canada bond yield plus 4.19 percent, provided that, in any event, such rate shall not be less than 5.25 percent per annum.

(j) Holders of Series K Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the then five-year Government of Canada bond yield plus 3.80 percent, provided that, in any event, such rate shall not be less than 5.00 percent per annum.

Share Option Plan

AltaGas has an employee share option plan under which employees and directors are eligible to receive grants. As at December 31, 2018,  21,213,224 shares were reserved for issuance under the plan. As at December 31, 2018, options granted under the plan have a term between six and ten years until expiry and vest no longer than over a four-year period.

As at December 31, 2018, unexpensed fair value of share option compensation cost associated with future periods was $3.7 million (December 31, 2017 - $1.3 million).

The following table summarizes information about the Corporation’s share options:

As at	December 31, 2018			December 31, 2017
	Options outstanding			Options outstanding
	Number of options	Exercise price(a)		Number of options	Exercise price(a)
Share options outstanding, beginning of year	4,533,761	$	32.35	4,119,386	$	32.39
Granted	2,811,460		16.69	848,000		30.80
Exercised	(57,275)		20.68	(240,125)		24.63
Forfeited	(878,013)		36.47	(193,500)		36.36
Expired	(100,750)		14.60	—		—
Share options outstanding, end of year	6,309,183	$	25.18	4,533,761	$	32.35
Share options exercisable, end of year	2,897,723	$	32.01	3,326,197	$	31.93

(a) Weighted average.

As at December 31, 2018, the aggregate intrinsic value of the total options exercisable was $nil  (December 31, 2017 - $6.0million), the total intrinsic value of options outstanding was $nil(December 31, 2017 - $6.0 million) and the total intrinsic value of options exercised was $0.3million (December 31, 2017 - $1.4 million).

The following table summarizes the employee share option plan as at December 31, 2018:

	Options outstanding				Options exercisable
			Weighted	Weighted average			Weighted	Weighted average
	Number		average	remaining	Number		average	remaining
	outstanding		exercise price	contractual life	exercisable		exercise price	contractual life
$14.24 to $18.00	2,322,635	$	14.55	5.91	28,000	$	17.10	1.33
$18.01 to $25.08	425,000		20.76	1.83	425,000		20.76	1.83
$25.09 to $50.89	3,561,548		32.65	3.48	2,444,723		34.14	2.95
	6,309,183	$	25.18	4.26	2,897,723	$	32.01	2.77

The fair value of each option granted is estimated on the date of grant using the Black-Scholes-Merton option pricing model. The weighted average grant date fair value and assumptions are as follows:

Year ended December 31	2018	2017
Fair value per option ($)	1.27	1.91
Risk-free interest rate (%)	1.99	1.31
Expected life (years)	6	6
Expected volatility (%)	23.23	21.05
Annual dividend per share ($) (a)	1.18	2.12
Forfeiture rate (%)	—	—

(a) Annual dividend per share is calculated based on a weighted average share price and forward dividend yields as of the grant dates.

MTIP and DSUP

AltaGas has a MTIP for employees and executive officers, which includes RUs and PUs with vesting periods between 36 to 44 months from the grant date. In addition, AltaGas has a DSUP, which allows granting of DSUs to directors, officers and employees. DSUs granted under the DSUP vest immediately but settlement of the DSUs occurs when the individual ceases to be a director.

PUs, RUs, and DSUs	December 31, 2018	December 31, 2017
(number of units)
Balance, beginning of year	564,549	364,839
Acquired (a)	5,291,621	—
Granted	9,502,347	386,126
Additional units added by performance factor	—	24,301
Vested and paid out	(148,154)	(221,775)
Forfeited	(66,522)	(27,279)
Units in lieu of dividends	55,934	38,337
Outstanding, end of year	15,199,775	564,549

(a) Upon close of the WGL Acquisition, AltaGas acquired WGL’s PUs. These were converted to a fixed cash amount at a value of US$1.00 per unit.

For the year ended December 31, 2018, the compensation expense recorded for the MTIP and DSUP was $16.6 million (2017-$9.1 million). As at December 31, 2018, the unrecognized compensation expense relating to the remaining vesting period for the MTIP was $26.9 million (December 31, 2017 - $8.4 million) and is expected to be recognized over the vesting period.

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NET INCOME PER COMMON SHARE

12 Months Ended

Dec. 31, 2018

NET INCOME PER COMMON SHARE [Abstract]

NET INCOME PER COMMON SHARE

25.  NET INCOME PER COMMON SHARE

The following table summarizes the computation of net income per common share:

	Year ended December 31
	2018		2017
Numerator:
Net income (loss) applicable to controlling interests	$	(435.1)	$	91.6
Less: Preferred share dividends		(66.6)		(61.3)
Net income (loss) applicable to common shares	$	(501.7)	$	30.3
Denominator:
(millions)
Weighted average number of common shares outstanding		222.6		171.0
Dilutive equity instruments(a)		0.1		0.3
Weighted average number of common shares    outstanding - diluted		222.7		171.3
Basic net income (loss) per common share	$	(2.25)	$	0.18
Diluted net income (loss) per common share	$	(2.25)	$	0.18

(a) Includes all options that have a strike price lower than the share price of AltaGas' common shares as at December 31, 2018 and 2017.

For the year ended December 31, 2018, 4.0 million of share options (2017 – 2.8 million) were excluded from the diluted net income per share calculation as their effects were anti-dilutive.

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OTHER INCOME

12 Months Ended

Dec. 31, 2018

OTHER INCOME [Abstract]

OTHER INCOME

26.  OTHER INCOME 

Year ended December 31	2018		2017
Losses from sale of assets	$	(10.6)	$	(2.7)
Other components of net benefit cost (note 2)		18.9		—
Interest income and other revenue		2.7		8.7
Gains (losses) on investments		(10.1)		3.6
	$	0.9	$	9.6

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OPERATING LEASES

12 Months Ended

Dec. 31, 2018

OPERATING LEASES [Abstract]

OPERATING LEASES

27.  OPERATING LEASES

Certain of AltaGas’ revenues are obtained through power purchase agreements or take-or-pay contracts whereby AltaGas is the lessor in these operating lease arrangements. Minimum lease payments received are amortized over the term of the lease. Contingent rentals are recorded when the condition that created the present obligation to make such payments occurs such as when actual electricity is generated and delivered. The carrying value of property, plant, and equipment associated with these leases was $2.5 billion as at December 31, 2018  (December 31, 2017-$3.0 billion). For the year ended December 31, 2018, the total revenue earned from minimum lease payments was $285.1 million (2017 - $290.8 million) and from contingent rentals was $167.1 million (2017-$175.6 million).

The following table sets forth the future fixed minimum revenue related to the operating leases for the years ended December 31:

2019	194.4
2020	155.3
2021	111.9
2022	112.0
2023	104.2

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PENSION PLANS AND RETIREE BENEFITS

12 Months Ended

Dec. 31, 2018

PENSION PLANS AND RETIREE BENEFITS [Abstract]

PENSION PLANS AND RETIREE BENEFITS

28.  PENSION PLANS AND RETIREE BENEFITS

The costs of the defined benefit and post-retirement benefit plans are based on management's estimate of the future rate of return on the fair value of pension plan assets, salary escalations, mortality rates and other factors affecting the payment of future benefits.

Defined Contribution Plan

AltaGas has a defined contribution (DC) pension plan for substantially all employees who are not members of defined benefit plans. The pension cost recorded for the DC plan was $15.4 million for the year ended December 31, 2018  (2017 - $8.4 million).

Defined Benefit Plans

AltaGas has several defined benefit pension plans for unionized and non-unionized employees, including five in Canada and six in the United States. These benefit plans are partially funded except for three of the Canadian plans which are fully funded.

Supplemental Executive Retirement Plan (SERP)

AltaGas has non-registered, defined benefit plans that provide defined benefit pension benefits to eligible executives based on average earnings, years of service and age at retirement. The SERP benefits will be paid from the general revenue of the Corporation as payments come due. Security will be provided for the SERP benefits through a letter of credit within a retirement compensation arrangement trust account.

Post-Retirement Benefits

AltaGas has several post-retirement benefit plans for unionized and non-unionized employees, including one in Canada and four in the United States. The post-retirement benefit plan in Canada is limited to the payment of life insurance and health insurance premiums.This benefit plan is not funded. Post-retirement benefit plans in the United States provide certain medical and prescription drug benefits to eligible retired employees, their spouses and covered dependents. Benefits are based on a combination of the retiree's age and years of service at retirement. Two of these benefit plans are partially funded and two of them are fully funded.

AltaGas’ most recent actuarial valuation of the Canadian defined benefit plans for funding purposes was completed in 2016. AltaGas is required to file an actuarial valuation of its Canadian defined benefit plans with the pension regulators at least every three years. The next actuarial valuation for funding purposes is required to be completed as of a date no later than December 31, 2019, and is expected to be filed with the pension regulators in 2020. Actuarial valuations are required annually for AltaGas’ U.S. defined benefit plans.

The following defined benefit and post-retirement benefit plans were acquired in connection with the acquisition of WGL:

Defined Benefit Plans:

· Qualified Pension Plan - Washington Gas maintains a qualified, trusteed, non-contributory defined benefit pension plan covering most active and vested former employees of Washington Gas and certain employees of WGL subsidiaries. The non-contributory defined benefit pension plan is closed to all employees hired on or after January 1, 2010.

· Supplemental Executive Retirement Plan (DB SERP) - several executive officers of Washington Gas participate in the non-funded DB SERP, a nonqualified pension plan. The DB SERP was closed to new entrants beginning January 1, 2010.

· Defined Benefit Restoration Plan (DB Restoration) - a non-funded defined benefit restoration plan for the purpose of providing supplemental pension and pension-related benefits to a select group of management employees of Washington Gas.

Post-retirement Benefit Plans:

· Life Plan - Washington Gas provides life insurance benefits for retired employees of Washington Gas and certain employees of WGL subsidiaries.

· Retiree Medical Plan – under this plan Washington Gas provides medical, prescription drug and dental benefits through Preferred Provider Organization (PPO) or Health Maintenance Organization (HMO) plans for eligible retirees and dependents not yet receiving Medicare benefits.

· Health Reimbursement Account (HRA) Plan – under this plan retirees age 65 and older and dependents receive an annual subsidy to help purchase supplemental medical, prescription drug and dental coverage in the marketplace.

Rabbi trusts have been funded to satisfy the employee benefit obligations associated with WGL’s various pension plans for a total of $89.3 million. These balances are included in prepaid expenses and other current assets and long-term investments and other assets in the Consolidated Balance Sheets. 

The following table summarizes the details of the defined benefit plans, including the SERP and post-retirement plans in Canada and the United States:

		Canada			United States				Total
			Post-				Post-				Post-
	Defined		Retirement		Defined		Retirement		Defined		Retirement
Year ended December 31, 2018	Benefit		Benefits		Benefit		Benefits		Benefit		Benefits
Accrued benefit obligation
Balance, beginning of year	$	165.6	$	15.8	$	303.8	$	82.7	$	469.4	$	98.5
Plans disposed (note 4)		(132.1)		(13.6)		—		—		(132.1)		(13.6)
Actuarial gain		(0.8)		(0.1)		(67.7)		(33.8)		(68.5)		(33.9)
Current service cost		2.4		0.1		16.2		5.3		18.6		5.4
Member contributions		—		—		—		2.1		—		2.1
Interest cost		1.2		0.1		38.0		10.9		39.2		11.0
Benefits paid		(2.7)		—		(43.2)		(13.4)		(45.9)		(13.4)
Expenses paid		—		—		(0.9)		(0.1)		(0.9)		(0.1)
Plan combinations		0.7		—		1,311.7		382.9		1,312.4		382.9
Plan amendments		—		(0.4)		—		—		—		(0.4)
Foreign exchange translation		—		—		77.4		21.4		77.4		21.4
Balance, end of year	$	34.3	$	1.9	$	1,635.3	$	458.0	$	1,669.6	$	459.9
Plan assets
Fair value, beginning of year	$	115.2	$	8.1	$	248.7	$	70.8	$	363.9	$	78.9
Plans disposed (note 4)		(102.1)		(8.1)		—		—		(102.1)		(8.1)
Actual return on plan assets		(0.3)		—		(54.7)		(37.2)		(55.0)		(37.2)
Employer contributions		3.4		—		7.6		2.5		11.0		2.5
Member contributions		—		—		—		2.1		—		2.1
Benefits paid		(2.7)		—		(43.2)		(13.4)		(45.9)		(13.4)
Expenses paid		—		—		(0.9)		(0.1)		(0.9)		(0.1)
Plan combinations		0.3		—		1,133.2		732.7		1,133.5		732.7
Foreign exchange translation		—		—		63.4		33.8		63.4		33.8
Fair value, end of year	$	13.8	$	—	$	1,354.1	$	791.2	$	1,367.9	$	791.2
Net amount recognized	$	(20.5)	$	(1.9)	$	(281.2)	$	333.2	$	(301.7)	$	331.3

		Canada			United States				Total
			Post-				Post-				Post-
	Defined		Retirement		Defined		Retirement		Defined		Retirement
Year ended December 31, 2017	Benefit		Benefits		Benefit		Benefits		Benefit		Benefits
Accrued benefit obligation
Balance, beginning of year	$	150.0	$	16.4	$	290.5	$	72.7	$	440.5	$	89.1
Actuarial loss (gain)		8.3		(1.6)		23.2		14.4		31.5		12.8
Current service cost		7.9		0.7		8.0		1.8		15.9		2.5
Member contributions		0.2		—		—		—		0.2		—
Interest cost		5.8		0.6		11.7		2.9		17.5		3.5
Benefits paid		(6.3)		(0.3)		(8.6)		(3.2)		(14.9)		(3.5)
Expenses paid		(0.3)		—		(0.8)		(0.1)		(1.1)		(0.1)
Plan settlements		—		—		—		(0.5)		—		(0.5)
Foreign exchange translation		—		—		(20.2)		(5.3)		(20.2)		(5.3)
Balance, end of year	$	165.6	$	15.8	$	303.8	$	82.7	$	469.4	$	98.5
Plan assets
Fair value, beginning of year	$	101.5	$	6.8	$	226.9	$	67.2	$	328.4	$	74.0
Actual return on plan assets		8.5		0.4		37.9		11.0		46.4		11.4
Employer contributions		11.6		1.2		9.5		0.6		21.1		1.8
Member contributions		0.2		—		—		—		0.2		—
Benefits paid		(6.3)		(0.3)		(8.6)		(3.2)		(14.9)		(3.5)
Expenses paid		(0.3)		—		(0.8)		(0.1)		(1.1)		(0.1)
Foreign exchange translation		—		—		(16.2)		(4.7)		(16.2)		(4.7)
Fair value, end of year	$	115.2	$	8.1	$	248.7	$	70.8	$	363.9	$	78.9
Net amount recognized	$	(50.4)	$	(7.7)	$	(55.1)	$	(11.9)	$	(105.5)	$	(19.6)

The following amounts were included in the Consolidated Balance Sheets:

	December 31, 2018						December 31, 2017
				Post-						Post-
		Defined		Retirement				Defined		Retirement
		Benefit		Benefits		Total		Benefit		Benefits		Total
Prepaid post-retirement benefits	$	—	$	341.4	$	341.4	$	—	$	—	$	—
Accounts payable and accrued liabilities		(27.6)		—		(27.6)		(0.6)		—		(0.6)
Future employee obligations		(273.9)		(10.3)		(284.2)		(104.9)		(19.6)		(124.5)
	$	(301.5)	$	331.1	$	29.6	$	(105.5)	$	(19.6)	$	(125.1)

The funded status based on the accumulated benefit obligation for all defined benefit plans were:

		December 31, 2018				December 31, 2017
		Canada		United States		Canada		United States
Accumulated benefit obligation (a)	$	(32.9)	$	(1,525.6)	$	(143.9)	$	(274.2)
Fair value of plan assets		13.8		1,354.1		115.2		248.7
Funded status	$	(19.1)	$	(171.5)	$	(28.7)	$	(25.5)

(a) Accumulated benefit obligation differs from accrued benefit obligation in that it does not include an assumption with respect to future compensation levels.

The following amounts were not recognized in the net periodic benefit cost and recorded in the other comprehensive Income (losses):

		Canada			United States				Total
			Post-				Post-				Post-
	Defined		Retirement		Defined		Retirement		Defined		Retirement
Year ended December 31, 2018	Benefit		Benefits		Benefit		Benefits		Benefit		Benefits
Past service cost	$	(0.3)	$	0.4	$	(0.2)	$	—	$	(0.5)	$	0.4
Net actuarial loss		(8.7)		(0.5)		(10.7)		(5.0)		(19.4)		(5.5)
Recognized in AOCI pre-tax	$	(9.0)	$	(0.1)	$	(10.9)	$	(5.0)	$	(19.9)	$	(5.1)
Increase by the amount    included in deferred tax liabilities		2.4		—		2.2		1.4		4.6		1.4
Net amount in AOCI after-tax	$	(6.6)	$	(0.1)	$	(8.7)	$	(3.6)	$	(15.3)	$	(3.7)

		Canada			United States				Total
			Post-				Post-				Post-
	Defined		Retirement		Defined		Retirement		Defined		Retirement
Year ended December 31, 2017	Benefit		Benefits		Benefit		Benefits		Benefit		Benefits
Past service cost	$	(0.4)	$	—	$	—	$	—	$	(0.4)	$	—
Net actuarial loss		(13.9)		(1.3)		—		—		(13.9)		(1.3)
Recognized in AOCI pre-tax	$	(14.3)	$	(1.3)	$	—	$	—	$	(14.3)	$	(1.3)
Increase (decrease) by the amount    included in deferred tax liabilities		4.0		0.3		(0.1)		—		3.9		0.3
Net amount in AOCI after-tax	$	(10.3)	$	(1.0)	$	(0.1)	$	—	$	(10.4)	$	(1.0)

The following amounts were not recognized in the net periodic benefit cost and recorded in a regulatory asset (liability):

		Canada			United States				Total
			Post-				Post-				Post-
	Defined		Retirement		Defined		Retirement		Defined		Retirement
Year ended December 31, 2018	Benefit		Benefits		Benefit		Benefits		Benefit		Benefits
Past service cost	$	—	$	—	$	0.8	$	(110.2)	$	0.8	$	(110.2)
Net actuarial gain (loss)		—		—		188.2		(52.6)		188.2		(52.6)
Recognized in regulatory asset (liability)	$	—	$	—	$	189.0	$	(162.8)	$	189.0	$	(162.8)

		Canada			United States				Total
			Post-				Post-				Post-
	Defined		Retirement		Defined		Retirement		Defined		Retirement
Year ended December 31, 2017	Benefit		Benefits		Benefit		Benefits		Benefit		Benefits
Past service cost	$	—	$	—	$	(1.2)	$	5.6	$	(1.2)	$	5.6
Net actuarial gain (loss)		(30.6)		0.4		(74.0)		(12.8)		(104.6)		(12.4)
Recognized in regulatory asset (liability)	$	(30.6)	$	0.4	$	(75.2)	$	(7.2)	$	(105.8)	$	(6.8)

The costs of the defined benefit and post-retirement benefit plans are based on Management's estimate of the future rate of return on the fair value of pension plan assets, salary escalations, mortality rates and other factors affecting the payment of future benefits.

				Post-
		Defined		Retirement
Amounts to be amortized in the next fiscal year from AOCI		Benefit		Benefits
Past service costs	$	0.1	$	0.2
Actuarial losses		0.5		—
Total	$	0.6	$	0.2

				Post-
Amounts to be amortized in the next fiscal year from regulatory		Defined		Retirement
assets (liabilities)		Benefit		Benefits
Past service costs	$	0.2	$	(21.3)
Actuarial losses		9.1		0.1
Total	$	9.3	$	(21.2)

The net pension expense by plan for the period was as follows:

	Year ended December 31, 2018
		Canada				United States				Total
			Post-				Post-				Post-
	Defined		retirement		Defined		retirement		Defined		retirement
	Benefit		Benefits		Benefit		Benefits		Benefit		Benefits
Current service cost (a)	$	2.4	$	0.1	$	16.2	$	5.3	$	18.6	$	5.4
Interest cost (b)		1.2		0.1		38.0		10.9		39.2		11.0
Expected return on plan assets (b)		(0.5)		—		(49.9)		(21.6)		(50.4)		(21.6)
Amortization of past service cost (b)		0.1		—		—		—		0.1		—
Amortization of net actuarial loss (b)		0.6		—		—		—		0.6		—
Amortization of regulatory asset (b)		—		—		7.8		(11.1)		7.8		(11.1)
Net benefit cost (income) recognized	$	3.8	$	0.2	$	12.1	$	(16.5)	$	15.9	$	(16.3)

(a) Recorded under the line item “Operating and administrative” expenses on the Consolidated Statements of Income.

(b) Recorded under the line item “Other Income” on the Consolidated Statements of Income.

	Year ended December 31, 2017
		Canada				United States				Total
			Post-				Post-				Post-
	Defined		retirement		Defined		retirement		Defined		retirement
	Benefit		Benefits		Benefit		Benefits		Benefit		Benefits
Current service cost (a)	$	7.9	$	0.7	$	8.0	$	1.8	$	15.9	$	2.5
Interest cost (b)		5.8		0.6		11.7		2.9		17.5		3.5
Expected return on plan assets (b)		(5.9)		(0.2)		(16.9)		(4.7)		(22.8)		(4.9)
Settlement of plan (b)		—		—		—		0.2		—		0.2
Amortization of past service cost (b)		0.2		—		—		—		0.2		—
Amortization of net actuarial loss (b)		0.7		—		—		—		0.7		—
Amortization of regulatory asset/liability (b)		1.3		0.1		6.5		(0.3)		7.8		(0.2)
Net benefit cost (income) recognized	$	10.0	$	1.2	$	9.3	$	(0.1)	$	19.3	$	1.1

(a) Recorded under the line item “Operating and administrative” expenses on the Consolidated Statements of Income.

(b) Recorded under the line item “Other Income” on the Consolidated Statements of Income.

The objective of the Corporation's investment policy is to maximize long-term total return while protecting the capital value of the fund from major market fluctuations through diversification and selection of investments.

The objective for fund returns, over three to five-year periods, is the sum of two components - a passive component, which is the benchmark index market returns for the asset mix in effect, plus the added value expected from active management. It is the Corporation’s belief that the potential additional returns justify the additional risk associated with active management. The risk inherent in the investment strategy over a market cycle (a three-to five-year period) is two-fold. There is a risk that the market returns, as measured by the benchmark returns, will not be in line with expectations. The other risk is that the expected added value of active management over passive management will not be realized over the time period prescribed in each fund manager's mandate. There is also the risk of annual volatility in returns, which means that in any one year the actual return may be very different from the expected return.

Cash and money market investments may be held from time to time as short-term investment decisions at the discretion of the fund manager(s) within the constraints prescribed by their mandate(s).

The Corporation has a target asset mix for the Canadian plans of 45 percent to 55 percent fixed income assets. The target asset mix for SEMCO plans is 33 percent fixed income assets and for WGL plans is 40 percent to 55 percent fixed income assets. These objectives have taken into account the nature of the liabilities and the risk-reward tolerance of the Corporation.

The collective investment mixes for the plans are as follows as at December 31, 2018:

Canada		Fair value		Level 1		Level 2	Percentage of Plan Assets (%)
Cash and short-term equivalents	$	1.7	$	1.7	$	—	12.3
Canadian equities		3.7		3.7		—	26.8
Foreign equities		2.1		2.1		—	15.2
Fixed income		5.5		5.5		—	39.9
Real estate		0.8		—		0.8	5.8
	$	13.8	$	13.0	$	0.8	100.0
United States		Fair value		Level 1		Level 2	Percentage of Plan Assets (%)
Cash and short-term equivalents	$	6.3	$	6.3	$	—	0.3
Canadian equities		2.1		2.1		—	0.1
Foreign equities (a)		273.2		270.6		2.6	12.7
Fixed income		850.1		99.2		750.9	39.6
Derivatives		9.3		—		9.3	0.4
Other		10.9		—		10.9	0.5
Total investments in the fair value hierarchy	$	1,151.9		378.2		773.7	53.6
Investments measured at net asset value using the NAV practical expedient (b)
Commingled funds and pooled separate accounts (c)		945.3					44.2
Private Equity/Limited Partnership (d)		48.2					2.2
Total fair value of plan investments	$	2,145.4					100.0
Net payable (e)		(0.1)					—
	$	2,145.3					100.0

(a) Investments in foreign equities include U.S. and international securities.

(b) In accordance with ASC Topic 820, these investments are measured at fair value using net asset value (NAV) per share as a practical expedient and, therefore, have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliations of the fair value hierarchy to the statements of net assets available for plan benefits.

(c) As of December 31, 2018, investments in commingled funds and a pooled separate account consisted of approximately 89 percent common stock U.S. companies; 10 percent income producing properties located in the United States; and 1 percent short-term money market investments for WGL’s defined benefit plans and 54 percent of common stock of large-cap U.S. companies, 20 percent of U.S. Government fixed income securities and 26 percent of corporate bonds for WGL’s post-retirement benefit plans.

(d) At December 31, 2018, investments in a private equity/limited partnership consisted of common stock of international companies.

(e) At December 31, 2018, this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable.

Total		Fair value		Level 1		Level 2	Percentage of Plan Assets (%)
Cash and short-term equivalents	$	8.0	$	8.0	$	—	0.4
Canadian equities		5.8		5.8		—	0.3
Foreign equities (a)		275.3		272.7		2.6	12.8
Fixed income		855.6		104.7		750.9	39.6
Derivatives		9.3		—		9.3	0.4
Real estate		0.8		—		—	—
Other		10.9		—		11.7	0.5
Total investments in the fair value hierarchy	$	1,165.7	$	391.2	$	774.5	54.0
Investments measured at net asset value using the NAV practical expedient (b)
Commingled funds and pooled separate accounts (c)		945.3					43.8
Private Equity/Limited Partnership (d)		48.2					2.2
Total fair value of plan investments	$	2,159.2					100.0
Net payable (e)		(0.1)					—
	$	2,159.1					100.0

(a) Investments in foreign equities include U.S. and international securities.

(b) In accordance with ASC Topic 820, these investments are measured at fair value using net asset value (NAV) per share as a practical expedient and, therefore, have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliations of the fair value hierarchy to the statements of net assets available for plan benefits.

(c) As of December 31, 2018, investments in commingled funds and a pooled separate account consisted of approximately 89 percent common stock U.S. companies; 10 percent income producing properties located in the United States; and 1 percent short-term money market investments for WGL’s defined benefit plans and 54 percent of common stock of large-cap U.S. companies, 20 percent of U.S. Government fixed income securities and 26 percent of corporate bonds for WGL’s post-retirement benefit plans.

(d) At December 31, 2018, investments in a private equity/limited partnership consisted of common stock of international companies.

(e) At December 31, 2018, this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable.

		Post-		Post-
Significant actuarial assumptions used in measuring	Defined	Retirement	Defined	Retirement
net benefit plan costs	Benefit	Benefits	Benefit	Benefits
Year ended December 31	2018		2017
Discount rate (%)	3.25 - 4.30	3.60 - 4.30	2.65 - 4.20	4.00 - 4.20
Expected long-term rate of return on plan assets (%) (a)	3.20 - 7.60	3.75 - 7.60	6.18 - 7.30	3.10 - 7.30
Rate of compensation increase (%)	2.75 - 4.10	4.10	2.75 - 4.00	3.25
Average remaining service life of active employees (years)	9.6	14.1	12.7	13.5
(a) Only applicable for funded plans
		Post-		Post-
Significant actuarial assumptions used in measuring	Defined	Retirement	Defined	Retirement
benefit obligations	Benefit	Benefits	Benefit	Benefits
As at December 31	2018		2017
Discount rate (%)	3.60 - 4.40	3.90 - 4.50	2.80 - 3.70	3.60 - 3.70
Rate of compensation increase (%)	2.75 - 4.10	4.10	2.75 - 4.00	3.25

The expected rate of return on assets is based on the current level of expected returns on risk free investments, the historical level of risk premium associated with other asset classes in which the portfolio is invested, and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based on the target asset allocation to develop the expected rate of return on assets assumption for the portfolio. 

The discount rate is based on high-quality long-term corporate bonds, with maturities matching the estimated timing and amount of expected benefit payments.

The estimates for health care benefits take into consideration increased health care benefits due to aging and cost increases in the future. The assumed health care cost trend rates used to measure the expected cost of benefits for the next year were between 6.4 and 6.5 percent. The health care cost trend rates were assumed to decline to between 2.1 and 5 percent by 2024.

The assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one percentage point change in the assumed health care trend rates would have the following effects for 2018:

		Increase		Decrease
Service and interest costs	$	1.7	$	(1.3)
Accrued benefit obligation	$	19.8	$	(16.0)

The following table shows the expected cash flows for defined benefit pension and other-post retirement plans:

				Post-
		Defined		Retirement
		Benefit		Benefits
Expected employer contributions:
2019	$	41.4	$	0.1
Expected benefit payments:
2019	$	109.8	$	25.3
2020		92.2		24.6
2021		95.3		25.0
2022		101.0		25.4
2023		99.4		25.5
2024 - 2028	$	521.9	$	130.9

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COMMITMENTS, CONTINGENCIES AND GUARANTEES

12 Months Ended

Dec. 31, 2018

COMMITMENTS, CONTINGENCIES AND GUARANTEES [Abstract]

COMMITMENTS, CONTINGENCIES AND GUARANTEES

29.  COMMITMENTS, CONTINGENCIES AND GUARANTEES

Commitments

AltaGas has long-term natural gas purchase and transportation arrangements, electricity purchase arrangements, service agreements, storage contracts, environmental commitments, and operating leases for office space, office equipment, rail cars, and automobile equipment, all of which are transacted at market prices and in the normal course of business.

In connection with the WGL Acquisition, AltaGas and WGL have made commitments related to the terms of the PSC of DC settlement agreement and the conditions of approval from the PSC of MD and the SCC of VA. Among other things, these commitments include rate credits distributable to both residential and non-residential customers, gas expansion and other programs, various public interest commitments, and safety programs. The total amount expensed in 2018 was approximately US$140 million, of which US$111 million has been paid as of December 31, 2018. In addition, there are certain additional regulatory commitments which will be expensed when the costs are incurred in the future, including the hiring of damage prevention trainers, investment of US$70 million over a 10 year period to further extend natural gas service, and US$8 million for leak mitigation.

Future payments of these commitments at December 31, 2018 are estimated as follows:

	2019		2020		2021		2022		2023		2024 and beyond		Total
Gas purchase(a)	$	3,157.1	$	2,940.5	$	2,639.3	$	2,527.4	$	2,349.9	$	30,309.2	$	43,923.4
Electricity purchase(c)		533.1		368.6		139.2		38.6		5.7		0.4		1,085.6
Service agreements(b)(d)		74.3		48.2		30.9		17.3		14.8		168.0		353.5
Pipeline and storage services(e)		861.6		862.2		818.8		795.6		781.7		4,645.3		8,765.2
Capital projects(f)		119.2		—		—		—		—		—		119.2
Operating leases(g)		23.9		30.9		29.4		28.0		25.8		164.8		302.8
Environmental(h)		6.1		4.7		3.0		0.5		0.4		0.5		15.2
Merger commitments		29.3		30.8		22.8		19.2		19.2		62.1		183.4
	$	4,804.6	$	4,285.9	$	3,683.4	$	3,426.6	$	3,197.5	$	35,350.3	$	54,748.3

(a) AltaGas enters into contracts to purchase natural gas from various suppliers for its utilities. These contracts are used to ensure that there is an adequate supply of natural gas to meet the needs of customers and to minimize exposure to market price fluctuations. Gas purchase commitments are valued based on forward prices, which may fluctuate significantly from period to period.

(b) In 2014, AltaGas' Blythe facility entered into a Long-Term Service Agreement with Siemens to complete various upgrade and maintenance services on the Combustion Turbines (CT) at the Blythe facility over 124,000 equivalent operating hour per CT, or 25 years, whichever comes first. The LTSA has fixed fees that will be incurred in the five years following December 31, 2014 and variable fees on a per equivalent operating hour basis. As at December 31, 2018, the total commitment was $190.9 million payable over the next 16 years, of which $59.6 million is expected to be paid over the next five years. 

(c) AltaGas enters into contracts to purchase electricity from various suppliers for its utilities.Electricity purchase commitments are based on existing fixed price and fixed volume contracts, and include $44.1 million of commitments related to renewable energy credits.

(d) In 2017, AltaGas entered into a 12-year service agreement for tug services to support the marine operations of RIPET. AltaGas is obligated to pay fixed and variable fees of approximately $60.1 million over the term of the contract.

(e) Pipeline and storage commitments include minimum payments for natural gas transportation, storage and peaking contracts that have expiration dates through 2044.

(f) Commitments for capital projects. Estimated amounts are subject to variability depending on the actual construction costs.

(g) Operating leases include lease arrangements for office spaces, vehicles, rail cars, land, office and other equipment.

(h) Environmental commitments relate to future costs associated with sites where AltaGas or its predecessors may have operated manufactured gas plants.

Guarantees

AltaGas has guaranteed payments primarily for certain commitments on behalf of some of its subsidiaries. AltaGas has also guaranteed payments for certain of its external partners. As at December 31, 2018, AltaGas has no guarantees to external parties.

Contingencies

AltaGas and its subsidiaries are subject to various legal claims and actions arising in the normal course of business. While the final outcome of such legal claims and actions cannot be predicted with certainty, the Corporation does not believe that the resolution of such claims and actions will have a material impact on the Corporation’s consolidated financial position or results of operations.

As a result of the WGL Acquisition, AltaGas has the following additional contingencies:

Antero Contract 

Washington Gas and WGL Midstream contracted in June 2014 with Antero Resources Corporation (Antero) to buy gas from Antero at invoiced prices based on an index, and at a delivery point, specified in the contracts. Since deliveries began, however, the index price paid has been more than the fair market value at the same physical delivery point, resulting in losses within WGL entities of approximately US$40 million. Accordingly, Washington Gas and WGL Midstream notified Antero that it sought to apply a provision of the contracts that would permit a new index to be established. Antero objected, claiming that the contract provisions permitting re-pricing did not apply, unless Antero itself chose to sell gas at cheaper prices at the delivery point (which Antero claimed it had not). The dispute was arbitrated in January 2017, and the arbitral tribunal ruled in favor of Antero on the applicability of the re-pricing mechanism. However, the tribunal ruled that it lacked authority to determine whether Antero was in breach of its obligation to deliver gas to Washington Gas and WGL Midstream at a point where they could obtain the higher pricing. Accordingly, Washington Gas and WGL Midstream filed suit in state court in Colorado for a determination of this issue. The state court initially granted Antero’s motion to dismiss the case and WGL subsequently filed an appeal. In October 2018, the Court of Appeals reversed the state court’s decision and remanded the lawsuit to the trial court.

Separately, Antero has initiated suit against Washington Gas and WGL Midstream, claiming that they have failed to purchase specified daily quantities of gas and seeking alleged cover damages exceeding US$100 million as of April 4, 2018 according to Antero’s complaint. Washington Gas and WGL Midstream oppose both the validity and amount of Antero’s claim. WGL believes the probability that Antero could succeed in collecting these penalties is remote therefore no accrual was made as of December 31, 2018. In December 2017, WGL Midstream amended its purchase contract with Antero and, effective February 1, 2018, is no longer obligated to purchase gas at the delivery point that is the subject of these disputes.

These two cases have been consolidated and a jury trial has been scheduled for June 10, 2019.

Silver Spring, Maryland Incident 

Washington Gas has continually worked with the National Transportation and Safety Board (NTSB) to support its investigation of the August 2016 explosion and fire at an apartment complex on Arliss Street in Silver Spring, Maryland, the cause of which has not been determined. Additional information will be made available by the NTSB at the appropriate time. A total of 40 civil actions related to the incident have been filed against WGL and Washington Gas in the Circuit Court for Montgomery County, Maryland. All of these suits seek unspecified damages for personal injury and/or property damage. The one class action suit filed against WGL and Washington Gas was amended to assert property damage and loss of use claims. WGL maintains excess liability insurance coverage from highly-rated insurers, subject to a nominal self-insured retention and expects this coverage will be sufficient to cover any significant liability to it that may result from this incident. Management is unable to determine a range of potential losses that is reasonably possible of occurring and therefore has not recorded a reserve associated with this incident. Washington Gas was invited by the NTSB to be a party to the investigation and in that capacity, continues to work closely with the NTSB.The NTSB has scheduled a hearing for April 23, 2019 to determine the probable cause of the incident.

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RELATED PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2018

RELATED PARTY TRANSACTIONS [Abstract]

RELATED PARTY TRANSACTIONS

30.  RELATED PARTY TRANSACTIONS

In the normal course of business, AltaGas transacts with its subsidiaries, affiliates and joint ventures. Amounts due to or from related parties on the Consolidated Balance Sheets were measured at the exchange amount and were as follows:

As at	December 31, 2018		December 31, 2017
Due from related parties
Accounts receivable (a)	$	60.8	$	0.8
Long-term investments and other assets (b)		45.0		75.0
	$	105.8	$	75.8
Due to related parties
Accounts payable (c)		6.3		3.2
Risk management liabilities - current (d)		0.9		—
	$	7.2	$	3.2

(a) Receivables from joint ventures and ACI.

(b) AltaGas has provided a $100.0 million interest bearing secured loan facility to Petrogas of which $50.0 million is committed. The facility is available for Petrogas to draw upon from time to time for general corporate purposes. The facility is subject to annual renewal and has a maturity date of June 27, 2021. As at December 31, 2018, Petrogas had drawn $45.0 million (December 31, 2017 - $75.0 million) under the facility.

(c) Payables to ACI and a joint venture.

(d) Foreign exchange hedge with ACI.

The following transactions with related parties have been recorded on the Consolidated Statements of Income for the year ended December 31, 2018 and 2017:

Year ended December 31		2018		2017
Revenue (a)	$	68.4	$	15.0
Cost of sales (b)	$	(4.2)	$	(6.5)
Operating and administrative expenses (c)	$	1.3	$	—
Other income (d)	$	9.2	$	4.4

(a) In the ordinary course of business, AltaGas sold natural gas and natural gas liquids to a joint venture and ACI.  In addition, subsequent to the IPO of ACI, AltaGas is providing certain day-to-day services to ACI under a Transition Services Agreement on a cost recovery basis. The Transition Services Agreement will operate until June 30, 2020, subject to earlier termination in certain circumstances, and is extendable by mutual agreement of the parties. Revenue also includes an unrealized loss on a foreign exchange hedge with ACI of $0.2 million in 2018 (2017 - $nil).  

(b) In the ordinary course of business, AltaGas obtained natural gas storage services from a joint venture as well as incurred costs related to the sale of natural gas liquids to affiliates.

(c) Administrative costs recovered from joint ventures. In 2017, amount was offset by the expense associated with the forgiveness of a loan to an executive.

(d) Interest income fromloans to Petrogas (secured loan facility) and loans to ACI. Subsequent to the IPO of ACI, AltaGas provided certain loans to ACI for a portion of the year. Loans to ACI were fully repaid by December 31, 2018.

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SUPPLEMENTAL CASH FLOW INFORMATION

12 Months Ended

Dec. 31, 2018

SUPPLEMENTAL CASH FLOW INFORMATION [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

31.  SUPPLEMENTAL CASH FLOW INFORMATION

The following table details the changes in operating assets and liabilities from operating activities:

	Year ended December 31
	2018		2017
Source (use) of cash:
Accounts receivable	$	(526.9)	$	(55.6)
Inventory		(100.8)		4.7
Other current assets		12.5		7.0
Regulatory assets (current)		(15.8)		(0.2)
Accounts payable and accrued liabilities		237.9		85.4
Customer deposits		(13.3)		(2.8)
Regulatory liabilities (current)		69.2		(4.8)
Other current liabilities		(5.9)		13.0
Other operating assets and liabilities		(143.4)		(44.8)
Changes in operating assets and liabilities	$	(486.5)	$	1.9

The following cash payments have been included in the determination of earnings:

	Year ended December 31
	2018		2017
Interest paid (net of capitalized interest)	$	288.9	$	151.1
Income taxes paid	$	36.9	$	36.3

The following table is a reconciliation of cash and restricted cash balances:

As at December 31		2018		2017
Cash and cash equivalents	$	101.6	$	27.3
Restricted cash holdings from customers - current		4.1		8.9
Restricted cash holdings from customers - non-current		6.1		7.5
Restricted cash included in prepaid expenses and other current assets(a)		27.6		—
Restricted cash included in long-term investments and other assets(a)		61.7		—
Cash, cash equivalents and restricted cash per consolidated statement of cash flow	$	201.1	$	43.7

(a) The restricted cash balances included in prepaid expenses and other current assets and long-term investments and other assets relates to Rabbi trusts associated with WGL’s pension plans (Note 28). On the date of the WGL Acquisition, the restricted cash balances related to Rabbi trusts was $81.0 million.

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SEGMENTED INFORMATION

12 Months Ended

Dec. 31, 2018

SEGMENTED INFORMATION [Abstract]

SEGMENTED INFORMATION

32.  SEGMENTED INFORMATION

AltaGas owns and operates a portfolio of assets and services used to move energy from the source to the end-user. The following describes the Corporation’s four reporting segments:

Utilities	–     – –	rate-regulated natural gas distribution assets in Michigan, Alaska, the District of Columbia, Maryland, and Virginia; rate-regulated natural gas storage in the United States; and equity investment in AltaGas Canada Inc.
Midstream	–	NGL processing and extraction plants;
	–	transmission pipelines to transport natural gas and NGL;
	–	natural gas gathering lines and field processing facilities;
	–	purchase and sale of natural gas;
	–	natural gas storage facilities;
	–    –	liquefied petroleum gas (LPG) terminal currently under construction; natural gas and NGL marketing;
	–	equity investment in Petrogas, a North American entity engaged in the marketing, storage and distribution of NGL, drilling fluids, crude oil and condensate diluents;
	–	interests in four regulated gas pipelines in the Marcellus/Utica basins; and
	–	sale of natural gas to residential, commercial and industrial customers in Washington D.C., Maryland, Virginia, Delaware, and Pennsylvania.
Power	–	natural gas-fired, biomass, and solar power generation assets, whereby outputs are generally sold under power purchase agreements, both operational and under development;
	–	energy storage; and
–		sale of power to residential, commercial and industrial users in Washington D.C., Maryland, Virginia, Delaware, and Pennsylvania.
Corporate	–	the cost of providing corporate services, financing and general corporate overhead, investments in certain public and private entities, corporate assets, financing other segments and the effects of changes in the fair value of certain risk management contracts.

The following table provides a reconciliation of segment revenue to the disaggregated revenue table as disclosed under Note 23:

	Year ended December 31, 2018
	Utilities		Midstream		Power		Corporate		Total
External revenue (note 23)	$	1,752.6	$	1,344.6	$	1,162.0	$	(2.5)	$	4,256.7
Intersegment revenue		13.0		90.4		9.0		0.1		112.5
Segment revenue	$	1,765.6	$	1,435.0	$	1,171.0	$	(2.4)	$	4,369.2

Geographic Information

Year ended December 31		2018		2017
Revenue(a)
Canada	$	1,626.8	$	1,508.8
United States		2,553.0		1,109.9
Total	$	4,179.8	$	2,618.7

(a) Operating revenue from external customers, excluding unrealized gains (losses) on risk management contracts.

As at December 31		2018		2017
Property, plant and equipment
Canada	$	2,348.2	$	4,320.5
United States		8,581.4		2,369.3
Total	$	10,929.6	$	6,689.8

The following tables show the composition by segment:

	Year ended December 31, 2018
	Utilities		Midstream		Power		Corporate		Intersegment Elimination(a)		Total
Segment revenue	$	1,765.6	$	1,435.0	$	1,171.0	$	(2.4)	$	(112.5)	$	4,256.7
Cost of sales		(838.3)		(976.4)		(743.7)		—		103.1		(2,455.3)
Operating and administrative		(727.4)		(201.7)		(159.1)		(50.6)		9.8		(1,129.0)
Accretion expenses		(0.1)		(4.0)		(6.8)		—		—		(10.9)
Depreciation and amortization		(165.8)		(84.4)		(130.5)		(13.3)		—		(394.0)
Provisions on assets (note 10)		(193.7)		(153.7)		(381.3)		—		—		(728.7)
Income from equity investments		7.2		51.1		(10.4)		—		—		47.9
Other income (loss)		4.5		0.7		(5.9)		2.0		(0.4)		0.9
Foreign exchange gains		—		(0.2)		(0.1)		4.8		—		4.5
Interest expense		(103.9)		(10.6)		(8.9)		(185.6)		—		(309.0)
Loss before income taxes	$	(251.9)	$	55.8	$	(275.7)	$	(245.1)	$	—	$	(716.9)
Net additions (reductions) to:
Property, plant and equipment(b)	$	507.0	$	383.4	$	(321.9)	$	4.0	$	—	$	572.5
Intangible assets	$	21.8	$	4.7	$	12.5	$	6.7	$	—	$	45.7

(a) Intersegment transactions are recorded at market value.

(b) Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statement of Cash flow due to classification of business acquisition and foreign exchange changes on U.S. assets.

	Year ended December 31, 2017
	Utilities		Midstream		Power		Corporate		Intersegment Elimination(a)		Total
Segment revenue	$	1,126.7	$	1,008.0	$	631.7	$	(58.4)	$	(151.8)	$	2,556.2
Cost of sales		(610.1)		(647.0)		(242.8)		—		142.8		(1,357.1)
Operating and administrative		(226.1)		(165.0)		(93.1)		(97.5)		9.5		(572.2)
Accretion expenses		(0.1)		(3.9)		(6.9)		—		—		(10.9)
Depreciation and amortization		(81.8)		(68.6)		(118.0)		(14.0)		—		(282.4)
Provision on assets		—		(6.6)		(133.0)		—		—		(139.6)
Income from equity investments		2.6		22.0		6.8		—		—		31.4
Other income (loss)		3.9		(0.9)		0.8		6.3		(0.5)		9.6
Foreign exchange gains		—		0.2		—		1.5		—		1.7
Interest expense		—		—		—		(170.3)		—		(170.3)
Income (loss) before income taxes	$	215.1	$	138.2	$	45.5	$	(332.4)	$	—	$	66.4
Net additions (reductions) to:
Property, plant and equipment(b)	$	124.3	$	245.3	$	16.5	$	1.5	$	—	$	387.6
Intangible assets	$	2.1	$	2.8	$	13.2	$	2.2	$	—	$	20.3

(a) Intersegment transactions are recorded at market value.

(b) Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statement of Cash flow due to classification of business acquisition and foreign exchange changes on U.S. assets.

The following table shows goodwill and total assets by segment:

	Utilities		Midstream		Power		Corporate		Total
As at December 31, 2018
Goodwill	$	3,450.8	$	426.4	$	191.0	$	—	$	4,068.2
Segmented assets	$	12,991.3	$	6,398.8	$	3,814.7	$	282.9	$	23,487.7
As at December 31, 2017
Goodwill	$	664.7	$	152.6	$	—	$	—	$	817.3
Segmented assets	$	3,460.2	$	3,096.8	$	3,192.5	$	282.7	$	10,032.2

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SUBSEQUENT EVENTS

12 Months Ended

Dec. 31, 2018

SUBSEQUENT EVENTS [Abstract]

SUBSEQUENT EVENTS

33.  SUBSEQUENT EVENTS

Subsequent events have been reviewed through February 27, 2019, the date these Consolidated Financial Statements were issued.  On January 31, 2019, AltaGas completed the sale of its remaining interest in the Northwest Hydro facilities for net proceeds of approximately $1.37 billion. On February 1, 2019, AltaGas completed the sale of non-core Midstream and Power assets in Canada.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2018

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract]

BASIS OF PRESENTATION

BASIS OF PRESENTATION

These Consolidated Financial Statements have been prepared by Management in accordance with United States Generally Accepted Accounting Principles (U.S. GAAP).

Pursuant to National Instrument 52-107, "Acceptable Accounting Principles and Auditing Standards" (NI 52-107), financial statements of an “SEC issuer” may be prepared in accordance with U.S. GAAP. On July 13, 2018, AltaGas filed a final short form base shelf prospectus in Alberta and a corresponding registration statement on Form F-10 in the United States, by virtue of which AltaGas is now required to file reports under section 15(d) of the Securities Exchange Act of 1934 with the United States Securities and Exchange Commission. As a result, AltaGas became an SEC issuer at such time and is now entitled to prepare its financial statements in accordance with U.S. GAAP.

PRINCIPLES OF CONSOLIDATION

PRINCIPLES OF CONSOLIDATION

These Consolidated Financial Statements of AltaGas include the accounts of the Corporation, its subsidiaries, variable interest entities (VIEs) for which the Corporation is the primary beneficiary, and its interest in various partnerships and joint ventures where AltaGas has an undivided interest in the assets and liabilities. Investments in unconsolidated companies that AltaGas has significant influence over, but not control, are accounted for using the equity method.

Hypothetical Liquidation at Book Value (HLBV) methodology is used for certain WGL equity method investments as well as WGL consolidating equity investments with non-controlling interests when the governing structuring agreement over the equity investment results in different liquidation rights and priorities than what is reflected by the underlying ownership interest percentage.

All intercompany balances and transactions are eliminated on consolidation. Where there is a party with a non-controlling interest in a subsidiary that AltaGas controls, that non-controlling interest is reflected as “non-controlling interests” in the Consolidated Financial Statements. The non-controlling interests in net income (or loss) of consolidated subsidiaries are shown as an allocation of the consolidated net income and are presented separately in "net income applicable to non-controlling interests".

USE OF ESTIMATES AND MEASUREMENT UNCERTAINTY

USE OF ESTIMATES AND MEASUREMENT UNCERTAINTY

The preparation of Consolidated Financial Statements in accordance with U.S. GAAP requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenue and expenses during the period. Key areas where Management has made complex or subjective judgments, when matters are inherently uncertain, include but are not limited to: determining the nature and timing of satisfaction of performance obligations and determining the transaction price and amounts allocated to performance obligations for revenue recognition; depreciation and amortization rates, fair value of asset retirement obligations, fair value of property, plant and equipment and goodwill for impairment assessments, fair value of financial instruments, provisions for income taxes, assumptions used to measure employee future benefits, provisions for contingencies, and carrying value of regulatory assets and liabilities. Certain estimates are necessary for the regulatory environment in which AltaGas' subsidiaries or affiliates operate, which often require amounts to be recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. By their nature, these estimates are subject to measurement uncertainty and may impact the Consolidated Financial Statements of future periods.

Rate-Regulated Operations

Rate-Regulated Operations

SEMCO Gas, ENSTAR, Washington Gas, and Hampshire (collectively Utilities) engage in the delivery, sale, and storage of natural gas. SEMCO Gas and ENSTAR are regulated by the Michigan Public Service Commission (MPSC) and Regulatory Commission of Alaska (RCA), respectively. Washington Gas operates in the District of Columbia, Maryland, and Virginia and is regulated in those jurisdictions by the Public Service Commission of the District of Columbia (PSC of DC), the Maryland Public Service Commission (PSC of MD) and the Commonwealth of Virginia State Corporation Commission (SCC of VA), respectively.  

The MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA exercise statutory authority over matters such as tariffs, rates, construction, operations, financing, returns, accounting and certain contracts with customers. In order to recognize the economic effects of the actions and decisions of the MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA, the timing of recognition of certain assets, liabilities, revenues and expenses as a result of regulation may differ from that otherwise expected using U.S. GAAP for entities not subject to rate regulation. 

Regulatory assets represent future revenues associated with certain costs incurred in the current period or in prior periods that are expected to be recovered from customers in future periods through the rate setting process. Regulatory liabilities represent future reductions or limitations of increases in revenue associated with amounts that are expected to be refunded to customers through the rate setting process.

Cash and Cash Equivalents

Cash and Cash Equivalents

Cash and cash equivalents consist of cash on hand, balances with banks, and investments in money market instruments with original maturities of less than three months.

Restricted Cash Holdings from Customers

Restricted Cash Holdings from Customers

Cash deposited, which is restricted and is not available for general use by AltaGas, is separately presented as restricted cash holdings in the Consolidated Balance Sheets. Pursuant to the acquisition of WGL Holdings, Inc. (the WGL Acquisition), rabbi trust funds were funded to satisfy certain WGL executive and outside director retirement benefit plan obligations. As of December 31, 2018, the rabbi trust funds are invested in money market funds which are considered as cash equivalents. These balances are included in prepaid expenses and other current assets and long-term investments and other assets in the Consolidated Balance Sheets.    

Accounts Receivable

Accounts Receivable

Receivables are recorded net of the allowance for doubtful accounts in the Consolidated Balance Sheets. AltaGas regularly analyzes and evaluates the collectability of the accounts receivable based on a combination of factors. If circumstances related to the collectability change, the allowance for doubtful accounts is further adjusted. Accounts are written off when collection efforts are complete and future recovery is unlikely.

Inventory

Inventory

Inventory consists of materials, supplies, natural gas, renewable energy credits, and emission compliance instruments which are valued at the lower of cost or net realizable value. Cost of inventory is assigned using a weighted average cost formula. In general, commodity costs and variable transportation costs are capitalized as gas in underground storage. Fixed costs, primarily pipeline demand charges and storage charges, are expensed as incurred through the cost of gas.

Property, Plant and Equipment (PP&E), Depreciation and Amortization

Property, Plant, and Equipment (PP&E), Depreciation and Amortization

Property, plant, and equipment are carried at cost. The Corporation depreciates the cost of capital assets, net of salvage value, on a straight-line basis over the estimated useful life of the assets, with the exception of rate regulated utilities assets, where depreciation is calculated on a straight-line basis or over the contract term of a specific agreement at rates as approved by the regulatory authorities. 

The U.S. utilities charge maintenance and repairs directly to operating expense and capitalize betterments and renewal costs. In accordance with regulatory requirements, depreciation expense includes an amount allowed for regulatory purposes to be collected in current rates for future removal and site restoration costs.

Interest costs are capitalized on major additions to property, plant, and equipment until the asset is ready for its intended use. The interest rate used for calculating the interest costs to be capitalized is based on AltaGas' prior quarter actual borrowing long-term interest rate.

Utilities capitalize an imputed carrying cost on assets during construction as authorized by regulatory authorities and the amount so capitalized is an allowance for funds used during construction (AFUDC). AFUDC is the amount that a rate regulated enterprise is allowed to recover for its cost of financing assets under construction. Capitalized overhead, administrative expenses and AFUDC are included in the cost of the related assets and are recovered in rates charged to customers through depreciation expense, as allowed by the regulators.

The range of useful lives for AltaGas’ PP&E is as follows:

Utilities assets	3-80 years
Midstream assets	3-45 years
Power generation assets	2-120 years
Corporate assets	1 - 20 years

As required by the regulatory authority, net additions to SEMCO's utility assets are amortized for one half year in the year in which they are brought into active service. Net additions to WGL’s assets are amortized in the month they are brought into active service.

Generally, when a regulated asset is retired or disposed of, there is no gain or loss recorded in the Consolidated Statement of Income. Any difference between the cost and accumulated depreciation of the asset, net of salvage proceeds, is charged to accumulated depreciation or another regulatory asset or liability account. It is expected that any gain or loss that is charged to accumulated depreciation or another regulatory account will be reflected in future depreciation expense when it is refunded or collected in rates. When a non-regulated asset is retired or disposed of from PP&E, the original cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in the Consolidated Statement of Income.

Leases are classified as either capital or operating. Leases that transfer substantially all the benefits and risks of ownership of property to AltaGas are accounted for as capital leases.

Intangible Assets

Intangible Assets

Intangible assets are recorded at cost. Intangible assets which have a finite useful life are amortized on a straight-line basis over their term or estimated useful life. The range of useful lives for intangible assets with a finite life is as follows:

Energy services relationships	5-19 years
Electricity service agreements	2 - 60 years
Software	3-10 years
Land rights	5-64 years
Franchises and consents	9-25 years
Extraction and Transmission (E&T) Contracts	25 years
Commodity contracts	5 years

The intangible assets recorded in the purchase price allocation for certain WGL commodity contracts are amortized based on the estimated fair value of the deliveries over the term of the contracts, which are over a period of 20 years. 

Assets Held for Sale

Assets Held for Sale

The Corporation classifies assets as held for sale when the carrying amount will be recovered through a sale transaction rather than through continuing use. This condition is met when Management approves and commits to a formal plan to sell the assets, the assets are available for immediate sale in their present condition, and Management expects the sale to close within the next 12 months. Upon classifying an asset as held for sale, an asset is recorded at the lower of its carrying value or the estimated fair value less cost to sell. Assets held for sale are not depreciated or amortized.

Business Acquisitions

Business Acquisitions

Business acquisitions are accounted for using the acquisition method. Under the acquisition method, assets and liabilities of the acquired entity are recorded at fair value at the date of acquisition. Acquisition-related costs are expensed as incurred. Goodwill represents the excess of purchase price over the fair value of the net assets acquired.

Provision on Assets

Provisions on Assets

If facts and circumstances suggest that a long-lived asset or an intangible asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset is not recoverable, as determined by the projected undiscounted cash flows related to the asset over its remaining life, then the carrying value of the asset is reduced to its estimated fair value and an impairment loss is recognized.

Goodwill is not subject to amortization, but assessed at least annually for impairment, or more often when events or changes in circumstances indicate that goodwill may be impaired. The annual assessment of goodwill is performed at the reporting unit level, which is an operating segment or one level below. The Corporation has the option to first assess qualitative factors to determine whether events or changes in circumstances indicate that the goodwill may be impaired. If a quantitative impairment test is performed, the fair value of the reporting unit will be compared to its carrying value (including goodwill). If the carrying value of the reporting unit exceeds the fair value, goodwill is reduced to its fair value and an impairment loss would be recorded in the Consolidated Statement of Income.

Development Costs

Development Costs

AltaGas expenses development costs as incurred unless such development costs meet certain criteria related to technical, market, regulatory and financial feasibility for capitalization. Development costs are examined annually to ensure capitalization criteria continue to be met. When the criteria that previously justified the deferral of costs are no longer met, the unamortized balance is taken as a charge to income in the period when this determination is made. Development costs are amortized based on the expected period of benefit, beginning at the commencement of commercial operations.

Investments Accounted for by the Equity Method

Investments Accounted for by the Equity Method

The equity method of accounting is used for investments in which AltaGas has the ability to exercise significant influence, but does not have a controlling interest. Equity investments are initially measured at cost and are adjusted for the Corporation’s proportionate share of earnings or losses. Equity investments are increased for contributions made and decreased for distributions received. To the extent an investee undertakes activities necessary to commence its planned principal operations, the Corporation will capitalize interest costs associated with its investment during such period.

The HLBV methodology is used to allocate earnings or losses for certain WGL equity method investments when WGL’s ownership interest percentage is different than distribution percentages. When applying HLBV accounting, the Corporation determines the amount that it would receive if an equity investment entity were to liquidate all of its assets at book value (as valued in accordance with U.S. GAAP) and distribute that cash to the investors based on the contractually defined liquidation priorities. The change in the Corporation’s claim on the equity investment entity's book value at the beginning and end of the reporting period (adjusted for contributions and distributions) is the Corporation’s share of the earnings or losses from the equity investment for the period.

An equity method investment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the investment may not be recoverable. When such condition is deemed other than temporary, the carrying value of the investment is written down to its fair value, and an impairment charge is recorded in the Consolidated Statement of Income.

Financial Instruments

Financial Instruments

Non-Utility Operations

All financial instruments are initially recorded at fair value unless they qualify for, and are designated under, a normal purchase and normal sale (NPNS) exemption. Subsequent measurement of the financial instruments is based on their classification. The financial assets are classified as "held-for-trading", "held-to-maturity", or "loans and receivables". Financial liabilities are classified as "held-for-trading" or other financial liabilities. Subsequent measurement is determined by classification. 

A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to AltaGas’ business needs and AltaGas has the ability, and intent, to deliver or take delivery of the underlying item. AltaGas continually assesses the contracts designated under the NPNS exemption and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met.

Held-for-trading instruments include non-derivative financial assets and financial assets and liabilities that may consist of swaps, options, forwards and equity securities. These financial instruments are initially recorded at their fair value, with subsequent changes in fair value recorded in net income. Held-to-maturity, loans and receivables, and other financial liabilities are recognized at amortized cost using the effective interest method unless they are held-for-sale and recognized at the lower of cost or fair value less transaction fees. 

Investments in equity instruments not accounted for under the equity method that do not have a quoted market price in an active market are measured at cost. Income earned from these investments is included in the Consolidated Statement of Income under "other income".

Derivatives embedded in other financial instruments or contracts (the host instrument) are recorded separately and are measured at fair value if the economic characteristics of the embedded derivative are not closely related to the host instrument, the terms of the embedded derivative are the same as those of a standalone derivative and the entire contract is not held-for-trading or accounted for at fair value. Changes in fair value are included in earnings.

The fair values recorded on the Consolidated Balance Sheets reflect netting of the asset and liability positions where counterparty master netting arrangements contain provisions for net settlement.

Transaction costs related to the acquisition of held-for-trading financial assets and liabilities are expensed as incurred. 

Transaction costs for obtaining debt financing other than line-of-credit arrangements are recognized as a direct deduction from the related debt liability on the Consolidated Balance Sheets. Transaction costs related to line-of-credit arrangements are capitalized and included under "long-term investments and other assets" on the Consolidated Balance Sheets. Premiums and discounts are netted against long-term debt on the Consolidated Balance Sheets. The deferred charges are amortized over the life of the related debt on an effective interest basis and included in “interest expense” on the Consolidated Statement of Income.

Regulated Utility Operations

All physical and financial derivative contracts are initially recorded at fair value. Changes in the fair value of derivative instruments that are recoverable or refunded to customers when they settle are recorded as regulatory assets or liabilities. Changes in the fair value of derivatives not affected by rate regulation are reflected in net income.

Weather-Related Instruments

Weather-Related Instruments

WGL purchases certain weather-related instruments, such as heating degree day (HDD) derivatives and cooling degree day (CDD) derivatives to manage weather and price risks related to its natural gas and electricity sales. These derivatives are accounted for in accordance with ASC 815-45, Derivatives and Hedging – Weather Derivatives. For HDD derivatives, gains or losses are recognized when the actual HDD’s falls above or below the contractual HDD’s for each instrument. For CDD derivatives, gains or losses are recognized when the average temperature exceeds or is below a contractually stated level during the contract period. Refer to Note 22for further discussion on weather-related instruments.  

Hedges

Hedges

As part of its risk management strategy, AltaGas may use derivatives to reduce its exposure to commodity price, interest rate and foreign exchange risk. AltaGas has designated certain U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. No other derivatives have been designated as hedges under ASC Topic 815.

Non-Utility Operations

The change in fair value of cash flow hedges is recognized in OCI. Gains or losses from cash flow hedges are reclassified to net income when the hedged transaction affects earnings, such as when the hedged forecasted transaction occurs.

Regulated Utility Operations

During planned issuances of debt securities, Washington Gas may utilize derivative instruments to manage the risk of interest-rate volatility. Gains and losses associated with these types of derivatives are recorded as regulatory liabilities or assets, and amortized in accordance with regulatory requirements, typically over the life of the related debt.  

Asset Retirement Obligations

Asset Retirement Obligations

AltaGas recognizes asset retirement obligations in the period in which the legal obligation is incurred and a reasonable estimate of fair value can be determined. The associated asset retirement costs are capitalized as part of the carrying amount of the asset and are depreciated over the estimated useful life of the asset. The liability is increased due to the passage of time over the estimated period until the settlement of the obligation, with a corresponding charge to accretion expense for asset retirement obligations.

There are timing differences between accretion and depreciation amounts being recorded pursuant to GAAP and the recognition of depreciation expense for legal asset removal costs that are recovered in rates, as allowed by the regulators. These timing differences are recorded as a reduction to “regulatory liabilities” in accordance with ASC 980.

Certain utility assets will have future legal obligations on retirement, but an asset retirement obligation has not been recorded due to its indeterminate life and corresponding indeterminable timing and scope of these asset retirement obligations. The U.S. Utilities recognize asset retirement obligations for some interim retirements, as expected by their regulators.

Revenue Recognition

Revenue Recognition

AltaGas has revenue from various sources, including rate regulated revenue, commodity sales, midstream service contracts, gas sales and transportation services, and gas storage services. For a detailed description of the Corporation’s revenue recognition policy by major source of revenue, please refer to Note 23.

Foreign Currency Translation

Foreign Currency Translation

Monetary assets and liabilities denominated in a foreign currency are converted to the functional currency using the exchange rate in effect at the balance sheet date. Adjustments resulting from the conversion are recorded in the Consolidated Statement of Income. Non-monetary assets and liabilities are converted at the historical exchange rate in effect at the transaction date. Revenues and expenses are converted at the exchange rate applicable at the transaction date.

For foreign entities with a functional currency other than Canadian dollars, AltaGas’ reporting currency, assets, and liabilities are translated into Canadian dollars at the rate in effect at the reporting date. Revenues and expenses are translated at average exchange rates during the reporting period. All adjustments resulting from the translation of the foreign operations are recorded in OCI.

AltaGas may designate some of its U.S. dollar denominated long-term debt as a foreign currency hedge of its investment in foreign operations. Accordingly, foreign exchange gains and losses, from the dates of designation, on the translation of the U.S. dollar denominated long-term debt are included in OCI.

Share Options and Other Compensation Plans

Share Options and Other Compensation Plans

Share options granted are recorded using fair value. Compensation expense is measured at the date of the grant using the Black-Scholes-Merton model and is recognized over the vesting period of the options. Consideration received by AltaGas on exercise of the share options is credited to shareholders’ equity.

AltaGas has a medium-term incentive plan (MTIP) for employees and executive officers which includes two types of awards: restricted units (RUs) and performance units (PUs). A portion of AltaGas’ RUs and PUs are valued based on the dividends declared during the vesting period and the weighted average share price of AltaGas' common shares multiplied by the units outstanding at the end of the vesting period. Upon vesting, the RUs and PUs are paid in cash or, at the election of AltaGas, its equivalent in common shares purchased from the market. The other portion of RU’s and PSUs are valued at US$1 per unit. Upon vesting, the RUs and PSUs are paid in cash. All PUs are also subject to a performance multiplier ranging from 0 to 2 dependent on the Corporation's performance relative to performance targets agreed between the Corporation and the employees. Compensation expense is recognized using the liability method and is recorded as operating and administrative expense over the vesting period. A change in value of the RUs or PUs is recognized in the period the change occurs.

In addition, AltaGas has a deferred share unit plan (DSUP) for directors, officers and employees as an additional form of long-term variable compensation incentive. Although the DSUP is available to directors, officers and employees, AltaGas currently only grants deferred share units (DSUs) under the DSUP as a form of director compensation. The DSUs granted are fully vested upon being credited to a participant’s account, and the participant is entitled to payment at his or her termination date, and payment is not subject to satisfaction of any requirements as to any minimum period of membership or employment or other conditions. DSUs are accounted for at fair value. Compensation expense is determined based on the fair value of the DSUs on the date of the grant and fluctuations in fair value are recognized in the period the change occurs.

Pension Plans and Post-Retirement Benefits

Pension Plans and Post-Retirement Benefits

AltaGas maintains defined benefit pension plans, defined contribution plans, and other post-retirement benefit plans for eligible employees. Contributions made by the Corporation to the defined contribution plans are expensed in the period in which the contribution occurs.

The cost of defined benefit pension plans and post-retirement benefits is actuarially determined using the projected benefit method prorated based on service and Management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected health care costs. Pension plan assets are measured at fair value. The expected return on plan assets is based on historical and projected rates of return for each asset class in the plan portfolio. The projected benefit obligation is discounted using the market interest rate on high-quality debt instruments with cash flows matching the timing and amount of benefit payments. Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation and the fair value of plan assets or the market-related value of assets along with any unamortized past service costs are amortized on a straight-line basis over the expected average remaining service life of active employees. The expected average remaining service period of the active members covered by the defined benefit pension plans and post-retirement benefit plans is 9.6 years and 14.1 years, respectively.

AltaGas recognizes the overfunded or underfunded status of its pension and post-retirement benefit plans as either assets or liabilities in the Consolidated Balance Sheets. Unrecognized actuarial gains and losses and past service costs and credits that arise during the period are recognized in OCI or a regulatory asset or liability.

For certain regulated utilities, the Corporation expects to recover pension expense in future rates and therefore records unrecognized balances as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the expected average remaining service life of active employees.

Income Taxes

Income Taxes

Income taxes for the Corporation and its subsidiaries are calculated using the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are determined based on differences between the carrying value and the tax basis of assets and liabilities and are measured using the enacted tax rates and laws that are in effect in the periods in which the differences are expected to be settled or realized. Deferred income tax assets are routinely reviewed and a valuation allowance is recorded to reduce the deferred tax assets if it is more likely than not that deferred tax assets will not be realized. The financial statement effects of an uncertain tax position are recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxing authority. The current and deferred tax impact is equal to the largest amount, considering possible settlement outcomes, that is greater than 50 percent likely of being realized upon settlement with the taxing authorities.

Investment tax credits are recognized as reductions to income tax expense over the estimated service lives of the related properties.

The rate-regulated natural gas distribution subsidiaries recognize a separate regulatory asset or liability for the amount of deferred income taxes expected to be recovered from, or paid to, customers in the future. 

Net Income per Share

Net Income per Share

Basic net income per common share is computed using the weighted average number of common shares outstanding during the period. Dilutive net income per common share is calculated using the weighted average number of common shares outstanding adjusted for dilutive common shares related to the Corporation’s share-based compensation awards.

The potentially dilutive impact of the share-based compensation awards is determined using the treasury stock method. Under the treasury stock method, awards are treated as if they had been exercised with any proceeds used to repurchase common stock at the average market price during the period. Any incremental difference between the assumed number of shares issued and purchased is included in the diluted share computation. 

Contingencies

Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Any such accruals are adjusted thereafter as additional information becomes available or circumstances change.

ADOPTION OF NEW ACCOUNTING STANDARDS AND FUTURE CHANGES IN ACCOUNTING PRINCIPLES

ADOPTION OF NEW ACCOUNTING STANDARDS

Effective January 1, 2018, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU):

· ASU No. 2014-09 “Revenue from Contracts with Customers” and all related amendments (collectively “ASC 606”).  AltaGas adopted ASC 606 using the modified retrospective method to contracts that have not been completed as at January 1, 2018. Under the modified retrospective method, the comparative information is not adjusted. The adoption of ASC 606 impacted the timing of revenue recognition in relation to contracts with take-or-pay or minimum volume commitments whereby the customers have make up rights for deficiency quantities. However, on adoption, no cumulative adjustments to opening retained earnings were required for this change in revenue recognition pattern as none of the customers had material deficiency quantities. Please also refer to Note 23 for further details. The application of ASC 606 did not have a material impact on AltaGas’ consolidated financial statements in 2018;

· ASU No. 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” which revised an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. It also amended certain disclosure requirements associated with the fair value of financial instruments. Upon adoption, AltaGas reclassified its equity securities with readily determinable fair values from available-for-sale to held for trading. Changes in fair value for equity securities with readily determinable fair values are now recognized through earnings instead of other comprehensive income. As a result, a cumulative-effect adjustment to retained earnings of approximately $7 million was recognized as at January 1, 2018. The remaining provisions of this ASU did not have a material impact on AltaGas’ consolidated financial statements; 

· ASU No. 2016-15 “Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments”. The amendments in this ASU clarified the classification of certain cash flow transactions on the statement of cash flow.  The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

· ASU No. 2016-16 “Income Taxes: Intra-Entity Transfers of Assets Other Than Inventory”. The amendments in this ASU revised the accounting for income tax consequences on intra-entity transfers of assets by requiring an entity to recognize current and deferred tax on intra-entity transfers of assets other than inventory when the transfer occurs. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

· ASU No. 2016-18 “Statement of Cash Flows: Restricted Cash”. The amendments in this ASU required those amounts deemed to be restricted cash and restricted cash equivalents to be included in the cash and cash equivalents balance on the statement of cash flows. The change in presentation of the restricted cash balance on the statement of cash flows was applied on a retrospective basis;

· ASU No. 2017-01 “Business Combinations: Clarifying the Definition of a Business”. The amendments in this ASU changed the definition of a business to assist entities with evaluating when a set of transferred assets and activities is a business. AltaGas will apply the amendments to this ASU prospectively;

· ASU No. 2017-04 “Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment”. The amendments in this ASU removed Step 2 of the goodwill impairment test, eliminating the requirement to determine the fair value of individual assets and liabilities of a reporting unit to measure the goodwill impairment. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

· ASU No. 2017-05 “Other Income – Gains and Losses from the De-recognition of Nonfinancial Assets: Clarifying the Scope of Asset De-recognition Guidance and Accounting for Partial Sales of Nonfinancial Assets”. The amendments in this ASU clarified the scope of ASC 610-20 as well as the accounting for partial sales of nonfinancial assets. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

· ASU No. 2017-07 “Compensation – Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”. The amendments in this ASU revised the presentation of net periodic pension cost and net periodic postretirement benefit cost on the income statement and limited the components that are eligible for capitalization in assets to only the service cost component. AltaGas applied the change in presentation of the current service cost and other components of net benefit cost on the income statement retrospectively. As a result, $1.6 million of net benefit cost associated with other components were reclassified from the line item “operating and administrative” to “other income” on the Consolidated Statements of Income for the year ended December 31, 2017. AltaGas applied the change related to the capitalization of the service cost prospectively. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

· ASU No. 2017-09 “Compensation – Stock Compensation: Scope of Modifications Accounting”. The amendments in this ASU provided guidance on the types of changes to the terms or conditions of share-based payment arrangements to which an entity would be required to apply modification accounting. The guidance was applied prospectively and did not have a material impact on AltaGas’ consolidated financial statements;

· ASU No. 2017-12 “Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities”. The amendments in this ASU improved the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and made certain targeted improvements to simplify the application of hedge accounting. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

· ASU No. 2018-02 “Income Statement – Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”. The amendments in this ASU allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act (TCJA). AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and

· ASU No. 2018-03 “Technical Corrections and Improvements to Financial Instruments – Overall”. The amendments in this ASU clarified certain aspects of the guidance issued in ASU No. 2016-01. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements.

FUTURE CHANGES IN ACCOUNTING PRINCIPLES

In February 2016, FASB issued ASU No. 2016-02 “Leases”, which requires lessees to recognize on the balance sheet a right-of-use asset and a lease liability. Lessor accounting remains substantially unchanged, however, the ASU modifies what qualifies as a sales-type and direct financing lease and eliminates the real estate-specific provisions included in ASC 840. The ASU also requires additional disclosures regarding leasing arrangements. In January 2018, FASB issued ASU 2018-01 “Land Easement Practical Expedient for Transition to Topic 842”, providing entities with an optional election not to evaluate existing and expired land easements not previously accounted for as leases under ASC 840 using the provisions of ASC 842. In July 2018, FASB issued ASU 2018-11 “Targeted Improvements”, allowing entities to report the comparative periods presented in the period of adoption under the previous lease standard (ASC 840), and recognize a cumulative-effect adjustment to the opening balance of retained earnings as of January 1, 2019. The ASU also provides a practical expedient under which lessors are not required to separate out lease and non-lease components of a contract, provided certain conditions are met. In December 2018, FASB issued ASU 2018-20 “Narrow-Scope Improvement for Lessors”, allowing lessors to include and exclude certain costs from variable payments. The ASU also require lessors to allocate certain variable payments to the lease and non-lease components when the changes in facts and circumstances on which the variable payment is based occur. The amendments to the new lease standard are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. AltaGas is in the final stages of evaluating the impact of adopting ASC 842 on its consolidated financial statements. Leases, except as noted below, for which AltaGas is the lessee will be reflected on the balance sheet upon adoption by recording an increase to long-term assets and an increase to long-term liabilities net of the current portion that is recorded in current liabilities. The increases are expected to be less than 1 percent of total assets. AltaGas will utilize the transition practical expedients which allow entities to not have to reassess whether an arrangement contains a lease under the provisions of ASC 842, as well as the transition practical expedients related to land easements and not separating out lease and non-lease components of a contract for certain classes of assets. As a result of the transition practical expedients, AltaGas expects to have primarily operating leases on transition consistent with its current conclusions under ASC 840. AltaGas will also elect to exclude leases with terms of 12 months or less from the calculation of lease liabilities and right of use assets under the short term lease exemption.

In June 2016, FASB issued ASU No. 2016-13 “Financial Instruments – Credit Losses: Measurement of Credit Losses on Financial Instruments”. The amendments in this ASU replace the current “incurred loss” impairment methodology with an “expected loss” model for financial assets measured at amortized cost. The amendments in this ASU are effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted. AltaGas is currently assessing the impact of this ASU on its consolidated financial statements.

In June 2018, FASB issued ASU No. 2018-07 “Compensation – Stock Compensation: Improvements to Nonemployee Share-Based Payment Accounting”. The amendments in this ASU expand the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees, with the objective of making the measurement consistent with employee share based payment awards. The amendments in this update are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In June 2018, FASB issued ASU No. 2018-08 “Not-for-Profit-Entities – Clarifying the Scope and the Accounting Guidance for Contributions Received and Contributions Made”. The amendments in this Update clarify whether a transfer of assets is a contribution or an exchange transaction. The amendments in this update are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In August 2018, FASB issued ASU No. 2018-13 “Fair Value Measurement – Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurement”. The amendments in this ASU modify the disclosure requirements on fair value measurements. The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In August 2018, FASB issued ASU No. 2018-14 “Compensation – Retirement Benefits-Defined Benefit Plans – General: Disclosure Framework – Changes to the Disclosure Requirements for the Defined Benefit Plans”. The amendments in this ASU modify the disclosure requirements on defined benefit pension and other postretirement plans. The amendments in this update are effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In August 2018, FASB issued ASU No. 2018-15 “Intangibles – Goodwill and Other – Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement (CCA) that is a Service Contract”. The amendments in this ASU align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal use software license). The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted and AltaGas will early adopt this ASU on January 1, 2019. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In October 2018, FASB issued ASU No. 2018-16 “Derivatives and Hedging: Inclusion of the Second Overnight Financing Rate (SOFR) Overnight Index Swap (OIS) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes”. The amendments in this ASU permit the use of Overhead Index Swap (OIS) rate based on SOFR as a U.S. benchmark interest rate for hedge accounting purposes. The amendments in this update should be adopted concurrently with ASU 2017-12. AltaGas early adopted ASU 2017-12 on January 1, 2018 and therefore will adopt this update on January 1, 2019. An entity should apply the amendments prospectively for any qualifying new or re-designated cash flow hedging relationships. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In October 2018, FASB issued ASU No. 2018-17 “Consolidation: Targeted Improvements to Related Party Guidance for Variable Interest Entities”. The amendments in this Update provide a private-company scope exception to the VIE guidance for certain entities and clarify that indirect interest held through related parties under common control will be considered on a proportional basis when determining whether fees paid to decision makers and service providers are variable interests. The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. AN entity should apply the amendments retrospectively with a cumulative-effect adjustment to retained earnings at the beginning of the earliest period presented Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2018

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract]

Summary of Estimated Useful Lives of Property, Plant and Equipment

Utilities assets	3-80 years
Midstream assets	3-45 years
Power generation assets	2-120 years
Corporate assets	1 - 20 years

Summary of Estimated Useful Lives of Finite-Lived Intangible Assets

Energy services relationships	5-19 years
Electricity service agreements	2 - 60 years
Software	3-10 years
Land rights	5-64 years
Franchises and consents	9-25 years
Extraction and Transmission (E&T) Contracts	25 years
Commodity contracts	5 years

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ACQUISITION OF WGL HOLDINGS INC. (Tables)

12 Months Ended

Dec. 31, 2018

ACQUISITION OF WGL HOLDINGS INC. [Abstract]

Schedule of Final Purchase Price Allocation

Purchase consideration	$	5,973
Fair value assigned to net assets
Current assets	$	1,187
Property, plant and equipment		5,943
Intangible assets		637
Regulatory assets		402
Long-term investments		1,411
Other long-term assets		449
Current liabilities		(1,798)
Long-term debt		(2,548)
Preferred shares		(41)
Regulatory liabilities		(1,125)
Deferred income taxes		(772)
Other long-term liabilities		(959)
Non-controlling interest		(9)
Fair value of net assets acquired	$	2,777
Goodwill	$	3,196

Summary of Pro Forma Information

	Year ended December 31
	2018		2017
Pro forma revenue	$	5,962	$	5,704
Pro forma net income (loss) after taxes	$	(304)	$	450

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ASSETS HELD FOR SALE (Tables)

12 Months Ended

Dec. 31, 2018

SALE OF MINORITY INTEREST AND OTHER DISPOSITIONS AND ASSETS HELD FOR SALE [Abstract]

Schedule of Assets Held for Sale

As at	December 31, 2018		December 31, 2017
Assets held for sale
Cash	$	4.9	$	—
Accounts receivable		85.2		0.3
Inventory		0.5		—
Property, plant and equipment		1,189.6		5.3
Intangible assets		248.7		0.1
Goodwill		—		0.3
	$	1,528.9	$	6.0
Liabilities associated with assets held for sale
Accounts payable and accrued liabilities	$	23.8	$	—
Asset retirement obligations		10.8		0.3
Other long-term liabilities		136.8		—
	$	171.4	$	0.3

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INVENTORY (Tables)

12 Months Ended

Dec. 31, 2018

INVENTORY [Abstract]

Schedule of Inventory

	December 31,		December 31,
As at	2018		2017
Natural gas held in storage	$	418.0	$	133.9
Materials and supplies		53.3		32.3
Renewable energy credits and emission compliance instruments		38.2		28.4
Other inventory		6.4		6.5
	$	515.9	$	201.1

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PROPERTY, PLANT AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2018

PROPERTY, PLANT AND EQUIPMENT [Abstract]

Schedule of Property, Plant and Equipment

As at	December 31, 2018						December 31, 2017
	Cost		Accumulated amortization		Net book value		Cost		Accumulated amortization		Net book value
Utilities	$	7,090.5	$	(89.7)	$	7,000.8	$	2,245.4	$	(226.1)		2,019.3
Midstream		3,178.2		(845.7)		2,332.5		2,801.4		(636.3)	$	2,165.1
Power		4,633.9		(1,858.3)		2,775.6		2,874.8		(392.3)		2,482.5
Corporate		49.4		(39.1)		10.3		65.9		(37.7)		28.2
Reclassified to assets held for sale (note 5)		(2,999.3)		1,809.7		(1,189.6)		(16.7)		11.4		(5.3)
	$	11,952.7	$	(1,023.1)	$	10,929.6	$	7,970.8	$	(1,281.0)	$	6,689.8

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INTANGIBLE ASSETS (Tables)

12 Months Ended

Dec. 31, 2018

PROVISIONS ON ASSETS, INTANGIBLE ASSETS AND GOODWILL [Abstract]

Summary of Intangible Assets

As at	December 31, 2018						December 31, 2017
	Cost		Accumulated amortization		Net book value		Cost		Accumulated amortization		Net book value
E&T contracts	$	26.6	$	(14.3)	$	12.3	$	26.6	$	(13.4)	$	13.2
Electricity service agreements		269.5		(25.9)		243.6		603.1		(108.5)		494.6
Energy services relationships		176.1		(33.8)		142.3		10.2		(8.1)		2.1
Software		293.9		(77.7)		216.2		126.8		(61.6)		65.2
Land rights		1.4		(0.2)		1.2		11.0		(2.4)		8.6
Commodity contracts		346.3		(6.3)		340.0		—		—		—
Franchises and consents		5.0		—		5.0		7.4		(2.2)		5.2
Reclassified to assets held for sale (note 5)		(277.4)		28.7		(248.7)		(0.1)		—		(0.1)
	$	841.4	$	(129.5)	$	711.9	$	785.0	$	(196.2)	$	588.8

Summary of Estimated Amortization Expense of Intangible Assets

2019	$	84.2
2020	$	82.5
2021	$	57.6
2022	$	132.3
2023	$	38.3
Thereafter	$	120.6

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GOODWILL (Tables)

12 Months Ended

Dec. 31, 2018

PROVISIONS ON ASSETS, INTANGIBLE ASSETS AND GOODWILL [Abstract]

Schedule of Goodwill

	December 31,		December 31,
As at	2018		2017
Balance, beginning of year	$	817.3	$	856.0
Provisions on assets (notes 5 and 10)		(124.2)		—
Business acquisition (note 3)		3,196.4		—
Foreign exchange translation		178.7		(38.4)
Reclassified to assets held for sale		—		(0.3)
Balance, end of year	$	4,068.2	$	817.3

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PROVISIONS ON ASSETS (Tables)

12 Months Ended

Dec. 31, 2018

PROVISIONS ON ASSETS, INTANGIBLE ASSETS AND GOODWILL [Abstract]

Schedule of Provisions on Assets

Year ended December 31	2018		2017
Utilities	$	193.7	$	—
Midstream		153.7		6.6
Power		381.3		133.0
	$	728.7	$	139.6

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LONG-TERM INVESTMENTS AND OTHER ASSETS (Tables)

12 Months Ended

Dec. 31, 2018

LONG-TERM INVESTMENTS AND OTHER ASSETS [Abstract]

Schedule of Long-Term and Other Investments

As at	December 31, 2018		December 31, 2017
Investments in publicly-traded entities	$	8.4	$	95.0
Loan to affiliate (note 30)		45.0		75.0
Deferred lease receivable		24.4		29.0
Debt issuance costs associated with credit facilities		7.9		20.3
Refundable deposits		16.2		14.9
Prepayment on long-term service agreements		82.5		68.1
Subscription receipts issuance costs		—		1.7
Contract asset (note 23)		11.5		—
Rabbi trust (note 28)		61.7		—
Other		25.5		8.6
	$	283.1	$	312.6

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VARIABLE INTEREST ENTITIES (Tables)

12 Months Ended

Dec. 31, 2018

VARIABLE INTEREST ENTITIES [Abstract]

Schedule of VIE Amounts in Consolidated Balance Sheets

As at	December 31,		December 31,
		2018		2017
Current assets	$	1,383.5	$	1.4
Property, plant and equipment		619.2		84.3
Long-term investments and other assets		48.0		48.0
Current liabilities		(161.8)		—
Asset retirement obligations		(0.9)		—
Deferred tax credits		(3.0)		—
Net assets	$	1,885.0	$	133.7

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INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD (Tables)

12 Months Ended

Dec. 31, 2018

INVESTMENTS ACCOUNTED FOR BY EQUITY METHOD [Abstract]

Schedule of Equity Method Investments

				Carrying value as at December 31				Equity income (loss) for the year ended December 31
Description	Location	Ownership Percentage		2018		2017		2018		2017
AltaGas Canada Inc. (ACI)	Canada	36.75	$	112.5	$	—	$	5.4	$	—
AltaGas Idemitsu Joint Venture LP (AIJVLP)	Canada	50		342.9		323.3		2.1		6.6
Constitution Pipeline, LLC (Constitution)	United States	10		—		—		(0.2)		—
Craven County Wood Energy LP	United States	50		7.8		20.9		(14.1)		3.3
Eaton Rapids Gas Storage System	United States	50		29.4		26.4		2.0		2.5
Grayling Generating Station LP	United States	50		29.0		27.6		3.6		3.5
Inuvik Gas Ltd. (a)	Canada	33.333		—		—		(0.2)		—
Meade Pipeline Co. LLC (Meade) (b)	United States	55		757.8		—		12.2		—
Mountain Valley Pipeline, LLC (Mountain Valley)	United States	10		532.5		—		11.5		—
Sarnia Airport Storage Pool LP	Canada	50		18.7		18.8		1.0		1.0
Petrogas Preferred Shares	Canada	n/a		150.0		150.0		12.8		12.8
Tidewater Midstream and Infrastructure Ltd. (c)	Canada	n/a		—		—		—		1.7
Stonewall Gas Gathering Systems LLC	United States	30		411.8		—		11.8		—
			$	2,392.4	$	567.0	$	47.9	$	31.4

(a) Inuvik Gas Ltd. was sold to AltaGas Canada Inc. in October 2018.

(b) Meade is a VIE (Note 12).

(c) AltaGas sold 43.7 million shares of Tidewater Midstream and Infrastructure Inc. in September 2018 (Note 11).

Schedule of Combined Financial Information of Equity Method Investments

Year ended December 31	2018			2017
Revenues	$	351.6	$	110.6
Expenses		(142.7)		(74.2)
	$	208.9	$	36.4
As at December 31		2018		2017
Current assets	$	1,204.6	$	24.8
Property, plant and equipment	$	7,602.5	$	82.8
Intangible assets	$	22.9	$	5.6
Long-term investments and other assets	$	1,326.6	$	843.3
Current liabilities	$	(1,015.2)	$	(41.7)
Other long-term liabilities	$	(949.6)	$	(189.1)

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SHORT-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2018

SHORT-TERM AND LONG-TERM DEBT [Abstract]

Schedule of Short-Term Debt

As at	December 31, 2018		December 31, 2017
Bank indebtedness (a)	$	0.2	$	6.2
US$150 million operating facility (b)		—		31.7
$25 million operating facility (c)		—		8.9
Commercial paper (d)		1,145.2		—
Project financing		64.5		—
	$	1,209.9	$	46.8

(a) Bank indebtedness bears interest at the lender's prime rate or at the interest rate applicable to bankers' acceptances. The prime lending rate at December 31, 2018was 3.95percent (December 31, 2017 – 3.2 percent).

(b) As at December 31, 2018, SEMCO held a US$150 million (December 31, 2017-US$150.0 million) unsecured revolving operating credit facility with a Canadian chartered bank with a maturity date of December 20, 2023. Draws on the facility can be by way of U.S. base-rate loans, letters of credit and LIBOR loans. Letters of credit outstanding under this facility as at December 31, 2018 were $0.7 million (December 31, 2017-$0.6 million).

(c) Upon completion of the ACI IPO, the operating facility was transferred to ACI.

(d) WGL and Washington Gas use short-term debt in the form of commercial paper or unsecured short-term bank loans to fund seasonal cash requirements. Revolving committed credit facilities are maintained in an amount equal to or greater than the expected maximum commercial paper position.

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LONG-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2018

SHORT-TERM AND LONG-TERM DEBT [Abstract]

Schedule of Long-Term Debt

			December 31,		December 31,
As at	Maturity date	2018		2017
Credit facilities
$1,400 million unsecured extendible revolving(a)	15-May-2023	$	964.7	$	219.1
US$300 million unsecured extendible revolving(b)	15-May-2022		287.8		—
Acquisition credit facility	6-Jan-2020		113.2		—
US$1,200 million revolving credit facility(g)	28-Dec-2021		1,637.0		—
Medium-term notes (MTNs)
$175 million Senior unsecured - 4.60 percent	15-Jan-2018		—		175.0
$200 million Senior unsecured - 4.55 percent	17-Jan-2019		200.0		200.0
$200 million Senior unsecured - 4.07 percent	1-Jun-2020		200.0		200.0
$350 million Senior unsecured - 3.72 percent	28-Sep-2021		350.0		350.0
$300 million Senior unsecured - 3.57 percent	12-Jun-2023		300.0		300.0
$200 million Senior unsecured - 4.40 percent	15-Mar-2024		200.0		200.0
$300 million Senior unsecured - 3.84 percent	15-Jan-2025		299.9		299.9
$100 million Senior unsecured - 5.16 percent	13-Jan-2044		100.0		100.0
$300 million Senior unsecured - 4.50 percent	15-Aug-2044		299.8		299.8
$350 million Senior unsecured - 4.12 percent	7-Apr-2026		349.8		349.8
$200 million Senior unsecured - 3.98 percent	4-Oct-2027		199.9		199.9
$250 million Senior unsecured - 4.99 percent	4-Oct-2047		250.0		250.0
WGL and Washington Gas medium-term notes
US$500 million Senior unsecured - 2.25 to 4.76 percent	Jan - Nov 2019		682.1		—
US$250 million Senior unsecured - 2.88 percent	12-Mar-2020		341.1		—
US$20 million Senior unsecured - 6.65 percent	20-Mar-2023		27.3		—
US$40.5 million Senior unsecured - 5.44 percent	11-Aug-2025		55.3		—
US$53 million Senior unsecured - 6.62 to 6.82 percent	Oct - 2026		72.3		—
US$72 million Senior unsecured - 6.40 to 6.57 percent	Feb - Sep 2027		98.2		—
US$52 million Senior unsecured - 6.57 to 6.85 percent	Jan - Mar 2028		70.9		—
US$8.5 million Senior unsecured - 7.50 percent	1-Apr-2030		11.6		—
US$50 million Senior unsecured - 5.70 to 5.78 percent	Jan - Mar 2036		68.2		—
US$75 million Senior unsecured - 5.21 percent	3-Dec-2040		102.3		—
US$75 million Senior unsecured - 5.00 percent	15-Dec-2043		102.3		—
US$300 million Senior unsecured - 4.22 to 4.60 percent	Sep - Dec 2044		409.3		—
US$450 million Senior unsecured - 3.80 percent	15-Sep-2046		613.9		—
SEMCO long-term debt
US$300 million SEMCO Senior secured - 5.15 percent(d)	21-Apr-2020		409.3		376.4
US$82 million CINGSA Senior secured - 4.48 percent(e)	2-Mar-2032		86.3		85.2
Debenture notes
PNG 2018 Series Debenture - 8.75 percent (c)(f)	15-Nov-2018		—		7.0
PNG 2025 Series Debenture - 9.30 percent (c)(f)	18-Jul-2025		—		13.0
PNG 2027 Series Debenture - 6.90 percent (c)(f)	2-Dec-2027		—		14.0
CINGSA capital lease - 3.50 percent	1-May-2040		0.6		0.5
CINGSA capital lease - 4.48 percent	4-Jun-2068		0.2		0.2
Fair value adjustment on WGL Acquisition (note 3)			89.0		—
		$	8,992.3	$	3,639.8
Less debt issuance costs			(35.2)		(14.4)
			8,957.1		3,625.4
Less current portion			(890.2)		(188.9)
		$	8,066.9	$	3,436.5

(a) Borrowings on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers' acceptances or letters of credit. Borrowings on the facility have fees and interest at rates relevant to the nature of the draw made.

(b) Borrowings on the facility can be by way of U.S. base rate loans, U.S. prime loans, LIBOR loans, or letters of credit.

(c) Collateral for the Secured Debentures and secured extendible revolving credit facility consisted of a specific first mortgage on substantially all of PNG's property, plant and equipment, and gas purchase and gas sales contracts, and a first floating charge on other property, assets and undertakings.

(d) Collateral for the US$ MTNs is certain SEMCO assets.

(e) Collateral for the CINGSA Senior secured loan is certain CINGSA assets, Alaska Storage Holding Company, LLC, a subsidiary in which AltaGas has a controlling interest, is the non-recourse guarantor of this loan.

(f) PNG debentures totaling $33.3 million have been sold toACI (Note 4)

Borrowings on the facility can be by way of U.S. base rate loans, U.S. prime loans, or LIBOR loans.

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ASSET RETIREMENT OBLIGATION (Tables)

12 Months Ended

Dec. 31, 2018

ASSET RETIREMENT OBLIGATIONS [Abstract]

Schedule of Changes in Asset Retirement Obligations

As at	December 31, 2018		December 31, 2017
Balance, beginning of year	$	88.3	$	81.6
Obligations acquired (note 3)		399.1		—
New obligations		3.3		1.5
Obligations settled		(4.2)		(4.0)
Disposals		(1.6)		—
Revision in estimated cash flow		3.8		6.0
Accretion expense (a)		12.3		4.4
Foreign exchange translation		20.3		(0.9)
Reclassified to liabilities associated with assets held for sale (note 5)		(10.8)		(0.3)
Total		510.5		88.3
Less current portion (included in accounts payable and accrued liabilities)		(9.9)		—
Balance, end of year	$	500.6	$	88.3

(a) The majority of accretion expense is recorded through the Consolidated Statement of Income. Certain amounts relating to Washington Gas’ Utility asset retirement obligations are recorded through regulatory liabilities on the Consolidated Balance Sheets due to regulatory treatment.

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OTHER LONG-TERM LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2018

OTHER LONG-TERM LIABILITIES [Abstract]

Schedule of Other Long-Term Liabilities

As at	December 31, 2018		December 31, 2017
Deferred lease payable	$	13.1	$	2.4
Deferred revenue		3.9		3.8
Customer advances for construction		58.6		40.9
Sundance B PPA termination expense (a)		2.0		4.0
NTL liability (b)		—		142.0
Lease inducement		2.7		3.1
Merger commitments		21.4		—
Other long-term liabilities		20.3		5.7
	$	122.0	$	201.9

(a) On December 16, 2016, AltaGas Pipeline Partnership and the Government of Alberta reached a definitive settlement agreement regarding the termination of the Sundance B PPAs. Under the settlement agreement, AltaGas has agreed to make a total of $6.0 million in cash payments in equal annual installments over three years starting in 2018, $2.0 million of which has been recorded under “accounts payable and accrued liabilities”.

(b) The NTL liability has been reclassified as liabilities associated with assets held for sale (Note 5).

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2018

INCOME TAXES [Abstract]

Schedule of Income Tax Provision

Year ended December 31		2018		2017
Income (loss) before income taxes - consolidated	$	(716.9)	$	66.4
Statutory income tax rate (%)		27.0		27.0
Expected taxes at statutory rates	$	(193.6)	$	17.9
Add (deduct) the tax effect of:
Permanent differences		(1.0)		9.5
Statutory and other rate differences		(19.6)		(30.5)
Rate adjustment for change in tax rates		1.3		(34.1)
Deferred income tax recovery on regulated assets		(7.3)		(7.4)
Tax differences on divestitures and transactions		(32.3)		6.9
Non-controlling interests		4.7		—
Change in valuation allowance		(22.3)		4.2
Other		6.9		—
	$	(263.2)	$	(33.5)
Income tax provision
Current
Canada		23.7		18.0
United States		0.7		12.5
	$	24.4	$	30.5
Deferred
Canada		(166.1)		(7.4)
United States		(121.5)		(56.6)
	$	(287.6)	$	(64.0)
Effective income tax rate (%)		36.7		(50.5)

Schedule of Deferred Income Tax Liabilities

As at	December 31, 2018		December 31, 2017
PP&E and intangible assets	$	1,764.6	$	726.5
Regulatory assets		(166.3)		22.8
Tax pools, deferred financing and compensation		(453.6)		(302.3)
Other		(209.9)		(59.3)
Valuation allowance		23.1		53.7
	$	957.9	$	441.4

Schedule of Uncertain Tax Positions

Year ended December 31		2018		2017
Balance, beginning of year	$	5.9	$	2.2
Net changes during the year		(3.7)		3.7
Balance, end of year	$	2.2	$	5.9

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REGULATORY ASSETS AND LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2018

REGULATORY ASSETS AND LIABILITIES [Abstract]

Schedule of Regulatory Assets and Liabilities

As at	December 31, 2018		December 31, 2017		Recovery Period
Regulatory assets - current
Deferred cost of gas (a)	$	20.4	$	0.5	Less than one year
Deferred property taxes		—		0.3	Less than one year
Other		0.6		0.3	Less than one year
	$	21.0	$	1.1
Regulatory assets - non-current
Deferred regulatory costs and rate stabilization adjustment mechanism (a)(b)	$	215.5	$	20.5	1 - 3 years
Pipeline rehabilitation costs		—		0.3	Various
Future recovery of pension and other retirement benefits (a)		192.9		113.9	Various
Future recovery of non-retirement employee benefits (a)(c)		21.3		—	Various
Deferred pension costs (d)		7.8		—		1 years
Deferred environmental costs (a)(e)		19.9		13.9	1 - 10 years
Deferred loss on reacquired debt (a)(f)		109.3		2.5	1 - 15 years
Deferred depreciation and amortization		—		23.3	Various
Deferred future income taxes (a)(g)		67.0		104.7	Various
Deferred customer retention program amortization		—		16.5		Various
Revenue deficiency account		—		31.0	Various
Other		29.3		2.0	Various
	$	663.0	$	328.6
Regulatory liabilities - current
Deferred cost of gas	$	71.2	$	9.0	Less than one year
Refundable tax credit (h)		3.8		1.9	Less than one year
Federal income tax rate change (i)		26.2		—	Less than one year
Other		13.7		—	Less than one year
	$	114.9	$	10.9
Regulatory liabilities - non-current
Option fees deferral (a)	$	—	$	4.3	Various
Refundable tax credit (h)		6.1		7.5	Various
Future expense of pension and other retirement benefits (a)		166.7		—		Various
Future removal and site restoration costs (j)		514.7		153.3	3 - 56 years
Deferred loss on reacquired debt		1.8		—		Various
Federal income tax rate change (a)(i)		698.4		101.8	Various
Insurance recovery of environmental costs		—		0.3	2 years
Other		5.1		1.4	Various
	$	1,392.8	$	268.6

(a) Washington Gas is not entitled to a rate of return on these assets. Washington Gas is allowed to recover and required to pay, using short-term interest rates, the carrying costs related to billed gas costs due from and to its customers in the District of Columbia and Virginia jurisdictions.

(b) Includes fair value of derivatives, which are not included in customer bills until settled.

(c) Represents the timing difference between the recognition of workers compensation and short-term disability costs in accordance with generally accepted accounting principles and the way these costs are recovered through rates.Certain utilities have recovered pension costs related to regulated operations in rates, and as such the Corporation has recorded a regulatory asset for the unamortized costs associated with the defined benefit and post-retirement benefit plans. Depending on the method utilized by the utility, the recovery period can be either the expected service life of the employees, the benefit period for employees, or a specific recovery period as approved by the respective regulator.

(d) Relates to costs not recoverable through rates in the District of Columbia jurisdiction. However, Washington Gas is allowed to amortize these prior unrecovered pension and other post-retirement benefits through 2019.

(e) This balance represents allowed environmental remediation expenditures at SEMCO Gas and Washington Gas sites to be recovered through rates.

(f) The losses or gains on the issuance and extinguishment of debt and interest-rate derivative instruments include unamortized balances from transactions executed in prior fiscal years. These transactions create gains and losses that are amortized over the remaining life of the debt as prescribed by regulatory accounting requirements. This also includes a fair value adjustment of $89 million recorded on the WGL Acquisition (Note 3).

(g) This regulatory asset reflects the amount of deferred income taxes expected to be refunded, or recovered from, customers in future rates.

(h) On September 18, 2013, CINGSA received a US$15.0 million gas storage facility tax credit from the State of Alaska for the benefit of its firm storage service customers. CINGSA will derive no direct or indirect benefit from the tax credit. Following receipt of the tax credit, CINGSA deposited it in a separate interest-bearing account. CINGSA will act as a custodian of the tax credit and any interest earned for the benefit of CINGSA's customers. On an annual basis, covering the years 2012 through 2021, CINGSA will disburse to the customers 1/10th of the amount of the tax credit not subject to refund to the State and interest earned. The RCA has approved the disbursement methodology.

(i) The TCJA was enacted on December 22, 2017, and required the Corporation to revalue its U.S. deferred tax assets and liabilities to the lower federal corporate tax rate of 21 percent resulting in excess accumulated deferred income taxes. The tax rate reduction created a reduction in deferred tax liability, which SEMCO Gas and Washington Gas are required to refund to ratepayers.

This amount and timing of draw down is dependent upon the cost of removal of underlying utility property, plant and equipment and the life of property, plant and equipment

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ACCUMULATED OTHER COMPREHENSIVE INCOME (Tables)

12 Months Ended

Dec. 31, 2018

ACCUMULATED OTHER COMPREHENSIVE INCOME [Abstract]

Schedule of Accumulated Other Comprehensive Income

($ millions)	Available- for-sale		Defined benefit pension and PRB plans		Hedge net investments		Translation foreign operations		Equity investee		Total
Opening balance, January 1, 2018	$	(7.1)	$	(11.4)	$	(129.0)	$	342.9	$	3.7	$	199.1
OCI before reclassification		—		(14.1)		(90.6)		458.5		2.1		355.9
Amounts reclassified from OCI		—		0.7		—		—		—		0.7
Adoption of ASU No. 2016-01 (note 2)		7.1		—		—		—		—		7.1
Curtailment of DB and PRB plan		—		4.2		—		—		—		4.2
Current period OCI (pre-tax)		7.1		(9.2)		(90.6)		458.5		2.1		367.9
Income tax on amounts retained in    AOCI		—		3.3		10.4		—		—		13.7
Income tax on amounts reclassified    to earnings		—		(0.2)		—		—		—		(0.2)
Income tax on amounts related to curtailment of DB and PRB plan		—		(1.5)		—		—		—		(1.5)
Net current period OCI		7.1		(7.6)		(80.2)		458.5		2.1		379.9
Ending balance, December 31, 2018	$	—	$	(19.0)	$	(209.2)	$	801.4	$	5.8	$	579.0
Opening balance, January 1, 2017	$	19.8	$	(11.3)	$	(135.6)	$	526.3	$	5.9	$	405.1
OCI before reclassification		(30.3)		(1.3)		6.6		(183.4)		(2.2)		(210.6)
Amounts reclassified from AOCI		—		1.3		—		—		—		1.3
Current period OCI (pre-tax)		(30.3)		—		6.6		(183.4)		(2.2)		(209.3)
Income tax on amounts retained in    AOCI		3.4		0.3		—		—		—		3.7
Income tax on amounts reclassified    to earnings		—		(0.4)		—		—		—		(0.4)
Net current period OCI		(26.9)		(0.1)		6.6		(183.4)		(2.2)		(206.0)
Ending balance, December 31, 2017	$	(7.1)	$	(11.4)	$	(129.0)	$	342.9	$	3.7	$	199.1

Summary of Reclassification from Accumulated Other Comprehensive Income

AOCI components reclassified	Income statement line item		Year ended December 31, 2018		Year ended December 31, 2017
Defined benefit pension and PRB plans	Operating and administrative expense	$	0.7	$	1.3
Deferred income taxes	Income tax expenses – deferred		(0.2)		(0.4)
		$	0.5	$	0.9

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FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGMENT (Tables)

12 Months Ended

Dec. 31, 2018

Derivative [Line Items]

Schedule of Fair Value of Risk Management Assets and Liabilities

	December 31, 2018
	Carrying Amount		Level 1		Level 2		Level 3		Total Fair Value
Financial assets
Fair value through net income(a)
Risk management assets - current	$	99.0	$	—	$	68.3	$	30.7	$	99.0
Risk management assets - non-current		49.0		—		18.0		31.0		49.0
Equity securities(b)		8.4		8.4		—		—		8.4
Fair value through regulatory assets/liabilities (a)
Risk management assets - current		15.1		—		2.7		12.4		15.1
Risk management assets - non-current		8.7		—		—		8.7		8.7
Amortized cost
Loans and receivables (b)		45.0		—		45.2		—		45.2
	$	225.2	$	8.4	$	134.2	$	82.8	$	225.4
Financial liabilities
Fair value through net income(a)
Risk management liabilities - current	$	72.0	$	—	$	41.3	$	30.7	$	72.0
Risk management liabilities - non-current		103.4		—		15.3		88.1		103.4
Fair value through regulatory assets/liabilities (a)
Risk management liabilities - current		17.3		—		2.9		14.4		17.3
Risk management liabilities - non-current		109.6		—		0.1		109.5		109.6
Amortized cost
Current portion of long-term debt		890.2		—		884.4		—		884.4
Long-term debt		8,066.9		—		6,027.6		2,012.7		8,040.3
Other current liabilities (c)		11.2		—		11.2		—		11.2
Other long-term liabilities (c)		2.0		—		2.0		—		2.0
	$	9,272.6	$	—	$	6,984.8	$	2,255.4	$	9,240.2

(a) To manage price risk associated with acquiring natural gas supply for Maryland, Virginia, and District of Columbia utility customers, Washington Gas, a subsidiary of the Corporation, enters into physical and financial derivative transactions. Any gains and losses associated with these derivatives are recorded as regulatory liabilities or assets, respectively, to reflect the rate treatment for these economic hedging activities. Additionally, as part of its asset optimization program, Washington Gas enters into derivatives with the primary objective of securing operating margins that Washington Gas will ultimately realize. Regulatory sharing mechanisms provide for the annual realized profit from these transactions to be shared between Washington Gas' shareholder and customers; therefore, changes in fair value are recorded through earnings, or as regulatory assets or liabilities to the extent that it is probable that realized gains and losses associated with these derivative transactions will be included in the rates charged to customers when they are realized.

(b) Included under the line item "long-term investments and other assets" on the Consolidated Balance Sheets.

(c) Excludes non-financial liabilities.

	December 31, 2017
	Carrying Amount		Level 1		Level 2		Level 3		Total Fair Value
Financial assets
Fair value through net income
Risk management assets - current	$	38.6	$	—	$	38.6	$	—	$	38.6
Risk management assets - non-current		15.9		—		15.9		—		15.9
Equity securities(a)		95.0		95.0		—		—		95.0
Amortized cost
Loans and receivables (a)		75.0		—		85.6		—		85.6
	$	224.5	$	95.0	$	140.1	$	—	$	235.1
Financial liabilities
Fair value through net income
Risk management liabilities - current	$	57.6	$	—	$	57.6	$	—	$	57.6
Risk management liabilities - non-current		13.8		—		13.8		—		13.8
Amortized cost
Current portion of long-term debt		188.9		—		189.6		—		189.6
Long-term debt		3,436.5		—		3,568.3		—		3,568.3
Other current liabilities (b)		22.4		—		22.4		—		22.4
Other long-term liabilities (b)		146.0		—		147.7		—		147.7
	$	3,865.2	$	—	$	3,999.4	$	—	$	3,999.4

(a) Included under the line item "long-term investments and other assets" on the Consolidated Balance Sheets.

(b) Excludes non-financial liabilities.

Quantitative Information About The Significant Unobservable Inputs Used In The Fair Value Measurement Of Level 3

		Net Fair Value	Valuation Technique	Unobservable Inputs	Range
Natural gas	$	(144.1)	Discounted Cash Flow	Natural Gas Basis Price (per dekatherm)	($1.40) - $7.28
Natural gas	$	(4.4)	Option Model	Natural Gas Basis Price (per dekatherm)	($1.37) - $5.07
				Annualized Volatility of Spot Market Natural Gas	37.46% - 900.98%
Electricity	$	(14.7)	Discounted Cash Flow	Electricity Congestion Price (per megawatt hour)	($8.28) - $84.44

Changes In Net Fair Value Of Derivative Assets And Liabilities Classified As Level 3

For the year ended December 31	2018						2017
		Natural Gas		Electricity		Total		Natural Gas		Electricity		Total
Balance, beginning of year	$	—	$	—	$	—	$	—	$	—	$	—
Acquired (note 3)		(136.1)		(10.6)		(146.7)		—		—		—
Realized and unrealized losses:								—		—		—
Recorded in income		(8.3)		(6.5)		(14.8)
Recorded in regulatory assets		(5.9)		—		(5.9)		—		—		—
Transfers out of Level 3		7.3		—		7.3		—		—		—
Purchases		—		6.4		6.4		—		—		—
Settlements		0.3		(3.4)		(3.1)		—		—		—
Foreign exchange translation		(5.8)		(0.6)		(6.4)
Balance, end of year	$	(148.5)	$	(14.7)	$	(163.2)	$	—	$	—	$	—

Realized And Unrealized Losses Recorded To Income For Level 3 Measurements

For the year ended December 31	2018		2017
Recorded to revenue
Commodity contracts	$	(11.1)	$	—
Recorded to cost of sales
Commodity contracts		(3.7)		—
	$	(14.8)	$	—

Summary of Unrealized Gains (Losses) on Risk Management Contracts

For the year ended December 31	2018		2017
Natural gas	$	(2.2)	$	2.2
Storage optimization		—		2.7
NGL frac spread		40.0		(11.7)
Power		9.3		(20.8)
Foreign exchange		33.7		(34.9)
	$	80.8	$	(62.5)

Schedule of Offsetting Assets and Liabilities

	December 31, 2018
Risk management assets (a)	Gross amounts of recognized assets/liabilities		Gross amounts offset in balance sheet		Netting of collateral		Net amounts presented in balance sheet
Natural gas	$	200.8	$	(82.0)	$	—	$	118.8
NGL frac spread		18.7		(0.7)		—		18.0
Power		42.8		(7.8)		—		35.0
	$	262.3	$	(90.5)	$	—	$	171.8
Risk management liabilities (b)
Natural gas	$	340.4	$	(82.0)	$	(3.3)	$	255.1
NGL frac spread		2.7		(0.7)		—		2.0
Power		50.6		(7.8)		1.2		44.0
Foreign exchange		1.2		—		—		1.2
	$	394.9	$	(90.5)	$	(2.1)	$	302.3

(a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $114.1 million and risk management assets (non-current) balance of $57.7 million.

(b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $89.3 million and risk management liabilities (non-current) balance of $213.0 million.

	December 31, 2017
Risk management assets (a)	Gross amounts of recognized assets/liabilities		Gross amounts offset in balance sheet		Netting of collateral		Net amounts presented in balance sheet
Natural gas	$	41.0	$	(6.2)	$	—	$	34.8
NGL frac spread		1.3		(0.3)		—		1.0
Power		17.7		(0.7)		—		17.0
Foreign exchange		1.7		—		—		1.7
	$	61.7	$	(7.2)	$	—	$	54.5
Risk management liabilities (b)
Natural gas	$	35.1	$	(6.2)	$	—	$	28.9
NGL frac spread		25.3		(0.3)		—		25.0
Power		14.0		(0.7)		4.2		17.5
	$	74.4	$	(7.2)	$	4.2	$	71.4

(a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $38.6 million and risk management assets (non-current) balance of $15.9 million.

(b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $57.6 million and risk management liabilities (non-current) balance of $13.8 million.

Cash Collateral

The following table presents collateral not offset against risk management assets and liabilities:

		December 31, 2018		December 31, 2017
Collateral posted with counterparties	$	27.6	$	—
Cash collateral held representing an obligation	$	0.8	$	—

Any collateral posted that is not offset against risk management assets and liabilities is included in line item “prepaid expenses and other current assets” in the Consolidated Balance Sheets. Collateral received and not offset against risk management assets and liabilities is included in line item “customer deposits” in the Consolidated Balance Sheets.

Certain derivative instruments contain contract provisions that require collateral to be posted if the credit rating of AltaGas or certain of its subsidiaries falls below certain levels. At December 31, 2018 and 2017, AltaGas had not posted any collateral related to its derivative liabilities that contained credit-related contingent features. The following table shows the aggregate fair value of all derivative instruments with credit-related contingent features that are in a liability position, as well as the maximum amount of collateral that would be required if the most intrusive credit-risk-related contingent features underlying these agreements were triggered:

		December 31, 2018		December 31, 2017
Risk management liabilities with credit-risk-contingent features	$	14.7	$	—
Maximum potential collateral requirements	$	7.5	$	—

Summary of Potential Impact on Pre-Tax Income Due to Change in Fair Value of Price Risk Derivatives

Factor	Increase or decrease to forward prices	Increase or decrease to income before tax ($ millions)
Alberta power price	$1/MWh	0.3
PJM power price	$1/MWh	1.2
AECO natural gas price	$0.50/GJ	5.9
NYMEX natural gas price	$0.50/GJ	31.5
NGL frac spread:
Propane	$1/Bbl	1.7
Butane	$1/Bbl	0.1
Western Texas Intermediate (WTI) crude oil	$1/Bbl	0.3
Natural gas	$0.50/GJ	4.7

Schedule of Accounts Receivable Past Due or Impaired

As at December 31, 2018	Total		AR accruals		Receivables impaired		Less than 30 days		31 to 60 days		61 to 90 days		Over 90 days
Trade receivable	$	1,574.6	$	447.5	$	54.7	$	961.5	$	74.1	$	12.8	$	24.0
Other		27.6		—		—		27.5		—		—		0.1
Allowance for credit losses		(54.7)		—		(54.7)		—		—		—		—
	$	1,547.5	$	447.5	$	—	$	989.0	$	74.1	$	12.8	$	24.1

As at December 31, 2017	Total		AR accruals		Receivables impaired		Less than 30 days		31 to 60 days		61 to 90 days		Over 90 days
Trade receivable	$	383.0	$	184.6	$	2.4	$	187.0	$	7.9	$	1.4	$	(0.3)
Other		2.3		—		—		2.3		—		—		—
Allowance for credit losses		(2.4)		—		(2.4)		—		—		—		—
	$	382.9	$	184.6	$	—	$	189.3	$	7.9	$	1.4	$	(0.3)

Allowance for credit losses	December 31, 2018		December 31, 2017
Balance, beginning of year	$	2.4	$	2.5
Foreign exchange translation		0.1		(0.1)
New allowance (a)		53.1		0.4
Change in allowance		(0.9)		—
Allowance applied to uncollectible customer accounts		—		(0.4)
Balance, end of year	$	54.7	$	2.4

Schedule of Contractual Maturities for Financial Liabilities

	Contractual maturities by period
As at December 31, 2018	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Accounts payable and accrued liabilities	$	1,488.2	$	1,488.2	$	—	$	—	$	—
Dividends payable		22.0		22.0		—		—		—
Short-term debt		1,209.9		1,209.9		—		—		—
Other current liabilities (a)		11.2		11.2		—		—		—
Other long-term liabilities (a)		2.0		—		2.0		—		—
Risk management contract liabilities		302.3		89.3		113.3		33.3		66.4
Current portion of long-term debt (b)		888.5		888.5		—		—		—
Long-term debt (b)		8,014.8		—		3,063.4		1,592.6		3,358.8
	$	11,938.9	$	3,709.1	$	3,178.7	$	1,625.9	$	3,425.2

(a) Excludes non-financial liabilities

(b) Excludes deferred financing costs and discounts

	Contractual maturities by period
As at December 31, 2017	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Accounts payable and accrued liabilities	$	415.3	$	415.3	$	—	$	—	$	—
Dividends payable		32.0		32.0		—		—		—
Short-term debt		46.8		46.8		—		—		—
Other current liabilities (a)		22.4		22.4		—		—		—
Other long-term liabilities (a)		146.0		—		25.7		20.8		99.5
Risk management contract liabilities		71.4		57.6		11.1		2.7		—
Current portion of long-term debt (b)		188.9		188.9		—		—		—
Long-term debt (b)		3,450.9		—		1,009.1		363.8		2,078.0
	$	4,373.7	$	763.0	$	1,045.9	$	387.3	$	2,177.5

(a) Excludes non-financial liabilities

(b) Excludes deferred financing costs and discounts

Natural Gas [Member]

Derivative [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

December 31, 2018	Fixed price (per GJ)	Period (months)	Notional volume (GJ)	Fair Value ($ millions)
Sales	1.07 to 12.19	1-178	858,640,810	19.0
Purchases	0.69 to 16.26	1-179	1,638,207,391	(179.5)
Swaps	2.56 to 15.37	1-231	621,578,572	20.9
December 31, 2017	Fixed price (per GJ)	Period (months)	Notional volume (GJ)	Fair Value ($ millions)
Sales	0.42 to 6.89	1-60	94,804,039	14.8
Purchases	0.52 to 6.40	1-48	61,980,315	(16.8)
Swaps	2.86 to 9.38	1-10	6,039,642	7.9

NGL Frac Spread [Member] [Member]

Derivative [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

December 31, 2018	Fixed price	Period (months)	Notional volume	Fair Value ($ millions)
Propane swaps	$38.89 to $47.63/bbl	1-12	1,725,114 Bbl	12.6
Butane swaps	$52.95 to $55.26/bbl	1-12	74,371 Bbl	1.2
Crude oil swaps	$79.64 to $86.28/bbl	1-12	329,230 Bbl	6.0
Natural gas swaps	$1.38 to $1.68/GJ	1-12	9,490,365 GJ	(3.8)
December 31, 2017	Fixed price	Period (months)	Notional volume	Fair Value ($ millions)
Propane swaps	$28.77 to $49.21 /Bbl	1-12	1,992,927 Bbl	(10.9)
Butane swaps	$47.83 to $54.67 /Bbl	1-12	130,088 Bbl	(0.3)
Crude oil swaps	$61.05 to $75.64 /Bbl	1-12	518,665 Bbl	(4.4)
Natural gas swaps	$0.42 to $2.27 /GJ	1-12	11,428,515 GJ	(8.4)

Power [Member]

Derivative [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

December 31, 2018	Fixed price (per MWh)	Period (months)	Notional volume (MWh)	Fair Value ($ millions)
Power sales	26.90 to 95.03	1-60	11,881,575	(1.9)
Power purchases	25.50 to 50.25	1-42	8,507,874	16.4
Swap purchases	(6.07) to 76.18	1-48	20,957,180	(22.3)
December 31, 2017	Fixed price (per MWh)	Period (months)	Notional volume (MWh)	Fair Value ($ millions)
Power sales	38.20 to 95.03	1-60	2,169,321	(2.5)
Power purchases	58.50	1-12	17,520	(4.5)
Swap purchases	37.50 to 63.50	1-48	1,563,160	6.5

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REVENUE (Tables)

12 Months Ended

Dec. 31, 2018

REVENUE [Abstract]

Disaggregation of Revenue by Major Sources

	Year ended December 31, 2018
		Utilities		Midstream		Power		Corporate		Total
Revenue from contracts with customers
Commodity sales contracts	$	—	$	665.2	$	497.5	$	—	$	1,162.7
Midstream service contracts		—		205.0		—		—		205.0
Gas sales and transportation services		1,684.3		—		—		—		1,684.3
Storage services		35.4		—		—		—		35.4
Other		10.7		0.6		25.1		—		36.4
Total revenue from contracts with customers	$	1,730.4	$	870.8	$	522.6	$	—	$	3,123.8
Other sources of revenue
Revenue from alternative revenue programs (a)	$	21.7	$	—	$	—	$	—	$	21.7
Leasing revenue (b)		0.6		96.6		354.9		—		452.1
Risk management and trading activities (c)(d)		1.0		377.6		268.5		(2.9)		644.2
Other		(1.1)		(0.4)		16.0		0.4		14.9
Total revenue from other sources	$	22.2	$	473.8	$	639.4	$	(2.5)	$	1,132.9
Total revenue	$	1,752.6	$	1,344.6	$	1,162.0	$	(2.5)	$	4,256.7

(a) A large portion of revenue generated from the Utilities segment is subject to rate regulation and accordingly there are circumstances where the revenue recognized is mandated by the applicable regulators in accordance with ASC 980.

(b) Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Power segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases.

(c) Risk management activities involve the use of derivative instruments such as physical and financial swaps, forward contracts, and options. These derivatives are accounted for under ASC 815 and ASC 825. The majority of revenue generated by the Midstream and Power segments is from the physical sale and delivery of natural gas and power to end users, except for WGL Midstream (see footnote d).

(d) WGL Midstream trading margins are reported in risk management and trading activities from the Midstream segment. WGL Midstream enters into derivative contracts for the purpose of optimizing its storage and transportation capacity as well as managing the transportation and storage assets on behalf of third parties. The trading margins of WGL Midstream, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues of $264.2 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract, which are in scope of ASC 606, are reported in the risk management and trading activities. While the GAIL contract is individually not accounted for as a derivative, it is inseparable from the overall trading portfolio of WGL Midstream. Revenue is recognized at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount. The contract has a term of 20 years and began on March 31, 2018.

Schedule of Estimated Revenue Related to Performance Obligations

		2019		2020		2021		2022		2023		> 2023		Total
Midstream service contracts	$	52.2	$	55.7	$	32.3	$	31.9	$	28.0	$	192.4	$	392.5
Gas sales and transportation services		0.6		0.6		0.6		0.6		0.6		3.2		6.2
Storage services		36.7		36.3		36.3		36.3		36.3		299.8		481.7
Other		37.0		10.5		1.6		0.8		0.8		3.2		53.9
Subtotals	$	126.5	$	103.1	$	70.8	$	69.6	$	65.7	$	498.6	$	934.3

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SHAREHOLDERS' EQUITY (Tables)

12 Months Ended

Dec. 31, 2018

SHAREHOLDERS' EQUITY [Abstract]

Schedule of Common Shares Issued and Outstanding

Common Shares Issued and Outstanding	Number of  shares		Amount
January 1, 2017	166,906,833	$	3,773.4
Shares issued for cash on exercise of options	240,125		6.5
Deferred taxes on share issuance cost	—		(8.3)
Shares issued under DRIP	8,132,258		236.3
December 31, 2017	175,279,216		4,007.9
Shares issued on conversion of subscription receipts, net of issuance costs	84,510,000		2,305.6
Shares issued for cash on exercise of options	57,275		1.3
Deferred taxes on share issuance costs	—		13.3
Shares issued under DRIP	15,377,575		325.8
Issued and outstanding at December 31, 2018	275,224,066	$	6,653.9

Schedule of Preferred Shares Issued and Outstanding

As at	December 31, 2018			December 31, 2017
Issued and Outstanding	Number of shares		Amount	Number of shares		Amount
Series A	5,511,220	$	137.8	5,511,220	$	137.8
Series B	2,488,780		62.2	2,488,780		62.2
Series C	8,000,000		205.6	8,000,000		205.6
Series E	8,000,000		200.0	8,000,000		200.0
Series G	8,000,000		200.0	8,000,000		200.0
Series I	8,000,000		200.0	8,000,000		200.0
Series K	12,000,000		300.0	12,000,000		300.0
Washington Gas
$4.80 series	150,000		19.7	—		—
$4.25 series	70,600		9.4	—		—
$5.00 series	60,000		7.9	—		—
Share issuance costs, net of taxes			(27.9)			(27.9)
Fair value adjustment on WGL Acquisition (note 3)			4.1			—
	52,280,600	$	1,318.8	52,000,000	$	1,277.7

Schedule of Common and Preferred Stock Outstanding Roll Forward

Common Shares Issued and Outstanding	Number of  shares		Amount
January 1, 2017	166,906,833	$	3,773.4
Shares issued for cash on exercise of options	240,125		6.5
Deferred taxes on share issuance cost	—		(8.3)
Shares issued under DRIP	8,132,258		236.3
December 31, 2017	175,279,216		4,007.9
Shares issued on conversion of subscription receipts, net of issuance costs	84,510,000		2,305.6
Shares issued for cash on exercise of options	57,275		1.3
Deferred taxes on share issuance costs	—		13.3
Shares issued under DRIP	15,377,575		325.8
Issued and outstanding at December 31, 2018	275,224,066	$	6,653.9

Preferred Shares

As at	December 31, 2018			December 31, 2017
Issued and Outstanding	Number of shares		Amount	Number of shares		Amount
Series A	5,511,220	$	137.8	5,511,220	$	137.8
Series B	2,488,780		62.2	2,488,780		62.2
Series C	8,000,000		205.6	8,000,000		205.6
Series E	8,000,000		200.0	8,000,000		200.0
Series G	8,000,000		200.0	8,000,000		200.0
Series I	8,000,000		200.0	8,000,000		200.0
Series K	12,000,000		300.0	12,000,000		300.0
Washington Gas
$4.80 series	150,000		19.7	—		—
$4.25 series	70,600		9.4	—		—
$5.00 series	60,000		7.9	—		—
Share issuance costs, net of taxes			(27.9)			(27.9)
Fair value adjustment on WGL Acquisition (note 3)			4.1			—
	52,280,600	$	1,318.8	52,000,000	$	1,277.7

Summary of Cumulative Redeemable Preferred Shares

	Current yield	Annual dividend per share(b)	Redemption price per share	Redemption and conversion option date(c)(d)	Right to convert into(d)
AltaGas
Series A (e)	3.38%	$0.845	$25	September 30, 2020	Series B
Series B (f)	Floating (f)	Floating (f)	$25	September 30, 2020 (g)	Series A
Series C (h)	5.29%	US$1.3225	US$25	September 30, 2022	Series D
Series E (e)	5.393%	$1.34825	$25	December 31, 2023	Series F
Series G (e)	4.75%	$1.1875	$25	September 30, 2019	Series H
Series I (i)	5.25%	$1.3125	$25	December 31, 2020	Series J
Series K (j)	5.00%	$1.25	$25	March 31, 2022	Series L
Washington Gas
$4.80 series	4.27%	US$4.80	US$101	n/a	n/a
$4.25 series	4.27%	US$4.25	US$105	n/a	n/a
$5.00 series	4.27%	US$5.00	US$102	n/a	n/a

(a) The table above only includes those series of preferred shares that are currently issued and outstanding. The Corporation is authorized to issue up to 8,000,000 of each of Series D Shares,  Series F Shares,  Series H Shares, and Series J Shares, and up to 12,000,000 of Series L Shares, subject to certain conditions, upon conversion by the holders of the applicable currently issued and outstanding series of preferred shares noted opposite such series in the table on the applicable conversion option date. If issued upon the conversion of the applicable series of preferred shares, Series F Shares,  Series H Shares,  Series J Shares, and Series L Shares are also redeemable for $25.50, and Series D Shares are redeemable for US$25.50 on any date after the applicable conversion option date, plus all accrued but unpaid dividends to, but excluding, the date fixed for redemption. 

(b) The holders of Series A Shares, Series C Shares, Series E Shares, Series G Shares, Series I Shares and Series K Shares are entitled to receive a cumulative quarterly fixed dividend as and when declared by the Board of Directors. The holders of Series B Shares are entitled to receive a quarterly floating dividend as and when declared by the Board of Directors. If issued upon the conversion of the applicable series of Preferred Shares, the holders of Series D Shares, Series F Shares, Series H Shares, Series J Shares and Series L Shares will be entitled to receive a quarterly floating dividend as and when declared by the Board of Directors.

(c) AltaGas may, at its option, redeem all or a portion of the outstanding shares for the redemption price per share, plus all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary thereafter.

(d) The holder will have the right, subject to certain conditions, to convert their preferred shares of a specified series into Preferred Shares of that other specified series as noted in this column of the table on the applicable conversion option date and every fifth anniversary thereafter.

(e) Holders will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at a rate equal to the sum of the then five-year Government of Canada bond yield plus 2.66 percent (Series A Shares), 3.17 percent (Series E Shares), and 3.06 percent (Series G Shares). 

(f) Holders of Series B Shares will be entitled to receive cumulative quarterly floating dividends, which will reset each quarter thereafter at a rate equal to the sum of the then 90-day government of Canada Treasury Bill rate plus 2.66 percent. Each quarterly dividend is calculated as the annualized amount multiplied by the number of days in the quarter, divided by the number of days in the year. Commencing December 31, 2018, the floating quarterly dividend rate for Series B Shares is $0.26938 per share for the period starting December 31, 2018 to, but excluding, March 31, 2019.

(g) Series B Shares can be redeemed for $25.50 per share on any date after September 30, 2015 that is not a Series B conversion date, plus all accrued and unpaid dividends to, but excluding, the date fixed for redemption.

(h) Holders of Series C Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the sum of the five-year U.S. Government bond yield plus 3.58 percent.

(i) Holders of Series I Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the then five-year Government of Canada bond yield plus 4.19 percent, provided that, in any event, such rate shall not be less than 5.25 percent per annum.

(j) Holders of Series K Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the then five-year Government of Canada bond yield plus 3.80 percent, provided that, in any event, such rate shall not be less than 5.00 percent per annum.

Summary of Share Option Activity

As at	December 31, 2018			December 31, 2017
	Options outstanding			Options outstanding
	Number of options	Exercise price(a)		Number of options	Exercise price(a)
Share options outstanding, beginning of year	4,533,761	$	32.35	4,119,386	$	32.39
Granted	2,811,460		16.69	848,000		30.80
Exercised	(57,275)		20.68	(240,125)		24.63
Forfeited	(878,013)		36.47	(193,500)		36.36
Expired	(100,750)		14.60	—		—
Share options outstanding, end of year	6,309,183	$	25.18	4,533,761	$	32.35
Share options exercisable, end of year	2,897,723	$	32.01	3,326,197	$	31.93

(a) Weighted average.

Summary of Employee Share Option Plan

	Options outstanding				Options exercisable
			Weighted	Weighted average			Weighted	Weighted average
	Number		average	remaining	Number		average	remaining
	outstanding		exercise price	contractual life	exercisable		exercise price	contractual life
$14.24 to $18.00	2,322,635	$	14.55	5.91	28,000	$	17.10	1.33
$18.01 to $25.08	425,000		20.76	1.83	425,000		20.76	1.83
$25.09 to $50.89	3,561,548		32.65	3.48	2,444,723		34.14	2.95
	6,309,183	$	25.18	4.26	2,897,723	$	32.01	2.77

Summary of Fair Value of Options Granted

Year ended December 31	2018	2017
Fair value per option ($)	1.27	1.91
Risk-free interest rate (%)	1.99	1.31
Expected life (years)	6	6
Expected volatility (%)	23.23	21.05
Annual dividend per share ($) (a)	1.18	2.12
Forfeiture rate (%)	—	—

Schedule of MTIP and DSUP Activity

PUs, RUs, and DSUs	December 31, 2018	December 31, 2017
(number of units)
Balance, beginning of year	564,549	364,839
Acquired (a)	5,291,621	—
Granted	9,502,347	386,126
Additional units added by performance factor	—	24,301
Vested and paid out	(148,154)	(221,775)
Forfeited	(66,522)	(27,279)
Units in lieu of dividends	55,934	38,337
Outstanding, end of year	15,199,775	564,549

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NET INCOME PER COMMON SHARE (Tables)

12 Months Ended

Dec. 31, 2018

NET INCOME PER COMMON SHARE [Abstract]

Summary of Net Income per Common Share

	Year ended December 31
	2018		2017
Numerator:
Net income (loss) applicable to controlling interests	$	(435.1)	$	91.6
Less: Preferred share dividends		(66.6)		(61.3)
Net income (loss) applicable to common shares	$	(501.7)	$	30.3
Denominator:
(millions)
Weighted average number of common shares outstanding		222.6		171.0
Dilutive equity instruments(a)		0.1		0.3
Weighted average number of common shares    outstanding - diluted		222.7		171.3
Basic net income (loss) per common share	$	(2.25)	$	0.18
Diluted net income (loss) per common share	$	(2.25)	$	0.18

(a) Includes all options that have a strike price lower than the share price of AltaGas' common shares as at December 31, 2018 and 2017.

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OTHER INCOME (Tables)

12 Months Ended

Dec. 31, 2018

OTHER INCOME [Abstract]

Schedule of Other Income (Loss)

Year ended December 31	2018		2017
Losses from sale of assets	$	(10.6)	$	(2.7)
Other components of net benefit cost (note 2)		18.9		—
Interest income and other revenue		2.7		8.7
Gains (losses) on investments		(10.1)		3.6
	$	0.9	$	9.6

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OPERATING LEASES (Tables)

12 Months Ended

Dec. 31, 2018

OPERATING LEASES [Abstract]

Schedule of Future Minimum Revenue from Operating Leases

2019	194.4
2020	155.3
2021	111.9
2022	112.0
2023	104.2

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PENSION PLANS AND RETIREE BENEFITS (Tables)

12 Months Ended

Dec. 31, 2018

PENSION PLANS AND RETIREE BENEFITS [Abstract]

Summary of Defined Benefit Plans

		Canada			United States				Total
			Post-				Post-				Post-
	Defined		Retirement		Defined		Retirement		Defined		Retirement
Year ended December 31, 2018	Benefit		Benefits		Benefit		Benefits		Benefit		Benefits
Accrued benefit obligation
Balance, beginning of year	$	165.6	$	15.8	$	303.8	$	82.7	$	469.4	$	98.5
Plans disposed (note 4)		(132.1)		(13.6)		—		—		(132.1)		(13.6)
Actuarial gain		(0.8)		(0.1)		(67.7)		(33.8)		(68.5)		(33.9)
Current service cost		2.4		0.1		16.2		5.3		18.6		5.4
Member contributions		—		—		—		2.1		—		2.1
Interest cost		1.2		0.1		38.0		10.9		39.2		11.0
Benefits paid		(2.7)		—		(43.2)		(13.4)		(45.9)		(13.4)
Expenses paid		—		—		(0.9)		(0.1)		(0.9)		(0.1)
Plan combinations		0.7		—		1,311.7		382.9		1,312.4		382.9
Plan amendments		—		(0.4)		—		—		—		(0.4)
Foreign exchange translation		—		—		77.4		21.4		77.4		21.4
Balance, end of year	$	34.3	$	1.9	$	1,635.3	$	458.0	$	1,669.6	$	459.9
Plan assets
Fair value, beginning of year	$	115.2	$	8.1	$	248.7	$	70.8	$	363.9	$	78.9
Plans disposed (note 4)		(102.1)		(8.1)		—		—		(102.1)		(8.1)
Actual return on plan assets		(0.3)		—		(54.7)		(37.2)		(55.0)		(37.2)
Employer contributions		3.4		—		7.6		2.5		11.0		2.5
Member contributions		—		—		—		2.1		—		2.1
Benefits paid		(2.7)		—		(43.2)		(13.4)		(45.9)		(13.4)
Expenses paid		—		—		(0.9)		(0.1)		(0.9)		(0.1)
Plan combinations		0.3		—		1,133.2		732.7		1,133.5		732.7
Foreign exchange translation		—		—		63.4		33.8		63.4		33.8
Fair value, end of year	$	13.8	$	—	$	1,354.1	$	791.2	$	1,367.9	$	791.2
Net amount recognized	$	(20.5)	$	(1.9)	$	(281.2)	$	333.2	$	(301.7)	$	331.3

		Canada			United States				Total
			Post-				Post-				Post-
	Defined		Retirement		Defined		Retirement		Defined		Retirement
Year ended December 31, 2017	Benefit		Benefits		Benefit		Benefits		Benefit		Benefits
Accrued benefit obligation
Balance, beginning of year	$	150.0	$	16.4	$	290.5	$	72.7	$	440.5	$	89.1
Actuarial loss (gain)		8.3		(1.6)		23.2		14.4		31.5		12.8
Current service cost		7.9		0.7		8.0		1.8		15.9		2.5
Member contributions		0.2		—		—		—		0.2		—
Interest cost		5.8		0.6		11.7		2.9		17.5		3.5
Benefits paid		(6.3)		(0.3)		(8.6)		(3.2)		(14.9)		(3.5)
Expenses paid		(0.3)		—		(0.8)		(0.1)		(1.1)		(0.1)
Plan settlements		—		—		—		(0.5)		—		(0.5)
Foreign exchange translation		—		—		(20.2)		(5.3)		(20.2)		(5.3)
Balance, end of year	$	165.6	$	15.8	$	303.8	$	82.7	$	469.4	$	98.5
Plan assets
Fair value, beginning of year	$	101.5	$	6.8	$	226.9	$	67.2	$	328.4	$	74.0
Actual return on plan assets		8.5		0.4		37.9		11.0		46.4		11.4
Employer contributions		11.6		1.2		9.5		0.6		21.1		1.8
Member contributions		0.2		—		—		—		0.2		—
Benefits paid		(6.3)		(0.3)		(8.6)		(3.2)		(14.9)		(3.5)
Expenses paid		(0.3)		—		(0.8)		(0.1)		(1.1)		(0.1)
Foreign exchange translation		—		—		(16.2)		(4.7)		(16.2)		(4.7)
Fair value, end of year	$	115.2	$	8.1	$	248.7	$	70.8	$	363.9	$	78.9
Net amount recognized	$	(50.4)	$	(7.7)	$	(55.1)	$	(11.9)	$	(105.5)	$	(19.6)

Schedule of Amounts Included in the Consolidated Balance Sheets

	December 31, 2018						December 31, 2017
				Post-						Post-
		Defined		Retirement				Defined		Retirement
		Benefit		Benefits		Total		Benefit		Benefits		Total
Prepaid post-retirement benefits	$	—	$	341.4	$	341.4	$	—	$	—	$	—
Accounts payable and accrued liabilities		(27.6)		—		(27.6)		(0.6)		—		(0.6)
Future employee obligations		(273.9)		(10.3)		(284.2)		(104.9)		(19.6)		(124.5)
	$	(301.5)	$	331.1	$	29.6	$	(105.5)	$	(19.6)	$	(125.1)

Schedule of Funded Status Based on Accumulated Benefit Obligation

		December 31, 2018				December 31, 2017
		Canada		United States		Canada		United States
Accumulated benefit obligation (a)	$	(32.9)	$	(1,525.6)	$	(143.9)	$	(274.2)
Fair value of plan assets		13.8		1,354.1		115.2		248.7
Funded status	$	(19.1)	$	(171.5)	$	(28.7)	$	(25.5)

(a) Accumulated benefit obligation differs from accrued benefit obligation in that it does not include an assumption with respect to future compensation levels.

Summary of Amounts Recorded in Other Comprehensive Income (Loss)

		Canada			United States				Total
			Post-				Post-				Post-
	Defined		Retirement		Defined		Retirement		Defined		Retirement
Year ended December 31, 2018	Benefit		Benefits		Benefit		Benefits		Benefit		Benefits
Past service cost	$	(0.3)	$	0.4	$	(0.2)	$	—	$	(0.5)	$	0.4
Net actuarial loss		(8.7)		(0.5)		(10.7)		(5.0)		(19.4)		(5.5)
Recognized in AOCI pre-tax	$	(9.0)	$	(0.1)	$	(10.9)	$	(5.0)	$	(19.9)	$	(5.1)
Increase by the amount    included in deferred tax liabilities		2.4		—		2.2		1.4		4.6		1.4
Net amount in AOCI after-tax	$	(6.6)	$	(0.1)	$	(8.7)	$	(3.6)	$	(15.3)	$	(3.7)

		Canada			United States				Total
			Post-				Post-				Post-
	Defined		Retirement		Defined		Retirement		Defined		Retirement
Year ended December 31, 2017	Benefit		Benefits		Benefit		Benefits		Benefit		Benefits
Past service cost	$	(0.4)	$	—	$	—	$	—	$	(0.4)	$	—
Net actuarial loss		(13.9)		(1.3)		—		—		(13.9)		(1.3)
Recognized in AOCI pre-tax	$	(14.3)	$	(1.3)	$	—	$	—	$	(14.3)	$	(1.3)
Increase (decrease) by the amount    included in deferred tax liabilities		4.0		0.3		(0.1)		—		3.9		0.3
Net amount in AOCI after-tax	$	(10.3)	$	(1.0)	$	(0.1)	$	—	$	(10.4)	$	(1.0)

Summary of Amounts Recorded in A Regulatory Asset (Liability)

		Canada			United States				Total
			Post-				Post-				Post-
	Defined		Retirement		Defined		Retirement		Defined		Retirement
Year ended December 31, 2018	Benefit		Benefits		Benefit		Benefits		Benefit		Benefits
Past service cost	$	—	$	—	$	0.8	$	(110.2)	$	0.8	$	(110.2)
Net actuarial gain (loss)		—		—		188.2		(52.6)		188.2		(52.6)
Recognized in regulatory asset (liability)	$	—	$	—	$	189.0	$	(162.8)	$	189.0	$	(162.8)

		Canada			United States				Total
			Post-				Post-				Post-
	Defined		Retirement		Defined		Retirement		Defined		Retirement
Year ended December 31, 2017	Benefit		Benefits		Benefit		Benefits		Benefit		Benefits
Past service cost	$	—	$	—	$	(1.2)	$	5.6	$	(1.2)	$	5.6
Net actuarial gain (loss)		(30.6)		0.4		(74.0)		(12.8)		(104.6)		(12.4)
Recognized in regulatory asset (liability)	$	(30.6)	$	0.4	$	(75.2)	$	(7.2)	$	(105.8)	$	(6.8)

Schedule of Amounts to be Amortized from AOCI in the Next Fiscal Year

				Post-
		Defined		Retirement
Amounts to be amortized in the next fiscal year from AOCI		Benefit		Benefits
Past service costs	$	0.1	$	0.2
Actuarial losses		0.5		—
Total	$	0.6	$	0.2

Schedule of Amounts in Regulatory Assets (Liabilities) to be Recognized over Next Fiscal Year

				Post-
Amounts to be amortized in the next fiscal year from regulatory		Defined		Retirement
assets (liabilities)		Benefit		Benefits
Past service costs	$	0.2	$	(21.3)
Actuarial losses		9.1		0.1
Total	$	9.3	$	(21.2)

Schedule of Net Periodic Benefit Expense

	Year ended December 31, 2018
		Canada				United States				Total
			Post-				Post-				Post-
	Defined		retirement		Defined		retirement		Defined		retirement
	Benefit		Benefits		Benefit		Benefits		Benefit		Benefits
Current service cost (a)	$	2.4	$	0.1	$	16.2	$	5.3	$	18.6	$	5.4
Interest cost (b)		1.2		0.1		38.0		10.9		39.2		11.0
Expected return on plan assets (b)		(0.5)		—		(49.9)		(21.6)		(50.4)		(21.6)
Amortization of past service cost (b)		0.1		—		—		—		0.1		—
Amortization of net actuarial loss (b)		0.6		—		—		—		0.6		—
Amortization of regulatory asset (b)		—		—		7.8		(11.1)		7.8		(11.1)
Net benefit cost (income) recognized	$	3.8	$	0.2	$	12.1	$	(16.5)	$	15.9	$	(16.3)

(a) Recorded under the line item “Operating and administrative” expenses on the Consolidated Statements of Income.

(b) Recorded under the line item “Other Income” on the Consolidated Statements of Income.

	Year ended December 31, 2017
		Canada				United States				Total
			Post-				Post-				Post-
	Defined		retirement		Defined		retirement		Defined		retirement
	Benefit		Benefits		Benefit		Benefits		Benefit		Benefits
Current service cost (a)	$	7.9	$	0.7	$	8.0	$	1.8	$	15.9	$	2.5
Interest cost (b)		5.8		0.6		11.7		2.9		17.5		3.5
Expected return on plan assets (b)		(5.9)		(0.2)		(16.9)		(4.7)		(22.8)		(4.9)
Settlement of plan (b)		—		—		—		0.2		—		0.2
Amortization of past service cost (b)		0.2		—		—		—		0.2		—
Amortization of net actuarial loss (b)		0.7		—		—		—		0.7		—
Amortization of regulatory asset/liability (b)		1.3		0.1		6.5		(0.3)		7.8		(0.2)
Net benefit cost (income) recognized	$	10.0	$	1.2	$	9.3	$	(0.1)	$	19.3	$	1.1

(a) Recorded under the line item “Operating and administrative” expenses on the Consolidated Statements of Income.

(b) Recorded under the line item “Other Income” on the Consolidated Statements of Income.

Schedule of Collective Investment Mixes for Plan Assets

Canada		Fair value		Level 1		Level 2	Percentage of Plan Assets (%)
Cash and short-term equivalents	$	1.7	$	1.7	$	—	12.3
Canadian equities		3.7		3.7		—	26.8
Foreign equities		2.1		2.1		—	15.2
Fixed income		5.5		5.5		—	39.9
Real estate		0.8		—		0.8	5.8
	$	13.8	$	13.0	$	0.8	100.0
United States		Fair value		Level 1		Level 2	Percentage of Plan Assets (%)
Cash and short-term equivalents	$	6.3	$	6.3	$	—	0.3
Canadian equities		2.1		2.1		—	0.1
Foreign equities (a)		273.2		270.6		2.6	12.7
Fixed income		850.1		99.2		750.9	39.6
Derivatives		9.3		—		9.3	0.4
Other		10.9		—		10.9	0.5
Total investments in the fair value hierarchy	$	1,151.9		378.2		773.7	53.6
Investments measured at net asset value using the NAV practical expedient (b)
Commingled funds and pooled separate accounts (c)		945.3					44.2
Private Equity/Limited Partnership (d)		48.2					2.2
Total fair value of plan investments	$	2,145.4					100.0
Net payable (e)		(0.1)					—
	$	2,145.3					100.0

(b) Investments in foreign equities include U.S. and international securities.

(c) In accordance with ASC Topic 820, these investments are measured at fair value using net asset value (NAV) per share as a practical expedient and, therefore, have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliations of the fair value hierarchy to the statements of net assets available for plan benefits.

(d) As of December 31, 2018, investments in commingled funds and a pooled separate account consisted of approximately 89 percent common stock U.S. companies; 10 percent income producing properties located in the United States; and 1 percent short-term money market investments for WGL’s defined benefit plans and 54 percent of common stock of large-cap U.S. companies, 20 percent of U.S. Government fixed income securities and 26 percent of corporate bonds for WGL’s post-retirement benefit plans.

(e) At December 31, 2018, investments in a private equity/limited partnership consisted of common stock of international companies.

(f) At December 31, 2018, this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable.

Schedule of Significant Actuarial Assumptions Used in Measuring Net Benefit Plan Costs and Benefit Obligations

		Post-		Post-
Significant actuarial assumptions used in measuring	Defined	Retirement	Defined	Retirement
net benefit plan costs	Benefit	Benefits	Benefit	Benefits
Year ended December 31	2018		2017
Discount rate (%)	3.25 - 4.30	3.60 - 4.30	2.65 - 4.20	4.00 - 4.20
Expected long-term rate of return on plan assets (%) (a)	3.20 - 7.60	3.75 - 7.60	6.18 - 7.30	3.10 - 7.30
Rate of compensation increase (%)	2.75 - 4.10	4.10	2.75 - 4.00	3.25
Average remaining service life of active employees (years)	9.6	14.1	12.7	13.5
(a) Only applicable for funded plans
		Post-		Post-
Significant actuarial assumptions used in measuring	Defined	Retirement	Defined	Retirement
benefit obligations	Benefit	Benefits	Benefit	Benefits
As at December 31	2018		2017
Discount rate (%)	3.60 - 4.40	3.90 - 4.50	2.80 - 3.70	3.60 - 3.70
Rate of compensation increase (%)	2.75 - 4.10	4.10	2.75 - 4.00	3.25

Summary of Assumed Health Care Cost Trend Rates

		Increase		Decrease
Service and interest costs	$	1.7	$	(1.3)
Accrued benefit obligation	$	19.8	$	(16.0)

Schedule of Expected Cash Flows for Defined Benefit Pension and Other Post-Retirement Plans

				Post-
		Defined		Retirement
		Benefit		Benefits
Expected employer contributions:
2019	$	41.4	$	0.1
Expected benefit payments:
2019	$	109.8	$	25.3
2020		92.2		24.6
2021		95.3		25.0
2022		101.0		25.4
2023		99.4		25.5
2024 - 2028	$	521.9	$	130.9

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COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables)

12 Months Ended

Dec. 31, 2018

COMMITMENTS, CONTINGENCIES AND GUARANTEES [Abstract]

Summary of Future Payment Commitments

	2019		2020		2021		2022		2023		2024 and beyond		Total
Gas purchase(a)	$	3,157.1	$	2,940.5	$	2,639.3	$	2,527.4	$	2,349.9	$	30,309.2	$	43,923.4
Electricity purchase(c)		533.1		368.6		139.2		38.6		5.7		0.4		1,085.6
Service agreements(b)(d)		74.3		48.2		30.9		17.3		14.8		168.0		353.5
Pipeline and storage services(e)		861.6		862.2		818.8		795.6		781.7		4,645.3		8,765.2
Capital projects(f)		119.2		—		—		—		—		—		119.2
Operating leases(g)		23.9		30.9		29.4		28.0		25.8		164.8		302.8
Environmental(h)		6.1		4.7		3.0		0.5		0.4		0.5		15.2
Merger commitments		29.3		30.8		22.8		19.2		19.2		62.1		183.4
	$	4,804.6	$	4,285.9	$	3,683.4	$	3,426.6	$	3,197.5	$	35,350.3	$	54,748.3

(a) AltaGas enters into contracts to purchase natural gas from various suppliers for its utilities. These contracts are used to ensure that there is an adequate supply of natural gas to meet the needs of customers and to minimize exposure to market price fluctuations. Gas purchase commitments are valued based on forward prices, which may fluctuate significantly from period to period.

(b) In 2014, AltaGas' Blythe facility entered into a Long-Term Service Agreement with Siemens to complete various upgrade and maintenance services on the Combustion Turbines (CT) at the Blythe facility over 124,000 equivalent operating hour per CT, or 25 years, whichever comes first. The LTSA has fixed fees that will be incurred in the five years following December 31, 2014 and variable fees on a per equivalent operating hour basis. As at December 31, 2018, the total commitment was $190.9 million payable over the next 16 years, of which $59.6 million is expected to be paid over the next five years. 

(c) AltaGas enters into contracts to purchase electricity from various suppliers for its utilities.Electricity purchase commitments are based on existing fixed price and fixed volume contracts, and include $44.1 million of commitments related to renewable energy credits.

(d) In 2017, AltaGas entered into a 12-year service agreement for tug services to support the marine operations of RIPET. AltaGas is obligated to pay fixed and variable fees of approximately $60.1 million over the term of the contract.

(e) Pipeline and storage commitments include minimum payments for natural gas transportation, storage and peaking contracts that have expiration dates through 2044.

(f) Commitments for capital projects. Estimated amounts are subject to variability depending on the actual construction costs.

(g) Operating leases include lease arrangements for office spaces, vehicles, rail cars, land, office and other equipment.

(h) Environmental commitments relate to future costs associated with sites where AltaGas or its predecessors may have operated manufactured gas plants.

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RELATED PARTY TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2018

RELATED PARTY TRANSACTIONS [Abstract]

Summary of Related Party Amounts Included in Balance Sheets

As at	December 31, 2018		December 31, 2017
Due from related parties
Accounts receivable (a)	$	60.8	$	0.8
Long-term investments and other assets (b)		45.0		75.0
	$	105.8	$	75.8
Due to related parties
Accounts payable (c)		6.3		3.2
Risk management liabilities - current (d)		0.9		—
	$	7.2	$	3.2

(a) Receivables from joint ventures and ACI.

(b) AltaGas has provided a $100.0 million interest bearing secured loan facility to Petrogas of which $50.0 million is committed. The facility is available for Petrogas to draw upon from time to time for general corporate purposes. The facility is subject to annual renewal and has a maturity date of June 27, 2021. As at December 31, 2018, Petrogas had drawn $45.0 million (December 31, 2017 - $75.0 million) under the facility.

(c) Payables to ACI and a joint venture.

(d) Foreign exchange hedge with ACI.

Schedule of Related Party Transactions

Year ended December 31		2018		2017
Revenue (a)	$	68.4	$	15.0
Cost of sales (b)	$	(4.2)	$	(6.5)
Operating and administrative expenses (c)	$	1.3	$	—
Other income (d)	$	9.2	$	4.4

(a) In the ordinary course of business, AltaGas sold natural gas and natural gas liquids to a joint venture and ACI.  In addition, subsequent to the IPO of ACI, AltaGas is providing certain day-to-day services to ACI under a Transition Services Agreement on a cost recovery basis. The Transition Services Agreement will operate until June 30, 2020, subject to earlier termination in certain circumstances, and is extendable by mutual agreement of the parties. Revenue also includes an unrealized loss on a foreign exchange hedge with ACI of $0.2 million in 2018 (2017 - $nil).  

(b) In the ordinary course of business, AltaGas obtained natural gas storage services from a joint venture as well as incurred costs related to the sale of natural gas liquids to affiliates.

(c) Administrative costs recovered from joint ventures. In 2017, amount was offset by the expense associated with the forgiveness of a loan to an executive.

(d) Interest income fromloans to Petrogas (secured loan facility) and loans to ACI. Subsequent to the IPO of ACI, AltaGas provided certain loans to ACI for a portion of the year. Loans to ACI were fully repaid by December 31, 2018.

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SUPPLEMENTAL CASH FLOW INFORMATION (Tables)

12 Months Ended

Dec. 31, 2018

SUPPLEMENTAL CASH FLOW INFORMATION [Abstract]

Schedule of Changes in Operating Assets and Liabilities

	Year ended December 31
	2018		2017
Source (use) of cash:
Accounts receivable	$	(526.9)	$	(55.6)
Inventory		(100.8)		4.7
Other current assets		12.5		7.0
Regulatory assets (current)		(15.8)		(0.2)
Accounts payable and accrued liabilities		237.9		85.4
Customer deposits		(13.3)		(2.8)
Regulatory liabilities (current)		69.2		(4.8)
Other current liabilities		(5.9)		13.0
Other operating assets and liabilities		(143.4)		(44.8)
Changes in operating assets and liabilities	$	(486.5)	$	1.9

Schedule of Supplemental Cash Payments

	Year ended December 31
	2018		2017
Interest paid (net of capitalized interest)	$	288.9	$	151.1
Income taxes paid	$	36.9	$	36.3

Reconciliation of Cash and Restricted Cash Balances

As at December 31		2018		2017
Cash and cash equivalents	$	101.6	$	27.3
Restricted cash holdings from customers - current		4.1		8.9
Restricted cash holdings from customers - non-current		6.1		7.5
Restricted cash included in prepaid expenses and other current assets(a)		27.6		—
Restricted cash included in long-term investments and other assets(a)		61.7		—
Cash, cash equivalents and restricted cash per consolidated statement of cash flow	$	201.1	$	43.7

The restricted cash balances included in prepaid expenses and other current assets and long-term investments and other assets relates to Rabbi trusts associated with WGL’s pension plans (Note 28). On the date of the WGL Acquisition, the restricted cash balances related to Rabbi trusts was $81.0 million.

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SEGMENTED INFORMATION (Tables)

12 Months Ended

Dec. 31, 2018

SEGMENTED INFORMATION [Abstract]

Reconciliation Of Segment Revenue

	Year ended December 31, 2018
	Utilities		Midstream		Power		Corporate		Total
External revenue (note 23)	$	1,752.6	$	1,344.6	$	1,162.0	$	(2.5)	$	4,256.7
Intersegment revenue		13.0		90.4		9.0		0.1		112.5
Segment revenue	$	1,765.6	$	1,435.0	$	1,171.0	$	(2.4)	$	4,369.2

Schedule of Geographic Information

Year ended December 31		2018		2017
Revenue(a)
Canada	$	1,626.8	$	1,508.8
United States		2,553.0		1,109.9
Total	$	4,179.8	$	2,618.7

(a) Operating revenue from external customers, excluding unrealized gains (losses) on risk management contracts.

As at December 31		2018		2017
Property, plant and equipment
Canada	$	2,348.2	$	4,320.5
United States		8,581.4		2,369.3
Total	$	10,929.6	$	6,689.8

Schedule of Segment Composition

	Year ended December 31, 2018
	Utilities		Midstream		Power		Corporate		Intersegment Elimination(a)		Total
Segment revenue	$	1,765.6	$	1,435.0	$	1,171.0	$	(2.4)	$	(112.5)	$	4,256.7
Cost of sales		(838.3)		(976.4)		(743.7)		—		103.1		(2,455.3)
Operating and administrative		(727.4)		(201.7)		(159.1)		(50.6)		9.8		(1,129.0)
Accretion expenses		(0.1)		(4.0)		(6.8)		—		—		(10.9)
Depreciation and amortization		(165.8)		(84.4)		(130.5)		(13.3)		—		(394.0)
Provisions on assets (note 10)		(193.7)		(153.7)		(381.3)		—		—		(728.7)
Income from equity investments		7.2		51.1		(10.4)		—		—		47.9
Other income (loss)		4.5		0.7		(5.9)		2.0		(0.4)		0.9
Foreign exchange gains		—		(0.2)		(0.1)		4.8		—		4.5
Interest expense		(103.9)		(10.6)		(8.9)		(185.6)		—		(309.0)
Loss before income taxes	$	(251.9)	$	55.8	$	(275.7)	$	(245.1)	$	—	$	(716.9)
Net additions (reductions) to:
Property, plant and equipment(b)	$	507.0	$	383.4	$	(321.9)	$	4.0	$	—	$	572.5
Intangible assets	$	21.8	$	4.7	$	12.5	$	6.7	$	—	$	45.7

(a) Intersegment transactions are recorded at market value.

(b) Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statement of Cash flow due to classification of business acquisition and foreign exchange changes on U.S. assets.

	Year ended December 31, 2017
	Utilities		Midstream		Power		Corporate		Intersegment Elimination(a)		Total
Segment revenue	$	1,126.7	$	1,008.0	$	631.7	$	(58.4)	$	(151.8)	$	2,556.2
Cost of sales		(610.1)		(647.0)		(242.8)		—		142.8		(1,357.1)
Operating and administrative		(226.1)		(165.0)		(93.1)		(97.5)		9.5		(572.2)
Accretion expenses		(0.1)		(3.9)		(6.9)		—		—		(10.9)
Depreciation and amortization		(81.8)		(68.6)		(118.0)		(14.0)		—		(282.4)
Provision on assets		—		(6.6)		(133.0)		—		—		(139.6)
Income from equity investments		2.6		22.0		6.8		—		—		31.4
Other income (loss)		3.9		(0.9)		0.8		6.3		(0.5)		9.6
Foreign exchange gains		—		0.2		—		1.5		—		1.7
Interest expense		—		—		—		(170.3)		—		(170.3)
Income (loss) before income taxes	$	215.1	$	138.2	$	45.5	$	(332.4)	$	—	$	66.4
Net additions (reductions) to:
Property, plant and equipment(b)	$	124.3	$	245.3	$	16.5	$	1.5	$	—	$	387.6
Intangible assets	$	2.1	$	2.8	$	13.2	$	2.2	$	—	$	20.3

(a) Intersegment transactions are recorded at market value.

(b) Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statement of Cash flow due to classification of business acquisition and foreign exchange changes on U.S. assets.

Schedule of Goodwill and Total Assets by Segment

	Utilities		Midstream		Power		Corporate		Total
As at December 31, 2018
Goodwill	$	3,450.8	$	426.4	$	191.0	$	—	$	4,068.2
Segmented assets	$	12,991.3	$	6,398.8	$	3,814.7	$	282.9	$	23,487.7
As at December 31, 2017
Goodwill	$	664.7	$	152.6	$	—	$	—	$	817.3
Segmented assets	$	3,460.2	$	3,096.8	$	3,192.5	$	282.7	$	10,032.2

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ORGANIZATION AND OVERVIEW OF THE BUSINESS (Narrative) (Details) customer in Millions, $ in Billions	1 Months Ended	12 Months Ended
	Jan. 31, 2019	Dec. 31, 2018 CAD ($) MMcf / d state segment customer item MW	Dec. 13, 2018
Organization And Overview Of Business [Line Items]
Number of segments | segment		3
Northwest Hydro Facilities [Member]
Organization And Overview Of Business [Line Items]
Equity method investment, ownership interest			55.00%
Petrogas [Member]
Organization And Overview Of Business [Line Items]
Equity method investment, ownership interest		33.333%
Utilities [Member]
Organization And Overview Of Business [Line Items]
Number of customers | customer		1.6
Utilities customers, base rate | $		$ 3.7
Number of utilities jurisdictions | item		5
Midstream [Member]
Organization And Overview Of Business [Line Items]
Production capacity | MMcf / d		1,500
Midstream [Member] | AIJVLP [Member]
Organization And Overview Of Business [Line Items]
Equity method investment, ownership interest		50.00%
Midstream [Member] | Petrogas [Member]
Organization And Overview Of Business [Line Items]
Equity method investment, ownership interest		33.33%
Power [Member]
Organization And Overview Of Business [Line Items]
Power capacity | MW		1,105
Power [Member] | Northwest Hydro Facilities [Member] | Subsequent Event [Member]
Organization And Overview Of Business [Line Items]
Interest sold	55.00%
United States [Member] | Power [Member]
Organization And Overview Of Business [Line Items]
Number of states/provinces | state		20

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative) (Details) $ in Millions		12 Months Ended
	Jan. 01, 2018 CAD ($)	Dec. 31, 2018 $ / shares	Dec. 31, 2018 CAD ($) item
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Assets held for sale, expected sale period			12 months
Other portions of RU's and PSU's, value per share | $ / shares		$ 1
Accounting Standards Update 2016-01 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Cumulative-effect adjustment to retained earnings | $	$ 7.0
Accounting Standards Update 2017-07 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | $			$ 1.6
Pension Benefits [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected average remaining service period			9 years 7 months 6 days
Postretirement Health Coverage [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected average remaining service period			14 years 1 month 6 days
Normal Purchase Normal Sale (NPNS) Contracts [Member] | WGL Holdings [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Finite-Lived Intangible Asset, Useful Life			20 years
Minimum [Member] | Performance Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Performance multiplier | item			0
Maximum [Member] | Performance Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Performance multiplier | item			2

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Summary of Estimated Useful Lives of Property, Plant and Equipment) (Details)	12 Months Ended
	Dec. 31, 2018
Minimum [Member] | Utilities [Member]
Property Plant And Equipment [Line Items]
Useful life	3 years
Minimum [Member] | Midstream [Member]
Property Plant And Equipment [Line Items]
Useful life	3 years
Minimum [Member] | Power [Member]
Property Plant And Equipment [Line Items]
Useful life	2 years
Minimum [Member] | Corporate [Member]
Property Plant And Equipment [Line Items]
Useful life	1 year
Maximum [Member] | Utilities [Member]
Property Plant And Equipment [Line Items]
Useful life	80 years
Maximum [Member] | Midstream [Member]
Property Plant And Equipment [Line Items]
Useful life	45 years
Maximum [Member] | Power [Member]
Property Plant And Equipment [Line Items]
Useful life	120 years
Maximum [Member] | Corporate [Member]
Property Plant And Equipment [Line Items]
Useful life	20 years

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Summary of Estimated Useful Lives of Finite-Lived Intangible Assets) (Details)	12 Months Ended
	Dec. 31, 2018
Extraction And Transmission (E&T) Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible asset, useful life	25 years
Commodity Contract [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible asset, useful life	5 years
Minimum [Member] | Energy Services Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible asset, useful life	5 years
Minimum [Member] | Electricity Service Agreements [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible asset, useful life	2 years
Minimum [Member] | Software [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible asset, useful life	3 years
Minimum [Member] | Land Rights [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible asset, useful life	5 years
Minimum [Member] | Franchise And Consents [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible asset, useful life	9 years
Maximum [Member] | Energy Services Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible asset, useful life	19 years
Maximum [Member] | Electricity Service Agreements [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible asset, useful life	60 years
Maximum [Member] | Software [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible asset, useful life	10 years
Maximum [Member] | Land Rights [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible asset, useful life	64 years
Maximum [Member] | Franchise And Consents [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible asset, useful life	25 years

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ACQUISITION OF WGL HOLDINGS INC. (Narrative) (Details) $ / shares in Units, shares in Millions, $ in Millions, $ in Millions			6 Months Ended	12 Months Ended
	Jul. 06, 2018 USD ($) $ / shares shares	Jul. 06, 2018 CAD ($) shares	Dec. 31, 2018 CAD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2017 CAD ($)	Jul. 06, 2018 CAD ($) $ / $	Dec. 31, 2016 CAD ($)
Business Acquisition [Line Items]
Goodwill			$ 4,068.2	$ 4,068.2	$ 817.3		$ 856.0
Revenue				4,256.7	2,556.2
Net income (loss)				$ (435.1)	91.6
Meade Pipeline Co LLC [Member]
Business Acquisition [Line Items]
Equity method investment, ownership interest			55.00%	55.00%
WGL Holdings [Member] | Meade Pipeline Co LLC [Member]
Business Acquisition [Line Items]
Parent ownership interest			55.00%	55.00%
WGL Holdings [Member] | Mountain Valley Pipeline LLC [Member]
Business Acquisition [Line Items]
Noncontrolling ownership interest			10.00%	10.00%
WGL Holdings [Member] | Stonewall Gas Gathering Systems LLC [Member]
Business Acquisition [Line Items]
Equity method investment, ownership interest			30.00%	30.00%
WGL Holdings [Member] | Central Penn [Member]
Business Acquisition [Line Items]
Equity method investment, ownership interest			21.00%	21.00%
WGL Holdings [Member] | Non-recurring Adjustments [Member]
Business Acquisition [Line Items]
Net income (loss)				$ 132.0	19.0
Meade Pipeline Co LLC [Member] | Central Penn [Member]
Business Acquisition [Line Items]
Equity method investment, ownership interest			39.00%	39.00%
Public And Private Placement [Member]
Business Acquisition [Line Items]
Proceeds from issuance of subscription receipts		$ 2.3
WGL Holdings [Member]
Business Acquisition [Line Items]
Aggregate purchase price	$ 7,100	9,300.0
Acquisition, assumption of debt	2,500	3,300.0
Acquisition, equity issued	$ 31	41.0
Acquisition, share price | $ / shares	$ 88.25
Cash consideration	$ 4,600	$ 6,000.0
Shares issued on conversion of subscription receipts | shares	84.5	84.5
Exchange rate | $ / $						1.31
Fair value adjustment of property, plant and equipment				$ (92.0)
Goodwill						$ 3,196.0
Intangible assets						$ 637.0
Fair value adjustment of equity interests				464.0
Fair value adjustment of long-term debt				87.0
Acquisition costs				237.2	65.7
Revenues of acquiree			$ 1,406.0
Income (loss) of acquiree			$ 113.0
WGL Holdings [Member] | Foreign Exchange Contracts, Gains (Losses) [Member]
Business Acquisition [Line Items]
Revenue				$ 2.0	$ 34.0
WGL Holdings [Member] | Acquisition Credit Facility [Member]
Business Acquisition [Line Items]
Proceeds from credit lines	$ 2,300	$ 3,000.0

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ACQUISITION OF WGL HOLDINGS INC. (Schedule of Final Purchase Price Allocation) (Details) - CAD ($) $ in Millions	Jul. 06, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Goodwill		$ 4,068.2	$ 817.3	$ 856.0
WGL Holdings [Member]
Business Acquisition [Line Items]
Purchase consideration	$ 5,973.0
Current assets	1,187.0
Property, plant and equipment	5,943.0
Intangible assets	637.0
Regulatory assets	402.0
Long-term investments	1,411.0
Other long-term assets	449.0
Current liabilities	(1,798.0)
Long-term debt	(2,548.0)
Preferred shares	(41.0)
Regulatory liabilities	(1,125.0)
Deferred income taxes	(772.0)
Other long-term liabilities	(959.0)
Non-controlling interest	(9.0)
Fair value of net assets acquired	2,777.0
Goodwill	$ 3,196.0

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ACQUISITION OF WGL HOLDINGS INC. (Summary of Pro Forma Information) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
ACQUISITION OF WGL HOLDINGS INC. [Abstract]
Pro forma revenue	$ 5,962	$ 5,704
Pro forma net income (loss) after taxes	$ (304)	$ 450

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SALE OF MINORITY INTEREST AND OTHER DISPOSITIONS (Narrative) (Details) $ / shares in Units, $ in Millions, $ in Millions						1 Months Ended		3 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 11, 2018 CAD ($)	Nov. 13, 2018 USD ($) MW	Oct. 25, 2018 CAD ($) $ / shares	Jun. 22, 2018 CAD ($)	Mar. 31, 2018 CAD ($)	Mar. 31, 2017 CAD ($)	Jun. 30, 2018 CAD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2017 CAD ($)	Dec. 13, 2018
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from non-controlling interest recorded as contributed surplus										$ 3.0
Gains (losses) from sale of assets									$ (10.6)	(2.7)
AltaGas Canada [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Pretax provision									193.7
Proceeds from sale of shares				$ 892.2
Gains (losses) from sale of assets									$ (0.5)
AltaGas Canada [Member] | Northwest Hydro Facilities [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Noncontrolling ownership interest	10.00%								10.00%
AltaGas Canada [Member] | IPO [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Sale price of shares | $ / shares				$ 14.50
Ownership interest after transaction	37.00%
Northwest Hydro Facilities [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Equity method investment, ownership interest											55.00%
Proceeds from asset dispositions					$ 921.6
Noncontrolling interest increase								$ 420.4
Proceeds from non-controlling interest recorded as deferred tax labilities								153.3
Proceeds from non-controlling interest recorded as contributed surplus								$ 335.2
Northwest Hydro Facilities [Member] | Sale of Minority Interest and Other Dispositions [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Equity method investment, ownership interest					35.00%
San Joaquin Facilities [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from asset dispositions			$ 299.4
Pretax provision									$ 340.6
Gains (losses) from sale of assets									(14.4)
Power capacity | MW			523
Busch Ranch [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from asset dispositions		$ 16.3
Gains (losses) from sale of assets									(3.2)
Certent Non-Core Gas Facilities [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from asset dispositions						$ 7.0
Gains (losses) from sale of assets									$ 1.3
EDS And JFP Transmission Assets [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from asset dispositions							$ 67.0
Gains (losses) from sale of assets										$ (3.4)

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ASSETS HELD FOR SALE (Narrative) (Details) - CAD ($) shares in Millions, $ in Millions		1 Months Ended	3 Months Ended		12 Months Ended
	Dec. 13, 2018	Sep. 30, 2018	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Number of shares of investment sold					43.7
Non-Core Midstream and Power Assets in Canada [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Aggregate purchase price				$ 165.0
Assets held for sale		$ 102.1		102.1
Liabilities held for sale		$ 10.8		10.8
Number of shares of investment sold		43.7
Northwest Hydro Facilities [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Assets held for sale	$ 1,350.2
Liabilities held for sale	$ 160.6
Equity Method Investment, Ownership Percentage	55.00%
Proceeds from Sale of Property Held-for-sale	$ 1,370.0
Annual Payments Related To Assets Held For Sale	$ 11.0
Electricity purchase agreement term					60 years
Architect of the Capitol (AOC) Project [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Pretax provision			$ 6.0
Assets held for sale			76.6		$ 76.6
Property, Plant and Equipment [Member] | Non-Core Midstream and Power Assets in Canada [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Pretax provision				121.4
Intangible Assets [Member] | Non-Core Midstream and Power Assets in Canada [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Pretax provision				0.5
Goodwill [Member] | Non-Core Midstream and Power Assets in Canada [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Pretax provision				$ 5.1
Held-For-Sale [Member]
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Assets held for sale			1,528.9		1,528.9	$ 6.0
Liabilities held for sale			$ 171.4		$ 171.4	$ 0.3

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ASSETS HELD FOR SALE (Schedule of Assets Held for Sale) (Details) - Held-For-Sale [Member] - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Cash	$ 4.9
Accounts receivable	85.2	$ 0.3
Inventory	0.5
Property, plant and equipment	1,189.6	5.3
Intangible assets	248.7	0.1
Goodwill		0.3
Total assets held for sale	1,528.9	6.0
Accounts payable and accrued liabilities	23.8
Asset retirement obligations	10.8	0.3
Other long-term liabilities	136.8
Total liabilities associated with assets held for sale	$ 171.4	$ 0.3

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INVENTORY (Schedule of Inventory) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
INVENTORY [Abstract]
Natural gas held in storage	$ 418.0	$ 133.9
Materials and supplies	53.3	32.3
Renewable energy credits and emission compliance instruments	38.2	28.4
Other inventory	6.4	6.5
Total inventory	$ 515.9	$ 201.1

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PROPERTY, PLANT AND EQUIPMENT (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
PROPERTY, PLANT AND EQUIPMENT [Abstract]
Interest capitalized	$ 12.6	$ 10.8
Capital projects under construction	872.7	269.5
Depreciation expense	$ 324.3	$ 239.7

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PROPERTY, PLANT AND EQUIPMENT (Schedule of Property, Plant and Equipment) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Property Plant And Equipment [Line Items]
Property, plant and equipment, Reclassified to assets held for sale (note 5), Cost	$ (2,999.3)	$ (16.7)
Property, plant and equipment, Cost	11,952.7	7,970.8
Property, plant and equipment, Reclassified to assets held for sale (note 5), Accumulated amortization	1,809.7	11.4
Property, plant and equipment, Accumulated amortization	(1,023.1)	(1,281.0)
Property, plant and equipment, Reclassified to assets held for sale (note 5), Net book value	(1,189.6)	(5.3)
Property, plant and equipment, Net book value	10,929.6	6,689.8
Utilities [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment before reclassifications, Cost	7,090.5	2,245.4
Property, plant and equipment before reclassifications, Accumulated amortization	(89.7)	(226.1)
Property, plant and equipment before reclassifications, Net book value	7,000.8	2,019.3
Midstream [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment before reclassifications, Cost	3,178.2	2,801.4
Property, plant and equipment before reclassifications, Accumulated amortization	(845.7)	(636.3)
Property, plant and equipment before reclassifications, Net book value	2,332.5	2,165.1
Power [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment before reclassifications, Cost	4,633.9	2,874.8
Property, plant and equipment before reclassifications, Accumulated amortization	(1,858.3)	(392.3)
Property, plant and equipment before reclassifications, Net book value	2,775.6	2,482.5
Corporate [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment before reclassifications, Cost	49.4	65.9
Property, plant and equipment before reclassifications, Accumulated amortization	(39.1)	(37.7)
Property, plant and equipment before reclassifications, Net book value	$ 10.3	$ 28.2

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INTANGIBLE ASSETS (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
PROVISIONS ON ASSETS, INTANGIBLE ASSETS AND GOODWILL [Abstract]
Amortization expense	$ 69.7	$ 42.7
Assets excluded from asset base subject to amortization	$ 196.4	$ 11.2

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INTANGIBLE ASSETS (Summary of Intangible Assets) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Reclassified to assets held for sale (note 5), Cost	$ (277.4)	$ (0.1)
Intangible assets, Cost	841.4	785.0
Intangible assets, reclassified to assets held for sale (note 5), Accumulated amortization	28.7
Intangible assets, Accumulated amortization	(129.5)	(196.2)
Intangible assets, Reclassified to assets held for sale (note 5), Net book value	(248.7)	(0.1)
Intangible assets, Net book value	711.9	588.8
Extraction And Transmission (E&T) Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible assets before reclassifications, Cost	26.6	26.6
Intangible assets before reclassifications, Accumulated amortization	(14.3)	(13.4)
Intangible assets before reclassifications, Net book value	12.3	13.2
Electricity Service Agreements [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible assets before reclassifications, Cost	269.5	603.1
Intangible assets before reclassifications, Accumulated amortization	(25.9)	(108.5)
Intangible assets before reclassifications, Net book value	243.6	494.6
Energy Services Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible assets before reclassifications, Cost	176.1	10.2
Intangible assets before reclassifications, Accumulated amortization	(33.8)	(8.1)
Intangible assets before reclassifications, Net book value	142.3	2.1
Software [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible assets before reclassifications, Cost	293.9	126.8
Intangible assets before reclassifications, Accumulated amortization	(77.7)	(61.6)
Intangible assets before reclassifications, Net book value	216.2	65.2
Land Rights [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible assets before reclassifications, Cost	1.4	11.0
Intangible assets before reclassifications, Accumulated amortization	(0.2)	(2.4)
Intangible assets before reclassifications, Net book value	1.2	8.6
Commodity Contract [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible assets before reclassifications, Cost	346.3
Intangible assets before reclassifications, Accumulated amortization	(6.3)
Intangible assets before reclassifications, Net book value	340.0
Franchise And Consents [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible assets before reclassifications, Cost	5.0	7.4
Intangible assets before reclassifications, Accumulated amortization		(2.2)
Intangible assets before reclassifications, Net book value	$ 5.0	$ 5.2

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INTANGIBLE ASSETS (Summary of Estimated Amortization Expense of Intangible Assets) (Details) $ in Millions	Dec. 31, 2018 CAD ($)
PROVISIONS ON ASSETS, INTANGIBLE ASSETS AND GOODWILL [Abstract]
2019	$ 84.2
2020	82.5
2021	57.6
2022	132.3
2023	38.3
Thereafter	$ 120.6

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GOODWILL (Schedule of Goodwill) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
PROVISIONS ON ASSETS, INTANGIBLE ASSETS AND GOODWILL [Abstract]
Balance, beginning of year	$ 817.3	$ 856.0
Provisions on assets (notes 5 and 10)	(124.2)
Business acquisition (note 3)	3,196.4
Foreign exchange translation	178.7	(38.4)
Reclassified to assets held for sale		(0.3)
Balance, end of year	$ 4,068.2	$ 817.3

XML

PROVISIONS ON ASSETS (Narrative) (Details) - CAD ($) $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Nov. 30, 2018	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017
Provisions On Assets Disclosure [Line Items]
Provisions on assets			$ 728.7	$ 139.6
Power [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets			381.3	133.0
Midstream [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets			153.7	6.6
Utilities [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets		$ 193.7	193.7
Held-For-Sale [Member] | Power [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets			9.8
Held-For-Sale [Member] | Midstream [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets			117.2	6.6
Sale of Minority Interest and Other Dispositions [Member] | Power [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets	$ 340.6
Shut-In Assets [Member] | Midstream [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets			36.5
Intangible Assets [Member] | Power [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets			119.3
Intangible Assets [Member] | Midstream [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets			0.5
Property, Plant and Equipment [Member] | Power [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets			221.3
Property, Plant and Equipment [Member] | Midstream [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets			148.1
Property, Plant and Equipment [Member] | Utilities [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets		74.6
Goodwill [Member] | Midstream [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets			5.1
Goodwill [Member] | Utilities [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets		$ 119.1
Development Projects [Member] | Power [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets			23.1
Natural Gas-Fired Co-Generation Facility [Member] | Power [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets			1.8
Financing Receivable [Member] | Power [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets			$ 6.0
California And Alberta [Member] | Power [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets				133.0
California And Alberta [Member] | Intangible Assets [Member] | Power [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets				48.5
California And Alberta [Member] | Property, Plant and Equipment [Member] | Power [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets				$ 84.5

XML

PROVISIONS ON ASSETS (Schedule of Provisions on Assets) (Details) - CAD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017
Provisions On Assets Disclosure [Line Items]
Provisions on assets		$ 728.7	$ 139.6
Power [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets		381.3	133.0
Midstream [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets		153.7	$ 6.6
Utilities [Member]
Provisions On Assets Disclosure [Line Items]
Provisions on assets	$ 193.7	$ 193.7

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LONG-TERM INVESTMENTS AND OTHER ASSETS (Narrative) (Details) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018 CAD ($) shares
Number of shares of investment sold | shares	43.7
Proceeds from sale of investment	$ 76.5
Loss on Sale of Investments	2.0
Tidewater Midstream and Infrastructure Inc. [Member]
Proceeds from sale of investment	$ 63.4

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LONG-TERM INVESTMENTS AND OTHER ASSETS (Schedule of Long-Term and Other Investments) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
LONG-TERM INVESTMENTS AND OTHER ASSETS [Abstract]
Investments in publicly traded entities	$ 8.4	$ 95.0
Loan to affiliate (note 30)	45.0	75.0
Deferred lease receivable	24.4	29.0
Debt issuance costs associated with credit facilities	7.9	20.3
Refundable deposits	16.2	14.9
Prepayment on long-term service agreements	82.5	68.1
Prepaid post-retirement benefits (note 28)	341.4
Subscription receipts issuance costs		1.7
Contract asset (note 23)	11.5
Rabbi trust (note 28)	61.7
Other	25.5	8.6
Long-term investments and other assets	$ 283.1	$ 312.6

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VARIABLE INTEREST ENTITIES (Narrative) (Details) $ in Millions		1 Months Ended	12 Months Ended
	Jun. 22, 2018	Jan. 31, 2019 CAD ($)	Dec. 31, 2018 USD ($) mi	Dec. 31, 2018 CAD ($) mi	Dec. 31, 2017 CAD ($)
Variable Interest Entity [Line Items]
Proceeds from noncontrolling interests, excluding contributed surplus					$ 20,000,000
Proceeds from sale of non-controlling interests				$ 908,600,000	24,100,000
Proceeds from non-controlling interest recorded as contributed surplus					3,000,000
Equity method investment				2,392,400,000	567,000,000
Rile LP [Member] | Minimum [Member]
Variable Interest Entity [Line Items]
Estimated project costs					450,000,000
Rile LP [Member] | Maximum [Member]
Variable Interest Entity [Line Items]
Estimated project costs					$ 500,000,000
Northwest Hydro Facilities [Member]
Variable Interest Entity [Line Items]
VIE interest sold	35.00%
Proceeds from noncontrolling interests, excluding contributed surplus				420,400,000
Proceeds from sale of non-controlling interests				921,600,000
Proceeds from non-controlling interest recorded as contributed surplus				334,600,000
Northwest Hydro Facilities [Member] | Subsequent Event [Member]
Variable Interest Entity [Line Items]
Proceeds from sale of non-controlling interests		$ 1,370,000,000
Indirect interest percentage		55.00%
Meade Pipeline Co LLC [Member]
Variable Interest Entity [Line Items]
Equity method investment				$ 666,900,000
Equity Method Investment, Ownership Percentage				55.00%
Share of construction costs			$ 446
Central Penn [Member]
Variable Interest Entity [Line Items]
Indirect interest percentage			21.00%	21.00%
Natural Gas Transported, Per Day				1.7
Expected Pipeline Length | mi			185	185
AltaGas LPG [Member] | Rile LP [Member]
Variable Interest Entity [Line Items]
VIE ownership percentage					70.00%
AltaGas LPG [Member] | Vopak [Member]
Variable Interest Entity [Line Items]
VIE ownership percentage					30.00%

XML

VARIABLE INTEREST ENTITIES (Schedule of VIE Amounts in Consolidated Balance Sheets) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Variable Interest Entity [Line Items]
Current assets	$ 4,033.0	$ 701.9
Property, plant and equipment	10,929.6	6,689.8
Long-term investments and other assets	283.1	312.6
Current liabilities	(4,102.0)	(815.2)
Asset retirement obligations	(500.6)	(88.3)
Deferred tax credits	(957.9)	(441.4)
Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Current assets	1,383.5	1.4
Property, plant and equipment	619.2	84.3
Long-term investments and other assets	48.0	48.0
Current liabilities	(161.8)
Asset retirement obligations	(0.9)
Deferred tax credits	(3.0)
Net assets	$ 1,885.0	$ 133.7

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INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD (Narrative) (Details) $ / shares in Units, $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) mi	Dec. 31, 2018 CAD ($) item mi $ / shares	Dec. 31, 2017 CAD ($)	Dec. 31, 2016 CAD ($) shares	Apr. 30, 2018
Schedule of Equity Method Investments [Line Items]
Investment in affiliate		$ 235.4	$ 16.8
Equity income (loss)		47.9	31.4
Equity Method Investments		2,392.4	567.0
Provision on equity method investments		$ 14.5	0.0
Petrogas [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership interest		33.333%
Equity income (loss)		$ 12.8	12.8
Petrogas [Member] | Redeemable Convertible Preferred Stock [Member]
Schedule of Equity Method Investments [Line Items]
Number of shares owned | shares				6,000,000
Dividend rate	8.50%	8.50%
EQM [Member] | WGL Holdings [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership interest					5.00%
ACI [Member]
Schedule of Equity Method Investments [Line Items]
Share Price | $ / shares		$ 14.50
Interest in hydro facility percent		10.00%
Canada [Member] | Petrogas [Member]
Schedule of Equity Method Investments [Line Items]
Investment in affiliate				$ 150.0
Equity income (loss)		$ 12.8	12.8
Equity Method Investments		150.0	150.0
Canada [Member] | Tidewater [Member]
Schedule of Equity Method Investments [Line Items]
Equity income (loss)			1.7
Equity Method Investments
Canada [Member] | AIJVLP [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership interest		50.00%
Equity income (loss)		$ 2.1	6.6
Equity Method Investments		$ 342.9	$ 323.3
Canada [Member] | Inuvik Gas Ltd [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership interest		33.333%
Equity income (loss)		$ (0.2)
Equity Method Investments
Canada [Member] | ACI [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership interest		36.75%
Equity income (loss)		$ 5.4
Equity Method Investments		$ 112.5
United States [Member] | Mountain Valley Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership interest		10.00%
Investment in affiliate	$ 350
Equity income (loss)		$ 11.5
Natural Gas Transported, Per Day | item		2.0
Expected Pipeline Length | mi	300	300
Equity Method Investments		$ 532.5
United States [Member] | Stonewall Gas Gathering Systems LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership interest		30.00%
Equity income (loss)		$ 11.8
Natural Gas Transported, Per Day | item		1.4
Equity Method Investments		$ 411.8
United States [Member] | Constitution [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership interest		10.00%
Equity income (loss)		$ (0.2)
Equity Method Investments

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INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD (Schedule of Equity Method Investments) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Equity method investment	$ 2,392.4	$ 567.0
Equity income (loss)	$ 47.9	31.4
Petrogas [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership interest	33.333%
Equity income (loss)	$ 12.8	12.8
Canada [Member] | ACI [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership interest	36.75%
Equity method investment	$ 112.5
Equity income (loss)	$ 5.4
Canada [Member] | AIJVLP [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership interest	50.00%
Equity method investment	$ 342.9	323.3
Equity income (loss)	$ 2.1	6.6
Canada [Member] | Inuvik Gas Ltd [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership interest	33.333%
Equity method investment
Equity income (loss)	$ (0.2)
Canada [Member] | Sarnia Airport Storage Pool LP [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership interest	50.00%
Equity method investment	$ 18.7	18.8
Equity income (loss)	1.0	1.0
Canada [Member] | Petrogas [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment	150.0	150.0
Equity income (loss)	12.8	12.8
Canada [Member] | Tidewater [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment
Equity income (loss)		1.7
United States [Member] | Constitution [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership interest	10.00%
Equity method investment
Equity income (loss)	$ (0.2)
United States [Member] | Craven County Wood Energy LP [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership interest	50.00%
Equity method investment	$ 7.8	20.9
Equity income (loss)	$ (14.1)	3.3
United States [Member] | Eaton Rapids Gas Storage System [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership interest	50.00%
Equity method investment	$ 29.4	26.4
Equity income (loss)	$ 2.0	2.5
United States [Member] | Grayling Generating Station LP [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership interest	50.00%
Equity method investment	$ 29.0	27.6
Equity income (loss)	$ 3.6	$ 3.5
United States [Member] | Meade Pipeline Co LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership interest	55.00%
Equity method investment	$ 757.8
Equity income (loss)	$ 12.2
United States [Member] | Mountain Valley Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership interest	10.00%
Equity method investment	$ 532.5
Equity income (loss)	$ 11.5
United States [Member] | Stonewall Gas Gathering Systems LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership interest	30.00%
Equity method investment	$ 411.8
Equity income (loss)	$ 11.8

XML

INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD (Schedule of Combined Financial Information of Equity Method Investments) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
INVESTMENTS ACCOUNTED FOR BY EQUITY METHOD [Abstract]
Revenues	$ 351.6	$ 110.6
Expenses	(142.7)	(74.2)
Gross profit	208.9	36.4
Current assets	1,204.6	24.8
Property, plant and equipment	7,602.5	82.8
Intangible assets	22.9	5.6
Long-term investments and other assets	1,326.6	843.3
Current liabilities	(1,015.2)	(41.7)
Other long-term liabilities	$ (949.6)	$ (189.1)

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SHORT-TERM DEBT (Narrative) (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2017 CAD ($)
Short-term Debt [Line Items]
Commercial Paper		$ 1,145.2
Project Financing		64.5
Unsecured Demand Revolving Operating Credit Facility [Member] | Parent Company [Member]
Short-term Debt [Line Items]
Credit facility maximum borrowing capacity		70.0	$ 50.0
WGL And Washington Gas [Member]
Short-term Debt [Line Items]
Commercial Paper	$ 839.5
Letter of Credit [Member] | Unsecured Demand Revolving Operating Credit Facility [Member]
Short-term Debt [Line Items]
Credit facility maximum borrowing capacity		35.0
Amount outstanding		6.0
Letter of Credit [Member] | Unsecured Extendible Revolving Facility [Member]
Short-term Debt [Line Items]
Credit facility maximum borrowing capacity		150.0	150.0
Amount outstanding		117.0	40.8
Term	4 years
Letter of Credit [Member] | Unsecured Bilateral Demand Facility [Member]
Short-term Debt [Line Items]
Credit facility maximum borrowing capacity	$ 200.0		150.0
Amount outstanding		$ 147.3	$ 71.3
Letter of Credit [Member] | Unsecured Extendible Revolving Facility II [Member]
Short-term Debt [Line Items]
Credit facility maximum borrowing capacity	300.0
Letter of Credit [Member] | WGL Holdings [Member]
Short-term Debt [Line Items]
Credit facility maximum borrowing capacity	650.0
Amount outstanding	0.0
Letter of Credit [Member] | Washington Gas [Member]
Short-term Debt [Line Items]
Credit facility maximum borrowing capacity	350.0
Amount outstanding	$ 0.0

XML

SHORT-TERM DEBT (Schedule of Short-Term Debt) (Details) $ in Millions, $ in Millions	Dec. 31, 2018 USD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2017 CAD ($)
Short-term Debt [Line Items]
Bank indebtedness		$ 0.2		$ 6.2
Commercial paper		1,145.2
Project financing		64.5
Short-term debt		1,209.9		46.8
US Operating Facility [Member]
Short-term Debt [Line Items]
Operating facility				31.7
Credit facility maximum borrowing capacity	$ 150.0		$ 150.0
US Operating Facility [Member] | Letter of Credit [Member]
Short-term Debt [Line Items]
Operating facility		0.7		0.6
Domestic Operating Facility [Member
Short-term Debt [Line Items]
Operating facility				$ 8.9
Credit facility maximum borrowing capacity		$ 25.0
Prime Rate [Member]
Short-term Debt [Line Items]
Effective rate	3.95%	3.95%	3.20%	3.20%

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LONG-TERM DEBT (Schedule of Long-Term Debt) (Details)	12 Months Ended
	Dec. 31, 2018 USD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2017 CAD ($)
Debt Instrument [Line Items]
Fair value adjustment on WGL Acquisition (note 3)		$ 89,000,000
Long-term debt, gross		8,992,300,000	$ 3,639,800,000
Less debt issuance costs		(35,200,000)	(14,400,000)
Total long-term debt		8,957,100,000	3,625,400,000
Less current portion		(890,200,000)	(188,900,000)
Long-term debt, noncurrent		8,066,900,000	3,436,500,000
Debenture Notes [Member]
Debt Instrument [Line Items]
Debentures amount sold		33,300,000
$1,400 million unsecured extendible revolving [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Maturity date	May 15, 2023
Long-term debt, gross		964,700,000	219,100,000
Debt face amount		1,400,000,000
US$300 million unsecured extendible revolving [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Maturity date	May 15, 2022
Long-term debt, gross		287,800,000
Debt face amount	$ 300,000,000
Acquisition credit facility [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Maturity date	Jan. 06, 2020
Long-term debt, gross		113,200,000
US$1,200 million revolving credit facility [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Maturity date	Dec. 28, 2021
Long-term debt, gross		1,637,000,000
Debt face amount	$ 1,200,000,000
$175 million Senior unsecured - 4.60 percent [Member] | Medium-term Notes [Member]
Debt Instrument [Line Items]
Maturity date	Jan. 15, 2018
Long-term debt, gross			175,000,000
Debt face amount		$ 175,000,000
Debt instrument rate	4.60%	4.60%
$200 million Senior unsecured - 4.55 percent [Member] | Medium-term Notes [Member]
Debt Instrument [Line Items]
Maturity date	Jan. 17, 2019
Long-term debt, gross		$ 200,000,000	200,000,000
Debt face amount		$ 200,000,000
Debt instrument rate	4.55%	4.55%
$200 million Senior unsecured - 4.07 percent [Member] | Medium-term Notes [Member]
Debt Instrument [Line Items]
Maturity date	Jun. 01, 2020
Long-term debt, gross		$ 200,000,000	200,000,000
Debt face amount		$ 200,000,000
Debt instrument rate	4.07%	4.07%
$350 million Senior unsecured - 3.72 percent [Member] | Medium-term Notes [Member]
Debt Instrument [Line Items]
Maturity date	Sep. 28, 2021
Long-term debt, gross		$ 350,000,000	350,000,000
Debt face amount		$ 350,000,000
Debt instrument rate	3.72%	3.72%
$300 million Senior unsecured - 3.57 percent [Member] | Medium-term Notes [Member]
Debt Instrument [Line Items]
Maturity date	Jun. 12, 2023
Long-term debt, gross		$ 300,000,000	300,000,000
Debt face amount		$ 300,000,000
Debt instrument rate	3.57%	3.57%
$200 million Senior unsecured - 4.40 percent [Member] | Medium-term Notes [Member]
Debt Instrument [Line Items]
Maturity date	Mar. 15, 2024
Long-term debt, gross		$ 200,000,000	200,000,000
Debt face amount		$ 200,000,000
Debt instrument rate	4.40%	4.40%
$300 million Senior unsecured - 3.84 percent [Member] | Medium-term Notes [Member]
Debt Instrument [Line Items]
Maturity date	Jan. 15, 2025
Long-term debt, gross		$ 299,900,000	299,900,000
Debt face amount		$ 300,000,000
Debt instrument rate	3.84%	3.84%
$100 million Senior unsecured - 5.16 percent [Member] | Medium-term Notes [Member]
Debt Instrument [Line Items]
Maturity date	Jan. 13, 2044
Long-term debt, gross		$ 100,000,000	100,000,000
Debt face amount		$ 100,000,000
Debt instrument rate	5.16%	5.16%
$300 million Senior unsecured - 4.50 percent [Member] | Medium-term Notes [Member]
Debt Instrument [Line Items]
Maturity date	Aug. 15, 2044
Long-term debt, gross		$ 299,800,000	299,800,000
Debt face amount		$ 300,000,000
Debt instrument rate	4.50%	4.50%
$350 million Senior unsecured - 4.12 percent [Member] | Medium-term Notes [Member]
Debt Instrument [Line Items]
Maturity date	Apr. 07, 2026
Long-term debt, gross		$ 349,800,000	349,800,000
Debt face amount		$ 350,000,000
Debt instrument rate	4.12%	4.12%
$200 million Senior unsecured - 3.98 percent [Member] | Medium-term Notes [Member]
Debt Instrument [Line Items]
Maturity date	Oct. 04, 2027
Long-term debt, gross		$ 199,900,000	199,900,000
Debt face amount		$ 200,000,000
Debt instrument rate	3.98%	3.98%
$250 million Senior unsecured - 4.99 percent [Member] | Medium-term Notes [Member]
Debt Instrument [Line Items]
Maturity date	Oct. 04, 2047
Long-term debt, gross		$ 250,000,000	250,000,000
Debt face amount		$ 250,000,000
Debt instrument rate	4.99%	4.99%
US$300 million SEMCO Senior secured - 5.15 percent [Member] | Long-Term Debt [Member]
Debt Instrument [Line Items]
Maturity date	Apr. 21, 2020
Long-term debt, gross		$ 409,300,000	376,400,000
Debt face amount	$ 300,000,000
Debt instrument rate	5.15%	5.15%
US$82 million CINGSA Senior secured - 4.48 percent [Member] | Long-Term Debt [Member]
Debt Instrument [Line Items]
Maturity date	Mar. 02, 2032
Long-term debt, gross		$ 86,300,000	85,200,000
Debt face amount	$ 82,000,000
Debt instrument rate	4.48%	4.48%
PNG 2018 Series Debenture - 8.75 percent [Member] | Debenture Notes [Member]
Debt Instrument [Line Items]
Maturity date	Nov. 15, 2018
Long-term debt, gross			7,000,000
Debt instrument rate	8.75%	8.75%
PNG 2025 Series Debenture - 9.30 percent [Member] | Debenture Notes [Member]
Debt Instrument [Line Items]
Maturity date	Jul. 18, 2025
Long-term debt, gross			13,000,000
Debt instrument rate	9.30%	9.30%
PNG 2027 Series Debenture - 6.90 percent [Member] | Debenture Notes [Member]
Debt Instrument [Line Items]
Maturity date	Dec. 02, 2027
Long-term debt, gross			14,000,000
Debt instrument rate	6.90%	6.90%
CINGSA capital lease - 3.50 percent [Member] | Debenture Notes [Member]
Debt Instrument [Line Items]
Maturity date	May 01, 2040
Long-term debt, gross		$ 600,000	500,000
Debt instrument rate	3.50%	3.50%
CINGSA capital lease - 4.48 percent [Member] | Debenture Notes [Member]
Debt Instrument [Line Items]
Maturity date	Jun. 04, 2068
Long-term debt, gross		$ 200,000	$ 200,000
Debt instrument rate	4.48%	4.48%
US$500 million Senior unsecured - 2.25 to 4.76 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Maturity date range	Jan - Nov 2019
Long-term debt, gross		$ 682,100,000
Debt face amount	$ 500,000,000
US$250 million Senior unsecured - 2.88 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Maturity date	Mar. 12, 2020
Long-term debt, gross		$ 341,100,000
Debt face amount	$ 250,000,000
Debt instrument rate	2.88%	2.88%
US$20 million Senior unsecured - 6.65 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Maturity date	Mar. 20, 2023
Long-term debt, gross		$ 27,300,000
Debt face amount	$ 20,000,000
Debt instrument rate	6.65%	6.65%
US$40.5 million Senior unsecured - 5.44 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Maturity date	Aug. 11, 2025
Long-term debt, gross		$ 55,300,000
Debt face amount	$ 40,500,000
Debt instrument rate	5.44%	5.44%
US$53 million Senior unsecured - 6.62 to 6.82 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Maturity date	Oct. 01, 2026
Long-term debt, gross		$ 72,300,000
Debt face amount	$ 53,000,000
US$72 million Senior unsecured - 6.40 to 6.57 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Maturity date range	Feb - Sep 2027
Long-term debt, gross		98,200,000
Debt face amount	$ 72,000,000
US$52 million Senior unsecured - 6.57 to 6.85 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Maturity date range	Jan - Mar 2028
Long-term debt, gross		70,900,000
Debt face amount	$ 52,000,000
US$8.5 million Senior unsecured - 7.50 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Maturity date	Apr. 01, 2030
Long-term debt, gross		$ 11,600,000
Debt face amount	$ 8,500,000
Debt instrument rate	7.50%	7.50%
US$50 million Senior unsecured - 5.70 to 5.78 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Maturity date range	Jan - Mar 2036
Long-term debt, gross		$ 68,200,000
Debt face amount	$ 50,000,000
US$75 million Senior unsecured - 5.21 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Maturity date	Dec. 03, 2040
Long-term debt, gross		$ 102,300,000
Debt face amount	$ 75,000,000
Debt instrument rate	5.21%	5.21%
US$75 million Senior unsecured - 5.00 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Maturity date	Dec. 15, 2043
Long-term debt, gross		$ 102,300,000
Debt face amount	$ 75,000,000
Debt instrument rate	5.00%	5.00%
US$300 million Senior unsecured - 4.22 to 4.60 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Maturity date range	Sep - Dec 2044
Long-term debt, gross		$ 409,300,000
Debt face amount	$ 300,000,000
US$450 million Senior unsecured - 3.80 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Maturity date	Sep. 15, 2046
Long-term debt, gross		$ 613,900,000
Debt face amount	$ 450,000,000
Debt instrument rate	3.80%	3.80%
Minimum [Member] | US$500 million Senior unsecured - 2.25 to 4.76 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Debt instrument rate	2.25%	2.25%
Minimum [Member] | US$53 million Senior unsecured - 6.62 to 6.82 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Debt instrument rate	6.62%	6.62%
Minimum [Member] | US$72 million Senior unsecured - 6.40 to 6.57 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Debt instrument rate	6.40%	6.40%
Minimum [Member] | US$52 million Senior unsecured - 6.57 to 6.85 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Debt instrument rate	6.57%	6.57%
Minimum [Member] | US$50 million Senior unsecured - 5.70 to 5.78 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Debt instrument rate	5.70%	5.70%
Minimum [Member] | US$300 million Senior unsecured - 4.22 to 4.60 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Debt instrument rate	4.22%	4.22%
Maximum [Member] | US$500 million Senior unsecured - 2.25 to 4.76 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Debt instrument rate	4.76%	4.76%
Maximum [Member] | US$53 million Senior unsecured - 6.62 to 6.82 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Debt instrument rate	6.82%	6.82%
Maximum [Member] | US$72 million Senior unsecured - 6.40 to 6.57 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Debt instrument rate	6.57%	6.57%
Maximum [Member] | US$52 million Senior unsecured - 6.57 to 6.85 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Debt instrument rate	6.85%	6.85%
Maximum [Member] | US$50 million Senior unsecured - 5.70 to 5.78 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Debt instrument rate	5.78%	5.78%
Maximum [Member] | US$300 million Senior unsecured - 4.22 to 4.60 percent [Member] | Medium-term Notes [Member] | WGL And Washington Gas [Member]
Debt Instrument [Line Items]
Debt instrument rate	4.60%	4.60%

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ASSET RETIREMENT OBLIGATIONS (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligations [Line Items]
Undiscounted cash required to settle the asset retirement obligations, excluding growth for inflation	$ 770.0	$ 232.9
Legally restricted assets	$ 0.0
Minimum [Member]
Asset Retirement Obligations [Line Items]
Discount rate for asset retirement obligations	1.50%
Year of expected discount rate application	2019
Maximum [Member]
Asset Retirement Obligations [Line Items]
Discount rate for asset retirement obligations	8.50%
Year of expected discount rate application	2064

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ASSET RETIREMENT OBLIGATIONS (Schedule of Accumulated Other Comprehensive Income) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
ASSET RETIREMENT OBLIGATIONS [Abstract]
Balance, beginning of year	$ 88.3	$ 81.6
Obligations acquired (note 3)	399.1
New obligations	3.3	1.5
Obligations settled	(4.2)	(4.0)
Disposals	(1.6)
Revision in estimated cash flow	3.8	6.0
Accretion expense	12.3	4.4
Foreign exchange translation	20.3	(0.9)
Reclassified to liabilities associated with assets held for sale (note 5)	(10.8)	(0.3)
Total	510.5	88.3
Less current portion (included in accounts payable and accrued liabilities)	(9.9)
Balance, end of year	$ 500.6	$ 88.3

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ENVIRONMENTAL MATTERS (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 CAD ($) item	Dec. 31, 2017 CAD ($)
Site Contingency [Line Items]
Identified operated manufactured gas plants | item	12
Accrual for environmental loss contingencies	$ 15.4
Regulatory Assets	19.9	$ 13.9
Maximum [Member]
Site Contingency [Line Items]
Accrual for environmental loss contingencies	$ 40.1

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OTHER LONG-TERM LIABILITIES (Schedule of Other Long-Term Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Other Long-Term Liabilities [Line Items]
Deferred lease payable	$ 13.1	$ 2.4
Deferred revenue	3.9	3.8
Customer advances for construction	58.6	40.9
NTL liability		142.0
Lease inducement	2.7	3.1
Merger commitments	21.4
Other long term liabilities	20.3	5.7
Other long-term liabilities	122.0	201.9
Power purchase agreement termination, settlement amount	2.0	$ 4.0
ASTC [Member]
Other Long-Term Liabilities [Line Items]
Power purchase agreement termination, settlement amount	6.0
Accounts Payable and Accrued Liabilities [Member] | ASTC [Member]
Other Long-Term Liabilities [Line Items]
Power purchase agreement termination, settlement amount	$ 2.0

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INCOME TAXES (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Income Taxes [Line Items]
Statutory income tax rate	27.00%	27.00%
Tax-affected non-capital losses	$ 392.1
Internal Revenue Service (IRS) [Member]
Income Taxes [Line Items]
Statutory income tax rate	21.00%	35.00%
Minimum [Member]
Income Taxes [Line Items]
Tax-affected non-capital losses, expiration date	Dec. 31, 2023
Maximum [Member]
Income Taxes [Line Items]
Tax-affected non-capital losses, expiration date	Dec. 31, 2038

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INCOME TAXES (Schedule of Income Tax Provision) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
INCOME TAXES [Abstract]
Income (loss) before income taxes - consolidated	$ (716.9)	$ 66.4
Statutory income tax rate (%)	27.00%	27.00%
Expected taxes at statutory rates	$ (193.6)	$ 17.9
Permanent differences	(1.0)	9.5
Statutory and other rate differences	(19.6)	(30.5)
Rate adjustment for change in tax rates	1.3	(34.1)
Deferred income tax recovery on regulated assets	(7.3)	(7.4)
Tax differences on divestitures and transactions	(32.3)	6.9
Non-controlling interests	4.7
Change in valuation allowance	(22.3)	4.2
Other	6.9
Income tax expense, total	(263.2)	(33.5)
Canada	23.7	18.0
United States	0.7	12.5
Current income tax provision	24.4	30.5
Canada	(166.1)	(7.4)
United States	(121.5)	(56.6)
Deferred income tax expense	$ (287.6)	$ (64.0)
Effective income tax rate	36.70%	(50.50%)

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INCOME TAXES (Schedule of Deferred Income Tax Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
INCOME TAXES [Abstract]
PP&E and intangible assets	$ 1,764.6	$ 726.5
Regulatory assets	(166.3)
Regulatory liabilities		22.8
Tax pools, deferred financing and compensation	(453.6)	(302.3)
Other	(209.9)	(59.3)
Valuation allowance	23.1	53.7
Net deferred income tax liabilities	$ 957.9	$ 441.4

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INCOME TAXES (Schedule of Uncertain Tax Positions) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
INCOME TAXES [Abstract]
Balance, beginning of year	$ 5.9	$ 2.2
Net changes during the year	(3.7)	3.7
Balance, end of year	$ 2.2	$ 5.9

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REGULATORY ASSETS AND LIABILITIES (Schedule of Regulatory Assets and Liabilities) (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2018 CAD ($)
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets - current		$ 1.1	$ 21.0
Regulatory assets - non-current		328.6	663.0
Regulatory liabilities - current		10.9	114.9
Regulatory liabilities - non-current		$ 268.6	1,392.8
Fair Value Adjustment On Acquisition			89.0
Statutory income tax rate	27.00%	27.00%
Internal Revenue Service (IRS) [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Statutory income tax rate	21.00%	35.00%
Deferred Cost Of Gas [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities - current		$ 9.0	71.2
Option Fees Deferral [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities - non-current		4.3
Refundable Tax Credit [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities - current		1.9	3.8
Regulatory liabilities - non-current		7.5	6.1
Gas storage facility tax credit	$ 15.0
Future Recovery Of Pension And Other Retirement Benefits [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities - non-current			166.7
Future Removal And Site Restoration Costs [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities - non-current		153.3	514.7
Deferred Loss On Reacquired Debt [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities - non-current			1.8
Federal Income Tax Rate Change [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities - current			26.2
Regulatory liabilities - non-current		101.8	698.4
Insurance Recovery Of Environmental Costs [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities - non-current		0.3
Regulatory liabilities, Recovery Period	2 years
Other [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities - current			13.7
Regulatory liabilities - non-current		1.4	5.1
Deferred Cost Of Gas [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets - current		0.5	20.4
Deferred Property Taxes [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets - current		0.3
Deferred Regulatory Costs And Rate Stabilization Adjustment Mechanism [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets - non-current		20.5	215.5
Pipeline Rehabilitation Costs [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets - non-current		0.3
Future Recovery Of Pension And Other Retirement Benefits [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets - non-current		113.9	192.9
Future Recovery Of Non-Retirement Employee Benefits [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets - non-current			21.3
Deferred Pension Costs [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets - non-current			7.8
Regulatory assets, Recovery Period	1 year
Deferred Environmental Costs [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets - non-current		13.9	19.9
Deferred Loss On Reacquired Debt [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets - non-current		2.5	109.3
Deferred Depreciation And Amortization [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets - non-current		23.3
Deferred Future Income Taxes [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets - non-current		104.7	67.0
Deferred Customer Retention Program Amortization [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets - non-current		16.5
Revenue Deficiency Account [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets - non-current		31.0
Other [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets - current		0.3	0.6
Regulatory assets - non-current		$ 2.0	$ 29.3
CINGSA [Member] | Refundable Tax Credit [Member] | 2012 Through 2021 [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Annual disbursement rate of tax credit	10.00%
Minimum [Member] | Future Removal And Site Restoration Costs [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, Recovery Period	3 years
Minimum [Member] | Deferred Regulatory Costs And Rate Stabilization Adjustment Mechanism [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets, Recovery Period	1 year
Minimum [Member] | Deferred Environmental Costs [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets, Recovery Period	1 year
Minimum [Member] | Deferred Loss On Reacquired Debt [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets, Recovery Period	1 year
Maximum [Member] | Deferred Cost Of Gas [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, Recovery Period	1 year
Maximum [Member] | Refundable Tax Credit [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, Recovery Period	1 year
Maximum [Member] | Future Removal And Site Restoration Costs [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, Recovery Period	56 years
Maximum [Member] | Federal Income Tax Rate Change [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, Recovery Period	1 year
Maximum [Member] | Other [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, Recovery Period	1 year
Maximum [Member] | Deferred Cost Of Gas [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets, Recovery Period	1 year
Maximum [Member] | Deferred Property Taxes [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets, Recovery Period	1 year
Maximum [Member] | Deferred Regulatory Costs And Rate Stabilization Adjustment Mechanism [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets, Recovery Period	3 years
Maximum [Member] | Deferred Environmental Costs [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets, Recovery Period	10 years
Maximum [Member] | Deferred Loss On Reacquired Debt [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets, Recovery Period	15 years
Maximum [Member] | Other [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory assets, Recovery Period	1 year

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ACCUMULATED OTHER COMPREHENSIVE INCOME (Schedule of Accumulated Other Comprehensive Income) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Accumulated Other Comprehensive Income Loss [Line Items]
Opening balance	$ 4,639.2
Total other comprehensive income (loss) (OCI), net of taxes (note 21)	379.9	$ (206.0)
Ending balance	7,640.2	4,639.2
Available-For-Sale [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Opening balance	(7.1)	19.8
OCI before reclassification		(30.3)
Adoption Of ASU No. 2016-01 (note 2)	7.1
Current period OCI (pre-tax)	7.1	(30.3)
Income tax on amounts retained in AOCI		3.4
Total other comprehensive income (loss) (OCI), net of taxes (note 21)	7.1	(26.9)
Ending balance		(7.1)
Defined Benefit Pension And PRB Plans [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Opening balance	(11.4)	(11.3)
OCI before reclassification	(14.1)	(1.3)
Amounts reclassified from OCI	0.7	1.3
Curtailment of DB and PRB plan	4.2
Current period OCI (pre-tax)	(9.2)
Income tax on amounts retained in AOCI	3.3	0.3
Income tax on amounts reclassified to earnings	(0.2)	(0.4)
Income tax on amounts related to curtailment of DB and PRB plan	(1.5)
Total other comprehensive income (loss) (OCI), net of taxes (note 21)	(7.6)	(0.1)
Ending balance	(19.0)	(11.4)
Hedge Net investments [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Opening balance	(129.0)	(135.6)
OCI before reclassification	(90.6)	6.6
Current period OCI (pre-tax)	(90.6)	6.6
Income tax on amounts retained in AOCI	10.4
Total other comprehensive income (loss) (OCI), net of taxes (note 21)	(80.2)	6.6
Ending balance	(209.2)	(129.0)
Translation Foreign Operations [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Opening balance	342.9	526.3
OCI before reclassification	458.5	(183.4)
Current period OCI (pre-tax)	458.5	(183.4)
Total other comprehensive income (loss) (OCI), net of taxes (note 21)	458.5	(183.4)
Ending balance	801.4	342.9
Equity Investee [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Opening balance	3.7	5.9
OCI before reclassification	2.1	(2.2)
Current period OCI (pre-tax)	2.1	(2.2)
Total other comprehensive income (loss) (OCI), net of taxes (note 21)	2.1	(2.2)
Ending balance	5.8	3.7
Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Opening balance	199.1	405.1
OCI before reclassification	355.9	(210.6)
Amounts reclassified from OCI	0.7	1.3
Adoption Of ASU No. 2016-01 (note 2)	7.1
Curtailment of DB and PRB plan	4.2
Current period OCI (pre-tax)	367.9	(209.3)
Income tax on amounts retained in AOCI	13.7	3.7
Income tax on amounts reclassified to earnings	(0.2)	(0.4)
Income tax on amounts related to curtailment of DB and PRB plan	(1.5)
Total other comprehensive income (loss) (OCI), net of taxes (note 21)	379.9	(206.0)
Ending balance	$ 579.0	$ 199.1

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ACCUMULATED OTHER COMPREHENSIVE INCOME (Summary of Reclassification from Accumulated Other Comprehensive Income) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating and administrative expense	$ 1,129.0	$ 572.2
Deferred income tax recovery (note 19)	(287.6)	(64.0)
Net income (loss)	(435.1)	91.6
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Deferred income tax recovery (note 19)	(0.2)	(0.4)
Net income (loss)	0.5	0.9
Reclassification out of Accumulated Other Comprehensive Income [Member] | Defined Benefit Pension And PRB Plans [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating and administrative expense	$ 0.7	$ 1.3

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FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGMENT (Narrative) (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018 CAD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2018 USD ($) contract	Dec. 31, 2018 CAD ($) contract	Jun. 30, 2018 CAD ($)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Unrealized gains (losses) on risk management contracts	$ 80.8	$ (62.5)
Customer Concentration Risk [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Concentration risk	0.00%
Foreign Exchange Forward [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative notional amount					$ 3,200.0
Derivative, Gain on Derivative	$ 1.3
Interest Rate Swap [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fixed rate debt, percent			59.00%	59.00%
Number of instruments | contract			0	0
Foreign Exchange Option [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative, Loss on Derivative	36.0
Weather Related Derivative [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Unrealized gains (losses) on risk management contracts	(1.0)
Currency, U.S. Dollar [Member] | Net Investment Hedge [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gain (loss) on translation, net of tax	80.2	6.6
Outstanding amount of hedge			$ 1,494.0
Currency, U.S. Dollar [Member] | Foreign Exchange Option [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative notional amount				$ 1,200.0
Unrealized gains (losses) on risk management contracts	$ 34.3	$ (34.3)

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FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Schedule of Fair Value of Risk Management Assets and Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Risk management assets - current	$ 114.1	$ 38.6
Risk management assets - non-current	57.7	15.9
Risk management liabilities - current	89.3	57.6
Risk management liabilities - non-current	213.0	13.8
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Equity securities	8.4	95.0
Loans and receivables	45.0	75.0
Financial assets	225.2	224.5
Current portion of long-term debt	890.2	188.9
Long-term debt	8,066.9	3,436.5
Other current liabilities	11.2	22.4
Other long-term liabilities	2.0	146.0
Financial liabilities	9,272.6	3,865.2
Carrying Amount [Member] | Fair Value Through Net Income [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Risk management assets - current	99.0	38.6
Risk management assets - non-current	49.0	15.9
Risk management liabilities - current	72.0	57.6
Risk management liabilities - non-current	103.4	13.8
Carrying Amount [Member] | Fair Value Through Regulatory Assets/Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Risk management assets - current	15.1
Risk management assets - non-current	8.7
Risk management liabilities - current	17.3
Risk management liabilities - non-current	109.6
Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Equity securities	8.4	95.0
Loans and receivables	45.2	85.6
Financial assets	225.4	235.1
Current portion of long-term debt	884.4	189.6
Long-term debt	8,040.3	3,568.3
Other current liabilities	11.2	22.4
Other long-term liabilities	2.0	147.7
Financial liabilities	9,240.2	3,999.4
Fair Value [Member] | Fair Value Through Net Income [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Risk management assets - current	99.0	38.6
Risk management assets - non-current	49.0	15.9
Risk management liabilities - current	72.0	57.6
Risk management liabilities - non-current	103.4	13.8
Fair Value [Member] | Fair Value Through Regulatory Assets/Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Risk management assets - current	15.1
Risk management assets - non-current	8.7
Risk management liabilities - current	17.3
Risk management liabilities - non-current	109.6
Fair Value [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Equity securities	8.4	95.0
Financial assets	8.4	95.0
Fair Value [Member] | Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Loans and receivables	45.2	85.6
Financial assets	134.2	140.1
Current portion of long-term debt	884.4	189.6
Long-term debt	6,027.6	3,568.3
Other current liabilities	11.2	22.4
Other long-term liabilities	2.0	147.7
Financial liabilities	6,984.8	3,999.4
Fair Value [Member] | Level 2 [Member] | Fair Value Through Net Income [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Risk management assets - current	68.3	38.6
Risk management assets - non-current	18.0	15.9
Risk management liabilities - current	41.3	57.6
Risk management liabilities - non-current	15.3	$ 13.8
Fair Value [Member] | Level 2 [Member] | Fair Value Through Regulatory Assets/Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Risk management assets - current	2.7
Risk management liabilities - current	2.9
Risk management liabilities - non-current	0.1
Fair Value [Member] | Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets	82.8
Long-term debt	2,012.7
Financial liabilities	2,255.4
Fair Value [Member] | Level 3 [Member] | Fair Value Through Net Income [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Risk management assets - current	30.7
Risk management assets - non-current	31.0
Risk management liabilities - current	30.7
Risk management liabilities - non-current	88.1
Fair Value [Member] | Level 3 [Member] | Fair Value Through Regulatory Assets/Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Risk management assets - current	12.4
Risk management assets - non-current	8.7
Risk management liabilities - current	14.4
Risk management liabilities - non-current	$ 109.5

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FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Quantitative Information About The Significant Unobservable Inputs Used In The Fair Value Measurement Of Level 3) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 CAD ($) $ / item
Natural Gas [Member] | Valuation Technique, Discounted Cash Flow [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value, Net Asset (Liability) | $	$ (144.1)
Natural Gas [Member] | Valuation Technique, Option Pricing Model [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value, Net Asset (Liability) | $	(4.4)
Electricity [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value, Net Asset (Liability) | $	$ (14.7)
Minimum [Member] | Natural Gas [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value, Net Asset (Liability), Percent	37.46%
Minimum [Member] | Natural Gas [Member] | Valuation Technique, Discounted Cash Flow [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value, Net Asset (Liability), Per Dekatherm	(1.40)
Minimum [Member] | Natural Gas [Member] | Valuation Technique, Option Pricing Model [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value, Net Asset (Liability), Per Dekatherm	(1.37)
Minimum [Member] | Electricity [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value, Net Asset (Liability), Per Megawatt Hour	8.28
Maximum [Member] | Natural Gas [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value, Net Asset (Liability), Percent	900.98%
Maximum [Member] | Natural Gas [Member] | Valuation Technique, Discounted Cash Flow [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value, Net Asset (Liability), Per Dekatherm	7.28
Maximum [Member] | Natural Gas [Member] | Valuation Technique, Option Pricing Model [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value, Net Asset (Liability), Per Dekatherm	5.07
Maximum [Member] | Electricity [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value, Net Asset (Liability), Per Megawatt Hour	84.44

XML

FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Changes In Net Fair Value Of Derivative Assets And Liabilities Classified As Level 3) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance, beginning of year
Acquired (note 3)	(146.7)
Recorded in income	(14.8)
Recorded in regulatory assets	(5.9)
Transfers out of Level 3	7.3
Purchases	6.4
Settlements	(3.1)
Foreign exchange translation	(6.4)
Balance, end of year	(163.2)
Natural Gas [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance, beginning of year
Acquired (note 3)	(136.1)
Recorded in income	(8.3)
Recorded in regulatory assets	(5.9)
Transfers out of Level 3	7.3
Purchases
Settlements	0.3
Foreign exchange translation	(5.8)
Balance, end of year	(148.5)
Electricity [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance, beginning of year
Acquired (note 3)	(10.6)
Recorded in income	(6.5)
Recorded in regulatory assets
Transfers out of Level 3
Purchases	6.4
Settlements	(3.4)
Foreign exchange translation	(0.6)
Balance, end of year	$ (14.7)

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FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Realized and Unrealized Losses Recorded to Income for Level 3 Measurements) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 CAD ($)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Realized and Unrealized Losses Recorded to Income for Level 3 Measurements	$ (14.8)
Commodity Contract [Member] | Recorded to Revenue [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Realized and Unrealized Losses Recorded to Income for Level 3 Measurements	(11.1)
Commodity Contract [Member] | Recorded to Cost of Sales [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Realized and Unrealized Losses Recorded to Income for Level 3 Measurements	$ (3.7)

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FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Summary of Unrealized Gains (Losses) on Risk Management Contracts) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments Gain Loss [Line Items]
Unrealized gains (losses) on risk management contracts	$ 80.8	$ (62.5)
Natural Gas Contracts [Member]
Derivative Instruments Gain Loss [Line Items]
Unrealized gains (losses) on risk management contracts	(2.2)	2.2
Storage Optimization [Member]
Derivative Instruments Gain Loss [Line Items]
Unrealized gains (losses) on risk management contracts		2.7
NGL Frac Spread [Member]
Derivative Instruments Gain Loss [Line Items]
Unrealized gains (losses) on risk management contracts	40.0	(11.7)
Power Contracts [Member]
Derivative Instruments Gain Loss [Line Items]
Unrealized gains (losses) on risk management contracts	9.3	(20.8)
Foreign Exchange [Member]
Derivative Instruments Gain Loss [Line Items]
Unrealized gains (losses) on risk management contracts	$ 33.7	$ (34.9)

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FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Schedule of Offsetting Assets and Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Offsetting Assets And Liabilities [Line Items]
Gross amount of recognized assets	$ 262.3	$ 61.7
Gross amount of liabilities offset in balance sheet	(90.5)	(7.2)
Net amount of assets presented in balance sheet	171.8	54.5
Gross amounts of recognized liabilities	394.9	74.4
Gross amount of assets offset in balance sheet	(90.5)	(7.2)
Netting of collateral	(2.1)	4.2
Net amount of liabilities presented in balance sheet	302.3	71.4
Risk management assets - current	114.1	38.6
Risk management assets - non-current	57.7	15.9
Risk management liabilities - current	89.3	57.6
Risk management liabilities - non-current	213.0	13.8
Natural Gas Contracts [Member]
Offsetting Assets And Liabilities [Line Items]
Gross amount of recognized assets	200.8	41.0
Gross amount of liabilities offset in balance sheet	(82.0)	(6.2)
Net amount of assets presented in balance sheet	118.8	34.8
Gross amounts of recognized liabilities	340.4	35.1
Gross amount of assets offset in balance sheet	(82.0)	(6.2)
Netting of collateral	(3.3)
Net amount of liabilities presented in balance sheet	255.1	28.9
NGL Frac Spread [Member]
Offsetting Assets And Liabilities [Line Items]
Gross amount of recognized assets	18.7	1.3
Gross amount of liabilities offset in balance sheet	(0.7)	(0.3)
Net amount of assets presented in balance sheet	18.0	1.0
Gross amounts of recognized liabilities	2.7	25.3
Gross amount of assets offset in balance sheet	(0.7)	(0.3)
Net amount of liabilities presented in balance sheet	2.0	25.0
Power Contracts [Member]
Offsetting Assets And Liabilities [Line Items]
Gross amount of recognized assets	42.8	17.7
Gross amount of liabilities offset in balance sheet	(7.8)	(0.7)
Net amount of assets presented in balance sheet	35.0	17.0
Gross amounts of recognized liabilities	50.6	14.0
Gross amount of assets offset in balance sheet	(7.8)	(0.7)
Netting of collateral	1.2	4.2
Net amount of liabilities presented in balance sheet	44.0	17.5
Foreign Exchange [Member]
Offsetting Assets And Liabilities [Line Items]
Gross amount of recognized assets		1.7
Net amount of assets presented in balance sheet		$ 1.7
Gross amounts of recognized liabilities	1.2
Net amount of liabilities presented in balance sheet	$ 1.2

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FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Collateral Not Offset Against Risk Management Assets and Liabilities) (Details) $ in Millions	Dec. 31, 2018 CAD ($)
FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT [Abstract]
Collateral posted with counterparties	$ 27.6
Cash collateral held representing an obligation	$ 0.8

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FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Risk Management Liabilities And Maximum Potential Collateral Requirements) (Details) $ in Millions	Dec. 31, 2018 CAD ($)
FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT [Abstract]
Risk management liabilities with credit-risk-contingent features	$ 14.7
Maximum potential collateral requirements	$ 7.5

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FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Schedule of Fixed and Market Price Contract) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 CAD ($) MWh kJ $ / item $ / bbl $ / kJ $ / MWh bbl	Dec. 31, 2017 CAD ($) MWh kJ $ / item $ / bbl $ / kJ $ / MWh bbl
Natural Gas Contracts [Member] | Sales [Member]
Derivative [Line Items]
Notional volume (GJ or MWh) | kJ	858,640,810,000	94,804,039,000
Fair Value ($)	$ 19.0	$ 14.8
Natural Gas Contracts [Member] | Purchases [Member]
Derivative [Line Items]
Notional volume (GJ or MWh) | kJ	1,638,207,391,000	61,980,315,000
Fair Value ($)	$ (179.5)	$ (16.8)
Natural Gas Contracts [Member] | Swaps [Member]
Derivative [Line Items]
Notional volume (GJ or MWh) | kJ	621,578,572,000	6,039,641,000
Fair Value ($)	$ 20.9	$ 7.9
Natural Gas Contracts [Member] | Minimum [Member] | Sales [Member]
Derivative [Line Items]
Fixed price | $ / kJ	1,070.00	420.00
Period (months)	1 month	1 month
Natural Gas Contracts [Member] | Minimum [Member] | Purchases [Member]
Derivative [Line Items]
Fixed price | $ / kJ	690.00	520.00
Period (months)	1 month	1 month
Natural Gas Contracts [Member] | Minimum [Member] | Swaps [Member]
Derivative [Line Items]
Fixed price | $ / kJ	2,560.00	2,860.00
Period (months)	1 month	1 month
Natural Gas Contracts [Member] | Maximum [Member] | Sales [Member]
Derivative [Line Items]
Fixed price | $ / kJ	12,190.00	6,890.00
Period (months)	178 months	60 months
Natural Gas Contracts [Member] | Maximum [Member] | Purchases [Member]
Derivative [Line Items]
Fixed price | $ / kJ	16,260.00	6,400.00
Period (months)	179 months	48 months
Natural Gas Contracts [Member] | Maximum [Member] | Swaps [Member]
Derivative [Line Items]
Fixed price | $ / kJ	15,370.00	9,380.00
Period (months)	231 months	10 months
Power Contracts [Member] | Sales [Member]
Derivative [Line Items]
Notional volume (GJ or MWh) | MWh	11,881,575	2,169,321
Fair Value ($)	$ (1.9)	$ (2.5)
Power Contracts [Member] | Purchases [Member]
Derivative [Line Items]
Fixed price | $ / MWh		58.50
Notional volume (GJ or MWh) | MWh	8,507,874	17,520
Fair Value ($)	$ 16.4	$ (4.5)
Power Contracts [Member] | Swaps [Member]
Derivative [Line Items]
Notional volume (GJ or MWh) | MWh	20,957,180	1,563,160
Fair Value ($)	$ (22.3)	$ 6.5
Power Contracts [Member] | Minimum [Member] | Sales [Member]
Derivative [Line Items]
Fixed price | $ / MWh	26.90	38.20
Period (months)	1 month	1 month
Power Contracts [Member] | Minimum [Member] | Purchases [Member]
Derivative [Line Items]
Fixed price | $ / MWh	25.50
Period (months)	1 month	1 month
Power Contracts [Member] | Minimum [Member] | Swaps [Member]
Derivative [Line Items]
Fixed price | $ / MWh	(6.07)	37.50
Period (months)	1 month	1 month
Power Contracts [Member] | Maximum [Member] | Sales [Member]
Derivative [Line Items]
Fixed price | $ / MWh	95.03	95.03
Period (months)	60 months	60 months
Power Contracts [Member] | Maximum [Member] | Purchases [Member]
Derivative [Line Items]
Fixed price | $ / MWh	50.25
Period (months)	36 months	12 months
Power Contracts [Member] | Maximum [Member] | Swaps [Member]
Derivative [Line Items]
Fixed price | $ / MWh	76.18	63.50
Period (months)	48 months	48 months
Propane [Member] | NGL Frac Spread [Member] | Swaps [Member]
Derivative [Line Items]
Notional volume (Bbl) | bbl	1,725,114	1,992,927
Fair Value ($)	$ 12.6	$ (10.9)
Propane [Member] | NGL Frac Spread [Member] | Minimum [Member] | Swaps [Member]
Derivative [Line Items]
Fixed price | $ / bbl	38.89	28.77
Period (months)	1 month	1 month
Propane [Member] | NGL Frac Spread [Member] | Maximum [Member] | Swaps [Member]
Derivative [Line Items]
Fixed price | $ / bbl	47.63	49.21
Period (months)	12 months	12 months
Butane [Member] | NGL Frac Spread [Member] | Swaps [Member]
Derivative [Line Items]
Notional volume (Bbl) | bbl	74,371	130,088
Fair Value ($)	$ 1.2	$ (0.3)
Butane [Member] | NGL Frac Spread [Member] | Minimum [Member] | Swaps [Member]
Derivative [Line Items]
Fixed price | $ / bbl	52.95	47.83
Period (months)	1 month	1 month
Butane [Member] | NGL Frac Spread [Member] | Maximum [Member] | Swaps [Member]
Derivative [Line Items]
Fixed price | $ / bbl	55.26	54.67
Period (months)	12 months	12 months
Crude Oil [Member] | NGL Frac Spread [Member] | Swaps [Member]
Derivative [Line Items]
Notional volume (Bbl) | bbl	329,230	518,665
Fair Value ($)	$ 6.0	$ (4.4)
Crude Oil [Member] | NGL Frac Spread [Member] | Minimum [Member] | Swaps [Member]
Derivative [Line Items]
Fixed price | $ / bbl	79.64	61.05
Period (months)	1 month	1 month
Crude Oil [Member] | NGL Frac Spread [Member] | Maximum [Member] | Swaps [Member]
Derivative [Line Items]
Fixed price | $ / bbl	86.28	75.64
Period (months)	12 months	12 months
Natural Gas [Member] | NGL Frac Spread [Member] | Swaps [Member]
Derivative [Line Items]
Notional volume (GJ or MWh) | kJ	9,490,365,000	11,428,515,000
Fair Value ($)	$ (3.8)	$ (8.4)
Natural Gas [Member] | NGL Frac Spread [Member] | Minimum [Member] | Swaps [Member]
Derivative [Line Items]
Fixed price | $ / item	1.38	0.42
Period (months)	1 month	1 month
Natural Gas [Member] | NGL Frac Spread [Member] | Maximum [Member] | Swaps [Member]
Derivative [Line Items]
Fixed price | $ / item	1.68	2.27
Period (months)	12 months	12 months

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FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Summary of Potential Impact on Pre-Tax Income Due to Change in Fair Value of Price Risk Derivatives) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 CAD ($) $ / item $ / item $ / bbl $ / MWh	Dec. 31, 2017 CAD ($)
Derivative [Line Items]
Unrealized gains (losses) on risk management contracts	$ 80.8	$ (62.5)
Alberta Power Price [Member]
Derivative [Line Items]
Increase or decrease to forward prices, energy | $ / MWh	1
Unrealized gains (losses) on risk management contracts	$ 0.3
PJM Power Price [Member]
Derivative [Line Items]
Increase or decrease to forward prices, energy | $ / item	1.00
Unrealized gains (losses) on risk management contracts	$ 1.2
AECO Natural Gas Price [Member]
Derivative [Line Items]
Increase or decrease to forward prices, energy | $ / item	0.50
Unrealized gains (losses) on risk management contracts	$ 5.9
NYMEX Natural Gas Price [Member]
Derivative [Line Items]
Increase or decrease to forward prices, energy | $ / item	0.50
Unrealized gains (losses) on risk management contracts	$ 31.5
NGL Frac Spread [Member]
Derivative [Line Items]
Unrealized gains (losses) on risk management contracts	$ 40.0	$ (11.7)
NGL Frac Spread [Member] | Propane [Member]
Derivative [Line Items]
Increase or decrease to forward prices, volume | $ / bbl	1
Unrealized gains (losses) on risk management contracts	$ 1.7
NGL Frac Spread [Member] | Butane [Member]
Derivative [Line Items]
Increase or decrease to forward prices, volume | $ / bbl	1
Unrealized gains (losses) on risk management contracts	$ 0.1
NGL Frac Spread [Member] | WTI Crude Oil [Member]
Derivative [Line Items]
Increase or decrease to forward prices, volume | $ / bbl	1
Unrealized gains (losses) on risk management contracts	$ 0.3
NGL Frac Spread [Member] | Natural Gas [Member]
Derivative [Line Items]
Increase or decrease to forward prices, energy | $ / item	0.50
Unrealized gains (losses) on risk management contracts	$ 4.7

XML

FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Schedule of Accounts Receivable Past Due or Impaired) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017
Accounts, Notes, Loans and Financing Receivable [Line Items]
AR accruals			$ 447.5	$ 184.6
Allowance for credit losses	$ (2.4)	$ (2.5)	(54.7)	(2.4)
Accounts receivable			1,547.5	382.9
Allowance for credit losses, Balance, beginning of year	2.4	2.5
Allowance for credit losses, Foreign exchange translation	0.1	(0.1)
Allowance for credit losses, New allowance	53.1	0.4
Allowance for credit losses, Change in allowance	(0.9)
Allowance for credit losses, Allowance applied to uncollectible customer accounts		(0.4)
Allowance for credit losses, Balance, end of year	54.7	$ 2.4
WGL Holdings [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance credit losses acquired	$ 52.9
Less Than 30 Days [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross				189.3
Accounts receivable			989.0
31 to 60 Days [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross				7.9
Accounts receivable			74.1
61 to 90 Days [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross				1.4
Accounts receivable			12.8
Over 90 Days [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross				(0.3)
Accounts receivable			24.1
Trade Accounts Receivable [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross			1,574.6	383.0
AR accruals			447.5	184.6
Receivables impaired			54.7	2.4
Trade Accounts Receivable [Member] | Less Than 30 Days [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross				187.0
Accounts receivable			961.5
Trade Accounts Receivable [Member] | 31 to 60 Days [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross				7.9
Accounts receivable			74.1
Trade Accounts Receivable [Member] | 61 to 90 Days [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross				1.4
Accounts receivable			12.8
Trade Accounts Receivable [Member] | Over 90 Days [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross				(0.3)
Accounts receivable			24.0
Other Accounts Receivable [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross			27.6	2.3
Other Accounts Receivable [Member] | Less Than 30 Days [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross				$ 2.3
Accounts receivable			27.5
Other Accounts Receivable [Member] | Over 90 Days [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable			$ 0.1

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FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (Schedule of Contractual Maturities for Financial Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Contractual maturities, Total	$ 11,938.9	$ 4,373.7
Contractual maturities, Less than 1 year	3,709.1	763.0
Contractual maturities, 1 - 3 years	3,178.7	1,045.9
Contractual maturities, 4 - 5 years	1,625.9	387.3
Contractual maturities, After 5 years	3,425.2	2,177.5
Accounts Payable and Accrued Liabilities [Member]
Derivative [Line Items]
Contractual maturities, Total	1,488.2	415.3
Contractual maturities, Less than 1 year	1,488.2	415.3
Dividends Payable [Member]
Derivative [Line Items]
Contractual maturities, Total	22.0	32.0
Contractual maturities, Less than 1 year	22.0	32.0
Short-term Debt [Member]
Derivative [Line Items]
Contractual maturities, Total	1,209.9	46.8
Contractual maturities, Less than 1 year	1,209.9	46.8
Other Current Liabilities [Member]
Derivative [Line Items]
Contractual maturities, Total	11.2	22.4
Contractual maturities, Less than 1 year	11.2	22.4
Other Long-Term Liabilities [Member]
Derivative [Line Items]
Contractual maturities, Total	2.0	146.0
Contractual maturities, 1 - 3 years	2.0	25.7
Contractual maturities, 4 - 5 years		20.8
Contractual maturities, After 5 years		99.5
Risk Management Contract Liabilities [Member]
Derivative [Line Items]
Contractual maturities, Total	302.3	71.4
Contractual maturities, Less than 1 year	89.3	57.6
Contractual maturities, 1 - 3 years	113.3	11.1
Contractual maturities, 4 - 5 years	33.3	2.7
Contractual maturities, After 5 years	66.4
Current Portion Of Long-Term Debt [Member]
Derivative [Line Items]
Contractual maturities, Total	888.5	188.9
Contractual maturities, Less than 1 year	888.5	188.9
Long-Term Debt [Member]
Derivative [Line Items]
Contractual maturities, Total	8,014.8	3,450.9
Contractual maturities, 1 - 3 years	3,063.4	1,009.1
Contractual maturities, 4 - 5 years	1,592.6	363.8
Contractual maturities, After 5 years	$ 3,358.8	$ 2,078.0

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REVENUE (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Contract with Customer, Asset, Net	$ 11.5
WGL Energy Systems [Member]
Contract with Customer, Asset, Net	47.3
Provision on assets held for sale	6.0
Contract with Customer, Liability	$ 2.2
Utilities [Member] | Gas Storage Services [Member]
Contract with Customer, Duration	1 year
Midstream [Member] | Minimum [Member] | Commodity Sales Contracts [Member]
Contract with Customer, Duration	1 year
Midstream [Member] | Maximum [Member] | Commodity Sales Contracts [Member]
Contract with Customer, Duration	5 years
Power [Member] | Commodity Sales Contracts [Member]
Contract with Customer, Duration	20 years

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REVENUE (Disaggregation of Revenue by Major Sources) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 3,123.8
Other sources of revenue	1,132.9
Total revenue	4,256.7	$ 2,556.2
Commodity Sales Contracts [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,162.7
Midstream Service Contracts [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	205.0
Gas Sales And Transportation Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,684.3
Storage Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	35.4
Other Product And Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	36.4
Revenue From Alternative Revenue Programs [Member]
Disaggregation of Revenue [Line Items]
Other sources of revenue	21.7
Leasing Revenue [Member]
Disaggregation of Revenue [Line Items]
Other sources of revenue	452.1
Risk Management And Trading Activities [Member]
Disaggregation of Revenue [Line Items]
Other sources of revenue	644.2
Risk Management And Trading Activities [Member] | GAIL [Member]
Disaggregation of Revenue [Line Items]
Total revenue	$ 264.2
Contract with Customer, Duration	20 years
Other Sources Of Revenue [Member]
Disaggregation of Revenue [Line Items]
Other sources of revenue	$ 14.9
Utilities [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,730.4
Other sources of revenue	22.2
Total revenue	1,752.6
Utilities [Member] | Gas Sales And Transportation Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,684.3
Utilities [Member] | Storage Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	35.4
Utilities [Member] | Other Product And Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	10.7
Utilities [Member] | Revenue From Alternative Revenue Programs [Member]
Disaggregation of Revenue [Line Items]
Other sources of revenue	21.7
Utilities [Member] | Leasing Revenue [Member]
Disaggregation of Revenue [Line Items]
Other sources of revenue	0.6
Utilities [Member] | Risk Management And Trading Activities [Member]
Disaggregation of Revenue [Line Items]
Other sources of revenue	1.0
Utilities [Member] | Other Sources Of Revenue [Member]
Disaggregation of Revenue [Line Items]
Other sources of revenue	(1.1)
Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	870.8
Other sources of revenue	473.8
Total revenue	1,344.6
Midstream [Member] | Commodity Sales Contracts [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	665.2
Midstream [Member] | Midstream Service Contracts [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	205.0
Midstream [Member] | Other Product And Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0.6
Midstream [Member] | Leasing Revenue [Member]
Disaggregation of Revenue [Line Items]
Other sources of revenue	96.6
Midstream [Member] | Risk Management And Trading Activities [Member]
Disaggregation of Revenue [Line Items]
Other sources of revenue	377.6
Midstream [Member] | Other Sources Of Revenue [Member]
Disaggregation of Revenue [Line Items]
Other sources of revenue	(0.4)
Power [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	522.6
Other sources of revenue	639.4
Total revenue	1,162.0
Power [Member] | Commodity Sales Contracts [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 497.5
Contract with Customer, Duration	20 years
Power [Member] | Other Product And Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 25.1
Power [Member] | Leasing Revenue [Member]
Disaggregation of Revenue [Line Items]
Other sources of revenue	354.9
Power [Member] | Risk Management And Trading Activities [Member]
Disaggregation of Revenue [Line Items]
Other sources of revenue	268.5
Power [Member] | Other Sources Of Revenue [Member]
Disaggregation of Revenue [Line Items]
Other sources of revenue	16.0
Corporate [Member]
Disaggregation of Revenue [Line Items]
Other sources of revenue	(2.5)
Total revenue	(2.5)
Corporate [Member] | Risk Management And Trading Activities [Member]
Disaggregation of Revenue [Line Items]
Other sources of revenue	(2.9)
Corporate [Member] | Other Sources Of Revenue [Member]
Disaggregation of Revenue [Line Items]
Other sources of revenue	$ 0.4

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REVENUE (Schedule of Estimated Revenue Related to Performance Obligations) (Details) $ in Millions	Dec. 31, 2018 CAD ($)
Revenue, Remaining Performance Obligation, Amount	$ 934.3
2019 [Member]
Revenue, Remaining Performance Obligation, Amount	126.5
2020 [Member]
Revenue, Remaining Performance Obligation, Amount	103.1
2021 [Member]
Revenue, Remaining Performance Obligation, Amount	70.8
2022 [Member]
Revenue, Remaining Performance Obligation, Amount	69.6
2023 [Member]
Revenue, Remaining Performance Obligation, Amount	65.7
>2023 [Member]
Revenue, Remaining Performance Obligation, Amount	498.6
Midstream Service Contracts [Member]
Revenue, Remaining Performance Obligation, Amount	392.5
Midstream Service Contracts [Member] | 2019 [Member]
Revenue, Remaining Performance Obligation, Amount	52.2
Midstream Service Contracts [Member] | 2020 [Member]
Revenue, Remaining Performance Obligation, Amount	55.7
Midstream Service Contracts [Member] | 2021 [Member]
Revenue, Remaining Performance Obligation, Amount	32.3
Midstream Service Contracts [Member] | 2022 [Member]
Revenue, Remaining Performance Obligation, Amount	31.9
Midstream Service Contracts [Member] | 2023 [Member]
Revenue, Remaining Performance Obligation, Amount	28.0
Midstream Service Contracts [Member] | >2023 [Member]
Revenue, Remaining Performance Obligation, Amount	192.4
Gas Sales And Transportation Services [Member]
Revenue, Remaining Performance Obligation, Amount	6.2
Gas Sales And Transportation Services [Member] | 2019 [Member]
Revenue, Remaining Performance Obligation, Amount	0.6
Gas Sales And Transportation Services [Member] | 2020 [Member]
Revenue, Remaining Performance Obligation, Amount	0.6
Gas Sales And Transportation Services [Member] | 2021 [Member]
Revenue, Remaining Performance Obligation, Amount	0.6
Gas Sales And Transportation Services [Member] | 2022 [Member]
Revenue, Remaining Performance Obligation, Amount	0.6
Gas Sales And Transportation Services [Member] | 2023 [Member]
Revenue, Remaining Performance Obligation, Amount	0.6
Gas Sales And Transportation Services [Member] | >2023 [Member]
Revenue, Remaining Performance Obligation, Amount	3.2
Storage Services [Member]
Revenue, Remaining Performance Obligation, Amount	481.7
Storage Services [Member] | 2019 [Member]
Revenue, Remaining Performance Obligation, Amount	36.7
Storage Services [Member] | 2020 [Member]
Revenue, Remaining Performance Obligation, Amount	36.3
Storage Services [Member] | 2021 [Member]
Revenue, Remaining Performance Obligation, Amount	36.3
Storage Services [Member] | 2022 [Member]
Revenue, Remaining Performance Obligation, Amount	36.3
Storage Services [Member] | 2023 [Member]
Revenue, Remaining Performance Obligation, Amount	36.3
Storage Services [Member] | >2023 [Member]
Revenue, Remaining Performance Obligation, Amount	299.8
Other [Member]
Revenue, Remaining Performance Obligation, Amount	53.9
Other [Member] | 2019 [Member]
Revenue, Remaining Performance Obligation, Amount	37.0
Other [Member] | 2020 [Member]
Revenue, Remaining Performance Obligation, Amount	10.5
Other [Member] | 2021 [Member]
Revenue, Remaining Performance Obligation, Amount	1.6
Other [Member] | 2022 [Member]
Revenue, Remaining Performance Obligation, Amount	0.8
Other [Member] | 2023 [Member]
Revenue, Remaining Performance Obligation, Amount	0.8
Other [Member] | >2023 [Member]
Revenue, Remaining Performance Obligation, Amount	$ 3.2

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SHAREHOLDERS' EQUITY (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common shares outstanding	275,200,000	175,300,000
Proceeds from issuance of shares	$ 2,633.7	$ 236.3
Dividend reinvestment discount rate	3.00%
Dividend reinvestment cash purchase price, percentage	101.00%
Average market price measurement period	10 days
Share Option Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares reserved for issuance	21,213,224
Unexpensed fair value of share option compensation cost	$ 3.7	1.3
Aggregate intrinsic value of options exercisable		6.0
Intrinsic value of options outstanding		6.0
Intrinsic value of options exercised	$ 0.3	1.4
Share Option Plan [Member] | Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Options term	6 years
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period	6 years
Share Option Plan [Member] | Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Options term	10 years
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period	10 years
Vesting period	4 years
Mid-Term Incentive Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation expense	$ 26.9	8.4
Mid-Term Incentive Plan [Member] | Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	36 months
Mid-Term Incentive Plan [Member] | Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	44 months
Mid-Term Incentive And Deferred Share Unit Plans [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Compensation expense	$ 16.6	$ 9.1
Common Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common shares outstanding	275,224,066	175,279,216	166,906,833
Cumulative Preferred Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Preferred stock authorized, percentage of voting rights	50.00%

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SHAREHOLDERS' EQUITY (Schedule of Common Shares Issued and Outstanding) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Class of Stock [Line Items]
Common Shares Issued and Outstanding, Beginning balance, Number of shares	175,300,000
Shares issued for cash on exercise of options, Number of shares	57,275	240,125
Common Shares Issued and Outstanding, Ending balance, Number of shares	275,200,000	175,300,000
Balance, beginning of year	$ 4,573.4
Balance at end of year	$ 7,019.6	$ 4,573.4
Common Stock [Member]
Class of Stock [Line Items]
Common Shares Issued and Outstanding, Beginning balance, Number of shares	175,279,216	166,906,833
Shares issued on conversion of subscription receipts, net of issuance costs, Number of shares	84,510,000
Shares issued for cash on exercise of options, Number of shares	57,275	240,125
Shares issued under DRIP, Number of shares	15,377,575	8,132,258
Common Shares Issued and Outstanding, Ending balance, Number of shares	275,224,066	175,279,216
Balance, beginning of year	$ 4,007.9	$ 3,773.4
Shares issued on conversion of subscription receipts, net of issuance costs, Amount	2,305.6
Shares issued for cash on exercise of options, Amount	1.3	6.5
Deferred taxes on share issuance cost, Amount	13.3	(8.3)
Shares issued under DRIP, Amount	325.8	236.3
Balance at end of year	$ 6,653.9	$ 4,007.9

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SHAREHOLDERS' EQUITY (Schedule of Preferred Shares Issued and Outstanding) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Class of Stock [Line Items]
Preferred Shares Issued and Outstanding, Amount	$ 7,019.6	$ 4,573.4
Fair value adjustment on WGL Acquisition (note 3)	$ 89.0
Cumulative Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Shares Issued and Outstanding, Number of shares	52,280,600	52,000,000
Preferred Shares Issued and Outstanding, Amount	$ 1,318.8	$ 1,277.7	$ 985.1
Fair value adjustment on WGL Acquisition (note 3)	4.1
Share issuance costs, net of taxes	$ (27.9)	$ (27.9)
Series A [Member] | Cumulative Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Shares Issued and Outstanding, Number of shares	5,511,220	5,511,220
Preferred Shares Issued and Outstanding, Amount	$ 137.8	$ 137.8
Series B [Member] | Cumulative Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Shares Issued and Outstanding, Number of shares	2,488,780	2,488,780
Preferred Shares Issued and Outstanding, Amount	$ 62.2	$ 62.2
Series C [Member] | Cumulative Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Shares Issued and Outstanding, Number of shares	8,000,000	8,000,000
Preferred Shares Issued and Outstanding, Amount	$ 205.6	$ 205.6
Series E [Member] | Cumulative Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Shares Issued and Outstanding, Number of shares	8,000,000	8,000,000
Preferred Shares Issued and Outstanding, Amount	$ 200.0	$ 200.0
Series G [Member] | Cumulative Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Shares Issued and Outstanding, Number of shares	8,000,000	8,000,000
Preferred Shares Issued and Outstanding, Amount	$ 200.0	$ 200.0
Series I [Member] | Cumulative Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Shares Issued and Outstanding, Number of shares	8,000,000	8,000,000
Preferred Shares Issued and Outstanding, Amount	$ 200.0	$ 200.0
Series K [Member] | Cumulative Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Shares Issued and Outstanding, Number of shares	12,000,000	12,000,000
Preferred Shares Issued and Outstanding, Amount	$ 300.0	$ 300.0
$4.80 Series [Member] | Cumulative Preferred Stock [Member] | Washington Gas [Member]
Class of Stock [Line Items]
Preferred Shares Issued and Outstanding, Number of shares	150,000
Preferred Shares Issued and Outstanding, Amount	$ 19.7
$4.25 Series [Member] | Cumulative Preferred Stock [Member] | Washington Gas [Member]
Class of Stock [Line Items]
Preferred Shares Issued and Outstanding, Number of shares	70,600
Preferred Shares Issued and Outstanding, Amount	$ 9.4
$5.00 Series [Member] | Cumulative Preferred Stock [Member] | Washington Gas [Member]
Class of Stock [Line Items]
Preferred Shares Issued and Outstanding, Number of shares	60,000
Preferred Shares Issued and Outstanding, Amount	$ 7.9

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SHAREHOLDERS' EQUITY (Summary of Cumulative Redeemable Preferred Shares) (Details) - 12 months ended Dec. 31, 2018	$ / shares shares	$ / shares $ / shares shares	$ / shares shares
Series A [Member]
Class of Stock [Line Items]
Current Yield	3.38%	3.38%
Annual dividend per share	$ 0.845
Redemption price per share	$ 25	$ 25
Series A [Member] | Five-Year Government Of Canada Bond [Member]
Class of Stock [Line Items]
Preferred stock dividend rate in addition to variable rate	2.66%	2.66%
Series B [Member]
Class of Stock [Line Items]
Redemption price per share	$ 25.50	$ 25.50
Floating quarterly dividend rate	$ 0.26938
Series B [Member] | 90-Day Government Of Canada Treasury Bill [Member]
Class of Stock [Line Items]
Preferred stock dividend rate in addition to variable rate	2.66%	2.66%
Series C [Member]
Class of Stock [Line Items]
Current Yield	5.29%	5.29%
Series C [Member] | United States Government Bond Yield [Member]
Class of Stock [Line Items]
Preferred stock dividend rate in addition to variable rate	3.58%	3.58%
Series C, Redemption Price US$25, Annual Dividend US$1.3225 [Member]
Class of Stock [Line Items]
Annual dividend per share		$ 1.3225
Redemption price per share			$ 25
Series E [Member]
Class of Stock [Line Items]
Current Yield	5.393%	5.393%
Annual dividend per share	$ 1.34825
Redemption price per share	$ 25	$ 25
Series E [Member] | Five-Year Government Of Canada Bond [Member]
Class of Stock [Line Items]
Preferred stock dividend rate in addition to variable rate	3.17%	3.17%
Series G [Member]
Class of Stock [Line Items]
Current Yield	4.75%	4.75%
Annual dividend per share	$ 1.1875
Redemption price per share	$ 25	$ 25
Series G [Member] | Five-Year Government Of Canada Bond [Member]
Class of Stock [Line Items]
Preferred stock dividend rate in addition to variable rate	3.06%	3.06%
Series I [Member]
Class of Stock [Line Items]
Current Yield	5.25%	5.25%
Annual dividend per share	$ 1.3125
Redemption price per share	$ 25	$ 25
Series I [Member] | Minimum [Member]
Class of Stock [Line Items]
Current Yield	5.25%	5.25%
Series I [Member] | Five-Year Government Of Canada Bond [Member]
Class of Stock [Line Items]
Preferred stock dividend rate in addition to variable rate	4.19%	4.19%
Series K [Member]
Class of Stock [Line Items]
Current Yield	5.00%	5.00%
Annual dividend per share	$ 1.25
Redemption price per share	$ 25	$ 25
Series K [Member] | Minimum [Member]
Class of Stock [Line Items]
Current Yield	5.00%	5.00%
Series K [Member] | Five-Year Government Of Canada Bond [Member]
Class of Stock [Line Items]
Preferred stock dividend rate in addition to variable rate	3.80%	3.80%
Series D [Member]
Class of Stock [Line Items]
Redemption price per share			$ 25.50
Shares authorized | shares	8,000,000	8,000,000	8,000,000
Series F [Member]
Class of Stock [Line Items]
Redemption price per share			$ 25.50
Shares authorized | shares	8,000,000	8,000,000	8,000,000
Series H [Member]
Class of Stock [Line Items]
Redemption price per share			$ 25.50
Shares authorized | shares	8,000,000	8,000,000	8,000,000
Series J [Member]
Class of Stock [Line Items]
Redemption price per share			$ 25.50
Shares authorized | shares	8,000,000	8,000,000	8,000,000
Series L [Member]
Class of Stock [Line Items]
Redemption price per share			$ 25.50
Shares authorized | shares	12,000,000	12,000,000	12,000,000
Washington Gas [Member] | $4.80 Series [Member]
Class of Stock [Line Items]
Current Yield	4.27%	4.27%
Annual dividend per share	$ 4.80
Redemption price per share	$ 101	$ 101
Washington Gas [Member] | $4.25 Series [Member]
Class of Stock [Line Items]
Current Yield	4.27%	4.27%
Annual dividend per share	$ 4.25
Redemption price per share	$ 105	$ 105
Washington Gas [Member] | $5.00 Series [Member]
Class of Stock [Line Items]
Current Yield	4.27%	4.27%
Annual dividend per share	$ 5.00
Redemption price per share	$ 102	$ 102

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SHAREHOLDERS' EQUITY (Summary of Share Option Activity) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
SHAREHOLDERS' EQUITY [Abstract]
Share options outstanding, beginning of year, Number of options	4,533,761	4,119,386
Granted, Number of options	2,811,460	848,000
Exercised, Number of options	(57,275)	(240,125)
Forfeited, Number of options	(878,013)	(193,500)
Expired, Number of options	(100,750)
Share options outstanding, end of year, Number of options	6,309,183	4,533,761
Share options exercisable, end of year, Number of options	2,897,723	3,326,197
Share options outstanding, beginning of year, Exercise price	$ 32.35	$ 32.39
Granted, Exercise price	16.69	30.80
Exercised, Exercise price	20.68	24.63
Forfeited, Exercise price	36.47	36.36
Expired, Exercise price	14.60
Share options outstanding, end of year, Exercise price	25.18	32.35
Share options exercisable, end of year, Exercise price	$ 32.01	$ 31.93

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SHAREHOLDERS' EQUITY (Summary of Employee Share Option Plan) (Details) - 12 months ended Dec. 31, 2018	$ / shares shares	$ / shares $ / shares shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Options outstanding, Number outstanding | shares	6,309,183	6,309,183
Options outstanding, Weighted average exercise price	$ 25.18	$ 25.18
Options outstanding, Weighted average remaining contractual life	4 years 3 months 4 days	4 years 3 months 4 days
Options exercisable, Number exercisable | shares	2,897,723	2,897,723
Options exercisable, Weighted average exercise price	$ 32.01	$ 32.01
Options exercisable, Weighted average remaining contractual life	2 years 9 months 7 days	2 years 9 months 7 days
$14.24 to $18.00 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Options outstanding, Exercise price range, Lower limit	$ 14.24
Options outstanding, Exercise price range, Upper limit	$ 18.00
Options outstanding, Number outstanding | shares	2,322,635	2,322,635
Options outstanding, Weighted average exercise price	$ 14.55	$ 14.55
Options outstanding, Weighted average remaining contractual life	5 years 10 months 28 days	5 years 10 months 28 days
Options exercisable, Number exercisable | shares	28,000	28,000
Options exercisable, Weighted average exercise price	$ 17.10	$ 17.10
Options exercisable, Weighted average remaining contractual life	1 year 3 months 29 days	1 year 3 months 29 days
$18.01 to $25.08 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Options outstanding, Exercise price range, Lower limit	$ 18.01
Options outstanding, Exercise price range, Upper limit	$ 25.08
Options outstanding, Number outstanding | shares	425,000	425,000
Options outstanding, Weighted average exercise price	$ 20.76	$ 20.76
Options outstanding, Weighted average remaining contractual life	1 year 9 months 29 days	1 year 9 months 29 days
Options exercisable, Number exercisable | shares	425,000	425,000
Options exercisable, Weighted average exercise price	$ 20.76	$ 20.76
Options exercisable, Weighted average remaining contractual life	1 year 9 months 29 days	1 year 9 months 29 days
$25.09 to $50.89 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Options outstanding, Exercise price range, Lower limit		$ 25.09
Options outstanding, Exercise price range, Upper limit		$ 50.89
Options outstanding, Number outstanding | shares	3,561,548	3,561,548
Options outstanding, Weighted average exercise price	$ 32.65	$ 32.65
Options outstanding, Weighted average remaining contractual life	3 years 5 months 23 days	3 years 5 months 23 days
Options exercisable, Number exercisable | shares	2,444,723	2,444,723
Options exercisable, Weighted average exercise price	$ 34.14	$ 34.14
Options exercisable, Weighted average remaining contractual life	2 years 11 months 12 days	2 years 11 months 12 days

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SHAREHOLDERS' EQUITY (Summary of Fair Value Options Granted) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
SHAREHOLDERS' EQUITY [Abstract]
Fair value per option ($)	$ 1.27	$ 1.91
Risk-free interest rate (%)	1.99%	1.31%
Expected life (years)	6 years	6 years
Expected volatility (%)	23.23%	21.05%
Annual dividend per share ($)	$ 1.18	$ 2.12

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SHAREHOLDERS' EQUITY (Schedule of MTIP and DSUP Activity) (Details) - shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
SHAREHOLDERS' EQUITY [Abstract]
Balance, beginning of year	564,549	364,839
Acquired	5,291,621
Granted	9,502,347	386,126
Additional units added by performance factor		24,301
Vested and paid out	(148,154)	(221,775)
Forfeited	(66,522)	(27,279)
Units in lieu of dividends	55,934	38,337
Balance, ending of year	15,199,775	564,549

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NET INCOME PER COMMON SHARE (Summary of Net Income per Common Share) (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
NET INCOME PER COMMON SHARE [Abstract]
Net income (loss) applicable to controlling interests	$ (435.1)	$ 91.6
Less: Preferred share dividends	(66.6)	(61.3)
Net income (loss) applicable to common shares	$ (501.7)	$ 30.3
Weighted average number of common shares outstanding	222.6	171.0
Dilutive equity instruments	0.1	0.3
Weighted average number of common shares outstanding - diluted	222.7	171.3
Basic net income (loss) per common share	$ (2.25)	$ 0.18
Diluted net income (loss) per common share	$ (2.25)	$ 0.18
Anti-dilutive share options excluded from diluted income per share	4.0	2.8

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OTHER INCOME (Schedule of Other Income (Loss)) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
OTHER INCOME [Abstract]
Losses from sale of assets	$ (10.6)	$ (2.7)
Other components of net benefit cost (note 2)	18.9
Interest income and other revenue	2.7	8.7
Gains (losses) on investments	(10.1)	3.6
Total other income (loss)	$ 0.9	$ 9.6

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OPERATING LEASES (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Operating Leased Assets [Line Items]
Property, plant and equipment	$ 10,929.6	$ 6,689.8
Operating Leases, Income Statement, Minimum Lease Revenue	285.0	290.8
Revenue from minimum lease payments	285.0	290.8
Revenue from contingent leases	167.1	175.6
Assets Leased to Others [Member]
Operating Leased Assets [Line Items]
Property, plant and equipment	$ 2,000.0	$ 3,000.0

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OPERATING LEASES (Schedule of Future Minimum Revenue from Operating Leases) (Details) $ in Millions	Dec. 31, 2018 CAD ($)
OPERATING LEASES [Abstract]
2019	$ 194.4
2020	155.3
2021	111.9
2022	112.0
2023	$ 104.2

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PENSION PLANS AND RETIREE BENEFITS (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Defined contribution plan cost recorded	$ 15.4	$ 8.4
Rabbi trust	$ 89.3
Year trend rate reaches maximum	2024
Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan assets investment objective period	3 years
Assumed initial healthcare cost trend rate	6.40%
Ultimate trend rate	2.10%
Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan assets investment objective period	5 years
Assumed initial healthcare cost trend rate	6.50%
Ultimate trend rate	5.00%
Fixed Income [Member] | Minimum [Member] | Canada [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset mix	45.00%
Fixed Income [Member] | Maximum [Member] | SEMCO [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset mix	33.00%
Fixed Income [Member] | Maximum [Member] | WGL Holdings [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset mix	55.00%
Fixed Income [Member] | Maximum [Member] | Canada [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset mix	55.00%

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PENSION PLANS AND RETIREE BENEFITS (Summary of Defined Benefit Plans) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Plan assets, Fair value, end of year	$ 2,159.1
Defined Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Accrued benefit obligation, Balance, beginning of year	469.4	$ 440.5
Plans disposed (note 4)	(132.1)
Actuarial loss (gain)	(68.5)	31.5
Current service cost	18.6	15.9
Member contributions		0.2
Interest cost	39.2	17.5
Benefits paid	(45.9)	(14.9)
Expenses paid	(0.9)	(1.1)
Plan combinations	1,312.4
Foreign exchange translation	77.4	(20.2)
Balance, end of year	1,669.6	469.4
Plan assets, Fair value, beginning of year	363.9	328.4
Plan disposed (note 4)	(102.1)
Actual return on plan assets	(55.0)	46.4
Employer contributions	11.0	21.1
Member contributions		0.2
Benefits paid	(45.9)	(14.9)
Expenses paid	(0.9)	(1.1)
Plan combinatinos	1,133.5
Foreign exchange translation	63.4	(16.2)
Plan assets, Fair value, end of year	1,367.9	363.9
Accrued benefit liability	(301.7)	(105.5)
Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Accrued benefit obligation, Balance, beginning of year	98.5	89.1
Plans disposed (note 4)	(13.6)
Actuarial loss (gain)	(33.9)	12.8
Current service cost	5.4	2.5
Member contributions	2.1
Interest cost	11.0	3.5
Benefits paid	(13.4)	(3.5)
Expenses paid	(0.1)	(0.1)
Plan combinations	382.9
Plan amendments	(0.4)
Plan settlements		(0.5)
Foreign exchange translation	21.4	(5.3)
Balance, end of year	459.9	98.5
Plan assets, Fair value, beginning of year	78.9	74.0
Plan disposed (note 4)	(8.1)
Actual return on plan assets	(37.2)	11.4
Employer contributions	2.5	1.8
Member contributions	2.1
Benefits paid	(13.4)	(3.5)
Expenses paid	(0.1)	(0.1)
Plan combinatinos	732.7
Foreign exchange translation	33.8	(4.7)
Plan assets, Fair value, end of year	791.2	78.9
Accrued benefit liability	331.3	(19.6)
Canada [Member] | Defined Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Accrued benefit obligation, Balance, beginning of year	165.6	150.0
Plans disposed (note 4)	(132.1)
Actuarial loss (gain)	(0.8)	8.3
Current service cost	2.4	7.9
Member contributions		0.2
Interest cost	1.2	5.8
Benefits paid	(2.7)	(6.3)
Expenses paid		(0.3)
Plan combinations	0.7
Balance, end of year	34.3	165.6
Plan assets, Fair value, beginning of year	115.2	101.5
Plan disposed (note 4)	(102.1)
Actual return on plan assets	(0.3)	8.5
Employer contributions	3.4	11.6
Member contributions		0.2
Benefits paid	(2.7)	(6.3)
Expenses paid		(0.3)
Plan combinatinos	0.3
Plan assets, Fair value, end of year	13.8	115.2
Accrued benefit liability	(20.5)	(50.4)
Canada [Member] | Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Accrued benefit obligation, Balance, beginning of year	15.8	16.4
Plans disposed (note 4)	(13.6)
Actuarial loss (gain)	(0.1)	(1.6)
Current service cost	0.1	0.7
Interest cost	0.1	0.6
Benefits paid		(0.3)
Plan amendments	(0.4)
Balance, end of year	1.9	15.8
Plan assets, Fair value, beginning of year	8.1	6.8
Plan disposed (note 4)	(8.1)
Actual return on plan assets		0.4
Employer contributions		1.2
Benefits paid		(0.3)
Plan assets, Fair value, end of year		8.1
Accrued benefit liability	(1.9)	(7.7)
United States [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan assets, Fair value, end of year	2,145.3
United States [Member] | Defined Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Accrued benefit obligation, Balance, beginning of year	303.8	290.5
Actuarial loss (gain)	(67.7)	23.2
Current service cost	16.2	8.0
Interest cost	38.0	11.7
Benefits paid	(43.2)	(8.6)
Expenses paid	(0.9)	(0.8)
Plan combinations	1,311.7
Foreign exchange translation	77.4	(20.2)
Balance, end of year	1,635.3	303.8
Plan assets, Fair value, beginning of year	248.7	226.9
Actual return on plan assets	(54.7)	37.9
Employer contributions	7.6	9.5
Benefits paid	(43.2)	(8.6)
Expenses paid	(0.9)	(0.8)
Plan combinatinos	1,133.2
Foreign exchange translation	63.4	(16.2)
Plan assets, Fair value, end of year	1,354.1	248.7
Accrued benefit liability	(281.2)	(55.1)
United States [Member] | Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Accrued benefit obligation, Balance, beginning of year	82.7	72.7
Actuarial loss (gain)	(33.8)	14.4
Current service cost	5.3	1.8
Member contributions	2.1
Interest cost	10.9	2.9
Benefits paid	(13.4)	(3.2)
Expenses paid	(0.1)	(0.1)
Plan combinations	382.9
Plan settlements		(0.5)
Foreign exchange translation	21.4	(5.3)
Balance, end of year	458.0	82.7
Plan assets, Fair value, beginning of year	70.8	67.2
Actual return on plan assets	(37.2)	11.0
Employer contributions	2.5	0.6
Member contributions	2.1
Benefits paid	(13.4)	(3.2)
Expenses paid	(0.1)	(0.1)
Plan combinatinos	732.7
Foreign exchange translation	33.8	(4.7)
Plan assets, Fair value, end of year	791.2	70.8
Accrued benefit liability	$ 333.2	$ (11.9)

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PENSION PLANS AND RETIREE BENEFITS (Schedule of Amount Included in the Consolidated Balance Sheets) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Prepaid post-retirement benefits	$ 341.4
Accounts payable and accrued liabilities	(27.6)	$ (0.6)
Future employee obligations	(284.2)	(124.5)
Total amounts included in Consolidated Balance Sheets	29.6	(125.1)
Defined Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Accounts payable and accrued liabilities	(27.6)	(0.6)
Future employee obligations	(273.9)	(104.9)
Total amounts included in Consolidated Balance Sheets	(301.5)	(105.5)
Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Prepaid post-retirement benefits	341.4
Future employee obligations	(10.3)	(19.6)
Total amounts included in Consolidated Balance Sheets	$ 331.1	$ (19.6)

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PENSION PLANS AND RETIREE BENEFITS (Schedule of Funded Status Based on Accumulated Benefit Obligation) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Canada [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ (32.9)	$ (143.9)
Fair value of plan assets	13.8	115.2
Funded status	(19.1)	(28.7)
United States [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	(1,525.6)	(274.2)
Fair value of plan assets	1,354.1	248.7
Funded status	$ (171.5)	$ (25.5)

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PENSION PLANS AND RETIREE BENEFITS (Summary of Amounts Recorded in Other Comprehensive Income (Loss)) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Past service cost	$ (0.5)	$ (0.4)
Net actuarial loss	(19.4)	(13.9)
Recognized in AOCI pre-tax	(19.9)	(14.3)
Increase (decrease) by the amount included in deferred tax liabilities	4.6	3.9
Net amount in AOCI after-tax	(15.3)	(10.4)
Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Past service cost	0.4
Net actuarial loss	(5.5)	(1.3)
Recognized in AOCI pre-tax	(5.1)	(1.3)
Increase (decrease) by the amount included in deferred tax liabilities	1.4	0.3
Net amount in AOCI after-tax	(3.7)	(1.0)
Canada [Member] | Defined Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Past service cost	(0.3)	(0.4)
Net actuarial loss	(8.7)	(13.9)
Recognized in AOCI pre-tax	(9.0)	(14.3)
Increase (decrease) by the amount included in deferred tax liabilities	2.4	4.0
Net amount in AOCI after-tax	(6.6)	(10.3)
Canada [Member] | Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Past service cost	0.4
Net actuarial loss	(0.5)	(1.3)
Recognized in AOCI pre-tax	(0.1)	(1.3)
Increase (decrease) by the amount included in deferred tax liabilities		0.3
Net amount in AOCI after-tax	(0.1)	(1.0)
United States [Member] | Defined Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Past service cost	(0.2)
Net actuarial loss	(10.7)
Recognized in AOCI pre-tax	(10.9)
Increase (decrease) by the amount included in deferred tax liabilities	2.2	(0.1)
Net amount in AOCI after-tax	(8.7)	$ (0.1)
United States [Member] | Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	(5.0)
Recognized in AOCI pre-tax	(5.0)
Increase (decrease) by the amount included in deferred tax liabilities	1.4
Net amount in AOCI after-tax	$ (3.6)

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PENSION PLANS AND RETIREE BENEFITS (Summary of Amounts Recorded in A Regulatory Asset (Liability)) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Prior service cost	$ 0.8	$ (1.2)
Net actuarial gain (loss)	188.2	(104.6)
Recognized in regulatory asset (liability)	189.0	(105.8)
Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Prior service cost	(110.2)	5.6
Net actuarial gain (loss)	(52.6)	(12.4)
Recognized in regulatory asset (liability)	(162.8)	(6.8)
Canada [Member] | Defined Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial gain (loss)		(30.6)
Recognized in regulatory asset (liability)		(30.6)
Canada [Member] | Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial gain (loss)		0.4
Recognized in regulatory asset (liability)		0.4
United States [Member] | Defined Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Prior service cost	0.8	(1.2)
Net actuarial gain (loss)	188.2	(74.0)
Recognized in regulatory asset (liability)	189.0	(75.2)
United States [Member] | Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Prior service cost	(110.2)	5.6
Net actuarial gain (loss)	(52.6)	(12.8)
Recognized in regulatory asset (liability)	$ (162.8)	$ (7.2)

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PENSION PLANS AND RETIREE BENEFITS (Summary of Amounts to be Amortized from AOCI in the Next Fiscal Year) (Details) $ in Millions	Dec. 31, 2018 CAD ($)
Defined Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Past service costs	$ 0.1
Actuarial losses	0.5
Total amounts to be amortized in the next fiscal year from AOCI	0.6
Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Past service costs	0.2
Actuarial losses
Total amounts to be amortized in the next fiscal year from AOCI	$ 0.2

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PENSION PLANS AND RETIREE BENEFITS (Schedule of Amounts in Regulatory Assets (Liabilities) to be Recognized over Next Fiscal Year) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 CAD ($)
Defined Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Prior service cost	$ 0.2
Actuarial losses	9.1
Total	9.3
Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Prior service cost	(21.3)
Actuarial losses	0.1
Total	$ (21.2)

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PENSION PLANS AND RETIREE BENEFITS (Schedule of Net Periodic Benefit Expense) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Settlement (gain) loss		$ (0.2)
Defined Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Current service cost	$ 18.6	15.9
Interest cost	39.2	17.5
Expected return on plan assets	(50.4)	(22.8)
Amortization of past service cost	0.1	0.2
Amortization of net actuarial loss	0.6	0.7
Amortization of regulatory assets	7.8	7.8
Net benefit cost (income) recognized	15.9	19.3
Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Current service cost	5.4	2.5
Interest cost	11.0	3.5
Expected return on plan assets	(21.6)	(4.9)
Settlement (gain) loss		0.2
Amortization of regulatory assets	(11.1)	(0.2)
Net benefit cost (income) recognized	(16.3)	1.1
Canada [Member] | Defined Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Current service cost	2.4	7.9
Interest cost	1.2	5.8
Expected return on plan assets	(0.5)	(5.9)
Amortization of past service cost	0.1	0.2
Amortization of net actuarial loss	0.6	0.7
Amortization of regulatory assets		1.3
Net benefit cost (income) recognized	3.8	10.0
Canada [Member] | Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Current service cost	0.1	0.7
Interest cost	0.1	0.6
Expected return on plan assets		(0.2)
Amortization of regulatory assets		0.1
Net benefit cost (income) recognized	0.2	1.2
United States [Member] | Defined Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Current service cost	16.2	8.0
Interest cost	38.0	11.7
Expected return on plan assets	(49.9)	(16.9)
Amortization of regulatory assets	7.8	6.5
Net benefit cost (income) recognized	12.1	9.3
United States [Member] | Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Current service cost	5.3	1.8
Interest cost	10.9	2.9
Expected return on plan assets	(21.6)	(4.7)
Settlement (gain) loss		0.2
Amortization of regulatory assets	(11.1)	(0.3)
Net benefit cost (income) recognized	$ (16.5)	$ (0.1)

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PENSION PLANS AND RETIREE BENEFITS (Schedule of Collective Investment Mixes for Plan Assets) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan investment	$ 2,159.2
Net payable	(0.1)
Fair value of Plan Assets	$ 2,159.1
Percentage of Plan Assets	100.00%
Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 1,165.7
Percentage of Plan Assets	54.00%
Cash and Short-Term Equivalents [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 8.0
Percentage of Plan Assets	0.40%
Equities [Member] | Domestic [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 5.8
Percentage of Plan Assets	0.30%
Equities [Member] | Foreign [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 275.3
Percentage of Plan Assets	12.80%
Fixed Income [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 855.6
Percentage of Plan Assets	39.60%
Real Estate [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 0.8
Derivative [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 9.3
Percentage of Plan Assets	0.40%
Defined Benefit Plan, Other [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 10.9
Percentage of Plan Assets	0.50%
Level 1 [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 391.2
Level 1 [Member] | Cash and Short-Term Equivalents [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	8.0
Level 1 [Member] | Equities [Member] | Domestic [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	5.8
Level 1 [Member] | Equities [Member] | Foreign [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	272.7
Level 1 [Member] | Fixed Income [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	104.7
Level 2 [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	774.5
Level 2 [Member] | Equities [Member] | Foreign [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	2.6
Level 2 [Member] | Fixed Income [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	750.9
Level 2 [Member] | Derivative [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	9.3
Level 2 [Member] | Defined Benefit Plan, Other [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	11.7
Fair Value Measured at NAV [Member] | Commingled Funds And Pooled Separate Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 945.3
Percentage of Plan Assets	43.80%
Fair Value Measured at NAV [Member] | Private Equity/Limited Partnership [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 48.2
Percentage of Plan Assets	2.20%
Canada [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 13.8
Percentage of Plan Assets	100.00%
Canada [Member] | Cash and Short-Term Equivalents [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 1.7
Percentage of Plan Assets	12.30%
Canada [Member] | Equities [Member] | Domestic [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 3.7
Percentage of Plan Assets	26.80%
Canada [Member] | Equities [Member] | Foreign [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 2.1
Percentage of Plan Assets	15.20%
Canada [Member] | Fixed Income [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 5.5
Percentage of Plan Assets	39.90%
Canada [Member] | Real Estate [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 0.8
Percentage of Plan Assets	5.80%
Canada [Member] | Level 1 [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 13.0
Canada [Member] | Level 1 [Member] | Cash and Short-Term Equivalents [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	1.7
Canada [Member] | Level 1 [Member] | Equities [Member] | Domestic [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	3.7
Canada [Member] | Level 1 [Member] | Equities [Member] | Foreign [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	2.1
Canada [Member] | Level 1 [Member] | Fixed Income [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	5.5
Canada [Member] | Level 2 [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	0.8
Canada [Member] | Level 2 [Member] | Real Estate [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	0.8
United States [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan investment	2,145.4
Fair value of Plan Assets	$ 2,145.3
Percentage of Plan Assets	100.00%
United States [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 1,151.9
Percentage of Plan Assets	53.60%
United States [Member] | Cash and Short-Term Equivalents [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 6.3
Percentage of Plan Assets	0.30%
United States [Member] | Equities [Member] | Domestic [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 2.1
Percentage of Plan Assets	0.10%
United States [Member] | Equities [Member] | Foreign [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 273.2
Percentage of Plan Assets	12.70%
United States [Member] | Fixed Income [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 850.1
Percentage of Plan Assets	39.60%
United States [Member] | Derivative [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 9.3
Percentage of Plan Assets	0.40%
United States [Member] | Defined Benefit Plan, Other [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 10.9
Percentage of Plan Assets	0.50%
United States [Member] | Level 1 [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 378.2
United States [Member] | Level 1 [Member] | Cash and Short-Term Equivalents [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	6.3
United States [Member] | Level 1 [Member] | Equities [Member] | Domestic [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	2.1
United States [Member] | Level 1 [Member] | Equities [Member] | Foreign [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	270.6
United States [Member] | Level 1 [Member] | Fixed Income [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	99.2
United States [Member] | Level 2 [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	773.7
United States [Member] | Level 2 [Member] | Equities [Member] | Foreign [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	2.6
United States [Member] | Level 2 [Member] | Fixed Income [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	750.9
United States [Member] | Level 2 [Member] | Derivative [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	9.3
United States [Member] | Level 2 [Member] | Defined Benefit Plan, Other [Member] | Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	10.9
United States [Member] | Fair Value Measured at NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Net payable	(0.1)
United States [Member] | Fair Value Measured at NAV [Member] | Commingled Funds And Pooled Separate Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 945.3
Percentage of Plan Assets	44.20%
United States [Member] | Fair Value Measured at NAV [Member] | Private Equity/Limited Partnership [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 48.2
Percentage of Plan Assets	2.20%
Defined Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 1,367.9	$ 363.9	$ 328.4
Defined Benefit Plans [Member] | Canada [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	13.8	115.2	101.5
Defined Benefit Plans [Member] | United States [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 1,354.1	248.7	226.9
Defined Benefit Plans [Member] | WGL Holdings [Member] | Money Market Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset mix	1.00%
Defined Benefit Plans [Member] | WGL Holdings [Member] | United States [Member] | Commingled Funds And Pooled Separate Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset mix	89.00%
Defined Benefit Plans [Member] | WGL Holdings [Member] | United States [Member] | Income Producing Properties [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset mix	10.00%
Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 791.2	78.9	74.0
Post-Retirement Benefits [Member] | Canada [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets		8.1	6.8
Post-Retirement Benefits [Member] | United States [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of Plan Assets	$ 791.2	$ 70.8	$ 67.2
Post-Retirement Benefits [Member] | WGL Holdings [Member] | Corporate Bond Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset mix	26.00%
Post-Retirement Benefits [Member] | WGL Holdings [Member] | United States [Member] | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset mix	20.00%
Post-Retirement Benefits [Member] | WGL Holdings [Member] | United States [Member] | Common Stock, Large Cap [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset mix	54.00%

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PENSION PLANS AND RETIREE BENEFITS (Schedule of Significant Actuarial Assumptions Used in Measuring Net Benefit Plan Costs and Benefit Obligations) (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plans [Member]
Significant actuarial assumptions used in measuring net benefit plan costs
Expected long-term rate of return on plan assets	7.60%
Average remaining service life of active employees	9 years 7 months 6 days	12 years 8 months 12 days
Defined Benefit Plans [Member] | Minimum [Member]
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate	3.25%	2.65%
Expected long-term rate of return on plan assets	3.20%	6.18%
Rate of compensation increase	2.75%	2.75%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate	3.60%	2.80%
Rate of compensation increase	2.75%	2.75%
Defined Benefit Plans [Member] | Maximum [Member]
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate	4.30%	4.20%
Expected long-term rate of return on plan assets		7.30%
Rate of compensation increase	4.10%	4.00%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate	4.40%	3.70%
Rate of compensation increase	4.10%	4.00%
Post-Retirement Benefits [Member]
Significant actuarial assumptions used in measuring net benefit plan costs
Rate of compensation increase	4.10%	3.25%
Average remaining service life of active employees	14 years 1 month 6 days	13 years 6 months
Significant actuarial assumptions used in measuring benefit obligations
Rate of compensation increase	4.10%	3.25%
Post-Retirement Benefits [Member] | Minimum [Member]
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate	3.60%
Expected long-term rate of return on plan assets	3.75%	3.10%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate	3.90%	3.60%
Post-Retirement Benefits [Member] | Maximum [Member]
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate	4.30%
Expected long-term rate of return on plan assets	7.60%	7.30%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate	4.50%	3.70%

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PENSION PLANS AND RETIREE BENEFITS (Summary of Assumed Health Care Cost Trend Rates) (Details)	12 Months Ended
	Dec. 31, 2018 CAD ($)
PENSION PLANS AND RETIREE BENEFITS [Abstract]
Increase, Service and interest costs	$ 1,700,000.0
Decrease, Service and interest costs	(1,300,000.0)
Increase, Accrued benefit obligations	19,800,000.0
Decrease, Accrued benefit obligation	$ (16,000,000.0)

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PENSION PLANS AND RETIREE BENEFITS (Schedule of Expected Cash Flows for Defined Benefit Pension and Other Post-Retirement Plans) (Details) $ in Millions	Dec. 31, 2018 CAD ($)
Defined Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected employer contributions, 2019	$ 41.4
Expected benefit payments, 2019	109.8
Expected benefit payments, 2020	92.2
Expected benefit payments, 2021	95.3
Expected benefit payments, 2022	101.0
Expected benefit payments, 2023	99.4
Expected benefit payments, 2024 - 2028	521.9
Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected employer contributions, 2019	0.1
Expected benefit payments, 2019	25.3
Expected benefit payments, 2020	24.6
Expected benefit payments, 2021	25.0
Expected benefit payments, 2022	25.4
Expected benefit payments, 2023	25.5
Expected benefit payments, 2024 - 2028	$ 130.9

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COMMITMENTS, CONTINGENCIES AND GUARANTEES (Narrative) (Details) $ in Millions, $ in Millions		12 Months Ended
	Apr. 04, 2018 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2018 CAD ($)
Commitments, Contingencies And Guaranteed [Line Items]
Guarantee obligations		$ 0.0
Regulatory Commitments		140.0
Regulatory Commitments Paid		111.0
Loss on Contracts		40.0
Loss Contingency, Damages Sought, Value	$ 100.0
Loss Contingency Accrual			$ 0.0
Damage Prevention Trainers, Investment [Member]
Commitments, Contingencies And Guaranteed [Line Items]
Regulatory Commitments		$ 70.0
Regulatory Commitments Term		10 years
Leak Mitigation [Member]
Commitments, Contingencies And Guaranteed [Line Items]
Regulatory Commitments		$ 8.0

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COMMITMENTS, CONTINGENCIES AND GUARANTEES (Summary of Future Payment Commitments) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 CAD ($) item	Dec. 31, 2017
Other Commitments [Line Items]
Operating leases, 2019	$ 23.9
Operating leases, 2020	30.9
Operating leases, 2021	29.4
Operating leases, 2022	28.0
Operating leases, 2023	25.8
Operating leases, 2024 and beyond	164.8
Operating leases	302.8
Commitments, 2019	4,804.6
Commitments, 2020	4,285.9
Commitments, 2021	3,683.4
Commitments, 2022	3,426.6
Commitments, 2023	3,197.5
Commitments, 2024 and beyond	35,350.3
Commitments	54,748.3
Capital Projects [Member]
Other Commitments [Line Items]
Other commitments, 2019	119.2
Other commitments, 2020
Other commitments, 2021
Other commitments, 2022
Other commitments, 2023
Other commitments, 2024 and beyond
Other commitments	119.2
Environmental [Member]
Other Commitments [Line Items]
Other commitments, 2019	6.1
Other commitments, 2020	4.7
Other commitments, 2021	3.0
Other commitments, 2022	0.5
Other commitments, 2023	0.4
Other commitments, 2024 and beyond	0.5
Other commitments	15.2
Merger Commitments [Member]
Other Commitments [Line Items]
Other commitments, 2019	29.3
Other commitments, 2020	30.8
Other commitments, 2021	22.8
Other commitments, 2022	19.2
Other commitments, 2023	19.2
Other commitments, 2024 and beyond	62.1
Other commitments	183.4
Natural Gas [Member]
Other Commitments [Line Items]
Purchase obligations, 2019	3,157.1
Purchase obligations, 2020	2,940.5
Purchase obligations, 2021	2,639.3
Purchase obligations, 2022	2,527.4
Purchase obligations, 2023	2,349.9
Purchase obligations, 2024 and beyond	30,309.2
Purchase obligations	43,923.4
Electricity Purchase [Member]
Other Commitments [Line Items]
Purchase obligations, 2019	533.1
Purchase obligations, 2020	368.6
Purchase obligations, 2021	139.2
Purchase obligations, 2022	38.6
Purchase obligations, 2023	5.7
Purchase obligations, 2024 and beyond	0.4
Purchase obligations	1,085.6
Service Agreements [Member]
Other Commitments [Line Items]
Purchase obligations, 2019	74.3
Purchase obligations, 2020	48.2
Purchase obligations, 2021	30.9
Purchase obligations, 2022	17.3
Purchase obligations, 2023	14.8
Purchase obligations, 2024 and beyond	168.0
Purchase obligations	$ 353.5
Service agreement term, (EOH/CT) | item	124,000
Service agreement term	25 years	12 years
Service agreement payable	$ 190.9
Service agreement payable in five years	$ 59.6
Service agreement payment period	16 years
Contract Fees	$ 60.1
Storage Services [Member]
Other Commitments [Line Items]
Purchase obligations, 2019	861.6
Purchase obligations, 2020	862.2
Purchase obligations, 2021	818.8
Purchase obligations, 2022	795.6
Purchase obligations, 2023	781.7
Purchase obligations, 2024 and beyond	4,645.3
Purchase obligations	8,765.2
Electricity, Renewable Energy Credits [Member]
Other Commitments [Line Items]
Purchase obligations	$ 44.1

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RELATED PARTY TRANSACTIONS (Summary of Related Party Amounts Included in Balance Sheets) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Due from related parties, Accounts receivable	$ 60.8	$ 0.8
Due from related parties, Long-term investments and other assets	45.0	75.0
Due from related parties	105.8	75.8
Due to related parties, Accounts payable	6.3	3.2
Due to related parties, Risk management liabilities - current	0.9
Due to related parties	7.2	3.2
Petrogas [Member] | AltaGas [Member]
Related Party Transaction [Line Items]
Due from related parties, Long-term investments and other assets	45.0	$ 75.0
Credit facility maximum borrowing capacity	100.0
Committed amount	$ 50.0
Maturity date	Jun. 27, 2021

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RELATED PARTY TRANSACTIONS (Schedule of Related Party Transactions) (Details) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Revenue	[1]	$ 68.4	$ 15.0
Cost of sales	[2]	(4.2)	(6.5)
Operating and administrative expenses	[3]	1.3
Other income	[4]	9.2	4.4
Unrealized Loss On Foreign Exchange Hedge With ACI [Member]
Related Party Transaction [Line Items]
Revenue		$ 0.2

[1] Year ended December 3120182017Revenue (a)$ 68.4 $ 15.0 Cost of sales (b)$ (4.2)$ (6.5)Operating and administrative expenses (c)$ 1.3 $ -Other income (d)$ 9.2 $ 4.4 In the ordinary course of business, AltaGas sold natural gas and natural gas liquids to a joint venture and ACI. In addition, subsequent to the IPO of ACI, AltaGas is providing certain day-to-day services to ACI under a Transition Services Agreement on a cost recovery basis. The Transition Services Agreement will operate until June 30, 2020, subject to earlier termination in certain circumstances, and is extendable by mutual agreement of the parties. Revenue also includes an unrealized loss on a foreign exchange hedge with ACI of $0.2 million in 2018 (2017 - $nil).

[2] In the ordinary course of business, AltaGas obtained natural gas storage services from a joint venture as well as incurred costs related to the sale of natural gas liquids to affiliates.

[3] Administrative costs recovered from joint ventures. In 2017, amount was offset by the expense associated with the forgiveness of a loan to an executive.

[4] Interest income from loans to Petrogas (secured loan facility) and loans to ACI. Subsequent to the IPO of ACI, AltaGas provided certain loans to ACI for a portion of the year. Loans to ACI were fully repaid by December 31, 2018.

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SUPPLEMENTAL CASH FLOW INFORMATION (Schedule of Changes in Operating Assets and Liabilities) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
SUPPLEMENTAL CASH FLOW INFORMATION [Abstract]
Accounts receivable	$ (526.9)	$ (55.6)
Inventory	(100.8)	4.7
Other current assets	12.5	7.0
Regulatory assets (current)	(15.8)	(0.2)
Accounts payable and accrued liabilities	237.9	85.4
Customer deposits	(13.3)	(2.8)
Regulatory liabilities (current)	69.2	(4.8)
Other current liabilities	(5.9)	13.0
Other operating assets and liabilities	(143.4)	(44.8)
Changes in operating assets and liabilities	$ (486.5)	$ 1.9

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SUPPLEMENTAL CASH FLOW INFORMATION (Schedule of Supplemental Cash Payments) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
SUPPLEMENTAL CASH FLOW INFORMATION [Abstract]
Interest paid (net of capitalized interest)	$ 288.9	$ 151.1
Income taxes paid	$ 36.9	$ 36.3

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SUPPLEMENTAL CASH FLOW INFORMATION (Reconciliation of Cash and Restricted Cash Balances) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
SUPPLEMENTAL CASH FLOW INFORMATION [Abstract]
Cash and cash equivalents	$ 101.6	$ 27.3
Restricted cash holdings from customers - current	4.1	8.9
Restricted cash holdings from customers - non-current	6.1	7.5
Restricted Cash Included In Prepaid Expesnes And Other Current Assets	27.6
Restricted Cash Included In Long-Term Investments And Other Assets	61.7
Cash, cash equivalents and restricted cash per consolidated statement of cash flow	201.1	$ 43.7	$ 34.1
Restricted cash acquired	$ 81.0

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SEGMENTED INFORMATION (Narrative) (Details)	12 Months Ended
	Dec. 31, 2018 segment
SEGMENTED INFORMATION [Abstract]
Number of reporting segments	4

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SEGMENTED INFORMATION (Reconciliation Of Segment Revenue) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Revenues	$ 4,256.7	$ 2,556.2
Operating Segments [Member]
Revenues	4,369.2
Intersegment Eliminations [Member]
Revenues	(112.5)
Utilities [Member]
Revenues	1,752.6
Utilities [Member] | Operating Segments [Member]
Revenues	1,765.6
Utilities [Member] | Intersegment Eliminations [Member]
Revenues	(13.0)
Midstream [Member]
Revenues	1,344.6
Midstream [Member] | Operating Segments [Member]
Revenues	1,435.0
Midstream [Member] | Intersegment Eliminations [Member]
Revenues	(90.4)
Power [Member]
Revenues	1,162.0
Power [Member] | Operating Segments [Member]
Revenues	1,171.0
Power [Member] | Intersegment Eliminations [Member]
Revenues	(9.0)
Corporate [Member]
Revenues	(2.5)
Corporate [Member] | Operating Segments [Member]
Revenues	(2.4)
Corporate [Member] | Intersegment Eliminations [Member]
Revenues	$ (0.1)

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SEGMENTED INFOMRATION (Schedule of Geographic Information) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Revenues	$ 4,256.7	$ 2,556.2
Property, plant and equipment	10,929.6	6,689.8
Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues	4,179.8	2,618.7
Canada [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment	2,348.2	4,320.5
Canada [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues	1,626.8	1,508.8
United States [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment	8,581.4	2,369.3
United States [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues	$ 2,553.0	$ 1,109.9

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SEGMENTED INFORMATION (Schedule of Segment Composition) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Revenues	$ 4,256.7	$ 2,556.2
Cost of sales	(2,455.3)	(1,357.1)
Operating and administrative	(1,129.0)	(572.2)
Accretion expenses	(10.9)	(10.9)
Depreciation and amortization	(394.0)	(282.4)
Provisions on assets	(728.7)	(139.6)
Income from equity investments (note 13)	47.9	31.4
Other income (loss)	0.9	9.6
Foreign exchange gains	4.5	1.7
Interest expense	(309.0)	(170.3)
Income (loss) before income taxes	(716.9)	66.4
Net additions (reductions) to property, plant and equipment	572.5	387.6
Net additions (reductions) to intangible assets	45.7	20.3
Corporate [Member]
Segment Reporting Information [Line Items]
Revenues	(2.4)	(58.4)
Operating and administrative	(50.6)	(97.5)
Depreciation and amortization	(13.3)	(14.0)
Other income (loss)	2.0	6.3
Foreign exchange gains	4.8	1.5
Interest expense	(185.6)	(170.3)
Income (loss) before income taxes	(245.1)	(332.4)
Net additions (reductions) to property, plant and equipment	4.0	1.5
Net additions (reductions) to intangible assets	6.7	2.2
Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues	4,179.8	2,618.7
Operating Segments [Member] | Midstream [Member]
Segment Reporting Information [Line Items]
Revenues	1,435.0	1,008.0
Cost of sales	(976.4)	(647.0)
Operating and administrative	(201.7)	(165.0)
Accretion expenses	(4.0)	(3.9)
Depreciation and amortization	(84.4)	(68.6)
Provisions on assets	(153.7)	(6.6)
Income from equity investments (note 13)	51.1	22.0
Other income (loss)	0.7	(0.9)
Foreign exchange gains	(0.2)	0.2
Interest expense	(10.6)
Income (loss) before income taxes	55.8	138.2
Net additions (reductions) to property, plant and equipment	383.4	245.3
Net additions (reductions) to intangible assets	4.7	2.8
Operating Segments [Member] | Power [Member]
Segment Reporting Information [Line Items]
Revenues	1,171.0	631.7
Cost of sales	(743.7)	(242.8)
Operating and administrative	(159.1)	(93.1)
Accretion expenses	(6.8)	(6.9)
Depreciation and amortization	(130.5)	(118.0)
Provisions on assets	(381.3)	(133.0)
Income from equity investments (note 13)	(10.4)	6.8
Other income (loss)	(5.9)	0.8
Foreign exchange gains	(0.1)
Interest expense	(8.9)
Income (loss) before income taxes	(275.7)	45.5
Net additions (reductions) to property, plant and equipment	(321.9)	16.5
Net additions (reductions) to intangible assets	12.5	13.2
Operating Segments [Member] | Utilities [Member]
Segment Reporting Information [Line Items]
Revenues	1,765.6	1,126.7
Cost of sales	(838.3)	(610.1)
Operating and administrative	(727.4)	(226.1)
Accretion expenses	(0.1)	(0.1)
Depreciation and amortization	(165.8)	(81.8)
Provisions on assets	(193.7)
Income from equity investments (note 13)	7.2	2.6
Other income (loss)	4.5	3.9
Interest expense	(103.9)
Income (loss) before income taxes	(251.9)	215.1
Net additions (reductions) to property, plant and equipment	507.0	124.3
Net additions (reductions) to intangible assets	21.8	2.1
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(112.5)	(151.8)
Cost of sales	103.1	142.8
Operating and administrative	9.8	9.5
Other income (loss)	$ (0.4)	$ (0.5)

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SEGMENTED INFORMATION (Schedule of Goodwilll and Total Assets by Segment) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Goodwill	$ 4,068.2	$ 817.3	$ 856.0
Segmented assets	23,487.7	10,032.2
Corporate [Member]
Segment Reporting Information [Line Items]
Segmented assets	282.9	282.7
Operating Segments [Member] | Midstream [Member]
Segment Reporting Information [Line Items]
Goodwill	426.4	152.6
Segmented assets	6,398.8	3,096.8
Operating Segments [Member] | Power [Member]
Segment Reporting Information [Line Items]
Goodwill	191.0
Segmented assets	3,814.7	3,192.5
Operating Segments [Member] | Utilities [Member]
Segment Reporting Information [Line Items]
Goodwill	3,450.8	664.7
Segmented assets	$ 12,991.3	$ 3,460.2

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SUBSEQUENT EVENTS (Details) $ in Millions	Jan. 31, 2019 CAD ($)
Northwest Hydro Facilities [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Proceeds from sale of facilities	$ 1,370

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Label	Element	Value
Accounting Standards Update201601 [Member] | Retained Earnings [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ (7,100,000)