40-F

U.S. SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 40-F

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

ý ANNUAL REPORT PURSUANT TO SECTION 13(a) or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 2019 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, 355-4^th Avenue SW

Calgary, Alberta T2P 0J1

(403) 691-7575

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

AltaGas Services (U.S.) Inc.

1000 Maine Ave.

Washington DC 20024

(703) 750-4400

(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:

ý  Annual information form ý 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 279,074,685 Common Shares, of no par value, outstanding as of December 31, 2019.

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.

YesýNoo

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 ý Noo

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

Emerging growth companyo

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 Exhibits hereto:

A. Annual Information Form

The Annual Information Form of AltaGas Ltd. (the “Company” or “Registrant”) for the fiscal year ended December 31, 2019 is included as Exhibit 13.1 of this Annual Report on Form 40-F.

B. Management's Discussion and Analysis and Audited Annual Financial Statements

The Company’s Management’s Discussion and Analysis for the year ended December 31, 2019 and audited consolidated financial statements for the fiscal year ended December 31, 2019, including the auditor’s report with respect thereto, are included as Exhibit 13.2 of this Annual Report on Form 40-F.

CERTIFICATIONS AND DISCLOSURE REGARDING CONTROLS AND PROCEDURES

Certifications. See Exhibits 31.1, 31.2, 32.1, and 32.2 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 Securities Exchange Act of 1934, as amended ("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: The Registrant’s management is responsible for establishing and maintaining adequate internal control over financial reporting. The Registrant’s internal control framework is based on the criteria published in the 2013 Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission. The Registrant’s management, including the CEO and CFO, evaluated the effectiveness of the Registrant’s internal control over financial reporting as at December 31, 2019 and concluded that the Registrant’s internal control over financial reporting is effective as at December 31, 2019.

Auditor’s Attestation Report: This annual report does not include an attestation report of the Registrant's registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Registrant's registered public accounting firm pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (the “Dodd-Frank Act”). The Dodd-Frank Act permits a “non-accelerated filer” to provide only management's report on internal control over financial reporting in an annual report and omit an attestation report of the issuer's registered public accounting firm regarding management's report on internal control over financial reporting.

Changes in Internal Control Over Financial Reporting. During the fiscal year ended December 31, 2019, 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: Allan L. Edgeworth, Robert B. Hodgins, Cynthia Johnston, Linda G. Sullivan and Nancy G. Tower.

AUDIT COMMITTEE FINANCIAL EXPERT

The board of directors of the Registrant has determined that each Allan L. Edgeworth, Robert B. Hodgins, Cynthia Johnston, Linda G. Sullivan and Nancy G. Tower, 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 page53 of the Registrant’s Annual Information Form for the fiscal year ended December 31, 2019, filed as part of this Annual Report on Form 40-F in Exhibit 13.1. The board of directors has further determined that each of Allan L. Edgeworth, Robert B. Hodgins, Cynthia Johnston, Linda G. Sullivan and Nancy G. Tower 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 Allan L. Edgeworth, Robert B. Hodgins, Cynthia Johnston, Linda G. Sullivan and Nancy G. Toweras an audit committee financial 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 2019, 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” at page 55 of the Registrant’s Annual Information Form for the fiscal year ended December 31, 2019, filed as part of this Annual Report on Form 40-F in Exhibit 13.1.

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, 2019 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, 2019, filed as part of this Annual Report on Form 40-F in Exhibit 13.2.

Mine Safety Disclosure.

Not applicable.

UNDERTAKING

The 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

The Registrant has previously filed with the Commission a Form F-X in connection with the class of securities in relation to which the obligation to file this report arises.

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.

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, 2020

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

EXHIBIT INDEX

13.1     2019 Annual Information Form dated February 27, 2020 for the fiscal year ended December 31, 2019

13.2 Management's Discussion and Analysis for the year ended December 31, 2019 and audited consolidated financial statements for the fiscal year ended December 31, 2019

23.1     Consent of Ernst & Young LLP, Independent Registered Public Accountant

31.1    Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2    Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1    Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2    Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101    Interactive Data File

EX-13.1

ALTAGAS LTD.

Annual Information Form

For the year ended December 31, 2019

Dated: February 27, 2020

TABLE OF CONTENTS

GENERAL INFORMATION	2
FORWARD-LOOKING INFORMATION AND STATEMENTS	2
GLOSSARY	3
METRIC CONVERSION	12
CORPORATE STRUCTURE	12
OVERVIEW OF THE BUSINESS	13
ALTAGAS’ GEOGRAPHIC FOOTPRINT	15
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	45
CORPORATE SEGMENT	49
CAPITAL STRUCTURE	50
GENERAL	52
EMPLOYEES	52
DIRECTORS AND OFFICERS	52
EXECUTIVE OFFICERS	56
AUDIT COMMITTEE	56
RISK FACTORS	58
ENVIRONMENTAL, HEALTH, SAFETY, AND SOCIAL POLICIES	72
ENVIRONMENTAL REGULATION	73
STAKEHOLDER ENGAGEMENT AND INDIGENOUS PEOPLES POLICY	74
DIVIDENDS	74
MARKET FOR SECURITIES	75
CREDIT RATINGS	78
MATERIAL CONTRACTS	80
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	81
LEGAL PROCEEDINGS	81
REGULATORY ACTIONS	82
INTERESTS OF EXPERTS	82
ADDITIONAL INFORMATION	82
TRANSFER AGENTS AND REGISTRARS	83
SCHEDULE A: AUDIT COMMITTEE MANDATE	84

AltaGas Ltd. – 2019 Annual Information Form –1

GENERAL INFORMATION

Unless otherwise noted, the information contained in this AIF is stated as at December 31, 2019 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; expectation that the Corporation will target opportunities to develop high-quality natural gas and NGL assets that complement its existing infrastructure; the Corporation's 2020 priorities; expectations to increase utilization and export volumes at RIPET; expected $900 million growth capital program in 2020; targeted 10 percent increase in Utilities rate base; expiration of the Northwest Hydro operating agreement in January 2021; timing of material regulatory filings, proceedings and decisions in the Utilities business; expected conditions to closing and closing date of the ACI Arrangement; expected in-service and completion dates for current projects in the Midstream business; expected effective dates of material environmental legislation; and duration of the suspension of the DRIP program. .

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: health and safety risks; operating risks; infrastructure risks; service interruptions; regulatory risks; litigation risk; decommissioning, abandonment and reclamation costs; climate and carbon tax risks; reputation risk; weather data; Indigenous land and rights claims; crown duty to consult with Indigenous peoples; changes in laws; capital market and liquidity risks; general economic conditions; internal credit risk; foreign exchange risk; debt financing, refinancing, and debt service risk; interest rates; cyber security, information, and control systems; technical systems and processes incidents; dependence on certain partners; growth strategy risk; construction and development; RIPET rail and marine transport; impact of competition in AltaGas' Midstream and Power businesses; commitments associated with regulatory approvals for the acquisition of WGL; counterparty credit risk; composition risk; collateral; reg agreements; non-controlling interests in investments; delays in U.S. federal government budget appropriations; consumption risk; market risk; market value of common shares and other securities; variability of dividends; potential sales of additional shares; volume throughput; natural gas supply risk; risk management costs and limitations; underinsured and uninsured losses; Cook Inlet gas supply; securities class action suits and derivative suits; electricity and resource adequacy prices; cost of providing retirement plan benefits; labor relations; key personnel; failure of service providers; compliance with Section 404(a) of Sarbanes-Oxley Act; integration of WGL; and the other factors discussed under the heading "Risk Factors" in this AIF.

AltaGas Ltd. – 2019 Annual Information Form –2

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 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.

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;

"AER" means the Alberta Energy Regulator;

"AESO" means the Alberta Electric System Operator;

"AIF" means this Annual Information Form;

"AIJVLP" means AltaGas Idemitsu Joint Venture Limited Partnership;

"AltaGas", the "Company", or the "Corporation" means AltaGas Ltd., including, where the context requires, the affiliates of AltaGas Ltd.;

"ARB" means the California Air Resources Board;

"ASC" means the Alberta Securities Commission;

"AUI" means AltaGas Utilities Inc.;

"B.C." or "BC" means the province of British Columbia in Canada;

"Bbls" means stock tank barrels of ethane and other 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;

AltaGas Ltd. – 2019 Annual Information Form –3

"Bcf/d" means Bcf per day;

"Birchcliff" means Birchcliff Energy Ltd.;

"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;

"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;

"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;

"CFIUS" means the Committee on Foreign Investment in the United States;

"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;

"CO2" means carbon dioxide;

"CO2e" means carbon dioxide equivalent;

"Common Shares" means common shares of AltaGas Ltd.;

AltaGas Ltd. – 2019 Annual Information Form –4

"Constitution" means Constitution Pipeline Company, LLC, an entity formed to create a pipeline to transport natural gas from the Marcellus region in northern Pennsylvania to northeastern markets;

"CPI" means the Consumer Price Index;

"CPUC" means the California Public Utilities Commission;

"DBRS" means DBRS Limited and its successors;

"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;

"Dekatherm" means 10 Therms;

"DOEE" means the District of Columbia Department of Energy and Environment;

"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;

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

"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;

"EQM" means EQM Gathering Opco, LLC;

"EQT" means EQT Midstream Partners, LP;

"ESA" means Energy Storage Resource Adequacy Purchase Agreement;

"ESG" means Environment, Social & Governance;

"FERC" means the United States Federal Energy Regulatory Commission;

"Ferndale terminal" means the storage, distribution, and export facility for bulk shipments of propane, and 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;

"g" means grams;

"GHG" means greenhouse gas;

"GJ" means gigajoule or 1,000,000,000 joules;

AltaGas Ltd. – 2019 Annual Information Form –5

"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" or "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;

"HE" means Hearing Examiner;

"Heritage Gas" means Heritage Gas Limited;

"Idemitsu" means Idemitsu Kosan Co., Ltd.;

"IRIP" means the Infrastructure Reliability Improvement Program;

"JEEP" means the Joffre ethane extraction plant and related facilities;

"Kelt" means Kelt Exploration (LNG) Ltd;

"km" means kilometer;

"kWh" means kilowatt hour;

"LNG" means liquefied natural gas;

"LPG" means liquefied petroleum gas;

"Marquette Connector Pipeline" means the recently completed pipeline that is owned and operated by SEMCO Gas and connects 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;

"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;

AltaGas Ltd. – 2019 Annual Information Form –6

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

"Mmcf/d" means Mmcf per day;

"Moody's" means Moody's Investor Service;

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

"MPSC" means the Michigan Public Service Commission;

"MRP" means Main Replacement Program;

"MRU" means Mount Royal University;

"MTN" means medium term notes issued from time to time under either the amended and restated trust indenturedated 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;

"NAESB" means North American Energy Standards Board;

"NEBC" means Northeast British Columbia;

"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;

"NOx" means nitrogen oxides;

"NTSB" means the National Transportation Safety Board;

"NYSDEC" means the New York State Department of Environmental Conservation;

AltaGas Ltd. – 2019 Annual Information Form –7

"O2" means oxygen;

"Painted Pony" means Painted Pony Energy Ltd.;

"PEEP" means the Pembina Empress extraction plant and related facilities;

"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 an approximate two-thirds ownership interest;

"PG&E" means Pacific Gas & Electric Company;

"Plan" means the Premium Dividend^TM, Dividend Reinvestment, and Optional Cash Purchase Plan of the Corporation;

"PNG" means Pacific Northern Gas Ltd.;

"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.;

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

"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;

"PROJECTpipes" means Washington Gas' 40-year accelerated pipeline replacement program, that was launched in 2014 in the District of Columbia and is designed to enhance the safety and reliability of its system;

"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;

"Put Notice" means the notice received by AIJVLP from SAM of its exercise of a put option with respect to its approximate one-third interest in Petrogas.

"Put Option" means the put option with respect to SAM's approximate one-third interest in Petrogas;

"RCA" means the Regulatory Commission of Alaska;

"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;

AltaGas Ltd. – 2019 Annual Information Form –8

"Ring Fenced Entities" means Washington Gas and the SPE;

"RIPET" means the Ridley Island Propane Export Terminal, the propane export terminal 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;

"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;

"SAM" means Sam Holdings Ltd.;

"Sarbanes-Oxley" means the Sarbanes-Oxley Act of 2002;

"SAVE" means Steps to Advance Virginia's Energy Plan;

"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;

AltaGas Ltd. – 2019 Annual Information Form –9

"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 onJanuary 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;

"SOS" means Standard offer Service;

"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;

"STRIDE" means Strategic Infrastructure Development Enhancement Plan;

"TCJA" means the Tax Cuts and Jobs Act of 2017;

"TIER" means Technology Innovation and Emissions Reduction;

"Tourmaline" means Tourmaline Oil Corp.;

"Townsend 2A" means the first 99 Mmcf/d train of the Townsend expansion, 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 2020;

"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;

"Transco" means Transcontinental Gas Pipeline Company LLC;

"TSX" means the Toronto Stock Exchange;

"UESC" means Utility Energy Savings Contracts;

"United States", "US", or "U.S." means the United States of America;

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

AltaGas Ltd. – 2019 Annual Information Form –10

"USEPA" means United States Environmental Protection Agency;

"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 that were redeemed by Washington Gas on December 20, 2019;

"Washington Gas $4.80 Shares" means the US$4.80 series cumulative preferred shares of Washington Gas that were redeemed by Washington Gas on December 20, 2019;

"Washington Gas $5.00 Shares" means the US$5.00 series cumulative preferred shares of Washington Gas that were redeemed by Washington Gas on December 20, 2019;

"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.

AltaGas Ltd. – 2019 Annual Information Form –11

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	To Convert From	To	Multiply by
Mcf	cubic meters	28.174	feet	meters	0.305
cubic meters	cubic feet	35.494	meters	feet	3.281
Bbls	cubic meters	0.159	miles	km	1.609
cubic meters	Bbls	6.29	km	miles	0.621
tonnes	long tons	0.98	gigajoule	Mcf	0.9482
million tonnes	Bbls	12.40

CORPORATE STRUCTURE

Incorporation

AltaGas is a Canadian corporation amalgamated pursuant to the CBCA on January 1, 2020. 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 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 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. On January 1, 2020, AltaGas filed articles of amalgamation to effect the amalgamation of AltaGas with its non-operating subsidiaries AltaGas Investment Ltd., 11801376 Canada Ltd., and Northwest Triumph Contracting Ltd.

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, 2019.

AltaGas Ltd. – 2019 Annual Information Form –12

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

(2)    Unless otherwise stated, ownership is 100%.

OVERVIEW OF THE BUSINESS

AltaGas, a Canadian corporation, is a leading North American energy infrastructure company that connects NGLs and natural gas to domestic and global markets. The Corporation’s long-term strategy is to grow in attractive areas across its Utilities and Midstream 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 the West Coast of Canada via the Corporation’s footprint in the Montney region. In the Utilities business, the Corporation seeks to grow through rate base investment and the use of accelerated rate recovery programs, while providing effective and cost-efficient service for customers. AltaGas has three business segments:

▪ Utilities, which serves approximately 1.7 million customers with a rate base of approximately US$3.9 billionthrough 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.

AltaGas Ltd. – 2019 Annual Information Form –13

The Utilities business also includes storage facilities and contracts for interstate natural gas transportation and storage services;

▪ Midstream, which includes a 70 percent interest in the recently completed Ridley Island Propane Export Terminal, allowing AltaGas to leverage its assets along the energy value chain in Western Canada including natural gas gathering and processing, NGL extraction and fractionation, and natural gas and NGL marketing. The Midstream segment also includes transmission, storage, an interest in a regulated pipeline in the Marcellus/Utica gas formation in the northeastern United States, WGL’s retail gas marketing business, the Corporation’s 50 percent interest in AIJVLP, and an indirectly held approximate one-third ownership investment in Petrogas, through which AltaGas’ interest in the Ferndale terminal is held; and

▪ Power, which includes 710 MW of operational gross capacity from natural gas-fired, distributed generation, and energy storage assets, certain of which are pending sale, located in Alberta, Canada and the United States, primarily in California and Colorado. The Power business also includes energy efficiency contracting and WGL’s retail power marketing business.

AltaGas Ltd. – 2019 Annual Information Form –14

ALTAGAS’ GEOGRAPHIC FOOTPRINT

AltaGas Ltd. – 2019 Annual Information Form –15

AltaGas Ltd. – 2019 Annual Information Form –16

OUTLOOK

In 2019, AltaGas successfully completed its plan to refocus the Company, capture the intrinsic value of its core assets, and regain its financial footing to capitalize on the significant investment opportunities ahead. Since the acquisition of WGL in 2018, AltaGas has integrated the WGL assets, streamlined its business portfolio through approximately $5 billion of non-core asset sales, substantially simplified its business model, and significantly enhanced its financial strength and flexibility, all while continuing to deliver solid operating and financial performance.

AltaGas’ strategy is largely focused on two core businesses: Utilities and Midstream. Moving forward, AltaGas expects to target opportunities to develop high-quality natural gas and NGL assets that complement its existing integrated infrastructure footprint within these businesses, and to grow its position in key markets to deliver optimal growth over the long term.

In 2020, AltaGas plans to focus on capitalizing on the significant growth potential of its Utilities and Midstream assets. Specific priorities include to:

▪ Ensure safe reliable operations, providing effective and cost-efficient service for customers;

AltaGas Ltd. – 2019 Annual Information Form –17

▪ Enhance returns and capital efficiency through base rate cases, and facilitate timely recovery of expenditures and improve safety through increased utilization of accelerated rate recovery programs;

▪ Enhance the business through asset optimization and operational efficiencies to reduce costs and deliver an improved customer experience;

▪ Maximize the unique structural advantage within AltaGas' integrated platform in the Montney region;

▪ Increase utilization and export volumes at RIPET;

▪ Execute the planned $900 million growth capital program, including a targeted 10 percent increase in the Utilities rate base; and

▪ Pursue capital efficient organic growth through disciplined capital allocation while improving balance sheet strength and flexibility.

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 Gas’ application to construct, own, and operate the Marquette Connector Pipeline. The Marquette Connector Pipeline is a new pipeline that connects 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 was completed and placed in-service in December 2019.

On July 6, 2018, the WGL Acquisition closed and the operations of Washington Gas and Hampshire Gas were added to AltaGas’ Utilities business.

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.

On July 31, 2018, Washington Gas filed an application with the SCC of VA to increase its base rates for natural gas service. A Final Order was received in December 2019. On January 9, 2020, Washington Gas filed a petition for reconsideration regarding one of the findings in the Final Order. On January 30, 2020, the SCC of VA denied this request and the rate case is now final. See "Business of the Corporation - Utilities Business - Washington Gas - Material Regulatory Developments and Approvals".

On October 15, 2019, the PSC of MD issued a Final Order approving Washington Gas' settlement agreement in their recent rate case, reflecting a US$27 million base rate increase effective October 15, 2019. See "Business of the Corporation - Utilities Business - Washington Gas - Material Regulatory Developments and Approvals".

On October 21, 2019, ACI announced that the Public Sector Pension Investment Board and the Alberta Teachers' Retirement Fund Board (together, the "Consortium") and ACI had concluded a definitive arrangement agreement (the "Arrangement Agreement") whereby the Consortium will indirectly acquire all of the issued and outstanding common shares of ACI in an all-cash transaction for $33.50 per common share (the "Arrangement"). On December 19, 2019, the shareholders of ACI approved the Arrangement Agreement. In addition, on December 16, 2019, ACI received a "no-action letter" from the Canadian Competition Bureau confirming that the Commissioner of Competition does not at this time intend to challenge the proposed Arrangement. On December 20, 2019, ACI received the final order from the Court of Queen's Bench of Alberta approving the Arrangement. On February 18, 2020, the Alberta Utilities Commission issued a decision approving the Arrangement. The closing of the Arrangement remains subject to the receipt of approval from the British Columbia Utilities Commission,

AltaGas Ltd. – 2019 Annual Information Form –18

and the satisfaction or waiver of other customary closing conditions. ACI and the Consortium expect to close the Arrangement in the first half of 2020. AltaGas owns 11,025,000 common shares or approximately 37 percent of the total number of common shares of ACI.

On December 6, 2019, the MPSC issued a Final Order approving SEMCO Gas' settlement agreement in its recent rate case, reflecting a base rate increase of approximately US$20 million effective January 1, 2020. See "Business of the Corporation - Utilities Business - SEMCO Gas - Material Regulatory Developments and Approvals".

On January 13, 2020, Washington Gas filed an application with the PSC of DC for an increase in rates. See "Business of the Corporation - Utilities Business - Washington Gas - Material Regulatory Developments and Approvals".

Development of the Midstream Business of AltaGas

In January 2017, AltaGas reached a positive FID on RIPET, the first propane marine export facility in 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 the first shipment of propane to Asia departed on May 23, 2019. Based on production from AltaGas Midstream facilities and commercial contracts executed or currently under negotiation, RIPET's physical volumes are currently averaging approximately 40,000 Bbls/d or 1.2 million tonnes annually. For further details on this project see below under the heading "Business of the Corporation – Midstream Business – Global Exports".

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

On April 3, 2018, AltaGas entered into a long-term natural gas processing arrangement with Birchcliff 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 U.S. (two of which have since been sold and one project for which the partners have elected not to proceed) as well as the retail gas marketing business of WGL were added to AltaGas’ Midstream business.

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.

In October 2018, AltaGas acquired 50 percent ownership in certain existing and future natural gas processing plants of Black Swan. AltaGas and Black Swan also entered into long-term processing, transportation, and marketing agreements that include new AltaGas liquids handling infrastructure.

On May 31, 2019, AltaGas completed the disposition of WGL Midstream's entire interest in the Stonewall System to a wholly-owned subsidiary of DTE Energy for total gross proceeds of approximately $379 million (US$280 million).

On September 30, 2019, AltaGas announced that it had entered into a definitive agreement for the sale of its indirect, non-operating interest in Central Penn held by its subsidiary WGL Midstream, Inc. to Meade Pipeline Investment, LLC, a subsidiary of NextEra Energy Partners, LP. Total cash proceeds for WGL Midstream's interest were approximately $812 million (US$611 million) and the transaction closed on November 13, 2019.

On January 2, 2020, AltaGas announced that AIJVLP had received the Put Notice from SAM of its exercise of the Put Option with respect to SAM's approximate one-third interest in Petrogas effective December 31, 2019. Pursuant to the Petrogas unanimous shareholders agreement, a valid exercise of the Put Option by SAM after October 1, 2019, triggers a requirement

AltaGas Ltd. – 2019 Annual Information Form –19

for AIJVLP to purchase SAM's approximate one-third interest in Petrogas at the fair market value therefore, as determined by third party valuators.

In February 2020, following evaluations of the diminished underlying economics for the proposed Constitution pipeline project, the partners of Constitution elected not to proceed with the project. AltaGas held a 10 percent equity interest in Constitution.

Development of the Power Business of AltaGas

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.

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.

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.

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 January 31, 2019, AltaGas completed the sale of its remaining interest of approximately 55 percent in the Northwest Hydro facilities for net cash proceeds of approximately $1.3 billion, resulting in a pre-tax gain of $688 million. AltaGas remains the operator of the facilities under an operating and maintenance agreement expiring January 31, 2021.

On August 13, 2019, AltaGas completed the sale of its equity ownership interests in Craven County Wood Energy LP and Grayling Generation Station LP for net proceeds of approximately $24.5 million (US$18.5 million).

On September 26, 2019, AltaGas closed the sale of its portfolio of U.S. distributed generation assets held by its subsidiaries WGL Energy Systems, Inc. and WGSW, Inc., to TerraForm Power, Inc., an affiliate of Brookfield Asset Management. Total cash proceeds received were approximately $975 million (US$735 million) and a pre-tax gain on disposition of $168 million was recorded in 2019. There are certain projects for which legal title has not yet transferred as various consents and approvals remain outstanding. Accordingly, assets of approximately $27 million and liabilities of $4 million remain held for sale at December 31, 2019.

In October 2019, AltaGas announced the successful recontracting of the Blythe facility to SCE. Under the tolling agreement, SCE has exclusive rights to all capacity, energy, ancillary services, and resource adequacy benefits from August 1, 2020 to December 31, 2023. California Public Utilities Commission approval was received on January 16, 2020.

AltaGas Ltd. – 2019 Annual Information Form –20

BUSINESS OF THE CORPORATION

AltaGas’ revenue for the year ended December 31, 2019 was approximately $5.5 billion compared to $4.3 billion for the year ended December 31, 2018.

Note: 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 that 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 $2.6 billion for the year ended December 31, 2019 (2018 - $1.7 billion), representing approximately 46 percent (2018 – 40 percent) of AltaGas’ total revenue before Corporate segment and intersegment eliminations.

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, a regulated natural gas storage utility 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.

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 cost levels established in the rate-setting processes.

SEMCO Gas and Washington Gas have accelerated pipe and infrastructure replacement programs in place in Michigan and in the District of Columbia, Maryland, and Virginia, respectively. These are long-term programs subject to both changing

AltaGas Ltd. – 2019 Annual Information Form –21

conditions and regulatory review and approval in five-year increments. These programs enable SEMCO Gas and Washington Gas to accelerate 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 outside of a normal rate case process, mitigating regulatory lag. Once new base rates are put into effect in a given jurisdiction following approval of an application to increase rates, 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, regulate interactions with affiliates, and regulate retail competition for natural gas supply service. In all jurisdictions, the regulators approve distribution rates based on a cost-of-service regulatory model. In Alaska, the District of Columbia, and Maryland, rates are set using the results from a historical test year plus known and measurable changes. In Michigan and Virginia, 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. In most jurisdictions, the rates are also designed to earn a reasonable return on its investment in the net assets used in its firm gas sales and delivery service.

Utilities Business Key Utility Metrics

The following table summarizes the average rate base for the Utilities business for the years ended December 31, 2019 and 2018:

(US$ millions)	2019	2018
Rate base (1) (2)	3,865	3,684

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

The following table summarizes the capital expenditures for the years ended December 31, 2019 and 2018:

(US$ millions)	2019	2018
New business	252	69
System betterment and gas supply	165	140
General plant	30	64
Accelerated Replacement Programs	200	88
Total	647	361

AltaGas Ltd. – 2019 Annual Information Form –22

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, 2019	Allowed Common Equity (%)	Allowed ROE (%) 2018	Allowed ROE (%) 2019	Significant Features/ Material Regulatory Developments
Washington Gas	PSC of MD SCC of VA PSC of DC	75%	53.5 - 55.7	9.25 - 9.7	9.2 - 9.7	n    Distribution rates approved under cost of service model. n    Rate cases filed with the PSC of MD in 2018 and 2019 for increase in rates and accelerated pipeline replacement programs. Final Orders were received in 2019. n    Rate case filed in 2018 with the SCC of VA for an increase in rates. The Final Order was received in December 2019. In January 2020, a petition for reconsideration was filed and denied, and the rate case is now final. n    Rate case filed in January 2020 with the PSC of DC for an increase in rates.
SEMCO Gas	MPSC	16%	49.04	10.35	10.35	n    Distribution rates approved under cost of service model. n    Use of projected test year for rate cases with 10-month limit to issue a rate order. n    Rate rider provides recovery relating to the Main Replacement Program which allows SEMCO Gas to accelerate the replacement of older portions of its system. New Infrastructure Reliability Improvement Program (IRIP) was approved in the 2019 rate case for the years 2020 - 2025. Customers will be billed a surcharge beginning in 2021 for the IRIP. n    Rate case filed in May 2019. The settlement was approved in December 2019 and the new rates are effective on January 1, 2020.
ENSTAR	RCA	7%	51.81	11.875	11.875	nDistribution rates approved under cost of service model using historical test year and allows for known and measurable changes. n    Rate order approving rate increase issued on September 22, 2017. Final rates effective November 1, 2017. n    Required to file another rate case no later than June 1, 2021 based upon 2020 test year.
CINGSA	RCA	2%	53.00	11.875	10.25	nDistribution rates approved under cost of service model using historical test year and allows for known and measurable changes. nRate case filed in 2018 based on 2017 historical test year. nRate case hearing April 2019 with a decision received in August 2019. The decision included an ROE of 10.25% (compared to 11.875% requested) and 100% of Interruptible Storage Service revenues payable to customers (versus 50% requested). CINGSA filed a petition for partial reconsideration on September 3, 2019. The Commission denied the petition and on November 4, 2019 CINGSA filed an appeal with the Superior Court challenging one decision from the order. This matter is currently ongoing.
Hampshire Gas	FERC	n/a	n/a	n/a	n/a	nPass through cost of service tariff approved by FERC.

AltaGas Ltd. – 2019 Annual Information Form –23

Investment in AltaGas Canada Inc.

As of December 31, 2019, AltaGas owns 11,025,000 common shares or approximately 37 percent of the total number of common shares of ACI. AltaGas’ interest in ACI is accounted for as an equity investment.

On December 19, 2019, ACI announced that the holders of common shares of ACI approved the arrangement whereby the Consortium would together indirectly acquire all of the issued and outstanding common shares of ACI for $33.50 in cash per common share. The Arrangement is expected to close in the first half of 2020. See "General Development of AltaGas' Business - Development of the Utilities Business of AltaGas".

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, Maryland, and Virginia. The utility has approximately 1.2 million customers across these three jurisdictions: District of Columbia (~164,000; 14 percent), Maryland (~493,000; 41 percent), and Virginia (~535,000; 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.

The number of customers at Washington Gas increased by approximately 1 percent in 2019.

Operations

Washington Gas obtains natural gas supplies that originate from multiple regions throughout the U.S. At December 31, 2019, it had service agreements with four pipeline companies that provided firm transportation and storage services, with contract expiration dates ranging from 2020 to 2044. Washington Gas has also contracted with various interstate pipeline and storage companies to add to its storage and transportation capacity.

The following table sets out, by customer category, Washington Gas’ deliveries for the period since close of the WGL Acquisition to December 31, 2019:

AltaGas Ltd. – 2019 Annual Information Form –24

	2019	2018
Deliveries: (MDth)
Residential	69,660	27,567
Commercial	21,997	8,623
Transport	85,658	39,368
Total deliveries	177,315	75,558
	2019	2018
Customers at Year End:
Residential	973,549	962,003
Commercial	47,677	47,772
Transport	171,236	175,055
Total customers	1,192,462	1,184,830

Seasonality

The natural gas distribution business in the District of Columbia, Maryland, and Virginia 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 in the District of Columbia are set based on the 30-year rolling average Degree Days expected for the period. In Maryland and Virginia, 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 Washington Gas hedge to offset the effects of weather. As a result, colder or warmer weather will result in variances to financial results. On January 13, 2020, Washington Gas filed an application with the PSC of DC that requested approval for a weather normalization billing mechanism. See "Business of the Corporation - Utilities Business - Washington Gas - Material Regulatory Developments and Approvals - District of Columbia Jurisdiction".

Material Regulatory Developments and Approvals

District of Columbia Jurisdiction

In 2013, Washington Gas filed a revised Accelerated Pipe Replacement Plan (PROJECTpipes) with the PSC of DC 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. On January 29, 2015, the PSC of DC issued an order approving the settlement agreement and approving recovery through the surcharge of total project costs up to US$110 million through September 30, 2019. On December 7, 2018, Washington Gas filed a request with the PSC of DC for approval of the PROJECTpipes 2 Plan for the period of October 1, 2019 through December 31, 2024. As of September 5, 2019, the PSC of DC had not made final ruling on PROJECTpipes 2, and issued an order extending PROJECTpipes an additional six months through March 31, 2020, in an amount not to exceed US$12.5 million, and directed the interested parties to schedule a settlement conference within 15 days of the order. On February 14, 2020, a final settlement conference report was submitted, and the PSC of DC continues to review the PROJECTpipes 2 Plan.

On January 13, 2020, Washington Gas filed an application with the PSC of DC to increase its base rates by approximately US$35 million, including approximately US$9 million pertaining to a PROJECTpipes surcharge that customers are currently paying in the form of a rate rider. The filing requested a return on equity of 10.4 percent on allowed common equity of 52.2 percent, which is based on a US$532 million rate base value. Additionally, Washington Gas requested approval for a Revenue Normalization Adjustment mechanism to reduce customer bill fluctuations due to weather-related and conservation-related usage variations, similar to existing mechanisms in both Maryland and Virginia. Washington Gas requested that new rates be implemented by January 1, 2021. A conference to discuss process schedule is expected to be held in March 2020.

Maryland Jurisdiction

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 US$15 million pertaining to a STRIDE surcharge it was collecting in the form of a rate rider. The PSC of MD granted Washington Gas US$29 million base rate increase and increased Washington Gas' return on equity to 9.7 percent. On January 10, 2019, Washington Gas filed an application for rehearing with the PSC of MD, alleging two errors in the Commission’s Final Order. On June 25, 2019, the PSC of MD issued an order granting in part and denying in part Washington Gas’ application for a rehearing, resulting in an additional US$1 million increase in annual distribution revenues.

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. 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 April 22, 2019, Washington Gas filed an application with the PSC of MD to increase its base rates for natural gas service, requesting a US$36 million increase in base rates, including a US$5 million related to costs being collected through monthly STRIDE surcharges for system upgrades, and to increase its return on equity from 9.7 to 10.4 percent. On August 30, 2019, Washington Gas, the Staff of the PSC of MD, the Maryland Office of People’s Counsel, and the Apartment & Office Building Association of Metropolitan Washington submitted a Stipulation and Settlement designed to generate an additional US$27 million in base rates. The Stipulation stated an overall rate of return of 7.42 percent, established a return on equity of 9.70

AltaGas Ltd. – 2019 Annual Information Form –25

percent, and stated a common equity ratio of 53.5 percent. On October 15, 2019, the PSC of MD issued Final Order No. 89303 which accepted the Stipulation and Settlement without change. Pursuant to Order No. 89303, Washington Gas’ revised base rates went into effect for service renderedbeginning October 15, 2019.

On September 5, 2019, the PSC of MD ordered Washington Gas, within 30 days, to (i) provide a detailed response to the NTSB’s probable cause findings and (ii) provide evidence regarding the status of a 2003 mercury regulator replacement program and, if the program was not completed, to show cause why the PSC of MD should not impose a civil penalty on Washington Gas. On November 18, 2019, the Technical Staff of the PSC of MD, the MD Office of People’s Counsel (OPC), Montgomery County, MD and the Apartment and Office Building Association of Metropolitan Washington (AOBA) filed written comments on Washington Gas' response to the Show-Cause Order. Technical Staff commented that the PSC of MD may impose a civil penalty but did not expressly recommend same. Montgomery County, MD, OPC and AOBA requested that the PSC of MD impose a civil penalty on Washington Gas. On December 17, 2019, the PSC of MD held a public hearing near the apartment complex at Arliss Street, at which some residents requested that Washington Gas accelerate and complete its mercury service regulator program and that Washington Gas absorb the cost of same. Washington Gas intends to file comments with the PSC of MD responding to all written comments and resident testimony and has accrued a penalty of US$0.3 million based on a potential range of estimates.

Virginia Jurisdiction

On July 31, 2018, Washington Gas filed an application with the SCC of VA to increase its base rates for natural gas service by US$38 million, which included US$15 million related to the SAVE surcharge. Additionally, the requested revenue increase incorporated the effects of the TCJA. Interim rates became effective, subject to refund, for usage in the January 2019 billing cycle. On April 12, 2019, Washington Gas filed rebuttal testimony and revised its original return on equity down from 10.6 percent to 10.3 percent and its overall rate of return down from 7.94 percent to 7.81 percent. On September 16, 2019, the HE issued a report with recommendations to the SCC of VA including no incremental rate increase aside from bringing the SAVE rider to the base rate. On October 21, 2019, Washington Gas filed comments on and exceptions to the HE's report, recommending the SCC of VA reject certain of the HE's findings. On December 20, 2019, the Commission issued a Final Order adjusting certain of the HE’s findings, some of which are favorable to Washington Gas. The Final Order approved: (i) an increase in base rates of US$13 million to reflect the transfer of US$102 million of SAVE investment from the SAVE rider to rate base; (ii) an ROE range of 8.7 percent to 9.7 percent with a mid-point of 9.2 percent; (iii) the amortization of unprotected excess deferred income tax over eight years; and (iv) the refund of a US$26 million TCJA liability over a 12-month period as a sur-credit. On January 9, 2020, Washington Gas filed a petition for rehearing regarding one of the findings. On January 30, 2020, the SCC of VA denied this request and the rate case is now final.

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. As at December 31, 2019, the cumulative amount expensed to date was approximately US$137 million, of which US$17 million had not been paid. 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, investing up to US$70 million over a 10-year period to further extend natural gas service, and investing US$8 million for leak mitigation.

Hampshire Gas

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 the commodity cost of its regulated energy bills to customers. Hampshire 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

AltaGas Ltd. – 2019 Annual Information Form –26

in CINGSA, a regulated natural gas storage utility in Alaska. The gas utility business accounts for approximately 99 percent of SEMCO Energy’s 2019 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 307,000 regulated customers located in both southern Michigan and Michigan’s Upper Peninsula, approximately 85 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 percent annually during the past three years (with an increase of 1 percent in 2019). 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.

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 U.S. 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 NAESB form of agreement with a variety of suppliers.

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

	2019	2018
Deliveries: (MDth)
Residential	26,841	27,278
Commercial	15,976	13,595
Transport	22,712	22,248
Gas Customer Choice (1)	3,719	3,394
Total deliveries	69,248	66,515
	2019	2018
Customers at Year End (2):
Residential	260,548	258,300
Commercial	23,880	23,523
Transport	249	253
Gas Customer Choice (1)	22,247	21,102
Total customers	306,924	303,178

(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.

AltaGas Ltd. – 2019 Annual Information Form –27

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 an approximately US$2 million upward adjustment to depreciation expense when compared to the current rates and were 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 May 31, 2019, SEMCO Gas filed a request with the MPSC seeking authority to increase SEMCO Gas' base rates by approximately US$38 million on an annual basis established with a forecasted test year of 2020. The increase in rates requested captures the inflation of operations and maintenance costs from the last rate case in 2010 as well as the investment in the Marquette Connector Pipeline. With the upcoming sunset of the MRP in 2020, this case includes the addition of a new MRP and the introduction of an IRIP to recover the capital costs associated with the replacement of certain mains, services, and other infrastructure through surcharges similar to the currently-enacted MRP program. In November 2019, a settlement agreement was filed for a rate increase of approximately US$20 million and an allowed return on equity of 9.87 percent. The MPSC approved the settlement in December 2019 and the new rates are effective January 1, 2020. Pursuant to the approval of the IRIP, SEMCO Gas will complete certain projects totaling US$55 million to improve the reliability of infrastructure and customers will be billed a surcharge beginning in 2021. SEMCO Gas cannot seek an increase in its general rates to take effect prior to January 1, 2023.

ENSTAR

In Alaska, ENSTAR distributes natural gas to approximately 147,000 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 an LNG plant. ENSTAR’s service area encompasses over 50 percent of the population of Alaska.

The average number of customers at ENSTAR has increased by an average of approximately 1 percent annually during the past three years (with an increase of 1 percent in 2019). 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 3,149 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

AltaGas Ltd. – 2019 Annual Information Form –28

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.

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

	2019	2018
Deliveries: (Mmcf)
Residential	16,308	18,322
Commercial	13,367	12,415
Transport	24,473	25,041
Total deliveries	54,148	55,778
	2019	2018
Customers at Year End:
Residential	133,654	132,270
Commercial	12,940	12,829
Transport	23	22
Total customers	146,617	145,121

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 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.

On November 30, 2018, Southcentral Alaska experienced a magnitude 7.1 earthquake with an epicenter close to Anchorage, Alaska. ENSTAR experienced a large number of above and below ground gas leaks in its service territory. On December 2, 2019, ENSTAR filed a request to establish a regulatory deferred asset with the RCA to recover uninsured losses associated with the earthquake in its next rate case, which is required to be filed in 2021. As at December 31, 2019, the associated losses totaled US$2 million. ENSTAR's insurance deductible for this type of claim is US$1 million.

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

AltaGas Ltd. – 2019 Annual Information Form –29

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 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. The application was denied on February 28, 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 based on a 2017 historical test year, reducing rates by US$4 million due to a lower rate base, lower ROE, and lower federal income tax. A decision was received in August 2019 and included an ROE of 10.25 percent (compared to 11.875 percent requested) and 100 percent of Interruptible Storage Service revenues payable to customers (versus 50 percent requested). CINGSA filed a petition for partial reconsideration on September 3, 2019. The Commission denied the petition on November 4, 2019. CINGSA filed an appeal with the Superior Court challenging one decision in the rate order. This matter is currently ongoing.

Environmental Considerations Impacting the Utilities Business

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. The cost of compliance associated with environmental laws and regulation can be significant and is subject to change. Almost all 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;

▪ 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 located in Washington, D.C., which is adjacent to the Anacostia River, under a 2012 Consent Decree with the District of Columbia and federal government. Remedial measures include ground water pump and treat, tar recovery, soil encapsulation, and other treatment. In addition, at another adjoining property located to the east of the property owned by the District of Columbia, Washington Gas agreed to perform a site investigation and report the findings pursuant to oversight by the DOEE. Additional remediation may be required at this property.

In addition, at another adjoining property known as the "Boat Club Property", located to the east of the property owned by the District of Columbia, Washington Gas agreed to perform a site investigation and report the findings pursuant to oversight

AltaGas Ltd. – 2019 Annual Information Form –30

by the DOEE. The property was subject to a July 12, 2019 Administrative Order from the DOEE. This Administrative Order has been withdrawn and a consent order is being negotiated.

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. On December 27, 2019, the DOEE issued an Anacostia River Sediment Project Proposed Plan, a River-wide Feasibility Study, and supporting documents for public comment. Although the Proposed Plan identifies the East Station property as one of fifteen potential environmental cleanup sites, the DOEE is proposing to continue remediation of the East Station property under the existing Consent Decree rather than as part of the Anacostia River Sediment Project. The DOEE is proposing to issue an Interim Record of Decision for remediation of "Early Action Areas" (that do not include the East Station property) in the Anacostia River by September 30, 2020. 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 for its share of the feasibility study costs.

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.

If applicable environmental laws change that require further investigation and remediation to be performed at the sites in the future, Washington Gas could incur a material liability. This liability would be offset by a corresponding regulatory asset. To the extent that any costs are not fully recoverable from customers through regulatory proceedings or from insurance or other potentially responsible persons in any of Washington Gas' jurisdictions, these costs would reduce its earnings and results of operations.

SEMCO Gas

As of December 31, 2019, 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 Environment, Great Lakes, and Energy for both sites. SEMCO Gas will continue to monitor these sites in the future as required by the NFA letters.

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.

MIDSTREAM BUSINESS

AltaGas’ Midstream business contributed revenue of $1.6 billion for the year ended December 31, 2019 (2018 - $1.4 billion), representing approximately 29 percent (2018 – 33 percent) of AltaGas’ total revenue before Corporate segment and intersegment eliminations. The Midstream business is comprised of global export assets and strategically located processing, fractionation, and liquids handling infrastructure that connect Western Canadian producers from wellhead to the coast and to global export markets, primarily focusing on LPG. In Canada, the Midstream business also includes integrated liquids handling services that are comprised of storage, rail logistics, pipeline, and truck loading, as well as natural gas and NGL marketing initiatives that support the Midstream infrastructure. In the U.S., AltaGas' Midstream business is comprised of the sale of natural gas to retail customers, contracted underground natural gas storage, and a pipeline investment.

AltaGas Ltd. – 2019 Annual Information Form –31

AltaGas' facilities are set out in the table below:

2019 Licensed Capacity (Net)
Facility	Location	Interest (%)		Operated / Non-Operated	Gas Processing (Mmcf/d)	Fractionation (Bbls/d)	Export (Bbls/d)
RIPET	Prince Rupert, BC	70.0	%	Operated	—	—	40,000
Ferndale (1)	Washington (US)	33.0	%	Non-Operated	—	—	50,000
Townsend	North of Fort St. John, BC	100.0	%	Operated	396	—	—
Gordondale	Bonanza, AB	100.0	%	Operated	150	—	—
Blair Creek	North of Fort St. John, BC	100.0	%	Operated	120	—	—
Aitken Creek (2)	Aitken, BC	50.0	%	Non-Operated	105	—	—
JEEP	Joffre, AB	100.0	%	Operated	250	—	—
EEEP	Edmonton, AB	100.0	%	Operated	390	—	—
PEEP	Empress, AB	11.3	%	Non-Operated	135	—	—
North Pine	North of Fort St. John, BC	100.0	%	Operated	—	20,000	—
Harmattan	Sundre, AB	100.0	%	Operated	490	35,000	—
Younger (3)	Taylor, BC	28.3	%	Non-Operated	213	9,750	—
Total					2,249	64,750	90,000

(1) Ferndale shown on a gross basis. AltaGas' investment in Ferndale is accounted for as an indirect equity investment.

(2) Includes Aitken Creek North and Nig Creek.

(3) AltaGas' interest in Younger is 28.3% in processing and extraction and 50% in fractionation and terminalling assets.

The total actual throughput of AltaGas' above facilities are set out in the table below ⁽¹⁾:

	2019	2018
Export (Bbls/d) (2)	35,446	—
Gas Processing (Mmcf/d)	1,407	1,378
Fractionation (Bbls/d)	37,546	38,128

(1) As total actual throughput is included, future capacity associated with projects not yet in-service is excluded.

(2) Total throughput excludes Ferndale which is accounted for as an indirect equity investment.

Global Exports

AltaGas' global export assets are focused on providing Western Canadian producers global market access and incremental value for Canadian NGLs. Global export assets extend AltaGas' integrated value chain and attract additional volumes to the AltaGas system, supporting future growth of the overall Midstream infrastructure platform.

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 AltaGas and RTI. A positive FID was made on RIPET in January 2017 with construction commencing in April 2017. In May 2017, AltaGas entered into a joint venture agreement with Vopak pursuant to which Vopak acquired a 30 percent interest in RIPET. The commercial operations of RIPET commenced on May 23, 2019, with the first propane shipment departing from the terminal to Asia.

Based on production at AltaGas' Midstream facilities and commercial contracts executed or under negotiation, RIPET's physical volumes currently average approximately 40,000 Bbls/d or 1.2 million tonnes annually.

AltaGas Ltd. – 2019 Annual Information Form –32

The terminal leverages CN’s existing railway network and the deepest harbor in North America to offer Canada’s natural gas producers direct access to international markets and a 15-day shipping advantage versus the U.S. Gulf Coast. With RIPET being the closest North American LPG terminal to Asia, it allows Canadian natural gas and propane producers to diversify their market access to Asia, a premium market for propane. RIPET is capable of storing 600,000 Bbls. The terminal offloads approximately 50 to 60 rail cars of liquid propane from B.C. and Alberta each day and delivers by marine transport approximately 20 to 30 cargos of propane per year to the global markets. AltaGas expects to increase throughput from RIPET as it builds on the operational capabilities and global counterparty networks for RIPET. In preparation for this, in November 2019, AltaGas filed an application to increase RIPET's propane export license to 80,000 Bbls/d.

AltaGas' liquids handling supports RIPET operations by providing marketing and supply services as well as managing the rail logistics network consisting of approximately 1,200 rail cars, together with LPG storage capacity upstream of RIPET. See below under the heading "Fractionation and Liquids Handling".

Petrogas – Ferndale Terminal

AltaGas, through its fifty percent ownership in AIJVLP, has approximate one-third indirect ownership interest in Petrogas, which owns and operates the Ferndale terminal and exports LPG to Asia. The Ferndale terminal is capable of handling LPG exports up to 50,000 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 owns, operates, and leases storage, blending, and rail and truck terminal facilities that support Petrogas' marketing and distribution activities in Canada and the U.S. along with ownership or access to another nine LPG terminals in North America. Petrogas' logistics network consists of over 3,000 rail car leases used entirely to support its transportation needs.

Gas Processing

Midstream processing activities are comprised of gathering systems that move natural gas on behalf of producers from the wellhead to AltaGas plants where impurities and certain hydrocarbon components are removed, and the gas is compressed to meet the operating specifications of downstream pipeline systems. AltaGas’ Midstream processing facilities serve customers primarily in the WCSB that deliver natural gas into downstream pipeline systems and can connect producers to the global export markets for LPG. AltaGas has a total net licensed processing capacity of approximately 2.2 Bcf/d, of which 18 percent is capable of processing sour gas. AltaGas operates all but three of its Midstream processing facilities. All AltaGas' processing facilities are capable of extracting NGLs. The main drivers of AltaGas' processing activities are throughput, inlet composition, 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, natural production declines in areas served by AltaGas’ processing facilities, and gas available on the main lines.

Townsend Complex

The Townsend facility, which is wholly owned by AltaGas, is a 396 MMcf/d gas processing facility located approximately 100 km north of Fort St. John and 20 km southeast of AltaGas’ Blair Creek facility. The majority of the processing capacity is contracted with Montney producers in the area under long-term take-or-pay agreements. In addition, the Townsend facility is able to provide NGL handling, treatment, and storage services to producers. Refer to the "Fractionation and Liquids Handling" section below.

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 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. This will add a 198 Mmcf/d C3+ deep cut gas processing capacity. The expanded facility will provide Kelt with firm processing of 75 Mmcf/d of raw gas under an initial 10 year take-or-pay agreement. The estimated project cost is approximately $165 million and includes a gas gathering pipeline that

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connects upstream fields to AltaGas' Townsend facility. Construction activities for the new facility are substantially complete and the project is on track to be commissioned in the first quarter of 2020.

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's Gordondale Montney development under a long-term take-or-pay contract. The plant is equipped with liquids extraction facilities to capture the NGL value for the producer.

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 Montney producers in the area.The plant is equipped with liquids extraction facilities to capture the NGL 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 and Nig Creek. Aitken Creek North is an operating shallow gas plant with current capacity of 110 Mmcf/d (55 Mmcf/d net). Nig Creek is a shallow gas plant with capacity of 100 Mmcf/d (50 Mmcf/d net) and came on-stream in the third 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 at the Townsend complex and North Pine facility. The Aitken Creek processing facilities are located in the liquids-rich Montney resource play in NEBC and are operated by Black Swan.

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 other NGLs.

The plant is adjacent to Nova Chemicals’ Joffre petrochemical complex and recovers ethane and other NGLs from the fuel gas used at the complex. All ethane production from JEEP is sold under a long-term, cost-of-service type contracts with Nova Chemicals. AltaGas delivers its NGL production to Harmattan Fractionation Plant for further processing. The resulting spec products are sold 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 licensed gross inlet capacity of 390 Mmcf/d of natural gas and gross production capacity of 30,000 Bbls/d of ethane and other NGLs.

The processed gas from the facility supplies end-use markets in the city of Edmonton, Alberta. Almost all of EEEP ethane production capacity is currently sold to ethane buyers under long-term fee-for-service contracts. The NGL production is delivered to a Fort Saskatchewan fractionator for further processing. AltaGas takes the resulting spec products in-kind and sells to North American and global markets, through RIPET, 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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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, and NGL extraction. In addition, Harmattan has fractionation and terminalling facilities (see the "Fractionation and Liquids Handling" section below). Harmattan’s raw natural gas supply is based on producer activity in the west‑central region of Alberta. Harmattan is well-positioned as the high-volume, low-cost processing facility in its service area.

At Harmattan, natural gas processing services are provided to approximately 70 producers under contracts with a variety of commercial arrangements and terms. 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 processing 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. The Co‑stream processing has resulted in increased utilization at the plant, with the added benefit that the equipment installed for the Co-stream process increases reliability and efficiency for both gas processing and Co-streaming customers. AltaGas entered into a 250 Mmcf/d cost-of-service Co-stream processing agreement with Nova Chemicals related to ethane and other 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 that 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 processing and extraction assets and a 50 percent interest in Younger's fractionation and terminalling assets (see the "Fractionation and Liquids Handling" section below). Younger has a license 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 plant operatorship. Younger processes natural gas transported on the West Coast transmission system and other regional transmission systems to recover NGLs. Natural gas supply to Younger is dependent on the amount of raw gas processed at the McMahon gas plant, which is based on the robust natural gas producing region of northeastern British Columbia.

Fractionation and Liquids Handling

Fractionation production is a function of NGL mix volumes processed, liquids composition, recovery efficiency of the plants, and plant on-line time. Due to the integration and inter-connectivity of AltaGas' Midstream assets, the fractionation and liquids handling activities provide integral services to the other Midstream segments and customers by providing access to high value NGL products with access to North American and global markets through rail networks, pipelines, RIPET, and the Ferndale terminal.

AltaGas' liquids handling infrastructure consists of NGL pipelines, treating, storage, truck and rail terminal infrastructure centered around AltaGas’ key Midstream operating assets at RIPET, Harmattan, and in NEBC, Townsend and North Pine.

In the NEBC area, a network of NGL pipelines connects upstream gas plant producers to AltaGas North Pine facility. The NEBC NGL pipelines consist of two liquids egress lines, with a third line under construction, connecting the Townsend facility to the Townsend truck terminal on the Alaska Highway (30 km) and AltaGas' North Pine facility (70 km). In addition, construction is underway to connect the Townsend complex, in the North, to Aitken Creek facilities through a 60 km NGL pipeline (Aitken

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Connector) and to the Tourmaline Gundy facility (Gundy Lateral), in the West, through a 15 km spec propane line. These NGL and spec propane pipelines are expected to be fully operational by the first quarter of 2020. In addition to the NGL pipelines, AltaGas liquids handling infrastructure consists of a 15,000 Bbls/d NGL treatment facility at the Townsend complex designed to process mercaptan rich NGL volumes delivered from the Townsend deep-cut plant and Aitken Connector.

North Pine Facility

The North Pine facility is the only custom fractionation plant in B.C., providing area producers with a lower cost, higher netback alternative for their NGLs than transporting and fractionating in Edmonton. 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 NGL mix. The construction is ongoing for the second NGL separation train capable of processing up to an additional 10,000 Bbls/d of 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 first quarter of 2020.

The North Pine facility is connected via the North Pine pipelines to the Townsend truck terminal which has a capacity of 10,000 Bbls/d and is contracted through long-term supply agreements with the producers at the Townsend and Aitken Creek facilities. The North Pine facility is also connected to the Tourmaline Gundy facility, and has access to the CN rail network, allowing for the transportation of propane, butane, and condensate to North American markets and propane to global markets via RIPET.

Harmattan

Harmattan has NGL fractionation capacity of 35,000 Bbls/d, a 450 Bbls/d capacity frac oil processing facility, and a 200 tonnes/d capacity industrial grade carbon dioxide (CO2) facility. Harmattan is the only deep‑cut and full fractionation plant in its operating area.

Fractionation services at Harmattan are provided under contracts with a variety of commercial arrangements and terms, typically fee-for-service revenues.

Harmattan fractionation services include a truck terminal for NGL mix delivered from adjacent plants in the area, as well as a rail terminal at Didsbury with a loading capacity of approximately 10,000 Bbls/d.

Younger

Effective April 1, 2018, AltaGas’ ownership was reduced to a 50 percent interest in Younger's fractionation, storage, loading, treating and terminalling of NGL, with the remaining interest held by Pembina. Pembina has also assumed plant operatorship. While Younger is the only straddle plant in its operating area, the Alliance pipeline competes for local natural gas supply.

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

Other Liquids Handling Services

To support LPG and NGL handling, AltaGas manages a rail logistics network consisting of approximately 1,200 rail cars. AltaGas is active in identifying opportunities to buy and resell 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.

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In addition, AltaGas' natural gas storage assets include a 50 percent ownership of the 5.3 Bcf Sarnia natural gas storage facility connected to the Dawn Hub in Eastern Canada, as well as the Alton Natural Gas Storage Project under construction.

Midstream 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 plants, which come from new well tie-ins and from reactivations, re-completions, and well optimizations performed by producers, are offset by natural production declines.

Gas Processing

Average processing facility utilization of core assets increased to 62 percent in 2019 from 60 percent in 2018 primarily due to the full year from the Aitken Creek North facility and the completion of the Nig Creek facility in the third quarter of 2019, partially offset by the lower volumes at Younger due to temporary outages during the year.

Fractionation

Average fractionation utilization of 69 percent in 2019 is lower than 70 percent utilization in 2018 due to lower volumes at Younger, partially offset by higher fractionation volumes at North Pine.

Significant Operating Areas and Customers

Global Exports

As LPG terminals operating on the west coast of North America, RIPET and the Ferndale terminal offer significantly reduced shipping times to the Asian LPG markets compared to the other North American LPG terminals. Both terminals are connected to the key North American hubs with rail networks.

Processing and Fractionation

Approximately 44 percent of AltaGas’ processing volumes are processed through the Townsend complex, Blair Creek facility, Gordondale facility, Aitken Creek facilities, and the Younger facility located in the liquids-rich Montney resource play in NEBC.

AltaGas has also fractionation capacity in the NEBC area through the North Pine and Younger facilities. The North Pine facility is interconnected to the Townsend complex, and 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.

The JEEP and EEEP facilities are strategically located and take advantage of the gas consumption by the petrochemical industry and the City of Edmonton. 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.

Midstream Contractual Arrangements

Global Exports

RIPET annual capacity is currently managed through a combination of merchant supply agreements and tolling arrangements. AltaGas' plans are to have the majority of RIPET's capacity to be underpinned by tolling arrangements with focus on creating an integrated value chain for AltaGas' customers in the WCSB from the wellhead to the global export markets. Currently, AltaGas has in place multi-year agreements for the purchase of approximately 50 percent of the propane expected to be shipped from RIPET each year.

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Processing and Fractionation

AltaGas gathers, processes and fractionates natural gas and NGL under contracts with natural gas producers. Subsequent to the sale of certain non-core Midstream assets in February 2019, there are approximately 100 active processing contracts. These contracts, in general:

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

▪ Establish operating costs flow through to the producers for a significant portion of the contracts;

▪ 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

▪ Establish processing fees at several facilities on a take-or-pay basis.

The majority of contracts in place at December 31, 2019 were subject to annual price escalation related to changes in CPI.

Where natural gas reserves have been dedicated under a 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 a 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 processing system for their entire productive lives.

Natural gas processing 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 NGL from the transporter’s natural gas. Ethane and NGL are extracted from the energy content of the shipper’s natural gas.

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.

Fractionation facilities charge a fee to separate NGL mix into specification propane, butane, and condensate.

Mountain Valley

AltaGas owns a 10 percent equity interest in Mountain Valley through WGL Midstream. 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 of natural gas 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. In August 2019, certain construction activities were voluntarily suspended, thereby shifting more mainline work into 2020. On October 15, 2019, FERC issued a project-wide order halting forward-construction progress, much of which was already deferred following the August 2019 voluntary suspension or was winding down for the winter season. The project is expected to be placed into service in late 2020.

As at December 31, 2019, project work is approximately 90 percent complete, which includes the completion of the three compressor stations and three certificated interconnects, as well as approximately 80 percent of the pipeline work. Despite

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the aforementioned delays, AltaGas' exposure is contractually capped to the original estimated contributions of approximately US$352 million. 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 lateral project to build an interstate natural gas pipeline (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 mid-2021.

Retail Energy Marketing - Natural Gas

AltaGas' retail gas marketing business 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, 2019, WGL Energy Services served approximately 101,600 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 jurisdictions in which it 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 North America (US), L.P. (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 2022.

Competition

To further increase utilization of AltaGas' existing assets and attract future growth, AltaGas' strategy is to provide fully-integrated Midstream services to its customers across the energy value chain, with higher producer netbacks resulting from access to higher value global energy markets, including Asia.

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Following RIPET reaching commercial operations, AltaGas is able, through its integrated infrastructure value chain, to connect Western Canadian producers from the wellhead to the global LPG markets via RIPET. Whilst AltaGas' integrated value proposition is unique in Western Canada, AltaGas is competing for LPG supply from the WCSB. Currently, RIPET and the Ferndale terminal, at approximately 90,000 Bbls/d capacity, account for approximately 35 percent of the LPG demand in the WCSB. The expectation of continued North American natural gas and LPG supply/demand imbalance combined with strong Asian demand is expected to maintain a robust pricing differential between North America and Asia. AltaGas' structural and locational advantage through RIPET and Petrogas through the Ferndale terminal will enhance producers' netbacks and compete with other North American LPG exports for LPG supply as AltaGas' global export operations continue to be optimized.

For natural gas processing services, AltaGas competes with integrated upstream natural gas exploration and production entities, as well as other midstream entities operating in the WCSB. In 2019, AltaGas processed an average of 1.4 Bcf/d, which is approximately 9 percent of volumes produced in the WCSB. The majority of WCSB processing capacity generally continues to be provided by the upstream natural gas exploration and production companies. With the ability to provide Western Canadian producers a fully integrated value chain, supported by liquids handling and global export capabilities, AltaGas is well positioned to compete for incremental throughput for its existing processing facilities and attract future growth.

AltaGas’ 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 providing producers with access to lower cost and higher netback alternatives for their NGL.

AltaGas' retail gas marketing and natural gas storage and transportation businesses compete 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 transportation assets. Operations can be positively or negatively affected by significant volatility in the wholesale price of natural gas. Accordingly, 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 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.

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Environmental Considerations Impacting the Midstream Business

The Midstream business is subject to the following environmental regulations:

Canadian Federal Air and GHG Regulations

Multi-Sector Air Pollutants Regulations

The Multi-Sector Air Pollutants Regulation 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 were 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.

AltaGas is currently focused on evaluating and implementing emissions reductions opportunities to reduce 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 expects to 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 took 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. The federal government has also proposed regulations setting out requirements to produce 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 combusted fossil fuels, currently priced at $20 per tonne of carbon emitted but increasing annually up 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, 2019, 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 exceed the threshold will continue to be regulated by the carbon pricing and reporting systems within those provinces. The carbon pricing schemes 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 took effect in April 2019. Alberta challenged the constitutionality of the federal government's pricing regime and the Alberta Court of Appeal ruled that the federal legislation is unconstitutional. The Supreme Court of Canada is scheduled to hear arguments regarding the federal carbon levy in March 2020.

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Federal Greenhouse Gas Reporting Program (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, 2019, ten facilities within the Midstream segment reported to the GHGRP as a result of the lower reporting threshold.

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 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 can 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 Gordondale facilities are considered large final emitters under the CCIR and as at December 31, 2019, were compliant with the regulation.

TIER

In October 2019, the Alberta Government announced that the TIER Regulation will replace the Carbon Competitiveness Incentive Regulation on January 1, 2020. It will automatically apply to facilities that produce 100,000 tonnes or more of emissions per year. Facilities under this threshold will have the option to voluntarily become a regulated facility under TIER by becoming an aggregate facility. Emission reduction obligations under TIER are determined according to a facility specific benchmark approach, and high-performance benchmark approach. Under the facility specific benchmark methodology, a facility is required to reduce emissions intensity by 10 percent relative to the facility's historical production weighted average emissions intensity. The stringency of the facility specific benchmark will increase by 1 percent annually beginning in 2021. High performance benchmarks are set to the average emission intensity of the most efficient facilities producing each benchmarked product over selected reference years.

TIER provides regulated facilities with the same compliance options available to them, as they did under the CCIR. Emission performance credits and emissions offsets combined may not be used to satisfy more than 60 percent of the facility's total obligations for a single compliance year. TIER will also maintain the credit expiry timeline for emission performance credits and offsets, where credits will expire eight years after creation.

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The Government of Canada will apply the federal fuel charge in Alberta beginning January 1, 2020 under the Greenhouse Gas Pollution Pricing Act (GGPPA). The charge will apply to all fossil fuels used in Alberta, including those in the oil and gas sector, that previously had been given a carbon tax exemption until 2023 under the previous provincial administration, while the province focused on methane reduction. The GGPPA includes provisions to exempt facilities subject to provincial policies that meet the federal benchmark criteria. The TIER program has been designed to meet federal requirements and protect regulated facilities from the full costs of complying with the GGPPA, while achieving emission reductions using an approach that is cost efficient and tailored to Alberta's industry.

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 are effective 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. These operational requirements could result in significant equipment retrofit, equipment replacement, advanced planning, and investment to ensure compliance. In addition, companies are also required to have in place a fugitive emissions management program that must be designed to reduce fugitive emissions over time to achieve the 45 percent reduction target relative to 2014 levels. Companies will also be required to conduct leak detection surveys at their facilities at a prescribed frequency (annually or tri-annually) based on equipment or facility type. 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, 2019, are in compliance with the Greenhouse Gas Emission Reporting Regulation.

Methane Reduction

On December 17, 2018, the Board of the Oil and Gas Commission amended the Drilling and Production Regulation in B.C. The amended schedule is effective January 1, 2020. Amendments to the regulation included Leak Detection and Repair. A facility permit holder in B.C. will be required to conduct leak detection surveys at their facilities at a prescribed frequency (annually or tri-annually) based on equipment or facility type.

Detected leaks at a facility identified during a survey must be repaired within 30 days or, if the repair requires the facility to be shut down, then the repair must be completed at the next turnaround. Records of the surveys at a facility must be maintained and include date of survey and method used, leak rate for any leak detected, and leak repair information.

In addition to the above requirements, the amended regulations contain various natural gas vent gas limits or restrictions on the following types of equipment: tanks, compressors, gas conservation equipment, pneumatic devices, pneumatic pumps and compressor starters and glycol dehydrators. These equipment specific natural gas vent limits may result in equipment retrofit or replacement.

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Carbon Tax Act

B.C.’s carbon tax is currently set at $40 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.

CleanBC

On December 5, 2018, the Government of British Columbia announced an updated clean energy plan, "CleanBC", which seeks to ensure that B.C. achieves 75 percent of its GHG emissions reduction target by 2030. The CleanBC plan includes a number of strategies targeting the industrial, transportation construction, and waste sectors of the B.C. economy. Key initiatives include: i) increasing the generation of electricity from clean and renewable energy sources; ii) imposing a 15 percent renewable content requirement in natural gas by 2030; iii) requiring fuel suppliers to reduce the carbon intensity of diesel and gasoline by 20 percent by 2030; iv) investing in the electrification of crude oil and natural gas production; v) reducing 45 percent of methane emissions associated with natural gas production; and vi) incentivizing the adoption of zero-emissions vehicles. The 2019 provincial budget provided $902 million over three years to support CleanBC, including electric vehicle rebates, incentives for making homes and businesses more energy efficient, and an enhanced climate action tax credit.

AltaGas Ltd. – 2019 Annual Information Form –44

POWER BUSINESS

AltaGas’ Power business contributed revenue of $1.4 billionfor the year ended December 31, 2019 (2018 - $1.2 billion), representing approximately 25 percent (2018 – 27 percent) of AltaGas’ total revenue before Corporate segment and intersegment eliminations.

AltaGas Ltd. – 2019 Annual Information Form –45

The Power business is engaged in the generation and sale of capacity, electricity, ancillary services, and related products in Alberta, California, and Colorado. After the sale of the WGL distributed generation business in September 2019, biomass assets in August 2019, non-core Canadian power assets in February 2019, and the remaining 55 percent interest in the Northwest Hydro facilities in January 2019, AltaGas has 710 MW of installed power capacity from a combination of gas-fired, energy storage, and remaining distributed generation assets, as more particularly set forth in the below table:

Facility	Interest (%)	Capacity (MW)	Type	Geographic Region	Contracted Expiry Date
Blythe	100	507	Gas-fired	California, U.S.	2023
Brush II	100	70	Gas-fired	Colorado, U.S.	2019
Ripon	100	50	Gas-fired	California, U.S.	n/a
Pomona Energy Storage	100	20	Storage	California, U.S.	2027
Cogeneration I	100	15	Gas-fired	Alberta, Canada	n/a
Cogeneration II	100	15	Gas-fired	Alberta, Canada	n/a
Cogeneration III	100	15	Gas-fired	Alberta, Canada	n/a
Gordondale	100	3	Gas-fired	Alberta, Canada	n/a
Distributed Generation	100	15	Various	Various regions in the U.S.	Various
TOTAL		710

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

	2019	2018
Renewable power sold (GWh)	616	1,551
Conventional power sold (GWh)	1,793	3,728
Renewable capacity factor (%)	17.7	29.7
Contracted conventional equivalent availability factor (%) (1)	75.4	97.2
WGL retail energy marketing – electricity sales volumes (GWh)	13,218	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.

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 California Independent System Operator (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 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 2019,AltaGas announced the successful recontracting of the Blythe facility to SCE. Under the tolling agreement, SCE has exclusive rights to all capacity, energy, ancillary services, and resource adequacy benefits from August 1, 2020 to December 31, 2023. California Public Utilities Commission approval was received on January 16, 2020.

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 has negotiated resource adequacy contracts that include the majority of 2020. In Colorado, the Brush II facility was contracted until December 31, 2019.

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 cogeneration facilities are located at AltaGas' Midstream Harmattan facility and 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.

AltaGas Ltd. – 2019 Annual Information Form –46

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. In addition, AltaGas is in the initial stages of permitting a new 40MW stand-alone energy storage project in Goleta, California.

Retail Energy Marketing – Power

As at December 31, 2019, WGL Energy Services served approximately 98,200 residential, commercial, and industrial electricity customer accounts located in Maryland, Virginia, Delaware, Pennsylvania, Ohio, and the District of Columbia. WGL Energy Services does not own or operate any other electric generation, transmission, or distribution assets. See "Midstream Business – WGL Midstream - U.S. Midstream Retail Energy Marketing" for further information on WGL Energy Services.

Competition

All of the power produced in Alberta and not used by the Harmattan facility 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.

With the approval of the new PPA with SCE by CPUC in January 2020, the Blythe Energy Center is contracted under a PPA until December 31, 2023. Under the tolling agreement(s), SCE has exclusive rights to all capacity, energy, ancillary services, and resource adequacy benefits during the PPA term. Ripon was contracted by PG&E under a PPA until May 31, 2018, following which AltaGas has been successful in securing resource adequacy contracts that include the majority of 2020.

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 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.

AltaGas Ltd. – 2019 Annual Information Form –47

Environmental Considerations Impacting the Power Business

The Power business is subject to the following environmental regulations:

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, 2019, 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.

California GHG Regulations

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, 2019, 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 on 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). 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. It is uncertain whether or how SGMA may impact water supplies for AltaGas’ power generation facilities in California.

AltaGas Ltd. – 2019 Annual Information Form –48

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, 2019, the revenue for the Corporate segment was less than $1 million excluding intersegment eliminations and risk management and trading activities (2018 – less than $1 million). In addition, as at December 31, 2019, AltaGas held approximately 4 percent of the common shares of Painted Pony through the Corporate segment.

AltaGas Ltd. – 2019 Annual Information Form –49

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, 2019, AltaGas had 279,074,685 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, 6,885,823 outstanding Series G Shares, 1,114,177 Series H Shares, 8,000,000 outstanding Series I Shares, and 12,000,000 outstanding Series K Shares.

Washington Gas redeemed the Washington Gas $4.25 Series, Washington Gas $4.80 Series, and Washington Gas $5.00 Series Preferred Shares on December 20, 2019.

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.

AltaGas Ltd. – 2019 Annual Information Form –50

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)
Series A Shares (5)	3.38	%		$0.845		$25	September 30, 2020	Series B
Series B Shares (6) (7)	Floating		Floating			$25	September 30, 2020	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)	4.62	%		$1.1558		$25	September 30, 2024	Series H
Series H Shares (6) (7)	Floating		Floating			$25	September 30, 2024	Series G
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

(1) This table only includes those series of preferred shares that are currently issued and outstanding. The Corporation is authorized to issue up to8,000,000of each of Series D Shares, Series F Shares, and Series J Shares, and up to12,000,000of 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 J Shares, and Series L Shares are also redeemable for$25.50, and Series D Shares are redeemable forUS$25.50on 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 and Series H 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 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 of Series A Shares, Series E Shares, and Series G Shares 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 plus2.66 percent(Series A Shares),3.17 percent(Series E Shares), and3.06 percent(Series G Shares).

(6) Holders of Series B Shares and Series H 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 plus2.66 percent(Series B Shares) and3.06 percent(Series H Shares). 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, 2019, the floating quarterly dividend rate is$0.26803per share for Series B Shares and$0.29289per share for Series H Shares for the period starting December 31, 2019 to, but excluding, March 31, 2020.

(7) Series B Shares can be redeemed for$25.50per 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. Series H Shares can be redeemed for$25.50per share on any date after September 30, 2019 that is not a Series H 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 plus3.58 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 plus0.0419, provided that, in any event, such rate shall not be less than5.25 percentper 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 plus3.80 percent, provided that, in any event, such rate shall not be less than5.00 percentper 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 parity with Preferred Shares of every other series with respect to accumulated dividends and return of capital and the holders

AltaGas Ltd. – 2019 Annual Information Form –51

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 66⅔ 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 prospectus supplement of AltaGas dated August 11, 2010; (ii) Series C Shares and the Series D Shares, reference should be made to the prospectus supplement of AltaGas dated May 30, 2012; (iii) Series E Shares and Series F Shares, reference should be made to the prospectus supplement of AltaGas dated December 6, 2013; (iv) Series G Shares and Series H Shares, reference should be made to the prospectus supplement of AltaGas dated June 25, 2014; (v) Series I Shares and Series J Shares, reference should be made to the prospectus supplement of AltaGas dated November 16, 2015; and (vi) Series K Shares and Series L Shares, reference should be made to the prospectus supplement of AltaGas dated February 15, 2017. The articles of the corporation and each of the prospectus supplements described herein have 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 16 to AltaGas’ audited Consolidated Financial Statements as at and for the year ended December 31, 2019 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 16 in AltaGas’ audited Consolidated Financial Statements as at and for the year ended December 31, 2019.

GENERAL

Employees

At December 31, 2019, there were 2,801 individuals employed by AltaGas.

	December 31, 2019
Utilities	2,186
Midstream	295
Power	139
Corporate	181
Total	2,801

Directors and Officers

As at February 21, 2020, the directors and executive officers of AltaGas Ltd., as a group, owned beneficially, directly or indirectly, or exercised control or direction over 1,839,094 of the outstanding Common Shares, or approximately 0.66 percent of the 279,425,083 Common Shares issued and outstanding.

AltaGas Ltd. – 2019 Annual Information Form –52

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 ten 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, unless the term ends earlier in the event of death, resignation, or removal, disqualification or 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 21, 2020, 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
Victoria A. Calvert(1) Calgary, Alberta, Canada Director	Ms. Calvert is a Corporate Director and Professor Emerita of Business at Mount Royal University in Calgary, where she taught from 1988 to 2018. She was also a Director of the Canadian Alliance of Community Service Learning from 2009 to 2017.	November 1, 2015
David W. Cornhill (1) (2) Calgary, Alberta, Canada Director	Mr. Cornhill is a founding shareholder of AltaGas and its predecessors. Mr. Cornhill was Chief Executive Officer from 1994 to 2016 and served as interim Co-CEO from July to December 2018. He was Chairman of the Board from 1994 to April 2019. 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 (3) 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
Daryl H. Gilbert (1) (4) 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) (5) Calgary, Alberta, Canada Director	Mr. Hodgins is a Chartered Professional Accountant and Chartered Accountant and has been an independent businessman since November 2004. Mr. Hodgins has been a Senior Advisor, Investment Banking for Canaccord Genuity Corp. since September 2018. Mr. Hodgins served as the Chief Financial Officer of Pengrowth Energy Trust 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

AltaGas Ltd. – 2019 Annual Information Form –53

Name of Director, Municipality of Residence, and Position	Principal Occupation During the Past Five Years	Director Since
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 Chair of the Board	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) 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 from July to December 2018. He was CEO of Corridor Resources Inc. from October 2010 to September 2014. Prior thereto, Mr. Knoll 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(3) Santa Fe, New Mexico, USA Director	Mr. McCallister is an independent businessman. He 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
Linda G. Sullivan(1) Mullica Hill, New Jersey, USA Director	Ms. Sullivan is a Corporate Director. She was Executive Vice President and Chief Financial Officer at American Water Works Company, Inc. from 2016 until 2019, and prior thereto was Senior Vice President and Chief Financial Officer from 2014. Prior to joining American Water Works, she held various roles with the Edison International companies, including Senior Vice President and Chief Financial Officer at Southern California Edison Company.	January 9, 2020
Nancy G. Tower(1) Tampa, Florida, USA Director	Ms. Tower is the President and Chief Executive Officer of Tampa Electric Company, a regulated electric utility and a subsidiary of Emera Inc. (Emera) in Tampa, Florida, a position she has held since December 2017. Prior thereto, she was the Chief Corporate Development Officer of Emera from 2014 to 2017. Ms. Tower joined Emera in 1997, and held several senior positions at Emera and with its subsidiaries, including Controller and Vice President, Customer Operations of Nova Scotia Power Inc., Chief Financial Officer of Emera, and Chief Executive Officer of Emera Newfoundland and Labrador.	January 9, 2020

(1) Independent director. 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, however the interim role did not impact their independence.

(2) Mr. Cornhill is no longer deemed to be in a material relationship with the Corporation as it has been three years since he retired from his executive position and he has been determined to be independent under National Instrument 52-110.

(3) Mr. Crawford, as current CEO of the Corporation, is not considered independent. Mr. McCallister, as former CEO of a major subsidiary of the Corporation until July 6, 2018, is deemed to be a non-independent director until the third anniversary of that date.

(4) 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 by 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

AltaGas Ltd. – 2019 Annual Information Form –54

continued listing requirements. On February 16, 2019 Connacher announced that it was proceeding to close on a credit bid transaction with its supporting lenders. Mr. Gilbert was a director of Trident Exploration Corp. (Trident) from 2010 to 2018. On April 30, 2019, Trident ceased operations and transferred all its assets to the Alberta Energy Regulator.

(5) 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.

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 February 21, 2020 are identified below:

Director	Audit Committee	Governance Committee	HRC Committee	EH&S Committee
Victoria A. Calvert		n	n
David W. Cornhill
Allan L. Edgeworth	n		Chair
Daryl H. Gilbert			n
Cynthia Johnston	n			Chair
Pentti O. Karkkainen
Robert B. Hodgins	Chair	n
Phillip R. Knoll		Chair		n
Terry D. McCallister				n
Linda G. Sullivan	n		n
Nancy G. Tower	n		n

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Executive Officers

The names, municipality of residence and position of each of the current executive officers of AltaGas 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.
D. James Harbilas Calgary, Alberta, Canada Executive Vice President and Chief Financial Officer	Executive Vice President and Chief Financial Officer of AltaGas from June 2019. Prior to joining AltaGas, Mr. Harbilas was the Executive Vice President and Chief Financial Officer of Enerflex Ltd. from 2007.
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.
Donald M. Jenkins Washington, DC, U.S.A. Executive Vice President and President Utilities, President of Washington Gas Light Company	Executive Vice President and President, Utilities of AltaGas from December 2019. President of WGL and Washington Gas from December 2019. Prior thereto, Mr. Jenkins was with EQT Corporation from 2012, most recently as Chief Commercial Officer.
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 from 2014 to 2015. Various executive commercial roles in EQT’s Distribution, Midstream and Energy Services companies since joining EQT in 2003.
Randy W. Toone Calgary, Alberta, Canada Executive Vice President and President, Midstream	Executive Vice President and President, Midstream 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 and Chief Legal Officer of AltaGas since July 2018. 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.

Audit Committee

Composition of the Audit Committee

The Committee is currently comprised of five members, Allan Edgeworth, Robert Hodgins, Cynthia Johnston, Linda Sullivan and Nancy Tower. 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

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

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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 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 a Chartered Accountant in Ontario and Alberta. He has served on a number of public company audit committees.

Ms. Johnston 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. Prior thereto, Ms. Johnston held various executive leadership positions with TransAlta and FortisAlberta. She served on the Finance, Audit and Risk Committee of the Lethbridge College Board of Governors from 2011 to 2014 and as chair from 2013 to 2014.

Ms. Sullivan was Executive Vice President and Chief Financial Officer at American Water Works Company, Inc. from 2016 until 2019, and prior thereto was Senior Vice President and Chief Financial Officer from 2014. Prior to joining American Water Works, she held various roles with the Edison International companies, last serving as Senior Vice President and Chief Financial Officer at Southern California Edison Company from 2009 to 2014. Ms. Sullivan has over 25 years of utility finance and regulatory experience. She has received her Certified Public Accountant and Certified Management Accountant designations in 1991 and 1996, respectively. Ms. Sullivan holds a Bachelor of Science in Business Administration and Accounting from Portland State University. Ms. Sullivan is the chair of the audit committee at NorthWestern Energy Corp., a U.S. public company.

Ms. Tower currently serves as President and Chief Executive Officer of Tampa Electric Company, a regulated electric utility and a subsidiary of Emera Inc. (Emera) in Tampa, Florida (TECO Energy), a position she has held since December of 2017. Prior thereto, she was the Chief Corporate Development Officer of Emera from 2014 to 2017. Since joining Emera in 1997, Ms. Tower has held several senior positions in corporate finance and in operations at Emera and with its subsidiaries, including Controller and Vice President, Customer Operations of Nova Scotia Power Inc., Chief Financial Officer of Emera, and Chief Executive Officer of Emera Newfoundland and Labrador. Ms. Tower holds a Bachelor of Commerce from Dalhousie University and received her Fellow Chartered Accountant designation in 1985.

Pre-Approval Policies and Procedures

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

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External Auditor Service Fees by Category

The fees billed by Ernst & Young LLP (E&Y), AltaGas’ external auditor, during 2019 and 2018 were as follows:

Category of External Auditor Service Fee (1)		2019		2018
Audit fees	$	7,783,502	$	2,766,074
Audit-related fees (2)		833,268		1,242,606
Tax compliance fees (3)		259,313		66,389
All other fees (4)		357,002		86,970
Total	$	9,233,085	$	4,162,039

(1) Due to the timing of appointing E&Y as WGL's auditor, $3.7 million of fees relating to 2018 were paid in 2019.

(2) 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 2019 and 2018, 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); review of pro forma consolidated financial statements; review of new accounting standards implementation; internal controls assessment; cost allocation manual audits; environmental, social, and governance services; and registration costs for the Canadian Public Accountability Board, the Public Company Accounting Oversight Board, and the Financial Accounting Standards Board.

(3) During 2019 and 2018, the nature of the services provided was for tax compliance and transfer pricing.

(4) Represents 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 2019 and 2018, the nature of the services provided was for translation services and an assessment of AltaGas' IT risk management and cyber security.

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 2, 2019 and will also be included in AltaGas’ management information circular for its 2020 annual meeting of the Shareholders.

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 carry 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, in the Utilities business, with support from each of certain regulatory commissions, AltaGas is accelerating the replacement of aging pipeline infrastructure prioritized on a risk-based approach and has implemented

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preventive and remedial measures to address increased leak rates in its distribution system caused by an 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.

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, constraints on natural resource development, delay of or restrictions for projects due to climate change policies and initiatives, protests, activist activity, 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 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.

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 utilities 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.

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.

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.

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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 to afford the utilities the opportunity to earn their 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, 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. Changes to regulatory and environmental laws could increase AltaGas’ operating costs and require enhanced disclosures. Increased expenditures could include capital expenditures, operating expenditures, and decommissioning, abandonment, and reclamation costs, which may not be recoverable in the marketplace or through rate cases. These changes could adversely affect AltaGas, resulting in current operations and projects becoming less profitable or uneconomic and could require significant investment to develop new technologies.

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 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.

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.”

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 and the U.S. Utilities. 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. See the section "Environmental Regulation", "Business of the Corporation – Utilities Business – Environmental Regulations Impacting the Utilities Business".

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Climate 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" 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, 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.

Reputation

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 peoples. There is an increasing level of public concern and scrutiny 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 overall environmental performance, emissions, 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 peoples may ultimately impact AltaGas, including its ability to obtain or maintain permits, the anticipated timing and costs associated with capital projects, its operations, shareholder confidence, 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" below. 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.

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 customers. Similarly, the business of AltaGas’ Midstream business is seasonal due to the tendency of storage and transportation spreads to increase during the winter. 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.

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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, and the operations of RIPET in British Columbia, 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. 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 peoples 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.

Changes in Laws

Applicable laws, including, without limitation, international trade laws and tariffs, 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. Concerns over climate change, including GHG emissions, fossil fuels, and land use, could lead to the introduction of additional or more stringent laws and regulation that would impact AltaGas, increasing AltaGas' exposure to legal risk.

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.

The Utilities 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

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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.

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.

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 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.

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.

A 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 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 its contracts, and (ii) entering into and maintaining ordinary course contracts with customers and suppliers on acceptable terms.

Additionally, with respect to WGL, a reduction in credit rating could lead to higher borrowing costs. Merger-related commitments placed limitations on Washington Gas' ability to recover increased costs of financing from customers if caused by the merger or the ongoing affiliation of AltaGas and its affiliates. Therefore, a downgrade in AltaGas' or WGL's credit ratings 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

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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' functional currency is the Canadian dollar. AltaGas is exposed to foreign exchange risk through its investments in the U.S. and is exposed to foreign exchange risk in the LNG and LPG export business. Changes in the Canadian dollar/U.S. dollar exchange rate could impact the earnings of AltaGas, the value of the U.S. investments, and the cash generated from the U.S. 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 Financing, Refinancing, and Debt Service

AltaGas relies on debt financing for some of its business activities, including capital and operating expenditures. The credit facilities and long-term senior unsecured notes have defined terms and there are no assurances that AltaGas will be able to refinance any or all of the borrowings at their maturity. In addition, there are no assurances that AltaGas will be able to comply at all times with the covenants applicable under its current borrowings, nor are there assurances that AltaGas will be able to secure new financing that may be necessary to finance its operations and capital growth program. Any failure of AltaGas to secure refinancing, to obtain new financing, or to comply with applicable covenants under its borrowings could have a material adverse effect on AltaGas' financial results, including its ability to maintain dividends to Shareholders. Further, any inability of AltaGas to obtain new financing may limit its ability to support future growth.

Borrowings or additional borrowings made by or on behalf of AltaGas will affect the leverage of the business. Interest and principal payments on such borrowings will take precedence over cash dividends to Shareholders and may increase the level of financial risk in the operations of AltaGas. AltaGas’ debt prohibits the payment of dividends at any time at which a default or event of default would exist under such debt, or if a default or event of default would exist as a result of paying a dividend.

If AltaGas is unable to refinance debt obligations at the time of maturity or is unable to refinance on equally favorable terms, the level of cash dividends to Shareholders may be affected. Details regarding the maturity dates of debt facilities can be found in Note 16 to AltaGas' audited Consolidated Financial Statements as at and for the year ended December 31, 2019.

AltaGas believes that the existing credit facilities will be sufficient for its immediate requirements and has no reason to believe that it will not be able to renew its existing credit facilities or refinance its long-term senior unsecured notes on commercially reasonable terms. However, continued uncertainty in the global economic situation means AltaGas, along with other energy companies, may have restricted access to capital and increased borrowing costs. AltaGas’ ability to raise debt is dependent upon, among other factors, the overall state of the capital markets, the quality of AltaGas’ public credit ratings, and investor appetite for investments in the energy industry and AltaGas’ securities in particular. The ability to make scheduled payments on or to refinance debt obligations depends on the financial condition and operating performance of AltaGas, which is subject to prevailing economic and competitive conditions and to certain financial, business, and other factors beyond its control. As a result, AltaGas may be unable to maintain a level of cash flow from operations sufficient to permit it to pay the principal, premium, if any, and interest on its indebtedness. These conditions could have an adverse effect on the industry in which AltaGas operates and its business, including future operating and financial results. There can be no assurance that AltaGas’ cash flow will be adequate for future financial obligations or that additional funds will be able to be obtained.

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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.

Some of our indebtedness, including borrowings under our revolving credit agreement, bears interest at a variable rate based on LIBOR. In July 2017, the United Kingdom Financial Conduct Authority (FCA), which regulates LIBOR, announced that the FCA intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. It is not possible to predict the effect of these changes, other reforms or the establishment of alternative reference rates in the United Kingdom or elsewhere.

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-attacks 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 its employees and proprietary information in respect of its 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, 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.

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.

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

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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 peoples, 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.

Growth Strategy Risk

During 2019, AltaGas made significant changes to its business, including 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 2020 and onwards will not be as successful as projected.

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 AltaGas' projects or disrupt operations on these projects, which could have an adverse effect on AltaGas’ financial results.

RIPET Rail and Marine Transportation

Propane is transported from natural gas producers to RIPET using the existing CN rail network and is delivered to customers by marine transport. Rail shipments and marine shipments may be impacted by protests, activist activities, strikes, service delays, inclement weather, rail car availability, rail car derailment, or other rail or marine transport incidents and could adversely impact volumes or the price received for product or impact its 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

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of new regulations, AltaGas’ business, operations, and financial condition may be adversely impacted. In addition, in instances where the rail transport is not available, AltaGas may not be able to procure substitute transportation and, as a result, may experience an adverse impact on its operations at RIPET or other assets.

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 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.

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.

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, and weakened overall North American natural gas prices, 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.

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.

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Collateral

AltaGas is able to obtain unsecured credit limits from 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.

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.

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.

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.

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.

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’

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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.

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 and stakeholder 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.

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.

In addition, Washington Gas, SEMCO Gas, and ENSTAR 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.

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Risk Management Costs and Limitations

AltaGas uses derivative financial instruments to hedge risks associated with exchange rates, interest rates, and commodity price fluctuations. AltaGas does not enter into derivatives transactions for speculative purposes. AltaGas' derivative 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 AltaGas' business, operations, and financial condition.

In addition, rules implementing the derivatives transaction provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) in the U.S. 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. Requirements of 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 may entitle AltaGas to exemptions from reporting obligations, there can be no assurance that AltaGas will be able to continue to rely on such exemptions for all transactions. In order to ensure its compliance with such obligations, AltaGas is required to incur the time and financial expense associated with maintaining the systems necessary to report its derivatives trades to a derivatives trade repository, 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.

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.

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 south central 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.

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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.

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.

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.

Labor Relations

The operations and maintenance staff at the Blythe Energy Center and Younger, as well as some employees of Washington Gas and SEMCO Energy, are members of a labor union. Aspects of RIPET’s operations are also performed by employees that are members of a labor union. Labor disruptions could restrict the ability of 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 (loss).

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 labor 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 U.S. 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.

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

Beginning in 2019, the Corporation’s internal control over financial reporting were 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.

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.

ENVIRONMENTAL, HEALTH, SAFETY, AND SOCIAL POLICIES

Values

AltaGas' core values form the foundation from which AltaGas does business with its customers, partners, and other stakeholders, and serve as a blueprint to fulfill the Company's vision and strategy. AltaGas' core values are:

▪ Work Safely, Think Responsibly;

▪ Act with Integrity;

▪ Make Informed Decisions;

▪ Achieve Results; and

▪ Invest in our People and Foster Diversity.

These core values reinforce AltaGas' commitment to integrating strong environmental, health and safety, social, and governance performance into all aspects of the business. These efforts support AltaGas' business strategy by allowing the Corporation to be more responsive to customer needs; better manage risks; and attract, motivate, and retain the talent we need to bring value to the communities we serve.

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By balancing economic priorities with its social and environmental values, AltaGas can help meet growing global demands for clean energy, while continuing to deliver sustainable benefits to its shareholders. AltaGas is committed to the following:

▪ Operating its business with the highest regard for safety for its employees, contractors, and stakeholders;

▪ Protecting the environment and minimizing its impact;

▪ Building long-term, mutually beneficial relationships with Indigenous peoples, partners, and communities;

▪ Working closely with governments and regulatory agencies to develop long-term sustainable projects; and

▪ Investing in communities through employment and training opportunities and donations to charitable organizations.

Environment, Health and Safety

The Board of Directors has established the EH&S Committee to review, monitor, and make recommendations to the Board of Directors regarding Environment, Health and Safety strategy, policy, compliance, and risk.

AltaGas' Environment, Health and Safety (EHS) policy guides its commitment to managing and minimizing its environmental impacts. Its EHS standards set expectations and parameters that apply consistently across the organization and provide a framework to reinforce our safety culture. This includes implementing programs that safeguard its people and the environment, proactively identifying and managing risks, and applying lessons learned and best practices to improve its performance. AltaGas’ EHS Management System provides a framework that establishes enterprise-wide requirements and expectations, and outlines actions and accountabilities for EHS-related performance within a Plan-Do-Check-Act cycle. Each business division is responsible for its internal policies and continuous improvement within this framework.

To ensure AltaGas is prepared and its teams are equipped to quickly and safely respond to emergency situations, it maintains comprehensive emergency response plans for each of its facilities, and for all lines of business. It conducts regular emergency response exercises, which are often coordinated with local first responders. These exercises offer a better understanding of each party's roles and responsibilities in the event of an emergency, resulting in a more effective response.

Policies

AltaGas has a number of policies in place with respect to environmental stewardship, health and safety, and social responsibility. Notably, AltaGas’ Code of Business Ethics (COBE) ensures it upholds its core values and conducts business in a safe, respectful, and ethical manner. The COBE is applicable to its people, contractors, suppliers, and partners, and is approved, along with its policies, by the Board. To ensure adherence to the COBE, all employees are required to review it and its related policies, and certify their understanding and compliance, on an annual basis. AltaGas' COBE related policies include:

▪ Whistleblower;

▪ Respectful Workplace;

▪ Privacy;

▪ Environment, Health and Safety;

▪ Drugs and Alcohol in the Workplace;

▪ Information Security;

▪ Social Media and Acceptable Use;

▪ Disclosure;

▪ Conflicts of Interest;

▪ Anti-Bribery and Anti-Corruption; and

▪ Securities Trading and Reporting.

In December 2019, AltaGas released its inaugural Environmental, Social & Governance (ESG) Report, highlighting its 2018 performance in several key areas relevant to the long-term sustainability of its business, and demonstrating its ongoing commitment to transparency. The report can be found on AltaGas’ new ESG microsite, www.ESGatAltaGas.ca.

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 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 are 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 – Reputation", "Risk Factors – Regulatory", "Risk Factors – Climate 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 – Utilities Business – Environmental Regulations Impacting the Utilities Business", "Business of the Corporation – Midstream Business – Environmental Regulations Impacting the Midstream Business", and "Business of the Corporation – Power Business – Environmental Regulations Impacting the Power Business" of this AIF.

U.S. Federal Air and GHG Regulations

Greenhouse Gas Reporting Program (U.S. GHGRP)

The U.S. 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 U.S. GHGRP. Facilities determine whether they are required to report based on the types of industrial operations

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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; or

▪ 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 U.S. GHGRP.

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 how the Corporation develops 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 the 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 H, Series I Shares, and Series K Shares are paid quarterly.

On December 20, 2019, Washington Gas redeemed the Washington Gas $4.25 Series, Washington Gas $4.80 Series, and Washington Gas $5.00 Series Preferred Shares.

AltaGas Ltd. – 2019 Annual Information Form –74

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.

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 period from the close of the WGL Acquisition until redemption on December 20, 2019.

$ per share	2019	2018	2017
Common Shares	0.960000	2.190000	2.107500
Series A Shares	0.845000	0.845000	0.845000
Series B Shares	1.084641	0.968620	0.806380
Series C Shares (1)	1.322500	1.322500	1.155625
Series E Shares	1.348252	1.250000	1.250000
Series G Shares	1.155750	1.187500	1.187500
Series H Shares	0.296040	—	—
Series I Shares	1.312500	1.312500	1.312500
Series K Shares	1.250000	1.250000	1.063400
Washington Gas $4.25 Series (1)	2.125000	2.125000	—
Washington Gas $4.80 Series (1)	2.400000	2.400000	—
Washington Gas $5.00 Series (1)	2.500000	2.500000	—

(1) Amounts disclosed are in U.S. dollars. Washington Gas preferred shares were redeemed on December 20, 2019.

Dividend Reinvestment And Optional Cash Purchase Plan

Effective May 17, 2016, AltaGas replaced, in its entirety, its dividend reinvestment plan with the Premium Dividend^TM, Dividend Reinvestment and Optional Cash Purchase Plan (the Plan). The Plan consists oftwocomponents:a Dividend Reinvestment component and an Optional Cash Purchase component. The Premium Dividend™ component of the plan was suspended in December 2018. The Dividend Reinvestment and Optional Cash Purchase component was suspended in December 2019, with the December dividend (payable January 2020) being the last dividend payment eligible for reinvestment by participating shareholders under the DRIP. The Plan in its entirety will remain suspended until further notice.

The Plan provided eligible holders of Common Shares with the opportunity to, at their election, reinvest the cash dividends paid by AltaGas on their Common Shares towards the purchase of new Common Shares at a3 percentdiscount 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).

In addition, the Plan provided 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 was 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 the10 business daysimmediately 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 (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.

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 2019 as reported by the TSX:

Month	High	Low	Volume Traded
January	14.59	13.25	25,633,918
February	17.81	13.39	31,157,366
March	18.12	17.31	19,120,605
April	18.65	17.46	15,089,861
May	19.76	17.58	16,373,266
June	20.25	18.96	12,156,609
July	20.87	19.57	12,997,597
August	20.55	17.72	17,093,887
September	20.00	17.65	13,670,419
October	19.97	17.91	18,450,569
November	20.39	18.85	21,119,986
December	20.18	18.57	17,785,590

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 2019 as reported by the TSX:    

Month	High	Low	Volume Traded
January	15.15	13.80	715,599
February	15.40	14.10	166,437
March	15.75	13.52	247,072
April	14.30	13.97	139,921
May	14.75	14.01	229,061
June	14.22	13.14	205,426
July	14.86	13.75	176,656
August	14.71	12.44	145,224
September	14.35	13.00	135,240
October	15.01	13.52	154,165
November	15.16	14.28	315,794
December	15.35	14.58	117,013

AltaGas Ltd. – 2019 Annual Information Form –75

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 2019 as reported by the TSX:

Month	High	Low	Volume Traded
January	15.29	13.65	27,520
February	15.50	14.06	26,390
March	15.85	13.98	43,422
April	14.53	14.14	28,135
May	14.86	14.35	46,886
June	14.40	13.50	24,232
July	15.05	14.20	20,942
August	14.85	12.56	68,162
September	14.36	13.09	101,690
October	14.95	13.81	47,416
November	15.20	14.48	30,302
December	15.40	14.55	67,438

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 2019 as reported by the TSX:

Month	High	Low	Volume Traded
January	19.17	17.40	229,434
February	20.00	18.35	168,850
March	20.63	19.00	89,108
April	19.76	18.99	97,981
May	19.94	19.00	133,957
June	19.15	18.05	90,259
July	19.49	18.75	113,428
August	19.45	16.73	137,794
September	18.30	17.30	124,607
October	19.96	17.75	302,841
November	19.44	18.75	141,441
December	20.50	18.84	134,238

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 2019 as reported by the TSX:

Month	High	Low	Volume Traded
January	18.50	17.19	229,111
February	18.63	17.80	210,116
March	19.51	18.25	202,876
April	19.00	18.31	188,980
May	19.26	18.50	237,253
June	18.80	17.71	139,189
July	19.41	18.63	173,265
August	19.59	17.80	114,372
September	19.80	18.21	467,524
October	19.54	18.90	105,837
November	19.46	18.90	100,481
December	19.50	18.55	140,980

AltaGas Ltd. – 2019 Annual Information Form –76

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 2019 as reported by the TSX:

Month	High	Low	Volume Traded
January	17.57	16.05	134,170
February	17.09	15.69	81,236
March	17.91	15.53	61,467
April	16.36	15.83	52,334
May	16.89	15.88	68,464
June	16.00	14.93	333,873
July	17.18	16.05	532,773
August	17.04	14.71	92,817
September	16.00	15.35	130,070
October	16.91	15.71	121,128
November	17.20	16.48	113,827
December	17.59	16.11	93,043

Series H Shares were listed on the TSX under the symbol ALA.PR.H on September 30, 2019. The following table sets forth the monthly price range and volume traded for Series H Shares for the period of September 30, 2019 to December 2019 as reported by the TSX:

Month	High	Low	Volume Traded
September	16.00	16.00	—
October	16.00	16.00	700
November	16.50	15.55	5,000
December	16.43	16.04	6,350

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 2019 as reported by the TSX:

Month	High	Low	Volume Traded
January	22.08	19.80	246,438
February	21.89	20.20	235,251
March	22.61	21.65	191,476
April	23.29	22.02	153,461
May	23.19	22.50	187,955
June	22.46	21.11	181,377
July	22.88	21.55	167,292
August	22.85	21.03	155,898
September	23.20	21.56	240,542
October	23.87	22.88	138,825
November	24.09	23.22	107,175
December	24.65	23.19	93,491

AltaGas Ltd. – 2019 Annual Information Form –77

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 2019 as reported by the TSX:

Month	High	Low	Volume Traded
January	19.40	17.56	422,071
February	20.08	18.35	307,105
March	20.79	19.49	388,920
April	20.40	19.41	159,775
May	20.76	20.05	149,506
June	20.30	19.34	157,558
July	21.44	20.17	192,505
August	21.51	19.75	239,174
September	22.02	20.26	102,814
October	22.78	21.57	219,618
November	22.80	21.66	108,073
December	22.99	21.83	122,032

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 credit ratings and rating outlook, as determined by credit rating agencies such as S&P, DBRS, Fitch, and Moody's, and if AltaGas’ ratings were downgraded, AltaGas’ financing costs and future debt issuances could be unfavorably impacted.

S&P, DBRS, Fitch, and Moody's are rating agencies that provide credit ratings. Ratings for debt instruments from S&P, DBRS, and Fitch range from a high of AAA to a low of D. Moody's ratings for debt instruments range from a high of Aaa to a low of C. S&P, DBRS, and Fitch 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.

AltaGas Ltd. – 2019 Annual Information Form –78

The below table summarizes the most recent credit ratings for AltaGas and subsidiaries:

Entity	Rating Agency	Debt Rated	Most Recent Rating	Comments
AltaGas	S&P	Issuer rating	BBB-	Affirmed on December 11, 2019 and outlook was revised from negative to stable.
		Senior unsecured	BBB-	Affirmed on December 11, 2019 and outlook was revised from negative to stable.
		Preferred shares	P-3	Affirmed on December 11, 2019.
	DBRS	Issuer	BBB(low)	Affirmed on December 12, 2019 with stable outlook.
		Preferred shares	Pfd-3(low)	Affirmed on December 12, 2019.
	Fitch	Issuer	BBB	Affirmed on September 6, 2019.
		Preferred shares	BB+	Affirmed on September 6, 2019.
Washington Gas	Moody's	Senior unsecured	A3	Downgraded to A3 from A2 on January 30, 2020. Stable outlook rating on February 4, 2020.
		Commercial paper	P-2	Downgraded to P-2 from P-1 on January 30, 2020. Stable outlook rating on February 4, 2020.
	S&P	Issuer and unsecured debt	A-	Raised from BBB+ to A- on December 11, 2019.
		Commercial paper	A-2	Affirmed on December 11, 2019.
	Fitch	Issuer	A-	Affirmed on September 6, 2019 with stable outlook.
WGL	Moody's	Senior unsecured	Baa1	Affirmed on January 30, 2020 and changed outlook from stable to negative. Stable outlook rating on February 4, 2020.
		Commercial paper	P-2	Affirmed on January 30, 2020 and changed outlook from stable to negative. Stable outlook rating on February 4, 2020.
	S&P	Issuer	BBB-	Affirmed on December 11, 2019 and outlook was revised from negative to stable.
		Senior unsecured	BB+	Affirmed on December 11, 2019.
		Commercial paper	A-3	Affirmed on December 11, 2019.
	Fitch	Issuer	BBB	Affirmed on September 6, 2019 with stable outlook.
SEMCO	Moody's	Long-term issuer	Baa1	Affirmed on January 29, 2020 with stable outlook.
		Senior secured notes	A2	Affirmed on January 29, 2020.
	S&P	Long-term issuer	BBB	Raised from BBB- to BBB on December 12, 2019.
		Senior secured notes	A-	Raised from BBB+ to A- on December 12, 2019.

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.

AltaGas Ltd. – 2019 Annual Information Form –79

According to the Moody’s rating system, Baa ratings indicate moderate credit risk. Obligations rated Baa are considered medium-grade and as such may possess speculative characteristics.

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.

A P-2 rating by Moody's is the second highest of four categories granted by Moody's under its global short-term rating scale. According to the Moody's rating definitions, issuers rated P-2 have a strong ability to repay short-term debt obligations. P-2 ratings generally correspond with A2 to Baa2 under the long-term rating scale.

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, Fitch, nor Moody's 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, Fitch, and Moody's for credit rating services. AltaGas has paid each of S&P, DBRS, Fitch, and Moody's its 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, Fitch, and Moody's.

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 Purchase and Sale Agreement by and among EIF Mead Holdings, LLC, VED NPI II, LLC, VED NPI I, LLC, WGL Midstream MP, LLC and COG Holdings LLC, as sellers and Mead Pipeline Investment, LLC as buyer dated

AltaGas Ltd. – 2019 Annual Information Form –80

as of September 29, 2019 for the sale of AltaGas' indirect, non-operating interest in the Central Penn Pipeline for total gross proceeds of approximately US$657 million;

▪ The Membership Interest Purchase Agreement between WGL Energy Systems, Inc., WGSW, Inc., and Terraforma Arcadia Holdings, LLC dated as of July 19, 2019, with regard to the sale of AltaGas' portfolio of U.S. distributed generation assets held by its subsidiaries WGL Energy Systems, Inc., and WGSW, Inc. for total gross proceeds of approximately $940 million (US$720 million);

▪ 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 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 are 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. See “Risk Factors – Litigation”.

• Antero Resources Corporation (Antero) initiated a 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. In June 2019, a jury trial was held in the County Court for Denver, Colorado to consider a contractual dispute relating to gas pricing between Washington Gas and WGL Midstream (together, the Companies) and Antero. Following the trial, the jury returned a verdict in favor of Antero for approximately US$96 million, of which approximately US$11 million was against Washington Gas with the remainder against WGL Midstream. Following the official entry of the judgment, the Companies filed an appeal on August 16, 2019.

AltaGas recorded a net reduction to the acquired working capital of WGL of approximately US$45 million to account for the verdict in favor of Antero net of tax and other expected recoveries.

AltaGas Ltd. – 2019 Annual Information Form –81

• A total of 37 civil actions related to the August 10, 2016, explosion and fire at an apartment complex on Arliss Street in Silver Spring, Maryland were filed against WGL and Washington Gas in the Circuit Court for Montgomery County, Maryland. All of these suits sought unspecified damages for personal injury and/or property damage. All personal injury and property damage claims asserted by residents at the Flower Branch Apartments have been settled and paid. Washington Gas has been reimbursed by its insurers for the amounts paid in the settlements.

In connection with the incident, on September 5, 2019, the PSC of MD ordered Washington Gas, within 30 days, to (i) provide a detailed response to the NTSB’s probable cause findings and (ii) provide evidence regarding the status of a 2003 mercury regulator replacement program and, if the program was not completed, to show cause why the PSC of MD should not impose a civil penalty on Washington Gas. On November 18, 2019, the Technical Staff of the PSC of MD, the MD Office of People’s Counsel (OPC), Montgomery County, MD and the Apartment and Office Building Association of Metropolitan Washington (AOBA) filed written comments on Washington Gas' response to the Show-Cause Order. Technical Staff commented that the PSC of MD may impose a civil penalty but did not expressly recommend same. Montgomery County, MD, OPC and AOBA requested that the PSC of MD impose a civil penalty on Washington Gas. On December 17, 2019, the PSC of MD held a public hearing near the apartment complex at Arliss Street, at which some residents requested that Washington Gas accelerate and complete its mercury service regulator program and that Washington Gas absorb the cost of same. Washington Gas intends to file comments with the PSC of MD responding to all written comments and resident testimony and has accrued a penalty of US$0.3 million based on a potential range of estimates.

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.

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, 2019 and Management’s Discussion and Analysis for the year ended December 31, 2019.

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.

AltaGas Ltd. – 2019 Annual Information Form –82

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.

AltaGas Ltd. – 2019 Annual Information Form –83

SCHEDULE A: AUDIT COMMITTEE MANDATE

I. PURPOSE

The Board of Directors (the “Board”) of AltaGas Ltd. (“AltaGas” or the “Corporation”) has established an Audit Committee (the “Committee”) to serve as the Audit Committee of the Board. The Committee is responsible for performing such duties as delegated by the Board to assist the Board in fulfilling its oversight role in relation to financial reporting. This oversight role includes reviewing the quality and integrity of the Corporation’s financial statements, financial disclosure and internal controls over financial reporting; reviewing the qualifications, independence and performance of the external and internal auditors and assessing the Corporation’s risks associated with financial reporting and other enterprise risk.

II. 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.

Each Member shall hold office until the Member resigns or is replaced, whichever first occurs. 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. 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.

III. 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 may waive notice of the meeting in any manner, including through their attendance at the meeting. Members of management of the Corporation or any subsidiary or affiliate of the Corporation shall attend whenever requested to do so by a Member. The Committee shall have the right to determine who shall be present at any time during a meeting of the Committee.

A meeting of the Committee shall be duly convened if a majority of Members are present. Members may participate in a meeting of the Committee by means of such telephonic, electronic or other communication facilities as permits all persons

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participating in the meeting to communicate 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 all Committee meetings and be provided the opportunity to attend every meeting relating to financial reporting.

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 of the Corporation or a designate of the Corporate Secretary, as approved by the Chair.

IV. 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. working with management on the development of agendas;

3. ensuring, to the extent possible, the Committee has sufficient information to properly discharge its duties and responsibilities;

4. presiding over meetings and ensuring such meetings are conducted in an efficient, effective and focused manner;

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

6. facilitating information sharing with other Board committees as required to address matters of mutual interest or concern; and

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

V. Duties and Responsibilities of the Committee

The Committee is hereby delegated by the Board, as permitted 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, the authority to perform the following functions:

Financial Reporting and Public Disclosure

1. Approve and recommend to the Board for approval, the consolidated financial statements, including management's discussion and analysis.

2. Review the analysis by management and the external auditor regarding financial reporting made in connection with the preparation of the consolidated financial statements.

3. Approve the financial information contained in public disclosure documents including information on audited or unaudited financial statements and external auditor appointment, services or fees, including such information contained in annual and interim press releases of financial results, prospectuses, annual information forms, and management information circulars.

4. Satisfy itself that adequate procedures are in place for review of public disclosure of financial information and periodically assess the adequacy of such procedures.

5. Approve any significant changes to the Corporation’s accounting principles and procedures.

6. Review reports from auditors, the audit committee or board of directors of subsidiaries that produce audited financial statements in regards to financial reporting relating to such subsidiaries.

External Auditors

7. On an annual basis, approve and recommend to the Board for approval, the appointment of the external auditor subject to shareholder approval.

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8. Approve and recommend to the Board for approval the compensation, retention and any termination of the external auditor of the Corporation.

9. Approve the terms of the external auditor’s annual engagement letter, including the proposed audit fee for the Corporation and its subsidiaries.

10. Review and pre-approve all non-audit services to be provided to the Corporation and its’ subsidiaries by the external auditor.

11. Approve the Corporation’s policies with respect to the hiring of current and former partners and employees of the external auditors.

12. Review the experience and qualifications of the audit team and assess the performance and effectiveness of the external auditor in its provision of services.

13. Review the report pertaining to auditor independence prepared by the external auditor on an annual basis, which report shall delineate all relationships between the external auditor and the Corporation and its subsidiaries, and determine the auditor’s independence.

14. Review and pre-approve the audit plans (and any changes) of the external auditor and the internal auditor, and determine the degree of coordination between such plans.

15. Oversee the work of the external auditor in the preparation of the auditor’s report, including the resolution of any disagreements between management and the auditors regarding financial reporting.

16. Review annually a report on the external auditors’ internal quality control process and review other reports from the external auditor, as necessary.

17. Regularly meet independently with external auditor in the absence of management on matters of interest, including matters that the external auditor recommends bringing to the attention of the Committee or the Board.

Internal Auditor

18. Review the responsibilities, budget and staffing of the Corporation’s internal audit function.

19. Assess the performance and effectiveness of the internal audit function and participate in succession planning for the head of internal audit.

20. Review the reports prepared periodically by the head of internal audit regarding the activities of the internal audit function, including any significant disagreements between internal auditor and management.

21. Receive summaries of significant reports to management prepared by the internal auditors and managements’ responses (or the full report if requested).

22. Regularly meet independently with internal auditor in the absence of management on matters of interest, including matters that the internal auditor recommends bringing to the attention of the Board.

Internal Control over Financial Reporting and Disclosure Controls

23. Review the adequacy and effectiveness of the accounting and internal control policies and procedures, including internal controls over financial reporting, through inquiry and discussions with the external auditor, 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.

24. Review the effectiveness of procedures for the receipt, retention and resolution of complaints regarding accounting, internal accounting controls or auditing matters, and review any complaints raised by employees or others regarding accounting, internal accounting controls, financial reporting, auditing matters or otherwise relating to matters within the Committee’s mandate.

25. Review management’s periodic reports on the adequacy and effectiveness of the disclosure control policies and procedures of the Corporation.

26. Review with management and the external auditor the certification and reports of management and the external auditor required in the Corporation’s periodic SEC reports concerning the Corporation’s internal controls 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.

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Risk Management

27. On a quarterly basis, review the Corporation's enterprise risk management (ERM) processes, including processes relating to management’s identification of material risks and methods of risk analysis.

28. On a quarterly basis, review management’s reporting on financial risk exposures, including commodity risk, counterparty and credit risk and management’s processes and practices for risk mitigation.

29. Review management’s periodic reports on the status of material litigation, claims and contingencies.

30. Review the financial aspects of any transactions of the Corporation that involve related parties (other than wholly-owned subsidiaries).

31. Review the Corporation's processes for identifying and managing cyber risk and processes for the development of data security programs and practices.

32. Review the Corporation's insurance programs.

Policies and Mandate

33. Review key policies relating to the Committee’s mandate and recommend any changes.

34. On an annual basis, review the Committee mandate and recommend any changes.

Pension and Benefits

35. Oversee financial aspects of pension and benefit plans that are delegated to the management Retirement and Savings Committee (the “RSC”) to manage and administer.

36. Review, at least annually, the financial management activities of the RSC, including funding levels, investment decisions and changes to valuation assumptions performed by the RSC.

37. Review any proposed changes to pension or benefit plans that may impact financial matters relating to such plans and make recommendations to the Human Resources and Compensation Committee in relation thereto.

38. Approve the financial information that supports the calculation of financial metrics used to evaluate performance under incentive compensation plans and funding pools under compensation plans and report to the Human Resources and Compensation Committee.

Other

39. Review the solvency and liquidity tests used to support dividend declarations by the Corporation.

40. Review environmental liability estimates in relation to decommissioning, reclamation and remediation.

41. Receive updates on material tax policies, tax planning initiatives and tax audits or assessments.

42. Review management’s process for certification under the Extractive Sector Transparency Measures Act (Canada).

43. Review, approve or make recommendations in respect of any other matters considered necessary or appropriate in the context of the mandate of this Committee, or otherwise delegated to it by the Board from time to time.

V. 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.

VII. 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.

VIII. Committee Timetable

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

Approved by the Board on October 29, 2019.

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EX-13.2

MANAGEMENT'S DISCUSSION AND ANALYSIS

This Management's Discussion and Analysis (MD&A) dated February 27, 2020 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, 2019. This MD&A 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, 2019.

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 and dollars refer to Canadian dollars, unless otherwise indicated.

Abbreviations, acronyms and capitalized terms used in this MD&A without express definition shall have the same meanings given to those terms in the MD&A as at and for the year ended December 31, 2019 or the Annual Information Form for the year ended December 31, 2019.

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", "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 MD&A 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: expectation that RIPET will be a catalyst for further growth in the Midstream business; expectation that the Townsend 2B expansion, North Pine expansion and the northeast BC pipeline projects will be completed in early 2020; expiration of the Northwest Hydro operating agreement in January 2021; conditions to and timing of the closing of the ACI Arrangement; expected cost savings related to the repayment of debt with proceeds of the December 2019 note offering; funding of the Petrogas put obligations; retirement of Daryl Gilbert from the Board of Directors; AltaGas' strategy for each of its core businesses; plan to focus on capitalization of significant growth potential of the Midstream and Utilities assets; plan to maximize structural advantage of the integrated platform in the Montney region; plan to increase utilization and export volumes at RIPET; expectation that volumes at RIPET will exceed 50,000 Bbls/d by the end of 2020; planned $900 million growth capital program; targeted 10 percent increase in the Utilities rate base; expected annual consolidated normalized EBITDA of approximately $1.275 to $1.325 billion in 2020; normalize earnings per share of approximately $1.20 to $1.30 per share in 2020; expected growth, EBITDA contributions and drivers behind each of the Midstream, Utilities and Power businesses; expectation that overall growth will more than offset lost EBITDA from a full year impact of asset sales completed in 2019; estimated exposure to frac spreads and the propane price differentials; expectation that the majority of the annual capacity of RIPET will be underpinned by tolling arrangements over the next several years; allocation of $900 million capital expenditures among and expected focus of spending within the Utilities, Midstream and Power businesses; expected sources of funding for the committed capital program; the estimated cost, status and expected in-service dates for grown capital projects in the Midstream and Utilities businesses; expected filing, procedure and decision dates for rate cases in the Utilities business; future changes in accounting policies and adoption of new accounting standards; and AltaGas’ long term strategy. 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: assumptions regarding asset sales anticipated to close in 2020, effective tax rate of approximately 22 percent, propane price differentials, degree day variance from normal, the U.S/Canadian dollar exchange rate, financing initiatives, the performance of the businesses underlying each sector; impacts of the hedging program; commodity prices; weather; frac spread; access to capital; timing and receipt of regulatory approvals; timing of regulatory approvals related to Utilities projects; seasonality; planned and unplanned plant outages; timing of in-service dates of new projects and acquisition and divestiture activities; taxes; operational expenses; returns on investments; dividend levels; and transaction costs.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 1

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: health and safety risks; operating risks; infrastructure risks; service interruptions; regulatory risks; litigation risk; decommissioning, abandonment and reclamation costs; climate and carbon tax risks; reputation risk; weather data; Indigenous land and rights claims; crown duty to consult with Indigenous peoples; changes in laws; capital market and liquidity risks; general economic conditions; internal credit risk; foreign exchange risk; debt financing, refinancing, and debt service risk; interest rates; cyber security, information, and control systems; technical systems and processes incidents; dependence on certain partners; growth strategy risk; construction and development; RIPET rail and marine transport; impact of competition in AltaGas' Midstream and Power businesses; commitments associated with regulatory approvals for the acquisition of WGL; counterparty credit risk; composition risk; collateral; regulatory agreements; non-controlling interests in investments; delays in U.S. federal government budget appropriations; consumption risk; market risk; market value of common shares and other securities; variability of dividends; potential sales of additional shares; volume throughput; natural gas supply risk; risk management costs and limitations; underinsured and uninsured losses; Cook Inlet gas supply; securities class action suits and derivative suits; electricity and resource adequacy prices; cost of providing retirement plan benefits; labor relations; key personnel; failure of service providers; compliance with Section 404(a) of Sarbanes-Oxley Act; integration of WGL; and the other factors discussed under the heading "Risk Factors" in the Corporation’s Annual Information Form for the year ended December 31, 2019 (AIF) and set out in AltaGas’ other continuous disclosure documents.

Many factors could cause AltaGas' or any particular business segment's actual results, performance or achievements to vary from those described in this MD&A, including, without limitation, those listed above and 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. Such 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 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, Annual Information Form, and press releases are available through AltaGas' website at www.altagas.ca or through SEDAR at www.sedar.com.

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. (WGL Energy Services), 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, Ridley Island LPG Export Limited Partnership, and WGL Midstream Inc. (WGL Midstream); in regards to the Power business, AltaGas Power Holdings (U.S.) Inc., WGL Energy Systems, Inc. (WGL Energy Systems), and Blythe Energy Inc. (Blythe); and, in regards to the Utilities business, Washington Gas Light Company (Washington Gas), Hampshire Gas Company, and SEMCO Energy, Inc.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 2

(SEMCO). SEMCO conducts its Michigan natural gas distribution business under the name SEMCO Energy Gas Company (SEMCO Gas), its Alaska natural gas distribution business under the name ENSTAR Natural Gas Company (ENSTAR) and its 65 percent interest in an Alaska regulated gas storage utility under the name Cook Inlet Natural Gas Storage Alaska LLC (CINGSA).

2019 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.)

Growth and Operational Highlights

▪ In the second quarter of 2019, the Ridley Island Propane Export Terminal (RIPET) was completed, with its first shipment of propane to Asia departing on May 23, 2019. RIPET is the first propane marine export facility in Canada and its completion is expected to be a catalyst for further growth within AltaGas' Midstream business;

▪ In the fourth quarter of 2019, construction of the Marquette Connector Pipeline (MCP) was completed. The MCP connects 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’ customers;

▪ In the Midstream segment, AltaGas made significant progress on its growth capital projects, including the completion of the 50 Mmcf/d (net) Nig Creek gas processing facility in the third quarter of 2019 and expected early 2020 completions of the 198 Mmcf/d Townsend 2B expansion, the 10,000 Bbls/d North Pine expansion, and the northeast British Columbia pipeline projects; and

▪ In the Power segment, AltaGas announced the successful recontracting of the Blythe facility to Southern California Edison (SCE). Under the tolling agreement, SCE has exclusive rights to all capacity, energy, ancillary services, and resource adequacy benefits from August 1, 2020 to December 31, 2023. California Public Utilities Commission approval was received on January 16, 2020.

Asset Sales Completed

▪ On September 26, 2019, AltaGas closed the sale of its portfolio of U.S. distributed generation assets held by its subsidiaries WGL Energy Systems, Inc. and WGSW, Inc., to TerraForm Power, Inc., an affiliate of Brookfield Asset Management. Total cash proceeds received were approximately US$735 million and a pre-tax gain on disposition of $168 million was recorded in 2019. There are certain projects for which legal title has not yet transferred as various consents and approvals remain outstanding. These projects remain held for sale at December 31, 2019;

▪ On November 13, 2019, AltaGas completed the sale of its indirect, non-operating interest in the Central Penn Pipeline (Central Penn) held by its subsidiary WGL Midstream, Inc. to Meade Pipeline Investment, LLC, a subsidiary of NextEra Energy Partners, LP for net cash proceeds of approximately US$611 million, resulting in a pre-tax loss of $11 million;

▪ On May 31, 2019, AltaGas completed the disposition of WGL Midstream's entire interest in the Stonewall Gas Gathering System (Stonewall) to a wholly-owned subsidiary of DTE Energy Company for total gross proceeds of approximately $379 million (US$280 million), resulting in a pre-tax gain of $34 million;

▪ On February 1, 2019, AltaGas completed the sale of certain non-core Midstream and Power assets in Canada. Cash proceeds for the portion of the sale that closed in the first quarter of 2019 were approximately $88 million, resulting in a pre-tax loss of $1 million; and

▪ On January 31, 2019, AltaGas completed the sale of its remaining interest of approximately 55 percent in the Northwest Hydro Electric facilities in British Columbia (Northwest Hydro) for net cash proceeds of approximately $1.3 billion, resulting in a pre-tax gain of $688 million. AltaGas remains the operator of the facilities under an operating and maintenance agreement expiring January 31, 2021.

Regulatory Developments

▪ On December 6, 2019, the Michigan Public Service Commission (MPSC) issued a Final Order approving SEMCO's settlement agreement in its recent rate case, reflecting a base rate increase of approximately US$20 million effective January 1, 2020;

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▪ On October 15, 2019, the Maryland Public Service Commission (PSC of MD) issued a Final Order approving Washington Gas' settlement agreement in its recent rate case, reflecting a US$27 million base rate increase effective October 15, 2019; and

▪ In September 2019, the Virginia Hearing Examiner assigned to Washington Gas' Virginia rate case issued a report with findings and recommendations to the State Corporation Commission of Virginia (SCC of VA), including the finding for no incremental revenues. In September 2019, the impact of these recommendations was recorded, resulting in a one-time reduction in normalized EBITDA of approximately $30 million and a reduction of approximately $14 million in net income after taxes. On October 21, 2019, Washington Gas filed comments on and exceptions to the Hearing Examiner's report, recommending the SCC of VA reject certain of the Hearing Examiner's findings. On December 20, 2019, the Commission issued a Final Orderadjusting certain of the Hearing Examiner’s findings, some of which are favorable to Washington Gas, resulting in a $8 million increase to EBITDA in the fourth quarter of 2019. In January 2020, Washington Gas filed a petition for reconsideration regarding one of the findings in the Final Order. On January 30, 2020, the SCC of VA denied this request and the rate case is now final.

Other Highlights

▪ In 2019, AltaGas successfully de-levered its balance sheet, regained financial flexibility, maintained its investment grade credit rating, and repositioned the business to focus on organic growth opportunities in the Utilities and Midstream segments. In addition, AltaGas successfully executed its WGL integration strategy, making significant progress in achieving near- and long-term integration priorities, including strategy, organizational effectiveness, and people and culture;  

▪ On December 17, 2019, AltaGas announced its 2020 guidance and provided an update on its 2020 strategic plan. This included an announcement that the Board of Directors approved the suspension of the Dividend Reinvestment and Optional Cash Purchase Plan (DRIP), with the December dividend (payable January 2020) being the last dividend payment eligible for reinvestment by participating shareholders under the DRIP, until further notice;

▪ On October 21, 2019, AltaGas Canada Inc. (ACI) announced that the Public Sector Pension Investment Board and the Alberta Teachers' Retirement Fund Board (together, the "Consortium") and ACI had concluded a definitive arrangement agreement (the "Arrangement Agreement") whereby the Consortium will indirectly acquire all of the issued and outstanding common shares of ACI(the "Common Shares")in an all-cash transaction for $33.50 per Common Share by way of arrangement under the Canada Business Corporations Act (the "Arrangement"). On December 19, 2019, the shareholders of ACI approved the Arrangement Agreement. In addition, on December 16, 2019, ACI received a "no-action letter" from the Canadian Competition Bureau confirming that the Commissioner of Competition does not at this time intend to challenge the proposed Arrangement. On December 20, 2019, ACI received the final order from the Court of Queen's Bench of Alberta approving the Arrangement. On February 18, 2020, the Alberta Utilities Commission issued a decision approving the Arrangement. The closing of the Arrangement remains subject to the receipt of approval from the British Columbia Utilities Commission, and the satisfaction or waiver of other customary closing conditions. ACI and the Consortium expect to close the Arrangement in the first half of 2020. AltaGas owns 11,025,000 Common Shares or approximately 37 percent of the total number of Common Shares;

▪ On September 30, 2019, 1,114,177 of the outstanding 8,000,000 Cumulative Redeemable Five-Year Fixed Rate Reset Preferred Shares, Series G were converted into Cumulative Floating Rate Preferred Shares, Series H;

▪ On December 16, 2019, AltaGas completed its aggregate issuance of $500 million of senior unsecured medium term notes with a coupon rate of 2.609 percent, maturing on December 16, 2022. The proceeds were used to pay down existing indebtedness under AltaGas' credit facilities and for general corporate purposes. Because the coupon rate is lower than the borrowing rate of the repaid debt, AltaGas expects cost savings of approximately $5 million per annum as a result of the debt repayment;

▪ On December 20, 2019, all outstanding Washington Gas preferred shares (US$4.25 series, US$4.80 series, and US$5.00 series) were redeemed. A pre-tax gain of $3 million was recognized upon redemption;

▪ On May 27, 2019, AltaGas announced the appointment of D. James Harbilas as Executive Vice President and Chief Financial Officer of AltaGas, effective June 10, 2019. Mr. Harbilas replaced Timothy Watson, who served as Executive Vice President and Chief Financial Officer until June 9, 2019;

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▪ Effective December 16, 2019, AltaGas appointed Donald “Blue” Jenkins as Executive Vice President and President, Utilities and President, Washington Gas. Mr. Jenkins succeeds Adrian Chapman, who has retired; and

▪ On December 11, 2019, AltaGas released its inaugural Environmental, Social, and Governance (ESG) Report, highlighting the Company's 2018 performance in several key areas related to the long-term sustainability of its business, and demonstrating its ongoing commitment to transparency.

Financial Highlights

▪ Normalized EBITDA was $1,271 million compared to $1,009 million in 2018;

▪ Cash from operations was $616 million ($2.22 per share) compared to cash used by operations of $79 million ($0.35 per share) in 2018;

▪ Normalized funds from operations were $895 million ($3.23 per share) compared to $657 million ($2.95 per share) in 2018;

▪ Net income applicable to common shares was $769 million ($2.78 per share) compared to net loss applicable to common shares of $502 million ($2.25 per share) in 2018;

▪ Normalized net income was $324 million ($1.17 per share) compared to $195 million ($0.88 per share) in 2018;

▪ Net debt was $7.2 billion as at December 31, 2019, compared to $10.0 billion at December 31, 2018; and

▪ Net debt‑to‑total capitalization ratio was 49 percent as at December 31, 2019, compared to 57 percent as at December 31, 2018.

Highlights Subsequent to Year End

▪ On January 2, 2020, AltaGas advised that AltaGas Idemitsu Joint Venture Limited Partnership (AIJVLP) had received notice (the Put Notice) from SAM Holdings Ltd. (SAM) of its exercise of a put option (the Put Option) with respect to SAM's approximately one-third interest in Petrogas Energy Corp. (Petrogas). AIJVLP, a limited partnership owned 50 percent by AltaGas and 50 percent by Idemitsu Kosan Co., Ltd. (Idemitsu), owns the other approximately two-thirds of the outstanding common shares of Petrogas. Pursuant to the Petrogas unanimous shareholders agreement, a valid exercise of the Put Option by SAM after October 1, 2019, triggers a requirement for AIJVLP to purchase SAM's interest in Petrogas at the fair market value thereof, as determined by third-party valuators. AltaGas anticipates funding its portion of any such obligation with internal cash flow, the sale of remaining non-core assets, and debt. Valuations are underway;

▪ On January 9, 2020, AltaGas announced the appointment of two new independent Directors - Linda Sullivan and Nancy Tower to its Board of Directors. In addition, AltaGas announced the retirement of Daryl Gilbert from the Board of Directors, to be effective following the conclusion of AltaGas' next annual meeting of shareholders in May 2020;

▪ On January 13, 2020, Washington Gas filed a rate case in the District of Columbia requesting a US$35 million increase in base rates, including US$9 million of annual PROJECTpipes surcharges currently paid by customers for accelerated pipeline replacement. Washington Gas has also requested approval for a Revenue Normalization Adjustment mechanism to reduce customer bill fluctuations due to weather-related usage variations, similar to existing mechanisms in both Maryland and Virginia; and

▪ In February 2020, following evaluations of the diminished underlying economics for the proposed Constitution pipeline project, the partners ofConstitution Pipeline Company, LLC (Constitution) elected not to proceed with the project. AltaGas held a 10 percent equity interest in Constitution. Upon the acquisition of WGL, AltaGas assigned a value of $nil to Constitution.

AltaGas' Vision and Objective

AltaGas’ vision is to be a leading North American infrastructure company that connects natural gas and natural gas liquids to domestic and global markets. The Corporation strives to improve the lives of customers by safely delivering clean, affordable, and reliable natural gas solutions that meet their evolving energy needs - today and tomorrow.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 5

Strategy

AltaGas' long-term strategy is largely focused on two core businesses - Utilities and Midstream - and is designed to deliver reliable, attractive long-term earnings and the potential for future dividend growth.

With infrastructure assets in some of the fastest growing energy markets in North America including a prominent position in the Montney region and utilities operations in five U.S. jurisdictions, AltaGas is developing an integrated footprint capable of delivering sustained value to stakeholders today and into the future. 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.

In 2020, AltaGas plans to focus on capitalizing on the significant growth potential of its Utilities and Midstream assets. Specific priorities include to:

▪ Ensure safe reliable operations, providing effective and cost-efficient service for customers;

▪ Enhance returns and capital efficiency through base rate cases, and facilitate timely recovery of expenditures and improve safety through increased utilization of accelerated rate recovery programs;

▪ Enhance the business through asset optimization and operational efficiencies to reduce costs and deliver an improved customer experience;

▪ Maximize the unique structural advantage within AltaGas' integrated platform in the Montney region;

▪ Increase utilization and export volumes at RIPET;

▪ Execute the planned $900 million growth capital program, including a targeted 10 percent increase in the Utilities rate base; and

▪ Pursue capital efficient organic growth through disciplined capital allocation while improving balance sheet strength and flexibility.

AltaGas’ Board of Directors is actively engaged in AltaGas’ strategy. The Corporation continually assesses the macro- and micro-economic trends impacting the businesses and seeks opportunities to generate value for stakeholders. 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.

2020 Outlook

In 2020, AltaGas expects to achieve annual consolidated normalized EBITDA of approximately $1.275 to $1.325 billion, and normalized earnings per share of approximately $1.20 to $1.30 per share assuming an effective tax rate of approximately 22 percent. This range is net of asset sales that are anticipated to close in 2020, including AltaGas' approximate 37 percent interest in ACI.

Growth is expected in 2020 in the Utilities and Midstream segments. The Utilities segment is expected to have the largest contribution to normalized EBITDA, with growth driven primarily by rate base growth and increased spend on accelerated capital programs. Growth in the Midstream segment is anticipated to largely be driven by a full year of contributions from RIPET, and increased volumes at Northeast British Columbia facilities, including North Pine, Townsend, and Aitken Creek, as well as higher expected margins on U.S. Midstream storage and transportation. Normalized EBITDA from AltaGas' remaining Power assets is also expected to grow primarily due to less expected downtime at Blythe. Overall growth is expected to more than offset lost EBITDA from a full year impact of asset sales completed in 2019.

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The overall forecasted normalized EBITDA and earnings per share include assumptions around asset sales anticipated to close in 2020, 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 normalized earnings per share.

AltaGas estimates an average of approximately 10,000Bbls/d of natural gas liquids (NGL) will be exposed to frac spreads prior to hedging activities. Pricing risk related to frac exposed propane is mitigated through export and the hedging program in place at RIPET. Hedges are in place for approximately 80 percent of frac exposed butane and condensate volumes.

At RIPET, AltaGas is exposed to the propane price differential between North American Indices and the Far East Index for contracts not under tolling arrangements. AltaGas estimates an average of approximately 30,000Bbls/d will be exposed to these price differentials in 2020, of which approximately74 percent have been hedged at an average FEI to Mont Belvieu spread of US$11/Bbl. AltaGas plans to manage 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.

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 2020:

Factor	Increase or decrease	Approximate impact on normalized annual EBITDA ($ millions)
Degree day variance from normal - Utilities (1)	5 percent	8
Change in Canadian dollar per U.S. dollar exchange rate	0.05	35
RIPET Propane Far East Index to Mont Belvieu spread (2)	US$1/Bbl	4
AECO/Station 2 gas prices(3)	$0.20/GJ	3
Pension discount rate	1 percent	17

(1) Degree days – Utilities relate to SEMCO Gas, ENSTAR, and Washington Gas service areas. Degree days are a measure of coldness determined daily as the

numbers of degrees the average temperature during the day in question is below 65 degrees Fahrenheit. 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.

(2) The impact on EBITDA due to changes in the spread will vary and is being managed through an active hedging program.

(3) Price risk related to frac exposed propane is mitigated through export and the hedging program in place at RIPET. Butane and condensate are 80 percent hedged.

Growth Capital

Based on projects currently under review, development, or construction, AltaGas expects net capital expenditures of approximately $900 million in 2020. The majority of capital expenditures are expected to focus on projects within the Utilities business that are anticipated to deliver stable and transparent rate base growth and strong risk-adjusted returns. The Utilities segment is expected to account for approximately 75 to 80 percent of total capital expenditures, while the Midstream segment is expected to account for approximately 15 to 20 percent and the Power and Corporate segments are expected to account for any remainder. Midstream and Power maintenance capital is expected to be approximately $30 to $40 million of the total capital expenditures in 2020.

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AltaGas’ capital expenditures for the Utilities segment will focus primarily on accelerated pipe replacement programs, customer growth, and system betterment.In the Midstream segment, capital expenditures are anticipated to primarily relate to the completion of Townsend and North Pine expansions and associated pipeline systems, maintenance and administrative capital, the completion of the Mountain Valley Pipeline expansion project (MVP Southgate), and new business development.The Power segment continues to pursue a capital-light strategy for remaining assets. The Corporation continues to focus on capital efficient organic growth and disciplined capital allocation while improving balance sheet strength and flexibility.

AltaGas' 2020 committed capital program is expected to be funded through internally-generated cash flow and normal course borrowings on existing committed credit facilities.

Growth Capital Project Updates

The following table summarizes the status of AltaGas’ significant growth projects. For further description of these projects please refer to AltaGas' most recent Annual Information Form which is available through SEDAR at www.sedar.com.

Project	AltaGas' Ownership Interest			Estimated Cost (1)	Expenditures to Date (2)		Status	Expected In-Service Date
Midstream Projects
Northeast B.C. Pipeline Projects		33% to 100%	$75 million		$56 million	The Northeast B.C. Pipeline projects consist of four pipelines: the Inga gas gathering pipeline (33% ownership), the Townsend East NGL pipeline (100% ownership), the Aitken Connector NGL pipeline (100% ownership), and the Gundy lateral pipeline (100% ownership). Construction of all segments is underway. The pipelines are expected to be in-service in the first quarter of 2020.		Q1 2020
Townsend 2B Expansion and Mercaptan Treating		100%	$165 million		$140 million	Field construction activities commenced in the second quarter of 2019 and are progressing according to plan. The expected completion date is the first quarter of 2020.		Q1 2020
North Pine Expansion		100%	$58 million		$44 million	Field construction activities commenced in the third quarter of 2019 and are progressing according to plan. The expected completion date is the first quarter of 2020.		Q1 2020
Mountain Valley Pipeline (Mountain Valley)		10%	US$352 million		US$352 million	Construction is underway. As at December 31, 2019, approximately 90% of the project is complete, which includes construction of all original interconnects and compressor stations. In the third quarter of 2019 there was a voluntary suspension of construction activities in a section of the pipeline and the Federal Energy Regulatory Commission (FERC) issued an order to suspend all construction. As a result, the in-service date is now expected to be late 2020. Despite the delays, AltaGas' exposure is contractually capped to the original estimated contributions of approximately US$352 million.		Late 2020 due to ongoing legal and regulatory challenges
MVP Southgate Project		5%	US$20 million		US$3 million	Construction is expected to begin in the fourth quarter of 2020. Expenditures to date relate to land surveys, land acquisition, and obtaining permits and regulatory approvals.		Mid 2021

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Project	AltaGas' Ownership Interest			Estimated Cost (1)	Expenditures to Date (2)			Status	Expected In-Service Date
Utilities Projects
Accelerated Utility Pipe Replacement Programs – District of Columbia		100%	Estimated US$305 million over the five year period from April 2020 to December 2024, plus additional expenditures in subsequent periods.			$nil (3)	Washington Gas has submitted an application for the second phase of PROJECTpipes to the Public Service Commission of the District of Columbia (PSC of DC). In the interim, Phase 1 has been extended to March 31, 2020 for an amount not to exceed US$12.5 million.		Individual assets are placed into service throughout the program.
Accelerated Utility Pipe Replacement Programs – Maryland		100%	Estimated US$350 million over the five year period from January 2019 to December 2023, plus additional expenditures in subsequent periods.			US$57 million (3)	The second phase of the accelerated utility pipe replacement programs in Maryland (STRIDE 2.0) began in January 2019.		Individual assets are placed into service throughout the program.
Accelerated Utility Pipe Replacement Programs – Virginia		100%	Estimated US$500 million over the five year period from January 2018 to December 2022, plus additional expenditures in subsequent periods.			US$171 million (3)	The second phase of the accelerated pipe replacement programs in Virginia (SAVE 2.0) began in January 2018.		Individual assets are placed into service throughout the program.
Accelerated Mains Replacement Programs – Michigan		100%	Estimated US$50 million over five year period from 2015 to 2020.			US$37 million (3)	The third phase of the Accelerated Mains Replacement Program (MRP3) in Michigan expires in May 2020. A new MRP program was agreed to in SEMCO's recently settled rate case. The new five-year MRP program begins in 2021 with a total spend of approximately US$60 million. In addition to the new MRP program, SEMCO was also granted a new Infrastructure Reliability Improvement Program (IRIP) which is also a five-year program with a total spend of approximately US$55 million beginning in 2021.		Individual assets are placed into service throughout the program.
Marquette Connector Pipeline		100%	US$154 million			US$152 million	The MCP has been completed and is in service. All interconnects have been commissioned and the pipeline is providing gas supply to SEMCO's Marquette service area in northern Michigan. Minor cleanup and restoration will take place in 2020. Community engagement, interaction, and media coverage was positive throughout the project.		Completed December 2019

(1) These amounts are estimates and are subject to change based on various factors. Where appropriate, the amounts reflect AltaGas’ share of the various projects.

(2) Expenditures to date reflect total cumulative expenditures incurred from inception of the projects to December 31, 2019. For WGL projects, this also includes any expenditures prior to the close of the WGL Acquisition on July 6, 2018.

(3) The utility accelerated replacement programs are long-term projects with multiple phases for which expenditures are approved by the regulators and managed in five year increments. Expenditures to date only include amounts for the current programs described above, and exclude any expenditures made under prior increments of the programs. Actual regulatory filings may differ from reported amounts.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 9

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, serving approximately1.7 millioncustomers and with a combined rate base of approximatelyUS$3.9 billion.

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;

▪ A 65 percent interest in Cook Inlet Natural Gas Storage Alaska LLC (CINGSA) in Alaska; and

▪ An approximate 37 percent interest in ACI.

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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 or mitigate 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 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, Virginia, and Maryland. At the end of 2019, Washington Gas had approximately 1.2 million customers, of which approximately 82 percent were residential. The number of customers at Washington Gas increased approximately 1 percent in 2019. The rate base at December 31, 2019 was approximately US$2.9 billion. At the end of 2019, the approved regulated ROE for Washington Gas in its various jurisdictions ranged from 9.2 percent to 9.7 percent based on an equity ratio ranging from 53.5 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 has accelerated pipe replacement programs in place in each of its three jurisdictions. Washington Gas accelerates pipe replacement in order to reduce risk and further enhance the safety and reliability of the pipeline system. Each regulatory commission having jurisdiction over Washington Gas’ retail rates has approved accelerated replacement programs with an associated surcharge mechanism to recover the cost, including a return, on those capital investments. In contrast to the traditional rate-making approach to capital investments, for the accelerated pipe replacement programs, Washington Gas is receiving recovery for these investments through the approved surcharges for each program and is authorized to invest in each of these programs over a five-year period.

Washington Gas’ customers are eligible to purchase their natural gas from unregulated third-party marketers through natural gas unbundling. As at December 31, 2019, approximately 14 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, 2019, it had service agreements with four pipeline companies that provided firm transportation and storage services with contract expiration dates ranging from 2020 to 2044. Washington Gas has also contracted with various interstate pipeline and storage companies to add to its storage and transportation capacity. Washington Gas, under its asset optimization program, makes use of storage and transportation capacity resources when those assets are not required to serve utility customers. The objective of this program is to derive a profit to be shared with its utility customers. These profits are earned by entering into commodity-related physical and financial contracts with third parties.

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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 the commodity cost of 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 operating under the name SEMCO Gas and has an interest in a regulated natural gas storage facility in Michigan. At the end of 2019, SEMCO Gas had approximately 307,000 customers. Of these customers, approximately 91 percent are residential. In 2019, 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$608 million. In 2019, the approved regulated ROE for SEMCO Gas was 10.35 percent with an approved capital structure based on 49.04 percent equity. For 2020, the approved regulated ROE is 9.87 percent with an approved capital structure based on 45.86 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 an Accelerated 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. SEMCO Gas has requested an additional renewal for the five year period beginning in 2020. The anticipated annual average capital spending over the five year period is approximately US$10 million. A new MRP was approved as part of the 2019 rate case. For the years 2021 to 2025 the anticipated annual average capital spending is approximately US$12 million. Additionally, a new Infrastructure Reliability Improvement Program was approved in the 2019 rate case. During the years 2020 to 2025, SEMCO Gas will complete certain projects totaling US$55 million to improve the reliability of infrastructure. Customers will be billed a surcharge beginning in 2021 for the IRIP.

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 2019, ENSTAR had approximately 147,000 customers including residential, commercial, and transportation, and of these customers, approximately 91 percent are residential. In 2019, 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$258 million for ENSTAR and US$68 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 measurable changes in their application for new rates.

ACI

AltaGas owns an approximate 37 percent equity interest in ACI. ACI holds certain assets formerly held by AltaGas, including rate-regulated utility distribution 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 interest in the Northwest Hydro facilities.

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On October 21, 2019, ACIannounced that the Consortium and ACI had concluded the Arrangement Agreement whereby the Consortium will indirectly acquire all of the Common Shares of ACI in an all-cash transaction for $33.50 per Common Share. On December 19, 2019, the shareholders of ACI approved the Arrangement Agreement. In addition, on December 16, 2019, ACI received a "no-action letter" from the Canadian Competition Bureau confirming that the Commissioner of Competition does not at this time intend to challenge the proposed Arrangement. On December 20, 2019, ACI received the final order from the Court of Queen's Bench of Alberta approving the Arrangement. On February 18, 2020, the Alberta Utilities Commission issued a decision approving the Arrangement. The closing of the Arrangement remains subject to the receipt of approval from the British Columbia Utilities Commission, and the satisfaction or waiver of other customary closing conditions. ACI and the Consortium expect to close the Arrangement in the first half of 2020.

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:

▪ Ensure safe, reliable operations and infrastructure, providing effective and cost-efficient service for customers;

▪ Enhance returns and capital efficiency and more timely recovery of expenditures through rate cases and increased utilization of accelerated rate recovery programs;

▪ Enhance and grow the business through asset optimization, cost reduction initiatives, and operational efficiencies to reduce costs and deliver an improved customer experience;

▪ Improve business processes and drive down leak remediation costs, reinvesting savings into improving the customer experience;

▪ Attract and retain customers through exceptional customer service;

▪ Grow the consolidated Utilities rate base by a targeted 10 percent in 2020;

▪ Maintain strong relationships with local communities, Indigenous peoples, governments, and regulatory bodies; and

▪ Maintain strong community and regulatory relationships while ensuring fair returns to shareholders.

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' utilities have had approximately 44 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 in 2018, prudent investments in current areas of operations, and the addition of new customers. Customer growth rates for AltaGas’ 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 is comprised of global export assets and strategically-located processing, fractionation, and liquids handling infrastructure in Canada that connects Western Canadian producers from wellhead to the coast and to the global export markets, as well as a pipeline investment, the sale of natural gas to retail customers, and underground natural gas storage facilities.

In Canada, AltaGasserves customers primarily in the Western Canada Sedimentary Basin (WCSB) and delivers natural gas into downstream pipeline systems, connecting producers to the global export markets for liquified petroleum gas (LPG). Subsequent to the disposition of the non-core Midstream assets in Canada which closed in February 2019, AltaGas transacts more than 1.4

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Bcf/d of natural gas including natural gas gathering and processing, NGL extraction and fractionation, logistics, liquids handling, and global exports. 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 has a total net licensed processing capacity of approximately 2.2 Bcf/d.

Through RIPET and the indirect interest in Ferndale, AltaGas is able to provide Western Canadian producers global market access and incremental value for Canadian NGLs. The Ferndale terminal is owned and operated by Petrogas, which exports LPG to Asian markets. See Global Exports section below for further details.

Liquids handling services include storage, rail logistics, pipelines, and truck loading as well as natural gas and NGL marketing initiatives. AltaGas identifies opportunities to buy and resell NGLs for producers, and exchange, reallocate, or resell pipeline capacity and storage to earn a profit. With the emergence of the global exports business, liquids handling provides integral support for managing RIPET's ocean and rail logistics as well as marketing the supply and offtake for RIPET. In support of the liquids handling operations, AltaGas manages a rail car fleet of approximately 1,200 rail cars.

In addition, the Midstream segment includes an investment in a pipeline in the northeastern United States, a wholesale gas asset management business, and a retail gas marketing business. AltaGas, through WGL Midstream, indirectly owns a 10 percent equity interest in the Mountain Valley pipeline. AltaGas' retail gas marketing business consists of the operations of WGL Energy Services, which sells natural gas directly to residential, commercial, and industrial customers in Maryland, Virginia, Delaware, Pennsylvania, and the District of Columbia.

The Midstream segment includes expansion and greenfield projects under development or construction, as discussed under the Growth Capital section of this MD&A.

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Global Exports

AltaGas’ global export assets include RIPET and Petrogas, which provide Western Canadian producers with global market access and incremental value for Canadian NGLs.

▪ RIPET commenced commercial operations on May 23, 2019, with the first propane shipment departing from the terminal to Asia. RIPET is capable of storing 600,000 Bbls and currently has a propane export license of 40,000 Bbls/d. As AltaGas builds on the operational capabilities and global counterparty networks for RIPET, AltaGas expects to continue to increase throughput from RIPET. In November 2019, AltaGas filed an application to increase RIPET's propane export license to 80,000 Bbls/d. For 2020, AltaGas has in place multi-year agreements for the purchase of approximately 50 percent of the propane expected to be shipped from RIPET; and

▪ Petrogas is a leading North American integrated midstream company, with an extensive logistics network consisting of over 3,000 rail car leases used entirely to support its transportation needs. Petrogas owns and operates the Ferndale terminal, which is capable of handling LPG exports up to 50,000 Bbls/d with 750,000 Bbls of on-site storage capacity. AltaGas has an approximate one-third indirect ownership interest in Petrogas via its 50 percent interest in AIJVLP, which holds an approximate two-thirds ownership interest in Petrogas. The remaining 50 percent interest in AIJVLP is owned

AltaGas Ltd. – 2019 MD&A and Financial Statements - 15

by Idemitsu Kosan Co., Ltd. AIJVLP has received a Put Notice from SAM for the purchase of SAM's approximate one-third interest in Petrogas.

Gas Processing

Gas processing activities are comprised of gathering systems that 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 to North American natural gas markets. All AltaGas' processing facilities are capable of extracting NGL. The 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. AltaGas' processing infrastructure includes:

▪ The Townsend facility, a 396 Mmcf/d gas processing facility, along with the related egress pipelines, truck terminal, and NGL treatment infrastructure (the Townsend complex), which is wholly owned by AltaGas. The majority of the processing capacity is contracted with Montney producers in the area under long-term take-or-pay agreements. In 2018, AltaGas entered into definitive agreements with Kelt Exploration Ltd. to provide an energy infrastructure solution for the liquids-rich Inga Montney development located in British Columbia. This project will add a 198 Mmcf/d C3+ deep cut gas processing facility and is expected to be on-stream in the first quarter of 2020. AltaGas is the operator of these facilities;

▪ The Gordondale facility, which has licensed capacity of 150 Mmcf/d of natural gas and is wholly owned and operated by AltaGas. 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 NGL value for the producer;

▪ The Blair Creek facility, which has licensed capacity of 120 Mmcf/d of natural gas and is wholly owned and operated by AltaGas. The facility processes gas gathered from producers in the area. The plant is equipped with liquids extraction facilities to capture the NGL value for the producer;

▪ The Aitken Creek processing facilities, in which AltaGas has a 50 percent ownership interest. Black Swan Energy Ltd. (Black Swan) owns the remaining 50 percent interest. These facilities include Aitken Creek North, an operating shallow gas plant with a current capacity of 110 Mmcf/d (55 Mmcf/d net), and Nig Creek, a shallow gas plant with capacity of 100 Mmcf/d (50 Mmcf/d net) that came on-stream in the third quarter of 2019. The Aitken Creek processing facilities are located in the liquids rich Montney resource play in Northeast British Columbia (NEBC) and are operated by Black Swan. AltaGas and Black Swan have also entered into long-term processing, transportation, and marketing agreements that will include new AltaGas liquids handling infrastructure in NEBC;

▪ The Harmattan facility, which has a natural gas processing capacity of 490 Mmcf/d and is wholly owned and operated by AltaGas. Harmattan's natural gas processing consists of sour gas treating, co-stream processing, and NGL extraction. In addition, Harmattan has fractionation and terminalling facilities (see below section on Fractionation and Liquids Handling); and

▪ Interests in four NGL extraction plants with net licensed inlet capacity of 1.0 Bcf/d. The extraction plants consist of Edmonton Ethane Extraction Plant (EEEP), Joffre Ethane Extraction Plant (JEEP), Pembina Empress Extraction Plant (PEEP), and the Younger extraction plant (Younger). The extraction assets provide stable fixed-fee or cost-of-service type revenues and margin based revenues. The natural gas supply to EEEP, JEEP, and PEEP 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.

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Fractionation and Liquids Handling

Fractionation production is a function of NGL mix volumes processed, liquids composition, recovery efficiency of the plants, and plant on-line time. Due to the integration and inter-connectivity of AltaGas' Midstream assets, the fractionation and liquids handling activities provide integral services to the other Midstream businesses and customers by providing access to high value NGL products with access to North American and global markets through rail networks, pipelines, RIPET, and Ferndale.

AltaGas' liquids handling infrastructure consists of NGL pipelines; treating, storage, truck, and rail terminal infrastructure centered around AltaGas’ key Midstream operating assets at RIPET; Harmattan; and, in NEBC, Townsend and North Pine.

AltaGas’ fractionation and liquids handling infrastructure includes:

▪ The North Pine facility, which is the only custom fractionation plant in British Columbia, providing area producers with a lower cost, higher netback alternative for their NGLs than transporting and fractionating in Edmonton. The first train of the North Pine facility is capable of processing up to 10,000 Bbls/d of NGL mix.Construction is ongoing for the second NGL separation train capable of processing up to an additional 10,000 Bbls/d of NGL mix and it is expected to be on-stream in the first quarter of 2020. The North Pine facility is connected to the Townsend truck terminal via the North Pine pipelines, to the Tourmaline Gundy facility, and also has access to the Canadian National rail network, allowing the transportation of propane, butane, and condensate to North American markets and propane to global markets via RIPET;

▪ The Harmattan gas processing complex, which has NGL fractionation capacity of 35,000 Bbls/d, a 450 Bbls/d capacity frac oil processing facility, and a 200 tonnes/d capacity industrial grade carbon dioxide (CO2) facility. Harmattan is the only deep‑cut and full fractionation plant in its operating area;

▪ Younger, which has fractionation capacity of 19,500 Bbls/d (9,750 Bbls/d net). Effective April 1, 2018, AltaGas has a 50 percent interest in Younger's fractionation, storage, loading, treating, and terminalling of NGL and Pembina assumed plant operatorship. The remaining interest is held by Pembina;

▪ A network of NGL pipelines in the NEBC area that connects upstream gas plant producers to the AltaGas North Pine facility. The NEBC NGL pipelines consist of two liquids egress lines, with a third line under construction, that connect the Townsend facility to the Townsend truck terminal on the Alaska Highway (30 km) and AltaGas' North Pine facility (70 km);

▪ NGL and spec propane lines currently under construction to connect the Townsend complex, in the North, to the Aitken Creek facilities through a 60 km NGL pipeline (Aitken Connector) and to the Tourmaline Gundy facility, in the West, through a 15 km spec propane line. The NGL and propane pipelines are currently under construction and are expected to be fully operational by the first quarter of 2020;

▪ A rail logistics network consisting of approximately 1,200 rail cars that AltaGas manages to support LPG and NGL handling;

▪ 50 percent ownership of the 5.3 Bcf Sarnia natural gas storage facility connected to the Dawn Hub in Eastern Canada; and

▪ The Alton Natural Gas Storage Project under construction.

In addition to supporting the other Midstream activities within AltaGas, the liquids handling business identifies opportunities to buy and resell 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.

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Pipeline Investments

AltaGas has a 10 percent equity interest in Mountain Valley. The proposed pipeline will transport approximately 2.0 Bcf/d of natural gas and is expected to be placed into service in late 2020. In April 2018, AltaGas 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 into service in mid-2021.

AltaGas also held a 10 percent interest in the Constitution pipeline through a 10 percent equity investment in Constitution Pipeline Company, LLC. The natural gas pipeline venture was proposed to transport natural gas from the Marcellus region in northern Pennsylvania to major northeastern markets. In February 2020, following evaluations of the diminished underlying economics for the proposed Constitution pipeline project, the partners ofConstitution Pipeline Company, LLC elected not to proceed with the project.

Retail Energy Marketing

AltaGas’ retail gas marketing business sells natural gas directly to residential, commercial, and industrial customers in Maryland, Virginia, Delaware, Pennsylvania, and the District of Columbia. AltaGas provides natural gas and NGL marketing and gas transportation services to optimize the value of the infrastructure assets and meet customer needs. Specifically, AltaGas 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. In addition, AltaGas also contracts for storage and pipeline capacity in its trading activities through both long-term contracts and short-term transportation releases.

Capitalize on Opportunities

To take advantage of opportunities such as continued Montney LPG growth and the increasing Asian demand for LPG, AltaGas plans to grow its Midstream business by expanding and optimizing strategically-located assets as well as its global export business. New infrastructure is expected to be larger scale facilities supporting the vast reserves in North America and growing the footprint and integration of AltaGas' existing assets. 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:

▪ Maximize and grow the unique structural advantage within AltaGas' integrated platform in the Montney region, leveraging RIPET and the integrated value chain to attract volumes;

▪ Increase utilization and export volumes at RIPET, continuing to build on export competency, with volumes expected to be in excess of 50,000 Bbls/d by the end of 2020;

▪ Develop high quality assets that enhance the integrated Midstream offering and connect producers to the global markets;

▪ Consolidate its position in key markets to deliver optimal growth over the long-term;

▪ Provide a fully-integrated Midstream service offering including gas processing and NGL extraction, fractionation, liquids handling facilities, and transportation and marketing services to customers across the energy value chain, with higher producer netbacks resulting from global export access to higher value global markets, including Asia;

▪ Maintain strong relationships with Indigenous peoples, regulators, customers, partners, and service providers;

▪ Optimize existing rail infrastructure to gain scale and efficiencies;

▪ Increase utilization and throughput at existing facilities while maintaining top tier operating costs, high reliability and NGL recovery, highly efficient business administration, and effective safety and environmental programs;

▪ Mitigate commodity risk through effective hedging programs and risk management systems;

AltaGas Ltd. – 2019 MD&A and Financial Statements - 18

▪ Mitigate volume risk through contractual structures, redeployment of equipment, and expansion of geographic reach; and

▪ Mitigate counterparty risk through customer base growth and diversification.

Power

Description of Assets

AltaGas' Power segment includes 710 MW of operational gross capacity from natural gas-fired, distributed generation, and energy storage assets, certain of which are pending sale, located in Alberta, Canada, and the United States, primarily in California and Colorado. The Power business also includes WGL’s retail power marketing business. Throughout 2018 and 2019, AltaGas has disposed of the majority of the assets in the Power segment and continues to operate under a capital-light power strategy.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 19

Specifically, 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 is under a Power Purchase Arrangement (PPA) with a creditworthy utility;

▪ 45 MW of cogeneration and 3 MW of gas-fired peaking plant capacity in Alberta;

▪ 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 power directly to residential, commercial, and industrial customers in Maryland, Virginia, Delaware, Pennsylvania, Ohio, and the District of Columbia; and

▪ Certain remaining distributed generation assets.

In southern California, the 507 MW Blythe Energy Center utilizes gas-fired generation to produce power and serves the transmission grid operated by the California Independent System Operator (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 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 2019,AltaGas announced the successful recontracting of the Blythe facility to SCE. With the approval of the new PPA with SCE by the California Public Utilities Commission in January 2020, the Blythe Energy Center is contracted under a PPA until December 31, 2023. Under the tolling agreement(s), SCE has exclusive rights to all capacity, energy, ancillary services, and resource adequacy benefits during the PPA term.

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 that included the remainder of 2018, as well as the majority of 2019 and 2020. AltaGas retains the rights to the energy and ancillary service attributes of the facility, which are sold on a merchant basis into the CAISO.

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.In addition, AltaGas is in the initial stages of permitting a new 40 MW stand-alone energy storage project in Goleta, California.

The U.S. retail power marketing business sells power to end users in Maryland, Virginia, Delaware, Pennsylvania, Ohio, 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 2022 has been entered into with Shell Energy North America (US), L.P. for the majority of electricity requirements to service end users, which also reduces credit requirements.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 20

Consolidated Financial Review

	Three Months Ended December 31				Year Ended December 31
($ millions except where noted)	2019		2018		2019		2018
Revenue	1,534		1,727		5,495		4,257
Normalized EBITDA (1)	425		394		1,271		1,009
Net income (loss) applicable to common shares	(103	)	174		769		(502	)
Normalized net income (1)	186		120		324		195
Total assets	19,795		23,488		19,795		23,488
Total long-term liabilities	9,301		11,746		9,301		11,746
Net additions (dispositions) of property, plant and equipment	240		16		(1,090	)	573
Dividends declared (2)	67		121		266		463
Cash from (used by) from operations	16		(60	)	616		(79	)
Normalized funds from operations (1)	332		255		895		657
Normalized adjusted funds from operations (1)	307		255		835		626
Normalized utility adjusted funds from operations (1)	241		192		573		460
Normalized effective income tax rate (%) (1)	12.2		13.1		15.4		14.0

	Three Months Ended December 31				Year Ended December 31
($ per share, except shares outstanding)	2019		2018		2019	2018
Net income (loss) per common share - basic	(0.37	)	0.64		2.78	(2.25	)
Net income (loss) per common share - diluted	(0.37	)	0.64		2.77	(2.25	)
Normalized net income - basic (1)	0.67		0.44		1.17	0.88
Normalized net income - diluted (1)	0.67		0.44		1.17	0.87
Dividends declared (2)	0.24		0.45		0.96	2.09
Cash from (used by) from operations	0.06		(0.22	)	2.22	(0.35	)
Normalized funds from operations (1)	1.19		0.94		3.23	2.95
Normalized adjusted funds from operations (1)	1.10		0.94		3.01	2.81
Normalized utility adjusted funds from operations (1)	0.87		0.71		2.07	2.06
Shares outstanding - basic (millions)
During the period (3)	278		272		277	223
End of period	279		275		279	275

(1) Non‑GAAP financial measure; see discussion in the Non-GAAP Financial Measures section of this MD&A.

(2) Dividends declared per common share per month: $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 2019 was $425 million, compared to $394 million for the same quarter in 2018. Factors positively impacting normalized EBITDA included contributions from RIPET which was placed into service in May 2019,higher contributions from Washington Gas' utilities primarily due to Virginia and Maryland rate cases,higher margins from WGL's retail gas and power marketing businesses, higher transportation and storage spreads from WGL Midstream assets, higher Allowance for Funds Used During Construction (AFUDC) related to Mountain Valley, higher NGL marketing EBITDA due to a strong spot market, and higher equity earnings from Petrogas primarily due to higher export volumes and domestic margins. These were partially offset by the impact of asset sales, including the U.S. distributed generation assets in September 2019, the San Joaquin facilities in the fourth quarter of 2018, the Northwest Hydro facilities in January 2019, WGL Midstream's indirect non-operating interest in Central Penn in November 2019, WGL Midstream's interest in Stonewall in May 2019, the initial public offering (IPO) of ACI in October 2018, and certain non-core Midstream and Power assets in February 2019. Other factors decreasing EBITDA in the fourth quarter of 2019 included higher operating costs at Washington Gas, the impact of CINGSA's rate case decision received in the third quarter of 2019, and higher corporate employee costs primarily due to incentive plans. For the three

AltaGas Ltd. – 2019 MD&A and Financial Statements - 21

months ended December 31, 2019, fluctuations in the Canadian/U.S. dollar exchange rate resulted in a $1 million decrease in normalized EBITDA.

Net loss applicable to common shares for the fourth quarter of 2019 was $103 million ($0.37 per share), compared to net income of $174 million ($0.64 per share) for the same quarter in 2018. The decrease was mainly due to provisions recorded in the fourth quarter of 2019 and higher unrealized losses on risk management contracts, partially offset by the same previously referenced factors impacting normalized EBITDA, lower depreciation and amortization expense, lower interest expense, and gains on the sale of assets.

Normalized funds from operations for the fourth quarter of 2019 were $332 million ($1.19 per share), compared to $255 million ($0.94 per share) for the same quarter in 2018. The increase was mainly due to lower interest expense and the same factors impacting normalized EBITDA. In the fourth quarter of 2019, AltaGas received $3 million of dividend income from the Petrogas Preferred Shares (2018 - $3 million) and $2 millionof common share dividends from Petrogas (2018 - $2 million).

Normalized adjusted funds from operations (AFFO) for the fourth quarter of 2019 were $307 million ($1.10 per share), compared to $255 million ($0.94 per share) for the same quarter in 2018. Factors impacting AFFO in the fourth quarter of 2019 included the same drivers as normalized funds from operations and higher net cash paid to non-controlling interests. In the fourth quarter of 2019, AltaGas paid $17 million of preferred share dividends (2018 - $17 million).

Normalized utility adjusted funds from operations (UAFFO) for the fourth quarter of 2019 were $241 million ($0.87 per share), compared to $192 million ($0.71 per share) for the same quarter in 2018. The increase was due to the same drivers as normalized adjusted funds from operations, partially offset by higher utilities depreciation.

In the fourth quarter of 2019, AltaGas recorded pre-tax provisions of approximately $415 million ($319 million after-tax). These provisions primarily related to various assets in the Power segment and a sour gas treatment facility in Alberta. In the fourth quarter of 2018, AltaGas recorded pre-tax provisions of approximately $31 million ($23 million after-tax). These provisions primarily related to a power development project in the U.S., a WGL Energy Systems financing receivable, and certain non-core Midstream assets. In addition, in the fourth quarter of 2018, AltaGas recorded a pre-tax provision of $15 million ($11 million after-tax) on its equity investment in Craven Wood Country Energy LP, which was sold in the third quarter of 2019.

Operating and administrative expenses for the fourth quarter of 2019 were $340 million, compared to $346 million for the same quarter in 2018. The decrease was mainly due to lower transaction costs on acquisitions and dispositions, the impact of the sale of the U.S. distributed generation assets in September 2019, the impact of the IPO of ACI in October 2018, the impact of the sale of the San Joaquin facilities in the fourth quarter of 2018, and the impact of the sale of Northwest Hydro in January 2019, partially offset by the impact of RIPET coming online in May 2019, and higher pipeline leak remediation costs at Washington Gas. Depreciation and amortization expense for the fourth quarter of 2019 was $109 million, compared to $126 million for the same quarter in 2018. The decrease was mainly due to the impact of asset sales completed in the fourth quarter of 2018 and throughout 2019, partially offset by new assets placed into service. Interest expense for the fourth quarter of 2019 was $77 million, compared to $110 million for the same quarter in 2018. The decrease was primarily due to lower average debt balances as a result of debt reduction from proceeds on asset sales.

AltaGas recorded an income tax recovery of $87 million for the fourth quarter of 2019 compared to $63 million in the same quarter in 2018. The increase in tax recovery was mainly due to tax recoveries booked on asset provisions in the fourth quarter of 2019, partially offset by a tax recovery on assets classified as held for sale in the fourth quarter of 2018.

Normalized net incomewas $186 million ($0.67 per share) for the fourth quarter of 2019, compared to $120 million ($0.44 per share) reported for the same quarter in 2018. The increase was mainly due to the same factors impacting normalized EBITDA, lower interest expense, and lower depreciation and amortization expense. Also driving the increase in normalized net income was a low normalized effective tax rate, which was impacted by the accretion of regulatory amounts through tax expense and

AltaGas Ltd. – 2019 MD&A and Financial Statements - 22

non-taxable equity earnings. Normalizing items in the fourth quarter of 2019increased normalized net income by $289 million and included after‑tax amounts related to gains on sale of assets, changes in fair value of natural gas optimization inventory, recovery of transaction costs related to acquisitions and dispositions, unrealized losses on risk management contracts, provisions on assets, a statutory tax rate change in Alberta, a unitary tax adjustment related to the acquisition of WGL and U.S. asset sales, a gain on the redemption of Washington Gas preferred shares, and merger commitment costs. Normalizing items in the fourth quarter of 2018reduced normalized net income by $54 million and 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. Please refer to the Non-GAAP Financial Measures section of this MD&A for further details on normalization adjustments.

Year Ended December 31

Normalized EBITDA for the year ended December 31, 2019 was $1.3 billion, compared to $1.0 billionin 2018. Factors positively impacting normalized EBITDA included a full year of contributions from WGL, contributions from RIPET which was placed into service in May 2019, higher equity earnings from Petrogas primarily due to higher export volumes and domestic margins, higher volumes from WGL's retail power business, equity earnings from ACI, higher AFUDC related to Mountain Valley, higher transportation and storage spreads from WGL Midstream assets, contributions from Central Penn which was placed into service in October 2018, the impact of the stronger U.S. dollar on reported results from U.S. assets, and contributions from the Aitken Creek facilities. These were partially offset by the impact of asset sales, including the San Joaquin facilities in the fourth quarter of 2018, the Northwest Hydro facilities in January 2019, the IPO of ACI in October 2018, the U.S. distributed generation assets in September 2019, certain non-core Midstream and Power assets in February 2019, WGL Midstream's interest in Stonewall in May 2019, the Busch Ranch facilities in the fourth quarter of 2018, and WGL Midstream's indirect non-operating interest in Central Penn in November 2019. Other factors negatively impacting normalized EBITDA included higher corporate costs primarily due to employee incentive plans, lower interest income, the impact of the extended planned outage at Blythe, and the impact of CINGSA's rate case decision received in the third quarter of 2019. For the year ended December 31, 2019, the average Canadian/U.S. dollar exchange rate increased to 1.33 from an average of 1.30 in 2018, resulting in an increase in normalized EBITDA of approximately$5 million.

Net income applicable to common shares for the year ended December 31, 2019 was$769 million ($2.78 per share), compared to net loss applicable to common shares of $502 million ($2.25 per share) in 2018. The increase was mainly due to gains on asset sales, lower provisions on assets, the absence of 2018 merger commitment costs, and the same previously referenced factors impacting normalized EBITDA, partially offset by lower income tax recovery, higher interest expense, higher provisions on equity investments, higher depreciation and amortization expense, and higher unrealized losses on risk management contracts.

Normalized funds from operations for the year ended December 31, 2019 were $895 million ($3.23 per share), compared to $657 million ($2.95 per share) in 2018. The increase was mainly due to the same drivers as normalized EBITDA, partially offset by higher interest expense. In 2019, AltaGas received $13 million of dividend income from the Petrogas Preferred Shares (2018 - $13 million) and $6 million of common share dividends from Petrogas (2018 - $5 million).

Normalized adjusted funds from operations for the year ended December 31, 2019 were $835 million ($3.01 per share), compared to $626 million ($2.81 per share) in 2018. The increase was mainly due to the same drivers as normalized funds from operations and lower cash received from non-controlling interests. In 2019, AltaGas paid $68 million of preferred share dividends (2018 - $67 million).

Normalized utility adjusted funds from operations for the year ended December 31, 2019 were $573 million ($2.07 per share), compared to $460 million ($2.06 per share) in 2018. The increase was due to the same drivers as normalized adjusted funds

AltaGas Ltd. – 2019 MD&A and Financial Statements - 23

from operations partially offset by higher utilities depreciation. The per share amount was impacted by the higher average number of shares outstanding in 2019 compared to 2018.

In 2019, AltaGas recorded pre-tax provisions of approximately $416 million ($320 million after-tax). These provisions primarily related to various assets in the Power segment and a sour gas treatment facility in Alberta. In addition, AltaGas recorded pre-tax provisions on equity investments of approximately $46 million ($29 million after-tax), including $44 million related to WGL Midstream's indirect, non-operating interest in Central Penn which was sold in November 2019, and $2 million related to biomass investments which were sold in the third quarter of 2019. In 2018, AltaGas recorded pre-tax provisions of approximately $729 million (after-tax $562 million). These provisions primarily related to the San Joaquin power assets in California which were sold in the fourth quarter of 2018, certain non-core Midstream and Power assets in Canada which were sold in the first quarter of 2019, and certain assets included in the 2018 IPO of ACI. In addition, pre-tax provisions of $37 million and $2 million were recorded on certain remaining Midstream assets and the Pomona Gas Repowering project respectively, $6 million was recorded on a WGL Energy Systems financing receivable, and $15 million ($11 million after-tax) against AltaGas' investment in Craven Wood Country Energy LP, which was subsequently sold in the third quarter of 2019.

Operating and administrative expenses for the year ended December 31, 2019 were $1.3 billion, compared to $1.1 billionin 2018. The increase was mainly due to the addition of WGL’s operating and administrative expenses for the first half of the year, and the impact of RIPET coming into service in May 2019, partially offset by the absence of merger commitment costs recorded in 2018 and the impact of asset sales completed in the fourth quarter of 2018 and throughout 2019. Depreciation and amortization expense for the year ended December 31, 2019 was $438 million, compared to $394 millionin 2018. The increase was mainly due to depreciation and amortization expense on WGL assets for the first half of the year and new assets placed into service, partially offset by the impact of asset sales completed in the fourth quarter of 2018 and throughout 2019. Interest expense for the year ended December 31, 2019 was $346 million, compared to $309 millionin 2018. The increase was primarily due a full year of interest on debt assumed in the WGL Acquisition, partly offset by lower average debt balances in the last half of 2019 as a result of proceeds on asset sales.

AltaGas recorded an income tax recovery of $28 million for the year ended December 31, 2019 compared to $263 millionin 2018. The decrease in tax recovery was mainly due to tax expense incurred on the sale of the remaining interest in the Northwest Hydro facilities and tax on WGL’s earnings. These tax expenses were partially offset by a tax recovery on the sale of WGL's distributed generation assets, a unitary tax rate adjustment related to the acquisition of WGL and U.S. asset sales, and a tax rate adjustment related to the Alberta Job Creation Tax Cut. Current tax expense of approximately $63 million was recorded in 2019, of which approximately $37 million related to tax on asset sales.

Normalized net income was $324 million ($1.17 per share) for the year ended December 31, 2019, compared to $195 million ($0.88 per share) in 2018. The increase was mainly due to the same previously referenced factors impacting normalized EBITDA, partially offset by lower income tax recovery, higher interest expense, and higher depreciation and amortization expense. Also driving the increase was a low normalized effective tax rate, which was impacted by the accretion of regulatory amounts through tax expense and non-taxable equity earnings. Normalizing items in the year ended December 31, 2019reduced normalized net income by $445 million and included after‑tax amounts related to gains on sale of assets, changes in fair value of natural gas optimization inventory, merger commitment cost recovery due to a change in timing related to certain WGL merger commitments, transaction costs related to acquisitions and dispositions, unrealized losses on risk management contracts, losses on investments, provisions on assets, provisions on investments accounted for by the equity method, a gain on the redemption of Washington Gas preferred shares, the impact of a statutory tax rate change in Alberta, and a unitary tax adjustment related to the acquisition of WGL and U.S. asset sales. Normalizing items in the year ended December 31, 2018increased normalized net income by $697 million and 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

AltaGas Ltd. – 2019 MD&A and Financial Statements - 24

with the bridge facility for the WGL Acquisition, losses on sale of assets, and losses on investments. Please refer to the Non-GAAP Financial Measures section of this MD&A for further details on normalization adjustments.

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, normalized adjusted funds from operations, normalized utility adjusted funds from operations, normalized income tax expense, normalized effective income tax rate, 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)	2019			2018			2019			2018
Normalized EBITDA	$	425		$	394		$	1,271		$	1,009
Add (deduct):
Transaction (costs) recoveries related to acquisitions and dispositions	4			(12		)	(12		)	(63		)
Merger commitment recovery (costs)	(1		)	—			4			(182		)
Unrealized gains (losses) on risk management contracts	(47		)	44			(62		)	56
Changes in fair value of natural gas optimization inventory	(6		)	12			7			15
Non-controlling interest related to HLBV investments	—			(22		)	(8		)	(39		)
Realized losses on foreign exchange derivatives	—			—			—			(35		)
Losses on investments	—			(10		)	(4		)	(10		)
Gains (losses) on sale of assets	56			(12		)	875			(10		)
Provisions on assets	(415		)	(31		)	(416		)	(729		)
Provisions on investments accounted for by the equity method	—			(15		)	(46		)	(15		)
Investment tax credits related to distributed generation assets	—			(2		)	(7		)	(5		)
Accretion expenses	(1		)	(3		)	(5		)	(11		)
Foreign exchange gains (losses)	(1		)	1			(1		)	5
EBITDA	$	14		$	344		$	1,596		$	(14	)
Add (deduct):
Depreciation and amortization	(109		)	(126		)	(438		)	(394		)
Interest expense	(77		)	(110		)	(346		)	(309		)
Income tax recovery	87			63			28			263
Net income (loss) after taxes (GAAP financial measure)	$	(85	)	$	171		$	840		$	(454	)

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 Statements of Income (Loss) using net income (loss) adjusted for pre‑tax depreciation and amortization, interest expense, and income tax recovery.

Normalized EBITDA includes additional adjustments for unrealized gains (losses) on risk management contracts, losses on investments, transaction (costs) recoveries related to acquisitions and dispositions, merger commitment recovery (costs) primarily

AltaGas Ltd. – 2019 MD&A and Financial Statements - 25

due to a change in timing related to certain WGL merger commitments, gains (losses) on the sale of assets, accretion expenses related to asset retirement obligations, realized losses on foreign exchange derivatives, provisions on assets, provisions on investments accounted for by the equity method, foreign exchange gains (losses), 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)	2019			2018			2019			2018
Normalized net income	$	186		$	120		$	324		$	195
Add (deduct) after-tax:
Transaction (costs) recoveries related to acquisitions and dispositions	3			(9		)	(10		)	(50		)
Merger commitment recovery (cost)	(1		)	—			5			(135		)
Unrealized gains (losses) on risk management contracts	(36		)	30			(47		)	34
Changes in fair value of natural gas optimization inventory	(5		)	12			4			15
Realized loss on foreign exchange derivatives	—			—			—			(35		)
Losses on investments	—			(10		)	(4		)	(1		)
Gains (losses) on sale of assets	42			(36		)	814			(35		)
Provisions on assets	(319		)	(23		)	(320		)	(562		)
Provisions on investments accounted for by the equity method	6			(11		)	(29		)	(11		)
Tax adjustment on assets held for sale	—			104			—			104
Unitary tax adjustment on acquisition of WGL and U.S. asset sales	19			—			19			—
Gain on redemption of preferred shares	3			—			3			—
Statutory tax rate change	(1		)	—			10			—
Financing costs associated with the bridge facility	—			(3		)	—			(21		)
Net income (loss) applicable to common shares (GAAP financial measure)	$	(103	)	$	174		$	769		$	(502	)

Normalized net income represents net income (loss) applicable to common shares adjusted for the after-tax impact of unrealized gains (losses) on risk management contracts, losses on investments, transaction (costs) recoveries related to acquisitions and dispositions, merger commitment recovery (cost) primarily due to a change in timing related to certain WGL merger commitments, gains (losses) on the sale of assets, financing costs associated with the bridge facility for the WGL Acquisition, realized loss on foreign exchange derivatives, provisions on investments accounted for by the equity method, provisions on assets, a tax adjustment on assets that were held for sale, statutory tax rate change, unitary tax adjustment related to the acquisition of WGL and U.S. asset sales, gain on redemption of preferred shares, 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.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 26

Normalized Funds from Operations, AFFO, and UAFFO

	Three Months Ended December 31						Year Ended December 31
($ millions)	2019			2018			2019			2018
Normalized utility adjusted funds from operations	$	241		$	192		$	573		$	460
Add (deduct):
Utilities depreciation and amortization	66			63			262			166
Normalized adjusted funds from operations	$	307		$	255		$	835		$	626
Add (deduct):
Net cash paid to (received from) non-controlling interests	4			(21		)	(34		)	(66		)
Midstream and Power maintenance capital	4			4			26			30
Preferred dividends paid	17			17			68			67
Normalized funds from operations	$	332		$	255		$	895		$	657
Add (deduct):
Transaction and financing recoveries (costs) related to acquisitions    and dispositions	4			(12		)	(12		)	(63		)
Merger commitment (costs) recovery	(1		)	—			4			(182		)
Current tax expense on asset sales	(37		)	—			(37		)	—
Funds from operations	$	298		$	243		$	850		$	412
Add (deduct):
Net change in operating assets and liabilities	(281		)	(301		)	(232		)	(487		)
Asset retirement obligations settled	(1		)	(2		)	(2		)	(4		)
Cash from (used by) operations (GAAP financial measure)	$	16		$	(60	)	$	616		$	(79	)

Normalized funds from operations, normalized adjusted funds from operations, and normalized utility adjusted funds from operations are used to assist Management and investors in analyzing the liquidity of the Corporation. Management uses these measures to understand the ability to generate funds for capital investments, debt repayment, dividend payments, and other investing activities.

Funds from operations are calculated from the Consolidated Statements of Cash Flows and are defined as cash from (used by) operations before net changes in operating assets and liabilities and expenditures incurred to settle asset retirement obligations. Normalized funds from operations is calculated based on cash from (used by) operations and adjusted for changes in operating assets and liabilities in the period and non‑operating related expenses (net of current taxes) such as transaction and financing costs related to acquisitions, merger commitments, and current taxes due to asset sales. Normalized adjusted funds from operations is based on normalized funds from operations, further adjusted to remove the impact of cash transactions with non-controlling interests, Midstream and Power maintenance capital, and preferred share dividends paid. Normalized utility adjusted funds from operations is based on normalized adjusted funds from operations, further adjusted for Utilities segment depreciation and amortization.

Funds from operations, normalized funds from operations, normalized adjusted funds from operations, and normalized utility adjusted funds from operations as presented should not be viewed as an alternative to cash from (used by) operations or other cash flow measures calculated in accordance with GAAP.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 27

Normalized Income Tax Expense

	Three Months Ended December 31						Year Ended December 31
($ millions)	2019			2018			2019			2018
Normalized income tax expense	$	29		$	21		$	74		$	46
Add (deduct) tax impact of:
Transaction (costs) recoveries related to acquisitions and dispositions	1			(2		)	(2		)	(12		)
Merger commitment recovery (cost)	—			—			—			(47		)
Unrealized gains (losses) on risk management contracts	(10		)	14			(14		)	24
Changes in fair value of natural gas optimization inventory	—			—			3			(1		)
Losses on investments	—			—			—			(10		)
Gains (losses) on sale of assets	14			24			61			25
Provisions on assets	(96		)	(9		)	(96		)	(167		)
Provisions on investments accounted for by the equity method	(6		)	(4		)	(18		)	(4		)
Tax adjustment on assets held for sale	—			(104		)	—			(104		)
Statutory tax rate change	1			—			(10		)	—
Unitary tax adjustment on acquisition of WGL and U.S. asset sales	(19		)	—			(19		)	—
Financing costs associated with the bridge facility	—			(1		)	—			(8		)
Investment tax credits related to distributed generation assets	(1		)	(2		)	(7		)	(5		)
Income tax recovery (GAAP financial measure)	$	(87	)	$	(63	)	$	(28	)	$	(263	)

Normalized income tax expense represents income tax recovery adjusted for the tax impact of unrealized gains (losses) on risk management contracts, losses on investments, transaction (costs) recoveries related to acquisitions and dispositions, merger commitment recovery (cost), gains (losses) on the sale of assets, financing costs associated with the bridge facility for the WGL Acquisition, provisions on investments accounted for by the equity method, provisions on assets, a tax adjustment on assets that were held for sale, statutory tax rate change, a unitary tax adjustment related to the acquisition of WGL and U.S. asset sales, distributed generation asset related investment tax credits, and changes in fair value of natural gas optimization inventory. This measure is used by Management to enhance the comparability of the impact of income tax on AltaGas’ earnings, as it reflects the underlying performance of AltaGas’ business activities, and is presented to provide this perspective to analysts and investors.

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 (excluding third-party project financing obtained for the construction of certain energy management services projects), 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 Capital Resources section of this MD&A. 

AltaGas Ltd. – 2019 MD&A and Financial Statements - 28

Supplemental Calculations

Reconciliation of Normalized EBITDA to Normalized Net Income

The below table provides a supplemental reconciliation of normalized EBITDA to normalized net income. Both of these non-GAAP measures have been previously reconciled to the relevant GAAP financial measures in the section above. This supplemental information is provided as additional information to assist analysts and investors in comparing normalized EBITDA to normalized net income and is not intended as a substitute for the reconciliations to the nearest comparable GAAP measures. Readers should not place undue reliance on this supplemental reconciliation.

	Three Months Ended December 31						Year Ended December 31
($ millions)	2019			2018			2019			2018
Normalized EBITDA	$	425		$	394		$	1,271		$	1,009
Add (deduct):
Depreciation and amortization	(109		)	(126		)	(438		)	(394		)
Interest expense	(77		)	(110		)	(346		)	(309		)
Normalizing items impacting interest expense	—			4			—			28
Income tax recovery	87			63			28			263
Normalizing items impacting tax recovery	(116		)	(84		)	(102		)	(309		)
Accretion expenses	(1		)	(3		)	(5		)	(11		)
Foreign exchange gains (losses)	(1		)	1			(1		)	5
Non-controlling interest related to HLBV investments	—			(22		)	(8		)	(39		)
Net (income) loss applicable to non-controlling interests	(5		)	20			(7		)	19
Preferred share dividends	(17		)	(17		)	(68		)	(67		)
Normalized net income	$	186		$	120		$	324		$	195

Calculation of Normalized Effective Income Tax Rate

The below table provides a calculation of normalized effective income tax rate from normalized net income and normalized income tax expense. Both of these non-GAAP measures have been previously reconciled to the relevant GAAP measures in the section above. This supplemental calculation is provided as additional information to assist analysts and investors in comparing normalized income tax expense to normalized net income and is not intended as a substitute for the reconciliations to the nearest comparable GAAP measures. Readers should not place undue reliance on this supplemental calculation.

	Three Months Ended December 31					Year Ended December 31
($ millions, except where noted)	2019		2018			2019		2018
Normalized net income	$	186	$	120		$	324	$	195
Add (deduct):
Normalized income tax expense	29		21			74		46
Net income (loss) applicable to non-controlling interests	5		(20		)	7		(19		)
Non-controlling interest related to HLBV investments	—		22			8		39
Preferred share dividends	17		17			68		67
Normalized net income before taxes	$	237	$	160		$	481	$	328
Normalized effective income tax rate (%) (1)	12.2		13.1			15.4		14.0

(1) Calculated as normalized income tax expense divided by normalized net income before taxes.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 29

Results of Operations by Reporting Segment

Normalized EBITDA (1)	Three Months Ended December 31						Year Ended December 31
($ millions)	2019			2018			2019			2018
Utilities	$	244		$	232		$	657		$	426
Midstream	171			93			501			277
Power	22			76			154			320
Sub-total: Operating Segments	$	437		$	401		$	1,312		$	1,023
Corporate	(12		)	(7		)	(41		)	(14		)
	$	425		$	394		$	1,271		$	1,009

(1) Non‑GAAP financial measure; See discussion in the Non‑GAAP Financial Measures section of this MD&A.

Revenue	Three Months Ended December 31						Year Ended December 31
($ millions)	2019			2018			2019			2018
Utilities	$	801		$	818		$	2,591		$	1,766
Midstream	424			489			1,581			1,435
Power	319			412			1,367			1,171
Sub-total: Operating Segments	$	1,544		$	1,719		$	5,539		$	4,372
Corporate	—			28			—			(2		)
Intersegment eliminations	(11		)	(20		)	(44		)	(113		)
	$	1,533		$	1,727		$	5,495		$	4,257

Utilities

Operating Statistics

	Three Months Ended December 31				Year Ended December 31
	2019		2018		2019		2018
Natural gas deliveries - end-use (Bcf) (1)	52.2		53.3		159.4		107.3
Natural gas deliveries - transportation (Bcf) (1)	38.3		39.1		134.4		89.2
Service sites (thousands) (2)	1,653		1,643		1,653		1,643
Degree day variance from normal - SEMCO Gas (%) (3)	4.3		7.5		5.0		5.6
Degree day variance from normal - ENSTAR (%) (3)	(20.6	)	(19.6	)	(17.7	)	(11.5	)
Degree day variance from normal - Washington Gas (%) (3) (4)	(3.2	)	0.4		(7.9	)	(2.5	)

(1) Bcf is one billion cubic feet.

(2) Service sites reflect all of the service sites of the utilities, including transportation and non‑regulated business lines.

(3) A degree day 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 that 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 Washington Gas hedge to offset the effects of weather. As a result, colder or warmer weather will result in variances to financial results.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 30

Regulatory Metrics

	Year Ended December 31
	2019	2018
Approved ROE (%) (1)	10.1	10.6
Approved return on debt (%) (1)	5.4	5.4
Rate base ($ millions) (2) (3) (4)	3,865	3,684

(1) Average of all the utilities.

(2) 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.

(3) Reflects AltaGas’ 65 percent interest in Cook Inlet Natural Gas Storage Alaska LLC.

(4) In U.S. dollars

During the fourth quarter of 2019, AltaGas’ Utilities segment experienced warmer weather at all of its jurisdictions compared to the same quarter in 2018. The increase in customers compared to the same period of 2018 represents the growth in customer base.

For the year ended December 31, 2019, AltaGas' Utilities segment experienced warmer weather at SEMCO and ENSTAR compared to 2018. Washington Gas also experienced warmer than normal weather. The increase in transportation represents the addition of Washington Gas natural gas deliveries for the first half of the year.

Service sites at December 31, 2019increased by approximately 10 thousand sites compared to December 31, 2018 due to growth in customer base.

Three Months Ended December 31

The Utilities segment reported normalized EBITDA of $244 million in the fourth quarter of 2019, compared to $232 million in the same quarter in 2018. The increase in normalized EBITDA was mainly due to the impact of Washington Gas' 2018 and 2019 Maryland rate cases, positive impacts from the final decision in the Virginia rate case, and higher revenue from accelerated pipe replacement program spend, partially offset by higher operating expenses, the impact of the ACI IPO in 2018, warmer weather in Michigan and Alaska, and the unfavorable impact of the weaker U.S. dollar.

Year Ended December 31

On July 31, 2018, Washington Gas filed an application with the SCC of VA to increase its base rates for natural gas service. In September 2019, the Virginia Hearing Examiner assigned to Washington Gas' Virginia rate case issued a report with findings and recommendations to the SCC of VA, including the finding for no incremental revenues.In September 2019, the impact of these recommendations was recorded, resulting in a one-time reduction in normalized EBITDA of approximately $30 million and a reduction of approximately $14 million in net income after taxes. The adjustments included a lower ROE, a revised amortization period for returning excess deferred income taxes as a result of theTax Cuts and Jobs Act (TCJA) combined with a one-time refund liability related to the effect of the TCJA in 2018, lower revenue from the Virginia SAVE program, and a one-time write-off of regulatory assets related to the utility distribution integrity management program (DIMP). On October 21, 2019, Washington Gas filed comments on and exceptions to the Hearing Examiner's report, recommending the SCC of VA reject certain of the Hearing Examiner's findings. On December 20, 2019, the Commission issued a Final Orderadjusting certain of the Hearing Examiner’s findings, some of which are favorable to Washington Gas, resulting in a $8 million increase to EBITDA in the fourth quarter of 2019. In January 2020, Washington Gas filed a petition for reconsideration regarding one of the findings in the Final Order. On January 30, 2020, the SCC of VA denied this request and the rate case is now final.

The Utilities segment reported normalized EBITDA of $657 million in the year ended December 31, 2019, compared to $426 millionin 2018. The increase in normalized EBITDA was mainly due to a full year of contributions from Washington Gas, higher rates at Washington Gas related to the Maryland rate case impact, the favorable impact of the stronger U.S. dollar, growth in

AltaGas Ltd. – 2019 MD&A and Financial Statements - 31

customer base, and colder weather in Michigan. The increase was partially offset by the impacts from the Virginia rate case, the impact of the ACI IPO in 2018, higher expenses at Washington Gas, lower storage revenue at CINGSA, the 2019 revenue impact related to the federal tax reduction at the U.S. utilities, and warmer weather in Alaska.

Rate Case Updates

Utility/Jurisdiction	Date Filed	Request	Status	Expected Timing of Decision
Washington Gas - Maryland	May 2018	US$56 million increase in base rates, including US$15 million in annual surcharges currently paid by customers for system upgrades.	In December 2018, the PSC of MD approved a rate increase of US$29 million (vs. US$56 million requested). Washington Gas requested a rehearing on two of the issues. In June 2019, the PSC of MD issued an order partially allowing for approximately US$1 million of overtime in its revenue adjustment and denied the other item.	Complete
Washington Gas - Maryland	April 2019	US$36 million increase in base rates, of which US$5 million relates to costs being collected through the monthly STRIDE surcharges for system upgrades.	A settlement agreement was filed for a US$27 million rate increase (vs. US$36 million applied for). Approval was received from the PSC of MD in October 2019.	Complete
Washington Gas - Virginia	July 2018	US$38 million increase in base rates, of which approximately US$15 million relates to costs being collected through the monthly SAVE surcharges for accelerated pipeline replacement.	The SCC of VA Hearing Examiner's report was issued in September 2019 recommending no incremental revenue increase and Washington Gas comments were provided on October 21, 2019. On December 20, 2019, the Commission issued a Final Orderadjusting certain of the Hearing Examiner’s findings, some of which are favorable to Washington Gas but still resulted in no incremental revenue increase. In January 2020, Washington Gas filed a petition for rehearing regarding one of the findings. On January 30, 2020, the SCC of VA denied this request and the rate case is now final.	Complete
Washington Gas - District of Columbia	January 2020	US$35 million increase in base rates, including US$9 million of annual PROJECTpipes surcharges currently paid by customers for accelerated pipeline replacement.	Washington Gas filed this rate case on January 13, 2020. Washington Gas has also requested approval for a Revenue Normalization Adjustment mechanism to reduce customer bill fluctuations due to weather-related usage variations, similar to existing mechanisms in both Maryland and Virginia. A conference to discuss process schedule is expected to be held in March 2020.	Not yet known
CINGSA - Alaska	April 2018	US$4 million reduction in rates, due to lower rate base, lower returns on equity, and lower federal income tax.	A decision was received in August 2019. The decision included an ROE of 10.25% (compared to 11.875% requested) and 100% of Interruptible Storage Service revenues payable to customers (versus 50% requested). CINGSA filed a petition for partial reconsideration on September 3, 2019. The Commission denied the petition and CINGSA partially appealed the Commission's decision to the Superior Court.	Complete
SEMCO - Michigan	May 2019	US$38 million increase in base rates.	In November 2019, a settlement agreement was filed for an approximately US$20 million rate increase (vs. US$38 million applied for) and an allowed return on equity of 9.87 percent. The MPSC approved the settlement in December 2019 and the new rates were effective January 1, 2020.	Complete

AltaGas Ltd. – 2019 MD&A and Financial Statements - 32

Midstream

Operating Statistics

	Three Months Ended December 31		Year Ended December 31
	2019	2018	2019	2018
Total inlet gas processed (Mmcf/d) (1)	1,413	1,413	1,407	1,378
Extraction ethane volumes (Bbls/d) (1)	25,951	25,448	23,826	24,346
Extraction NGL volumes (Bbls/d) (1) (2)	34,354	39,074	37,546	38,128
Total extraction volumes (Bbls/d) (1) (3)	60,305	64,522	61,372	62,474
Frac spread - realized ($/Bbl) (1) (4)	16.54	15.84	17.47	16.49
Frac spread - average spot price ($/Bbl) (1) (5)	8.29	21.00	11.05	22.79
RIPET export volumes (Bbls/d) (1)(6)	36,394	—	35,446	—
Propane Far East Index (FEI) to Mont Belvieu spread (US$/Bbl) (1) (7)	17.95	—	14.88	—
Natural gas optimization inventory (Bcf)	41.4	30.8	41.4	30.8
WGL retail energy marketing - gas sales volumes (Mmcf)	20,131	20,750	64,460	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.

(6) Energy export volumes represents propane volumes exported at RIPET since facility was placed into service in May 2019.

(7) Average propane spot price spread between Argus Far East Index and Mont Belvieu TET commercial index for the period beginning May 2019.

With RIPET commencing operations in late May 2019, propane volumes exported to Asia for the three months and year ended December 31, 2019 averaged 36,394 Bbls/d and 35,446 Bbls/d, respectively. There were 6 shipments in the fourth quarter of 2019 and 15 shipments in total for the year.

Inlet gas processing volumes were unchanged at 1,413 Mmcf/d for the fourth quarter of 2019, consistent with the same quarter of 2018. Factors positively impacting inlet gas processing volumes in the fourth quarter of 2019 included new volumes from the recently constructed Nig Creek facility which was placed in-service in September 2019, higher volumes at EEEP due to downstream gas demand, and higher volumes at Younger. These increases were offset by the disposal of certain non-core facilities in the first quarter of 2019 and lower volumes at the Townsend complex.

Inlet gas processing volumes for the year ended December 31, 2019 increased by 29 Mmcf/d compared to 2018. The increase was primarily due to a full year of operations at the Aitken Creek North facility and new volumes from the Nig Creek facility, higher volumes at Harmattan Co-stream, and new volumes from the Eagle Hill facility at Harmattan, partially offset by the disposition of certain non-core facilities in the first quarter of 2019.

Average ethane production volumes for the fourth quarter of 2019increased by 503 Bbls/d, while average NGL production volumes decreased by 4,720 Bbls/d compared to the same quarter in 2018. Higher ethane volumes were a result of higher contracted ethane volumes at EEEP, partially offset by reinjected ethane production volumes at Harmattan and PEEP. Lower NGL volumes were a result of lower inlet volumes at the Townsend complex, Blair Creek, and the disposition of certain non-core facilities in the first quarter of 2019, partially offset by higher NGL volumes at EEEP due to higher inlet.

Average ethane production volumes for the year ended December 31, 2019decreased by 520 Bbls/d, and average NGL production volumes decreased by 582 Bbls/d compared to 2018. Lower ethane volumes were a result of reinjected ethane production volumes at Harmattan and Younger due to uneconomic pricing in the first half of 2019, partially offset by new contracted ethane volumes

AltaGas Ltd. – 2019 MD&A and Financial Statements - 33

at EEEP, and higher volumes at JEEP and PEEP due to higher inlet. Lower NGL volumes were a result of temporary outages in 2019 and reduced ownership interest at the Younger facility, and the disposition of certain non-core facilities in the first quarter of 2019, partially offset by additional volumes produced from EEEP and the Townsend complex.

For the fourth quarter of 2019, U.S. retail sales volumes were 20,131 Mmcf, compared to 20,750 Mmcf in the same period of 2018. The decrease was primarily due to warmer weather in the fourth quarter of 2019 compared to the same period of 2018.

For the year ended December 31, 2019, U.S. retail sales volumes were 64,460 Mmcf, compared to 28,906 Mmcf in the same period of 2018. The increase in retail sale volumes was primarily due to the addition of WGL volumes for the first half of 2019.

Natural gas optimization inventory as at December 31, 2019 was41.4Bcf (December 31, 2018 - 30.8 Bcf). The increase in natural gas optimization inventory was primarily due to lower withdrawals of inventory in the fourth quarter of 2019 as a result of lower natural gas prices.

Three Months Ended December 31

The Midstream segment reported normalized EBITDA of $171 million in the fourth quarter of 2019, compared to $93 million in the same quarter in 2018. The increase was mainly due to contributions from RIPET which was placed in-service in May 2019, higher NGL revenues due to higher netbacks, favorable U.S. storage results, higher margins from WGL's retail gas business, higher AFUDC related to Mountain Valley, and contributions from the Nig Creek facility which was placed in-service in September 2019. These were partially offset by the impact of the sale of WGL Midstream's indirect non-operating interest in Central Penn in November 2019, the impact of the sale of Stonewall in the second quarter of 2019, the disposition of certain non-core facilities in the first quarter of 2019, and lower third-party volumes and rates at Townsend. During the fourth quarter of 2019, AltaGas recorded equity earnings of $31 million from Petrogas compared to $5 million in the same quarter of 2018, mainly due to higher export volumes and improved export margins together with improved contributions from Petrogas' other core business segments. In addition, Petrogas earnings included a one-time payment related to the termination of a customer contract.

During the fourth quarter of 2019, AltaGas hedged approximately 6,228 Bbls/d of NGL volumes at an average price of $40/Bbl excluding basis differentials. During the fourth quarter of 2018, AltaGas hedged 7,500 Bbls/d of NGL at an average price of $33/Bbl, excluding basis differentials. The average indicative spot NGL frac spread for the fourth quarter of 2019 was approximately $8/Bbl, compared to $21/Bbl in the same quarter of 2018 inclusive of basis differentials. The realized frac spread of approximately $17/Bbl in the fourth quarter of 2019 (2018 - $16/Bbl) was higher than the same period in 2018 due to frac hedge gains. For RIPET, during the fourth quarter of 2019, AltaGas hedged approximately 23,070 Bbls/d of propane export volumes at the FEI to Mont Belvieu spread of US$10/Bbl.

During the fourth quarter of 2019, the Midstream segment recorded a pre-tax provision of $35 million related to the Pouce Coupe sour gas treatment facility in Alberta. In addition, the Midstream segment recognized a pre-tax loss of $11 million on the sale of WGL Midstream's indirect non-operating interest in Central Penn. During the fourth quarter of 2018, the Midstream segment recognized a pre-tax provision of $2 million on certain non-core Midstream assets.

Year Ended December 31

The Midstream segment reported normalized EBITDA of $501 million in the year ended December 31, 2019, compared to $277 millionin 2018. The increase in normalized EBITDA was due to contributions from RIPET which was placed in-service in May 2019, a full year of contributions from WGL Midstream assets and the WGL retail marketing business, higher AFUDC related to Mountain Valley, higher margins from WGL's retail gas business, the full year impact from the acquisition of the Aitken Creek North facility, contributions from the Nig Creek facility which was placed in-service in September 2019, higher NGL revenues due to higher netbacks, and higher revenues at Harmattan due to increased NGL activities. These were partially offset by the disposition of certain non-core facilities in the first quarter of 2019, the impact of the sale of Stonewall in the second quarter of 2019, and

AltaGas Ltd. – 2019 MD&A and Financial Statements - 34

lower revenues at Younger due to change in operatorship. During the year ended December 31, 2019, AltaGas recorded equity earnings of $75 million from Petrogas, compared to $15 million in 2018. The increase in Petrogas earnings was due to higher export volumes and margins at the Ferndale terminal, the absence of the 2018 planned turnaround, and improved contributions from Petrogas' other core business segments. In addition, Petrogas earnings in the fourth quarter of 2019 included a payment related to a termination of a customer contract.

During the year ended December 31, 2019, AltaGas hedged approximately 6,228 Bbls/d of NGL volumes at an average price of $40/Bbl, excluding basis differentials. For the year ended December 31, 2018, AltaGas hedged 7,500 Bbls/d of NGL at an average price of $33/Bbl, excluding basis differentials. The average indicative spot NGL frac spread for year ended December 31, 2019 was approximately $11/Bbl compared to $23/Bbl in 2018 inclusive of basis differentials. The realized frac spread of $17/Bbl for the year ended December 31, 2019 (2018 - $16/Bbl) was higher than the same period in 2018 due to frac hedge gains. For RIPET, during the year ended December 31, 2019, AltaGas hedged approximately 21,106 Bbls/d of propane export volumes at the FEI to Mont Belvieu spread of US$11/Bbl.

During the year ended December 31, 2019, AltaGas recognized a pre-tax gain of $34 million on the disposition of WGL Midstream's equity investment in Stonewall, a pre-tax gain of $5 million on the sale of remaining non-core Midstream processing facilities, and a pre-tax loss of $11 million on the sale of WGL Midstream's indirect non-operating interest in Central Penn. 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, as well as a realized loss of $2 million on the sale of its investment in Tidewater Midstream and Infrastructure Inc.

During the year ended December 31, 2019, AltaGas recognized pre-tax provisions of $35 million in the Midstream segment related to the Pouce Coupe sour gas treatment facility in Alberta. Also, during the year ended December 31, 2019, AltaGas recognized a pre-tax provision on equity investments of $44 million in the Midstream segment related to the sale of WGL Midstream's indirect non-operating interest in Central Penn. During the year ended December 31, 2018, AltaGas recognized pre-tax provisions of $117 million on certain non-core Midstream assets that were 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.

Power

Operating Statistics

	Three Months Ended December 31		Year Ended December 31
	2019	2018	2019	2018
Renewable power sold (GWh)	10	233	616	1,551
Conventional power sold (GWh)	478	985	1,793	3,728
Renewable capacity factor (%)	11.4	14.6	17.7	29.7
Contracted conventional equivalent availability factor (%) (1)	92.9	97.4	75.4	97.2
WGL retail energy marketing - electricity sales volumes (GWh)	3,291	2,911	13,218	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 2019, the volume of renewable power sold decreased by 223 GWh and the volume of conventional power sold decreased by 507 GWh compared to the same quarter in 2018. The decrease in renewable volumes was primarily due to asset sales, including the sale of Northwest Hydro in January 2019, the Bear Mountain wind facility in October 2018, and the WGL distributed generation business in September 2019. The decrease in conventional volumes sold was primarily due to the sale of the San Joaquin facilities in November 2018 and the sale of AltaGas' interest in the biomass facilities in August 2019.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 35

The contracted conventional equivalent availability factor was slightly lower for the fourth quarter of 2019 as a result of a minor planned outage at Blythe during October. The renewable capacity factor was lower for the fourth quarter of 2019 due to the sale of the Northwest Hydro facilities, the Bear Mountain wind facility, and the majority of the WGL distributed generation business.

U.S. retail sales volumes were 3,291 in the fourth quarter of 2019, compared to 2,911 GWh in the same period of 2018. The increase was primarily due to an increase in customers served by the business.

For the year ended December 31, 2019, the volume of renewable power sold decreased by 935 GWh and the volume of conventional power sold decreased by 1,935 GWh. The change in volumes was primarily due to the same reasons as noted above for the fourth quarter of 2019.

The renewable capacity factor variance for the year ended December 31, 2019 was due to the same factors as noted above for the fourth quarter of 2019, while the contracted conventional availability factor variance for the same period was due to the same factors as noted above for the fourth quarter of 2019, as well as an extended planned outage at the Blythe facility during the spring of 2019.

For the year ended December 31, 2019, U.S. retail sales volumes were 13,218 GWh, compared to 5,906 in the same period of 2018. The increase was primarily due to the addition of WGL for the first half of the year and the previously mentioned factors impacting the fourth quarter of 2019.

Three Months Ended December 31

The Power segment reported normalized EBITDA of $22 million during the fourth quarter of 2019, compared to $76 millionthe same quarter in 2018. Normalized EBITDA decreased as a result of the impact of asset sales, including Northwest Hydro (January 2019), the San Joaquin facilities (November 2018), Canadian non-core Power assets (February 2019), the Biomass facilities (August 2019), the Busch Ranch facility (December 2018), and the WGL distributed generation business (September 2019). These decreases were partially offset by higher contributions to EBITDA from WGL retail energy marketing due to higher volumes and improved margins compared to the same period in 2018.

In thefourth quarter of 2019, certain additional distributed generation projects were transferred to the purchaser, resulting in a pre-tax gain of $68 million. Also in the fourth quarter of 2019, pre-tax provisions of $380 million were recorded related to various assets in the Power segment. 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.

Year Ended December 31

The Power segment reported normalized EBITDA of $154 million in the year ended December 31, 2019, compared to $320 millionin 2018. Normalized EBITDA decreased primarily for the same reasons noted above for the fourth quarter of 2019. Other events contributing to decreased normalized EBITDA for the year included the extended major planned outage at the Blythe facility impacting the first quarter and second quarter of 2019, and the sale of the Bear Mountain facility in October 2018, partially offset by the full year of contributions from WGL's Power business.

Asset sales completed in 2019 included the sale of the U.S. portfolio of distributed generation assets resulting in a pre-tax gain of $168 million, the sale of the remaining interest in the Northwest Hydro facilities resulting in a pre-tax gain of $688 million, the sale of Canadian non-core Power assets resulting in a pre-tax loss of $6 million, and the sale of a WGL Energy Systems financing receivable resulting in a pre-tax loss of $1 million. Other asset sales completed in 2019 include the sale of AltaGas' equity ownership interest in two biomass plants in the United States for net cash proceeds of approximately US$18 million and the sale of a capital

AltaGas Ltd. – 2019 MD&A and Financial Statements - 36

spare for proceeds of US$4 million. There were no gains or losses recorded on the dispositions of the biomass assets or the capital spare.

In the year ended December 31, 2019, AltaGas recognized pre-tax provisions on various assets in the Power segment of approximately $381 million. In addition, a pre-tax provision on equity investments of$2 million was recorded in 2019 related to biomass investments which were sold in the third quarter of 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, $6 million related to a WGL Energy Systems financing receivable that was classified as held for sale at December 31, 2018, $23 million related to a development project in the U.S, and $2 million related 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.

Corporate

Three Months Ended December 31

In the Corporate segment, normalized EBITDA for the fourth quarter of 2019 was a loss of $12 million, compared to a loss of $7 million in the same quarter in 2018. The increased loss was mainly due to higher expenses related to employee incentive plans, and lower interest income due to the absence of interest earned on loans provided to ACI subsequent to its IPO.

Year Ended December 31

In the Corporate segment, normalized EBITDA for the year ended December 31, 2019 was a loss of $41 million, compared to a loss of $14 millionin 2018. The increased loss was a result of a number of factors, including higher expenses related to employee incentive plans as a result of the increasing share price in 2019, lower interest income due to the absence of interest earned on funds that were held in escrow for the WGL Acquisition in 2018 and on loans provided to ACI, and higher information technology related costs.

Invested Capital

	Three Months Ended December 31, 2019
($ millions)	Utilities			Midstream			Power		Corporate		Total
Invested capital:
Property, plant and equipment	$	145		$	93		$	2	$	—	$	240
Intangible assets	21			1			—		2		24
Long-term investments	—			3			—		—		3
Contributions from non-controlling interest	—			(7		)	—		—		(7		)
Invested capital	166			90			2		2		260
Disposals:
Property, plant and equipment	(1		)	—			—		—		(1		)
Equity method investments	—			(812		)	—		—		(812		)
Net invested capital	$	165		$	(722	)	$	2	$	2	$	(553	)

	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

During the fourth quarter of 2019, AltaGas’ invested capital was $260 million, compared to $569 million in the same quarter in 2018. The decrease in invested capital was primarily due to lower additions to property, plant and equipment and lower contributions to WGL's equity investments in the Mountain Valley pipeline and Central Penn which was sold in November 2019.

The decrease in additions to property, plant and equipment in the fourth quarter of 2019 was mainly due to the absence of construction costs related to RIPET which was placed in-service in May 2019, and the acquisition of 50 percent ownership in Black Swan’s Aitken Creek North gas processing facility in the fourth quarter of 2018. The disposal of equity method investments in the fourth quarter of 2019 related tothe disposition of Central Penn in November 2019. The disposals of property, plant and equipment in 2018 primarily related to the disposition of the San Joaquin facilities in California, the Busch Ranch wind farm in Colorado, and a development stage wind asset.

The invested capital in the fourth quarter of 2019 included maintenance capital of $3 million (2018 ‑ $2 million) in the Midstream segment and $1 million (2018 ‑ $2 million) in the Power segment. Maintenance capital incurred in the fourth quarter of 2019 primarily related to maintenance at the Harmattan facility.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 37

	Year Ended December 31, 2019
($ millions)	Utilities			Midstream			Power			Corporate		Total
Invested capital:
Property, plant and equipment	$	841		$	438		$	38		$	1	$	1,318
Intangible assets	23			5			—			9		37
Long-term investments	—			179			—			—		179
Contributions from non-controlling interest	—			(41		)	—			—		(41		)
Invested capital	864			581			38			10		1,493
Disposals:
Property, plant and equipment	(1		)	(87		)	(2,319		)	—		(2,407		)
Equity method investments	—			(1,191		)	(25		)	—		(1,216		)
Net invested capital	$	863		$	(697	)	$	(2,306	)	$	10	$	(2,130	)

	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

During the year ended December 31, 2019, AltaGas’ invested capital was $1.5 billion, compared to $7.1 billionin 2018. The decrease in invested capital in theyear ended December 31, 2019 was mainly due to the absence of the 2018 cash payment of $5.9 billion for the WGL acquisition, partly offset by higher additions to property, plant and equipment and contributions to WGL's investments in the Central Penn and Mountain Valley pipelines. Net invested capital expenditures (excluding disposals, utility asset removal costs, and certain contributions to equity investments) were approximately $1.39 billion in 2019. This was slightly higher than the previously estimated range of $1.3 to $1.36 billion due to accelerated timing on certain growth capital projects and the timing of close of certain asset sales.

The increase in additions to property, plant and equipment in the year ended December 31, 2019 was mainly due to capital expenditures related to system betterment and accelerated pipeline replacement programs at Washington Gas, construction of the Marquette Connector pipeline, construction costs at RIPET, construction of Nig Creek and the Townsend expansion, and capital expenditures related to WGL's distributed generation projects. The disposals of property, plant and equipment for the year ended December 31, 2019 primarily related to the Northwest Hydro facilities, certain non-core Canadian Midstream and Power assets, and WGL's distributed generation projects, while in 2018 the disposals of property, plant, and equipment related to the disposition of the San Joaquin facilities in California, the Busch Ranch wind farm in Colorado, a development stage wind asset, and certain other non-core facilities in the Midstream segment. The disposals of equity method investments in 2019 related to the disposition of Stonewall in May 2019, the disposition of biomass investments in August 2019, and the disposition of Central Penn in November 2019.

The invested capital for the year ended December 31, 2019 included maintenance capital of $6 million (2018 ‑ $17 million) in the Midstream segment and $20 million (2018 ‑ $13 million) in the Power segment. The decrease in maintenance capital for the

AltaGas Ltd. – 2019 MD&A and Financial Statements - 38

Midstream segment was primarily due to reduced turnaround expenditures. The increase in maintenance capital for the Power segment was primarily due to a planned turnaround at the Blythe facility.

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, 2019 and December 31, 2018, the fair values of the Corporation’s derivatives were as follows:

($ millions)	December 31, 2019			December 31, 2018
Natural gas	$	(77	)	$	(137	)
Energy exports	(75		)	—
NGL frac spread	(2		)	16
Power	(12		)	(9		)
Foreign exchange	—			(1		)
Net derivative liability	$	(166	)	$	(131	)

Summary of Risk Management Contracts

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 onpublished 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 (Loss) in the period in which the change occurs. For the Utilities 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 (Loss) 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, 2019 was approximately $11/Bbl (2018 – $23/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, 2019 was approximately $17/Bbl inclusive of basis differentials (2018 - $16/Bbl).

▪ For 2020, AltaGas estimates an average of approximately 10,000 Bbls/d of NGL will be exposed to frac spreads prior to hedging activities. Pricing risk related to frac exposed propane is mitigated through export and the hedging program in place at RIPET. Hedges are in place for approximately 80 percent of frac exposed butane and condensate volumes.

▪ At RIPET, AltaGas is exposed to the propane price differential between North American Indices and the Far East Index for contracts not under tolling arrangements. AltaGas estimates an average of approximately 30,000 Bbls/d will be

AltaGas Ltd. – 2019 MD&A and Financial Statements - 39

exposed to these price differentials in 2020. To date for 2020, AltaGas has hedges in place for approximately 74 percent of these exposed propane volumes at an average FEI to Mont Belvieu spread of US$11/Bbl.

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 manage transportation and storage assets on behalf of third parties. To serve retail customers, AltaGas enters into retail sales contracts that contain optionality as well as physical and financial contracts which qualify as derivative instruments.

The Utilities 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.

Foreign Exchange Contracts

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 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, 2019, Management has designated US$300 million of outstanding U.S. dollar denominated long-term debt to hedge against the currency translation effect of its foreign investments (December 31, 2018 - US$1.5 billion).

▪ For the year ended December 31, 2019, AltaGas incurred an after-tax unrealized gain of $60 million arising from the translation of debt in other comprehensive income (2018 - after-tax unrealized loss of $80 million).

Interest Rate Contracts

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.

From time to time, AltaGas may concurrently draw on its credit facility in U.S. dollars and enter into cross currency basis swaps whereby, on final settlement, AltaGas receives U.S. dollars from the counterparty and pays Canadian dollars to the counterparty. As a result, AltaGas reduces its interest expense by taking advantage of the interest rate spread between the Banker's Acceptance (BA) rate and the London Inter-bank Offered Rate (LIBOR) without any additional foreign exchange risk.

Weather 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 year ended December 31, 2019, a pre-tax lossof $2 million(2018 - pre-tax loss of $1 million) was recorded related to heating degree day (HDD) and cooling degree day (CDD) instruments.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 40

The Effects of Derivative Instruments on the Consolidated Statements of Income (Loss)

The following table presents the unrealized gains (losses) on derivative instruments as recorded in the Corporation’s Consolidated Statements of Income (Loss):

	Three Months Ended December 31						Year Ended December 31
($ millions)	2019			2018			2019			2018
Natural gas	$	14		$	13		$	23		$	(2	)
Energy exports	(65		)	—			(87		)	—
NGL frac spread	(11		)	45			(17		)	40
Power	(2		)	12			(5		)	9
Foreign exchange	—			(1		)	1			34
	$	(64	)	$	69		$	(85	)	$	81

Please refer to Note 23 of the 2019 Annual Consolidated Financial Statements for further details regarding AltaGas' risk management activities.

Corporation Risks

AltaGas manages its exposure to risks using the strategies outlined in the following table:

Risks	Strategies and Organizational Capability to Mitigate Risks
Operations	• Maintain safe and reliable operations
	• Ensure appropriate policies, procedures, and systems are in place and internal controls are operating   efficiently
	• Programs to manage pipeline system integrity including accelerated replacement of aging pipeline   and infrastructure based on risk mitigation
	• 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, environmental, health, and safety programs
	• Carry property and business interruption insurance
	• Fixed price operating and maintenance contracts with equipment manufacturers
	• Hedging strategy used to balance price and operating risk
Environment, Health and Safety	• Measure, monitor emissions and seek new technologies to reduce greenhouse gas (GHG) emissions from operations
	• Programs in place to reduce fugitive methane emissions
	• Projects designed to limit impacts and throughout operations, monitor land, air, and water quality, where appropriate
	• Strong process safety management systems
	• Pipeline and asset integrity programs in place
	• Accelerated replacement of mature pipeline infrastructure
	• Preventative and remedial measures to address increased leak rates within Washington Gas’   distribution system
	• Continuous process improvement strategy employed
	• Comprehensive Environmental, Health and Safety management system to protect people
	• Purchase and maintain general liability and business interruption insurance

AltaGas Ltd. – 2019 MD&A and Financial Statements - 41

Risks	Strategies and Organizational Capability to Mitigate Risks
Regulatory and Stakeholder	• Strong working relationships with regulatory authorities
	• Regulatory and commercial personnel monitor and manage regulatory issues
	• Development of consistent framework for stakeholder communication and community consultation
	• Safe Digging campaign, emergency preparedness and 24/7 Gas Control and dispatch to protect utility customers and public
	• Public ESG disclosure and key ESG performance data updates
	• Utilities seek rate recovery through rate cases with regulatory commissions and agencies
Legislative	• Ongoing identification of public policy issues to determine risks to the 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
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 access to multiple credit facilities and continually monitor covenant   compliance
	• 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
	• 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
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
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

AltaGas Ltd. – 2019 MD&A and Financial Statements - 42

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
Commodity price	• Contracting terms and 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 to reduce exposure to commodity prices and earnings volatility with hedge targets   approved by the Board of Directors and monitor hedge transactions through Risk Management   Committee
	• Regulatory recovery mechanisms for gas purchases to serve utility customers
	• Matching natural gas and electricity purchase obligations with sales commitments in terms of   volume and pricing
	• AltaGas' Commodity Risk Policy prohibits transactions for speculative purposes
	• Employ strong systems and processes for monitoring and reporting compliance with the   Commodity Risk Policy
	• 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
Labor relations	• Maintain access to strong labor markets to attract qualified talent
	• Positive employee relations to retain existing talent and maintain strong relations with unions
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
Compliance with regulations and Section 404(a) of the Sarbanes-Oxley Act of 2002	• Experienced in-house legal department
	• Use of expert third parties when needed
	• Ensure appropriate policies, procedures, and systems are in place and internal controls are operating   effectively
	• Continuous monitoring of laws and regulations in applicable jurisdictions
	• Continuous monitoring of the related rules of the Securities Exchange Commission and the Public Company Accounting Oversight Board

AltaGas Ltd. – 2019 MD&A and Financial Statements - 43

Risks	Strategies and Organizational Capability to Mitigate Risks
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
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
Volume of power generated	• PPA for the Blythe facility includes 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

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.

In addition, Wrangler SPE LLC and Washington Gas made certain ring fencing commitments to the PSC of DC, the PSC of MD, and the SCC of VA with the intention of removing Washington Gas from the bankruptcy estate of AltaGas and its affiliates, other than Washington Gas and Wrangler SPE LLC (together, the “Ring Fenced Entities”). 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 AltaGas or any non-Ring Fenced Entity Affiliate, 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 any non-Ring Fenced Entity, and vice versa.

	Year Ended December 31
($ millions)	2019			2018
Cash from (used by) operations	$	616		$	(79	)
Investing activities	2,184			(5,834		)
Financing activities	(2,874		)	5,987
Increase (decrease) in cash, cash equivalents, and restricted cash	$	(74	)	$	74

AltaGas Ltd. – 2019 MD&A and Financial Statements - 44

Cash From (Used by) Operations

Cash from (used by) operationsincreased by $695 million for the year ended December 31, 2019 compared to 2018, primarily due to higher net income after taxes, higher distributions from equity investments, and a favorable variance in the net change in operating assets and liabilities. The majority of the variance in net change in operating assets and liabilities was due to the addition of WGL's operating assets and liabilities in the third quarter of 2018 and the impact of asset sales completed in late 2018 and throughout 2019.

Working Capital

($ millions except working capital ratio)	December 31, 2019			December 31, 2018
Current assets	$	2,196		$	4,033
Current liabilities	3,125			4,102
Working deficiency	$	(929	)	$	(69	)
Working capital ratio (1)	0.70			0.98

(1) Calculated as current assets divided by current liabilities.

The decrease in the working capital ratio was primarily due to decreases in assets held for sale, accounts receivable, and cash and cash equivalents, and increases in the current portion of long-term debt, regulatory liabilities, risk management liabilities, and operating lease liabilities. These were partially offset by increases in prepaid expenses and other current assets, and decreases in short-term debt, liabilities associated with assets held for sale, and accounts payable and accrued liabilities. AltaGas’ working capital will fluctuate in the normal course of business and given the seasonality of the utilities, is typically lower than average in the fourth quarter of each year. The working capital deficiency is expected to be funded using cash flow from operations, proceeds from asset sales, and available credit facilities as required.

Investing Activities

Cash from investing activities for the year ended December 31, 2019 was $2.2 billion, compared to cash used in investing activities of $5.8 billion in 2018. Investing activities for the year ended December 31, 2019 primarily included proceeds of $3.6 billion from asset sales completed in the year ended December 31, 2019 (including the Northwest Hydro facilities, distributed generation assets, Central Penn, Stonewall, biomass assets, and non-core Canadian Midstream and Power assets) and proceeds of $73 million from the sale of a WGL Energy Systems financing receivable, partially offset by expenditures of approximately $1.3 billion for property, plant, and equipment and intangible assets, and approximately $179 million of contributions to equity investments. 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).

Financing Activities

Cashused in financing activities for the year ended December 31, 2019 was $2.9 billion, compared to cash from financing activities of $6.0 billion in 2018. Financing activities for the year ended December 31, 2019 were primarily comprised of net repayments of short and long-term debt of $1.6 billion, net repayments under credit facilities of $1.9 billion, and dividends of $334 million, partially offset by debt issuances of $889 million, contributions from non-controlling interests of $48 million, and net proceeds from the issuance of common shares of $68 million (mainly from common shares issued through the DRIP).Financing activities for the year ended December 31, 2018 were primarily comprised of net short and long-term debt issuances of $2.3 billion, net

AltaGas Ltd. – 2019 MD&A and Financial Statements - 45

proceeds from the issuance of common shares of $2.6 billion, net borrowings under credit facilities of $846 million, repayment of long-term debt of $279 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. Total dividends paid to common and preferred shareholders of AltaGas for the year ended December 31, 2019 were $334 million (2018 - $540 million), of which $68 million was reinvested through the DRIP (2018 - $326 million).The decrease in dividends paid was due to the reduction in dividends on common shares declared in the fourth quarter of 2018, partially offset by more common shares outstanding.

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 the 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, 2019			December 31, 2018
Short-term debt (1)	$	389		$	1,145
Current portion of long-term debt	923			890
Long-term debt (2)	5,928			8,067
Total debt	7,240			10,102
Less: cash and cash equivalents	(57		)	(102		)
Net debt	$	7,183		$	10,000
Shareholders' equity	7,215			7,020
Non-controlling interests	154			621
Total capitalization	$	14,552		$	17,641
Net debt-to-total capitalization (%)	49			57

(1) For the purposes of the net debt calculation, short-term debt excludes third-party project financing obtained on behalf of the United States federal government to provide funds for the construction of certain energy management services projects. As this debt was obtained on behalf of the U.S. government, AltaGas would only need to repay in the event that the project is not completed or accepted by the government. See Note 15 of the 2019 Annual Consolidated Financial Statements for additional details. At December 31, 2019, the project financing balance excluded from short-term debt in above table was $71 million (December 31, 2019 - $65 million).

(2) Net of debt issuance costs of $36 million as at December 31, 2019 (December 31, 2018 - $35 million).

As at December 31, 2019, AltaGas’ total debt primarily consisted of outstanding medium-term notes (MTNs) of $3.0 billion (December 31, 2018 - $2.7 billion), WGL and Washington Gas long-term debt of $2.7 billion (December 31, 2018 - $2.7 billion), SEMCO long‑term debt of $466 million (December 31, 2018 - $496 million), $643 million drawn under the bank credit facilities (December 31, 2018 - $3.0 billion) and short-term debt of $460 million (December 31, 2018 - $1.2 billion). In addition, AltaGas had$307 million of letters of credit outstanding (December 31, 2018 - $271 million).

As at December 31, 2019, AltaGas’ total market capitalization was approximately $5.5 billion based on approximately 279 million common shares outstanding and a closing trading price on December 31, 2019 of $19.78 per common share.

AltaGas' earnings interest coverage for the rolling twelve months ended December 31, 2019 was 3.2 times(twelve months ended December 31, 2018 – (1.2) times).

AltaGas Ltd. – 2019 MD&A and Financial Statements - 46

Credit Facilities			Drawn at		Drawn at
($ millions)	Borrowing capacity		December 31, 2019		December 31, 2018
AltaGas unsecured demand credit facilities (1) (2)	$	330	$	156	$	153
AltaGas unsecured extendible revolving letter of credit facilities (1) (2)	540		150		117
AltaGas unsecured revolving credit facilities (1) (2)	3,348		90		2,890
AltaGas bridge facility (1) (3)	—		—		113
AltaGas unsecured term credit facility (1) (2)	390		390		—
SEMCO Energy US$200 million unsecured credit facilities (1) (2)	195		164		1
WGL US$250 million unsecured revolving credit facility (2) (4)	325		—		—
Washington Gas US$450 million unsecured revolving credit facility (2) (4)	584		—		—
	$	5,712	$	950	$	3,274

(1) Amount drawn at December 31, 2019 converted at the month‑end rate of 1 U.S. dollar = 1.2988 Canadian dollar (December 31, 2018 - 1 U.S. dollar = 1.3642 Canadian dollar).

(2) All US$ borrowing capacity was converted at the December 31, 2019 U.S./Canadian dollar month-end exchange rate.

(3) The remaining balance on the bridge facility was paid in full on February 1, 2019.

(4) WGL and Washington Gas have the right to request additional borrowings of up to US$100 million with the bank’s approval, for a total of US$350 million and US$550 million on their respective facilities.

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. As at December 31, 2019, commercial paper outstanding totaled US$583 million for WGL and Washington Gas (December 31, 2018 – US$840 million).

Effective July 19, 2019, WGL and Washington Gas amended and restated their unsecured, revolving credit facilities. The WGL facility was reduced from US$650 million to US$250 million for a period of three years. The Washington Gas facility was increased from US$350 million to US$450 million for a period of five years. The facilities both have a US$100 million accordion option and there were no changes to the financial covenants. The commercial paper programs supported by these facilities have been revised to match the new facility amounts. 

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. AltaGas and its subsidiaries are also in compliance with trust indenture requirements for its MTNs as at December 31, 2019 and December 31, 2018.

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, 2019
Bank debt-to-capitalization (1)	not greater than 65 percent	less than 50%
Bank EBITDA-to-interest expense (1) (2)	not less than 2.5x	greater than 3.5x
Bank debt-to-capitalization (SEMCO) (3)	not greater than 60 percent	less than 41%
Bank EBITDA-to-interest expense (SEMCO) (3)	not less than 2.25x	greater than 7.5x
Bank debt-to-capitalization (WGL) (4)	not greater than 65 percent	less than 51%
Bank debt-to-capitalization (Washington Gas) (4)	not greater than 65 percent	less than 53%

(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.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 47

On September 25, 2019, a $2.0 billion base shelf prospectus for the issuance of certain types of future public debt and/or equity issuances was filed. This enables AltaGas to access the Canadian capital markets on a timely basis during the 25-month period that the base shelf prospectus remains effective. As at December 31, 2019, approximately $1.5 billion was available under the base shelf prospectus.

On June 13, 2018, AltaGas filed a US$2.0 billion final short form prospectus for the issuance of both debt securities and preferred shares in Alberta and a corresponding F-10 in the U.S. As at December 31, 2019, US$2.0 billion was available under the base shelf prospectus. On January 21, 2020, AltaGas filed a final short form base shelf prospectus in both 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. US$2.0 billion is available under the base shelf prospectus.

Contractual Obligations

December 31, 2019	Payments Due by Period
($ millions)		Total		Less than 1 year		1 - 3 years		4 - 5 years		After 5 years
Short-term debt (1)	$	460	$	460	$	—	$	—	$	—
Long-term debt (1)		6,793		921		1,489		921		3,462
Operating leases (2)		226		28		53		45		100
Purchase obligations		43,336		3,941		6,865		5,445		27,085
Capital project commitments		7		7		—		—		—
Pension plan and retiree benefits (3)		40		40		—		—		—
Merger commitments (4)		22		8		6		4		4
Environmental commitments		14		7		5		2		—
Other liabilities (5)		15		15		—		—		—
Total contractual obligations (6)	$	50,913	$	5,427	$	8,418	$	6,417	$	30,651

(1) Excludes deferred financing costs, discounts, finance lease liabilities, and the fair value adjustment on the WGL Acquisition.

(2) Payments are presented on an undiscounted cash basis.

(3) Assumes only required payments will be made into the pension plans in 2020. Contributions are made in accordance with independent actuarial valuations.

(4) Relates to merger commitments arising from the WGL Acquisition. Represents the estimated future payments of merger commitments that have been accrued but not paid. In addition, there are certain additional merger commitments that will be expensed when costs are incurred in the future, including the investment of up to US$70 million over atenyear period to further extend natural gas service, investment ofUS$8 millionfor leak mitigation withinthreeyears of the merger, hiring damage prevention trainers in each jurisdiction for a total ofUS$2 millionoverfiveyears, and developing15megawatts of either electric grid energy storage or Tier 1 renewable resources within five years. As at December 31, 2019, the cumulative amount of merger commitments that have been expensed but not yet paid is approximatelyUS$17 million.

(5) Excludes non-financial liabilities.

(6) U.S. dollar commitments have been converted to Canadian dollars using the December 31, 2019 exchange rate.

AltaGas expects to fund its obligations through internally-generated cash flow, asset sales, 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 2019 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 (Loss).

AltaGas Ltd. – 2019 MD&A and Financial Statements - 48

Credit Ratings

The below table summarizes the most recent credit ratings for AltaGas and subsidiaries:

Entity	Rating Agency	Debt Rated	Most Recent Rating	Comments
AltaGas	Standard & Poor's (S&P)	Issuer rating	BBB-	Affirmed on December 11, 2019 and outlook was revised from negative to stable.
		Senior unsecured	BBB-	Affirmed on December 11, 2019 and outlook was revised from negative to stable.
		Preferred shares	P-3	Affirmed on December 11, 2019.
	DBRS Limited (DBRS)	Issuer	BBB(low)	Affirmed on December 12, 2019 with stable outlook.
		Preferred shares	Pfd-3(low)	Affirmed on December 12, 2019.
	Fitch Ratings (Fitch)	Issuer	BBB	Affirmed on September 6, 2019.
		Preferred shares	BB+	Affirmed on September 6, 2019.
Washington Gas	Moody's Investors Service (Moody's)	Senior unsecured	A3	Downgraded to A3 from A2 on January 30, 2020. Stable outlook rating on February 4, 2020.
		Commercial paper	P-2	Downgraded to P-2 from P-1 on January 30, 2020. Stable outlook rating on February 4, 2020.
	S&P	Issuer and unsecured debt	A-	Raised from BBB+ to A- on December 11, 2019.
		Commercial paper	A-2	Affirmed on December 11, 2019.
	Fitch	Issuer	A-	Affirmed on September 6, 2019 with stable outlook.
WGL	Moody's	Senior unsecured	Baa1	Affirmed on January 30, 2020 and changed outlook from stable to negative. Stable outlook rating on February 4, 2020.
		Commercial paper	P-2	Affirmed on January 30, 2020 and changed outlook from stable to negative. Stable outlook rating on February 4, 2020.
	S&P	Issuer	BBB-	Affirmed on December 11, 2019 and outlook was revised from negative to stable.
		Senior unsecured	BB+	Affirmed on December 11, 2019.
		Commercial paper	A-3	Affirmed on December 11, 2019.
	Fitch	Issuer	BBB	Affirmed on September 6, 2019 with stable outlook.
SEMCO	Moody's	Long-term issuer	Baa1	Affirmed on January 29, 2020 with stable outlook.
		Senior secured notes	A2	Affirmed on January 29, 2020.
	S&P	Long-term issuer	BBB	Raised from BBB- to BBB on December 12, 2019.
		Senior secured notes	A-	Raised from BBB+ to A- on December 12, 2019.

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 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.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 49

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.

According to the Moody’s rating system, Baa ratings indicate moderate credit risk. Obligations rated Baa are considered medium-grade and as such may possess speculative characteristics.

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.

Share Information

	As at February 21, 2020
Issued and outstanding
Common shares	279,425,083
Preferred Shares
Series A	5,511,220
Series B	2,488,780
Series C	8,000,000
Series E	8,000,000
Series G	6,885,823
Series H	1,114,177
Series I	8,000,000
Series K	12,000,000
Issued
Share options	9,349,556
Share options exercisable	2,891,857

AltaGas Ltd. – 2019 MD&A and Financial Statements - 50

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.

The following table summarizes AltaGas’ dividend declaration history:

Dividends
Year Ended December 31
($ per common share)	2019		2018
First quarter	$	0.240000	$	0.547500
Second quarter	0.240000		0.547500
Third quarter	0.240000		0.547500
Fourth quarter	0.240000		0.445000
Total	$	0.960000	$	2.087500

Series A Preferred Share Dividends
Year Ended December 31
($ per preferred share)	2019		2018
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)	2019		2018
First quarter	$	0.269380	$	0.217600
Second quarter	0.270510		0.238720
Third quarter	0.273921		0.249530
Fourth quarter	0.270830		0.262770
Total	$	1.084641	$	0.968620

Series C Preferred Share Dividends
Year Ended December 31
(US$ per preferred share)	2019		2018
First quarter	$	0.330625	$	0.330625
Second quarter	0.330625		0.330625
Third quarter	0.330625		0.330625
Fourth quarter	0.330625		0.330625
Total	$	1.322500	$	1.322500

AltaGas Ltd. – 2019 MD&A and Financial Statements - 51

Series E Preferred Share Dividends
Year Ended December 31
($ per preferred share)	2019		2018
First quarter	$	0.337063	$	0.312500
Second quarter	0.337063		0.312500
Third quarter	0.337063		0.312500
Fourth quarter	0.337063		0.312500
Total	$	1.348252	$	1.250000

Series G Preferred Share Dividends
Year Ended December 31
($ per preferred share)	2019		2018
First quarter	$	0.296875	$	0.296875
Second quarter	0.296875		0.296875
Third quarter	0.296875		0.296875
Fourth quarter	0.265125		0.296875
Total	$	1.155750	$	1.187500

Series H Preferred Share Dividends
Year ended December 31
($ per preferred share)	2019		2018
Third quarter	$	—	$	—
Fourth quarter	0.296040		—
Total	$	0.296040	$	—

Series I Preferred Share Dividends
Year Ended December 31
($ per preferred share)	2019		2018
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

Series K Preferred Share Dividends
Year Ended December 31
($ per preferred share)	2019		2018
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

AltaGas Ltd. – 2019 MD&A and Financial Statements - 52

US$4.25 series Preferred Share Dividends (1)
Year Ended December 31
(US$ per preferred share)	2019		2018
First quarter	$	1.062500	$	—
Second quarter	1.062500		—
Third quarter	—		1.062500
Fourth quarter	—		1.062500
Total	$	2.125000	$	2.125000

(1) These Washington Gas preferred shares were redeemed on December 20, 2019.

US$4.80 series Preferred Share Dividends (1)
Year Ended December 31
(US$ per preferred share)	2019		2018
First quarter	$	1.200000	$	—
Second quarter	1.200000		—
Third quarter	—		1.200000
Fourth quarter	—		1.200000
Total	$	2.400000	$	2.400000

(1) These Washington Gas preferred shares were redeemed on December 20, 2019.

US$5.00 series Preferred Share Dividends (1)
Year Ended December 31
(US$ per preferred share)	2019		2018
First quarter	$	1.250000	$	—
Second quarter	1.250000		—
Third quarter	—		1.250000
Fourth quarter	—		1.250000
Total	$	2.500000	$	2.500000

(1) These Washington Gas preferred shares were redeemed on December 20, 2019.

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 2019 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:

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.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 53

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, regulatory assets, and intangible assets with indefinite and 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 or other indicators of fair value, 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, 2019 and determined that no write-down was required.

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 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 20 of the 2019 Annual Consolidated Financial Statements.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 54

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, the expected rate of compensation increase, and mortality rates. 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 2019 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 judgment 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, 2019, no material 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, 2019, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU):

AltaGas Ltd. – 2019 MD&A and Financial Statements - 55

§ ASU No. 2016-02 “Leases” and all related amendments (collectively “ASC 842”). AltaGas has applied ASC 842 using the modified retrospective approach as of the effective date of the new standard. Comparative information has not been restated and continues to be reported under the previous lease guidance ASC 840. AltaGas has applied the package of transition practical expedients which permitted the Corporation to not reassess (a) whether any expired or existing contracts contain leases, (b) lease classifications for any expired or existing leases, and (c) initial direct costs for any existing leases. In addition, AltaGas applied the transition practical expedient that permitted the Corporation to grandfather its accounting policy for land easements that existed as of, or expired, before January 1, 2019. The transition practical expedient to not separate lease and non-lease components for its building, office equipment, transportation equipment, and vehicle leases has been elected for lessee arrangements. The transition practical expedient to not separate lease and non-lease components for its lessor arrangements related to certain assets has also been elected. AltaGas has applied the short-term lease recognition exemption under which lease arrangements with a term of twelve months or less, including extension options that are reasonably certain of being exercised, are exempt from the recognition of a right-of-use asset and lease liability and recorded as an expense over the term of the lease. This exemption applies to all classes of assets.

On adoption of ASC 842, all operating leases were recognized on the Consolidated Balance Sheets. The adoption resulted in an increase to long-term assets of approximately $181 million and an increase to long-term liabilities of approximately $171 million (net of the current portion that is recorded in current liabilities of approximately $23 million). The lease related liabilities were measured using the present value of the remaining minimum lease payments for existing leases discounted using the Corporation’s incremental borrowing rate as of January 1, 2019. For operating leases, the associated right-of-use assets were measured at the amount equal to the lease liabilities on January 1, 2019, adjusted for any prepaid or accrued lease payments and the remaining balance of any lease incentives received. The adoption of ASC 842 did not impact lessor accounting, the Consolidated Statements of Income (Loss), or the Consolidated Statements of Cash Flows.

Please also refer to Note 10 of the Consolidated Financial Statements as at and for the year ended December 31, 2019 for further details;

§ ASU No. 2017-08 “Receivables – Nonrefundable Fees and Other Costs: Premium Amortization on Purchased Callable Debt Securities". The amendments in this ASU shorten the amortization period for certain callable debt securities held at a premium. Specifically, the amendments require the premium to be amortized to the earliest call date. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§ ASU No. 2017-11 “Earnings per Share and Derivatives and Hedging – Distinguishing Liabilities from Equity: Accounting for Certain Financial Instruments with Down Round Features, Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Non-controlling Interests with a Scope Exception”. The amendments in this ASU simplify the accounting for certain equity-linked financial instruments and embedded features with down round features that reduce the exercise price when pricing of a future round of financing is lower. The amendments in this ASU also require entities that present earnings per share under ASC 260 to recognize the effect of a down round feature in a freestanding equity-classified financial instrument only when it is triggered. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§ 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 adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

AltaGas Ltd. – 2019 MD&A and Financial Statements - 56

§ 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 ASU clarify whether a transfer of assets is a contribution or an exchange transaction. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§ 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 adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and

§ 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 adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements.

Future Changes in Accounting Principles

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 will adopt this standard on January 1, 2020 using a modified-retrospective approach through a cumulative-effect adjustment to retained earnings. AltaGas has completed scoping and evaluation activities for this new accounting standard, and has quantified the impact of this ASU on its opening Consolidated Balance Sheet as at January 1, 2020. Upon adoption, "accounts receivable, net of allowances" is expected to decrease by less than 1 percent of the outstanding accounts receivable balance, with an offsetting increase to "accumulated deficit".

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 post-retirement plans. 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. 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 ASU 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 ASU 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.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 57

In March 2019, FASB issued ASU No. 2019-01 “Leases: Codification Improvements”. The amendments in this ASU provide a fair value exception for lessors that are not manufacturers or dealers, clarify the presentation of principal payments received under sales-type and direct finance leases on the statements of cash flows, and clarify transition disclosure requirements for the adoption of ASC 842. The amendments on the fair value exception and on the presentation on the statement of cash flows are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted. The amendment on the transition disclosure requirement is effective upon adoption of ASC 842. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In April 2019, FASB issued ASU No. 2019-04 “Financial Instruments - Credit Losses, Derivatives and Hedging, and Codification Improvements”. The amendments in this ASU provide clarification and improve the codification in recently issued accounting standards on credit losses (ASU 2016-13), hedging (ASU 2017-12), and recognizing and measuring financial instruments (ASU 2016-01). The amendments related to credit losses have the same effective date and transition requirements as ASU 2016-13, the amendments related to hedge accounting are effective as of the beginning of the first annual period beginning after issuance of this ASU and may be applied retrospectively to the date ASU 2017-12 was adopted or prospectively with some exceptions, and the amendments related to financial instruments are effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In May 2019, FASB issued ASU No. 2019-05 “Financial Instruments - Credit Losses: Targeted Transition Relief". The amendments in this ASU provide entities that have certain instruments within the scope of Subtopic 326-20 - Financial Instruments - Credit Losses - Measured at Amortized Cost (other than held-to-maturity debt securities) a one-time irrevocable option to elect fair value treatment on an eligible instrument-by-instrument basis. The effective date and transition methodology for the amendments in this ASU are the same as ASU 2016-13. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In November 2019, FASB issued ASU No. 2019-11 "Financial Instruments - Credit Losses: Codification Improvements". The amendments in this ASU provide clarification and improve the codification in ASU 2016-13. The effective date and transition methodology for the amendments in this ASU are the same as ASU 2016-13. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In December 2019, FASB issued ASU No. 2019-12 "Income Taxes: Simplifying the Accounting for Income Taxes". The amendments in this ASU simplify the accounting for income taxes by clarifying certain aspects of current guidance and removing some exceptions to the general principles in ASC 740. 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 assessing the impact of this ASU on its 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, are 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 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).

During the year ended December 31, 2019, there were no changes made to AltaGas' ICFR that materially affected, or are reasonably likely to materially affect, its ICFR or DCP.

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, 2019 and concluded that as at December 31, 2019 AltaGas' DCP and ICFR were effective.

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 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.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 58

Summary of Consolidated Results for the Eight Most Recent Quarters ⁽¹⁾ 

($ millions)	Q4-19		Q3-19	Q2-19	Q1-19	Q4-18	Q3-18		Q2-18	Q1-18
Total revenue	1,534		888	1,174	1,898	1,727	1,041		610	878
Normalized EBITDA (2)	425		178	203	466	394	226		166	223
Net income (loss) applicable to common shares	(103	)	22	41	809	174	(726	)	1	49
($ per share)	Q4-19		Q3-19	Q2-19	Q1-19	Q4-18	Q3-18		Q2-18	Q1-18
Net income (loss) per common share
Basic	(0.37	)	0.08	0.15	2.93	0.64	(2.78	)	0.01	0.28
Diluted	(0.37	)	0.08	0.15	2.93	0.64	(2.78	)	0.01	0.28
Dividends declared	0.24		0.24	0.24	0.24	0.45	0.55		0.55	0.55

(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:

§ Revenue from WGL after the acquisition closed in the third quarter of 2018;

§ The weaker U.S. dollar in the first half of 2018 on translated results of the U.S. assets;

§ The seasonally colder weather experienced at several of the utilities throughout 2018, and the first quarter of 2019;

§ Losses on risk management contracts recorded in 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 impact of the sale of non-core U.S. Power assets in the fourth quarter of 2018;

§ The impact of the sale of the Canadian utilities to ACI and ACI's IPO in the fourth quarter of 2018;

§ The impact of the sale of the Northwest Hydro facilities and non-core Canadian Midstream and Power assets in the first quarter of 2019;

§ RIPET entering commercial service in the second quarter of 2019;

§ The impact of the sale of the U.S. distributed generation assets in the third quarter of 2019; and

§ The impact of the sale of WGL Midstream's indirect non-operating interest in Central Penn in the fourth quarter of 2019.

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, provisions 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 and gains or losses on the redemption of preferred shares. For these reasons, 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:

§ The impact of WGL income for the period after the close of the acquisition on July 6, 2018;

§ Higher depreciation and amortization expense due to new assets placed into service, partially offset by the impact of asset sales;

§ After-tax transaction costs of approximately $50 million incurred throughout 2018 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;

§ After-tax provisions of approximately $562 million recognized in 2018 primarily related to assets held for sale;

AltaGas Ltd. – 2019 MD&A and Financial Statements - 59

§ 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;

§ The impact of the sale of the Canadian utilities to ACI and ACI's IPO in the fourth quarter of 2018;

§ The impact of the sale of the Northwest Hydro facilities and non-core Canadian Midstream and Power assets in the first quarter of 2019;

§ The impact of the sale of the U.S. distributed generation assets in the third quarter of 2019;

§ The impact of the sale of WGL Midstream's indirect non-operating interest in Central Penn in the fourth quarter of 2019; and

§ After-tax provisions of approximately $319 million recognized in the fourth quarter of 2019, primarily related to Power assets.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 60

SELECTED ANNUAL FINANCIAL INFORMATION

($ millions, except where noted)	2019	2018		2017
Revenue	5,495	4,257		2,556
Net income (loss) applicable to common shares	769	(502	)	30
Net income (loss) per common share - basic	2.78	(2.25	)	0.18
Net income (loss) per common share - diluted	2.77	(2.25	)	0.18
Total assets	19,795	23,488		10,032
Total long-term liabilities	9,301	11,746		4,578
Weighted average number of common shares outstanding (millions)	277	223		171
Dividends declared per common share ($ per share)	0.960000	2.087500		2.115000
Preferred share dividends declared ($ per share)
Series A	0.845000	0.845000		0.845000
Series B	1.084641	0.968620		0.806380
Series C (US$)	1.322500	1.322500		1.155625
Series E	1.348252	1.250000		1.250000
Series G	1.155750	1.187500		1.187500
Series H	0.296040	-		-
Series I	1.312500	1.312500		1.312500
Series K	1.250000	1.250000		1.063400
Washington Gas $4.80 series (US$) (1)	2.400000	2.400000		-
Washington Gas $4.25 series (US$) (1)	2.125000	2.125000		-
Washington Gas $5.00 series (US$) (1)	2.500000	2.500000		-

(1) Washington Gas preferred shares were redeemed on December 20, 2019.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 61

MANAGEMENT'S REPORT

The Consolidated Financial Statements of AltaGas Ltd. (AltaGas or the Corporation) and other financial information included in this report are the responsibility of Management. 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. It is Management's responsibility to ensure that judgments, estimates and accounting principles and methods used in the preparation of financial information are reasonable, appropriate, and applied consistently.

Management's Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal controls over financial reporting for the Corporation (as defined in Rules 13a-15(f) of the Securities Exchange Act and under National Instrument 52-109).

Management has used the framework established in the 2013 Internal Control ‑ Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) to evaluate the effectiveness of the Corporation's internal control over financial reporting. Based on this evaluation, Management, including the CEO and CFO, has concluded that the Corporation's internal control over financial reporting is effective as at December 31, 2019.

Internal control over financial reporting may not prevent all misstatements due to its inherent limitations. In addition, the evaluation of internal control was made as of a specific date and continued effectiveness in future periods is subject to the risk that controls may become inadequate.

The Board of Directors is responsible for ensuring that Management fulfills its responsibilities for financial reporting and internal controls. The Board is assisted in carrying out its responsibilities principally through its Audit Committee which 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 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. Ernst & Young LLP is not required under securities law to express an opinion as to the effectiveness of the Corporation's internal control over financial reporting. The report of Ernst & Young LLP outlines the scope of its examination and its opinion on the Consolidated Financial Statements.

(signed) "Randall Crawford"	(signed) "James Harbilas"
RANDALL CRAWFORD	JAMES HARBILAS
President and	Executive Vice President and
Chief Executive Officer of	Chief Financial Officer of
AltaGas Ltd.	AltaGas Ltd.

February 27, 2020

AltaGas Ltd. – 2019 MD&A and Financial Statements - 62

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. (the “Company”), which comprise the consolidated balance sheets as at December 31, 2019 and 2018, and the consolidated statements of income (loss), 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 AltaGas Ltd as at December 31, 2019 and 2018, 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.

Change in Accounting Principle

As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for leases under ASC 842 in 2019 due to the adoption of ASU 2016-02, Leases.

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, 2020

AltaGas Ltd. – 2019 MD&A and Financial Statements - 63

CONSOLIDATED BALANCE SHEETS

AltaGas Ltd. – 2019 MD&A and Financial Statements - 64

As at December 31	2019		2018
ASSETS
Current assets
Cash and cash equivalents (note 31)	$	57.1	$	101.6
Accounts receivable, net of allowances (note 23)	1,222.4		1,547.5
Inventory (note 7)	505.6		515.9
Restricted cash holdings from customers (note 31)	4.0		4.1
Regulatory assets (note 21)	12.8		21.0
Risk management assets (note 23)	86.6		114.1
Prepaid expenses and other current assets (notes 28 and 31)	280.2		199.9
Assets held for sale (note 5)	27.5		1,528.9
	2,196.2		4,033.0
Property, plant and equipment (note 8)	10,125.5		10,929.6
Intangible assets (note 9)	585.6		711.9
Operating right-of-use assets(note 10)	169.8		—
Goodwill (note 11)	3,942.1		4,068.2
Regulatory assets (note 21)	486.7		663.0
Risk management assets (note 23)	39.1		57.7
Restricted cash holdings from customers(note 31)	3.9		6.1
Prepaid post-retirement benefits (note 28)	487.5		342.7
Long-term investments and other assets (notes 12, 28, and 31)	296.5		283.1
Investments accounted for by the equity method (note 14)	1,461.6		2,392.4
	$	19,794.5	$	23,487.7
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities (notes 17, 18, 23, and 28)	$	1,324.9	$	1,488.2
Dividends payable (note 23)	22.3		22.0
Short-term debt (notes 15 and 23)	460.0		1,209.9
Current portion of long-term debt (notes 16 and 23)	922.9		890.2
Customer deposits	76.6		98.0
Regulatory liabilities (note 21)	145.5		114.9
Risk management liabilities (note 23)	124.8		89.3
Operating lease liabilities (note 10)	27.3		—
Other current liabilities (note 23)	17.0		18.1
Liabilities associated with assets held for sale (note 5)	3.8		171.4
	3,125.1		4,102.0
Long-term debt(notes 16 and 23)	5,927.8		8,066.9
Asset retirement obligations (note 17)	362.0		500.6
Unamortized investment tax credits (note 20)	3.8		190.1
Deferred income taxes (note 20)	959.1		957.9
Regulatory liabilities (note 21)	1,383.2		1,392.8
Risk management liabilities(note 23)	167.0		213.0
Operating lease liabilities(note 10)	153.4		—
Other long-term liabilities(notes 19 and 23)	101.8		122.0
Future employee obligations (note 28)	242.5		302.2
	$	12,425.7	$	15,847.5

As at December 31	2019			2018
Shareholders' equity
Common shares, no par values, unlimited shares authorized;    2019 - 279.1 million and 2018 - 275.2 million issued and outstanding (note 25)	$	6,719.0		$	6,653.9
Preferred shares (note 25)	1,277.1			1,318.8
Contributed surplus	376.7			373.2
Accumulated deficit	(1,402.8		)	(1,905.3		)
Accumulated other comprehensive income (AOCI) (note 22)	244.9			579.0
Total shareholders' equity	7,214.9			7,019.6
Non-controlling interests	153.9			620.6
Total equity	$	7,368.8		$	7,640.2
	$	19,794.5		$	23,487.7

Variable interest entities (note 13)

Commitments, guarantees and contingencies (note 29)

Segmented information (note 32)

Subsequent events (note 33)

See accompanying notes to the Consolidated Financial Statements.

Approved by the Board of Directors of AltaGas Ltd.

(signed) "Randall Crawford"	(signed) "Robert B. Hodgins"
RANDALL CRAWFORD	ROBERT B. HODGINS
Director	Director

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

Year Ended December 31	2019			2018
REVENUE(note 24)	$	5,495.0		$	4,256.7
EXPENSES
Cost of sales, exclusive of items shown separately	3,227.1			2,455.3
Operating and administrative	1,298.7			1,129.0
Accretion expenses (note 17)	5.1			10.9
Depreciation and amortization (notes 8 and 9)	438.0			394.0
Provisions on assets (note 6)	415.8			728.7
	5,384.7			4,717.9
Income from equity investments (note 14)	141.1			47.9
Other income (note 27)	908.1			0.9
Foreign exchange gains (losses)	(1.0		)	4.5
Interest expense	(345.8		)	(309.0		)
Income (loss) before income taxes	812.7			(716.9		)
Income tax expense (recovery)(note 20)
Current	63.3			24.4
Deferred	(90.9		)	(287.6		)
Net income (loss) after taxes	840.3			(453.7		)
Net income (loss) applicable to non-controlling interests	6.8			(18.6		)
Net income (loss) applicable to controlling interests	833.5			(435.1		)
Preferred share dividends	(68.5		)	(66.6		)
Gain on redemption of preferred shares (note 25)	3.5			—
Net income (loss) applicable to common shares	$	768.5		$	(501.7	)
Net income (loss) per common share (note 26)
Basic	$	2.78		$	(2.25	)
Diluted	$	2.77		$	(2.25	)
Weighted average number of common shares    outstanding (millions)(note 26)
Basic	276.9			222.6
Diluted	277.4			222.6

See accompanying notes to the Consolidated Financial Statements.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

Year Ended December 31	2019			2018
Net income (loss) after taxes	$	840.3		$	(453.7	)
Other comprehensive income (loss), net of taxes
Gain (loss) on foreign currency translation	(406.2		)	458.5
Unrealized gain (loss) on net investment hedge (note 23)	60.0			(80.2		)
Actuarial gain (loss) on pension plans and post-retirement benefit (PRB) plans (note 28)	12.0			(10.8		)
Reclassification of actuarial gains and prior service credits on defined benefit (DB) and post-retirement benefit plans (PRB) to net income (note 28)	0.8			0.5
Curtailment of DB and PRB plan (note 28)	—			2.7
Adoption of ASU 2016-01	—			7.1
Other comprehensive income (loss) from equity investees	(0.7		)	2.1
Total other comprehensive income (loss) (OCI), net of taxes (note 22)	(334.1		)	379.9
Comprehensive income (loss) attributable to controlling interests and non-controlling interests, net of taxes	$	506.2		$	(73.8	)
Comprehensive income (loss) attributable to:
Non-controlling interests	$	6.8		$	(18.6	)
Controlling interests	499.4			(55.2		)
	$	506.2		$	(73.8	)

 See accompanying notes to the Consolidated Financial Statements.

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CONSOLIDATED STATEMENTS OF EQUITY

Year Ended December 31	2019			2018
Common shares(note 25)
Balance, beginning of year	$	6,653.9		$	4,007.9
Shares issued for cash on exercise of options	1.2			1.3
Shares issued under DRIP (1)	67.8			325.8
Deferred taxes on share issuance costs	(3.9		)	13.3
Shares issued on conversion of subscription receipts, net of issuance costs	—			2,305.6
Balance, end of year	$	6,719.0		$	6,653.9
Preferred shares (note 25)
Balance, beginning of year	$	1,318.8		$	1,277.7
Preferred shares acquired through WGL Acquisition (note 3)	—			41.1
Redemption of WGL preferred shares	(41.1		)	—
Deferred taxes on share issuance costs	(0.6		)	—
Balance, end of year	$	1,277.1		$	1,318.8
Contributed surplus
Balance, beginning of year	$	373.2		$	22.3
Share options expense	3.7			0.9
Exercise of share options	(0.1		)	(0.1		)
Forfeiture of share options	(0.1		)	(0.1		)
Sale of non-controlling interest	—			350.2
Balance, end of year	$	376.7		$	373.2
Accumulated deficit
Balance, beginning of year	$	(1,905.3	)	$	(933.6	)
Net income (loss) applicable to controlling interests	833.5			(435.1		)
Common share dividends	(266.0		)	(462.9		)
Preferred share dividends	(68.5		)	(66.6		)
Gain on redemption of preferred shares	3.5			—
Adoption of ASU No. 2016-01	—			(7.1		)
Balance, end of year	$	(1,402.8	)	$	(1,905.3	)
AOCI (note 22)
Balance, beginning of year	$	579.0		$	199.1
Other comprehensive income (loss)	(334.1		)	379.9
Balance, end of year	$	244.9		$	579.0
Total shareholders' equity	$	7,214.9		$	7,019.6
Non-controlling interests
Balance, beginning of year	$	620.6		$	65.8
Net income (loss) applicable to non-controlling interests	6.8			(18.6		)
Sale of non-controlling interest	—			498.4
Adjustment on disposition of assets	(508.0		)	—
Contributions from non-controlling interests to subsidiaries	47.9			96.3
Distributions by subsidiaries to non-controlling interests	(13.4		)	(30.3		)
Acquisition of non-controlling interest through WGL Acquisition (note 3)	—			9.0
Balance, end of year	$	153.9		$	620.6
Total equity	$	7,368.8		$	7,640.2

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

See accompanying notes to the Consolidated Financial Statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31	2019			2018
Cash from (used by) operations
Net income (loss) after taxes	$	840.3		$	(453.7	)
Items not involving cash:
Depreciation and amortization	438.0			394.0
Provisions on assets (note 6)	415.8			728.7
Accretion expenses	5.1			10.9
Share-based compensation (note 25)	3.5			0.8
Deferred income tax recovery (note 20)	(90.9		)	(287.6		)
Losses (gains) on sale of assets (notes 4 and 27)	(875.8		)	10.6
Income from equity investments (note 14)	(141.1		)	(47.9		)
Unrealized losses (gains) on risk management contracts (note 23)	85.3			(80.8		)
Realized loss on expiry of foreign exchange options	—			36.0
Losses on investments (note 27)	4.1			10.1
Amortization of deferred financing costs	11.5			29.7
Provision for doubtful accounts	26.7			17.0
Net change in pension and other post-retirement benefits (note 28)	8.1			(3.8		)
Other	9.2			3.6
Asset retirement obligations settled (note 17)	(2.5		)	(4.2		)
Distributions from equity investments	109.7			44.5
Changes in operating assets and liabilities (note 31)	(231.5		)	(486.5		)
	$	615.5		$	(78.6	)
Investing activities
Business acquisitions, net of cash acquired	—			(5,931.0		)
Acquisition of property, plant and equipment	(1,296.8		)	(990.4		)
Acquisition of intangible assets	(37.7		)	(38.1		)
Contributions to equity investments	(178.7		)	(235.4		)
Loan to affiliate, net of repayment (note 30)	—			30.0
Financing receivable	—			(8.7		)
Proceeds from disposition of investments	—			76.5
Proceeds from initial public offering of AltaGas Canada Inc.	—			858.9
Proceeds from disposition of assets, net of transaction costs (note 4)	3,623.4			403.8
Proceeds from disposition of financing receivable (note 4)	73.5			—
	$	2,183.7		$	(5,834.4	)
Financing activities
Net issuance (repayment) of short-term debt	(700.9		)	497.7
Issuance of long-term debt, net of debt issuance costs	888.6			1,851.9
Repayment of long-term debt	(873.3		)	(278.8		)
Net borrowing (repayment) under credit facilities	(1,919.7		)	846.2
Dividends - common shares	(265.7		)	(472.9		)
Dividends - preferred shares	(68.5		)	(66.6		)
Distributions to non-controlling interest	(13.4		)	(30.3		)
Contributions from non-controlling interests	47.9			96.3
Net proceeds from shares issued on exercise of options	1.1			1.2
Net proceeds from issuance of common shares	67.8			2,633.7
Redemption of preferred shares (note 25)	(37.6		)	—
Net proceeds from sale of non-controlling interest	—			908.6
	$	(2,873.7	)	$	5,987.0
Change in cash, cash equivalents, and restricted cash	(74.5		)	74.0
Effect of exchange rate changes on cash, cash equivalents, and    restricted cash	(9.1		)	7.3
Net change in cash classified within assets held for sale	4.9			(4.9		)
Restricted cash acquired (note 31)	—			81.0
Cash, cash equivalents, and restricted cash beginning of year	201.1			43.7
Cash, cash equivalents, and restricted cash end of year (note 31)	$	122.4		$	201.1

See accompanying notes to the Consolidated Financial Statements. 

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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. (WGL Energy Services), 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, Ridley Island LPG Export Limited Partnership, and WGL Midstream Inc. (WGL Midstream); in regards to the Power business, AltaGas Power Holdings (U.S.) Inc., WGL Energy Systems, Inc. (WGL Energy Systems), and Blythe Energy Inc. (Blythe); and, in regards to the Utilities business, Washington Gas Light Company (Washington Gas), 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), its Alaska natural gas distribution business under the name ENSTAR Natural Gas Company (ENSTAR) and its 65 percent interest in an Alaska regulated gas storage utility under the name Cook Inlet Natural Gas Storage Alaska LLC (CINGSA).

AltaGas, a Canadian corporation, is a leading North American energy infrastructure company that connects natural gas liquids (NGLs) and natural gas to domestic and global markets. The Corporation’s long-term strategy is to grow in attractive areas across its Utilities and Midstream 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 the West Coast of Canada via the Corporation’s footprint in the Montney region. In the Utilities business, the Corporation seeks to grow through rate base investment and the use of accelerated rate recovery programs, while providing effective and cost-efficient service for customers. AltaGas has three business segments:

§ Utilities, which serves approximately 1.7 million customers with a rate base of approximately US$3.9 billionthrough 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 includes a 70 percent interest in the recently completed Ridley Island Propane Export Terminal, allowing AltaGas to leverage its assets along the energy value chain in Western Canada including natural gas gathering and processing,NGLextraction and fractionation, and natural gas and NGL marketing. The Midstream segment also includes transmission, storage, an interest in a regulated pipeline in the Marcellus/Utica gas formation in the northeastern United States, WGL’s retail gas marketing business, the Corporation’s 50 percent interest inAltaGas Idemitsu Joint Venture Limited Partnership (AIJVLP), and an indirectly held approximate one-third ownership investment in Petrogas Energy Corp. (Petrogas), through which AltaGas’ interest in the Ferndale terminal is held; and

§ Power, which includes 710 MW of operational capacity from natural gas-fired, distributed generation, and energy storage assets, certain of which are pending sale, located in Alberta, Canada and the United States, primarily in California and Colorado. The Power business also includes energy efficiency contracting and WGL’s retail power marketing business.

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).

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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, but not control, over are accounted for using the equity method.

Hypothetical Liquidation at Book Value (HLBV) methodology is used for certain equity method investments as well as 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. The majority of AltaGas' HLBV investments were sold during 2019.

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 (loss) and are presented separately in "net income (loss) 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; determination as to whether a contract is or contains a lease; determination of the classification, term, and discount rate for leases; 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; purchase price allocations; 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 Gas (collectively the 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. Hampshire is regulated under a cost-of-service tariff by the Federal Energy Regulatory Commission (FERC).

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 Washington Gas executive and outside director retirement benefit plan obligations. The rabbi trust funds are invested in money market funds which are considered 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, natural gas liquids, 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.

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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, for which 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 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.

The 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	4 to 69 years
Midstream assets	2 to 45 years
Power generation assets	3 to 46 years
Corporate assets	3 to 7 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 after 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 Statements of Income (Loss). 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 Statements of Income (Loss).

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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 to 19 years
Electricity service agreements	2 to 60 years
Software	3 to 10 years
Land rights	5 to 64 years
Franchises and consents	9 to 25 years
Extraction and Transmission (E&T) Contracts	25 years
Commodity contracts	5 to 20 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 principally 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. Management applies its best estimates and assumptions to determine the fair value of net assets acquired; however, the estimates are subject to further refinement of assumptions over a measurement period, which may be up to one year from the acquisition date. During the measurement period, adjustments to assets acquired and liabilities assumed may be recorded, with a corresponding impact to goodwill.

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 Statements of Income (Loss).

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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 Statements of Income (Loss).

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 Statements of Income (Loss) 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.

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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 Statements of Income (Loss).

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.

Transaction costs for obtaining debt financing and reacquired debt costs are recorded as regulatory assets or liabilities, or as a reduction of the debt liability on the Consolidated Balance Sheets.

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 23 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.

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Debt

AltaGas uses short-term debt in the form of commercial paper and advances under its syndicated bank credit facilities to fund seasonal cash requirements. Short-term obligations are excluded from current liabilities if AltaGas has the ability and the intent to refinance these obligations on a long-term basis. The ability to refinance is primarily demonstrated through the availability of long-term revolving committed credit facilities in an amount equal to or greater than the expected maximum short-term obligation.

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 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 24.

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 Statements of Income (Loss). 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.

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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 phantom unit plan (Phantom Plan, formerly the medium-term incentive plan) 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. The other portion of RU’s and PUs are valued at US$1 per unit. Upon vesting, the RUs and PUs are paid in cash. All PUs are also subject to a performance multiplier ranging from 0 to 2.4 dependent on the Corporation's performance relative to performance targets as approved by the Board of Directors. 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, the participant is entitled to payment upon retirement, 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, expected health care costs, and other actuarial factors including discount rates and mortality. 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 and credits 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 9.0 years and 13.2 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.

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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 (Loss) per Share

Basic net income (loss) 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.

Leases

The following are the Corporation’s significant accounting policies upon the adoption of ASC 842:

Leases – Lessee

AltaGas determines if an arrangement is a lease at inception. Operating leases are included in right-of-use (ROU) assets, current operating lease liabilities, and long-term operating lease liabilities in the Consolidated Balance Sheets. Finance leases are included in property, plant and equipment and current and long-term debt in the Consolidated Balance Sheets.

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ROU assets represent the right to use an underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Operating lease ROU assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. AltaGas uses the rate implicit in the lease when readily determinable. When the implicit lease rate is not readily determinable, AltaGas uses its incremental borrowing rate to determine the present value of lease payments. AltaGas includes lessee options to renew or terminate the lease term in the determination of the ROU asset and lease liability when exercise is reasonably certain. The operating lease ROU asset is adjusted for lease payments made in advance of the commencement date, initial direct costs, and any lease incentives.

Operating lease expense is recognized on a straight-line basis over the lease term in "operating and administrative expense". Depreciation and interest expense are recorded on finance leases.

Leases – Lessor

AltaGas determines if an arrangement is a lease at inception. Lease payments under an operating lease are recognized on a straight-line basis over the term of the lease. Variable lease payments are recognized as revenue as the facts and circumstances on which the variable lease payment is based occur.

AltaGas does not include taxes assessed by governmental authorities, such as sales and related taxes, in the lease payments or variable lease payments.

Collaborative Arrangements

WGL has collaborative arrangements with a third party to facilitate the asset optimization program. The collaborative arrangements allocate a tiered or fixed percentage of profits or losses to the third party as compensation for its participation. The income recorded related to the collaborative arrangements totaled $1.4 million for the year ended December 31, 2019 (2018 - expense of $0.2 million).

ADOPTION OF NEW ACCOUNTING STANDARDS

Effective January 1, 2019, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU):

§ ASU No. 2016-02 “Leases” and all related amendments (collectively “ASC 842”). AltaGas has applied ASC 842 using the modified retrospective approach as of the effective date of the new standard. Comparative information has not been restated and continues to be reported under the previous lease guidance ASC 840. AltaGas has applied the package of transition practical expedients which permitted the Corporation to not reassess (a) whether any expired or existing contracts contain leases, (b) lease classifications for any expired or existing leases, and (c) initial direct costs for any existing leases. In addition, AltaGas applied the transition practical expedient that permitted the Corporation to grandfather its accounting policy for land easements that existed as of, or expired, before January 1, 2019. The transition practical expedient to not separate lease and non-lease components for its building, office equipment, transportation equipment, and vehicle leases has been elected for lessee arrangements. The transition practical expedient to not separate lease and non-lease components for its lessor arrangements related to certain assets has also been elected. AltaGas has applied the short-term lease recognition exemption under which lease arrangements with a term of twelve months or less, including extension options that are reasonably certain of being exercised, are exempt from the recognition of a right-of-use asset and lease liability and recorded as an expense over the term of the lease. This exemption applies to all classes of assets.

On adoption of ASC 842, all operating leases were recognized on the Consolidated Balance Sheets. The adoption resulted in an increase to long-term assets of approximately$181.0million and an increase to long-term liabilities of

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approximately$170.5million (net of the current portion that is recorded in current liabilities of approximately$23.3million). The lease related liabilities were measured using the present value of the remaining minimum lease payments for existing leases discounted using the Corporation’s incremental borrowing rate as of January 1, 2019. For operating leases, the associated right-of-use assets were measured at the amount equal to the lease liabilities on January 1, 2019, adjusted for any prepaid or accrued lease payments and the remaining balance of any lease incentives received. The adoption of ASC 842 did not impact lessor accounting, the Consolidated Statements of Income (Loss), or the Consolidated Statements of Cash Flows.

Please also refer to Note 10 of the Consolidated Financial Statements as at and for the year ended December 31, 2019 for further details;

§ ASU No. 2017-08 “Receivables – Nonrefundable Fees and Other Costs: Premium Amortization on Purchased Callable Debt Securities". The amendments in this ASU shorten the amortization period for certain callable debt securities held at a premium. Specifically, the amendments require the premium to be amortized to the earliest call date. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§ ASU No. 2017-11 “Earnings per Share and Derivatives and Hedging – Distinguishing Liabilities from Equity: Accounting for Certain Financial Instruments with Down Round Features, Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Non-controlling Interests with a Scope Exception”. The amendments in this ASU simplify the accounting for certain equity-linked financial instruments and embedded features with down round features that reduce the exercise price when pricing of a future round of financing is lower. The amendments in this ASU also require entities that present earnings per share under ASC 260 to recognize the effect of a down round feature in a freestanding equity-classified financial instrument only when it is triggered. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§ 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 adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§ 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 ASU clarify whether a transfer of assets is a contribution or an exchange transaction. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§ 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 adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and

§ 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 adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements.

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FUTURE CHANGES IN ACCOUNTING PRINCIPLES

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 will adopt this standard on January 1, 2020 using a modified-retrospective approach through a cumulative-effect adjustment to retained earnings. AltaGas has completed scoping and evaluation activities for this new accounting standard, and has quantified the impact of this ASU on its opening Consolidated Balance Sheet as at January 1, 2020. Upon adoption, "accounts receivable, net of allowances" is expected to decrease by less than 1 percent of the outstanding accounts receivable balance, with an offsetting increase to "accumulated deficit".

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 post-retirement plans. 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. 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 ASU 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 ASU 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.

In March 2019, FASB issued ASU No. 2019-01 “Leases: Codification Improvements”. The amendments in this ASU provide a fair value exception for lessors that are not manufacturers or dealers, clarify the presentation of principal payments received under sales-type and direct finance leases on the statements of cash flows, and clarify transition disclosure requirements for the adoption of ASC 842. The amendments on the fair value exception and on the presentation on the statement of cash flows are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted. The amendment on the transition disclosure requirement is effective upon adoption of ASC 842. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In April 2019, FASB issued ASU No. 2019-04 “Financial Instruments - Credit Losses, Derivatives and Hedging, and Codification Improvements”. The amendments in this ASU provide clarification and improve the codification in recently issued accounting standards on credit losses (ASU 2016-13), hedging (ASU 2017-12), and recognizing and measuring financial instruments (ASU 2016-01). The amendments related to credit losses have the same effective date and transition requirements as ASU 2016-13, the amendments related to hedge accounting are effective as of the beginning of the first annual period beginning after issuance of this ASU and may be applied retrospectively to the date ASU 2017-12 was adopted or prospectively with some exceptions, and the amendments related to financial instruments are effective for fiscal years beginning after December 15, 2019, including

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interim periods within those fiscal years. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In May 2019, FASB issued ASU No. 2019-05 “Financial Instruments - Credit Losses: Targeted Transition Relief". The amendments in this ASU provide entities that have certain instruments within the scope of Subtopic 326-20 - Financial Instruments - Credit Losses - Measured at Amortized Cost (other than held-to-maturity debt securities) a one-time irrevocable option to elect fair value treatment on an eligible instrument-by-instrument basis. The effective date and transition methodology for the amendments in this ASU are the same as ASU 2016-13. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In November 2019, FASB issued ASU No. 2019-11 "Financial Instruments - Credit Losses: Codification Improvements". The amendments in this ASU provide clarification and improve the codification in ASU 2016-13. The effective date and transition methodology for the amendments in this ASU are the same as ASU 2016-13. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In December 2019, FASB issued ASU No. 2019-12 "Income Taxes: Simplifying the Accounting for Income Taxes". The amendments in this ASU simplify the accounting for income taxes by clarifying certain aspects of current guidance and removing some exceptions to the general principles in ASC 740. 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 assessing the impact of this ASU on its consolidated financial statements.

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. The WGL Acquisition was 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 was recognized as goodwill at the acquisition date.

The following table summarizes the final 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 was finalized on June 30, 2019 and reflects Management’s best estimate of the fair value of WGL’s assets and liabilities. In the first half of 2019, based on new information obtained in the period and further refinement of assumptions, adjustments to the purchase price allocation included amounts relating to intangible assets, deferred income taxes, pension liabilities, current liabilities, other long-term liabilities, valuation of equity investments in Midstream pipelines, and deferred rent, resulting in a net increase to goodwill of approximately $92.2 million (Note 11).

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Purchase consideration	$	5,973
Fair value assigned to net assets
Current assets	$	1,220
Property, plant and equipment	5,884
Intangible assets	577
Regulatory assets	408
Long-term investments	1,475
Other long-term assets	462
Current liabilities	(1,916		)
Long-term debt	(2,548		)
Preferred shares	(41		)
Regulatory liabilities	(1,126		)
Deferred income taxes	(741		)
Other long-term liabilities	(959		)
Non-controlling interest	(9		)
Accumulated other comprehensive income	(2		)
Fair value of net assets acquired	$	2,684
Goodwill	$	3,289

4. Dispositions

Northwest Hydro Electric Facilities

On January 31, 2019, AltaGas completed the disposition of its remaining 55 percent indirect interest in the Northwest Hydro Electric facilities in British Columbia (Northwest Hydro) for net cash proceeds of approximately $1.3 billion. The disposition was completed through the sale of 55 percent of Northwest Hydro Limited Partnership, a subsidiary of AltaGas which indirectly held the Northwest Hydro facilities. As a result, AltaGas recognized a pre-tax gain on disposition of approximately $687.6 million in the Consolidated Statements of Income (Loss) under the line item “other income” for the year ended December 31, 2019.

Non-Core Midstream and Power Assets in Canada

On February 1, 2019, AltaGas completed the disposition of certain non-core Midstream and Power assets for gross cash proceeds of approximately $87.8 million. As a result, AltaGas recognized a pre-tax loss on disposition of approximately $1.2 million in the Consolidated Statements of Income (Loss) under the line item “other income” for the year ended December 31, 2019.

Architect of the Capitol (AOC) Project

In February 2019, AltaGas completed the disposition of a financing receivable related to the construction of an energy management services project for gross cash proceeds of approximately $73.5 million. As a result, AltaGas recognized a pre-tax loss on disposition of approximately $1.3 million in the Consolidated Statements of Income (Loss) under the line item “other income” for the year ended December 31, 2019.

Stonewall Gas Gathering System

On May 31, 2019, AltaGas completed the disposition of WGL Midstream's entire interest in the Stonewall Gas Gathering System (Stonewall) to a wholly-owned subsidiary of DTE Energy Company for gross cash proceeds of approximately $379.2 million (US$280 million). As a result, AltaGas recognized a pre-tax gain on disposition of $34.1 million in the Consolidated Statements of Income (Loss) under the line item “other income” for the year ended December 31, 2019.

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Biomass Assets

On August 13, 2019, AltaGas completed the disposition of its equity ownership interests in Craven County Wood Energy LP and Grayling Generation Station LP for net proceeds of approximately $24.5 million (US$18.5 million). There was no gain or loss resulting from this disposition.

Distributed Generation Assets

On September 26, 2019, AltaGas closed the disposition of its portfolio of U.S. distributed generation assets for gross cash proceeds of approximately $975.0 million (US$735.0 million).As a result, AltaGas recognized a pre-tax gain on disposition of approximately $167.5 millionin the Consolidated Statements of Income (Loss) under the line item "other income" for the year ended December 31, 2019. There are certain projects for which ownership will not legally transfer to the purchaser until various consents and approvals are obtained. As such, the carrying value of the assets and liabilities relating to these projects remain classified as held for sale on the Consolidated Balance Sheets as at December 31, 2019 (Note 5). The portion of the purchase price relating to these projects is approximately $32.2 million(US$24.8 million)and is recorded within "accounts payable and accrued liabilities" on the Consolidated Balance Sheets until these projects are legally transferred to the purchaser. The pre-tax gain related to these remaining projects has also been deferred and will be recognized as these projects are legally transferred. The purchaser is entitled to after-tax earnings from the distributed generation projects, including those awaiting consent, beginning September 1, 2019.

Capital Spare

In the third quarter of 2019, AltaGas completed the sale of a capital spare turbine in the Power segment for gross cash proceeds of $4.6 million (US$3.5 million). There was no gain or loss resulting from this disposition in the year ended December 31, 2019.

Investment in Meade

On November 13, 2019, AltaGas completed the disposition of its investment in Meade Pipeline Co. LLC (Meade) which held WGL Midstream's indirect, non-operating interest in the Central Penn pipeline (Central Penn), for cash proceeds of approximately $811.5 million (US$610.8 million). As a result, AltaGas recognized a pre-tax loss on disposition of $11.1 millionin the Consolidated Statements of Income (Loss) under the line item “other income” for the year ended December 31, 2019. During 2019, AltaGas also recognized a pre-tax provision of $44.2 million against AltaGas' investment in Meade Pipeline Co. LLC (Note 14).

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5. Assets Held For Sale

As at	December 31, 2019		December 31, 2018
Assets held for sale
Cash	$	—	$	4.9
Accounts receivable	—		85.2
Inventory	—		0.5
Property, plant and equipment	22.9		1,189.6
Intangible assets	—		248.7
Operating right-of-use assets	0.4		—
Goodwill	1.0		—
Other long-term assets	3.2		—
	$	27.5	$	1,528.9
Liabilities associated with assets held for sale
Accounts payable and accrued liabilities	$	—	$	23.8
Asset retirement obligations	0.2		10.8
Unamortized investment tax credits	3.2		—
Operating lease liabilities - long-term	0.4		—
Other long-term liabilities	—		136.8
	$	3.8	$	171.4

Distributed Generation Assets

In September 2019, AltaGas closed the sale of its portfolio of U.S. distributed generation assets (Note 4). However, there are certain projects for which ownership will not legally transfer to the purchaser until various consents and approvals are obtained. As such, the carrying value of the assets and liabilities related to these projects remain classified as held for sale at December 31, 2019. These assets are recorded in the Power segment.

6. Provisions on Assets

Year Ended December 31	2019		2018
Utilities	$	—	$	193.7
Midstream	35.2		153.7
Power	380.6		381.3
	$	415.8	$	728.7

Utilities

There were no provisions recorded in the Utilities segment in 2019. In 2018, AltaGas recorded pre-tax provisions of $193.7 million related to certain rate-regulated natural gas distributed utility assets that were classified as held for sale in the third quarter of 2018.

Midstream

In 2019, AltaGas recorded pre-tax provisions of $35.2 million related to the Pouce Coupe sour gas treatment facility in Alberta. The pre-tax provisions were comprised of $35.0 million on property, plant and equipment and $0.2 million on intangible assets.

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In 2018, AltaGas recorded pre-tax provisions of $153.7 million related to certain non-core Midstream assets that were classified as held for sale at December 31, 2018 and shut-in assets in the South, Cold Lake and Northwest operating areas.

Power

In 2019, AltaGas recorded pre-tax provisions totaling $380.6 million in the Power segment. The pre-tax provisions were recorded against property, plant and equipment. In 2018, AltaGas recorded pre-tax provisions of $381.3 million primarily related to the Tracy, Hanford, and Henrietta gas-fired peaking plants in California that were disposed of in the fourth quarter of 2018, a development project in the U.S., the Pomona natural gas-fired co-generation facility in the United States, and non-core Power assets in Canada and a WGL Energy Systems financing receivable that were classified as held for sale at December 31, 2018.

7. Inventory

As at December 31	2019		2018
Natural gas held in storage (a)	$	359.0	$	418.0
Materials and supplies	56.3		53.3
Renewable energy credits and emission compliance instruments	64.1		38.2
Natural gas liquids	26.2		6.4
	$	505.6	$	515.9

(a) As at December 31, 2019, $214.3 million of the natural gas held in storage was held by rate-regulated utilities(2018 - $270.4 million).

8. Property, Plant and Equipment

As at	December 31, 2019									December 31, 2018
	Cost			Accumulated amortization			Net book value			Cost			Accumulated amortization			Net book value
Utilities	$	7,316.1		$	(155.0	)	$	7,161.1		$	7,090.5		$	(89.7	)	$	7,000.8
Midstream	3,182.0			(585.4		)	2,596.6			3,178.2			(845.7		)	2,332.5
Power	976.7			(594.6		)	382.1			4,633.9			(1,858.3		)	2,775.6
Corporate	49.5			(40.9		)	8.6			49.4			(39.1		)	10.3
Reclassified to assets held for sale	(25.2		)	2.3			(22.9		)	(2,999.3		)	1,809.7			(1,189.6		)
	$	11,499.1		$	(1,373.6	)	$	10,125.5		$	11,952.7		$	(1,023.1	)	$	10,929.6

Interest capitalized on long-term capital construction projects for the year ended December 31, 2019 was $14.5 million(2018 - $12.6 million).

As at December 31, 2019, the Corporation had approximately $725.2 million (December 31, 2018 - $872.7 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, 2019 was $357.8 million (2018 - $324.3 million).

AltaGas Ltd. – 2019 MD&A and Financial Statements - 86

9. Intangible Assets

As at	December 31, 2019							December 31, 2018
	Cost		Accumulated amortization			Net book value		Cost			Accumulated amortization			Net book value
E&T contracts	$	26.6	$	(15.2	)	$	11.4	$	26.6		$	(14.3	)	$	12.3
Electricity service agreements	8.5		(7.8		)	0.7		269.5			(25.9		)	243.6
Energy services relationships	91.6		(27.4		)	64.2		176.1			(33.8		)	142.3
Software	303.7		(101.2		)	202.5		293.9			(77.7		)	216.2
Land rights	1.1		(0.1		)	1.0		1.4			(0.2		)	1.2
Commodity contracts	327.1		(21.3		)	305.8		346.3			(6.3		)	340.0
Franchises and consents	—		—			—		5.0			—			5.0
Reclassified to assets held for sale (note 5)	—		—			—		(277.4		)	28.7			(248.7		)
	$	758.6	$	(173.0	)	$	585.6	$	841.4		$	(129.5	)	$	711.9

Amortization expense related to intangible assets for the year ended December 31, 2019 was 80.2 million(2018 - $69.7 million).

As at December 31, 2019, the Corporation excluded $184.5 million (December 31, 2018 - $196.4 million) from the asset base subject to amortization. Items excluded relate 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:

2020	$	79.1
2021	$	70.6
2022	$	69.7
2023	$	62.3
2024	$	24.2
Thereafter	$	95.2

10. Leases

Lessee

AltaGas has operating and finance leases for office space, office equipment, field equipment, rail cars, vehicles, power and gas facilities, transmission and distribution assets, and land.

The components of lease expense were as follows:

	Year Ended December 31, 2019
Operating lease cost (includes variable lease payments)	$	29.2
Finance lease cost
Amortization of right-of-use assets	$	3.4
Interest on lease liabilities	0.3
Total finance lease cost	$	3.7
Total lease cost	$	32.9

AltaGas Ltd. – 2019 MD&A and Financial Statements - 87

Supplemental cash flow information related to leases was as follows:

	Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from finance leases	$	(0.3	)
Operating cash flows from operating leases	$	(20.6	)
Financing cash flows from finance leases (a)	$	(3.7	)
Right-of-use assets obtained in exchange for new lease liabilities
Operating leases	$	50.4
Finance leases	$	5.4

(a) Included within repayment of long-term debt on the Consolidated Statements of Cash Flows.

Supplemental balance sheet information related to leases was as follows:

As at	December 31, 2019
Operating Leases
Operating lease right-of-use assets
Long-term	$	169.8
Included in assets held for sale (note 5)	0.4
Total operating lease right-of-use assets	$	170.2
Operating lease liabilities
Current	$	(27.3	)
Long-term	(153.4		)
Included in liabilities associated with assets held for sale (note 5)	(0.4		)
Total operating lease liabilities	$	(181.1	)
Finance Leases
Property and equipment, gross	$	13.2
Accumulated depreciation	(3.3		)
Property and equipment, net	$	9.9
Current portion of long-term debt	$	(3.5	)
Long-term debt	(6.4		)
Total finance lease liabilities	$	(9.9	)

As at	December 31, 2019
Weighted average remaining lease term (years)
Operating leases	10.9
Finance leases	5.2
Weighted average discount rate (%)
Operating leases	3.51
Finance leases	3.68

AltaGas Ltd. – 2019 MD&A and Financial Statements - 88

Maturity analysis of lease liabilities was as follows:

	Operating Leases			Finance Leases
2020	$	27.8		$	3.5
2021	27.1			2.9
2022	26.5			2.0
2023	24.5			1.1
2024	20.1			0.4
Thereafter	100.1			2.0
Total lease payments	226.1			11.9
Less: imputed interest	(45.0		)	(2.0		)
Total	$	181.1		$	9.9

As of December 31, 2019, AltaGas has additional operating leases, primarily for rail cars, that have not yet commenced of $4.8 million. These operating leases will commence in 2020 with lease terms of up to 6 years.

Lessor

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.

Maturity analysis of lease receivables was as follows:

	Operating Leases
2020	$	118.3
2021	115.4
2022	115.6
2023	115.9
2024	47.8
Thereafter	477.5
Total	$	990.5

The carrying value of property, plant, and equipment associated with these leases was approximately $0.5 billion as at December 31, 2019.

AltaGas manages its risk associated with the residual value of its leased assets through strategically constructing leased facilities in key commercial regions and retaining the ability to sell commodities and ancillary services via the merchant market or through commodity sales agreements.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 89

11. Goodwill

As at	December 31, 2019			December 31, 2018
Balance, beginning of year	$	4,068.2		$	817.3
Provisions on assets	—			(124.2		)
Business acquisition (note 3)	—			3,196.4
Adjustment to goodwill on business acquisition (note 3)	92.2			—
Goodwill included in dispositions (note 4)	(29.1		)	—
Reclassified to assets held for sale (note 5)	(1.0		)	—
Foreign exchange translation	(188.2		)	178.7
Balance, end of year	$	3,942.1		$	4,068.2

12. Long-Term Investments and Other Assets

As at	December 31, 2019		December 31, 2018
Investments in publicly-traded entities	$	4.3	$	8.4
Loan to affiliate	45.0		45.0
Deferred lease receivable	17.4		24.4
Debt issuance costs associated with credit facilities	6.2		7.9
Refundable deposits	8.9		16.2
Prepayment on long-term service agreements	80.6		82.5
Cash calls from joint venture partners	9.5		—
Contract asset (note 24)	30.0		11.5
Rabbi trust (notes 28 and 31)	32.0		61.7
Other long-term receivables (note 29)	33.1		—
Other	29.5		25.5
	$	296.5	$	283.1

13. 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:

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 was 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 provide operating services to RILE LP.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 90

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 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.

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. With the 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's operating costs by AltaGas LPG in accordance with the terms set out in the agreement.

Disposal of Consolidated VIE Investments

Prior to the close of the U.S. distributed generation asset sale in the third quarter of 2019, a subsidiary of WGL was the primary beneficiary of SFGF LLC, SFRC LLC, SFGF II LLC, SFEE LLC, and ASD Solar LP, 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. These VIEs were consolidated until the close of the distributed generation asset sale (Note 4). As at December 31, 2019, these entities are no longer VIEs of AltaGas.

The following table represents amounts included in the Consolidated Balance Sheets attributable to AltaGas’ consolidated VIEs:

As at	December 31, 2019			December 31, 2018
Current assets	$	6.4		$	1,383.5
Property, plant and equipment	371.1			619.2
Long-term investments and other assets	53.3			48.0
Operating right-of-use assets	0.1			—
Current liabilities	(3.6		)	(161.8		)
Asset retirement obligations	(3.3		)	(0.9		)
Other long-term liabilities	(0.1		)	(3.0		)
Net assets	$	423.9		$	1,885.0

The decrease in current assets, property, plant and equipment, and current liabilities associated with AltaGas’ consolidated VIEs as at December 31, 2019 compared to December 31, 2018 is primarily due to the sale of Northwest Hydro Limited Partnership in January 2019 and the sale of VIEs included in the sale of WGL's distributed generation portfolio (Note 4).

Disposal of Unconsolidated VIE Investments

Prior to the sale of AltaGas' investment in Meade and indirect, non-operating interest in Central Penn (Note 4), WGL Midstream owned a 55 percent interest in Meade (21 percent indirect interest in Central Penn). Although WGL Midstream held a greater than 50 percent interest in Meade, Meade was not consolidated by WGL Midstream and instead was accounted for under the equity method of accounting. WGL Midstream was not the primary beneficiary of Meade as it did not have the power to direct the activities most significant to the economic performance of Meade. WGL Midstream applied the HLBV equity method of accounting and any profits and losses were included in "income from equity investments" in the accompanying Consolidated Statements of Income (Loss) and were added to or subtracted from the carrying amount of AltaGas' investment balance until the close of the Meade sale. As at December 31, 2019, Meade is no longer a VIE of AltaGas.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 91

14. 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	2019		2018		2019			2018
AltaGas Canada Inc. (ACI) (a)	Canada	37	$	163.9	$	112.5	$	17.0		$	5.4
AltaGas Idemitsu Joint Venture LP	Canada	50	431.3		342.9		62.5			2.1
Constitution Pipeline, LLC (Constitution) (b)	United States	10	0.1		—		(0.5		)	(0.2		)
Craven County Wood Energy LP (c)	United States	50	—		7.8		0.1			(14.1		)
Eaton Rapids Gas Storage System	United States	50	27.0		29.4		1.3			2.0
Grayling Generating Station LP (c)	United States	50	—		29.0		0.3			3.6
Inuvik Gas Ltd. (d)	Canada	33	—		—		—			(0.2		)
Meade Pipeline Co. LLC (c) (e)	United States	55	—		757.8		(3.6		)	12.2
Mountain Valley Pipeline, LLC (Mountain Valley) (f)	United States	10	671.3		532.5		42.8			11.5
Sarnia Airport Storage Pool LP	Canada	50	18.0		18.7		1.0			1.0
Petrogas Preferred Shares	Canada	n/a	150.0		150.0		12.8			12.8
Stonewall Gas Gathering Systems LLC (c)	United States	30	—		411.8		7.4			11.8
			$	1,461.6	$	2,392.4	$	141.1		$	47.9

(a) As at December 31, 2019, the aggregate market value of AltaGas' investment in ACI was $367.9 million (11,025,000 shares at the quoted closing market price of $33.37 on December 31, 2019). As at December 31, 2018, the aggregate market value was $178.8 million (11,025,000 shares at the quoted closing market price of $16.22 on December 31, 2018).

(b) The equity method is considered appropriate because Constitution is a Limited Liability Company (LLC) with specific ownership accounts and ownership between five and fifty percent, resulting in WGL Midstream exercising a more than minor influence over the investee's operating and financing policies. In February 2020, the partners of Constitution elected not to proceed with the pipeline project (Note 33).

(c) Disposed of in 2019 (Note 4).

(d) Inuvik Gas Ltd. was sold to AltaGas Canada Inc. in October 2018.

(e) Meade was a VIE prior to disposition in November 2019 (Notes 4 and 13).

(f) The equity method is considered appropriate because Mountain Valley is an LLC with specific ownership accounts and ownership between five and fifty percent, resulting in WGL Midstream exercising a more than minor influence over the investee's operating and financing policies.

The carrying amount of certain equity investments differs from the amount of the underlying equity in net assets. These basis differences include amounts related to purchase accounting adjustments, capitalized interest, and a contractual cap on contributions to Mountain Valley.

Summarized combined financial information, assuming a 100 percent ownership interest in AltaGas’ equity investments listed above, is as follows ^(a):

Year Ended December 31	2019			2018
Revenues	$	1,109.3		$	351.6
Expenses	(355.0		)	(142.7		)
	$	754.3		$	208.9
As at December 31	2019			2018
Current assets	$	411.1		$	1,204.6
Property, plant and equipment	$	8,033.8		$	7,602.5
Intangible assets	$	21.9		$	22.9
Long-term investments and other assets	$	1,458.8		$	1,326.6
Current liabilities	$	(393.8	)	$	(1,015.2	)
Other long-term liabilities	$	(992.1	)	$	(949.6	)

(a) For equity investments that were disposed of in the year (Note 4), revenues and expenses reflect the period prior to disposition and balance sheet amounts as at December 31 are $nil.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 92

Provisions on investments accounted for by the equity method

During the year ended December 31, 2019, AltaGas recorded a pre-tax provision of $44.2 million against AltaGas' investment in Meade Pipeline Co. LLC as a result of the sale of WGL Midstream's interest in Central Penn. The disposition of the investment in this entity was completed in the fourth quarter of 2019 (Note 4). This equity investment was in the Midstream segment and the provision was recorded in the Consolidated Statements of Income (Loss) under the line item "income from equity investments".

In addition, during the year ended December 31, 2019, AltaGas recorded a pre-tax provision of $2.2 million against AltaGas' investment in Craven County Wood Energy LP as a result of a pending sale. The disposition of the investment in this entity was completed in the third quarter of 2019 (Note 4). This equity investment was in the Power segment and the provision was recorded in the Consolidated Statements of Income (Loss) under the line item "income from equity investments".

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.

AltaGas Canada Inc.

On October 21, 2019, ACIannounced that the Public Sector Pension Investment Board and the Alberta Teachers' Retirement Fund Board (together, the "Consortium") and ACI had concluded a definitive arrangement agreement (the "Arrangement Agreement") whereby the Consortium will indirectly acquire all of the issued and outstanding common shares of ACI(the "Common Shares")in an all-cash transaction for $33.50 per Common Share by way of arrangement under the Canada Business Corporations Act (the "Arrangement"). On December 19, 2019, the shareholders of ACI approved the Arrangement Agreement. In addition, on December 16, 2019, ACI received a "no-action letter" from the Canadian Competition Bureau confirming that the Commissioner of Competition does not at this time intend to challenge the proposed Arrangement. On December 20, 2019, ACI received the final order from the Court of Queen's Bench of Alberta approving the Arrangement. On February 18, 2020, the Alberta Utilities Commission issued a decision approving the Arrangement. The closing of the Arrangement remains subject to the receipt of approval from the British Columbia Utilities Commission, and the satisfaction or waiver of other customary closing conditions. ACI and the Consortium expect to close the Arrangement in the first half of 2020.

15. Short-term Debt

As at	December 31, 2019		December 31, 2018
Bank indebtedness	$	—	$	0.2
Commercial paper (a)	389.0		1,145.2
Project financing	71.0		64.5
	$	460.0	$	1,209.9

(a) 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. As at December 31, 2019, certain commercial paper balances have been classified as long-term debt as they are supported by long-term extendible committed credit facilities with maturities ranging from 2022 to 2024 (see Note 16).

Project Financing

WGL and certain of its subsidiaries previously obtained third-party project financing on behalf of the United States federal government to provide funds for the construction of certain energy management services projects entered into under Washington Gas' area-wide contract. When theseprojects are formally accepted by the government and deemed complete, the ownership of the receivable is assigned to the third-party lender in satisfaction of the obligation, removing both the receivable and the

AltaGas Ltd. – 2019 MD&A and Financial Statements - 93

obligation related to the financing from the Consolidated Financial Statements. As at December 31, 2019, draws related to project financing were $71.0 million (December 31, 2018 - $64.5 million).

Other Credit Facilities

As at December 31, 2019, the Corporation held a $70.0 million (December 31, 2018 - $70.0 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, 2019 were $nil (December 31, 2018 - $nil).

As at December 31, 2019, AltaGas held a $150.0 million (December 31, 2018 - $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, 2019 were $25.5 million (December 31, 2018 - $117.0 million).

As at December 31, 2019, AltaGas held a US$200.0 million (December 31, 2018 - US$200.0 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, 2019 were $156.4 million (December 31, 2018 - $147.3 million).

As at December 31, 2019, AltaGas held a US$300.0 million (December 31, 2018 - US$300.0 million) 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, 2019 were $124.6 million (December 31, 2018 - $nil).

WGL and Washington Gas use short-term debt in the form of commercial paper and advances under its syndicated bank credit facilities 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. As at December 31, 2019, commercial paper outstanding classified as short-term debt totaled US$299.5 million (December 31, 2018 - US$839.5 million).

AltaGas Ltd. – 2019 MD&A and Financial Statements - 94

16. Long-Term Debt

As at	Maturity date	December 31, 2019			December 31, 2018
Credit facilities
$1,400 million unsecured extendible revolving facility (a)	15-May-2023	$	89.6		$	964.7
US$300 million unsecured extendible revolving facility (b)	15-May-2022	—			287.8
Acquisition credit facility (c)	6-Jan-2020	—			113.2
US$1,200 million unsecured revolving credit facility (d)	28-Dec-2021	—			1,637.0
US$300 million unsecured term facility	27-Feb-2021	389.6			—
US$150 million unsecured extendible revolving facility	20-Dec-2023	163.5			—
Commercial paper (e)	Various	367.4			—
AltaGas Ltd. medium-term notes (MTNs)
$200 million Senior unsecured - 4.55 percent	17-Jan-2019	—			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
$500 million Senior unsecured - 2.61 percent	16-Dec-2022	500.0			—
$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	300.0			299.9
$350 million Senior unsecured - 4.12 percent	7-Apr-2026	349.9			349.8
$200 million Senior unsecured - 3.98 percent	4-Oct-2027	199.9			199.9
$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
$250 million Senior unsecured - 4.99 percent	4-Oct-2047	250.0			250.0
WGL and Washington Gas MTNs
US$450 million Senior unsecured - 2.25 to 4.76 percent (f)	Nov 2019	—			682.1
US$250 million Senior unsecured - 2.44 percent (g)	12-Mar-2020	324.7			341.1
US$20 million Senior unsecured - 6.65 percent	20-Mar-2023	26.0			27.3
US$40.5 million Senior unsecured - 5.44 percent	11-Aug-2025	52.6			55.3
US$53 million Senior unsecured - 6.62 to 6.82 percent	Oct - 2026	68.8			72.3
US$72 million Senior unsecured - 6.40 to 6.57 percent	Feb - Sep 2027	93.5			98.2
US$52 million Senior unsecured - 6.57 to 6.85 percent	Jan - Mar 2028	67.5			70.9
US$8.5 million Senior unsecured - 7.50 percent	1-Apr-2030	11.0			11.6
US$50 million Senior unsecured - 5.70 to 5.78 percent	Jan - Mar 2036	64.9			68.2
US$75 million Senior unsecured - 5.21 percent	3-Dec-2040	97.4			102.3
US$75 million Senior unsecured - 5.00 percent	15-Dec-2043	97.4			102.3
US$300 million Senior unsecured - 4.22 to 4.60 percent	Sep - Dec 2044	389.6			409.3
US$450 million Senior unsecured - 3.80 percent	15-Sep-2046	584.5			613.9
US$300 million Senior unsecured - 3.65 percent	16-Sep-2049	389.6			—
SEMCO long-term debt
US$300 million SEMCO Senior Secured - 5.15 percent (h)	21-Apr-2020	389.6			409.3
US$82 million SEMCO Senior Secured - 4.48 percent (i)	2-Mar-2032	76.1			86.3
Fair value adjustment on WGL Acquisition (note 3)		84.3			89.0
Finance lease liabilities (note 10)		9.9			0.8
		$	6,887.1		$	8,992.3
Less debt issuance costs		(36.4		)	(35.2		)
		$	6,850.7		$	8,957.1
Less current portion		(922.9		)	(890.2		)
		$	5,927.8		$	8,066.9

(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) The acquisition facility was repaid in full and canceled on February 1, 2019.

(d) Borrowings on the facility can be by way of U.S. base-rate loans, U.S. prime loans, or LIBOR loans.

(e) Commercial paper is supported by the availability of long-term committed credit facilities with maturity dates ranging from 2022 to 2024.

(f) Certain MTNs have a floating rate per annum reset quarterly based on terms set forth in the prospectus supplement filed by WGL pursuant to Securities Act Rule 424 on November 27, 2017.

(g) Floating rate per annum reset quarterly based on terms set forth in the prospectus filed by WGL pursuant to Securities Act Rule 424 on March 13, 2018.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 95

(h) Collateral for the U.S. dollar MTNs is certain SEMCO assets.

(i) 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.

Other Credit Facilities

As at December 31, 2019, WGL held a US$250.0 million (December 31, 2018 - 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, 2019 or December 31, 2018.

As at December 31, 2019, Washington Gas held a US$450.0 million (December 31, 2018 - US$350.0 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, 2019 or December 31, 2018.

WGL and Washington Gas use short-term debt in the form of commercial paper and advances under its syndicated bank credit facilities 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. As at December 31, 2019, outstanding commercial paper classified as long-term debt totaled US$283.5 million (December 31, 2018 - $nil).

17. Asset Retirement Obligations

As at December 31	2019			2018
Balance, beginning of year	$	500.6		$	88.3
Obligations acquired (note 3)	—			399.1
New obligations	7.0			3.3
Obligations settled	(2.5		)	(4.2		)
Disposals	(6.2		)	(1.6		)
Revision in estimated cash flow	(128.5		)	3.8
Accretion expense (a)	18.9			12.3
Foreign exchange translation	(20.7		)	20.3
Reclassified to liabilities associated with assets held for sale (note 5)	(0.2		)	(10.8		)
Total	$	368.4		$	510.5
Less current portion (included in accounts payable and accrued liabilities)	(6.4		)	(9.9		)
Balance, end of year	$	362.0		$	500.6

(a) Certain amounts relating to Utility asset retirement obligations are recorded through regulatory assets or liabilities on the Consolidated Balance Sheets due to regulatory treatment. The remaining portion is recorded through the Consolidated Statements of Income (Loss).

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, 2019 was $727.0 million (December 31, 2018 - $770.0 million).

The asset retirement obligations have been recorded in the Consolidated Financial Statements at estimated values discounted at rates between 2.0 and 8.5 percent (December 31, 2018 - between 1.5 to 8.5 percent) and are expected to be incurred between 2020 and 2137 (December 31, 2018 - between 2019 and 2064). No assets have been legally restricted for settlement of the estimated liability.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 96

18. 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.

As at December 31, 2019, a liability of $13.8 million has been recorded on an undiscounted basis related to future environmental response costs (December 31, 2018 - $15.4 million) 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. As at December 31, 2019, AltaGas estimated the maximum liability associated with all of its sites to be approximately $39.9 million (December 31, 2018 - $40.1 million). 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.

As at December 31, 2019, AltaGas reported a regulatory asset of $17.7 million (December 31, 2018 - $19.9 million) for the portion of environmental response costs that are expected to be recoverable in future rates (Note 21).

19. Other Long-term Liabilities

As at	December 31, 2019		December 31, 2018
Deferred lease payable	$	—	$	13.1
Deferred revenue	4.0		3.9
Customer advances for construction	63.9		58.6
Sundance B PPAs termination expense (a)	—		2.0
Lease inducement	—		2.7
Merger commitments	14.0		21.4
Other long-term liabilities	19.9		20.3
	$	101.8	$	122.0

(a) In 2016, AltaGas Pipeline Partnership and the Government of Alberta reached a definitive settlement agreement regarding the termination of the Sundance B Power Purchase Arrangements (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”.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 97

20. Income Taxes

Year Ended December 31	2019			2018
Income (loss) before income taxes - consolidated	$	812.7		$	(716.9	)
Statutory income tax rate (%)	26.5			27.0
Expected taxes at statutory rates	$	215.4		$	(193.6	)
Add (deduct) the tax effect of:
Permanent differences	$	10.9		$	(1.0	)
Statutory and other rate differences	(51.6		)	(19.6		)
Rate adjustment for change in tax rates	(10.7		)	1.3
Deferred income tax recovery on regulated assets	(24.8		)	(7.3		)
Tax differences on divestitures and transactions	(158.2		)	(32.3		)
Non-controlling interests	3.5			4.7
Change in valuation allowance	(11.1		)	(22.3		)
Other	(1.0		)	6.9
	$	(27.6	)	$	(263.2	)
Income tax provision
Current
Canada	$	26.7		$	23.7
United States	36.6			0.7
	$	63.3		$	24.4
Deferred
Canada	$	11.6		$	(166.1	)
United States	(102.5		)	(121.5		)
	$	(90.9	)	$	(287.6	)
Effective income tax rate (%)	(3.4		)	36.7

Net deferred income tax liabilities were composed of the following:

As at	December 31, 2019			December 31, 2018
PP&E and intangible assets	$	1,450.6		$	1,764.6
Regulatory assets	(204.1		)	(166.3		)
Tax pools, deferred financing, and compensation	(138.2		)	(453.6		)
Other	(161.2		)	(209.9		)
Valuation allowance	12.0			23.1
	$	959.1		$	957.9

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 Alberta government passed the Job Creation Tax Cut in 2019 which reduced Alberta's corporate tax rate from 12 percent to 11 percent on July 1, 2019. The tax rate will further be reduced from 11 percent to 10 percent on January 1, 2020 and by 1 percent each year until 2022. The rate from 2022 onwards will ultimately be 8 percent.

The B.C. government increased the corporate tax rate to 12 percent from 11 percent beginning in 2018.

As at December 31, 2019, the Corporation had tax-effected non-capital losses of approximately $170.4 million, which will be available to offset future taxable income. If not used, these losses will expire between 2024 and 2039.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 98

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 2018 remain subject to examination by taxation authorities. In the United States, both the federal and state tax returns filed for the years 2013 to 2018 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	2019			2018
Balance, beginning of year	$	2.2		$	5.9
Net changes during the year	(0.2		)	(3.7		)
Balance, end of year	$	2.0		$	2.2

21. 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 Statements of Income (Loss) by a non-rate-regulated entity. These deferred regulatory assets and liabilities are included in the Consolidated Statements of Income (Loss) 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 Statements of Income (Loss) 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 at December 31, 2019 and 2018, over which the Corporation expects to realize or settle the assets or liabilities:

AltaGas Ltd. – 2019 MD&A and Financial Statements - 99

As at December 31	2019		2018		Recovery Period
Regulatory assets - current
Deferred cost of gas (a)	$	7.6	$	20.4	Less than one year
Accelerated replacement recovery mechanisms (b)	2.5		—		Less than one year
Interruptible sharing (a)	2.7		0.6		Less than one year
	$	12.8	$	21.0
Regulatory assets - non-current
Deferred regulatory costs (a) (c)	$	149.5	$	215.5	1 - 51 years
Future recovery of pension and other retirement benefits (a)	128.2		192.9		Various
Future recovery of non-retirement employee benefits (a) (d)	19.4		21.3		Various
Deferred pension costs (e)	—		7.8		—
Deferred environmental costs (a) (f)	17.7		19.9		Various
Deferred loss on debt transactions and derivative instruments (a) (g)	99.2		109.3		Various
Deferred future income taxes (a) (h)	42.7		67.0		Various
Energy efficiency program - Maryland (i)	12.1		4.6		Various
Other	17.9		24.7		Various
	$	486.7	$	663.0
Regulatory liabilities - current
Deferred cost of gas (a)	$	60.2	$	71.2	Less than one year
Refundable tax credit (j)	1.9		3.8		Less than one year
Federal income tax rate change (k)	33.1		26.2		Less than one year
Virginia rate refund (l)	40.4		—		Less than one year
Accelerated replacement recovery mechanisms (b)	0.4		5.2		Less than one year
Interruptible sharing (a)	0.4		2.3		Less than one year
Other	9.1		6.2		Less than one year
	$	145.5	$	114.9
Regulatory liabilities - non-current
Refundable tax credit (j)	3.9		6.1		2 years
Future expense of pension and other retirement benefits (a)	261.2		166.7		Various
Future removal and site restoration costs (m)	483.9		514.7		Various
Deferred gain on debt transactions and derivative instruments (a) (g)	1.6		1.8		Various
Federal income tax rate change (k)	628.3		698.4		Various
Other	4.3		5.1		Various
	$	1,383.2	$	1,392.8

(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) Represents amounts for deferred over or under collections of surcharges associated with Washington Gas' accelerated pipeline recovery programs in the District of Columbia, Maryland, and Virginia.

(c) Includes deferred gas costs and fair value of derivatives, which are not included in customer bills until settled.

(d) 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.

(e) In 2018, this balance related to previously deferred pension and other post-retirement benefits expenses that were fully amortized in 2019.

(f) This balance represents allowed environmental remediation expenditures at SEMCO Gas and Washington Gas sites to be recovered through rates.

(g) 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. As at December 31, 2019, this also includes a fair value adjustment of $79.8 million (December 31, 2018 - $87.3 million) recorded on the WGL Acquisition (Note 3).

(h) This balance reflects the amount of deferred income taxes expected to be refunded, or recovered from, customers in future rates.

(i) Represents amounts for deferred credits associated with Washington Gas' participation in the energy conservation and efficiency program EmPower in Maryland.

(j) 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.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 100

(k) The Tax Cuts and Jobs Act (TCJA) was enacted on December 22, 2017, and required the Corporation to revalue its U.S. deferred tax assets and liabilities in 2018 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.

(l) Represents estimated refunds related to customers billed at a higher rate during the interim period as part of the 2019 Virginia rate case.

(m) 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.

22. 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, 2019	$	—		$	(19.0	)	$	(209.2	)	$	801.4		$	5.8		$	579.0
OCI before reclassification	—			15.2			68.2			(406.2		)	(0.7		)	(323.5		)
Amounts reclassified from OCI	—			1.1			—			—			—			1.1
Current period OCI (pre-tax)	—			16.3			68.2			(406.2		)	(0.7		)	(322.4		)
Income tax on amounts retained in AOCI	—			(3.2		)	(8.2		)	—			—			(11.4		)
Income tax on amounts reclassified to earnings	—			(0.3		)	—			—			—			(0.3		)
Net current period OCI	—			12.8			60.0			(406.2		)	(0.7		)	(334.1		)
Ending balance, December 31, 2019	$	—		$	(6.2	)	$	(149.2	)	$	395.2		$	5.1		$	244.9
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 AOCI	—			0.7			—			—			—			0.7
Adoption of ASU No. 2016-01	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

Reclassification From Accumulated Other Comprehensive Income

AOCI components reclassified	Income statement line item	Year Ended December 31, 2019			Year Ended December 31, 2018
Defined benefit pension and PRB plans	Other income	$	1.1		$	0.7
Deferred income taxes	Income tax expense – deferred	(0.3		)	(0.2		)
		$	0.8		$	0.5

23. 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.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 101

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 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.

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.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 102

As at	December 31, 2019
	Carrying Amount		Level 1		Level 2		Level 3		Total Fair Value
Financial assets
Fair value through net income (a)
Risk management assets - current	$	81.4	$	—	$	30.4	$	51.0	$	81.4
Risk management assets - non-current	30.9		—		6.7		24.2		30.9
Equity securities (b)	4.3		4.3		—		—		4.3
Fair value through regulatory assets (a)
Risk management assets - current	5.2		—		—		5.2		5.2
Risk management assets - non-current	8.2		—		0.4		7.8		8.2
Amortized cost
Loans and receivables (b)	45.0		—		46.1		—		46.1
	$	175.0	$	4.3	$	83.6	$	88.2	$	176.1
Financial liabilities
Fair value through net income (a)
Risk management liabilities - current	$	120.6	$	—	$	98.7	$	21.9	$	120.6
Risk management liabilities - non-current	77.0		—		19.2		57.8		77.0
Fair value through regulatory liabilities (a)
Risk management liabilities - current	4.2		—		0.6		3.6		4.2
Risk management liabilities - non-current	90.0		—		—		90.0		90.0
Amortized cost
Current portion of long-term debt	922.9		—		922.9		—		922.9
Long-term debt	5,927.8		—		6,263.8		—		6,263.8
Other current liabilities (c)	15.4		—		15.4		—		15.4
	$	7,157.9	$	—	$	7,320.6	$	173.3	$	7,493.9

(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.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 103

As at	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 (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 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		—		8,040.3		—		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	$	—	$	8,997.5	$	242.7	$	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.

The following table includes quantitative information about the significant unobservable inputs used in the fair value measurement of Level 3 financial instruments as at December 31, 2019:

	Net Fair Value			Valuation Technique	Unobservable Inputs	Range
Natural gas	$	(83.8	)	Discounted Cash Flow	Natural Gas Basis Price (per dekatherm)	$	(1.18	)	-	$	3.27
Natural gas	$	(1.4	)	Option Model	Natural Gas Basis Price (per dekatherm)	$	(1.19	)	-	$	3.30
					Annualized Volatility of Spot Market Natural Gas	29		%	-	906		%
Electricity	$	0.1		Discounted Cash Flow	Electricity Congestion Price (per megawatt hour)	$	(6.73	)	-	$	65.26

AltaGas Ltd. – 2019 MD&A and Financial Statements - 104

The following tables provide 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	2019									2018
	Natural Gas			Electricity			Total			Natural Gas			Electricity			Total
Balance, beginning of year	$	(148.5	)	$	(14.7	)	$	(163.2	)	$	—		$	—		$	—
Acquired (note 3)	—			—			—			(136.1		)	(10.6		)	(146.7		)
Realized and unrealized gains (losses):
Recorded in income	47.6			1.4			49.0			(8.3		)	(6.5		)	(14.8		)
Recorded in regulatory assets	23.6			—			23.6			(5.9		)	—			(5.9		)
Transfers into Level 3	(9.0		)	—			(9.0		)	—			—			—
Transfers out of Level 3	12.3			—			12.3			7.3			—			7.3
Purchases	—			(11.4		)	(11.4		)	—			6.4			6.4
Settlements	(17.1		)	24.4			7.3			0.3			(3.4		)	(3.1		)
Foreign exchange translation	5.9			0.4			6.3			(5.8		)	(0.6		)	(6.4		)
Balance, end of year	$	(85.2	)	$	0.1		$	(85.1	)	$	(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 period. Transfers out of Level 3 during the year ended December 31, 2019 were due to an increase in valuations using observable market inputs. Transfers into Level 3 during the year ended December 31, 2019 were due to an increase in unobservable market inputs used in valuations.

Realized and Unrealized Gains (Losses) Recorded to Income for Level 3 Measurements

Year Ended December 31	2019			2018
Recorded to revenue	$	75.2		$	(11.1	)
Recorded to cost of sales	(26.2		)	(3.7		)
	$	49.0		$	(14.8	)

Summary of Unrealized Gains (Losses) on Risk Management Contracts Recognized in Net Income (Loss)

Year Ended December 31	2019			2018
Natural gas	$	22.5		$	(2.2	)
Energy exports	(86.7		)	—
NGL frac spread	(17.4		)	40.0
Power	(4.9		)	9.3
Foreign exchange	1.2			33.7
	$	(85.3	)	$	80.8

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.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 105

As at	December 31, 2019
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	$	121.2	$	(53.7	)	$	—		$	67.5
Energy exports	9.7		(2.7		)	4.4			11.4
NGL frac spread	0.3		(0.2		)	—			0.1
Power	53.5		(6.8		)	—			46.7
	$	184.7	$	(63.4	)	$	4.4		$	125.7
Risk management liabilities (b)
Natural gas	$	226.1	$	(53.7	)	$	(27.7	)	$	144.7
Energy exports	89.5		(2.7		)	—			86.8
NGL frac spread	1.7		(0.2		)	—			1.5
Power	68.7		(6.8		)	(3.1		)	58.8
	$	386.0	$	(63.4	)	$	(30.8	)	$	291.8

(a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $86.6 million and risk management assets (non‑current) balance of $39.1 million.

(b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $124.8 million and risk management liabilities (non‑current) balance of $167.0 million.

As at	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.

Cash Collateral

The following table presents collateral not offset against risk management assets and liabilities:

As at	December 31, 2019		December 31, 2018
Collateral posted with counterparties	$	29.1	$	27.6
Cash collateral held representing an obligation	$	0.3	$	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.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 106

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, 2019, AltaGas has posted$5.5 million (December 31, 2018 - $nil)of 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 specific credit-risk-related contingent features underlying these agreements were triggered:

As at	December 31, 2019		December 31, 2018
Risk management liabilities with credit-risk-contingent features	$	42.2	$	14.7
Maximum potential collateral requirements	$	29.0	$	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 2033. 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, 2019 and 2018:

December 31, 2019	Fixed price (per GJ)	Period (months)	Notional volume (GJ)	Fair Value
Sales	1.32 to 6.81	1-166	698,126,985	$	28.9
Purchases	0.22 to 6.81	1-167	1,406,991,689	$	(104.4	)
Swaps	0.22 to 10.24	1-51	541,652,374	$	(1.7	)
December 31, 2018	Fixed price (per GJ)	Period (months)	Notional volume (GJ)	Fair Value
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

AltaGas Ltd. – 2019 MD&A and Financial Statements - 107

Energy Exports

AltaGas entered into a series of swaps to lock in a portion of the volumes exposed to the propane price differential between North American Indices and the Far East Index for contracts not under tolling arrangements at RIPET. AltaGas had the following contracts outstanding as at December 31, 2019:

December 31, 2019	Fixed price (per Bbl)	Period (months)	Notional volume (Bbl)	Fair Value
Propane	21.49 to 29.71	1-27	9,374,826	$	(75.4	)

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, 2019 and 2018:

December 31, 2019	Fixed price	Period (months)	Notional volume		Fair Value
Butane swaps	73.02 to 75.15/Bbl	1-12	346,852	Bbl	$	(0.5	)
Crude oil swaps	73.02 to 75.15/Bbl	1-12	212,587	Bbl	$	(0.9	)
Natural gas swaps	1.58 to 1.86/GJ	1-12	3,883,992	GJ	$	—
December 31, 2018	Fixed price	Period (months)	Notional volume		Fair Value
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	)

Power

AltaGas sells power to the Alberta Electric System Operator at market 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 2024. As at December 31, 2019, 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, 2019 and 2018:

December 31, 2019	Fixed price (per MWh)	Period (months)	Notional volume (MWh)	Fair Value
Power sales	31.63 to 66.76	1-42	8,034,024	$	39.0
Power purchases	31.63 to 66.76	1-60	8,552,467	$	(27.3	)
Swap purchases	(7.88) to 74.26	1-48	25,058,577	$	(23.8	)
December 31, 2018	Fixed price (per MWh)	Period (months)	Notional volume (MWh)	Fair Value
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	)

AltaGas Ltd. – 2019 MD&A and Financial Statements - 108

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, 2019:

Factor	Increase or decrease to forward prices	Increase or decrease to income before tax ($ millions)
Alberta power price	$1/MWh	2.3
PJM power price	US$1/MWh	1.9
AECO natural gas price	$0.50/GJ	1.1
NYMEX natural gas price	US$0.50/GJ	2.6
Energy Exports:
Propane Far East Index to Mont Belvieu spread	$1/Bbl	3.4
Baltic LPG Freight	$1/Bbl	6.1
NGL frac spread:
Western Texas Intermediate (WTI) crude oil	$1/Bbl	0.6
Natural gas	$0.50/GJ	1.9

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, 2019 and December 31, 2018, AltaGas did not have any outstanding foreign exchange forward contracts.

AltaGas may designate its U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. As at December 31, 2019, AltaGas has designated US$300.0 million of outstanding debt as a net investment hedge (December 31, 2018 - US$1,494.0 million). For the year ended December 31, 2019,AltaGas incurred after-tax unrealized gains of $60.0 million arising from the translation of debt in OCI (2018 ‑ after-tax unrealized loss of $80.2 million).

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, 2019, approximately 76 percent of AltaGas’ total outstanding short-term and long-term debt was at fixed rates (December 31, 2018 - 59 percent). 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, 2019.

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

AltaGas Ltd. – 2019 MD&A and Financial Statements - 109

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, 2019, 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 year ended December 31, 2019, a pre-tax loss of $1.9 million was recorded related to these instruments (2018 - pre-tax loss of $1.0 million).

Accounts Receivable Past Due or Impaired

AltaGas had the following past due or impaired accounts receivable (AR):

As at December 31, 2019	Total			AR accruals		Receivables impaired			Less than 30 days		31 to 60 days		61 to 90 days		Over 90 days
Trade receivable	$	1,238.2		$	343.5	$	33.2		$	757.9	$	61.2	$	11.6	$	30.8
Other	17.4			—		—			17.3		—		—		0.1
Allowance for credit losses	(33.2		)	—		(33.2		)	—		—		—		—
	$	1,222.4		$	343.5	$	—		$	775.2	$	61.2	$	11.6	$	30.9

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

Allowance for credit losses	December 31, 2019			December 31, 2018
Balance, beginning of year	$	54.7		$	2.4
Foreign exchange translation	(2.6		)	0.1
New allowance (a)	27.5			53.1
Change in allowance (b)	(9.2		)	(0.9		)
Allowance applied to uncollectible customer accounts	(37.2		)	—
Balance, end of year	$	33.2		$	54.7

(a) Upon close of the WGL Acquisition in 2018, AltaGas acquired WGL’s allowance for credit losses of approximately $52.9 million.

(b) Includes removal of allowance related to asset disposals of approximately $8.1 million in 2019.

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 Ltd. – 2019 MD&A and Financial Statements - 110

AltaGas had the following contractual maturities with respect to financial liabilities:

	Contractual maturities by period
As at December 31, 2019	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Accounts payable and accrued liabilities	$	1,324.9	$	1,324.9	$	—	$	—	$	—
Dividends payable	22.3		22.3		—		—		—
Short-term debt	460.0		460.0		—		—		—
Other current liabilities (a)	15.4		15.4		—		—		—
Risk management contract liabilities	291.8		124.8		34.1		13.2		119.7
Current portion of long-term debt (b)	920.4		920.4		—		—		—
Long-term debt (b)	5,872.5		—		1,489.2		921.3		3,462.0
	$	8,907.3	$	2,867.8	$	1,523.3	$	934.5	$	3,581.7

(a) Excludes non-financial liabilities.

(b) Excludes deferred financing costs, discounts, finance lease liabilities, and the fair value adjustment on the WGL Acquisition.

	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, discounts, finance lease liabilities, and the fair value adjustment on the WGL Acquisition.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 111

24. Revenue

The following tables disaggregate revenue by major sources for the year:

	Year Ended December 31, 2019
	Utilities			Midstream		Power		Corporate		Total
Revenue from contracts with customers
Commodity sales contracts	$	—		$	1,093.7	$	1,131.4	$	—	$	2,225.1
Midstream service contracts	—			145.0		—		—		145.0
Gas sales and transportation services	2,501.4			—		—		—		2,501.4
Storage services	28.1			—		—		—		28.1
Other	9.2			2.7		29.0		—		40.9
Total revenue from contracts with customers	$	2,538.7		$	1,241.4	$	1,160.4	$	—	$	4,940.5
Other sources of revenue
Revenue from alternative revenue programs (a)	$	29.5		$	—	$	—	$	—	$	29.5
Leasing revenue (b)	0.9			136.6		105.1		—		242.6
Risk management and trading activities (c) (d)	—			196.2		65.9		0.2		262.3
Other	(4.9		)	0.1		24.9		—		20.1
Total revenue from other sources	$	25.5		$	332.9	$	195.9	$	0.2	$	554.5
Total revenue	$	2,564.2		$	1,574.3	$	1,356.3	$	0.2	$	5,495.0

(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 for the year ended December 31, 2019 of $504.5 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract, which are in scope of ASC 606, are reported within 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 GAIL contract has a term of 20 years and began on March 31, 2018.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 112

	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. 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 for the year ended December 31, 2018 of $264.2 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract, which are in scope of ASC 606, are reported within 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 GAIL 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 segment and by major source of revenue from contracts with customers.

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

AltaGas Ltd. – 2019 MD&A and Financial Statements - 113

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 contracts at the RIPET generate revenue from the sale and delivery of liquid propane purchased from upstream producers. Revenue from these sales contracts is recognized when propane is loaded onto transport vessels, which is the delivery point. AltaGas has the right to consideration in an amount that directly corresponds to the volumes of propane loaded on a vessel.

Commodity sales also include gas sales to residential, commercial, and industrial customers in certain jurisdictions 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 Corporation 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.

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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 approximately 20 years. These long-term purchase agreements provide stable cash flow by way of contracted prices for the underlying commodities. During 2019, AltaGas closed the sale of its U.S. portfolio of distributed generation assets, which included wholly owned solar and fuel cell projects and tax equity partnership interests (Note 4). Subsequent to the sale, AltaGas will continue to generate energy from its combined heating and power assets.

Commodity sales also include electricity sales to residential, commercial, and industrial customers in certain jurisdictions 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 Corporation is entitled to invoice the customer.

Contract Balances

As at December 31, 2019, a contract asset of $30.0 million has been recorded within long-term investments and other assetson the Consolidated Balance Sheets (December 31, 2018 – $11.5 million). 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, 2019 there is a contract asset of $58.6 million (December 31, 2018 - $47.3 million) recorded within prepaid expenses and other current assets 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. At December 31, 2019, contract liabilities of $1.7 million (December 31, 2018 - $2.2 million) have been recorded within accounts payable and accrued 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.

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Contract Assets

As at	December 31, 2019			December 31, 2018
Balance, beginning of year	$	58.8		$	—
Additions	32.3			130.1
Transfers to held for sale (a)	—			(72.2		)
Transfers to accounts receivable (b)	—			(3.7		)
Foreign exchange translation	(2.5		)	4.6
Balance, end of year	$	88.6		$	58.8

(a) In the fourth quarter of 2018, WGL Energy Systems reached an agreement for the sale of a financing receivable included in the contract asset balance. Accordingly, the receivable was classified as held for sale at December 31, 2018. In February 2019, WGL Energy Systems completed the sale of the financing receivable (Note 4).

(b) Amounts included in contract assets are transferred to accounts receivable when AltaGas’ right to consideration becomes unconditional.

Contract Liabilities

As at	December 31, 2019			December 31, 2018
Balance, beginning of year	$	2.2		$	—
Additions	1.9			2.6
Revenue recognized from contract liabilities (a)	(2.2		)	(0.5		)
Foreign exchange translation	(0.2		)	0.1
Balance, end of year	$	1.7		$	2.2

(a) Recognition of revenue related to performance obligations satisfied in the current period for amounts that were previously included in contract liabilities.

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, 2019:

	2020		2021		2022		2023		2024		2025 & beyond		Total
Midstream service contracts	$	113.1	$	89.8	$	88.9	$	86.5	$	86.4	$	971.9	$	1,436.6
Storage services	24.2		24.2		23.5		23.2		23.2		168.4		286.7
Other	19.4		8.9		2.0		2.0		2.0		12.0		46.3
	$	156.7	$	122.9	$	114.4	$	111.7	$	111.6	$	1,152.3	$	1,769.6

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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25. Shareholders’ Equity

Authorization

AltaGas is authorized to issue an unlimited number of voting common shares. AltaGas is also authorized to issue such number of Preferred Shares 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.

Dividend Reinvestment and Optional Cash Purchase Plan (DRIP or the Plan)

The Plan consists oftwocomponents:a Dividend Reinvestment component and an Optional Cash Purchase component. The Premium Dividend™ component of the plan was suspended in December 2018. The Dividend Reinvestment and Optional Cash Purchase component was suspended in December 2019, with the December dividend (payable January 2020) being the last dividend payment eligible for reinvestment by participating shareholders under the DRIP. The Plan in its entirety will remain suspended until further notice.

The Plan provided eligible holders of common shares with the opportunity to, at their election, reinvest the cash dividends paid by AltaGas on their common shares towards the purchase of new common shares at a3 percentdiscount 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).

In addition, the Plan provided 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 was 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 the10 business daysimmediately 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 (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, 2018	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 cost	—	13.3
Shares issued under DRIP	15,377,575	325.8
December 31, 2018	275,224,066	$	6,653.9
Shares issued for cash on exercise of options	76,177	1.2
Deferred taxes on share issuance cost	—	(3.9		)
Shares issued under DRIP	3,774,442	67.8
Issued and outstanding at December 31, 2019	279,074,685	$	6,719.0

AltaGas Ltd. – 2019 MD&A and Financial Statements - 117

Preferred Shares

As at	December 31, 2019				December 31, 2018
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	6,885,823	172.1			8,000,000	200.0
Series H	1,114,177	27.9			—	—
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		(28.5		)		(27.9		)
Fair value adjustment on WGL Acquisition (note 3)		—				4.1
	52,000,000	$	1,277.1		52,280,600	$	1,318.8

On December 20, 2019, all outstanding Washington Gas preferred shares (US$4.25 series, US$4.80 series, and US$5.00 series) were redeemed. A gain of $3.5 million was recognized upon redemption.

.

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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)
Series A (e)	3.380	%	$0.84500	$25	September 30, 2020	Series B
Series B (f) (g)	Floating		Floating	$25	September 30, 2020	Series A
Series C (h)	5.290	%	US$1.32250	US$25	September 30, 2022	Series D
Series E (e)	5.393	%	$1.34825	$25	December 31, 2023	Series F
Series G (e)	4.620	%	$1.15575	$25	September 30, 2024	Series H
Series H (f) (g)	Floating		Floating	$25	September 30, 2024	Series G
Series I (i)	5.250	%	$1.31250	$25	December 31, 2020	Series J
Series K (j)	5.000	%	$1.25000	$25	March 31, 2022	Series L

(a) This table only includes those series of preferred shares that are currently issued and outstanding. The Corporation is authorized to issue up to8,000,000of each of Series D Shares, Series F Shares, and Series J Shares, and up to12,000,000of 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 J Shares, and Series L Shares are also redeemable for$25.50, and Series D Shares are redeemable forUS$25.50on 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 and Series H 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 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 of Series A Shares, Series E Shares, and Series G Shares 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 plus2.66 percent(Series A Shares),3.17 percent(Series E Shares), and3.06 percent(Series G Shares).

(f) Holders of Series B Shares and Series H 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 plus2.66 percent(Series B Shares) and3.06 percent(Series H Shares). 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, 2019, the floating quarterly dividend rate is$0.26803per share for Series B Shares and$0.29289per share for Series H Shares for the period starting December 31, 2019 to, but excluding, March 31, 2020.

(g) Series B Shares can be redeemed for$25.50per 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. Series H Shares can be redeemed for$25.50per share on any date after September 30, 2019 that is not a Series H 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 plus3.58 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 plus4.19 percent, provided that, in any event, such rate shall not be less than5.25 percentper 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 plus3.80 percent, provided that, in any event, such rate shall not be less than5.00 percentper annum.

Share Option Plan

AltaGas has an employee share option plan under which officers, employees, and service providers (as defined by the TSX) are eligible to receive grants. As at December 31, 2019, 13,915,160 shares were reserved for issuance under the plan. As at December 31, 2019, share 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, 2019, the unexpensed fair value of share option compensation cost associated with future periods was$4.5 million (December 31, 2018 ‑ $3.7 million).

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The following table summarizes information about the Corporation’s share options:

	December 31, 2019				December 31, 2018
As at	Options outstanding				Options outstanding
	Number of options		Exercise price (a)		Number of options		Exercise price (a)
Share options outstanding, beginning of year	6,309,183		$	25.18	4,533,761		$	32.35
Granted	2,287,385		19.12		2,811,460		16.69
Exercised	(76,177	)	14.52		(57,275	)	20.68
Forfeited	(1,165,435	)	27.31		(878,013	)	36.47
Expired	(311,000	)	36.16		(100,750	)	14.60
Share options outstanding, end of year	7,043,956		$	22.49	6,309,183		$	25.18
Share options exercisable, end of year	2,921,642		$	27.70	2,897,723		$	32.01

(a) Weighted average.

As at December 31, 2019, the aggregate intrinsic value of the total share options exercisable was $3.3 million (December 31, 2018 - $nil), the total intrinsic value of share options outstanding was $12.1 million (December 31, 2018 - $nil) and the total intrinsic value of share options exercised was $0.4 million (December 31, 2018 - $0.3 million).

The following table summarizes the employee share option plan as at December 31, 2019:

	Options outstanding				Options exercisable
	Number outstanding	Weighted average exercise price		Weighted average remaining contractual life	Number exercisable	Weighted average exercise price		Weighted average remaining contractual life
$14.52 to $18.00	2,557,328	$	15.19	4.98	638,385	$	14.62	4.79
$18.01 to $25.08	1,961,805	19.78		4.77	305,750	21.05		0.96
$25.09 to $46.70	2,524,823	32.00		2.72	1,977,507	32.95		2.39
	7,043,956	$	22.49	4.11	2,921,642	$	27.70	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	2019	2018
Fair value per options ($)	2.30	1.27
Risk-free interest rate (%)	1.48	1.99
Expected life (years)	6	6
Expected volatility (%)	24.84	23.23
Annual dividend per share ($) (a)	0.96	1.18
Forfeiture rate (%)	—	—

(a) Annual dividend per share is calculated based on a weighted average share price and forward dividend yields as the grant dates.

Phantom Unit Plan (Phantom Plan) and Deferred Share Unit Plan (DSUP)

AltaGas has a Phantom Plan for employees and executive officers, which includes restricted units (RUs) and performance units (PUs) with vesting periods of 36 months from the grant date. In addition, AltaGas has a DSUP, which allows granting of deferred share units (DSUs) to directors. DSUs granted under the DSUP vest immediately but settlement of the DSUs occur when the individual ceases to be a director.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 120

PUs, RUs, and DSUs (number of units)	2019		2018
Balance, beginning of year	9,908,154		564,549
Acquired (a)	—		5,291,621
Converted to cash (a)	—		(5,291,621	)
Granted	674,971		9,502,347
Exercised	(113,668	)	—
Vested and paid out	(677,667	)	(148,154	)
Forfeited	(3,377,962	)	(66,522	)
Units in lieu of dividends	71,003		55,934
Outstanding, end of year	6,484,831		9,908,154

(a) Upon close of the WGL Acquisition in 2018, AltaGas acquired WGL’s PUs. These were converted to a fixed cash amount at a value of US$1.00 per unit. At December 31, 2019, the WGL PUs comprised approximately 4.9 million of the outstanding units (December 31, 2018 - 8.9 million).

For the year ended December 31, 2019, the compensation expense recorded for the Phantom Plan and DSUP was $21.7 million (2018 – $16.6 million). As at December 31, 2019, the unrecognized compensation expense relating to the remaining vesting period for the Phantom Plan was $21.8 million (December 31, 2018 ‑ $26.9 million) and is expected to be recognized over the vesting period.

26. Net Income (Loss) Per Common Share

The following table summarizes the computation of net income (loss) per common share:

	Year Ended December 31
	2019			2018
Numerator:
Net income (loss) applicable to controlling interests	$	833.5		$	(435.1	)
Less: Preferred share dividends	(68.5		)	(66.6		)
Gain on redemption of preferred shares (note 25)	3.5			—
Net income (loss) applicable to common shares	$	768.5		$	(501.7	)
Denominator:
(millions)
Weighted average number of common shares outstanding	276.9			222.6
Dilutive equity instruments (a)	0.5			—
Weighted average number of common shares outstanding - diluted	277.4			222.6
Basic net income (loss) per common share	$	2.78		$	(2.25	)
Diluted net income (loss) per common share	$	2.77		$	(2.25	)

(a) Includes all options that have a strike price lower than the average share price of AltaGas' common shares during the periods noted.

For the year ended December 31, 2019, 4.3 million share options (2018 – 4.0 million) were excluded from the diluted net income (loss) per share calculation as their effects were anti‑dilutive.

27. Other Income

Year Ended December 31	2019			2018
Gains (losses) from sale of assets	$	875.8		$	(10.6	)
Other components of net benefit cost (note 28)	27.4			18.9
Interest income and other revenue	9.0			2.7
Losses on investments	(4.1		)	(10.1		)
	$	908.1		$	0.9

AltaGas Ltd. – 2019 MD&A and Financial Statements - 121

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. The pension cost recorded for the DC plan was$19.8 million for the year ended December 31, 2019 (2018 - $15.4 million).

Defined Benefit Plans

AltaGas has several defined benefit pension plans for unionized and non-unionized employees, including one in Canada (which is comprised of five divisions) and sixin the United States. The plans in the United States include a qualified, trusteed, non-contributory defined benefit pension plan, and a non-funded defined benefit restoration plan maintained by Washington Gas.

The defined benefit plans are partially funded except for two of the divisions in Canada which are fully funded and one of the plans in the United States which is not 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 will be filed with the pension regulators in 2020. Actuarial valuations for funding purposes are required annually for AltaGas’ U.S. defined benefit plans.

Supplemental Executive Retirement Plans (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 or from the Rabbi Trusts funded as part of the WGL acquisition. Security will be provided for the SERP benefits through a letter of credit within a retirement compensation arrangement trust account.

Several executive officers of Washington Gas participate in a separate non-funded defined benefit SERP (a non-qualified pension plan). This defined benefit SERP was closed to new entrants beginning January 1, 2010.

Post-Retirement Benefit Plans

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 an annual allocation to a Healthcare Spending Account (HSA). This benefit plan is not funded.

Post-retirement benefit plans in the United States provide certain medical, prescription drug, dental, and life insurance 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. For eligible Washington Gas retirees and dependents not yet receiving Medicare benefits, Washington Gas provides medical, prescription drug, and dental benefits through Preferred Provider Organization (PPO) or Health Maintenance Organization (HMO) plans, through the Washington Gas Light Company Retiree Medical Plan. For Medicare-eligible retirees age 65 and older and their dependents, eligible retirees and dependents participate in a tax-free Health Reimbursement

AltaGas Ltd. – 2019 MD&A and Financial Statements - 122

Account (HRA) Plan. The HRA plan provides an annual subsidy to help purchase supplemental medical, prescription drug and dental coverage in the marketplace. One of these benefit plans is partially funded and three of them are fully funded.

Rabbi Trusts

Rabbi trusts of $57.4 million as at December 31, 2019 have been funded to satisfy the employee benefit obligations associated with WGL’s various pension plans (December 31, 2018 - $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:

Year Ended December 31, 2019	Canada						United States						Total
	Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits
Projected benefit obligation (a)
Balance, beginning of year	$	34.3		$	1.9		$	1,635.3		$	458.0		$	1,669.6		$	459.9
Actuarial loss (gain)	2.1			0.2			182.0			(14.8		)	184.1			(14.6		)
Current service cost	2.6			—			23.8			8.5			26.4			8.5
Member contributions	—			—			—			2.2			—			2.2
Interest cost	1.2			0.1			67.8			19.1			69.0			19.2
Benefits paid	(4.0		)	(0.1		)	(77.3		)	(24.4		)	(81.3		)	(24.5		)
Expenses paid	(0.1		)	—			(0.6		)	(0.1		)	(0.7		)	(0.1		)
Settlements	—			—			(24.7		)	—			(24.7		)	—
Plan amendments	—			—			0.3			—			0.3			—
Other	—			—			—			1.0			—			1.0
Foreign exchange translation	—			—			(82.0		)	(21.8		)	(82.0		)	(21.8		)
Balance, end of year	$	36.1		$	2.1		$	1,724.6		$	427.7		$	1,760.7		$	429.8
Plan assets
Fair value, beginning of year	$	13.8		$	—		$	1,354.1		$	791.2		$	1,367.9		$	791.2
Actual return on plan assets	0.9			—			284.2			177.4			285.1			177.4
Employer contributions	4.3			0.1			38.7			0.1			43.0			0.2
Member contributions	—			—			—			2.2			—			2.2
Benefits paid	(4.0		)	(0.1		)	(77.3		)	(23.7		)	(81.3		)	(23.8		)
Expenses paid	(0.1		)	—			(0.6		)	(0.1		)	(0.7		)	(0.1		)
Settlements	—			—			(25.7		)	—			(25.7		)	—
Other	—			—			—			0.1			—			0.1
Foreign exchange translation	—			—			(69.5		)	(41.3		)	(69.5		)	(41.3		)
Fair value, end of year	$	14.9		$	—		$	1,503.9		$	905.9		$	1,518.8		$	905.9
Funded status	$	(21.2	)	$	(2.1	)	$	(220.7	)	$	478.2		$	(241.9	)	$	476.1

(a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 123

Year Ended December 31, 2018	Canada						United States						Total
	Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits
Projected benefit obligation (a)
Balance, beginning of year	$	165.6		$	15.8		$	303.8		$	82.7		$	469.4		$	98.5
Plans disposed	(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	(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
Funded status	$	(20.5	)	$	(1.9	)	$	(281.2	)	$	333.2		$	(301.7	)	$	331.3

(a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation.

The following amounts were included in the Consolidated Balance Sheets:

	December 31, 2019									December 31, 2018
	Defined Benefit			Post- Retirement Benefits			Total			Defined Benefit			Post- Retirement Benefits			Total (a)
Prepaid post-retirement benefits	$	—		$	486.8		$	486.8		$	—		$	341.4		$	341.4
Accounts payable and accrued liabilities	(25.7		)	—			(25.7		)	(27.6		)	—			(27.6		)
Future employee obligations	(216.2		)	(10.7		)	(226.9		)	(274.1		)	(10.1		)	(284.2		)
	$	(241.9	)	$	476.1		$	234.2		$	(301.7	)	$	331.3		$	29.6

(a) Account balances on the Consolidated Balance Sheets also include certain non-pension related amounts.

The accumulated benefit obligation for all defined benefit plans were:

As at	December 31, 2019				December 31, 2018
	Canada		United States		Canada		United States
Accumulated benefit obligation (a)	$	34.7	$	1,616.4	$	32.9	$	1,525.6

(a) Accumulated benefit obligation differs from projected benefit obligation in that it does not include an assumption with respect to future compensation levels.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 124

The following amounts were recorded in other comprehensive income (loss) and have not yet been recognized in net periodic benefit cost:

Year Ended December 31, 2019	Canada						United States						Total
	Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits
Past service credit (cost)	$	(0.2	)	$	0.3		$	0.1		$	—		$	(0.1	)	$	0.3
Net actuarial gain (loss)	(9.4		)	(0.7		)	(14.9		)	18.2			(24.3		)	17.5
Recognized in AOCI pre-tax	$	(9.6	)	$	(0.4	)	$	(14.8	)	$	18.2		$	(24.4	)	$	17.8
Increase (decrease) by the amount included in deferred tax liabilities	2.3			0.1			7.0			(9.0		)	9.3			(8.9		)
Net amount in AOCI after-tax	$	(7.3	)	$	(0.3	)	$	(7.8	)	$	9.2		$	(15.1	)	$	8.9

Year Ended December 31, 2018	Canada						United States						Total
	Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits
Past service credit (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	)

The following amounts were recorded in a regulatory asset (liability) and have not yet been recognized in net periodic benefit cost:

Year Ended December 31, 2019	Canada				United States					Total
	Defined Benefit		Post- Retirement Benefits		Defined Benefit		Post- Retirement Benefits			Defined Benefit		Post- Retirement Benefits
Past service cost (credit)	$	—	$	—	$	1.1	$	(105.4	)	$	1.1	$	(105.4	)
Net actuarial loss (gain)	—		—		127.1		(155.8		)	127.1		(155.8		)
Recognized in regulatory asset (liability)	$	—	$	—	$	128.2	$	(261.2	)	$	128.2	$	(261.2	)

Year Ended December 31, 2018	Canada				United States					Total
	Defined Benefit		Post- Retirement Benefits		Defined Benefit		Post- Retirement Benefits			Defined Benefit		Post- Retirement Benefits
Past service cost (credit)	$	—	$	—	$	0.8	$	(110.2	)	$	0.8	$	(110.2	)
Net actuarial loss (gain)	—		—		188.2		(52.6		)	188.2		(52.6		)
Recognized in regulatory asset (liability)	$	—	$	—	$	189.0	$	(162.8	)	$	189.0	$	(162.8	)

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.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 125

Amounts to be amortized in the next fiscal year from AOCI	Defined Benefit		Post-Retirement Benefits
Past service cost (credit)	$	0.2	$	(0.7	)
Actuarial loss	4.0		0.3
Total	$	4.2	$	(0.4	)

Amounts to be amortized in the next fiscal year from regulatory assets (liabilities)	Defined Benefit			Post-Retirement Benefits
Past service credit (cost)	$	(0.2	)	$	16.7
Actuarial gain (loss)	(17.1		)	0.5
Total	$	(17.3	)	$	17.2

The net pension expense by plan was as follows:

	Year Ended December 31, 2019
	Canada					United States						Total
	Defined Benefit			Post-Retirement Benefits		Defined Benefit			Post-Retirement Benefits			Defined Benefit			Post-Retirement Benefits
Current service cost (a)	$	2.6		$	—	$	23.8		$	8.5		$	26.4		$	8.5
Interest cost (b)	1.2			0.1		67.8			19.1			69.0			19.2
Expected return on plan assets (b)	(0.5		)	—		(74.6		)	(37.1		)	(75.1		)	(37.1		)
Amortization of past service cost (credit) (b)	0.1			—		0.4			(21.9		)	0.5			(21.9		)
Amortization of net actuarial loss (b)	0.9			—		11.7			0.1			12.6			0.1
Plan settlements (b)	—			—		4.1			—			4.1			—
Other (b)	—			—		—			0.9			—			0.9
Net benefit cost (income) recognized	$	4.3		$	0.1	$	33.2		$	(30.4	)	$	37.5		$	(30.3	)

(a) Recorded under the line item “operating and administrative” expenses on the Consolidated Statements of Income (Loss).

(b) Recorded under the line item “other income” on the Consolidated Statements of Income (Loss).

	Year Ended December 31, 2018
	Canada					United States						Total
	Defined Benefit			Post-Retirement Benefits		Defined Benefit			Post-Retirement Benefits			Defined Benefit			Post-Retirement 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 (credit) (b)	0.1			—		0.1			(11.5		)	0.2			(11.5		)
Amortization of net actuarial loss (b)	0.6			—		7.7			0.4			8.3			0.4
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 (Loss).

(b) Recorded under the line item “other income” on the Consolidated Statements of Income (Loss).

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

AltaGas Ltd. – 2019 MD&A and Financial Statements - 126

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's target asset mix for the Canadian plans is 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 50 percent to 60 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, 2019:

Canada	Fair value		Level 1		Level 2		Percentage of Plan Assets (%)
Cash and short-term equivalents	$	1.9	$	1.9	$	—	12.8
Canadian equities	4.1		4.1		—		27.5
Foreign equities	2.4		2.4		—		16.0
Fixed income	5.7		5.7		—		38.3
Real estate	0.8		—		0.8		5.4
	$	14.9	$	14.1	$	0.8	100.0

United States	Fair value			Level 1		Level 2			Percentage of Plan Assets (%)
Cash and short-term equivalents	$	10.8		$	10.8	$	—		0.4
Canadian equities	2.6			2.6		—			0.1
Foreign equities (a)	302.5			302.2		0.3			12.6
Fixed income	933.0			123.2		809.8			38.7
Derivatives	(0.2		)	—		(0.2		)	—
Other (b)	12.0			—		12.0			0.5
Total investments in the fair value hierarchy	$	1,260.7		$	438.8	$	821.9		52.3
Investments measured at net asset value using the NAV practical expedient (c)
Commingled funds (d)	$	648.9							26.9
Private equity/limited partnership (e)	55.6								2.3
Pooled separate accounts (f)	32.0								1.3
Collective trust fund (g)	433.8								18.1
Total fair value of plan investments	$	2,431.0							100.9
Net payable (h)	(21.2		)						(0.9	)
	$	2,409.8							100.0

(a) Investments in foreign equities include U.S. and international securities.

(b) As at December 31, 2019, these investments consisted primarily of non-U.S. government bonds.

(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 at December 31, 2019, investments in commingled funds consisted of approximately 58 percent common stock of large-cap U.S. companies, 18 percent U.S. Government fixed income securities, and 24 percent corporate bonds for WGL’s post-retirement benefit plans.

(e) As at December 31, 2019, investments in a private equity/limited partnership consisted of common stock of international companies.

(f) As at December 31, 2019, investments in pooled separate accounts consisted of income producing properties located in the United States.

(g) As at December 31, 2019, investments in collective trust funds consisted primarily of 90 percent common stock of U.S, companies, 8 percent income producing properties located in the United States, and 2 percent short-term money market investments.

(h) As at December 31, 2019, this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 127

Total	Fair value			Level 1		Level 2			Percentage of Plan Assets (%)
Cash and short-term equivalents	$	12.7		$	12.7	$	—		0.5
Canadian equities	6.7			6.7		—			0.3
Foreign equities (a)	304.9			304.6		0.3			12.6
Fixed income	938.7			128.9		809.8			38.7
Derivatives	(0.2		)	—		(0.2		)	—
Real estate	0.8			—		0.8			—
Other (b)	12.0			—		12.0			0.5
Total investments in the fair value hierarchy	$	1,275.6		$	452.9	$	822.7		52.6
Investments measured at net asset value using the NAV practical expedient (c)
Commingled funds(d)	$	648.9							26.8
Private equity/limited partnership (e)	55.6								2.3
Pooled separate accounts (f)	32.0								1.3
Collective trust fund (g)	433.8								17.9
Total fair value of plan investments	$	2,445.9							100.9
Net payable (h)	(21.2		)						(0.9	)
	$	2,424.7							100.0

(a) Investments in foreign equities include U.S. and international securities.

(b) As at December 31, 2019, these investments consisted primarily of non-U.S. government bonds.

(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 at December 31, 2019, investments in commingled funds consisted of approximately 58 percent common stock of large-cap U.S. companies, 18 percent U.S. Government fixed income securities, and 24 percent corporate bonds for WGL’s post-retirement benefit plans.

(e) As at December 31, 2019, investments in a private equity/limited partnership consisted of common stock of international companies.

(f) As at December 31, 2019, investments in pooled separate accounts consisted of income producing properties located in the United States.

(g) As at December 31, 2019, investments in collective trust funds consisted primarily of 90 percent common stock of U.S, companies, 8 percent income producing properties located in the United States, and 2 percent short-term money market investments.

(h) As at December 31, 2019, this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable.

Year Ended December 31	2019		2018
Significant actuarial assumptions used in measuring net benefit plan costs	Defined Benefit	Post-Retirement Benefits	Defined Benefit	Post-Retirement Benefits
Discount rate (%)	2.90 - 4.40	3.90 - 4.50	3.25 - 4.30	3.60 - 4.30
Expected long-term rate of return on plan assets (%) (a)	5.75 - 7.15	4.66 - 7.15	3.20 - 7.60	3.75 - 7.60
Rate of compensation increase (%)	2.75 - 4.10	4.10	2.75 - 4.10	4.10
Average remaining service life of active employees (years)	9.0	13.2	9.6	14.1

(a) Only applicable for funded plans

As at December 31	2019		2018
Significant actuarial assumptions used in measuring benefit obligations	Defined Benefit	Post-Retirement Benefits	Defined Benefit	Post-Retirement Benefits
Discount rate (%)	2.90 - 3.50	3.10 - 3.60	3.60 - 4.40	3.90 - 4.50
Rate of compensation increase (%)	2.75 - 4.00	3.50	2.75 - 4.10	4.10

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.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 128

The discount rate is based on yields available 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 rate used to measure the expected cost of benefits for the next year was 6.3 percent. The health care cost trend rates were assumed to decline to between 2.0 and 4.5 percent by 2027.

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 2019:

	Increase		Decrease
Service and interest costs	$	1.9	$	(1.5	)
Accrued benefit obligation	$	22.7	$	(18.4	)

The following table shows the expected cash flows for defined benefit pension and other post-retirement plans:

	Defined Benefit		Post-Retirement Benefits
Expected employer contributions:
2020	$	37.0	$	3.2
Expected benefit payments:
2020	$	104.6	$	23.8
2021	$	85.1	$	22.6
2022	$	93.3	$	22.5
2023	$	90.0	$	22.3
2024	$	90.7	$	22.1
2025 - 2028	$	474.1	$	112.6

AltaGas Ltd. – 2019 MD&A and Financial Statements - 129

29. Commitments, Guarantees, and Contingencies

Commitments

AltaGas has long-term natural gas purchase and transportation arrangements, propane purchase agreements, electricity purchase arrangements, service agreements, pipeline and storage contracts, capital commitments, environmental commitments, merger 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.

Future payments of these commitments as at December 31, 2019 are estimated as follows:

	2020		2021		2022		2023		2024		2025 & beyond		Total
Gas purchase (a)	$	2,374.0	$	2,488.2	$	2,323.6	$	2,076.1	$	1,959.5	$	22,772.0	$	33,993.4
Propane purchase (b)	220.2		127.2		94.9		86.5		58.4		127.1		714.3
Electricity purchase (c)	567.2		318.1		160.0		56.4		11.0		0.4		1,113.1
Service agreements (d) (e) (f)	58.7		44.0		28.2		23.4		22.9		309.1		486.3
Pipeline and storage services (g)	721.2		652.5		627.8		600.4		550.5		3,876.7		7,029.1
Capital projects (h)	6.9		—		—		—		—		—		6.9
Operating leases (i)	27.8		27.1		26.5		24.5		20.1		100.1		226.1
Environmental (j)	6.5		4.3		1.0		1.0		0.6		0.4		13.8
Merger commitments (k)	8.2		3.8		1.9		1.9		1.9		4.3		22.0
	$	3,990.7	$	3,665.2	$	3,263.9	$	2,870.2	$	2,624.9	$	27,190.1	$	43,605.0

(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) AltaGas enters into contracts to purchase propane for its operations at RIPET. These contracts are used to ensure that there is an adequate supply of propane to meet shipment commitments and to minimize exposure to market price fluctuations. Propane purchase commitments are valued based on forward prices, which may fluctuate significantly from period to period.

(c) AltaGas enters into contracts to purchase electricity from various suppliers for its non-utility business. Electricity purchase commitments are based on existing fixed price and fixed volume contracts, and include US$17.4 million of commitments related to renewable energy credits.

(d) In 2014, AltaGas' Blythe facility entered into a Long-Term Service Agreement (LTSA) with Siemens to complete various upgrade and maintenance services on the Combustion Turbines (CT) at the Blythe facility over 124,000 equivalent operating hours per CT, or 25 years, whichever comes first. The LTSA has variable fees on a per equivalent operating hour basis. As at December 31, 2019, the total commitment was $167.9 million payable over the next 16 years, of which $45.4 million is expected to be paid over the next five years.

(e) In 2017, AltaGas entered into a 12-year service agreement for tug services to support the marine operations of RIPET.

(f) In 2015, AltaGas entered into a Project Agreement that contemplated the sublease of lands from Ridley Terminals Inc. (RTI), provision of certain terminal services, and access to RTI's terminal facilities to support RIPET's operations for an initial term of 20 years ending in 2039. In 2019, RILE LP and RTI executed a Terminal Services Agreement that formalized the concepts outlined in the Project Agreement.

(g) Pipeline and storage commitments include minimum payments for natural gas transportation, storage and peaking contracts that have expiration dates through 2044.

(h) Commitments for capital projects. Estimated amounts are subject to variability depending on the actual construction costs.

(i) Operating leases include lease arrangements for office spaces, vehicles, rail cars, land, and office and other equipment.

(j) Environmental commitments include committed payments related to certain environmental response costs.

(k) Represents the estimated future payments of merger commitments that have been accrued but not paid. In addition, there are certain additional merger commitments that will be expensed when costs are incurred in the future, including the investment of up toUS$70 millionover atenyear period to further extend natural gas service, investment ofUS$8 millionfor leak mitigation withinthreeyears of the merger, hiring damage prevention trainers in each jurisdiction for a total ofUS$2 millionoverfiveyears, and developing15megawatts of either electric grid energy storage or Tier 1 renewable resources within five years. As at December 31, 2019, the cumulative amount of merger commitments that have been expensed but not yet paid is approximatelyUS$17 million.

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, 2019, AltaGas has no guarantees to external parties.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 130

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.

Antero Contract

In June 2019, a jury trial was held in the County Court for Denver, Colorado to consider a contractual dispute relating to gas pricing between Washington Gas and WGL Midstream (together, the Companies) and Antero Resources Corporation (Antero). Following the trial, the jury returned a verdict in favor of Antero for approximately US$96 million, of which approximately US$11 million was against Washington Gas with the remainder against WGL Midstream. Following the official entry of the judgment, the Companies filed an appeal on August 16, 2019.

AltaGas recorded a net reduction to the acquired working capital of WGL of approximately US$45 million to account for the verdict in favor of Antero net of tax and other expected recoveries. Expected recoveries include a $33.1 million receivable recorded in "Long-term investments and other assets" on the Consolidated Balance Sheets for amounts expected to be recovered under a commercial arrangement with a third party.

Silver Spring, Maryland Incident

On April 23, 2019, the National Transportation and Safety Board (NTSB) held a hearing during which it found, among other things, that the probable cause of the August 10, 2016, explosion and fire at an apartment complex on Arliss Street in Silver Spring, Maryland “was the failure of an indoor mercury service regulator with an unconnected vent line that allowed natural gas into the meter room where it accumulated and ignited from an unknown ignition source. Contributing to the accident was the location of the mercury service regulators where leak detection by odor was not readily available.” Washington Gas disagrees with the NTSB’s probable cause findings. Following this hearing, on June 10, 2019, the NTSB issued an accident report.

A total of 37 civil actions related to the incident were filed against WGL and Washington Gas in the Circuit Court for Montgomery County, Maryland. All of these suits sought unspecified damages for personal injury and/or property damage. All personal injury and property damage claims asserted by residents at the Flower Branch Apartments have been settled and paid. Washington Gas has been reimbursed by its insurers for the amounts paid in the settlements.

In connection with the incident, on September 5, 2019, the PSC of MD ordered Washington Gas, within 30 days, to (i) provide a detailed response to the NTSB’s probable cause findings and (ii) provide evidence regarding the status of a 2003 mercury regulator replacement program and, if the program was not completed, to show cause why the PSC of MD should not impose a civil penalty on Washington Gas. On November 18, 2019, the Technical Staff of the PSC of MD, the MD Office of People’s Counsel (OPC), Montgomery County, MD and the Apartment and Office Building Association of Metropolitan Washington (AOBA) filed written comments on Washington Gas' response to the Show-Cause Order. Technical Staff commented that the PSC of MD may impose a civil penalty but did not expressly recommend same. Montgomery County, MD, OPC and AOBA requested that the PSC of MD impose a civil penalty on Washington Gas. On December 17, 2019, the PSC of MD held a public hearing near the apartment complex at Arliss Street, at which some residents requested that Washington Gas accelerate and complete its mercury service regulator program and that Washington Gas absorb the cost of same. Washington Gas intends to file comments with the PSC of MD responding to all written comments and resident testimony. Management believes that the likelihood of a civil penalty is probable and has accrued US$0.3 million to reflect the minimum liability expected to result from the proceeding. Though Washington Gas is unable to estimate the maximum possible penalty, other parties recommended penalties ranging from US$32 million (AOBA, which argued that Washington Gas should absorb all costs of removal and relocation of mercury service regulators) to

AltaGas Ltd. – 2019 MD&A and Financial Statements - 131

US$123.3 million (OPC, which argued that Washington Gas should absorb all costs of removal and relocation of mercury service regulators and pay a fine of US$25,000 per day for each day mercury service regulators remain on Washington Gas’ system).

AltaGas Ltd. – 2019 MD&A and Financial Statements - 132

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, 2019		December 31, 2018
Due from related parties
Accounts receivable (a)	$	17.8	$	60.8
Long-term investments and other assets (b)	45.0		45.0
	$	62.8	$	105.8
Due to related parties
Accounts payable (c)	$	2.7	$	6.3
Risk management liabilities - current (d)	—		0.9
	$	2.7	$	7.2

(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, 2019, Petrogas had drawn $45.0 million (December 31, 2018 - $45.0 million) under the facility.

(c) Payables to joint venture.

(d) Foreign exchange hedge with ACI.

The following transactions with related parties have been recorded on the Consolidated Statements of Income (Loss) for the years ended December 31, 2019 and 2018:

Year Ended December 31	2019			2018
Revenue (a)	$	114.9		$	68.4
Cost of sales (b)	$	12.8		$	4.2
Operating and administrative recoveries (c)	$	(1.8	)	$	(1.3	)
Other income (d)	$	3.2		$	9.2

(a) In the ordinary course of business, AltaGas sold natural gas and natural gas liquids to a joint venture and ACI. For the year ended December 31, 2018, revenue also includes an unrealized loss on a foreign exchange hedge with ACI of $0.2 million.

(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 addition, subsequent to the initial public offering (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.

(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 2018. Loans to ACI were fully repaid by December 31, 2018.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 133

31. Supplemental Cash Flow Information

The following table details the changes in operating assets and liabilities from operating activities:

	Year Ended December 31
	2019			2018
Source (use) of cash:
Accounts receivable	$	168.4		$	(526.9	)
Inventory	(2.1		)	(100.8		)
Other current assets	(85.5		)	12.5
Regulatory assets - current	7.1			(15.8		)
Accounts payable and accrued liabilities	(280.2		)	237.9
Customer deposits	(16.9		)	(13.3		)
Regulatory liabilities - current	34.2			69.2
Risk management liabilities - current	1.1			—
Other current liabilities	(5.6		)	(5.9		)
Other operating assets and liabilities	(52.0		)	(143.4		)
Changes in operating assets and liabilities	$	(231.5	)	$	(486.5	)

The following cash payments have been included in the determination of earnings:

	Year Ended December 31
	2019		2018
Interest paid (net of capitalized interest)	$	351.7	$	288.9
Income taxes paid	$	67.2	$	36.9

The following table is a reconciliation of cash and restricted cash balances:

As at December 31	2019		2018
Cash and cash equivalents	$	57.1	$	101.6
Restricted cash holdings from customers - current	4.0		4.1
Restricted cash holdings from customers - non-current	3.9		6.1
Restricted cash included in prepaid expenses and other current assets (a)	25.4		27.6
Restricted cash included in long-term investments and other assets (a)	32.0		61.7
Cash, cash equivalents, and restricted cash per Consolidated Statements of Cash Flows	$	122.4	$	201.1

(a) The restricted cash balances included in prepaid expenses and other current assets and long-term investments and other assets relate to Rabbi trusts associated with WGL’s pension plans (seeNote 28).

AltaGas Ltd. – 2019 MD&A and Financial Statements - 134

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	nrate-regulated natural gas distribution assets in Michigan, Alaska, the District of Columbia, Maryland, and Virginia; nrate-regulated natural gas storage in the United States; and nequity investment in AltaGas Canada Inc.
Midstream	nNGL processing and extraction plants; ntransmission pipelines to transport natural gas and NGL; nnatural gas gathering lines and field processing facilities; npurchase and sale of natural gas; nnatural gas storage facilities; nliquefied petroleum gas (LPG) terminal; nnatural gas and NGL marketing; nequity investment in Petrogas, a North American entity engaged in the marketing, storage and distribution of NGL, drilling fluids, crude oil and condensate diluents; ninterest in a regulated pipeline in the Marcellus/Utica gas formation; and nsale of natural gas to residential, commercial and industrial customers in Washington D.C., Maryland, Virginia, Delaware, and Pennsylvania.
Power	nnatural gas-fired and distributed generation assets, certain of which are pending sale, whereby outputs are generally sold under power purchase agreements, both operational and under development; nenergy storage; and nsale of power to residential, commercial, and industrial users in Washington D.C., Maryland, Virginia, Delaware, Pennsylvania, and Ohio.
Corporate	nthe 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 24:

	Year Ended December 31, 2019
	Utilities		Midstream		Power		Corporate		Total
External revenue (note 24)	$	2,564.2	$	1,574.3	$	1,356.3	$	0.2	$	5,495.0
Intersegment revenue	26.6		6.9		10.9		—		$	44.4
Segment revenue	$	2,590.8	$	1,581.2	$	1,367.2	$	0.2	$	5,539.4

	Year Ended December 31, 2018
	Utilities		Midstream		Power		Corporate			Total
External revenue (note 24)	$	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

AltaGas Ltd. – 2019 MD&A and Financial Statements - 135

Geographic Information

Year Ended December 31	2019		2018
Revenue (a)
Canada	$	1,244.8	$	1,626.8
United States	4,325.5		2,553.0
TOTAL	$	5,570.3	$	4,179.8

(a) Operating revenue from external customers, excluding unrealized gains (losses) or risk management contracts.

As at December 31	2019		2018
Property, plant and equipment
Canada	$	2,682.2	$	2,348.2
United States	7,443.3		8,581.4
TOTAL	$	10,125.5	$	10,929.6

The following tables show the composition by segment:

	Year Ended December 31, 2019
	Utilities			Midstream			Power			Corporate			Intersegment Elimination (a)			Total
Segment revenue	$	2,590.8		$	1,581.2		$	1,367.2		$	0.2		$	(44.4	)	$	5,495.0
Cost of sales	(1,117.9		)	(1,057.7		)	(1,084.4		)	—			32.9			(3,227.1		)
Operating and administrative	(860.7		)	(249.1		)	(159.8		)	(40.6		)	11.5			(1,298.7		)
Accretion expenses	(0.1		)	(3.9		)	(1.1		)	—			—			(5.1		)
Depreciation and amortization	(261.6		)	(92.1		)	(72.3		)	(12.0		)	—			(438.0		)
Provisions on assets (note 6)	—			(35.2		)	(380.6		)	—			—			(415.8		)
Income from equity investments	18.3			122.4			0.4			—			—			141.1
Other income (loss)	27.0			28.7			853.8			(1.4		)	—			908.1
Foreign exchange gains (losses)	—			(4.5		)	—			3.5			—			(1.0		)
Interest expense	—			—			—			(345.8		)	—			(345.8		)
Income (loss) before income taxes	$	395.8		$	289.8		$	523.2		$	(396.1	)	$	—		$	812.7
Net additions (reductions) to:
Property, plant and equipment(b)	$	839.6		$	350.3		$	(2,281.3	)	$	1.2		$	—		$	(1,090.2	)
Intangible assets	$	22.6		$	4.9		$	—		$	9.0		$	—		$	36.5

(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 Statements of Cash Flows due to classification of business acquisition and foreign exchange changes on U.S. assets.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 136

	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		)
Provision on assets (note 6)	(193.7		)	(153.7		)	(381.3		)	—			—			(728.7		)
Income (loss) 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 (losses)	—			(0.2		)	(0.1		)	4.8			—			4.5
Interest expense	(103.9		)	(10.6		)	(8.9		)	(185.6		)	—			(309.0		)
Income (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 Statements of Cash Flows 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, 2019
Goodwill	$	3,573.0	$	246.5	$	122.6	$	—	$	3,942.1
Segmented assets	$	13,097.1	$	5,471.4	$	1,019.9	$206.1		$	19,794.5
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

33. Subsequent Events

Subsequent events have been reviewed through February 27, 2020, the date on which these audited Consolidated Financial Statements were issued.

Segment Change

During the first quarter of 2020, AltaGas began evaluating the structure of its business following asset sales that were completed as part of its 2019 asset monetization program. As a result of these changes, AltaGas has refocused on its core Utilities and Midstream segments and will no longer have a Power segment beginning in the first quarter of 2020. Consistent with Management’s strategic view of the business and the basis on which it assesses performance and allocates resources, beginning in 2020, segmented financial information will be presented under the Utilities, Midstream, and Corporate/Other segments. The retail energy marketing operations for natural gas and electricity, which were previously included in the Midstream and Power segments, respectively, will be included within the Utilities segment, and other remaining Power assets will be included in within Corporate/Other.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 137

Petrogas Put Option

On January 2, 2020, AltaGas advised that AltaGas Idemitsu Joint Venture Limited Partnership (AIJVLP) has received notice (the Put Notice) from SAM Holdings Ltd. (SAM) of its exercise of a put option (the Put Option) with respect to SAM's approximately one-third interest in Petrogas Energy Corp. (Petrogas). AIJVLP, a limited partnership owned 50 percent by AltaGas and 50 percent by Idemitsu Kosan Co., Ltd. (Idemitsu), owns the other approximately two-thirds of the outstanding common shares of Petrogas. Pursuant to the Petrogas unanimous shareholders agreement, a valid exercise of the Put Option by SAM after October 1, 2019, triggers a requirement for AIJVLP to purchase SAM's approximately one-third interest in Petrogas at the fair market value thereof, as determined by third-party valuators. AltaGas anticipates funding its portion of any such obligation with internal cash flow, the sale of remaining non-core assets and debt.

Constitution Pipeline

In February 2020, following evaluations of the diminished underlying economics for the proposed Constitution pipeline project, the partners ofConstitution Pipeline Company, LLC elected not to proceed with the project. AltaGas held a 10 percent equity interest in Constitution.Upon the acquisition of WGL, AltaGas assigned a value of $nil to Constitution.

SUPPLEMENTAL QUARTERLY OPERATING INFORMATION

	Q4-19		Q3-19		Q2-19		Q1-19		Q4-18
OPERATING HIGHLIGHTS
UTILITIES
Natural gas deliveries - end use (Bcf) (1)	52.2		11.1		20.7		75.4		53.3
Natural gas deliveries - transportation (Bcf) (1)	38.3		23.3		25.2		47.6		52.0
Service sites (thousands) (2)	1,653		1,647		1,648		1,647		1,643
Degree day variance from normal - SEMCO Gas (%) (3)	4.3		(47.2	)	14.5		5.7		7.5
Degree day variance from normal - ENSTAR (%) (3)	(20.6	)	(42.8	)	(16.1	)	(9.4	)	(19.6	)
Degree day variance from normal - Washington Gas (%) (3) (4)	(3.2	)	—		(44.5	)	(1.1	)	0.4
MIDSTREAM
Total inlet gas processed (Mmcf/d) (5)	1,413		1,307		1,417		1,481		1,413
Extraction volumes (Bbls/d) (5) (6)	60,305		65,831		56,990		62,332		64,522
Frac spread - realized ($/Bbl) (5) (7)	16.54		17.12		19.50		16.84		15.84
Frac spread - average spot price ($/Bbl) (5) (8)	8.29		9.17		15.27		11.79		21.00
RIPET export volumes (Bbls/d) (9)	36,394		36,225		31,711		—		—
Propane Far East Index to Mont Belvieu spread (US$/Bbl) (10)	17.95		12.00		14.27		—		—
Natural gas optimization inventory (Bcf)	41.4		35.7		31.9		13.2		35.9
WGL retail energy marketing - gas sales volumes (Mmcf)	20,131		6,476		9,360		27,411		20,750
POWER
Renewable power sold (GWh)	10		136		150		141		233
Conventional power sold (GWh)	478		672		361		263		985
Renewable capacity factor (%)	11.4		21.7		22.3		12.2		14.6
Contracted conventional availability factor (%) (11)	92.9		98.9		66.7		43.2		97.4
WGL retail energy marketing - electricity sales volumes (GWh)	3,291		3,723		3,125		3,080		2,911

(1) Bcf is one billion cubic feet.

(2) Service sites reflect all of the service sites of the utilities, including transportation and non‑regulated business lines.

(3) A degree day 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 that 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 Washington Gas 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) Energy export volumes represents propane volumes exported at RIPET since facility was placed into service in May 2019.

(10) Average propane spot price spread between Argus Far East Index and Mont Belvieu TET commercial index for the period beginning May 2019.

(11) 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.

AltaGas Ltd. – 2019 MD&A and Financial Statements - 138

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

US$    United States dollar

ABOUT ALTAGAS

AltaGas is an energy infrastructure company with a focus on regulated Utilities and Midstream. 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

AltaGas Ltd. – 2019 MD&A and Financial Statements - 139

EX-23.1

Consent of Independent Registered Public Accounting Firm

We consent to the reference of our Firm under the caption "Interest of Experts", and to the incorporation by reference in the following Registration Statements:

Form F-10 nos. No. 333-235922 pertaining to the registration of Preferred Shares and Debt Securities

of AltaGas Ltd. and the use herein of our report dated February 27, 2020, with respect to the consolidated balance sheets as at December 31, 2019 and 2018 and the consolidated statements of income (loss), consolidated statements of comprehensive income (loss), consolidated statements of equity and consolidated statements of cash flows for each of the years in the two-year period ended December 31, 2019, included in this Annual Report on Form 40-F.

Calgary, Alberta                                      /s/ Ernst & Young LLP

February 27, 2020                          Chartered Professional Accountants

EX-31.1

Exhibit 31.1

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, 2020

/s/ Randall L. Crawford

Name: Randall L. Crawford

Title: President and Chief Executive Officer

EX-31.2

Exhibit 31.2

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, D. James Harbilas, 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, 2020

/s/ D. James Harbilas _______________

Name: D. James Harbilas

Title: Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

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, 2019, 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, 2020

/s/ Randall L. Crawford_______________

Name: Randall L. Crawford

Title: President and Chief Executive Officer

EX-32.2

Exhibit 32.2

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, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, D. James Harbilas, 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, 2020

/s/ D. James Harbilas_____________________________

Name: D. James Harbilas

Title: Executive Vice President and Chief Financial Officer

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2019

Regulated Operations [Abstract]

Schedule of Regulatory Assets and Liabilities

The following table summarizes the regulatory assets and liabilities recorded in the Consolidated Balance Sheets, as well as the remaining period, as at December 31, 2019 and 2018, over which the Corporation expects to realize or settle the assets or liabilities:

As at December 31	2019		2018		Recovery Period
Regulatory assets - current
Deferred cost of gas (a)	$	7.6	$	20.4	Less than one year
Accelerated replacement recovery mechanisms (b)	2.5		—		Less than one year
Interruptible sharing (a)	2.7		0.6		Less than one year
	$	12.8	$	21.0
Regulatory assets - non-current
Deferred regulatory costs (a) (c)	$	149.5	$	215.5	1 - 51 years
Future recovery of pension and other retirement benefits (a)	128.2		192.9		Various
Future recovery of non-retirement employee benefits (a) (d)	19.4		21.3		Various
Deferred pension costs (e)	—		7.8		—
Deferred environmental costs (a) (f)	17.7		19.9		Various
Deferred loss on debt transactions and derivative instruments (a) (g)	99.2		109.3		Various
Deferred future income taxes (a) (h)	42.7		67.0		Various
Energy efficiency program - Maryland (i)	12.1		4.6		Various
Other	17.9		24.7		Various
	$	486.7	$	663.0
Regulatory liabilities - current
Deferred cost of gas (a)	$	60.2	$	71.2	Less than one year
Refundable tax credit (j)	1.9		3.8		Less than one year
Federal income tax rate change (k)	33.1		26.2		Less than one year
Virginia rate refund (l)	40.4		—		Less than one year
Accelerated replacement recovery mechanisms (b)	0.4		5.2		Less than one year
Interruptible sharing (a)	0.4		2.3		Less than one year
Other	9.1		6.2		Less than one year
	$	145.5	$	114.9
Regulatory liabilities - non-current
Refundable tax credit (j)	3.9		6.1		2 years
Future expense of pension and other retirement benefits (a)	261.2		166.7		Various
Future removal and site restoration costs (m)	483.9		514.7		Various
Deferred gain on debt transactions and derivative instruments (a) (g)	1.6		1.8		Various
Federal income tax rate change (k)	628.3		698.4		Various
Other	4.3		5.1		Various
	$	1,383.2	$	1,392.8

(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) Represents amounts for deferred over or under collections of surcharges associated with Washington Gas' accelerated pipeline recovery programs in the District of Columbia, Maryland, and Virginia.

(c) Includes deferred gas costs and fair value of derivatives, which are not included in customer bills until settled.

(d) 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.

(e) In 2018, this balance related to previously deferred pension and other post-retirement benefits expenses that were fully amortized in 2019.

(f) This balance represents allowed environmental remediation expenditures at SEMCO Gas and Washington Gas sites to be recovered through rates.

(g) 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. As at December 31, 2019, this also includes a fair value adjustment of $79.8 million (December 31, 2018 - $87.3 million) recorded on the WGL Acquisition (Note 3).

(h) This balance reflects the amount of deferred income taxes expected to be refunded, or recovered from, customers in future rates.

(i) Represents amounts for deferred credits associated with Washington Gas' participation in the energy conservation and efficiency program EmPower in Maryland.

(j) 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.

(k) The Tax Cuts and Jobs Act (TCJA) was enacted on December 22, 2017, and required the Corporation to revalue its U.S. deferred tax assets and liabilities in 2018 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.

(l) Represents estimated refunds related to customers billed at a higher rate during the interim period as part of the 2019 Virginia rate case.

(m) 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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Long-Term Investments and Other Assets (Tables)

12 Months Ended

Dec. 31, 2019

Investments, All Other Investments [Abstract]

Schedule of Long-Term and Other Investments

As at	December 31, 2019		December 31, 2018
Investments in publicly-traded entities	$	4.3	$	8.4
Loan to affiliate	45.0		45.0
Deferred lease receivable	17.4		24.4
Debt issuance costs associated with credit facilities	6.2		7.9
Refundable deposits	8.9		16.2
Prepayment on long-term service agreements	80.6		82.5
Cash calls from joint venture partners	9.5		—
Contract asset (note 24)	30.0		11.5
Rabbi trust (notes 28 and 31)	32.0		61.7
Other long-term receivables (note 29)	33.1		—
Other	29.5		25.5
	$	296.5	$	283.1

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Long-Term Debt - Narrative (Details)	Dec. 31, 2019 USD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2018 USD ($)
Debt Instrument
Commercial paper	$ 283,500,000		$ 0
Revolving credit facility | Letter of Credit | WGL Holdings
Debt Instrument
Credit facility maximum borrowing capacity	250,000,000		650,000,000.0
Amount outstanding		$ 0
Revolving credit facility | Letter of Credit | Washington Gas
Debt Instrument
Credit facility maximum borrowing capacity	450,000,000		$ 350,000,000.0
Amount outstanding	$ 0

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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, 2019	Dec. 31, 2018
Equity Method Investments and Joint Ventures [Abstract]
Revenues	$ 1,109.3	$ 351.6
Expenses	(355.0)	(142.7)
Gross profit	754.3	208.9
Current assets	411.1	1,204.6
Property, plant and equipment	8,033.8	7,602.5
Intangible assets	21.9	22.9
Long-term investments and other assets	1,458.8	1,326.6
Long-term investments and other assets	(393.8)	(1,015.2)
Other long-term liabilities	$ (992.1)	$ (949.6)

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Schedule of Long-Term Debt

As at	Maturity date	December 31, 2019			December 31, 2018
Credit facilities
$1,400 million unsecured extendible revolving facility (a)	15-May-2023	$	89.6		$	964.7
US$300 million unsecured extendible revolving facility (b)	15-May-2022	—			287.8
Acquisition credit facility (c)	6-Jan-2020	—			113.2
US$1,200 million unsecured revolving credit facility (d)	28-Dec-2021	—			1,637.0
US$300 million unsecured term facility	27-Feb-2021	389.6			—
US$150 million unsecured extendible revolving facility	20-Dec-2023	163.5			—
Commercial paper (e)	Various	367.4			—
AltaGas Ltd. medium-term notes (MTNs)
$200 million Senior unsecured - 4.55 percent	17-Jan-2019	—			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
$500 million Senior unsecured - 2.61 percent	16-Dec-2022	500.0			—
$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	300.0			299.9
$350 million Senior unsecured - 4.12 percent	7-Apr-2026	349.9			349.8
$200 million Senior unsecured - 3.98 percent	4-Oct-2027	199.9			199.9
$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
$250 million Senior unsecured - 4.99 percent	4-Oct-2047	250.0			250.0
WGL and Washington Gas MTNs
US$450 million Senior unsecured - 2.25 to 4.76 percent (f)	Nov 2019	—			682.1
US$250 million Senior unsecured - 2.44 percent (g)	12-Mar-2020	324.7			341.1
US$20 million Senior unsecured - 6.65 percent	20-Mar-2023	26.0			27.3
US$40.5 million Senior unsecured - 5.44 percent	11-Aug-2025	52.6			55.3
US$53 million Senior unsecured - 6.62 to 6.82 percent	Oct - 2026	68.8			72.3
US$72 million Senior unsecured - 6.40 to 6.57 percent	Feb - Sep 2027	93.5			98.2
US$52 million Senior unsecured - 6.57 to 6.85 percent	Jan - Mar 2028	67.5			70.9
US$8.5 million Senior unsecured - 7.50 percent	1-Apr-2030	11.0			11.6
US$50 million Senior unsecured - 5.70 to 5.78 percent	Jan - Mar 2036	64.9			68.2
US$75 million Senior unsecured - 5.21 percent	3-Dec-2040	97.4			102.3
US$75 million Senior unsecured - 5.00 percent	15-Dec-2043	97.4			102.3
US$300 million Senior unsecured - 4.22 to 4.60 percent	Sep - Dec 2044	389.6			409.3
US$450 million Senior unsecured - 3.80 percent	15-Sep-2046	584.5			613.9
US$300 million Senior unsecured - 3.65 percent	16-Sep-2049	389.6			—
SEMCO long-term debt
US$300 million SEMCO Senior Secured - 5.15 percent (h)	21-Apr-2020	389.6			409.3
US$82 million SEMCO Senior Secured - 4.48 percent (i)	2-Mar-2032	76.1			86.3
Fair value adjustment on WGL Acquisition (note 3)		84.3			89.0
Finance lease liabilities (note 10)		9.9			0.8
		$	6,887.1		$	8,992.3
Less debt issuance costs		(36.4		)	(35.2		)
		$	6,850.7		$	8,957.1
Less current portion		(922.9		)	(890.2		)
		$	5,927.8		$	8,066.9

(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) The acquisition facility was repaid in full and canceled on February 1, 2019.

(d) Borrowings on the facility can be by way of U.S. base-rate loans, U.S. prime loans, or LIBOR loans.

(e) Commercial paper is supported by the availability of long-term committed credit facilities with maturity dates ranging from 2022 to 2024.

(f) Certain MTNs have a floating rate per annum reset quarterly based on terms set forth in the prospectus supplement filed by WGL pursuant to Securities Act Rule 424 on November 27, 2017.

(g) Floating rate per annum reset quarterly based on terms set forth in the prospectus filed by WGL pursuant to Securities Act Rule 424 on March 13, 2018.

(h) Collateral for the U.S. dollar MTNs is certain SEMCO assets.

(i) 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.

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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, 2019	Dec. 31, 2017
Accounts, Notes, Loans and Financing Receivable
AR accruals	$ 447.5	$ 343.5
Receivables impaired	0.0	0.0
Allowance for credit losses	(54.7)	(33.2)	$ (2.4)
Accounts receivable	1,547.5	1,222.4
WGL Holdings
Accounts, Notes, Loans and Financing Receivable
Allowance credit losses acquired	52.9
Less than 30 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	989.0	775.2
31 to 60 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	74.1	61.2
61 to 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	12.8	11.6
Over 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	24.1	30.9
Trade receivable
Accounts, Notes, Loans and Financing Receivable
Accounts receivable, gross	1,574.6	1,238.2
AR accruals	447.5	343.5
Receivables impaired	54.7	33.2
Trade receivable | Less than 30 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	961.5	757.9
Trade receivable | 31 to 60 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	74.1	61.2
Trade receivable | 61 to 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	12.8	11.6
Trade receivable | Over 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	24.0	30.8
Other
Accounts, Notes, Loans and Financing Receivable
Accounts receivable, gross	27.6	17.4
AR accruals	0.0	0.0
Receivables impaired	0.0	0.0
Other | Less than 30 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	27.5	17.3
Other | 31 to 60 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	0.0	0.0
Other | 61 to 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	0.0	0.0
Other | Over 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	0.1	0.1
Allowance for credit losses
Accounts, Notes, Loans and Financing Receivable
AR accruals	0.0	0.0
Allowance for credit losses	(54.7)	(33.2)
Allowance for credit losses | Less than 30 days
Accounts, Notes, Loans and Financing Receivable
Allowance for credit losses	0.0	0.0
Allowance for credit losses | 31 to 60 days
Accounts, Notes, Loans and Financing Receivable
Allowance for credit losses	0.0	0.0
Allowance for credit losses | 61 to 90 days
Accounts, Notes, Loans and Financing Receivable
Allowance for credit losses	0.0	0.0
Allowance for credit losses | Over 90 days
Accounts, Notes, Loans and Financing Receivable
Allowance for credit losses	$ 0.0	$ 0.0

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Property, Plant and Equipment - Narratives (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Interest capitalized	$ 14.5	$ 12.6
Capital projects under construction	725.2	872.7
Depreciation expense	$ 357.8	$ 324.3

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Summary of Significant Accounting Policies - Effects of Adoption of New Accounting Principles (Details) - CAD ($) $ in Millions	Jan. 01, 2020	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
New Accounting Pronouncements or Change in Accounting Principle\
Current liabilities		$ 3,125.1		$ 4,102.0
ASU 2016-02
New Accounting Pronouncements or Change in Accounting Principle\
Long term assets			$ 181.0
Long term liabilities			170.5
Current liabilities			$ 23.3
ASU 2016-13 | Accounts receivable | Subsequent Event | Forecast
New Accounting Pronouncements or Change in Accounting Principle\
Anticipated effect on account balance (percent)	(1.00%)
ASU 2016-13 | Accumulated deficit | Subsequent Event | Forecast
New Accounting Pronouncements or Change in Accounting Principle\
Anticipated effect on account balance (percent)	1.00%

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Financial Instruments and Financial Risk Management - Realized and Unrealized Losses Recorded to Income for Level 3 Measurements (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation
Realized and Unrealized Losses Recorded to Income for Level 3 Measurements	$ 49.0	$ (14.8)
Commodity contracts | Recorded to revenue
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation
Realized and Unrealized Losses Recorded to Income for Level 3 Measurements	75.2	(11.1)
Commodity contracts | Recorded to cost of sales
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation
Realized and Unrealized Losses Recorded to Income for Level 3 Measurements	$ (26.2)	$ (3.7)

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Financial Instruments and Financial Risk Management - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 CAD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2018 CAD ($)
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Netting of collateral				$ 5,500,000		$ 0
Long term debt				$ 6,850,700,000		$ 8,957,100,000
Other comprehensive income (loss)	$ (334,100,000)	$ 379,900,000
Unrealized gain on net investment hedge	60,000,000	(80,200,000)
Unrealized gains (losses) on risk management contracts	(85,300,000)	80,800,000
Interest rate risk
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Fixed rate debt, percent			76.00%	76.00%	59.00%	59.00%
Weather related instruments
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Unrealized gains (losses) on risk management contracts	(1,900,000)	(1,000,000)
Net investment hedge
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Long term debt			$ 300.0		$ 1,494.0
Hedge net investments
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Other comprehensive income (loss)	$ 60,000,000	$ (80,200,000)

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Summary of Significant Accounting Policies - Summary of Estimated Useful Lives of Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2019
Minimum
Property, Plant and Equipment
Useful life	2 years
Minimum | Corporate
Property, Plant and Equipment
Useful life	3 years
Minimum | Utilities
Property, Plant and Equipment
Useful life	4 years
Minimum | Power
Property, Plant and Equipment
Useful life	3 years
Maximum | Corporate
Property, Plant and Equipment
Useful life	7 years
Maximum | Utilities
Property, Plant and Equipment
Useful life	69 years
Maximum | Midstream
Property, Plant and Equipment
Useful life	45 years
Maximum | Power
Property, Plant and Equipment
Useful life	46 years

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Provisions on Assets - Schedule of Provisions on Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Provisions On Assets Disclosure
Provisions on assets	$ 415.8	$ 728.7
Utilities
Provisions On Assets Disclosure
Provisions on assets	0.0	193.7
Midstream
Provisions On Assets Disclosure
Provisions on assets	35.2	153.7
Power
Provisions On Assets Disclosure
Provisions on assets	$ 380.6	$ 381.3

XML

Provisions on Assets

12 Months Ended

Dec. 31, 2019

Goodwill and Intangible Assets Disclosure [Abstract]

Provisions on Assets

Provisions on Assets

Year Ended December 31	2019		2018
Utilities	$	—	$	193.7
Midstream	35.2		153.7
Power	380.6		381.3
	$	415.8	$	728.7

Utilities

There were no provisions recorded in the Utilities segment in 2019. In 2018, AltaGas recorded pre-tax provisions of $193.7 million related to certain rate-regulated natural gas distributed utility assets that were classified as held for sale in the third quarter of 2018.

Midstream

In 2019, AltaGas recorded pre-tax provisions of $35.2 million related to the Pouce Coupe sour gas treatment facility in Alberta. The pre-tax provisions were comprised of $35.0 million on property, plant and equipment and $0.2 million on intangible assets. In 2018, AltaGas recorded pre-tax provisions of $153.7 million related to certain non-core Midstream assets that were classified as held for sale at December 31, 2018 and shut-in assets in the South, Cold Lake and Northwest operating areas.

Power

In 2019, AltaGas recorded pre-tax provisions totaling $380.6 million in the Power segment. The pre-tax provisions were recorded against property, plant and equipment. In 2018, AltaGas recorded pre-tax provisions of $381.3 million primarily related to the Tracy, Hanford, and Henrietta gas-fired peaking plants in California that were disposed of in the fourth quarter of 2018, a development project in the U.S., the Pomona natural gas-fired co-generation facility in the United States, and non-core Power assets in Canada and a WGL Energy Systems financing receivable that were classified as held for sale at December 31, 2018.

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Net Income (Loss) Per Common Share - Summary of Net Income per Common Share (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions		12 Months Ended
	Dec. 20, 2019	Dec. 31, 2019	Dec. 31, 2018
Numerator:
Net income (loss) applicable to controlling interests		$ 833.5	$ (435.1)
Less: Preferred share dividends		(68.5)	(66.6)
Gain on redemption of preferred shares (note 25)	$ 3.5	3.5	0.0
Net income (loss) applicable to common shares		$ 768.5	$ (501.7)
Denominator:
Weighted average number of common shares outstanding (shares)		276.9	222.6
Dilutive equity instruments (shares)		0.5	0.0
Weighted average number of common shares outstanding - diluted (shares)		277.4	222.6
Basic net income (loss) per common share (per share)		$ 2.78	$ (2.25)
Diluted net income (loss) per common share (per share)		$ 2.77	$ (2.25)
Anti-dilutive share options excluded from diluted income per share (shares)		4.3	4.0

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Shareholders’ Equity - Summary of Share Option Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Number of options
Share options outstanding, beginning of year (shares)	6,309,183.000000	4,533,761
Granted (shares)	2,287,385.000000	2,811,460
Exercised (shares)	(76,177.000000)	(57,275)
Forfeited, Number of options	(1,165,435.000000)	(878,013)
Expired, Number of options	(311,000.000000)	(100,750)
Share options outstanding, end of year (shares)	7,043,956.000000	6,309,183.000000
Share options exercisable, end of year (shares)	2,921,641.666654	2,897,723,000,000
Exercise price
Share options outstanding, beginning of year (per share)	$ 25.18	$ 32.35
Granted (per share)	19.12	16.69
Exercised (per share)	14.52	20.68
Forfeited (per share)	27.31	36.47
Expired (per share)	36.16	14.60
Share options outstanding, end of year (per share)	22.49	25.18
Share options exercisable, end of year (per share)	$ 27.70	$ 32.01

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Leases

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Leases

Leases

Lessee

AltaGas has operating and finance leases for office space, office equipment, field equipment, rail cars, vehicles, power and gas facilities, transmission and distribution assets, and land.

The components of lease expense were as follows:

	Year Ended December 31, 2019
Operating lease cost (includes variable lease payments)	$	29.2
Finance lease cost
Amortization of right-of-use assets	$	3.4
Interest on lease liabilities	0.3
Total finance lease cost	$	3.7
Total lease cost	$	32.9

Supplemental cash flow information related to leases was as follows:

	Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from finance leases	$	(0.3	)
Operating cash flows from operating leases	$	(20.6	)
Financing cash flows from finance leases (a)	$	(3.7	)
Right-of-use assets obtained in exchange for new lease liabilities
Operating leases	$	50.4
Finance leases	$	5.4

(a) Included within repayment of long-term debt on the Consolidated Statements of Cash Flows.

Supplemental balance sheet information related to leases was as follows:

As at	December 31, 2019
Operating Leases
Operating lease right-of-use assets
Long-term	$	169.8
Included in assets held for sale (note 5)	0.4
Total operating lease right-of-use assets	$	170.2
Operating lease liabilities
Current	$	(27.3	)
Long-term	(153.4		)
Included in liabilities associated with assets held for sale (note 5)	(0.4		)
Total operating lease liabilities	$	(181.1	)
Finance Leases
Property and equipment, gross	$	13.2
Accumulated depreciation	(3.3		)
Property and equipment, net	$	9.9
Current portion of long-term debt	$	(3.5	)
Long-term debt	(6.4		)
Total finance lease liabilities	$	(9.9	)

As at	December 31, 2019
Weighted average remaining lease term (years)
Operating leases	10.9
Finance leases	5.2
Weighted average discount rate (%)
Operating leases	3.51
Finance leases	3.68

Maturity analysis of lease liabilities was as follows:

	Operating Leases			Finance Leases
2020	$	27.8		$	3.5
2021	27.1			2.9
2022	26.5			2.0
2023	24.5			1.1
2024	20.1			0.4
Thereafter	100.1			2.0
Total lease payments	226.1			11.9
Less: imputed interest	(45.0		)	(2.0		)
Total	$	181.1		$	9.9

As of December 31, 2019, AltaGas has additional operating leases, primarily for rail cars, that have not yet commenced of $4.8 million. These operating leases will commence in 2020 with lease terms of up to 6 years.

Lessor

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.

Maturity analysis of lease receivables was as follows:

	Operating Leases
2020	$	118.3
2021	115.4
2022	115.6
2023	115.9
2024	47.8
Thereafter	477.5
Total	$	990.5

The carrying value of property, plant, and equipment associated with these leases was approximately $0.5 billion as at December 31, 2019.

AltaGas manages its risk associated with the residual value of its leased assets through strategically constructing leased facilities in key commercial regions and retaining the ability to sell commodities and ancillary services via the merchant market or through commodity sales agreements.

Leases

Leases

Lessee

AltaGas has operating and finance leases for office space, office equipment, field equipment, rail cars, vehicles, power and gas facilities, transmission and distribution assets, and land.

The components of lease expense were as follows:

	Year Ended December 31, 2019
Operating lease cost (includes variable lease payments)	$	29.2
Finance lease cost
Amortization of right-of-use assets	$	3.4
Interest on lease liabilities	0.3
Total finance lease cost	$	3.7
Total lease cost	$	32.9

Supplemental cash flow information related to leases was as follows:

	Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from finance leases	$	(0.3	)
Operating cash flows from operating leases	$	(20.6	)
Financing cash flows from finance leases (a)	$	(3.7	)
Right-of-use assets obtained in exchange for new lease liabilities
Operating leases	$	50.4
Finance leases	$	5.4

(a) Included within repayment of long-term debt on the Consolidated Statements of Cash Flows.

Supplemental balance sheet information related to leases was as follows:

As at	December 31, 2019
Operating Leases
Operating lease right-of-use assets
Long-term	$	169.8
Included in assets held for sale (note 5)	0.4
Total operating lease right-of-use assets	$	170.2
Operating lease liabilities
Current	$	(27.3	)
Long-term	(153.4		)
Included in liabilities associated with assets held for sale (note 5)	(0.4		)
Total operating lease liabilities	$	(181.1	)
Finance Leases
Property and equipment, gross	$	13.2
Accumulated depreciation	(3.3		)
Property and equipment, net	$	9.9
Current portion of long-term debt	$	(3.5	)
Long-term debt	(6.4		)
Total finance lease liabilities	$	(9.9	)

As at	December 31, 2019
Weighted average remaining lease term (years)
Operating leases	10.9
Finance leases	5.2
Weighted average discount rate (%)
Operating leases	3.51
Finance leases	3.68

Maturity analysis of lease liabilities was as follows:

	Operating Leases			Finance Leases
2020	$	27.8		$	3.5
2021	27.1			2.9
2022	26.5			2.0
2023	24.5			1.1
2024	20.1			0.4
Thereafter	100.1			2.0
Total lease payments	226.1			11.9
Less: imputed interest	(45.0		)	(2.0		)
Total	$	181.1		$	9.9

As of December 31, 2019, AltaGas has additional operating leases, primarily for rail cars, that have not yet commenced of $4.8 million. These operating leases will commence in 2020 with lease terms of up to 6 years.

Lessor

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.

Maturity analysis of lease receivables was as follows:

	Operating Leases
2020	$	118.3
2021	115.4
2022	115.6
2023	115.9
2024	47.8
Thereafter	477.5
Total	$	990.5

The carrying value of property, plant, and equipment associated with these leases was approximately $0.5 billion as at December 31, 2019.

AltaGas manages its risk associated with the residual value of its leased assets through strategically constructing leased facilities in key commercial regions and retaining the ability to sell commodities and ancillary services via the merchant market or through commodity sales agreements.

Leases

Leases

Lessee

AltaGas has operating and finance leases for office space, office equipment, field equipment, rail cars, vehicles, power and gas facilities, transmission and distribution assets, and land.

The components of lease expense were as follows:

	Year Ended December 31, 2019
Operating lease cost (includes variable lease payments)	$	29.2
Finance lease cost
Amortization of right-of-use assets	$	3.4
Interest on lease liabilities	0.3
Total finance lease cost	$	3.7
Total lease cost	$	32.9

Supplemental cash flow information related to leases was as follows:

	Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from finance leases	$	(0.3	)
Operating cash flows from operating leases	$	(20.6	)
Financing cash flows from finance leases (a)	$	(3.7	)
Right-of-use assets obtained in exchange for new lease liabilities
Operating leases	$	50.4
Finance leases	$	5.4

(a) Included within repayment of long-term debt on the Consolidated Statements of Cash Flows.

Supplemental balance sheet information related to leases was as follows:

As at	December 31, 2019
Operating Leases
Operating lease right-of-use assets
Long-term	$	169.8
Included in assets held for sale (note 5)	0.4
Total operating lease right-of-use assets	$	170.2
Operating lease liabilities
Current	$	(27.3	)
Long-term	(153.4		)
Included in liabilities associated with assets held for sale (note 5)	(0.4		)
Total operating lease liabilities	$	(181.1	)
Finance Leases
Property and equipment, gross	$	13.2
Accumulated depreciation	(3.3		)
Property and equipment, net	$	9.9
Current portion of long-term debt	$	(3.5	)
Long-term debt	(6.4		)
Total finance lease liabilities	$	(9.9	)

As at	December 31, 2019
Weighted average remaining lease term (years)
Operating leases	10.9
Finance leases	5.2
Weighted average discount rate (%)
Operating leases	3.51
Finance leases	3.68

Maturity analysis of lease liabilities was as follows:

	Operating Leases			Finance Leases
2020	$	27.8		$	3.5
2021	27.1			2.9
2022	26.5			2.0
2023	24.5			1.1
2024	20.1			0.4
Thereafter	100.1			2.0
Total lease payments	226.1			11.9
Less: imputed interest	(45.0		)	(2.0		)
Total	$	181.1		$	9.9

As of December 31, 2019, AltaGas has additional operating leases, primarily for rail cars, that have not yet commenced of $4.8 million. These operating leases will commence in 2020 with lease terms of up to 6 years.

Lessor

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.

Maturity analysis of lease receivables was as follows:

	Operating Leases
2020	$	118.3
2021	115.4
2022	115.6
2023	115.9
2024	47.8
Thereafter	477.5
Total	$	990.5

The carrying value of property, plant, and equipment associated with these leases was approximately $0.5 billion as at December 31, 2019.

AltaGas manages its risk associated with the residual value of its leased assets through strategically constructing leased facilities in key commercial regions and retaining the ability to sell commodities and ancillary services via the merchant market or through commodity sales agreements.

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Pension Plans and Retiree Benefits - Schedule of Amount Included in the Consolidated Balance Sheets (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure
Prepaid post-retirement benefits	$ 486.8	$ 341.4
Accounts payable and accrued liabilities	(25.7)	(27.6)
Future employee obligations	(226.9)	(284.2)
Total amounts included in Consolidated Balance Sheets	234.2	29.6
Defined Benefit
Defined Benefit Plan Disclosure
Prepaid post-retirement benefits	0.0	0.0
Accounts payable and accrued liabilities	(25.7)	(27.6)
Future employee obligations	(216.2)	(274.1)
Total amounts included in Consolidated Balance Sheets	(241.9)	(301.7)
Post- Retirement Benefits
Defined Benefit Plan Disclosure
Prepaid post-retirement benefits	486.8	341.4
Accounts payable and accrued liabilities	0.0	0.0
Future employee obligations	(10.7)	(10.1)
Total amounts included in Consolidated Balance Sheets	$ 476.1	$ 331.3

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Other Income

12 Months Ended

Dec. 31, 2019

Other Income and Expenses [Abstract]

Other Income

Other Income

Year Ended December 31	2019			2018
Gains (losses) from sale of assets	$	875.8		$	(10.6	)
Other components of net benefit cost (note 28)	27.4			18.9
Interest income and other revenue	9.0			2.7
Losses on investments	(4.1		)	(10.1		)
	$	908.1		$	0.9

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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, 2019	Dec. 31, 2018
Supplemental Cash Flow Elements [Abstract]
Accounts receivable	$ 168.4	$ (526.9)
Inventory	(2.1)	(100.8)
Other current assets	(85.5)	12.5
Regulatory assets - current	7.1	(15.8)
Accounts payable and accrued liabilities	(280.2)	237.9
Customer deposits	(16.9)	(13.3)
Regulatory liabilities - current	34.2	69.2
Risk management liabilities - current	1.1	0.0
Other current liabilities	(5.6)	(5.9)
Other operating assets and liabilities	(52.0)	(143.4)
Changes in operating assets and liabilities	$ (231.5)	$ (486.5)

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Segmented Information - Reconciliation Of Segment Revenue (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenues	$ 5,495.0	$ 4,256.7
Utilities
Revenues	2,564.2	1,752.6
Midstream
Revenues	1,574.3	1,344.6
Power
Revenues	1,356.3	1,162.0
Corporate
Revenues	0.2	(2.5)
Operating Segments
Revenues	5,539.4	4,369.2
Operating Segments | Utilities
Revenues	2,590.8	1,765.6
Operating Segments | Midstream
Revenues	1,581.2	1,435.0
Operating Segments | Power
Revenues	1,367.2	1,171.0
Operating Segments | Corporate
Revenues	0.2	(2.4)
Intersegment revenue
Revenues	(44.4)	(112.5)
Intersegment revenue | Utilities
Revenues	(26.6)	(13.0)
Intersegment revenue | Midstream
Revenues	(6.9)	(90.4)
Intersegment revenue | Power
Revenues	(10.9)	(9.0)
Intersegment revenue | Corporate
Revenues	$ 0.0	$ (0.1)

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Financial Instruments and Financial Risk Management

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Financial Instruments and Financial Risk Management

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 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.

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.

As at	December 31, 2019
	Carrying Amount		Level 1		Level 2		Level 3		Total Fair Value
Financial assets
Fair value through net income (a)
Risk management assets - current	$	81.4	$	—	$	30.4	$	51.0	$	81.4
Risk management assets - non-current	30.9		—		6.7		24.2		30.9
Equity securities (b)	4.3		4.3		—		—		4.3
Fair value through regulatory assets (a)
Risk management assets - current	5.2		—		—		5.2		5.2
Risk management assets - non-current	8.2		—		0.4		7.8		8.2
Amortized cost
Loans and receivables (b)	45.0		—		46.1		—		46.1
	$	175.0	$	4.3	$	83.6	$	88.2	$	176.1
Financial liabilities
Fair value through net income (a)
Risk management liabilities - current	$	120.6	$	—	$	98.7	$	21.9	$	120.6
Risk management liabilities - non-current	77.0		—		19.2		57.8		77.0
Fair value through regulatory liabilities (a)
Risk management liabilities - current	4.2		—		0.6		3.6		4.2
Risk management liabilities - non-current	90.0		—		—		90.0		90.0
Amortized cost
Current portion of long-term debt	922.9		—		922.9		—		922.9
Long-term debt	5,927.8		—		6,263.8		—		6,263.8
Other current liabilities (c)	15.4		—		15.4		—		15.4
	$	7,157.9	$	—	$	7,320.6	$	173.3	$	7,493.9

(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.

As at	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 (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 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		—		8,040.3		—		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	$	—	$	8,997.5	$	242.7	$	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.

The following table includes quantitative information about the significant unobservable inputs used in the fair value measurement of Level 3 financial instruments as at December 31, 2019:

	Net Fair Value			Valuation Technique	Unobservable Inputs	Range
Natural gas	$	(83.8	)	Discounted Cash Flow	Natural Gas Basis Price (per dekatherm)	$	(1.18	)	-	$	3.27
Natural gas	$	(1.4	)	Option Model	Natural Gas Basis Price (per dekatherm)	$	(1.19	)	-	$	3.30
					Annualized Volatility of Spot Market Natural Gas	29		%	-	906		%
Electricity	$	0.1		Discounted Cash Flow	Electricity Congestion Price (per megawatt hour)	$	(6.73	)	-	$	65.26

The following tables provide 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	2019									2018
	Natural Gas			Electricity			Total			Natural Gas			Electricity			Total
Balance, beginning of year	$	(148.5	)	$	(14.7	)	$	(163.2	)	$	—		$	—		$	—
Acquired (note 3)	—			—			—			(136.1		)	(10.6		)	(146.7		)
Realized and unrealized gains (losses):
Recorded in income	47.6			1.4			49.0			(8.3		)	(6.5		)	(14.8		)
Recorded in regulatory assets	23.6			—			23.6			(5.9		)	—			(5.9		)
Transfers into Level 3	(9.0		)	—			(9.0		)	—			—			—
Transfers out of Level 3	12.3			—			12.3			7.3			—			7.3
Purchases	—			(11.4		)	(11.4		)	—			6.4			6.4
Settlements	(17.1		)	24.4			7.3			0.3			(3.4		)	(3.1		)
Foreign exchange translation	5.9			0.4			6.3			(5.8		)	(0.6		)	(6.4		)
Balance, end of year	$	(85.2	)	$	0.1		$	(85.1	)	$	(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 period. Transfers out of Level 3 during the year ended December 31, 2019 were due to an increase in valuations using observable market inputs. Transfers into Level 3 during the year ended December 31, 2019 were due to an increase in unobservable market inputs used in valuations.

Realized and Unrealized Gains (Losses) Recorded to Income for Level 3 Measurements

Year Ended December 31	2019			2018
Recorded to revenue	$	75.2		$	(11.1	)
Recorded to cost of sales	(26.2		)	(3.7		)
	$	49.0		$	(14.8	)

Summary of Unrealized Gains (Losses) on Risk Management Contracts Recognized in Net Income (Loss)

Year Ended December 31	2019			2018
Natural gas	$	22.5		$	(2.2	)
Energy exports	(86.7		)	—
NGL frac spread	(17.4		)	40.0
Power	(4.9		)	9.3
Foreign exchange	1.2			33.7
	$	(85.3	)	$	80.8

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.

As at	December 31, 2019
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	$	121.2	$	(53.7	)	$	—		$	67.5
Energy exports	9.7		(2.7		)	4.4			11.4
NGL frac spread	0.3		(0.2		)	—			0.1
Power	53.5		(6.8		)	—			46.7
	$	184.7	$	(63.4	)	$	4.4		$	125.7
Risk management liabilities (b)
Natural gas	$	226.1	$	(53.7	)	$	(27.7	)	$	144.7
Energy exports	89.5		(2.7		)	—			86.8
NGL frac spread	1.7		(0.2		)	—			1.5
Power	68.7		(6.8		)	(3.1		)	58.8
	$	386.0	$	(63.4	)	$	(30.8	)	$	291.8

(a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $86.6 million and risk management assets (non‑current) balance of $39.1 million.

(b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $124.8 million and risk management liabilities (non‑current) balance of $167.0 million.

As at	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.

Cash Collateral

The following table presents collateral not offset against risk management assets and liabilities:

As at	December 31, 2019		December 31, 2018
Collateral posted with counterparties	$	29.1	$	27.6
Cash collateral held representing an obligation	$	0.3	$	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, 2019, AltaGas has posted$5.5 million (December 31, 2018 - $nil)of 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 specific credit-risk-related contingent features underlying these agreements were triggered:

As at	December 31, 2019		December 31, 2018
Risk management liabilities with credit-risk-contingent features	$	42.2	$	14.7
Maximum potential collateral requirements	$	29.0	$	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 2033. 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, 2019 and 2018:

December 31, 2019	Fixed price (per GJ)	Period (months)	Notional volume (GJ)	Fair Value
Sales	1.32 to 6.81	1-166	698,126,985	$	28.9
Purchases	0.22 to 6.81	1-167	1,406,991,689	$	(104.4	)
Swaps	0.22 to 10.24	1-51	541,652,374	$	(1.7	)
December 31, 2018	Fixed price (per GJ)	Period (months)	Notional volume (GJ)	Fair Value
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

Energy Exports

AltaGas entered into a series of swaps to lock in a portion of the volumes exposed to the propane price differential between North American Indices and the Far East Index for contracts not under tolling arrangements at RIPET. AltaGas had the following contracts outstanding as at December 31, 2019:

December 31, 2019	Fixed price (per Bbl)	Period (months)	Notional volume (Bbl)	Fair Value
Propane	21.49 to 29.71	1-27	9,374,826	$	(75.4	)

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, 2019 and 2018:

December 31, 2019	Fixed price	Period (months)	Notional volume		Fair Value
Butane swaps	73.02 to 75.15/Bbl	1-12	346,852	Bbl	$	(0.5	)
Crude oil swaps	73.02 to 75.15/Bbl	1-12	212,587	Bbl	$	(0.9	)
Natural gas swaps	1.58 to 1.86/GJ	1-12	3,883,992	GJ	$	—
December 31, 2018	Fixed price	Period (months)	Notional volume		Fair Value
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	)

Power

AltaGas sells power to the Alberta Electric System Operator at market 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 2024. As at December 31, 2019, 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, 2019 and 2018:

December 31, 2019	Fixed price (per MWh)	Period (months)	Notional volume (MWh)	Fair Value
Power sales	31.63 to 66.76	1-42	8,034,024	$	39.0
Power purchases	31.63 to 66.76	1-60	8,552,467	$	(27.3	)
Swap purchases	(7.88) to 74.26	1-48	25,058,577	$	(23.8	)
December 31, 2018	Fixed price (per MWh)	Period (months)	Notional volume (MWh)	Fair Value
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	)

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, 2019:

Factor	Increase or decrease to forward prices	Increase or decrease to income before tax ($ millions)
Alberta power price	$1/MWh	2.3
PJM power price	US$1/MWh	1.9
AECO natural gas price	$0.50/GJ	1.1
NYMEX natural gas price	US$0.50/GJ	2.6
Energy Exports:
Propane Far East Index to Mont Belvieu spread	$1/Bbl	3.4
Baltic LPG Freight	$1/Bbl	6.1
NGL frac spread:
Western Texas Intermediate (WTI) crude oil	$1/Bbl	0.6
Natural gas	$0.50/GJ	1.9

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, 2019 and December 31, 2018, AltaGas did not have any outstanding foreign exchange forward contracts.

AltaGas may designate its U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. As at December 31, 2019, AltaGas has designated US$300.0 million of outstanding debt as a net investment hedge (December 31, 2018 - US$1,494.0 million). For the year ended December 31, 2019,AltaGas incurred after-tax unrealized gains of $60.0 million arising from the translation of debt in OCI (2018 ‑ after-tax unrealized loss of $80.2 million).

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, 2019, approximately 76 percent of AltaGas’ total outstanding short-term and long-term debt was at fixed rates (December 31, 2018 - 59 percent). 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, 2019.

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, 2019, 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 year ended December 31, 2019, a pre-tax loss of $1.9 million was recorded related to these instruments (2018 - pre-tax loss of $1.0 million).

Accounts Receivable Past Due or Impaired

AltaGas had the following past due or impaired accounts receivable (AR):

As at December 31, 2019	Total			AR accruals		Receivables impaired			Less than 30 days		31 to 60 days		61 to 90 days		Over 90 days
Trade receivable	$	1,238.2		$	343.5	$	33.2		$	757.9	$	61.2	$	11.6	$	30.8
Other	17.4			—		—			17.3		—		—		0.1
Allowance for credit losses	(33.2		)	—		(33.2		)	—		—		—		—
	$	1,222.4		$	343.5	$	—		$	775.2	$	61.2	$	11.6	$	30.9

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

Allowance for credit losses	December 31, 2019			December 31, 2018
Balance, beginning of year	$	54.7		$	2.4
Foreign exchange translation	(2.6		)	0.1
New allowance (a)	27.5			53.1
Change in allowance (b)	(9.2		)	(0.9		)
Allowance applied to uncollectible customer accounts	(37.2		)	—
Balance, end of year	$	33.2		$	54.7

(a) Upon close of the WGL Acquisition in 2018, AltaGas acquired WGL’s allowance for credit losses of approximately $52.9 million.

(b) Includes removal of allowance related to asset disposals of approximately $8.1 million in 2019.

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, 2019	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Accounts payable and accrued liabilities	$	1,324.9	$	1,324.9	$	—	$	—	$	—
Dividends payable	22.3		22.3		—		—		—
Short-term debt	460.0		460.0		—		—		—
Other current liabilities (a)	15.4		15.4		—		—		—
Risk management contract liabilities	291.8		124.8		34.1		13.2		119.7
Current portion of long-term debt (b)	920.4		920.4		—		—		—
Long-term debt (b)	5,872.5		—		1,489.2		921.3		3,462.0
	$	8,907.3	$	2,867.8	$	1,523.3	$	934.5	$	3,581.7

(a) Excludes non-financial liabilities.

(b) Excludes deferred financing costs, discounts, finance lease liabilities, and the fair value adjustment on the WGL Acquisition.

	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, discounts, finance lease liabilities, and the fair value adjustment on the WGL Acquisition.

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2019

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

Supplemental Cash Flow Information

The following table details the changes in operating assets and liabilities from operating activities:

	Year Ended December 31
	2019			2018
Source (use) of cash:
Accounts receivable	$	168.4		$	(526.9	)
Inventory	(2.1		)	(100.8		)
Other current assets	(85.5		)	12.5
Regulatory assets - current	7.1			(15.8		)
Accounts payable and accrued liabilities	(280.2		)	237.9
Customer deposits	(16.9		)	(13.3		)
Regulatory liabilities - current	34.2			69.2
Risk management liabilities - current	1.1			—
Other current liabilities	(5.6		)	(5.9		)
Other operating assets and liabilities	(52.0		)	(143.4		)
Changes in operating assets and liabilities	$	(231.5	)	$	(486.5	)

The following cash payments have been included in the determination of earnings:

	Year Ended December 31
	2019		2018
Interest paid (net of capitalized interest)	$	351.7	$	288.9
Income taxes paid	$	67.2	$	36.9

The following table is a reconciliation of cash and restricted cash balances:

As at December 31	2019		2018
Cash and cash equivalents	$	57.1	$	101.6
Restricted cash holdings from customers - current	4.0		4.1
Restricted cash holdings from customers - non-current	3.9		6.1
Restricted cash included in prepaid expenses and other current assets (a)	25.4		27.6
Restricted cash included in long-term investments and other assets (a)	32.0		61.7
Cash, cash equivalents, and restricted cash per Consolidated Statements of Cash Flows	$	122.4	$	201.1

(a) The restricted cash balances included in prepaid expenses and other current assets and long-term investments and other assets relate to Rabbi trusts associated with WGL’s pension plans (seeNote 28).

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Commitments, Guarantees, and Contingencies - Summary of Future Payment Commitments (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)	Dec. 31, 2017	Dec. 31, 2014 hour	Dec. 31, 2019 CAD ($)	Dec. 31, 2015
Other Commitments
Operating leases, 2020				$ 27.8
Operating leases, 2021				27.1
Operating leases, 2022				26.5
Operating leases, 2023				24.5
Operating leases, 2024				20.1
Operating leases, 2025 and beyond				100.1
Total lease payments				226.1
Commitments, 2020				3,990.7
Commitments, 2021				3,665.2
Commitments, 2022				3,263.9
Commitments, 2023				2,870.2
Commitments, 2024				2,624.9
Commitments, 2025 and beyond				27,190.1
Commitments				43,605.0
Capital projects
Other Commitments
Other commitments, 2020				6.9
Other commitments, 2021				0.0
Other commitments, 2022				0.0
Other commitments, 2023				0.0
Other commitments, 2024				0.0
Other commitments, 2025 and beyond				0.0
Other commitments				6.9
Environmental
Other Commitments
Other commitments, 2020				6.5
Other commitments, 2021				4.3
Other commitments, 2022				1.0
Other commitments, 2023				1.0
Other commitments, 2024				0.6
Other commitments, 2025 and beyond				0.4
Other commitments				13.8
Merger commitments
Other Commitments
Other commitments, 2020				8.2
Other commitments, 2021				3.8
Other commitments, 2022				1.9
Other commitments, 2023				1.9
Other commitments, 2024				1.9
Other commitments, 2025 and beyond				4.3
Other commitments				22.0
Cumulative expenses incurred but not yet paid	$ 17.0
Natural Gas
Other Commitments
Purchase obligations, 2020				2,374.0
Purchase obligations, 2021				2,488.2
Purchase obligations, 2022				2,323.6
Purchase obligations, 2023				2,076.1
Purchase obligations, 2024				1,959.5
Purchase obligations, 2025 and beyond				22,772.0
Purchase obligations				33,993.4
Natural Gas | Merger commitments
Other Commitments
Other commitments	$ 70.0
Propane
Other Commitments
Purchase obligations, 2020				220.2
Purchase obligations, 2021				127.2
Purchase obligations, 2022				94.9
Purchase obligations, 2023				86.5
Purchase obligations, 2024				58.4
Purchase obligations, 2025 and beyond				127.1
Purchase obligations				714.3
Electricity purchase
Other Commitments
Purchase obligations, 2020				567.2
Purchase obligations, 2021				318.1
Purchase obligations, 2022				160.0
Purchase obligations, 2023				56.4
Purchase obligations, 2024				11.0
Purchase obligations, 2025 and beyond				0.4
Purchase obligations				1,113.1
Service agreements
Other Commitments
Purchase obligations, 2020				58.7
Purchase obligations, 2021				44.0
Purchase obligations, 2022				28.2
Purchase obligations, 2023				23.4
Purchase obligations, 2024				22.9
Purchase obligations, 2025 and beyond				309.1
Purchase obligations				486.3
Service agreement term, (EOH/CT) | hour			124,000
Service agreement term			25 years
Service agreement payable				167.9
Service agreement payable in five years				45.4
Service agreement payment period	16 years	12 years
Service agreements | Ridley Terminals Inc.
Other Commitments
Lease term (years)					20 years
Pipeline and storage services
Other Commitments
Purchase obligations, 2020				721.2
Purchase obligations, 2021				652.5
Purchase obligations, 2022				627.8
Purchase obligations, 2023				600.4
Purchase obligations, 2024				550.5
Purchase obligations, 2025 and beyond				3,876.7
Purchase obligations				$ 7,029.1
Electricity, renewable energy credits
Other Commitments
Purchase obligations	$ 17.4
Leak mitigation | Merger commitments
Other Commitments
Other commitments, 2022	8.0
Other commitments, 2024	$ 2.0

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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, 2019	Dec. 31, 2018
Defined Benefit
Defined Benefit Plan Disclosure
Past service cost (credit)	$ 1.1	$ 0.8
Net actuarial loss (gain)	127.1	188.2
Recognized in regulatory asset (liability)	128.2	189.0
Post- Retirement Benefits
Defined Benefit Plan Disclosure
Past service cost (credit)	(105.4)	(110.2)
Net actuarial loss (gain)	(155.8)	(52.6)
Recognized in regulatory asset (liability)	(261.2)	(162.8)
Canada | Defined Benefit
Defined Benefit Plan Disclosure
Past service cost (credit)	0.0	0.0
Net actuarial loss (gain)	0.0	0.0
Recognized in regulatory asset (liability)	0.0	0.0
Canada | Post- Retirement Benefits
Defined Benefit Plan Disclosure
Past service cost (credit)	0.0	0.0
Net actuarial loss (gain)	0.0	0.0
Recognized in regulatory asset (liability)	0.0	0.0
United States | Defined Benefit
Defined Benefit Plan Disclosure
Past service cost (credit)	1.1	0.8
Net actuarial loss (gain)	127.1	188.2
Recognized in regulatory asset (liability)	128.2	189.0
United States | Post- Retirement Benefits
Defined Benefit Plan Disclosure
Past service cost (credit)	(105.4)	(110.2)
Net actuarial loss (gain)	(155.8)	(52.6)
Recognized in regulatory asset (liability)	$ (261.2)	$ (162.8)

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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, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 2,445.9
Net payable	(21.2)
Fair value of Plan Assets	$ 2,424.7
Percentage of Plan Assets	100.00%
Percentage of Plan Asset before net payable	100.90%
Defined Benefit
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 1,518.8	$ 1,367.9	$ 363.9
Post- Retirement Benefits
Defined Benefit Plan Disclosure
Fair value of Plan Assets	905.9	791.2	78.9
Commingled funds and pooled separate accounts
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 648.9
Percentage of Plan Asset before net payable	26.80%
Private Equity/Limited Partnership
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 55.6
Percentage of Plan Asset before net payable	2.30%
Pooled separate accounts
Defined Benefit Plan Disclosure
Total fair value of plan investment		$ 32.0
Percentage of Plan Asset before net payable		1.30%
Collective trust fund
Defined Benefit Plan Disclosure
Total fair value of plan investment		$ 433.8
Percentage of Plan Asset before net payable		17.90%
Net payable
Defined Benefit Plan Disclosure
Percentage of Plan Assets payable	(0.90%)
Fair value
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 1,275.6
Percentage of Plan Assets	52.60%
Fair value | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 12.7
Percentage of Plan Assets	0.50%
Fair value | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 6.7
Percentage of Plan Assets	0.30%
Fair value | Equities | United States
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 304.9
Percentage of Plan Assets	12.60%
Fair value | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 938.7
Percentage of Plan Assets	38.70%
Fair value | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 0.8
Percentage of Plan Assets	0.00%
Fair value | Derivatives
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ (0.2)
Percentage of Plan Assets	0.00%
Fair value | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 12.0
Percentage of Plan Assets	0.50%
Level 1
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 452.9
Level 1 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	12.7
Level 1 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	6.7
Level 1 | Equities | United States
Defined Benefit Plan Disclosure
Total fair value of plan investment	304.6
Level 1 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	128.9
Level 1 | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.0
Level 1 | Derivatives
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.0
Level 1 | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.0
Level 2
Defined Benefit Plan Disclosure
Total fair value of plan investment	822.7
Level 2 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.0
Level 2 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.0
Level 2 | Equities | United States
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.3
Level 2 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	809.8
Level 2 | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.8
Level 2 | Derivatives
Defined Benefit Plan Disclosure
Total fair value of plan investment	(0.2)
Level 2 | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 12.0
Canada
Defined Benefit Plan Disclosure
Percentage of Plan Assets	100.00%
Canada | Defined Benefit
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 14.9	$ 13.8	115.2
Canada | Post- Retirement Benefits
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 0.0	0.0	8.1
Canada | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Percentage of Plan Assets	12.80%
Canada | Equities | Canada
Defined Benefit Plan Disclosure
Percentage of Plan Assets	27.50%
Canada | Equities | United States
Defined Benefit Plan Disclosure
Percentage of Plan Assets	16.00%
Canada | Fixed income
Defined Benefit Plan Disclosure
Percentage of Plan Assets	38.30%
Canada | Fixed income | SEMCO
Defined Benefit Plan Disclosure
Target asset mix	33.00%
Canada | Fixed income | Minimum
Defined Benefit Plan Disclosure
Target asset mix	45.00%
Canada | Fixed income | Minimum | WGL Holdings
Defined Benefit Plan Disclosure
Target asset mix	50.00%
Canada | Fixed income | Maximum
Defined Benefit Plan Disclosure
Target asset mix	55.00%
Canada | Fixed income | Maximum | WGL Holdings
Defined Benefit Plan Disclosure
Target asset mix	60.00%
Canada | Real estate
Defined Benefit Plan Disclosure
Percentage of Plan Assets	5.40%
Canada | Fair value
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 14.9
Canada | Fair value | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	1.9
Canada | Fair value | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	4.1
Canada | Fair value | Equities | United States
Defined Benefit Plan Disclosure
Total fair value of plan investment	2.4
Canada | Fair value | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	5.7
Canada | Fair value | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.8
Canada | Level 1
Defined Benefit Plan Disclosure
Total fair value of plan investment	14.1
Canada | Level 1 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	1.9
Canada | Level 1 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	4.1
Canada | Level 1 | Equities | United States
Defined Benefit Plan Disclosure
Total fair value of plan investment	2.4
Canada | Level 1 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	5.7
Canada | Level 1 | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.0
Canada | Level 2
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.8
Canada | Level 2 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.0
Canada | Level 2 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.0
Canada | Level 2 | Equities | United States
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.0
Canada | Level 2 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.0
Canada | Level 2 | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.8
United States
Defined Benefit Plan Disclosure
Total fair value of plan investment	2,431.0
Net payable	(21.2)
Fair value of Plan Assets	$ 2,409.8
Percentage of Plan Assets	100.00%
Percentage of Plan Asset before net payable	100.90%
United States | Defined Benefit
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 1,503.9	1,354.1	248.7
United States | Post- Retirement Benefits
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 905.9	$ 791.2	$ 70.8
United States | Fixed income | WGL Holdings | Post- Retirement Benefits
Defined Benefit Plan Disclosure
Target asset mix	18.00%
United States | Commingled funds and pooled separate accounts
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 648.9
Percentage of Plan Asset before net payable	26.90%
United States | Private Equity/Limited Partnership
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 55.6
Percentage of Plan Asset before net payable	2.30%
United States | Pooled separate accounts
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 32.0
Percentage of Plan Asset before net payable	1.30%
United States | Collective trust fund
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 433.8
Percentage of Plan Asset before net payable	18.10%
United States | Collective trust fund | Common stock large cap
Defined Benefit Plan Disclosure
Target asset mix	90.00%
United States | Collective trust fund | Short term money market
Defined Benefit Plan Disclosure
Target asset mix	2.00%
United States | Collective trust fund | Income producing property
Defined Benefit Plan Disclosure
Target asset mix	8.00%
United States | Common stock large cap | WGL Holdings | Defined Benefit
Defined Benefit Plan Disclosure
Target asset mix	58.00%
United States | Corporate bonds | WGL Holdings | Post- Retirement Benefits
Defined Benefit Plan Disclosure
Target asset mix	24.00%
United States | Net payable
Defined Benefit Plan Disclosure
Percentage of Plan Assets payable	(0.90%)
United States | Fair value
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 1,260.7
Percentage of Plan Assets	52.30%
United States | Fair value | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 10.8
Percentage of Plan Assets	0.40%
United States | Fair value | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 2.6
Percentage of Plan Assets	0.10%
United States | Fair value | Equities | United States
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 302.5
Percentage of Plan Assets	12.60%
United States | Fair value | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 933.0
Percentage of Plan Assets	38.70%
United States | Fair value | Derivatives
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ (0.2)
Percentage of Plan Assets	0.00%
United States | Fair value | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 12.0
Percentage of Plan Assets	0.50%
United States | Level 1
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 438.8
United States | Level 1 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	10.8
United States | Level 1 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	2.6
United States | Level 1 | Equities | United States
Defined Benefit Plan Disclosure
Total fair value of plan investment	302.2
United States | Level 1 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	123.2
United States | Level 1 | Derivatives
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.0
United States | Level 1 | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.0
United States | Level 2
Defined Benefit Plan Disclosure
Total fair value of plan investment	821.9
United States | Level 2 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.0
United States | Level 2 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.0
United States | Level 2 | Equities | United States
Defined Benefit Plan Disclosure
Total fair value of plan investment	0.3
United States | Level 2 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	809.8
United States | Level 2 | Derivatives
Defined Benefit Plan Disclosure
Total fair value of plan investment	(0.2)
United States | Level 2 | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 12.0

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Accumulated Other Comprehensive Income

12 Months Ended

Dec. 31, 2019

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

Accumulated Other Comprehensive Income

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, 2019	$	—		$	(19.0	)	$	(209.2	)	$	801.4		$	5.8		$	579.0
OCI before reclassification	—			15.2			68.2			(406.2		)	(0.7		)	(323.5		)
Amounts reclassified from OCI	—			1.1			—			—			—			1.1
Current period OCI (pre-tax)	—			16.3			68.2			(406.2		)	(0.7		)	(322.4		)
Income tax on amounts retained in AOCI	—			(3.2		)	(8.2		)	—			—			(11.4		)
Income tax on amounts reclassified to earnings	—			(0.3		)	—			—			—			(0.3		)
Net current period OCI	—			12.8			60.0			(406.2		)	(0.7		)	(334.1		)
Ending balance, December 31, 2019	$	—		$	(6.2	)	$	(149.2	)	$	395.2		$	5.1		$	244.9
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 AOCI	—			0.7			—			—			—			0.7
Adoption of ASU No. 2016-01	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

Reclassification From Accumulated Other Comprehensive Income

AOCI components reclassified	Income statement line item	Year Ended December 31, 2019			Year Ended December 31, 2018
Defined benefit pension and PRB plans	Other income	$	1.1		$	0.7
Deferred income taxes	Income tax expense – deferred	(0.3		)	(0.2		)
		$	0.8		$	0.5

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Investments Accounted for by the Equity Method

12 Months Ended

Dec. 31, 2019

Equity Method Investments and Joint Ventures [Abstract]

Investments Accounted for by the Equity Method

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	2019		2018		2019			2018
AltaGas Canada Inc. (ACI) (a)	Canada	37	$	163.9	$	112.5	$	17.0		$	5.4
AltaGas Idemitsu Joint Venture LP	Canada	50	431.3		342.9		62.5			2.1
Constitution Pipeline, LLC (Constitution) (b)	United States	10	0.1		—		(0.5		)	(0.2		)
Craven County Wood Energy LP (c)	United States	50	—		7.8		0.1			(14.1		)
Eaton Rapids Gas Storage System	United States	50	27.0		29.4		1.3			2.0
Grayling Generating Station LP (c)	United States	50	—		29.0		0.3			3.6
Inuvik Gas Ltd. (d)	Canada	33	—		—		—			(0.2		)
Meade Pipeline Co. LLC (c) (e)	United States	55	—		757.8		(3.6		)	12.2
Mountain Valley Pipeline, LLC (Mountain Valley) (f)	United States	10	671.3		532.5		42.8			11.5
Sarnia Airport Storage Pool LP	Canada	50	18.0		18.7		1.0			1.0
Petrogas Preferred Shares	Canada	n/a	150.0		150.0		12.8			12.8
Stonewall Gas Gathering Systems LLC (c)	United States	30	—		411.8		7.4			11.8
			$	1,461.6	$	2,392.4	$	141.1		$	47.9

(a) As at December 31, 2019, the aggregate market value of AltaGas' investment in ACI was $367.9 million (11,025,000 shares at the quoted closing market price of $33.37 on December 31, 2019). As at December 31, 2018, the aggregate market value was $178.8 million (11,025,000 shares at the quoted closing market price of $16.22 on December 31, 2018).

(b) The equity method is considered appropriate because Constitution is a Limited Liability Company (LLC) with specific ownership accounts and ownership between five and fifty percent, resulting in WGL Midstream exercising a more than minor influence over the investee's operating and financing policies. In February 2020, the partners of Constitution elected not to proceed with the pipeline project (Note 33).

(c) Disposed of in 2019 (Note 4).

(d) Inuvik Gas Ltd. was sold to AltaGas Canada Inc. in October 2018.

(e) Meade was a VIE prior to disposition in November 2019 (Notes 4 and 13).

(f) The equity method is considered appropriate because Mountain Valley is an LLC with specific ownership accounts and ownership between five and fifty percent, resulting in WGL Midstream exercising a more than minor influence over the investee's operating and financing policies.

The carrying amount of certain equity investments differs from the amount of the underlying equity in net assets. These basis differences include amounts related to purchase accounting adjustments, capitalized interest, and a contractual cap on contributions to Mountain Valley.

Summarized combined financial information, assuming a 100 percent ownership interest in AltaGas’ equity investments listed above, is as follows ^(a):

Year Ended December 31	2019			2018
Revenues	$	1,109.3		$	351.6
Expenses	(355.0		)	(142.7		)
	$	754.3		$	208.9
As at December 31	2019			2018
Current assets	$	411.1		$	1,204.6
Property, plant and equipment	$	8,033.8		$	7,602.5
Intangible assets	$	21.9		$	22.9
Long-term investments and other assets	$	1,458.8		$	1,326.6
Current liabilities	$	(393.8	)	$	(1,015.2	)
Other long-term liabilities	$	(992.1	)	$	(949.6	)

(a) For equity investments that were disposed of in the year (Note 4), revenues and expenses reflect the period prior to disposition and balance sheet amounts as at December 31 are $nil.

Provisions on investments accounted for by the equity method

During the year ended December 31, 2019, AltaGas recorded a pre-tax provision of $44.2 million against AltaGas' investment in Meade Pipeline Co. LLC as a result of the sale of WGL Midstream's interest in Central Penn. The disposition of the investment in this entity was completed in the fourth quarter of 2019 (Note 4). This equity investment was in the Midstream segment and the provision was recorded in the Consolidated Statements of Income (Loss) under the line item "income from equity investments".

In addition, during the year ended December 31, 2019, AltaGas recorded a pre-tax provision of $2.2 million against AltaGas' investment in Craven County Wood Energy LP as a result of a pending sale. The disposition of the investment in this entity was completed in the third quarter of 2019 (Note 4). This equity investment was in the Power segment and the provision was recorded in the Consolidated Statements of Income (Loss) under the line item "income from equity investments".

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.

AltaGas Canada Inc.

On October 21, 2019, ACIannounced that the Public Sector Pension Investment Board and the Alberta Teachers' Retirement Fund Board (together, the "Consortium") and ACI had concluded a definitive arrangement agreement (the "Arrangement Agreement") whereby the Consortium will indirectly acquire all of the issued and outstanding common shares of ACI(the "Common Shares")in an all-cash transaction for $33.50 per Common Share by way of arrangement under the Canada Business Corporations Act (the "Arrangement"). On December 19, 2019, the shareholders of ACI approved the Arrangement Agreement. In addition, on December 16, 2019, ACI received a "no-action letter" from the Canadian Competition Bureau confirming that the Commissioner of Competition does not at this time intend to challenge the proposed Arrangement. On December 20, 2019, ACI received the final order from the Court of Queen's Bench of Alberta approving the Arrangement. On February 18, 2020, the Alberta Utilities Commission issued a decision approving the Arrangement. The closing of the Arrangement remains subject to the receipt of approval from the British Columbia Utilities Commission, and the satisfaction or waiver of other customary closing conditions. ACI and the Consortium expect to close the Arrangement in the first half of 2020.

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Environmental Matters

12 Months Ended

Dec. 31, 2019

Environmental Remediation Obligations [Abstract]

Environmental Matters

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.

As at December 31, 2019, a liability of $13.8 million has been recorded on an undiscounted basis related to future environmental response costs (December 31, 2018 - $15.4 million) 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. As at December 31, 2019, AltaGas estimated the maximum liability associated with all of its sites to be approximately $39.9 million (December 31, 2018 - $40.1 million). 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.

As at December 31, 2019, AltaGas reported a regulatory asset of $17.7 million (December 31, 2018 - $19.9 million) for the portion of environmental response costs that are expected to be recoverable in future rates (Note 21).

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Income Taxes - Narrative (Details) - CAD ($) $ in Millions					6 Months Ended	12 Months Ended
	Jan. 01, 2022	Jan. 01, 2020	Jul. 01, 2019	Jan. 01, 2018	Jun. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Contingency
Statutory income tax rate (percent)						26.50%	27.00%
Tax-affected non-capital losses						$ 170.4
Canada Revenue Agency
Income Tax Contingency
Statutory income tax rate (percent)			11.00%		12.00%
Corporate tax rate (percent)				12.00%				11.00%
Canada Revenue Agency | Subsequent Event
Income Tax Contingency
Statutory income tax rate (percent)		10.00%
Forecasted decrease in effective tax rate (percent)		1.00%
Canada Revenue Agency | Subsequent Event | Forecast
Income Tax Contingency
Statutory income tax rate (percent)	8.00%

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Assets Held For Sale (Tables)

12 Months Ended

Dec. 31, 2019

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Assets Held for Sale

As at	December 31, 2019		December 31, 2018
Assets held for sale
Cash	$	—	$	4.9
Accounts receivable	—		85.2
Inventory	—		0.5
Property, plant and equipment	22.9		1,189.6
Intangible assets	—		248.7
Operating right-of-use assets	0.4		—
Goodwill	1.0		—
Other long-term assets	3.2		—
	$	27.5	$	1,528.9
Liabilities associated with assets held for sale
Accounts payable and accrued liabilities	$	—	$	23.8
Asset retirement obligations	0.2		10.8
Unamortized investment tax credits	3.2		—
Operating lease liabilities - long-term	0.4		—
Other long-term liabilities	—		136.8
	$	3.8	$	171.4

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Subsequent Events

12 Months Ended

Dec. 31, 2019

Subsequent Events [Abstract]

Subsequent Events

Subsequent Events

Subsequent events have been reviewed through February 27, 2020, the date on which these audited Consolidated Financial Statements were issued.

Segment Change

During the first quarter of 2020, AltaGas began evaluating the structure of its business following asset sales that were completed as part of its 2019 asset monetization program. As a result of these changes, AltaGas has refocused on its core Utilities and Midstream segments and will no longer have a Power segment beginning in the first quarter of 2020. Consistent with Management’s strategic view of the business and the basis on which it assesses performance and allocates resources, beginning in 2020, segmented financial information will be presented under the Utilities, Midstream, and Corporate/Other segments. The retail energy marketing operations for natural gas and electricity, which were previously included in the Midstream and Power segments, respectively, will be included within the Utilities segment, and other remaining Power assets will be included in within Corporate/Other.

Petrogas Put Option

On January 2, 2020, AltaGas advised that AltaGas Idemitsu Joint Venture Limited Partnership (AIJVLP) has received notice (the Put Notice) from SAM Holdings Ltd. (SAM) of its exercise of a put option (the Put Option) with respect to SAM's approximately one-third interest in Petrogas Energy Corp. (Petrogas). AIJVLP, a limited partnership owned 50 percent by AltaGas and 50 percent by Idemitsu Kosan Co., Ltd. (Idemitsu), owns the other approximately two-thirds of the outstanding common shares of Petrogas. Pursuant to the Petrogas unanimous shareholders agreement, a valid exercise of the Put Option by SAM after October 1, 2019, triggers a requirement for AIJVLP to purchase SAM's approximately one-third interest in Petrogas at the fair market value thereof, as determined by third-party valuators. AltaGas anticipates funding its portion of any such obligation with internal cash flow, the sale of remaining non-core assets and debt.

Constitution Pipeline

In February 2020, following evaluations of the diminished underlying economics for the proposed Constitution pipeline project, the partners ofConstitution Pipeline Company, LLC elected not to proceed with the project. AltaGas held a 10 percent equity interest in Constitution.Upon the acquisition of WGL, AltaGas assigned a value of $nil to Constitution.

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Accumulated Other Comprehensive Income - Summary of Reclassification from Accumulated Other Comprehensive Income (Details) - Total - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Defined benefit pension and PRB plans	$ 1.1	$ 0.7
Deferred income taxes	(0.3)	(0.2)
Reclassifications from AOCI, net	$ 0.8	$ 0.5

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Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2019

Goodwill and Intangible Assets Disclosure [Abstract]

Summary of Intangible Assets

The range of useful lives for intangible assets with a finite life is as follows:

Energy services relationships	5 to 19 years
Electricity service agreements	2 to 60 years
Software	3 to 10 years
Land rights	5 to 64 years
Franchises and consents	9 to 25 years
Extraction and Transmission (E&T) Contracts	25 years
Commodity contracts	5 to 20 years

As at	December 31, 2019							December 31, 2018
	Cost		Accumulated amortization			Net book value		Cost			Accumulated amortization			Net book value
E&T contracts	$	26.6	$	(15.2	)	$	11.4	$	26.6		$	(14.3	)	$	12.3
Electricity service agreements	8.5		(7.8		)	0.7		269.5			(25.9		)	243.6
Energy services relationships	91.6		(27.4		)	64.2		176.1			(33.8		)	142.3
Software	303.7		(101.2		)	202.5		293.9			(77.7		)	216.2
Land rights	1.1		(0.1		)	1.0		1.4			(0.2		)	1.2
Commodity contracts	327.1		(21.3		)	305.8		346.3			(6.3		)	340.0
Franchises and consents	—		—			—		5.0			—			5.0
Reclassified to assets held for sale (note 5)	—		—			—		(277.4		)	28.7			(248.7		)
	$	758.6	$	(173.0	)	$	585.6	$	841.4		$	(129.5	)	$	711.9

Summary of Estimated Amortization Expense of Intangible Assets

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:

2020	$	79.1
2021	$	70.6
2022	$	69.7
2023	$	62.3
2024	$	24.2
Thereafter	$	95.2

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Leases - Schedule of Future Lease Liability for Operating and Finance Lease (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Operating Leases
2020	$ 27.8
2021	27.1
2022	26.5
2023	24.5
2024	20.1
Thereafter	100.1
Total lease payments	226.1
Less: imputed interest	(45.0)
Total	181.1
Finance Leases
2020	3.5
2021	2.9
2022	2.0
2023	1.1
2024	0.4
Thereafter	2.0
Total lease payments	11.9
Less: imputed interest	(2.0)
Total	$ 9.9	$ 0.8

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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, but not control, over are accounted for using the equity method.

Hypothetical Liquidation at Book Value (HLBV) methodology is used for certain equity method investments as well as 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. The majority of AltaGas' HLBV investments were sold during 2019.

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 (loss) and are presented separately in "net income (loss) 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; determination as to whether a contract is or contains a lease; determination of the classification, term, and discount rate for leases; 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; purchase price allocations; 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 Gas (collectively the 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. Hampshire is regulated under a cost-of-service tariff by the Federal Energy Regulatory Commission (FERC).

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 Washington Gas executive and outside director retirement benefit plan obligations. The rabbi trust funds are invested in money market funds which are considered 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, natural gas liquids, 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, for which 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 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.

The 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	4 to 69 years
Midstream assets	2 to 45 years
Power generation assets	3 to 46 years
Corporate assets	3 to 7 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 after 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 Statements of Income (Loss). 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 Statements of Income (Loss).

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 to 19 years
Electricity service agreements	2 to 60 years
Software	3 to 10 years
Land rights	5 to 64 years
Franchises and consents	9 to 25 years
Extraction and Transmission (E&T) Contracts	25 years
Commodity contracts	5 to 20 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 principally 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. Management applies its best estimates and assumptions to determine the fair value of net assets acquired; however, the estimates are subject to further refinement of assumptions over a measurement period, which may be up to one year from the acquisition date. During the measurement period, adjustments to assets acquired and liabilities assumed may be recorded, with a corresponding impact to goodwill.

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 Statements of Income (Loss).

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 Statements of Income (Loss).

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 Statements of Income (Loss) 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 Statements of Income (Loss).

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.

Transaction costs for obtaining debt financing and reacquired debt costs are recorded as regulatory assets or liabilities, or as a reduction of the debt liability on the Consolidated Balance Sheets.

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 23 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.

Debt

AltaGas uses short-term debt in the form of commercial paper and advances under its syndicated bank credit facilities to fund seasonal cash requirements. Short-term obligations are excluded from current liabilities if AltaGas has the ability and the intent to refinance these obligations on a long-term basis. The ability to refinance is primarily demonstrated through the availability of long-term revolving committed credit facilities in an amount equal to or greater than the expected maximum short-term obligation.

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 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 24.

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 Statements of Income (Loss). 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 phantom unit plan (Phantom Plan, formerly the medium-term incentive plan) 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. The other portion of RU’s and PUs are valued at US$1 per unit. Upon vesting, the RUs and PUs are paid in cash. All PUs are also subject to a performance multiplier ranging from 0 to 2.4 dependent on the Corporation's performance relative to performance targets as approved by the Board of Directors. 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, the participant is entitled to payment upon retirement, 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, expected health care costs, and other actuarial factors including discount rates and mortality. 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 and credits 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 9.0 years and 13.2 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 (Loss) per Share

Basic net income (loss) 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.

Leases

The following are the Corporation’s significant accounting policies upon the adoption of ASC 842:

Leases – Lessee

AltaGas determines if an arrangement is a lease at inception. Operating leases are included in right-of-use (ROU) assets, current operating lease liabilities, and long-term operating lease liabilities in the Consolidated Balance Sheets. Finance leases are included in property, plant and equipment and current and long-term debt in the Consolidated Balance Sheets.

ROU assets represent the right to use an underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Operating lease ROU assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. AltaGas uses the rate implicit in the lease when readily determinable. When the implicit lease rate is not readily determinable, AltaGas uses its incremental borrowing rate to determine the present value of lease payments. AltaGas includes lessee options to renew or terminate the lease term in the determination of the ROU asset and lease liability when exercise is reasonably certain. The operating lease ROU asset is adjusted for lease payments made in advance of the commencement date, initial direct costs, and any lease incentives.

Operating lease expense is recognized on a straight-line basis over the lease term in "operating and administrative expense". Depreciation and interest expense are recorded on finance leases.

Leases – Lessor

AltaGas determines if an arrangement is a lease at inception. Lease payments under an operating lease are recognized on a straight-line basis over the term of the lease. Variable lease payments are recognized as revenue as the facts and circumstances on which the variable lease payment is based occur.

AltaGas does not include taxes assessed by governmental authorities, such as sales and related taxes, in the lease payments or variable lease payments.

Collaborative Arrangements

WGL has collaborative arrangements with a third party to facilitate the asset optimization program. The collaborative arrangements allocate a tiered or fixed percentage of profits or losses to the third party as compensation for its participation. The income recorded related to the collaborative arrangements totaled $1.4 million for the year ended December 31, 2019 (2018 - expense of $0.2 million).

ADOPTION OF NEW ACCOUNTING STANDARDS

Effective January 1, 2019, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU):

§ ASU No. 2016-02 “Leases” and all related amendments (collectively “ASC 842”). AltaGas has applied ASC 842 using the modified retrospective approach as of the effective date of the new standard. Comparative information has not been restated and continues to be reported under the previous lease guidance ASC 840. AltaGas has applied the package of transition practical expedients which permitted the Corporation to not reassess (a) whether any expired or existing contracts contain leases, (b) lease classifications for any expired or existing leases, and (c) initial direct costs for any existing leases. In addition, AltaGas applied the transition practical expedient that permitted the Corporation to grandfather its accounting policy for land easements that existed as of, or expired, before January 1, 2019. The transition practical expedient to not separate lease and non-lease components for its building, office equipment, transportation equipment, and vehicle leases has been elected for lessee arrangements. The transition practical expedient to not separate lease and non-lease components for its lessor arrangements related to certain assets has also been elected. AltaGas has applied the short-term lease recognition exemption under which lease arrangements with a term of twelve months or less, including extension options that are reasonably certain of being exercised, are exempt from the recognition of a right-of-use asset and lease liability and recorded as an expense over the term of the lease. This exemption applies to all classes of assets.

On adoption of ASC 842, all operating leases were recognized on the Consolidated Balance Sheets. The adoption resulted in an increase to long-term assets of approximately$181.0million and an increase to long-term liabilities of approximately$170.5million (net of the current portion that is recorded in current liabilities of approximately$23.3million). The lease related liabilities were measured using the present value of the remaining minimum lease payments for existing leases discounted using the Corporation’s incremental borrowing rate as of January 1, 2019. For operating leases, the associated right-of-use assets were measured at the amount equal to the lease liabilities on January 1, 2019, adjusted for any prepaid or accrued lease payments and the remaining balance of any lease incentives received. The adoption of ASC 842 did not impact lessor accounting, the Consolidated Statements of Income (Loss), or the Consolidated Statements of Cash Flows.

Please also refer to Note 10 of the Consolidated Financial Statements as at and for the year ended December 31, 2019 for further details;

§ ASU No. 2017-08 “Receivables – Nonrefundable Fees and Other Costs: Premium Amortization on Purchased Callable Debt Securities". The amendments in this ASU shorten the amortization period for certain callable debt securities held at a premium. Specifically, the amendments require the premium to be amortized to the earliest call date. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§ ASU No. 2017-11 “Earnings per Share and Derivatives and Hedging – Distinguishing Liabilities from Equity: Accounting for Certain Financial Instruments with Down Round Features, Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Non-controlling Interests with a Scope Exception”. The amendments in this ASU simplify the accounting for certain equity-linked financial instruments and embedded features with down round features that reduce the exercise price when pricing of a future round of financing is lower. The amendments in this ASU also require entities that present earnings per share under ASC 260 to recognize the effect of a down round feature in a freestanding equity-classified financial instrument only when it is triggered. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§ 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 adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§ 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 ASU clarify whether a transfer of assets is a contribution or an exchange transaction. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§ 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 adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and

§ 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 adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements.

FUTURE CHANGES IN ACCOUNTING PRINCIPLES

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 will adopt this standard on January 1, 2020 using a modified-retrospective approach through a cumulative-effect adjustment to retained earnings. AltaGas has completed scoping and evaluation activities for this new accounting standard, and has quantified the impact of this ASU on its opening Consolidated Balance Sheet as at January 1, 2020. Upon adoption, "accounts receivable, net of allowances" is expected to decrease by less than 1 percent of the outstanding accounts receivable balance, with an offsetting increase to "accumulated deficit".

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 post-retirement plans. 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. 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 ASU 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 ASU 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.

In March 2019, FASB issued ASU No. 2019-01 “Leases: Codification Improvements”. The amendments in this ASU provide a fair value exception for lessors that are not manufacturers or dealers, clarify the presentation of principal payments received under sales-type and direct finance leases on the statements of cash flows, and clarify transition disclosure requirements for the adoption of ASC 842. The amendments on the fair value exception and on the presentation on the statement of cash flows are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted. The amendment on the transition disclosure requirement is effective upon adoption of ASC 842. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In April 2019, FASB issued ASU No. 2019-04 “Financial Instruments - Credit Losses, Derivatives and Hedging, and Codification Improvements”. The amendments in this ASU provide clarification and improve the codification in recently issued accounting standards on credit losses (ASU 2016-13), hedging (ASU 2017-12), and recognizing and measuring financial instruments (ASU 2016-01). The amendments related to credit losses have the same effective date and transition requirements as ASU 2016-13, the amendments related to hedge accounting are effective as of the beginning of the first annual period beginning after issuance of this ASU and may be applied retrospectively to the date ASU 2017-12 was adopted or prospectively with some exceptions, and the amendments related to financial instruments are effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In May 2019, FASB issued ASU No. 2019-05 “Financial Instruments - Credit Losses: Targeted Transition Relief". The amendments in this ASU provide entities that have certain instruments within the scope of Subtopic 326-20 - Financial Instruments - Credit Losses - Measured at Amortized Cost (other than held-to-maturity debt securities) a one-time irrevocable option to elect fair value treatment on an eligible instrument-by-instrument basis. The effective date and transition methodology for the amendments in this ASU are the same as ASU 2016-13. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In November 2019, FASB issued ASU No. 2019-11 "Financial Instruments - Credit Losses: Codification Improvements". The amendments in this ASU provide clarification and improve the codification in ASU 2016-13. The effective date and transition methodology for the amendments in this ASU are the same as ASU 2016-13. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In December 2019, FASB issued ASU No. 2019-12 "Income Taxes: Simplifying the Accounting for Income Taxes". The amendments in this ASU simplify the accounting for income taxes by clarifying certain aspects of current guidance and removing some exceptions to the general principles in ASC 740. 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 assessing the impact of this ASU on its consolidated financial statements.

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Revenue - Contract Assets and Liabilities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Change in Contract with Customer, Asset
Balance, beginning of year	$ 58.8	$ 0.0
Additions	32.3	130.1
Transfers to held for sale	0.0	(72.2)
Transfers to accounts receivable	0.0	(3.7)
Foreign exchange translation	(2.5)	4.6
Balance, end of year	88.6	58.8
Change in Contract with Customer, Liability
Balance, beginning of year	2.2	0.0
Additions	1.9	2.6
Revenue recognized from contract liabilities	(2.2)	(0.5)
Foreign exchange translation	(0.2)	0.1
Balance, end of year	$ 1.7	$ 2.2

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Shareholders’ Equity (Tables)

12 Months Ended

Dec. 31, 2019

Stockholders' Equity Note [Abstract]

Schedule of Common Shares Issued and Outstanding

Common Shares Issued and Outstanding	Number of  shares	Amount
January 1, 2018	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 cost	—	13.3
Shares issued under DRIP	15,377,575	325.8
December 31, 2018	275,224,066	$	6,653.9
Shares issued for cash on exercise of options	76,177	1.2
Deferred taxes on share issuance cost	—	(3.9		)
Shares issued under DRIP	3,774,442	67.8
Issued and outstanding at December 31, 2019	279,074,685	$	6,719.0

Schedule of Preferred Shares Issued and Outstanding

As at	December 31, 2019				December 31, 2018
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	6,885,823	172.1			8,000,000	200.0
Series H	1,114,177	27.9			—	—
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		(28.5		)		(27.9		)
Fair value adjustment on WGL Acquisition (note 3)		—				4.1
	52,000,000	$	1,277.1		52,280,600	$	1,318.8

Summary of Cumulative Redeemable Preferred Shares

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)
Series A (e)	3.380	%	$0.84500	$25	September 30, 2020	Series B
Series B (f) (g)	Floating		Floating	$25	September 30, 2020	Series A
Series C (h)	5.290	%	US$1.32250	US$25	September 30, 2022	Series D
Series E (e)	5.393	%	$1.34825	$25	December 31, 2023	Series F
Series G (e)	4.620	%	$1.15575	$25	September 30, 2024	Series H
Series H (f) (g)	Floating		Floating	$25	September 30, 2024	Series G
Series I (i)	5.250	%	$1.31250	$25	December 31, 2020	Series J
Series K (j)	5.000	%	$1.25000	$25	March 31, 2022	Series L

(a) This table only includes those series of preferred shares that are currently issued and outstanding. The Corporation is authorized to issue up to8,000,000of each of Series D Shares, Series F Shares, and Series J Shares, and up to12,000,000of 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 J Shares, and Series L Shares are also redeemable for$25.50, and Series D Shares are redeemable forUS$25.50on 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 and Series H 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 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 of Series A Shares, Series E Shares, and Series G Shares 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 plus2.66 percent(Series A Shares),3.17 percent(Series E Shares), and3.06 percent(Series G Shares).

(f) Holders of Series B Shares and Series H 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 plus2.66 percent(Series B Shares) and3.06 percent(Series H Shares). 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, 2019, the floating quarterly dividend rate is$0.26803per share for Series B Shares and$0.29289per share for Series H Shares for the period starting December 31, 2019 to, but excluding, March 31, 2020.

(g) Series B Shares can be redeemed for$25.50per 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. Series H Shares can be redeemed for$25.50per share on any date after September 30, 2019 that is not a Series H 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 plus3.58 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 plus4.19 percent, provided that, in any event, such rate shall not be less than5.25 percentper 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 plus3.80 percent, provided that, in any event, such rate shall not be less than5.00 percentper annum.

Summary of Share Option Activity

The following table summarizes information about the Corporation’s share options:

	December 31, 2019				December 31, 2018
As at	Options outstanding				Options outstanding
	Number of options		Exercise price (a)		Number of options		Exercise price (a)
Share options outstanding, beginning of year	6,309,183		$	25.18	4,533,761		$	32.35
Granted	2,287,385		19.12		2,811,460		16.69
Exercised	(76,177	)	14.52		(57,275	)	20.68
Forfeited	(1,165,435	)	27.31		(878,013	)	36.47
Expired	(311,000	)	36.16		(100,750	)	14.60
Share options outstanding, end of year	7,043,956		$	22.49	6,309,183		$	25.18
Share options exercisable, end of year	2,921,642		$	27.70	2,897,723		$	32.01

(a) Weighted average.

Summary of Employee Share Option Plan

The following table summarizes the employee share option plan as at December 31, 2019:

	Options outstanding				Options exercisable
	Number outstanding	Weighted average exercise price		Weighted average remaining contractual life	Number exercisable	Weighted average exercise price		Weighted average remaining contractual life
$14.52 to $18.00	2,557,328	$	15.19	4.98	638,385	$	14.62	4.79
$18.01 to $25.08	1,961,805	19.78		4.77	305,750	21.05		0.96
$25.09 to $46.70	2,524,823	32.00		2.72	1,977,507	32.95		2.39
	7,043,956	$	22.49	4.11	2,921,642	$	27.70	2.77

Summary of Fair Value of Options Granted

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	2019	2018
Fair value per options ($)	2.30	1.27
Risk-free interest rate (%)	1.48	1.99
Expected life (years)	6	6
Expected volatility (%)	24.84	23.23
Annual dividend per share ($) (a)	0.96	1.18
Forfeiture rate (%)	—	—

(a) Annual dividend per share is calculated based on a weighted average share price and forward dividend yields as the grant dates.

Schedule of MTIP and DSUP Activity

PUs, RUs, and DSUs (number of units)	2019		2018
Balance, beginning of year	9,908,154		564,549
Acquired (a)	—		5,291,621
Converted to cash (a)	—		(5,291,621	)
Granted	674,971		9,502,347
Exercised	(113,668	)	—
Vested and paid out	(677,667	)	(148,154	)
Forfeited	(3,377,962	)	(66,522	)
Units in lieu of dividends	71,003		55,934
Outstanding, end of year	6,484,831		9,908,154

(a) Upon close of the WGL Acquisition in 2018, AltaGas acquired WGL’s PUs. These were converted to a fixed cash amount at a value of US$1.00 per unit. At December 31, 2019, the WGL PUs comprised approximately 4.9 million of the outstanding units (December 31, 2018 - 8.9 million).

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Commitments, Guarantees, and Contingencies (Tables)

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Summary of Future Payment Commitments

Future payments of these commitments as at December 31, 2019 are estimated as follows:

	2020		2021		2022		2023		2024		2025 & beyond		Total
Gas purchase (a)	$	2,374.0	$	2,488.2	$	2,323.6	$	2,076.1	$	1,959.5	$	22,772.0	$	33,993.4
Propane purchase (b)	220.2		127.2		94.9		86.5		58.4		127.1		714.3
Electricity purchase (c)	567.2		318.1		160.0		56.4		11.0		0.4		1,113.1
Service agreements (d) (e) (f)	58.7		44.0		28.2		23.4		22.9		309.1		486.3
Pipeline and storage services (g)	721.2		652.5		627.8		600.4		550.5		3,876.7		7,029.1
Capital projects (h)	6.9		—		—		—		—		—		6.9
Operating leases (i)	27.8		27.1		26.5		24.5		20.1		100.1		226.1
Environmental (j)	6.5		4.3		1.0		1.0		0.6		0.4		13.8
Merger commitments (k)	8.2		3.8		1.9		1.9		1.9		4.3		22.0
	$	3,990.7	$	3,665.2	$	3,263.9	$	2,870.2	$	2,624.9	$	27,190.1	$	43,605.0

(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) AltaGas enters into contracts to purchase propane for its operations at RIPET. These contracts are used to ensure that there is an adequate supply of propane to meet shipment commitments and to minimize exposure to market price fluctuations. Propane purchase commitments are valued based on forward prices, which may fluctuate significantly from period to period.

(c) AltaGas enters into contracts to purchase electricity from various suppliers for its non-utility business. Electricity purchase commitments are based on existing fixed price and fixed volume contracts, and include US$17.4 million of commitments related to renewable energy credits.

(d) In 2014, AltaGas' Blythe facility entered into a Long-Term Service Agreement (LTSA) with Siemens to complete various upgrade and maintenance services on the Combustion Turbines (CT) at the Blythe facility over 124,000 equivalent operating hours per CT, or 25 years, whichever comes first. The LTSA has variable fees on a per equivalent operating hour basis. As at December 31, 2019, the total commitment was $167.9 million payable over the next 16 years, of which $45.4 million is expected to be paid over the next five years.

(e) In 2017, AltaGas entered into a 12-year service agreement for tug services to support the marine operations of RIPET.

(f) In 2015, AltaGas entered into a Project Agreement that contemplated the sublease of lands from Ridley Terminals Inc. (RTI), provision of certain terminal services, and access to RTI's terminal facilities to support RIPET's operations for an initial term of 20 years ending in 2039. In 2019, RILE LP and RTI executed a Terminal Services Agreement that formalized the concepts outlined in the Project Agreement.

(g) Pipeline and storage commitments include minimum payments for natural gas transportation, storage and peaking contracts that have expiration dates through 2044.

(h) Commitments for capital projects. Estimated amounts are subject to variability depending on the actual construction costs.

(i) Operating leases include lease arrangements for office spaces, vehicles, rail cars, land, and office and other equipment.

(j) Environmental commitments include committed payments related to certain environmental response costs.

(k) Represents the estimated future payments of merger commitments that have been accrued but not paid. In addition, there are certain additional merger commitments that will be expensed when costs are incurred in the future, including the investment of up toUS$70 millionover atenyear period to further extend natural gas service, investment ofUS$8 millionfor leak mitigation withinthreeyears of the merger, hiring damage prevention trainers in each jurisdiction for a total ofUS$2 millionoverfiveyears, and developing15megawatts of either electric grid energy storage or Tier 1 renewable resources within five years. As at December 31, 2019, the cumulative amount of merger commitments that have been expensed but not yet paid is approximatelyUS$17 million.

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Financial Instruments and Financial Risk Management - Allowance for Credit Loss (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Balance, beginning of year
Balance, beginning of year	$ 54.7	$ 2.4
Foreign exchange translation	(2.6)	0.1
New allowance	27.5	53.1
Change in allowance	(9.2)	(0.9)
Allowance applied to uncollectible customer accounts	(37.2)	0.0
Balance, end of year	33.2	$ 54.7
Disposal group, allowance for doubtful receivables	$ 8.1

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Long-Term Investments and Other Assets - Schedule of Long-Term and Other Investments (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Investments, All Other Investments [Abstract]
Investments in publicly-traded entities	$ 4.3	$ 8.4
Loan to affiliate	45.0	45.0
Deferred lease receivable	17.4	24.4
Debt issuance costs associated with credit facilities	6.2	7.9
Refundable deposits	8.9	16.2
Prepayment on long-term service agreements	80.6	82.5
Cash calls from joint venture partners	9.5	0.0
Contract asset (note 24)	30.0	11.5
Rabbi trust (notes 28 and 31)	32.0	61.7
Other long-term receivables (note 29)	33.1	0.0
Other	29.5	25.5
Long-term investments and other assets	$ 296.5	$ 283.1

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Shareholders’ Equity - Narrative (Details)		12 Months Ended
	Dec. 20, 2019 CAD ($)	Dec. 31, 2019 $ / shares	Dec. 31, 2019 CAD ($)	Dec. 31, 2018 CAD ($) shares	Dec. 31, 2019 CAD ($) plan shares	Dec. 31, 2017 shares
Share-based Compensation Arrangement by Share-based Payment Award
Number of dividend reinvestment plans (plan) | plan					2
Equity discount rate (percent)					3.00%
Gain on redemption of preferred shares	$ 3,500,000		$ 3,500,000	$ 0
Common shares outstanding (shares) | shares				275,200,000	279,100,000
Balacne outstanding (units) | shares				9,908,154	6,484,831	564,549
Share Option Plan
Share-based Compensation Arrangement by Share-based Payment Award
Shares reserved for issuance | shares					13,915,160
Unexpensed fair value of share option compensation cost				$ 3,700,000	$ 4,500,000
Aggregate intrinsic value of options exercisable				0	3,300,000
Intrinsic value of options outstanding				0	12,100,000
Intrinsic value of options exercised			$ 400,000	300,000
Mid-Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award
Vesting period			36 months
Mid-Term Incentive And Deferred Share Unit Plans
Share-based Compensation Arrangement by Share-based Payment Award
Compensation expense			$ 21,700,000	16,600,000
Unrecognized compensation expense				$ 26,900,000	$ 21,800,000
Minimum | Share Option Plan
Share-based Compensation Arrangement by Share-based Payment Award
Options term			6 years
Maximum | Share Option Plan
Share-based Compensation Arrangement by Share-based Payment Award
Options term			10 years
Vesting period			4 years
Washington Gas
Share-based Compensation Arrangement by Share-based Payment Award
Price per unit acquired (per unit) | $ / shares		$ 1.00
Balacne outstanding (units) | shares				8,866,795	4,920,510
Preferred shares | Washington Gas | $4.25 series
Share-based Compensation Arrangement by Share-based Payment Award
Preferred stock par value (usd per share) | $ / shares		4.25
Preferred shares | Washington Gas | $4.80 series
Share-based Compensation Arrangement by Share-based Payment Award
Preferred stock par value (usd per share) | $ / shares		4.80
Preferred shares | Washington Gas | $5.00 series
Share-based Compensation Arrangement by Share-based Payment Award
Preferred stock par value (usd per share) | $ / shares		$ 5.00

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Consolidated Statements of Comprehensive Income (Loss) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
Net income (loss) after taxes	$ 840.3	$ (453.7)
Other comprehensive income (loss), net of taxes
Gain (loss) on foreign currency translation	(406.2)	458.5
Unrealized gain (loss) on net investment hedge (note 23)	60.0	(80.2)
Actuarial gain (loss) on pension plans and post-retirement benefit (PRB) plans (note 28)	12.0	(10.8)
Reclassification of actuarial gains and prior service credits on defined benefit (DB) and post-retirement benefit plans (PRB) to net income (note 28)	0.8	0.5
Curtailment of DB and PRB plan (note 28)	0.0	2.7
Adoption of ASU 2016-01	0.0	7.1
Other comprehensive income (loss) from equity investees	(0.7)	2.1
Total other comprehensive income (loss) (OCI), net of taxes (note 22)	(334.1)	379.9
Comprehensive income (loss) attributable to controlling interests and non-controlling interests, net of taxes	506.2	(73.8)
Comprehensive income (loss) attributable to:
Non-controlling interests	6.8	(18.6)
Controlling interests	$ 499.4	$ (55.2)

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Document and Entity Information	12 Months Ended
	Dec. 31, 2019 shares
Document And Entity Information [Abstract]
Document Type	40-F
Amendment Flag	false
Document Period End Date	Dec. 31, 2019
Document Fiscal Year Focus	2019
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	279,074,685.000000
Entity Interactive Data Current	Yes

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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, 2019	Dec. 31, 2018
Defined Benefit
Defined Benefit Plan Disclosure
Past service credit (cost)	$ (0.1)	$ (0.5)
Net actuarial gain (loss)	(24.3)	(19.4)
Recognized in AOCI pre-tax	(24.4)	(19.9)
Increase (decrease) by the amount included in deferred tax liabilities	9.3	4.6
Net amount in AOCI after-tax	(15.1)	(15.3)
Defined Benefit | Canada
Defined Benefit Plan Disclosure
Past service credit (cost)	(0.2)	(0.3)
Net actuarial gain (loss)	(9.4)	(8.7)
Recognized in AOCI pre-tax	(9.6)	(9.0)
Increase (decrease) by the amount included in deferred tax liabilities	2.3	2.4
Net amount in AOCI after-tax	(7.3)	(6.6)
Defined Benefit | United States
Defined Benefit Plan Disclosure
Past service credit (cost)	0.1	(0.2)
Net actuarial gain (loss)	(14.9)	(10.7)
Recognized in AOCI pre-tax	(14.8)	(10.9)
Increase (decrease) by the amount included in deferred tax liabilities	7.0	2.2
Net amount in AOCI after-tax	(7.8)	(8.7)
Post- Retirement Benefits
Defined Benefit Plan Disclosure
Past service credit (cost)	0.3	0.4
Net actuarial gain (loss)	17.5	(5.5)
Recognized in AOCI pre-tax	17.8	(5.1)
Increase (decrease) by the amount included in deferred tax liabilities	(8.9)	1.4
Net amount in AOCI after-tax	8.9	(3.7)
Post- Retirement Benefits | Canada
Defined Benefit Plan Disclosure
Past service credit (cost)	0.3	0.4
Net actuarial gain (loss)	(0.7)	(0.5)
Recognized in AOCI pre-tax	(0.4)	(0.1)
Increase (decrease) by the amount included in deferred tax liabilities	0.1	0.0
Net amount in AOCI after-tax	(0.3)	(0.1)
Post- Retirement Benefits | United States
Defined Benefit Plan Disclosure
Past service credit (cost)	0.0	0.0
Net actuarial gain (loss)	18.2	(5.0)
Recognized in AOCI pre-tax	18.2	(5.0)
Increase (decrease) by the amount included in deferred tax liabilities	(9.0)	1.4
Net amount in AOCI after-tax	$ 9.2	$ (3.6)

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Pension Plans and Retiree Benefits - Schedule of Net Periodic Benefit Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit
Defined Benefit Plan Disclosure
Current service cost	$ 26.4	$ 18.6
Interest cost	69.0	39.2
Expected return on plan assets	(75.1)	(50.4)
Amortization of past service cost (credit)	0.5	0.2
Amortization of net actuarial loss	12.6	8.3
Plan settlements	4.1
Other	0.0
Net benefit cost (income) recognized	37.5	15.9
Post- Retirement Benefits
Defined Benefit Plan Disclosure
Current service cost	8.5	5.4
Interest cost	19.2	11.0
Expected return on plan assets	(37.1)	(21.6)
Amortization of past service cost (credit)	(21.9)	(11.5)
Amortization of net actuarial loss	0.1	0.4
Plan settlements	0.0
Other	0.9
Net benefit cost (income) recognized	(30.3)	(16.3)
Canada | Defined Benefit
Defined Benefit Plan Disclosure
Current service cost	2.6	2.4
Interest cost	1.2	1.2
Expected return on plan assets	(0.5)	(0.5)
Amortization of past service cost (credit)	0.1	0.1
Amortization of net actuarial loss	0.9	0.6
Plan settlements	0.0
Other	0.0
Net benefit cost (income) recognized	4.3	3.8
Canada | Post- Retirement Benefits
Defined Benefit Plan Disclosure
Current service cost	0.0	0.1
Interest cost	0.1	0.1
Expected return on plan assets	0.0	0.0
Amortization of past service cost (credit)	0.0	0.0
Amortization of net actuarial loss	0.0	0.0
Plan settlements	0.0
Other	0.0
Net benefit cost (income) recognized	0.1	0.2
United States | Defined Benefit
Defined Benefit Plan Disclosure
Current service cost	23.8	16.2
Interest cost	67.8	38.0
Expected return on plan assets	(74.6)	(49.9)
Amortization of past service cost (credit)	0.4	0.1
Amortization of net actuarial loss	11.7	7.7
Plan settlements	4.1
Other	0.0
Net benefit cost (income) recognized	33.2	12.1
United States | Post- Retirement Benefits
Defined Benefit Plan Disclosure
Current service cost	8.5	5.3
Interest cost	19.1	10.9
Expected return on plan assets	(37.1)	(21.6)
Amortization of past service cost (credit)	(21.9)	(11.5)
Amortization of net actuarial loss	0.1	0.4
Plan settlements	0.0
Other	0.9
Net benefit cost (income) recognized	$ (30.4)	$ (16.5)

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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, 2019 CAD ($)
Defined Benefit
Defined Benefit Plan Disclosure
Expected employer contributions, 2020	$ 37.0
Expected benefit payments:
2020	104.6
2021	85.1
2022	93.3
2023	90.0
2024	90.7
2025 - 2028	474.1
Post- Retirement Benefits
Defined Benefit Plan Disclosure
Expected employer contributions, 2020	3.2
Expected benefit payments:
2020	23.8
2021	22.6
2022	22.5
2023	22.3
2024	22.1
2025 - 2028	$ 112.6

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Variable Interest Entities

12 Months Ended

Dec. 31, 2019

VARIABLE INTEREST ENTITIES [Abstract]

Variable Interest Entities

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:

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 was 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 provide 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 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.

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. With the 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's operating costs by AltaGas LPG in accordance with the terms set out in the agreement.

Disposal of Consolidated VIE Investments

Prior to the close of the U.S. distributed generation asset sale in the third quarter of 2019, a subsidiary of WGL was the primary beneficiary of SFGF LLC, SFRC LLC, SFGF II LLC, SFEE LLC, and ASD Solar LP, 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. These VIEs were consolidated until the close of the distributed generation asset sale (Note 4). As at December 31, 2019, these entities are no longer VIEs of AltaGas.

The following table represents amounts included in the Consolidated Balance Sheets attributable to AltaGas’ consolidated VIEs:

As at	December 31, 2019			December 31, 2018
Current assets	$	6.4		$	1,383.5
Property, plant and equipment	371.1			619.2
Long-term investments and other assets	53.3			48.0
Operating right-of-use assets	0.1			—
Current liabilities	(3.6		)	(161.8		)
Asset retirement obligations	(3.3		)	(0.9		)
Other long-term liabilities	(0.1		)	(3.0		)
Net assets	$	423.9		$	1,885.0

The decrease in current assets, property, plant and equipment, and current liabilities associated with AltaGas’ consolidated VIEs as at December 31, 2019 compared to December 31, 2018 is primarily due to the sale of Northwest Hydro Limited Partnership in January 2019 and the sale of VIEs included in the sale of WGL's distributed generation portfolio (Note 4).

Disposal of Unconsolidated VIE Investments

Prior to the sale of AltaGas' investment in Meade and indirect, non-operating interest in Central Penn (Note 4), WGL Midstream owned a 55 percent interest in Meade (21 percent indirect interest in Central Penn). Although WGL Midstream held a greater than 50 percent interest in Meade, Meade was not consolidated by WGL Midstream and instead was accounted for under the equity method of accounting. WGL Midstream was not the primary beneficiary of Meade as it did not have the power to direct the activities most significant to the economic performance of Meade. WGL Midstream applied the HLBV equity method of accounting and any profits and losses were included in "income from equity investments" in the accompanying Consolidated Statements of Income (Loss) and were added to or subtracted from the carrying amount of AltaGas' investment balance until the close of the Meade sale. As at December 31, 2019, Meade is no longer a VIE of AltaGas.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2019

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

As at December 31	2019			2018
Balance, beginning of year	$	500.6		$	88.3
Obligations acquired (note 3)	—			399.1
New obligations	7.0			3.3
Obligations settled	(2.5		)	(4.2		)
Disposals	(6.2		)	(1.6		)
Revision in estimated cash flow	(128.5		)	3.8
Accretion expense (a)	18.9			12.3
Foreign exchange translation	(20.7		)	20.3
Reclassified to liabilities associated with assets held for sale (note 5)	(0.2		)	(10.8		)
Total	$	368.4		$	510.5
Less current portion (included in accounts payable and accrued liabilities)	(6.4		)	(9.9		)
Balance, end of year	$	362.0		$	500.6

(a) Certain amounts relating to Utility asset retirement obligations are recorded through regulatory assets or liabilities on the Consolidated Balance Sheets due to regulatory treatment. The remaining portion is recorded through the Consolidated Statements of Income (Loss).

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, 2019 was $727.0 million (December 31, 2018 - $770.0 million).

The asset retirement obligations have been recorded in the Consolidated Financial Statements at estimated values discounted at rates between 2.0 and 8.5 percent (December 31, 2018 - between 1.5 to 8.5 percent) and are expected to be incurred between 2020 and 2137 (December 31, 2018 - between 2019 and 2064). No assets have been legally restricted for settlement of the estimated liability.

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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2019

Regulated Operations [Abstract]

Regulatory Assets and Liabilities

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 Statements of Income (Loss) by a non-rate-regulated entity. These deferred regulatory assets and liabilities are included in the Consolidated Statements of Income (Loss) 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 Statements of Income (Loss) 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 at December 31, 2019 and 2018, over which the Corporation expects to realize or settle the assets or liabilities:

As at December 31	2019		2018		Recovery Period
Regulatory assets - current
Deferred cost of gas (a)	$	7.6	$	20.4	Less than one year
Accelerated replacement recovery mechanisms (b)	2.5		—		Less than one year
Interruptible sharing (a)	2.7		0.6		Less than one year
	$	12.8	$	21.0
Regulatory assets - non-current
Deferred regulatory costs (a) (c)	$	149.5	$	215.5	1 - 51 years
Future recovery of pension and other retirement benefits (a)	128.2		192.9		Various
Future recovery of non-retirement employee benefits (a) (d)	19.4		21.3		Various
Deferred pension costs (e)	—		7.8		—
Deferred environmental costs (a) (f)	17.7		19.9		Various
Deferred loss on debt transactions and derivative instruments (a) (g)	99.2		109.3		Various
Deferred future income taxes (a) (h)	42.7		67.0		Various
Energy efficiency program - Maryland (i)	12.1		4.6		Various
Other	17.9		24.7		Various
	$	486.7	$	663.0
Regulatory liabilities - current
Deferred cost of gas (a)	$	60.2	$	71.2	Less than one year
Refundable tax credit (j)	1.9		3.8		Less than one year
Federal income tax rate change (k)	33.1		26.2		Less than one year
Virginia rate refund (l)	40.4		—		Less than one year
Accelerated replacement recovery mechanisms (b)	0.4		5.2		Less than one year
Interruptible sharing (a)	0.4		2.3		Less than one year
Other	9.1		6.2		Less than one year
	$	145.5	$	114.9
Regulatory liabilities - non-current
Refundable tax credit (j)	3.9		6.1		2 years
Future expense of pension and other retirement benefits (a)	261.2		166.7		Various
Future removal and site restoration costs (m)	483.9		514.7		Various
Deferred gain on debt transactions and derivative instruments (a) (g)	1.6		1.8		Various
Federal income tax rate change (k)	628.3		698.4		Various
Other	4.3		5.1		Various
	$	1,383.2	$	1,392.8

(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) Represents amounts for deferred over or under collections of surcharges associated with Washington Gas' accelerated pipeline recovery programs in the District of Columbia, Maryland, and Virginia.

(c) Includes deferred gas costs and fair value of derivatives, which are not included in customer bills until settled.

(d) 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.

(e) In 2018, this balance related to previously deferred pension and other post-retirement benefits expenses that were fully amortized in 2019.

(f) This balance represents allowed environmental remediation expenditures at SEMCO Gas and Washington Gas sites to be recovered through rates.

(g) 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. As at December 31, 2019, this also includes a fair value adjustment of $79.8 million (December 31, 2018 - $87.3 million) recorded on the WGL Acquisition (Note 3).

(h) This balance reflects the amount of deferred income taxes expected to be refunded, or recovered from, customers in future rates.

(i) Represents amounts for deferred credits associated with Washington Gas' participation in the energy conservation and efficiency program EmPower in Maryland.

(j) 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.

(k) The Tax Cuts and Jobs Act (TCJA) was enacted on December 22, 2017, and required the Corporation to revalue its U.S. deferred tax assets and liabilities in 2018 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.

(l) Represents estimated refunds related to customers billed at a higher rate during the interim period as part of the 2019 Virginia rate case.

(m) 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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Leases (Tables)

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Components of Lease cost

The components of lease expense were as follows:

	Year Ended December 31, 2019
Operating lease cost (includes variable lease payments)	$	29.2
Finance lease cost
Amortization of right-of-use assets	$	3.4
Interest on lease liabilities	0.3
Total finance lease cost	$	3.7
Total lease cost	$	32.9

Supplemental cash flow information related to leases was as follows:

	Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from finance leases	$	(0.3	)
Operating cash flows from operating leases	$	(20.6	)
Financing cash flows from finance leases (a)	$	(3.7	)
Right-of-use assets obtained in exchange for new lease liabilities
Operating leases	$	50.4
Finance leases	$	5.4

(a) Included within repayment of long-term debt on the Consolidated Statements of Cash Flows.

As at	December 31, 2019
Weighted average remaining lease term (years)
Operating leases	10.9
Finance leases	5.2
Weighted average discount rate (%)
Operating leases	3.51
Finance leases	3.68

Supplemental Balance Sheet Location

Supplemental balance sheet information related to leases was as follows:

As at	December 31, 2019
Operating Leases
Operating lease right-of-use assets
Long-term	$	169.8
Included in assets held for sale (note 5)	0.4
Total operating lease right-of-use assets	$	170.2
Operating lease liabilities
Current	$	(27.3	)
Long-term	(153.4		)
Included in liabilities associated with assets held for sale (note 5)	(0.4		)
Total operating lease liabilities	$	(181.1	)
Finance Leases
Property and equipment, gross	$	13.2
Accumulated depreciation	(3.3		)
Property and equipment, net	$	9.9
Current portion of long-term debt	$	(3.5	)
Long-term debt	(6.4		)
Total finance lease liabilities	$	(9.9	)

Operating Lease Liability, Future Minimum Payments

Maturity analysis of lease liabilities was as follows:

	Operating Leases			Finance Leases
2020	$	27.8		$	3.5
2021	27.1			2.9
2022	26.5			2.0
2023	24.5			1.1
2024	20.1			0.4
Thereafter	100.1			2.0
Total lease payments	226.1			11.9
Less: imputed interest	(45.0		)	(2.0		)
Total	$	181.1		$	9.9

Finance Lease Liability, Future Minimum Payments

Maturity analysis of lease liabilities was as follows:

	Operating Leases			Finance Leases
2020	$	27.8		$	3.5
2021	27.1			2.9
2022	26.5			2.0
2023	24.5			1.1
2024	20.1			0.4
Thereafter	100.1			2.0
Total lease payments	226.1			11.9
Less: imputed interest	(45.0		)	(2.0		)
Total	$	181.1		$	9.9

Maturity Analysis of Lease Receivables

Maturity analysis of lease receivables was as follows:

	Operating Leases
2020	$	118.3
2021	115.4
2022	115.6
2023	115.9
2024	47.8
Thereafter	477.5
Total	$	990.5

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Provisions on Assets (Tables)

12 Months Ended

Dec. 31, 2019

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Provisions on Assets

Year Ended December 31	2019		2018
Utilities	$	—	$	193.7
Midstream	35.2		153.7
Power	380.6		381.3
	$	415.8	$	728.7

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Income Taxes - Schedule of Deferred Income Tax Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
PP&E and intangible assets	$ 1,450.6	$ 1,764.6
Regulatory assets	(204.1)	(166.3)
Tax pools, deferred financing, and compensation	(138.2)	(453.6)
Other	(161.2)	(209.9)
Valuation allowance	12.0	23.1
Net deferred income tax liabilities	$ 959.1	$ 957.9

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Accumulated Other Comprehensive Income - Schedule of Accumulated Other Comprehensive Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	$ 7,640.2
Total other comprehensive income (loss) (OCI), net of taxes (note 22)	(334.1)	$ 379.9
Balance, end of year	7,368.8	7,640.2
Total
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	579.0	199.1
OCI before reclassification	(323.5)	355.9
Amounts reclassified from AOCI	1.1	0.7
Adoption Of ASU No. 2016-01 (note 2)		7.1
Curtailment of DB and PRB plan		4.2
Current period OCI (pre-tax)	(322.4)	367.9
Income tax on amounts retained in AOCI	(11.4)	13.7
Income tax on amounts reclassified to earnings	(0.3)	(0.2)
Income tax on amounts related to curtailment of DB and PRB plan		(1.5)
Total other comprehensive income (loss) (OCI), net of taxes (note 22)	(334.1)	379.9
Balance, end of year	244.9	579.0
Available-for-sale
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	0.0	(7.1)
OCI before reclassification	0.0	0.0
Amounts reclassified from AOCI	0.0	0.0
Adoption Of ASU No. 2016-01 (note 2)		7.1
Curtailment of DB and PRB plan		0.0
Current period OCI (pre-tax)	0.0	7.1
Income tax on amounts retained in AOCI	0.0	0.0
Income tax on amounts reclassified to earnings	0.0	0.0
Income tax on amounts related to curtailment of DB and PRB plan		0.0
Total other comprehensive income (loss) (OCI), net of taxes (note 22)	0.0	7.1
Balance, end of year	0.0	0.0
Defined benefit pension and PRB plans
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	(19.0)	(11.4)
OCI before reclassification	15.2	(14.1)
Amounts reclassified from AOCI	1.1	0.7
Adoption Of ASU No. 2016-01 (note 2)		0.0
Curtailment of DB and PRB plan		4.2
Current period OCI (pre-tax)	16.3	(9.2)
Income tax on amounts retained in AOCI	(3.2)	3.3
Income tax on amounts reclassified to earnings	(0.3)	(0.2)
Income tax on amounts related to curtailment of DB and PRB plan		(1.5)
Total other comprehensive income (loss) (OCI), net of taxes (note 22)	12.8	(7.6)
Balance, end of year	(6.2)	(19.0)
Hedge net investments
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	(209.2)	(129.0)
OCI before reclassification	68.2	(90.6)
Amounts reclassified from AOCI	0.0	0.0
Adoption Of ASU No. 2016-01 (note 2)		0.0
Curtailment of DB and PRB plan		0.0
Current period OCI (pre-tax)	68.2	(90.6)
Income tax on amounts retained in AOCI	(8.2)	10.4
Income tax on amounts reclassified to earnings	0.0	0.0
Income tax on amounts related to curtailment of DB and PRB plan		0.0
Total other comprehensive income (loss) (OCI), net of taxes (note 22)	60.0	(80.2)
Balance, end of year	(149.2)	(209.2)
Translation foreign operations
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	801.4	342.9
OCI before reclassification	(406.2)	458.5
Amounts reclassified from AOCI	0.0	0.0
Adoption Of ASU No. 2016-01 (note 2)		0.0
Curtailment of DB and PRB plan		0.0
Current period OCI (pre-tax)	(406.2)	458.5
Income tax on amounts retained in AOCI	0.0	0.0
Income tax on amounts reclassified to earnings	0.0	0.0
Income tax on amounts related to curtailment of DB and PRB plan		0.0
Total other comprehensive income (loss) (OCI), net of taxes (note 22)	(406.2)	458.5
Balance, end of year	395.2	801.4
Equity investee
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	5.8	3.7
OCI before reclassification	(0.7)	2.1
Amounts reclassified from AOCI	0.0	0.0
Adoption Of ASU No. 2016-01 (note 2)		0.0
Curtailment of DB and PRB plan		0.0
Current period OCI (pre-tax)	(0.7)	2.1
Income tax on amounts retained in AOCI	0.0	0.0
Income tax on amounts reclassified to earnings	0.0	0.0
Income tax on amounts related to curtailment of DB and PRB plan		0.0
Total other comprehensive income (loss) (OCI), net of taxes (note 22)	(0.7)	2.1
Balance, end of year	$ 5.1	$ 5.8

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2019

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, but not control, over are accounted for using the equity method.

Hypothetical Liquidation at Book Value (HLBV) methodology is used for certain equity method investments as well as 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. The majority of AltaGas' HLBV investments were sold during 2019.

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 (loss) and are presented separately in "net income (loss) 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; determination as to whether a contract is or contains a lease; determination of the classification, term, and discount rate for leases; 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; purchase price allocations; 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 Gas (collectively the 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. Hampshire is regulated under a cost-of-service tariff by the Federal Energy Regulatory Commission (FERC).

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 Washington Gas executive and outside director retirement benefit plan obligations. The rabbi trust funds are invested in money market funds which are considered 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, natural gas liquids, 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, for which 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 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.

The 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	4 to 69 years
Midstream assets	2 to 45 years
Power generation assets	3 to 46 years
Corporate assets	3 to 7 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 after 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 Statements of Income (Loss). 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 Statements of Income (Loss).

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 to 19 years
Electricity service agreements	2 to 60 years
Software	3 to 10 years
Land rights	5 to 64 years
Franchises and consents	9 to 25 years
Extraction and Transmission (E&T) Contracts	25 years
Commodity contracts	5 to 20 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 principally 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. Management applies its best estimates and assumptions to determine the fair value of net assets acquired; however, the estimates are subject to further refinement of assumptions over a measurement period, which may be up to one year from the acquisition date. During the measurement period, adjustments to assets acquired and liabilities assumed may be recorded, with a corresponding impact to goodwill.

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 Statements of Income (Loss).

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 Statements of Income (Loss).

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 Statements of Income (Loss) 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 Statements of Income (Loss).

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.

Transaction costs for obtaining debt financing and reacquired debt costs are recorded as regulatory assets or liabilities, or as a reduction of the debt liability on the Consolidated Balance Sheets.

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 23 for 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.

Debt

Debt

AltaGas uses short-term debt in the form of commercial paper and advances under its syndicated bank credit facilities to fund seasonal cash requirements. Short-term obligations are excluded from current liabilities if AltaGas has the ability and the intent to refinance these obligations on a long-term basis. The ability to refinance is primarily demonstrated through the availability of long-term revolving committed credit facilities in an amount equal to or greater than the expected maximum short-term obligation.

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 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 24.

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 Statements of Income (Loss). 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 phantom unit plan (Phantom Plan, formerly the medium-term incentive plan) 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. The other portion of RU’s and PUs are valued at US$1 per unit. Upon vesting, the RUs and PUs are paid in cash. All PUs are also subject to a performance multiplier ranging from 0 to 2.4 dependent on the Corporation's performance relative to performance targets as approved by the Board of Directors. 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, the participant is entitled to payment upon retirement, 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, expected health care costs, and other actuarial factors including discount rates and mortality. 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 and credits 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 9.0 years and 13.2 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 (Loss) per Share

Net Income (Loss) per Share

Basic net income (loss) 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.

Leases - Lessee

Leases – Lessee

AltaGas determines if an arrangement is a lease at inception. Operating leases are included in right-of-use (ROU) assets, current operating lease liabilities, and long-term operating lease liabilities in the Consolidated Balance Sheets. Finance leases are included in property, plant and equipment and current and long-term debt in the Consolidated Balance Sheets.

ROU assets represent the right to use an underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Operating lease ROU assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. AltaGas uses the rate implicit in the lease when readily determinable. When the implicit lease rate is not readily determinable, AltaGas uses its incremental borrowing rate to determine the present value of lease payments. AltaGas includes lessee options to renew or terminate the lease term in the determination of the ROU asset and lease liability when exercise is reasonably certain. The operating lease ROU asset is adjusted for lease payments made in advance of the commencement date, initial direct costs, and any lease incentives.

Operating lease expense is recognized on a straight-line basis over the lease term in "operating and administrative expense". Depreciation and interest expense are recorded on finance leases.

Leases - Lessor

Leases – Lessor

AltaGas determines if an arrangement is a lease at inception. Lease payments under an operating lease are recognized on a straight-line basis over the term of the lease. Variable lease payments are recognized as revenue as the facts and circumstances on which the variable lease payment is based occur.

AltaGas does not include taxes assessed by governmental authorities, such as sales and related taxes, in the lease payments or variable lease payments.

Collaborative Agreements

Collaborative Arrangements

WGL has collaborative arrangements with a third party to facilitate the asset optimization program. The collaborative arrangements allocate a tiered or fixed percentage of profits or losses to the third party as compensation for its participation.

ADOPTION OF NEW ACCOUNTING STANDARDS AND FUTURE CHANGES IN ACCOUNTING PRINCIPLES

ADOPTION OF NEW ACCOUNTING STANDARDS

Effective January 1, 2019, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU):

§ ASU No. 2016-02 “Leases” and all related amendments (collectively “ASC 842”). AltaGas has applied ASC 842 using the modified retrospective approach as of the effective date of the new standard. Comparative information has not been restated and continues to be reported under the previous lease guidance ASC 840. AltaGas has applied the package of transition practical expedients which permitted the Corporation to not reassess (a) whether any expired or existing contracts contain leases, (b) lease classifications for any expired or existing leases, and (c) initial direct costs for any existing leases. In addition, AltaGas applied the transition practical expedient that permitted the Corporation to grandfather its accounting policy for land easements that existed as of, or expired, before January 1, 2019. The transition practical expedient to not separate lease and non-lease components for its building, office equipment, transportation equipment, and vehicle leases has been elected for lessee arrangements. The transition practical expedient to not separate lease and non-lease components for its lessor arrangements related to certain assets has also been elected. AltaGas has applied the short-term lease recognition exemption under which lease arrangements with a term of twelve months or less, including extension options that are reasonably certain of being exercised, are exempt from the recognition of a right-of-use asset and lease liability and recorded as an expense over the term of the lease. This exemption applies to all classes of assets.

On adoption of ASC 842, all operating leases were recognized on the Consolidated Balance Sheets. The adoption resulted in an increase to long-term assets of approximately$181.0million and an increase to long-term liabilities of approximately$170.5million (net of the current portion that is recorded in current liabilities of approximately$23.3million). The lease related liabilities were measured using the present value of the remaining minimum lease payments for existing leases discounted using the Corporation’s incremental borrowing rate as of January 1, 2019. For operating leases, the associated right-of-use assets were measured at the amount equal to the lease liabilities on January 1, 2019, adjusted for any prepaid or accrued lease payments and the remaining balance of any lease incentives received. The adoption of ASC 842 did not impact lessor accounting, the Consolidated Statements of Income (Loss), or the Consolidated Statements of Cash Flows.

Please also refer to Note 10 of the Consolidated Financial Statements as at and for the year ended December 31, 2019 for further details;

§ ASU No. 2017-08 “Receivables – Nonrefundable Fees and Other Costs: Premium Amortization on Purchased Callable Debt Securities". The amendments in this ASU shorten the amortization period for certain callable debt securities held at a premium. Specifically, the amendments require the premium to be amortized to the earliest call date. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§ ASU No. 2017-11 “Earnings per Share and Derivatives and Hedging – Distinguishing Liabilities from Equity: Accounting for Certain Financial Instruments with Down Round Features, Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Non-controlling Interests with a Scope Exception”. The amendments in this ASU simplify the accounting for certain equity-linked financial instruments and embedded features with down round features that reduce the exercise price when pricing of a future round of financing is lower. The amendments in this ASU also require entities that present earnings per share under ASC 260 to recognize the effect of a down round feature in a freestanding equity-classified financial instrument only when it is triggered. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§ 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 adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§ 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 ASU clarify whether a transfer of assets is a contribution or an exchange transaction. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§ 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 adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and

§ 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 adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements.

FUTURE CHANGES IN ACCOUNTING PRINCIPLES

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 will adopt this standard on January 1, 2020 using a modified-retrospective approach through a cumulative-effect adjustment to retained earnings. AltaGas has completed scoping and evaluation activities for this new accounting standard, and has quantified the impact of this ASU on its opening Consolidated Balance Sheet as at January 1, 2020. Upon adoption, "accounts receivable, net of allowances" is expected to decrease by less than 1 percent of the outstanding accounts receivable balance, with an offsetting increase to "accumulated deficit".

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 post-retirement plans. 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. 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 ASU 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 ASU 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.

In March 2019, FASB issued ASU No. 2019-01 “Leases: Codification Improvements”. The amendments in this ASU provide a fair value exception for lessors that are not manufacturers or dealers, clarify the presentation of principal payments received under sales-type and direct finance leases on the statements of cash flows, and clarify transition disclosure requirements for the adoption of ASC 842. The amendments on the fair value exception and on the presentation on the statement of cash flows are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted. The amendment on the transition disclosure requirement is effective upon adoption of ASC 842. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In April 2019, FASB issued ASU No. 2019-04 “Financial Instruments - Credit Losses, Derivatives and Hedging, and Codification Improvements”. The amendments in this ASU provide clarification and improve the codification in recently issued accounting standards on credit losses (ASU 2016-13), hedging (ASU 2017-12), and recognizing and measuring financial instruments (ASU 2016-01). The amendments related to credit losses have the same effective date and transition requirements as ASU 2016-13, the amendments related to hedge accounting are effective as of the beginning of the first annual period beginning after issuance of this ASU and may be applied retrospectively to the date ASU 2017-12 was adopted or prospectively with some exceptions, and the amendments related to financial instruments are effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In May 2019, FASB issued ASU No. 2019-05 “Financial Instruments - Credit Losses: Targeted Transition Relief". The amendments in this ASU provide entities that have certain instruments within the scope of Subtopic 326-20 - Financial Instruments - Credit Losses - Measured at Amortized Cost (other than held-to-maturity debt securities) a one-time irrevocable option to elect fair value treatment on an eligible instrument-by-instrument basis. The effective date and transition methodology for the amendments in this ASU are the same as ASU 2016-13. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In November 2019, FASB issued ASU No. 2019-11 "Financial Instruments - Credit Losses: Codification Improvements". The amendments in this ASU provide clarification and improve the codification in ASU 2016-13. The effective date and transition methodology for the amendments in this ASU are the same as ASU 2016-13. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In December 2019, FASB issued ASU No. 2019-12 "Income Taxes: Simplifying the Accounting for Income Taxes". The amendments in this ASU simplify the accounting for income taxes by clarifying certain aspects of current guidance and removing some exceptions to the general principles in ASC 740. 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 assessing the impact of this ASU on its consolidated financial statements.

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Shareholders’ Equity - Summary of Cumulative Redeemable Preferred Shares (Details)	12 Months Ended
	Dec. 31, 2019 $ / shares shares	Dec. 31, 2019 $ / shares $ / shares shares	Dec. 31, 2019 $ / shares shares	Oct. 01, 2019 $ / shares	Oct. 01, 2015 $ / shares
Series A
Class of Stock
Current Yield	3.38%	3.38%
Annual dividend per share		$ 0.84500
Redemption price (per share)			$ 25
Series A | Five year government of Canada bond yield
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	2.66%	2.66%	2.66%
Series B
Class of Stock
Redemption price (per share)			$ 25		$ 25.50
Series B | 90-Day government of Canada treasury bill rate
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	2.66%	2.66%	2.66%
Preferred stock floating dividend rate (per share)			$ 0.26803
Series C
Class of Stock
Current Yield	5.29%	5.29%
Annual dividend per share	$ 1.32250
Redemption price (per share)	$ 25	$ 25
Series C | Five year United States government bond
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	3.58%	3.58%	3.58%
Series E
Class of Stock
Current Yield	5.393%	5.393%
Annual dividend per share		$ 1.34825
Redemption price (per share)			$ 25
Series E | Five year government of Canada bond yield
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	3.17%	3.17%	3.17%
Series G
Class of Stock
Current Yield	4.62%	4.62%
Annual dividend per share		$ 1.15575
Redemption price (per share)			$ 25
Series G | Five year government of Canada bond yield
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	3.06%	3.06%	3.06%
Series H
Class of Stock
Redemption price (per share)			$ 25	$ 25.50
Series H | 90-Day government of Canada treasury bill rate
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	3.06%	3.06%	3.06%
Preferred stock floating dividend rate (per share)			$ 0.29289
Series I
Class of Stock
Current Yield	5.25%	5.25%
Annual dividend per share		$ 1.31250
Redemption price (per share)			$ 25
Series I | Five year government of Canada bond yield
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	4.19%	4.19%	4.19%
Series I | Five year government of Canada bond yield | Minimum
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	5.25%	5.25%	5.25%
Series K
Class of Stock
Current Yield	5.00%	5.00%
Annual dividend per share		$ 1.25000
Redemption price (per share)			$ 25
Series K | Five year government of Canada bond yield
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	3.80%	3.80%	3.80%
Series K | Five year government of Canada bond yield | Minimum
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	5.00%	5.00%	5.00%
Series F
Class of Stock
Redemption price (per share)			$ 25.5
Preferred stock shares authorized (shares) | shares	8,000,000	8,000,000	8,000,000
Series J
Class of Stock
Redemption price (per share)			$ 25.5
Preferred stock shares authorized (shares) | shares	8,000,000	8,000,000	8,000,000
Series D
Class of Stock
Redemption price (per share)			$ 25.50
Preferred stock shares authorized (shares) | shares	8,000,000	8,000,000	8,000,000
Series L
Class of Stock
Redemption price (per share)			$ 25.50
Series L | Maximum
Class of Stock
Preferred stock shares authorized (shares) | shares	12,000,000	12,000,000	12,000,000

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Consolidated Statements of Income (Loss) - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Income Statement [Abstract]
REVENUE (note 24)	$ 5,495.0	$ 4,256.7
EXPENSES
Cost of sales, exclusive of items shown separately	3,227.1	2,455.3
Operating and administrative	1,298.7	1,129.0
Accretion expenses (note 17)	5.1	10.9
Depreciation and amortization (notes 8 and 9)	438.0	394.0
Provisions on assets (note 6)	415.8	728.7
Total expenses	5,384.7	4,717.9
Income from equity investments (note 14)	141.1	47.9
Other income (note 27)	908.1	0.9
Foreign exchange gains (losses)	(1.0)	4.5
Interest expense	(345.8)	(309.0)
Income (loss) before income taxes	812.7	(716.9)
Income tax expense (recovery) (note 20)
Current	63.3	24.4
Deferred	(90.9)	(287.6)
Net income (loss) after taxes	840.3	(453.7)
Net income (loss) applicable to non-controlling interests	6.8	(18.6)
Net income (loss) applicable to controlling interests	833.5	(435.1)
Preferred share dividends	(68.5)	(66.6)
Gain on redemption of preferred shares (note 25)	3.5	0.0
Net income (loss) applicable to common shares	$ 768.5	$ (501.7)
Net income (loss) per common share (note 26)
Basic (per share)	$ 2.78	$ (2.25)
Diluted (per share)	$ 2.77	$ (2.25)
Weighted average number of common shares outstanding (millions) (note 26)
Basic (shares)	276.9	222.6
Diluted (shares)	277.4	222.6

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Leases - Supplemental Balance Sheet Location (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Operating lease right-of-use assets
Long-term	$ 169.8
Included in assets held for sale (note 5)	0.4
Total operating lease right-of-use assets	170.2
Operating lease liabilities
Current	(27.3)
Long-term	(153.4)
Included in liabilities associated with assets held for sale (note 5)	(0.4)
Total operating lease liabilities	(181.1)
Finance Leases
Property and equipment, gross	13.2
Accumulated depreciation	(3.3)
Property and equipment, net	9.9
Current portion of long-term debt	(3.5)
Long-term debt	(6.4)
Total finance lease liabilities	$ (9.9)	$ (0.8)
Weighted average remaining lease term (years)
Operating leases	10 years 11 months
Finance leases	5 years 2 months
Weighted average discount rate (%)
Operating leases	3.51%
Finance leases (percent)	3.68%

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Organization and Overview of the Business

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Overview of the Business

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. (WGL Energy Services), 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, Ridley Island LPG Export Limited Partnership, and WGL Midstream Inc. (WGL Midstream); in regards to the Power business, AltaGas Power Holdings (U.S.) Inc., WGL Energy Systems, Inc. (WGL Energy Systems), and Blythe Energy Inc. (Blythe); and, in regards to the Utilities business, Washington Gas Light Company (Washington Gas), 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), its Alaska natural gas distribution business under the name ENSTAR Natural Gas Company (ENSTAR) and its 65 percent interest in an Alaska regulated gas storage utility under the name Cook Inlet Natural Gas Storage Alaska LLC (CINGSA).

AltaGas, a Canadian corporation, is a leading North American energy infrastructure company that connects natural gas liquids (NGLs) and natural gas to domestic and global markets. The Corporation’s long-term strategy is to grow in attractive areas across its Utilities and Midstream 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 the West Coast of Canada via the Corporation’s footprint in the Montney region. In the Utilities business, the Corporation seeks to grow through rate base investment and the use of accelerated rate recovery programs, while providing effective and cost-efficient service for customers. AltaGas has three business segments:

§ Utilities, which serves approximately 1.7 million customers with a rate base of approximately US$3.9 billionthrough 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 includes a 70 percent interest in the recently completed Ridley Island Propane Export Terminal, allowing AltaGas to leverage its assets along the energy value chain in Western Canada including natural gas gathering and processing,NGLextraction and fractionation, and natural gas and NGL marketing. The Midstream segment also includes transmission, storage, an interest in a regulated pipeline in the Marcellus/Utica gas formation in the northeastern United States, WGL’s retail gas marketing business, the Corporation’s 50 percent interest inAltaGas Idemitsu Joint Venture Limited Partnership (AIJVLP), and an indirectly held approximate one-third ownership investment in Petrogas Energy Corp. (Petrogas), through which AltaGas’ interest in the Ferndale terminal is held; and

§ Power, which includes 710 MW of operational capacity from natural gas-fired, distributed generation, and energy storage assets, certain of which are pending sale, located in Alberta, Canada and the United States, primarily in California and Colorado. The Power business also includes energy efficiency contracting and WGL’s retail power marketing business.

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Revenue (Tables)

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue by Major Sources

The following tables disaggregate revenue by major sources for the year:

	Year Ended December 31, 2019
	Utilities			Midstream		Power		Corporate		Total
Revenue from contracts with customers
Commodity sales contracts	$	—		$	1,093.7	$	1,131.4	$	—	$	2,225.1
Midstream service contracts	—			145.0		—		—		145.0
Gas sales and transportation services	2,501.4			—		—		—		2,501.4
Storage services	28.1			—		—		—		28.1
Other	9.2			2.7		29.0		—		40.9
Total revenue from contracts with customers	$	2,538.7		$	1,241.4	$	1,160.4	$	—	$	4,940.5
Other sources of revenue
Revenue from alternative revenue programs (a)	$	29.5		$	—	$	—	$	—	$	29.5
Leasing revenue (b)	0.9			136.6		105.1		—		242.6
Risk management and trading activities (c) (d)	—			196.2		65.9		0.2		262.3
Other	(4.9		)	0.1		24.9		—		20.1
Total revenue from other sources	$	25.5		$	332.9	$	195.9	$	0.2	$	554.5
Total revenue	$	2,564.2		$	1,574.3	$	1,356.3	$	0.2	$	5,495.0

(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 for the year ended December 31, 2019 of $504.5 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract, which are in scope of ASC 606, are reported within 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 GAIL contract has a term of 20 years and began on March 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. 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 for the year ended December 31, 2018 of $264.2 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract, which are in scope of ASC 606, are reported within 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 GAIL contract has a term of 20 years and began on March 31, 2018.

Contract with Customer, Asset and Liability

Contract Assets

As at	December 31, 2019			December 31, 2018
Balance, beginning of year	$	58.8		$	—
Additions	32.3			130.1
Transfers to held for sale (a)	—			(72.2		)
Transfers to accounts receivable (b)	—			(3.7		)
Foreign exchange translation	(2.5		)	4.6
Balance, end of year	$	88.6		$	58.8

(a) In the fourth quarter of 2018, WGL Energy Systems reached an agreement for the sale of a financing receivable included in the contract asset balance. Accordingly, the receivable was classified as held for sale at December 31, 2018. In February 2019, WGL Energy Systems completed the sale of the financing receivable (Note 4).

(b) Amounts included in contract assets are transferred to accounts receivable when AltaGas’ right to consideration becomes unconditional.

Contract Liabilities

As at	December 31, 2019			December 31, 2018
Balance, beginning of year	$	2.2		$	—
Additions	1.9			2.6
Revenue recognized from contract liabilities (a)	(2.2		)	(0.5		)
Foreign exchange translation	(0.2		)	0.1
Balance, end of year	$	1.7		$	2.2

(a) Recognition of revenue related to performance obligations satisfied in the current period for amounts that were previously included in contract liabilities.

Schedule of Estimated Revenue Related to Performance 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, 2019:

	2020		2021		2022		2023		2024		2025 & beyond		Total
Midstream service contracts	$	113.1	$	89.8	$	88.9	$	86.5	$	86.4	$	971.9	$	1,436.6
Storage services	24.2		24.2		23.5		23.2		23.2		168.4		286.7
Other	19.4		8.9		2.0		2.0		2.0		12.0		46.3
	$	156.7	$	122.9	$	114.4	$	111.7	$	111.6	$	1,152.3	$	1,769.6

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Revenue - Schedule of Estimated Revenue Related to Performance Obligations (Details) $ in Millions	Dec. 31, 2019 CAD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Estimated revenue expected to be recognized in the future related to performance obligations	$ 156.7
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	$ 113.1
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	$ 24.2
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Other
Estimated revenue expected to be recognized in the future related to performance obligations	$ 19.4
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Estimated revenue expected to be recognized in the future related to performance obligations	$ 122.9
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	$ 89.8
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	$ 24.2
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Other
Estimated revenue expected to be recognized in the future related to performance obligations	$ 8.9
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Estimated revenue expected to be recognized in the future related to performance obligations	$ 114.4
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	$ 88.9
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	$ 23.5
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Other
Estimated revenue expected to be recognized in the future related to performance obligations	$ 2.0
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Estimated revenue expected to be recognized in the future related to performance obligations	$ 111.7
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	$ 86.5
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	$ 23.2
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Other
Estimated revenue expected to be recognized in the future related to performance obligations	$ 2.0
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Estimated revenue expected to be recognized in the future related to performance obligations	$ 111.6
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	$ 86.4
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	$ 23.2
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Other
Estimated revenue expected to be recognized in the future related to performance obligations	$ 2.0
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Estimated revenue expected to be recognized in the future related to performance obligations	$ 1,152.3
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	$ 971.9
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	$ 168.4
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Other
Estimated revenue expected to be recognized in the future related to performance obligations	$ 12.0
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Estimated revenue expected to be recognized in the future related to performance obligations	$ 1,769.6
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	1,436.6
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	286.7
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Other
Estimated revenue expected to be recognized in the future related to performance obligations	$ 46.3

XML

Financial Instruments and Financial Risk Management - Schedule of Contractual Maturities for Financial Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Contractual maturities by period
Total	$ 8,907.3	$ 11,938.9
Less than 1 year	2,867.8	3,709.1
1-3 years	1,523.3	3,178.7
4-5 years	934.5	1,625.9
After 5 years	3,581.7	3,425.2
Accounts payable and accrued liabilities
Contractual maturities by period
Total	1,324.9	1,488.2
Less than 1 year	1,324.9	1,488.2
1-3 years	0.0	0.0
4-5 years	0.0	0.0
After 5 years	0.0	0.0
Dividends payable
Contractual maturities by period
Total	22.3	22.0
Less than 1 year	22.3	22.0
1-3 years	0.0	0.0
4-5 years	0.0	0.0
After 5 years	0.0	0.0
Short-term debt
Contractual maturities by period
Total	460.0	1,209.9
Less than 1 year	460.0	1,209.9
1-3 years	0.0	0.0
4-5 years	0.0	0.0
After 5 years	0.0	0.0
Other current liabilities
Contractual maturities by period
Total	15.4	11.2
Less than 1 year	15.4	11.2
1-3 years	0.0	0.0
4-5 years	0.0	0.0
After 5 years	0.0	0.0
Other long-term liabilities
Contractual maturities by period
Total		2.0
Less than 1 year		0.0
1-3 years		2.0
4-5 years		0.0
After 5 years		0.0
Risk management contract liabilities
Contractual maturities by period
Total	291.8	302.3
Less than 1 year	124.8	89.3
1-3 years	34.1	113.3
4-5 years	13.2	33.3
After 5 years	119.7	66.4
Current portion of long-term debt
Contractual maturities by period
Total	920.4	888.5
Less than 1 year	920.4	888.5
1-3 years	0.0	0.0
4-5 years	0.0	0.0
After 5 years	0.0	0.0
Long-term debt
Contractual maturities by period
Total	5,872.5	8,014.8
Less than 1 year	0.0	0.0
1-3 years	1,489.2	3,063.4
4-5 years	921.3	1,592.6
After 5 years	$ 3,462.0	$ 3,358.8

XML

Pension Plans and Retiree Benefits (Tables)

12 Months Ended

Dec. 31, 2019

Retirement Benefits [Abstract]

Summary of Defined Benefit Plans

The following table summarizes the details of the defined benefit plans, including the SERP and post-retirement plans in Canada and the United States:

Year Ended December 31, 2019	Canada						United States						Total
	Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits
Projected benefit obligation (a)
Balance, beginning of year	$	34.3		$	1.9		$	1,635.3		$	458.0		$	1,669.6		$	459.9
Actuarial loss (gain)	2.1			0.2			182.0			(14.8		)	184.1			(14.6		)
Current service cost	2.6			—			23.8			8.5			26.4			8.5
Member contributions	—			—			—			2.2			—			2.2
Interest cost	1.2			0.1			67.8			19.1			69.0			19.2
Benefits paid	(4.0		)	(0.1		)	(77.3		)	(24.4		)	(81.3		)	(24.5		)
Expenses paid	(0.1		)	—			(0.6		)	(0.1		)	(0.7		)	(0.1		)
Settlements	—			—			(24.7		)	—			(24.7		)	—
Plan amendments	—			—			0.3			—			0.3			—
Other	—			—			—			1.0			—			1.0
Foreign exchange translation	—			—			(82.0		)	(21.8		)	(82.0		)	(21.8		)
Balance, end of year	$	36.1		$	2.1		$	1,724.6		$	427.7		$	1,760.7		$	429.8
Plan assets
Fair value, beginning of year	$	13.8		$	—		$	1,354.1		$	791.2		$	1,367.9		$	791.2
Actual return on plan assets	0.9			—			284.2			177.4			285.1			177.4
Employer contributions	4.3			0.1			38.7			0.1			43.0			0.2
Member contributions	—			—			—			2.2			—			2.2
Benefits paid	(4.0		)	(0.1		)	(77.3		)	(23.7		)	(81.3		)	(23.8		)
Expenses paid	(0.1		)	—			(0.6		)	(0.1		)	(0.7		)	(0.1		)
Settlements	—			—			(25.7		)	—			(25.7		)	—
Other	—			—			—			0.1			—			0.1
Foreign exchange translation	—			—			(69.5		)	(41.3		)	(69.5		)	(41.3		)
Fair value, end of year	$	14.9		$	—		$	1,503.9		$	905.9		$	1,518.8		$	905.9
Funded status	$	(21.2	)	$	(2.1	)	$	(220.7	)	$	478.2		$	(241.9	)	$	476.1

(a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation.

Year Ended December 31, 2018	Canada						United States						Total
	Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits
Projected benefit obligation (a)
Balance, beginning of year	$	165.6		$	15.8		$	303.8		$	82.7		$	469.4		$	98.5
Plans disposed	(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	(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
Funded status	$	(20.5	)	$	(1.9	)	$	(281.2	)	$	333.2		$	(301.7	)	$	331.3

(a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation.

Schedule of Amounts Included in the Consolidated Balance Sheets

The following amounts were included in the Consolidated Balance Sheets:

	December 31, 2019									December 31, 2018
	Defined Benefit			Post- Retirement Benefits			Total			Defined Benefit			Post- Retirement Benefits			Total (a)
Prepaid post-retirement benefits	$	—		$	486.8		$	486.8		$	—		$	341.4		$	341.4
Accounts payable and accrued liabilities	(25.7		)	—			(25.7		)	(27.6		)	—			(27.6		)
Future employee obligations	(216.2		)	(10.7		)	(226.9		)	(274.1		)	(10.1		)	(284.2		)
	$	(241.9	)	$	476.1		$	234.2		$	(301.7	)	$	331.3		$	29.6

(a) Account balances on the Consolidated Balance Sheets also include certain non-pension related amounts.

Schedule of Funded Status Based on Accumulated Benefit Obligation

The accumulated benefit obligation for all defined benefit plans were:

As at	December 31, 2019				December 31, 2018
	Canada		United States		Canada		United States
Accumulated benefit obligation (a)	$	34.7	$	1,616.4	$	32.9	$	1,525.6

(a) Accumulated benefit obligation differs from projected 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)

The following amounts were recorded in other comprehensive income (loss) and have not yet been recognized in net periodic benefit cost:

Year Ended December 31, 2019	Canada						United States						Total
	Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits
Past service credit (cost)	$	(0.2	)	$	0.3		$	0.1		$	—		$	(0.1	)	$	0.3
Net actuarial gain (loss)	(9.4		)	(0.7		)	(14.9		)	18.2			(24.3		)	17.5
Recognized in AOCI pre-tax	$	(9.6	)	$	(0.4	)	$	(14.8	)	$	18.2		$	(24.4	)	$	17.8
Increase (decrease) by the amount included in deferred tax liabilities	2.3			0.1			7.0			(9.0		)	9.3			(8.9		)
Net amount in AOCI after-tax	$	(7.3	)	$	(0.3	)	$	(7.8	)	$	9.2		$	(15.1	)	$	8.9

Year Ended December 31, 2018	Canada						United States						Total
	Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits
Past service credit (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	)

Summary of Amounts Recorded in A Regulatory Asset (Liability)

The following amounts were recorded in a regulatory asset (liability) and have not yet been recognized in net periodic benefit cost:

Year Ended December 31, 2019	Canada				United States					Total
	Defined Benefit		Post- Retirement Benefits		Defined Benefit		Post- Retirement Benefits			Defined Benefit		Post- Retirement Benefits
Past service cost (credit)	$	—	$	—	$	1.1	$	(105.4	)	$	1.1	$	(105.4	)
Net actuarial loss (gain)	—		—		127.1		(155.8		)	127.1		(155.8		)
Recognized in regulatory asset (liability)	$	—	$	—	$	128.2	$	(261.2	)	$	128.2	$	(261.2	)

Year Ended December 31, 2018	Canada				United States					Total
	Defined Benefit		Post- Retirement Benefits		Defined Benefit		Post- Retirement Benefits			Defined Benefit		Post- Retirement Benefits
Past service cost (credit)	$	—	$	—	$	0.8	$	(110.2	)	$	0.8	$	(110.2	)
Net actuarial loss (gain)	—		—		188.2		(52.6		)	188.2		(52.6		)
Recognized in regulatory asset (liability)	$	—	$	—	$	189.0	$	(162.8	)	$	189.0	$	(162.8	)

Schedule of Amounts to be Amortized from AOCI in the Next Fiscal Year

Amounts to be amortized in the next fiscal year from AOCI	Defined Benefit		Post-Retirement Benefits
Past service cost (credit)	$	0.2	$	(0.7	)
Actuarial loss	4.0		0.3
Total	$	4.2	$	(0.4	)

Schedule of Amounts in Regulatory Assets (Liabilities) to be Recognized over Next Fiscal Year

Amounts to be amortized in the next fiscal year from regulatory assets (liabilities)	Defined Benefit			Post-Retirement Benefits
Past service credit (cost)	$	(0.2	)	$	16.7
Actuarial gain (loss)	(17.1		)	0.5
Total	$	(17.3	)	$	17.2

Schedule of Net Periodic Benefit Expense

The net pension expense by plan was as follows:

	Year Ended December 31, 2019
	Canada					United States						Total
	Defined Benefit			Post-Retirement Benefits		Defined Benefit			Post-Retirement Benefits			Defined Benefit			Post-Retirement Benefits
Current service cost (a)	$	2.6		$	—	$	23.8		$	8.5		$	26.4		$	8.5
Interest cost (b)	1.2			0.1		67.8			19.1			69.0			19.2
Expected return on plan assets (b)	(0.5		)	—		(74.6		)	(37.1		)	(75.1		)	(37.1		)
Amortization of past service cost (credit) (b)	0.1			—		0.4			(21.9		)	0.5			(21.9		)
Amortization of net actuarial loss (b)	0.9			—		11.7			0.1			12.6			0.1
Plan settlements (b)	—			—		4.1			—			4.1			—
Other (b)	—			—		—			0.9			—			0.9
Net benefit cost (income) recognized	$	4.3		$	0.1	$	33.2		$	(30.4	)	$	37.5		$	(30.3	)

(a) Recorded under the line item “operating and administrative” expenses on the Consolidated Statements of Income (Loss).

(b) Recorded under the line item “other income” on the Consolidated Statements of Income (Loss).

	Year Ended December 31, 2018
	Canada					United States						Total
	Defined Benefit			Post-Retirement Benefits		Defined Benefit			Post-Retirement Benefits			Defined Benefit			Post-Retirement 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 (credit) (b)	0.1			—		0.1			(11.5		)	0.2			(11.5		)
Amortization of net actuarial loss (b)	0.6			—		7.7			0.4			8.3			0.4
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 (Loss).

(b) Recorded under the line item “other income” on the Consolidated Statements of Income (Loss).

Schedule of Collective Investment Mixes for Plan Assets

The collective investment mixes for the plans are as follows as at December 31, 2019:

Canada	Fair value		Level 1		Level 2		Percentage of Plan Assets (%)
Cash and short-term equivalents	$	1.9	$	1.9	$	—	12.8
Canadian equities	4.1		4.1		—		27.5
Foreign equities	2.4		2.4		—		16.0
Fixed income	5.7		5.7		—		38.3
Real estate	0.8		—		0.8		5.4
	$	14.9	$	14.1	$	0.8	100.0

United States	Fair value			Level 1		Level 2			Percentage of Plan Assets (%)
Cash and short-term equivalents	$	10.8		$	10.8	$	—		0.4
Canadian equities	2.6			2.6		—			0.1
Foreign equities (a)	302.5			302.2		0.3			12.6
Fixed income	933.0			123.2		809.8			38.7
Derivatives	(0.2		)	—		(0.2		)	—
Other (b)	12.0			—		12.0			0.5
Total investments in the fair value hierarchy	$	1,260.7		$	438.8	$	821.9		52.3
Investments measured at net asset value using the NAV practical expedient (c)
Commingled funds (d)	$	648.9							26.9
Private equity/limited partnership (e)	55.6								2.3
Pooled separate accounts (f)	32.0								1.3
Collective trust fund (g)	433.8								18.1
Total fair value of plan investments	$	2,431.0							100.9
Net payable (h)	(21.2		)						(0.9	)
	$	2,409.8							100.0

(a) Investments in foreign equities include U.S. and international securities.

(b) As at December 31, 2019, these investments consisted primarily of non-U.S. government bonds.

(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 at December 31, 2019, investments in commingled funds consisted of approximately 58 percent common stock of large-cap U.S. companies, 18 percent U.S. Government fixed income securities, and 24 percent corporate bonds for WGL’s post-retirement benefit plans.

(e) As at December 31, 2019, investments in a private equity/limited partnership consisted of common stock of international companies.

(f) As at December 31, 2019, investments in pooled separate accounts consisted of income producing properties located in the United States.

(g) As at December 31, 2019, investments in collective trust funds consisted primarily of 90 percent common stock of U.S, companies, 8 percent income producing properties located in the United States, and 2 percent short-term money market investments.

(h) As at December 31, 2019, 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	$	12.7		$	12.7	$	—		0.5
Canadian equities	6.7			6.7		—			0.3
Foreign equities (a)	304.9			304.6		0.3			12.6
Fixed income	938.7			128.9		809.8			38.7
Derivatives	(0.2		)	—		(0.2		)	—
Real estate	0.8			—		0.8			—
Other (b)	12.0			—		12.0			0.5
Total investments in the fair value hierarchy	$	1,275.6		$	452.9	$	822.7		52.6
Investments measured at net asset value using the NAV practical expedient (c)
Commingled funds(d)	$	648.9							26.8
Private equity/limited partnership (e)	55.6								2.3
Pooled separate accounts (f)	32.0								1.3
Collective trust fund (g)	433.8								17.9
Total fair value of plan investments	$	2,445.9							100.9
Net payable (h)	(21.2		)						(0.9	)
	$	2,424.7							100.0

(a) Investments in foreign equities include U.S. and international securities.

(b) As at December 31, 2019, these investments consisted primarily of non-U.S. government bonds.

(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 at December 31, 2019, investments in commingled funds consisted of approximately 58 percent common stock of large-cap U.S. companies, 18 percent U.S. Government fixed income securities, and 24 percent corporate bonds for WGL’s post-retirement benefit plans.

(e) As at December 31, 2019, investments in a private equity/limited partnership consisted of common stock of international companies.

(f) As at December 31, 2019, investments in pooled separate accounts consisted of income producing properties located in the United States.

(g) As at December 31, 2019, investments in collective trust funds consisted primarily of 90 percent common stock of U.S, companies, 8 percent income producing properties located in the United States, and 2 percent short-term money market investments.

(h) As at December 31, 2019, this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable.

Year Ended December 31	2019		2018
Significant actuarial assumptions used in measuring net benefit plan costs	Defined Benefit	Post-Retirement Benefits	Defined Benefit	Post-Retirement Benefits
Discount rate (%)	2.90 - 4.40	3.90 - 4.50	3.25 - 4.30	3.60 - 4.30
Expected long-term rate of return on plan assets (%) (a)	5.75 - 7.15	4.66 - 7.15	3.20 - 7.60	3.75 - 7.60
Rate of compensation increase (%)	2.75 - 4.10	4.10	2.75 - 4.10	4.10
Average remaining service life of active employees (years)	9.0	13.2	9.6	14.1

(a) Only applicable for funded plans

Schedule of Significant Actuarial Assumptions Used in Measuring Net Benefit Plan Costs and Benefit Obligations

As at December 31	2019		2018
Significant actuarial assumptions used in measuring benefit obligations	Defined Benefit	Post-Retirement Benefits	Defined Benefit	Post-Retirement Benefits
Discount rate (%)	2.90 - 3.50	3.10 - 3.60	3.60 - 4.40	3.90 - 4.50
Rate of compensation increase (%)	2.75 - 4.00	3.50	2.75 - 4.10	4.10

Summary of Assumed Health Care Cost Trend Rates

A one percentage point change in the assumed health care trend rates would have the following effects for 2019:

	Increase		Decrease
Service and interest costs	$	1.9	$	(1.5	)
Accrued benefit obligation	$	22.7	$	(18.4	)

Schedule of Expected Cash Flows for Defined Benefit Pension and Other Post-Retirement Plans

The following table shows the expected cash flows for defined benefit pension and other post-retirement plans:

	Defined Benefit		Post-Retirement Benefits
Expected employer contributions:
2020	$	37.0	$	3.2
Expected benefit payments:
2020	$	104.6	$	23.8
2021	$	85.1	$	22.6
2022	$	93.3	$	22.5
2023	$	90.0	$	22.3
2024	$	90.7	$	22.1
2025 - 2028	$	474.1	$	112.6

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Goodwill - Schedule of Goodwill (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Goodwill
Balance, beginning of year	$ 4,068.2	$ 817.3
Provisions on assets	0.0	(124.2)
Business acquisition (note 3)	0.0	3,196.4
Adjustment to goodwill on business acquisition (note 3)	92.2	0.0
Goodwill included in dispositions (note 4)	(29.1)	0.0
Reclassified to assets held for sale (note 5)	(1.0)	0.0
Foreign exchange translation	(188.2)	178.7
Balance, end of year	$ 3,942.1	$ 4,068.2

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Asset Retirement Obligations - Schedule of Accumulated Other Comprehensive Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis
Balance, beginning of year	$ 500.6	$ 88.3
Obligations acquired (note 3)	0.0	399.1
New obligations	7.0	3.3
Obligations settled	(2.5)	(4.2)
Disposals	(6.2)	(1.6)
Revision in estimated cash flow	(128.5)	3.8
Accretion expense	18.9	12.3
Foreign exchange translation	(20.7)	20.3
Reclassified to liabilities associated with assets held for sale (note 5)	(0.2)	(10.8)
Total	368.4	510.5
Less current portion (included in accounts payable and accrued liabilities)	(6.4)	(9.9)
Balance, end of year	$ 362.0	$ 500.6

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Goodwill (Tables)

12 Months Ended

Dec. 31, 2019

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill

As at	December 31, 2019			December 31, 2018
Balance, beginning of year	$	4,068.2		$	817.3
Provisions on assets	—			(124.2		)
Business acquisition (note 3)	—			3,196.4
Adjustment to goodwill on business acquisition (note 3)	92.2			—
Goodwill included in dispositions (note 4)	(29.1		)	—
Reclassified to assets held for sale (note 5)	(1.0		)	—
Foreign exchange translation	(188.2		)	178.7
Balance, end of year	$	3,942.1		$	4,068.2

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Short-term Debt (Tables)

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Schedule of Short-Term Debt

As at	December 31, 2019		December 31, 2018
Bank indebtedness	$	—	$	0.2
Commercial paper (a)	389.0		1,145.2
Project financing	71.0		64.5
	$	460.0	$	1,209.9

(a) 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. As at December 31, 2019, certain commercial paper balances have been classified as long-term debt as they are supported by long-term extendible committed credit facilities with maturities ranging from 2022 to 2024 (see Note 16).

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Short-term Debt - Schedule of Short-Term Debt (Details) $ in Millions, $ in Millions	Dec. 31, 2019 USD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2018 CAD ($)
Debt Disclosure [Abstract]
Bank indebtedness		$ 0.0		$ 0.2
Commercial paper	$ 299.5	389.0	$ 839.5	1,145.2
Project financing		71.0		64.5
Short-term debt		$ 460.0		$ 1,209.9

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Schedule of Income Tax Provision

Year Ended December 31	2019			2018
Income (loss) before income taxes - consolidated	$	812.7		$	(716.9	)
Statutory income tax rate (%)	26.5			27.0
Expected taxes at statutory rates	$	215.4		$	(193.6	)
Add (deduct) the tax effect of:
Permanent differences	$	10.9		$	(1.0	)
Statutory and other rate differences	(51.6		)	(19.6		)
Rate adjustment for change in tax rates	(10.7		)	1.3
Deferred income tax recovery on regulated assets	(24.8		)	(7.3		)
Tax differences on divestitures and transactions	(158.2		)	(32.3		)
Non-controlling interests	3.5			4.7
Change in valuation allowance	(11.1		)	(22.3		)
Other	(1.0		)	6.9
	$	(27.6	)	$	(263.2	)
Income tax provision
Current
Canada	$	26.7		$	23.7
United States	36.6			0.7
	$	63.3		$	24.4
Deferred
Canada	$	11.6		$	(166.1	)
United States	(102.5		)	(121.5		)
	$	(90.9	)	$	(287.6	)
Effective income tax rate (%)	(3.4		)	36.7

Schedule of Deferred Income Tax Liabilities

Net deferred income tax liabilities were composed of the following:

As at	December 31, 2019			December 31, 2018
PP&E and intangible assets	$	1,450.6		$	1,764.6
Regulatory assets	(204.1		)	(166.3		)
Tax pools, deferred financing, and compensation	(138.2		)	(453.6		)
Other	(161.2		)	(209.9		)
Valuation allowance	12.0			23.1
	$	959.1		$	957.9

Schedule of Uncertain Tax Positions

Management determined that the following provision was required for uncertainty on income taxes during the year:

Year Ended December 31	2019			2018
Balance, beginning of year	$	2.2		$	5.9
Net changes during the year	(0.2		)	(3.7		)
Balance, end of year	$	2.0		$	2.2

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Intangible Assets - Summary of Intangible Assets (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Finite-Lived Intangible Assets
Cost	$ 758.6	$ 841.4
Accumulated amortization	(173.0)	(129.5)
Net book value	585.6	711.9
Held for sale
Finite-Lived Intangible Assets
Cost	0.0	277.4
Accumulated amortization	0.0	(28.7)
Net book value	0.0	248.7
E&T contracts
Finite-Lived Intangible Assets
Cost	26.6	26.6
Accumulated amortization	(15.2)	(14.3)
Net book value	11.4	12.3
Electricity service agreements
Finite-Lived Intangible Assets
Cost	8.5	269.5
Accumulated amortization	(7.8)	(25.9)
Net book value	0.7	243.6
Energy services relationships
Finite-Lived Intangible Assets
Cost	91.6	176.1
Accumulated amortization	(27.4)	(33.8)
Net book value	64.2	142.3
Software
Finite-Lived Intangible Assets
Cost	303.7	293.9
Accumulated amortization	(101.2)	(77.7)
Net book value	202.5	216.2
Land rights
Finite-Lived Intangible Assets
Cost	1.1	1.4
Accumulated amortization	(0.1)	(0.2)
Net book value	1.0	1.2
Commodity contracts
Finite-Lived Intangible Assets
Cost	327.1	346.3
Accumulated amortization	(21.3)	(6.3)
Net book value	305.8	340.0
Franchises and consents
Finite-Lived Intangible Assets
Cost	0.0	5.0
Accumulated amortization	0.0	0.0
Net book value	$ 0.0	$ 5.0

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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, 2019	Dec. 31, 2018
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance, beginning of year	$ (163.2)	$ 0.0
Acquired (note 3)	0.0	(146.7)
Recorded in income	49.0	(14.8)
Recorded in regulatory assets	23.6	(5.9)
Transfers into Level 3	(9.0)	0.0
Transfers out of Level 3	12.3	7.3
Purchases	(11.4)	6.4
Settlements	7.3	(3.1)
Foreign exchange translation	6.3	(6.4)
Balance, end of year	(85.1)	(163.2)
Natural Gas
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance, beginning of year	(148.5)	0.0
Acquired (note 3)	0.0	(136.1)
Recorded in income	47.6	(8.3)
Recorded in regulatory assets	23.6	(5.9)
Transfers into Level 3	(9.0)	0.0
Transfers out of Level 3	12.3	7.3
Purchases	0.0	0.0
Settlements	(17.1)	0.3
Foreign exchange translation	5.9	(5.8)
Balance, end of year	(85.2)	(148.5)
Electricity
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance, beginning of year	(14.7)	0.0
Acquired (note 3)	0.0	(10.6)
Recorded in income	1.4	(6.5)
Recorded in regulatory assets	0.0	0.0
Transfers into Level 3	0.0	0.0
Transfers out of Level 3	0.0	0.0
Purchases	(11.4)	6.4
Settlements	24.4	(3.4)
Foreign exchange translation	0.4	(0.6)
Balance, end of year	$ 0.1	$ (14.7)

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Summary of Significant Accounting Policies - Collaborative Agreements (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Income (loss) from collaborative agreements	$ 1.4	$ (0.2)

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Summary of Significant Accounting Policies - Summary of Estimated Useful Lives of Finite-Lived Intangible Assets (Details)	12 Months Ended
	Dec. 31, 2019
WGL Holdings
Finite-Lived Intangible Assets
Intangible asset, useful life	20 years
Energy services relationships | Minimum
Finite-Lived Intangible Assets
Intangible asset, useful life	5 years
Energy services relationships | Maximum
Finite-Lived Intangible Assets
Intangible asset, useful life	19 years
Electricity service agreements | Minimum
Finite-Lived Intangible Assets
Intangible asset, useful life	2 years
Electricity service agreements | Maximum
Finite-Lived Intangible Assets
Intangible asset, useful life	60 years
Software | Minimum
Finite-Lived Intangible Assets
Intangible asset, useful life	3 years
Software | Maximum
Finite-Lived Intangible Assets
Intangible asset, useful life	10 years
Land rights | Minimum
Finite-Lived Intangible Assets
Intangible asset, useful life	5 years
Land rights | Maximum
Finite-Lived Intangible Assets
Intangible asset, useful life	64 years
Franchises and consents | Minimum
Finite-Lived Intangible Assets
Intangible asset, useful life	9 years
Franchises and consents | Maximum
Finite-Lived Intangible Assets
Intangible asset, useful life	25 years
E&T contracts
Finite-Lived Intangible Assets
Intangible asset, useful life	25 years
Commodity contracts | Minimum
Finite-Lived Intangible Assets
Intangible asset, useful life	5 years
Commodity contracts | Maximum
Finite-Lived Intangible Assets
Intangible asset, useful life	20 years

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Financial Instruments and Financial Risk Management - Collateral Not Offset Against Risk Management Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Collateral posted with counterparties	$ 29.1	$ 27.6
Cash collateral held representing an obligation	$ 0.3	$ 0.8

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Provisions on Assets - Narratives (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Provisions On Assets Disclosure
Provisions on assets	$ 415.8	$ 728.7
Utilities
Provisions On Assets Disclosure
Provisions on assets	0.0	193.7
Midstream
Provisions On Assets Disclosure
Provisions on assets	35.2	153.7
Midstream | Property, Plant and Equipment
Provisions On Assets Disclosure
Provisions on assets	35.0
Midstream | Intangible Assets
Provisions On Assets Disclosure
Provisions on assets	0.2
Power
Provisions On Assets Disclosure
Provisions on assets	$ 380.6	$ 381.3

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- 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, 2019 CAD ($) $ / MWh $ / gigajoule $ / gigajoule $ / MWh $ / barrel	Dec. 31, 2018 CAD ($)
Derivative
Unrealized gains (losses) on risk management contracts	$ (85.3)	$ 80.8
Alberta power price
Derivative
Increase or decrease to forward prices, energy | $ / MWh	1
Unrealized gains (losses) on risk management contracts	$ 2.3
PJM power price
Derivative
Increase or decrease to forward prices, energy | $ / MWh	1
Unrealized gains (losses) on risk management contracts	$ 1.9
AECO natural gas price
Derivative
Increase or decrease to forward prices, energy | $ / gigajoule	0.5
Unrealized gains (losses) on risk management contracts	$ 1.1
NYMEX natural gas price
Derivative
Increase or decrease to forward prices, energy | $ / gigajoule	0.5
Unrealized gains (losses) on risk management contracts	$ 2.6
Energy exports | Propane
Derivative
Increase or decrease to forward prices, volume | $ / barrel	1
Unrealized gains (losses) on risk management contracts	$ 3.4
Baltic LPG Freight | Propane
Derivative
Increase or decrease to forward prices, volume | $ / barrel	1
Unrealized gains (losses) on risk management contracts	$ 6.1
NGL frac spread
Derivative
Unrealized gains (losses) on risk management contracts	$ (17.4)	$ 40.0
NGL frac spread | Western Texas Intermediate (WTI) crude oil
Derivative
Increase or decrease to forward prices, volume | $ / barrel	1
Unrealized gains (losses) on risk management contracts	$ 0.6
NGL frac spread | Gas purchase
Derivative
Increase or decrease to forward prices, energy | $ / gigajoule	0.5
Unrealized gains (losses) on risk management contracts	$ 1.9

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Pension Plans and Retiree Benefits - Schedule of Funded Status Based on Accumulated Benefit Obligation (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Canada
Defined Benefit Plan Disclosure
Accumulated benefit obligation	$ (34.7)	$ (32.9)
United States
Defined Benefit Plan Disclosure
Accumulated benefit obligation	$ (1,616.4)	$ (1,525.6)

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Other Income - Schedule of Other Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Other Income and Expenses [Abstract]
Gains (losses) from sale of assets	$ 875.8	$ (10.6)
Other components of net benefit cost (note 28)	27.4	18.9
Interest income and other revenue	9.0	2.7
Losses on investments	(4.1)	(10.1)
Total other income	$ 908.1	$ 0.9

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Assets Held For Sale

12 Months Ended

Dec. 31, 2019

Discontinued Operations and Disposal Groups [Abstract]

Assets Held For Sale

Dispositions

Northwest Hydro Electric Facilities

On January 31, 2019, AltaGas completed the disposition of its remaining 55 percent indirect interest in the Northwest Hydro Electric facilities in British Columbia (Northwest Hydro) for net cash proceeds of approximately $1.3 billion. The disposition was completed through the sale of 55 percent of Northwest Hydro Limited Partnership, a subsidiary of AltaGas which indirectly held the Northwest Hydro facilities. As a result, AltaGas recognized a pre-tax gain on disposition of approximately $687.6 million in the Consolidated Statements of Income (Loss) under the line item “other income” for the year ended December 31, 2019.

Non-Core Midstream and Power Assets in Canada

On February 1, 2019, AltaGas completed the disposition of certain non-core Midstream and Power assets for gross cash proceeds of approximately $87.8 million. As a result, AltaGas recognized a pre-tax loss on disposition of approximately $1.2 million in the Consolidated Statements of Income (Loss) under the line item “other income” for the year ended December 31, 2019.

Architect of the Capitol (AOC) Project

In February 2019, AltaGas completed the disposition of a financing receivable related to the construction of an energy management services project for gross cash proceeds of approximately $73.5 million. As a result, AltaGas recognized a pre-tax loss on disposition of approximately $1.3 million in the Consolidated Statements of Income (Loss) under the line item “other income” for the year ended December 31, 2019.

Stonewall Gas Gathering System

On May 31, 2019, AltaGas completed the disposition of WGL Midstream's entire interest in the Stonewall Gas Gathering System (Stonewall) to a wholly-owned subsidiary of DTE Energy Company for gross cash proceeds of approximately $379.2 million (US$280 million). As a result, AltaGas recognized a pre-tax gain on disposition of $34.1 million in the Consolidated Statements of Income (Loss) under the line item “other income” for the year ended December 31, 2019.

Biomass Assets

On August 13, 2019, AltaGas completed the disposition of its equity ownership interests in Craven County Wood Energy LP and Grayling Generation Station LP for net proceeds of approximately $24.5 million (US$18.5 million). There was no gain or loss resulting from this disposition.

Distributed Generation Assets

On September 26, 2019, AltaGas closed the disposition of its portfolio of U.S. distributed generation assets for gross cash proceeds of approximately $975.0 million (US$735.0 million).As a result, AltaGas recognized a pre-tax gain on disposition of approximately $167.5 millionin the Consolidated Statements of Income (Loss) under the line item "other income" for the year ended December 31, 2019. There are certain projects for which ownership will not legally transfer to the purchaser until various consents and approvals are obtained. As such, the carrying value of the assets and liabilities relating to these projects remain classified as held for sale on the Consolidated Balance Sheets as at December 31, 2019 (Note 5). The portion of the purchase price relating to these projects is approximately $32.2 million(US$24.8 million)and is recorded within "accounts payable and accrued liabilities" on the Consolidated Balance Sheets until these projects are legally transferred to the purchaser. The pre-tax gain related to these remaining projects has also been deferred and will be recognized as these projects are legally transferred. The purchaser is entitled to after-tax earnings from the distributed generation projects, including those awaiting consent, beginning September 1, 2019.

Capital Spare

In the third quarter of 2019, AltaGas completed the sale of a capital spare turbine in the Power segment for gross cash proceeds of $4.6 million (US$3.5 million). There was no gain or loss resulting from this disposition in the year ended December 31, 2019.

Investment in Meade

On November 13, 2019, AltaGas completed the disposition of its investment in Meade Pipeline Co. LLC (Meade) which held WGL Midstream's indirect, non-operating interest in the Central Penn pipeline (Central Penn), for cash proceeds of approximately $811.5 million (US$610.8 million). As a result, AltaGas recognized a pre-tax loss on disposition of $11.1 millionin the Consolidated Statements of Income (Loss) under the line item “other income” for the year ended December 31, 2019. During 2019, AltaGas also recognized a pre-tax provision of $44.2 million against AltaGas' investment in Meade Pipeline Co. LLC (Note 14).

Assets Held For Sale

As at	December 31, 2019		December 31, 2018
Assets held for sale
Cash	$	—	$	4.9
Accounts receivable	—		85.2
Inventory	—		0.5
Property, plant and equipment	22.9		1,189.6
Intangible assets	—		248.7
Operating right-of-use assets	0.4		—
Goodwill	1.0		—
Other long-term assets	3.2		—
	$	27.5	$	1,528.9
Liabilities associated with assets held for sale
Accounts payable and accrued liabilities	$	—	$	23.8
Asset retirement obligations	0.2		10.8
Unamortized investment tax credits	3.2		—
Operating lease liabilities - long-term	0.4		—
Other long-term liabilities	—		136.8
	$	3.8	$	171.4

Distributed Generation Assets

In September 2019, AltaGas closed the sale of its portfolio of U.S. distributed generation assets (Note 4). However, there are certain projects for which ownership will not legally transfer to the purchaser until various consents and approvals are obtained. As such, the carrying value of the assets and liabilities related to these projects remain classified as held for sale at December 31, 2019. These assets are recorded in the Power segment.

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Intangible Assets

12 Months Ended

Dec. 31, 2019

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets

Intangible Assets

As at	December 31, 2019							December 31, 2018
	Cost		Accumulated amortization			Net book value		Cost			Accumulated amortization			Net book value
E&T contracts	$	26.6	$	(15.2	)	$	11.4	$	26.6		$	(14.3	)	$	12.3
Electricity service agreements	8.5		(7.8		)	0.7		269.5			(25.9		)	243.6
Energy services relationships	91.6		(27.4		)	64.2		176.1			(33.8		)	142.3
Software	303.7		(101.2		)	202.5		293.9			(77.7		)	216.2
Land rights	1.1		(0.1		)	1.0		1.4			(0.2		)	1.2
Commodity contracts	327.1		(21.3		)	305.8		346.3			(6.3		)	340.0
Franchises and consents	—		—			—		5.0			—			5.0
Reclassified to assets held for sale (note 5)	—		—			—		(277.4		)	28.7			(248.7		)
	$	758.6	$	(173.0	)	$	585.6	$	841.4		$	(129.5	)	$	711.9

Amortization expense related to intangible assets for the year ended December 31, 2019 was 80.2 million(2018 - $69.7 million).

As at December 31, 2019, the Corporation excluded $184.5 million (December 31, 2018 - $196.4 million) from the asset base subject to amortization. Items excluded relate 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:

2020	$	79.1
2021	$	70.6
2022	$	69.7
2023	$	62.3
2024	$	24.2
Thereafter	$	95.2

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Shareholders’ Equity - Summary of Employee Share Option Plan (Details)	12 Months Ended
	Dec. 31, 2019 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award
Options outstanding, Number outstanding (shares) | shares	7,043,956
Options outstanding, Weighted average exercise price (per share)	$ 22.49
Options outstanding, Weighted average remaining contractual life	4 years 1 month 9 days
Options exercisable, Number exercisable (shares) | shares	2,921,641.666654
Options exercisable, Weighted average exercise price (per share)	$ 27.70
Options exercisable, Weighted average remaining contractual life	2 years 9 months 6 days
$14.52 to $18.00
Share-based Compensation Arrangement by Share-based Payment Award
Options outstanding, Exercise price range, Lower limit (per share)	$ 14.52
Options outstanding, Exercise price range, Upper limit (per share)	$ 18.00
Options outstanding, Number outstanding (shares) | shares	2,557,328
Options outstanding, Weighted average exercise price (per share)	$ 15.19
Options outstanding, Weighted average remaining contractual life	4 years 11 months 23 days
Options exercisable, Number exercisable (shares) | shares	638,384.666654
Options exercisable, Weighted average exercise price (per share)	$ 14.62
Options exercisable, Weighted average remaining contractual life	4 years 9 months 13 days
$18.01 to $25.08
Share-based Compensation Arrangement by Share-based Payment Award
Options outstanding, Exercise price range, Lower limit (per share)	$ 18.01
Options outstanding, Exercise price range, Upper limit (per share)	$ 25.08
Options outstanding, Number outstanding (shares) | shares	1,961,805
Options outstanding, Weighted average exercise price (per share)	$ 19.78
Options outstanding, Weighted average remaining contractual life	4 years 9 months 7 days
Options exercisable, Number exercisable (shares) | shares	305,750.000000
Options exercisable, Weighted average exercise price (per share)	$ 21.05
Options exercisable, Weighted average remaining contractual life	11 months 16 days
$25.09 to $46.70
Share-based Compensation Arrangement by Share-based Payment Award
Options outstanding, Exercise price range, Lower limit (per share)	$ 25.09
Options outstanding, Exercise price range, Upper limit (per share)	$ 46.70
Options outstanding, Number outstanding (shares) | shares	2,524,823
Options outstanding, Weighted average exercise price (per share)	$ 32.00
Options outstanding, Weighted average remaining contractual life	2 years 8 months 18 days
Options exercisable, Number exercisable (shares) | shares	1,977,507.000000
Options exercisable, Weighted average exercise price (per share)	$ 32.95
Options exercisable, Weighted average remaining contractual life	2 years 4 months 22 days

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Segmented Information

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Segmented Information

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	nrate-regulated natural gas distribution assets in Michigan, Alaska, the District of Columbia, Maryland, and Virginia; nrate-regulated natural gas storage in the United States; and nequity investment in AltaGas Canada Inc.
Midstream	nNGL processing and extraction plants; ntransmission pipelines to transport natural gas and NGL; nnatural gas gathering lines and field processing facilities; npurchase and sale of natural gas; nnatural gas storage facilities; nliquefied petroleum gas (LPG) terminal; nnatural gas and NGL marketing; nequity investment in Petrogas, a North American entity engaged in the marketing, storage and distribution of NGL, drilling fluids, crude oil and condensate diluents; ninterest in a regulated pipeline in the Marcellus/Utica gas formation; and nsale of natural gas to residential, commercial and industrial customers in Washington D.C., Maryland, Virginia, Delaware, and Pennsylvania.
Power	nnatural gas-fired and distributed generation assets, certain of which are pending sale, whereby outputs are generally sold under power purchase agreements, both operational and under development; nenergy storage; and nsale of power to residential, commercial, and industrial users in Washington D.C., Maryland, Virginia, Delaware, Pennsylvania, and Ohio.
Corporate	nthe 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 24:

	Year Ended December 31, 2019
	Utilities		Midstream		Power		Corporate		Total
External revenue (note 24)	$	2,564.2	$	1,574.3	$	1,356.3	$	0.2	$	5,495.0
Intersegment revenue	26.6		6.9		10.9		—		$	44.4
Segment revenue	$	2,590.8	$	1,581.2	$	1,367.2	$	0.2	$	5,539.4

	Year Ended December 31, 2018
	Utilities		Midstream		Power		Corporate			Total
External revenue (note 24)	$	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	2019		2018
Revenue (a)
Canada	$	1,244.8	$	1,626.8
United States	4,325.5		2,553.0
TOTAL	$	5,570.3	$	4,179.8

(a) Operating revenue from external customers, excluding unrealized gains (losses) or risk management contracts.

As at December 31	2019		2018
Property, plant and equipment
Canada	$	2,682.2	$	2,348.2
United States	7,443.3		8,581.4
TOTAL	$	10,125.5	$	10,929.6

The following tables show the composition by segment:

	Year Ended December 31, 2019
	Utilities			Midstream			Power			Corporate			Intersegment Elimination (a)			Total
Segment revenue	$	2,590.8		$	1,581.2		$	1,367.2		$	0.2		$	(44.4	)	$	5,495.0
Cost of sales	(1,117.9		)	(1,057.7		)	(1,084.4		)	—			32.9			(3,227.1		)
Operating and administrative	(860.7		)	(249.1		)	(159.8		)	(40.6		)	11.5			(1,298.7		)
Accretion expenses	(0.1		)	(3.9		)	(1.1		)	—			—			(5.1		)
Depreciation and amortization	(261.6		)	(92.1		)	(72.3		)	(12.0		)	—			(438.0		)
Provisions on assets (note 6)	—			(35.2		)	(380.6		)	—			—			(415.8		)
Income from equity investments	18.3			122.4			0.4			—			—			141.1
Other income (loss)	27.0			28.7			853.8			(1.4		)	—			908.1
Foreign exchange gains (losses)	—			(4.5		)	—			3.5			—			(1.0		)
Interest expense	—			—			—			(345.8		)	—			(345.8		)
Income (loss) before income taxes	$	395.8		$	289.8		$	523.2		$	(396.1	)	$	—		$	812.7
Net additions (reductions) to:
Property, plant and equipment(b)	$	839.6		$	350.3		$	(2,281.3	)	$	1.2		$	—		$	(1,090.2	)
Intangible assets	$	22.6		$	4.9		$	—		$	9.0		$	—		$	36.5

(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 Statements of Cash Flows due to classification of business acquisition and foreign exchange changes on U.S. assets.

	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		)
Provision on assets (note 6)	(193.7		)	(153.7		)	(381.3		)	—			—			(728.7		)
Income (loss) 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 (losses)	—			(0.2		)	(0.1		)	4.8			—			4.5
Interest expense	(103.9		)	(10.6		)	(8.9		)	(185.6		)	—			(309.0		)
Income (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 Statements of Cash Flows 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, 2019
Goodwill	$	3,573.0	$	246.5	$	122.6	$	—	$	3,942.1
Segmented assets	$	13,097.1	$	5,471.4	$	1,019.9	$206.1		$	19,794.5
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

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Related Party Transactions - Schedule of Related Party Transactions (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Related Party Transaction
Revenue	$ 114.9	$ 68.4
Cost of sales	12.8	4.2
Operating and administrative recoveries	(1.8)	(1.3)
Other income	$ 3.2	9.2
Unrealized Loss On Foreign Exchange Hedge With ACI
Related Party Transaction
Revenue		$ 0.2

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Pension Plans and Retiree Benefits

12 Months Ended

Dec. 31, 2019

Retirement Benefits [Abstract]

Pension Plans and Retiree Benefits

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. The pension cost recorded for the DC plan was$19.8 million for the year ended December 31, 2019 (2018 - $15.4 million).

Defined Benefit Plans

AltaGas has several defined benefit pension plans for unionized and non-unionized employees, including one in Canada (which is comprised of five divisions) and sixin the United States. The plans in the United States include a qualified, trusteed, non-contributory defined benefit pension plan, and a non-funded defined benefit restoration plan maintained by Washington Gas.

The defined benefit plans are partially funded except for two of the divisions in Canada which are fully funded and one of the plans in the United States which is not 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 will be filed with the pension regulators in 2020. Actuarial valuations for funding purposes are required annually for AltaGas’ U.S. defined benefit plans.

Supplemental Executive Retirement Plans (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 or from the Rabbi Trusts funded as part of the WGL acquisition. Security will be provided for the SERP benefits through a letter of credit within a retirement compensation arrangement trust account.

Several executive officers of Washington Gas participate in a separate non-funded defined benefit SERP (a non-qualified pension plan). This defined benefit SERP was closed to new entrants beginning January 1, 2010.

Post-Retirement Benefit Plans

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 an annual allocation to a Healthcare Spending Account (HSA). This benefit plan is not funded.

Post-retirement benefit plans in the United States provide certain medical, prescription drug, dental, and life insurance 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. For eligible Washington Gas retirees and dependents not yet receiving Medicare benefits, Washington Gas provides medical, prescription drug, and dental benefits through Preferred Provider Organization (PPO) or Health Maintenance Organization (HMO) plans, through the Washington Gas Light Company Retiree Medical Plan. For Medicare-eligible retirees age 65 and older and their dependents, eligible retirees and dependents participate in a tax-free Health Reimbursement Account (HRA) Plan. The HRA plan provides an annual subsidy to help purchase supplemental medical, prescription drug and dental coverage in the marketplace. One of these benefit plans is partially funded and three of them are fully funded.

Rabbi Trusts

Rabbi trusts of $57.4 million as at December 31, 2019 have been funded to satisfy the employee benefit obligations associated with WGL’s various pension plans (December 31, 2018 - $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:

Year Ended December 31, 2019	Canada						United States						Total
	Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits
Projected benefit obligation (a)
Balance, beginning of year	$	34.3		$	1.9		$	1,635.3		$	458.0		$	1,669.6		$	459.9
Actuarial loss (gain)	2.1			0.2			182.0			(14.8		)	184.1			(14.6		)
Current service cost	2.6			—			23.8			8.5			26.4			8.5
Member contributions	—			—			—			2.2			—			2.2
Interest cost	1.2			0.1			67.8			19.1			69.0			19.2
Benefits paid	(4.0		)	(0.1		)	(77.3		)	(24.4		)	(81.3		)	(24.5		)
Expenses paid	(0.1		)	—			(0.6		)	(0.1		)	(0.7		)	(0.1		)
Settlements	—			—			(24.7		)	—			(24.7		)	—
Plan amendments	—			—			0.3			—			0.3			—
Other	—			—			—			1.0			—			1.0
Foreign exchange translation	—			—			(82.0		)	(21.8		)	(82.0		)	(21.8		)
Balance, end of year	$	36.1		$	2.1		$	1,724.6		$	427.7		$	1,760.7		$	429.8
Plan assets
Fair value, beginning of year	$	13.8		$	—		$	1,354.1		$	791.2		$	1,367.9		$	791.2
Actual return on plan assets	0.9			—			284.2			177.4			285.1			177.4
Employer contributions	4.3			0.1			38.7			0.1			43.0			0.2
Member contributions	—			—			—			2.2			—			2.2
Benefits paid	(4.0		)	(0.1		)	(77.3		)	(23.7		)	(81.3		)	(23.8		)
Expenses paid	(0.1		)	—			(0.6		)	(0.1		)	(0.7		)	(0.1		)
Settlements	—			—			(25.7		)	—			(25.7		)	—
Other	—			—			—			0.1			—			0.1
Foreign exchange translation	—			—			(69.5		)	(41.3		)	(69.5		)	(41.3		)
Fair value, end of year	$	14.9		$	—		$	1,503.9		$	905.9		$	1,518.8		$	905.9
Funded status	$	(21.2	)	$	(2.1	)	$	(220.7	)	$	478.2		$	(241.9	)	$	476.1

(a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation.

Year Ended December 31, 2018	Canada						United States						Total
	Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits
Projected benefit obligation (a)
Balance, beginning of year	$	165.6		$	15.8		$	303.8		$	82.7		$	469.4		$	98.5
Plans disposed	(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	(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
Funded status	$	(20.5	)	$	(1.9	)	$	(281.2	)	$	333.2		$	(301.7	)	$	331.3

(a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation.

The following amounts were included in the Consolidated Balance Sheets:

	December 31, 2019									December 31, 2018
	Defined Benefit			Post- Retirement Benefits			Total			Defined Benefit			Post- Retirement Benefits			Total (a)
Prepaid post-retirement benefits	$	—		$	486.8		$	486.8		$	—		$	341.4		$	341.4
Accounts payable and accrued liabilities	(25.7		)	—			(25.7		)	(27.6		)	—			(27.6		)
Future employee obligations	(216.2		)	(10.7		)	(226.9		)	(274.1		)	(10.1		)	(284.2		)
	$	(241.9	)	$	476.1		$	234.2		$	(301.7	)	$	331.3		$	29.6

(a) Account balances on the Consolidated Balance Sheets also include certain non-pension related amounts.

The accumulated benefit obligation for all defined benefit plans were:

As at	December 31, 2019				December 31, 2018
	Canada		United States		Canada		United States
Accumulated benefit obligation (a)	$	34.7	$	1,616.4	$	32.9	$	1,525.6

(a) Accumulated benefit obligation differs from projected benefit obligation in that it does not include an assumption with respect to future compensation levels.

The following amounts were recorded in other comprehensive income (loss) and have not yet been recognized in net periodic benefit cost:

Year Ended December 31, 2019	Canada						United States						Total
	Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits
Past service credit (cost)	$	(0.2	)	$	0.3		$	0.1		$	—		$	(0.1	)	$	0.3
Net actuarial gain (loss)	(9.4		)	(0.7		)	(14.9		)	18.2			(24.3		)	17.5
Recognized in AOCI pre-tax	$	(9.6	)	$	(0.4	)	$	(14.8	)	$	18.2		$	(24.4	)	$	17.8
Increase (decrease) by the amount included in deferred tax liabilities	2.3			0.1			7.0			(9.0		)	9.3			(8.9		)
Net amount in AOCI after-tax	$	(7.3	)	$	(0.3	)	$	(7.8	)	$	9.2		$	(15.1	)	$	8.9

Year Ended December 31, 2018	Canada						United States						Total
	Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits			Defined Benefit			Post- Retirement Benefits
Past service credit (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	)

The following amounts were recorded in a regulatory asset (liability) and have not yet been recognized in net periodic benefit cost:

Year Ended December 31, 2019	Canada				United States					Total
	Defined Benefit		Post- Retirement Benefits		Defined Benefit		Post- Retirement Benefits			Defined Benefit		Post- Retirement Benefits
Past service cost (credit)	$	—	$	—	$	1.1	$	(105.4	)	$	1.1	$	(105.4	)
Net actuarial loss (gain)	—		—		127.1		(155.8		)	127.1		(155.8		)
Recognized in regulatory asset (liability)	$	—	$	—	$	128.2	$	(261.2	)	$	128.2	$	(261.2	)

Year Ended December 31, 2018	Canada				United States					Total
	Defined Benefit		Post- Retirement Benefits		Defined Benefit		Post- Retirement Benefits			Defined Benefit		Post- Retirement Benefits
Past service cost (credit)	$	—	$	—	$	0.8	$	(110.2	)	$	0.8	$	(110.2	)
Net actuarial loss (gain)	—		—		188.2		(52.6		)	188.2		(52.6		)
Recognized in regulatory asset (liability)	$	—	$	—	$	189.0	$	(162.8	)	$	189.0	$	(162.8	)

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.

Amounts to be amortized in the next fiscal year from AOCI	Defined Benefit		Post-Retirement Benefits
Past service cost (credit)	$	0.2	$	(0.7	)
Actuarial loss	4.0		0.3
Total	$	4.2	$	(0.4	)

Amounts to be amortized in the next fiscal year from regulatory assets (liabilities)	Defined Benefit			Post-Retirement Benefits
Past service credit (cost)	$	(0.2	)	$	16.7
Actuarial gain (loss)	(17.1		)	0.5
Total	$	(17.3	)	$	17.2

The net pension expense by plan was as follows:

	Year Ended December 31, 2019
	Canada					United States						Total
	Defined Benefit			Post-Retirement Benefits		Defined Benefit			Post-Retirement Benefits			Defined Benefit			Post-Retirement Benefits
Current service cost (a)	$	2.6		$	—	$	23.8		$	8.5		$	26.4		$	8.5
Interest cost (b)	1.2			0.1		67.8			19.1			69.0			19.2
Expected return on plan assets (b)	(0.5		)	—		(74.6		)	(37.1		)	(75.1		)	(37.1		)
Amortization of past service cost (credit) (b)	0.1			—		0.4			(21.9		)	0.5			(21.9		)
Amortization of net actuarial loss (b)	0.9			—		11.7			0.1			12.6			0.1
Plan settlements (b)	—			—		4.1			—			4.1			—
Other (b)	—			—		—			0.9			—			0.9
Net benefit cost (income) recognized	$	4.3		$	0.1	$	33.2		$	(30.4	)	$	37.5		$	(30.3	)

(a) Recorded under the line item “operating and administrative” expenses on the Consolidated Statements of Income (Loss).

(b) Recorded under the line item “other income” on the Consolidated Statements of Income (Loss).

	Year Ended December 31, 2018
	Canada					United States						Total
	Defined Benefit			Post-Retirement Benefits		Defined Benefit			Post-Retirement Benefits			Defined Benefit			Post-Retirement 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 (credit) (b)	0.1			—		0.1			(11.5		)	0.2			(11.5		)
Amortization of net actuarial loss (b)	0.6			—		7.7			0.4			8.3			0.4
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 (Loss).

(b) Recorded under the line item “other income” on the Consolidated Statements of Income (Loss).

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's target asset mix for the Canadian plans is 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 50 percent to 60 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, 2019:

Canada	Fair value		Level 1		Level 2		Percentage of Plan Assets (%)
Cash and short-term equivalents	$	1.9	$	1.9	$	—	12.8
Canadian equities	4.1		4.1		—		27.5
Foreign equities	2.4		2.4		—		16.0
Fixed income	5.7		5.7		—		38.3
Real estate	0.8		—		0.8		5.4
	$	14.9	$	14.1	$	0.8	100.0

United States	Fair value			Level 1		Level 2			Percentage of Plan Assets (%)
Cash and short-term equivalents	$	10.8		$	10.8	$	—		0.4
Canadian equities	2.6			2.6		—			0.1
Foreign equities (a)	302.5			302.2		0.3			12.6
Fixed income	933.0			123.2		809.8			38.7
Derivatives	(0.2		)	—		(0.2		)	—
Other (b)	12.0			—		12.0			0.5
Total investments in the fair value hierarchy	$	1,260.7		$	438.8	$	821.9		52.3
Investments measured at net asset value using the NAV practical expedient (c)
Commingled funds (d)	$	648.9							26.9
Private equity/limited partnership (e)	55.6								2.3
Pooled separate accounts (f)	32.0								1.3
Collective trust fund (g)	433.8								18.1
Total fair value of plan investments	$	2,431.0							100.9
Net payable (h)	(21.2		)						(0.9	)
	$	2,409.8							100.0

(a) Investments in foreign equities include U.S. and international securities.

(b) As at December 31, 2019, these investments consisted primarily of non-U.S. government bonds.

(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 at December 31, 2019, investments in commingled funds consisted of approximately 58 percent common stock of large-cap U.S. companies, 18 percent U.S. Government fixed income securities, and 24 percent corporate bonds for WGL’s post-retirement benefit plans.

(e) As at December 31, 2019, investments in a private equity/limited partnership consisted of common stock of international companies.

(f) As at December 31, 2019, investments in pooled separate accounts consisted of income producing properties located in the United States.

(g) As at December 31, 2019, investments in collective trust funds consisted primarily of 90 percent common stock of U.S, companies, 8 percent income producing properties located in the United States, and 2 percent short-term money market investments.

(h) As at December 31, 2019, 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	$	12.7		$	12.7	$	—		0.5
Canadian equities	6.7			6.7		—			0.3
Foreign equities (a)	304.9			304.6		0.3			12.6
Fixed income	938.7			128.9		809.8			38.7
Derivatives	(0.2		)	—		(0.2		)	—
Real estate	0.8			—		0.8			—
Other (b)	12.0			—		12.0			0.5
Total investments in the fair value hierarchy	$	1,275.6		$	452.9	$	822.7		52.6
Investments measured at net asset value using the NAV practical expedient (c)
Commingled funds(d)	$	648.9							26.8
Private equity/limited partnership (e)	55.6								2.3
Pooled separate accounts (f)	32.0								1.3
Collective trust fund (g)	433.8								17.9
Total fair value of plan investments	$	2,445.9							100.9
Net payable (h)	(21.2		)						(0.9	)
	$	2,424.7							100.0

(a) Investments in foreign equities include U.S. and international securities.

(b) As at December 31, 2019, these investments consisted primarily of non-U.S. government bonds.

(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 at December 31, 2019, investments in commingled funds consisted of approximately 58 percent common stock of large-cap U.S. companies, 18 percent U.S. Government fixed income securities, and 24 percent corporate bonds for WGL’s post-retirement benefit plans.

(e) As at December 31, 2019, investments in a private equity/limited partnership consisted of common stock of international companies.

(f) As at December 31, 2019, investments in pooled separate accounts consisted of income producing properties located in the United States.

(g) As at December 31, 2019, investments in collective trust funds consisted primarily of 90 percent common stock of U.S, companies, 8 percent income producing properties located in the United States, and 2 percent short-term money market investments.

(h) As at December 31, 2019, this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable.

Year Ended December 31	2019		2018
Significant actuarial assumptions used in measuring net benefit plan costs	Defined Benefit	Post-Retirement Benefits	Defined Benefit	Post-Retirement Benefits
Discount rate (%)	2.90 - 4.40	3.90 - 4.50	3.25 - 4.30	3.60 - 4.30
Expected long-term rate of return on plan assets (%) (a)	5.75 - 7.15	4.66 - 7.15	3.20 - 7.60	3.75 - 7.60
Rate of compensation increase (%)	2.75 - 4.10	4.10	2.75 - 4.10	4.10
Average remaining service life of active employees (years)	9.0	13.2	9.6	14.1

(a) Only applicable for funded plans

As at December 31	2019		2018
Significant actuarial assumptions used in measuring benefit obligations	Defined Benefit	Post-Retirement Benefits	Defined Benefit	Post-Retirement Benefits
Discount rate (%)	2.90 - 3.50	3.10 - 3.60	3.60 - 4.40	3.90 - 4.50
Rate of compensation increase (%)	2.75 - 4.00	3.50	2.75 - 4.10	4.10

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 yields available 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 rate used to measure the expected cost of benefits for the next year was 6.3 percent. The health care cost trend rates were assumed to decline to between 2.0 and 4.5 percent by 2027.

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 2019:

	Increase		Decrease
Service and interest costs	$	1.9	$	(1.5	)
Accrued benefit obligation	$	22.7	$	(18.4	)

The following table shows the expected cash flows for defined benefit pension and other post-retirement plans:

	Defined Benefit		Post-Retirement Benefits
Expected employer contributions:
2020	$	37.0	$	3.2
Expected benefit payments:
2020	$	104.6	$	23.8
2021	$	85.1	$	22.6
2022	$	93.3	$	22.5
2023	$	90.0	$	22.3
2024	$	90.7	$	22.1
2025 - 2028	$	474.1	$	112.6

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Revenue

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Revenue

Revenue

The following tables disaggregate revenue by major sources for the year:

	Year Ended December 31, 2019
	Utilities			Midstream		Power		Corporate		Total
Revenue from contracts with customers
Commodity sales contracts	$	—		$	1,093.7	$	1,131.4	$	—	$	2,225.1
Midstream service contracts	—			145.0		—		—		145.0
Gas sales and transportation services	2,501.4			—		—		—		2,501.4
Storage services	28.1			—		—		—		28.1
Other	9.2			2.7		29.0		—		40.9
Total revenue from contracts with customers	$	2,538.7		$	1,241.4	$	1,160.4	$	—	$	4,940.5
Other sources of revenue
Revenue from alternative revenue programs (a)	$	29.5		$	—	$	—	$	—	$	29.5
Leasing revenue (b)	0.9			136.6		105.1		—		242.6
Risk management and trading activities (c) (d)	—			196.2		65.9		0.2		262.3
Other	(4.9		)	0.1		24.9		—		20.1
Total revenue from other sources	$	25.5		$	332.9	$	195.9	$	0.2	$	554.5
Total revenue	$	2,564.2		$	1,574.3	$	1,356.3	$	0.2	$	5,495.0

(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 for the year ended December 31, 2019 of $504.5 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract, which are in scope of ASC 606, are reported within 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 GAIL contract has a term of 20 years and began on March 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. 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 for the year ended December 31, 2018 of $264.2 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract, which are in scope of ASC 606, are reported within 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 GAIL 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 segment and by major source of revenue from contracts with customers.

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 contracts at the RIPET generate revenue from the sale and delivery of liquid propane purchased from upstream producers. Revenue from these sales contracts is recognized when propane is loaded onto transport vessels, which is the delivery point. AltaGas has the right to consideration in an amount that directly corresponds to the volumes of propane loaded on a vessel.

Commodity sales also include gas sales to residential, commercial, and industrial customers in certain jurisdictions 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 Corporation 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 approximately 20 years. These long-term purchase agreements provide stable cash flow by way of contracted prices for the underlying commodities. During 2019, AltaGas closed the sale of its U.S. portfolio of distributed generation assets, which included wholly owned solar and fuel cell projects and tax equity partnership interests (Note 4). Subsequent to the sale, AltaGas will continue to generate energy from its combined heating and power assets.

Commodity sales also include electricity sales to residential, commercial, and industrial customers in certain jurisdictions 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 Corporation is entitled to invoice the customer.

Contract Balances

As at December 31, 2019, a contract asset of $30.0 million has been recorded within long-term investments and other assetson the Consolidated Balance Sheets (December 31, 2018 – $11.5 million). 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, 2019 there is a contract asset of $58.6 million (December 31, 2018 - $47.3 million) recorded within prepaid expenses and other current assets 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. At December 31, 2019, contract liabilities of $1.7 million (December 31, 2018 - $2.2 million) have been recorded within accounts payable and accrued 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.

Contract Assets

As at	December 31, 2019			December 31, 2018
Balance, beginning of year	$	58.8		$	—
Additions	32.3			130.1
Transfers to held for sale (a)	—			(72.2		)
Transfers to accounts receivable (b)	—			(3.7		)
Foreign exchange translation	(2.5		)	4.6
Balance, end of year	$	88.6		$	58.8

(a) In the fourth quarter of 2018, WGL Energy Systems reached an agreement for the sale of a financing receivable included in the contract asset balance. Accordingly, the receivable was classified as held for sale at December 31, 2018. In February 2019, WGL Energy Systems completed the sale of the financing receivable (Note 4).

(b) Amounts included in contract assets are transferred to accounts receivable when AltaGas’ right to consideration becomes unconditional.

Contract Liabilities

As at	December 31, 2019			December 31, 2018
Balance, beginning of year	$	2.2		$	—
Additions	1.9			2.6
Revenue recognized from contract liabilities (a)	(2.2		)	(0.5		)
Foreign exchange translation	(0.2		)	0.1
Balance, end of year	$	1.7		$	2.2

(a) Recognition of revenue related to performance obligations satisfied in the current period for amounts that were previously included in contract liabilities.

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, 2019:

	2020		2021		2022		2023		2024		2025 & beyond		Total
Midstream service contracts	$	113.1	$	89.8	$	88.9	$	86.5	$	86.4	$	971.9	$	1,436.6
Storage services	24.2		24.2		23.5		23.2		23.2		168.4		286.7
Other	19.4		8.9		2.0		2.0		2.0		12.0		46.3
	$	156.7	$	122.9	$	114.4	$	111.7	$	111.6	$	1,152.3	$	1,769.6

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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Segmented Information - Narrative (Details)	12 Months Ended
	Dec. 31, 2019 segment
Segment Reporting [Abstract]
Number of reporting segments	4

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Short-term Debt

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Short-term Debt

Short-term Debt

As at	December 31, 2019		December 31, 2018
Bank indebtedness	$	—	$	0.2
Commercial paper (a)	389.0		1,145.2
Project financing	71.0		64.5
	$	460.0	$	1,209.9

(a) 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. As at December 31, 2019, certain commercial paper balances have been classified as long-term debt as they are supported by long-term extendible committed credit facilities with maturities ranging from 2022 to 2024 (see Note 16).

Project Financing

WGL and certain of its subsidiaries previously obtained third-party project financing on behalf of the United States federal government to provide funds for the construction of certain energy management services projects entered into under Washington Gas' area-wide contract. When theseprojects are formally accepted by the government and deemed complete, the ownership of the receivable is assigned 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. As at December 31, 2019, draws related to project financing were $71.0 million (December 31, 2018 - $64.5 million).

Other Credit Facilities

As at December 31, 2019, the Corporation held a $70.0 million (December 31, 2018 - $70.0 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, 2019 were $nil (December 31, 2018 - $nil).

As at December 31, 2019, AltaGas held a $150.0 million (December 31, 2018 - $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, 2019 were $25.5 million (December 31, 2018 - $117.0 million).

As at December 31, 2019, AltaGas held a US$200.0 million (December 31, 2018 - US$200.0 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, 2019 were $156.4 million (December 31, 2018 - $147.3 million).

As at December 31, 2019, AltaGas held a US$300.0 million (December 31, 2018 - US$300.0 million) 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, 2019 were $124.6 million (December 31, 2018 - $nil).

WGL and Washington Gas use short-term debt in the form of commercial paper and advances under its syndicated bank credit facilities 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. As at December 31, 2019, commercial paper outstanding classified as short-term debt totaled US$299.5 million (December 31, 2018 - US$839.5 million).

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Subsequent Events (Details) - CAD ($)	Feb. 27, 2020	Jan. 02, 2020	Dec. 31, 2019	Dec. 31, 2018
Subsequent Event
Equity method investment			$ 1,461,600,000	$ 2,392,400,000
Subsequent Event | AIJVLP
Subsequent Event
Controlling interest (percent)		50.00%
Subsequent Event | Constitution Pipeline
Subsequent Event
Equity method investment, ownership interest (percent)	10.00%
Equity method investment	$ 0
Subsequent Event | Idemitsu | AIJVLP
Subsequent Event
Controlling interest (percent)		50.00%
Subsequent Event | SAM | Petrogas
Subsequent Event
Noncontrolling ownership interest (percent)		33.00%

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Other Long-term Liabilities

12 Months Ended

Dec. 31, 2019

Other Liabilities Disclosure [Abstract]

Other Long-term Liabilities

Other Long-term Liabilities

As at	December 31, 2019		December 31, 2018
Deferred lease payable	$	—	$	13.1
Deferred revenue	4.0		3.9
Customer advances for construction	63.9		58.6
Sundance B PPAs termination expense (a)	—		2.0
Lease inducement	—		2.7
Merger commitments	14.0		21.4
Other long-term liabilities	19.9		20.3
	$	101.8	$	122.0

(a) In 2016, AltaGas Pipeline Partnership and the Government of Alberta reached a definitive settlement agreement regarding the termination of the Sundance B Power Purchase Arrangements (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”.

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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, 2019 CAD ($)
Defined Benefit
Defined Benefit Plan Disclosure
Past service cost (credit)	$ 0.2
Actuarial loss	4.0
Total	4.2
Post- Retirement Benefits
Defined Benefit Plan Disclosure
Past service cost (credit)	(0.7)
Actuarial loss	0.3
Total	$ (0.4)

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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, 2019	Dec. 31, 2018
Defined Benefit
Significant actuarial assumptions used in measuring net benefit plan costs
Average remaining service life of active employees	9 years	9 years 7 months 6 days
Defined Benefit | Minimum
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate (percent)	2.90%	3.25%
Expected long-term rate of return on plan assets (percent)	5.75%	3.20%
Rate of compensation increase (percent)	2.75%	2.75%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate (percent)	2.90%	3.60%
Rate of compensation increase (percent)	2.75%	2.75%
Defined Benefit | Maximum
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate (percent)	4.40%	4.30%
Expected long-term rate of return on plan assets (percent)	7.15%	7.60%
Rate of compensation increase (percent)	4.10%	4.10%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate (percent)	3.50%	4.40%
Rate of compensation increase (percent)	4.00%	4.10%
Post- Retirement Benefits
Significant actuarial assumptions used in measuring net benefit plan costs
Rate of compensation increase (percent)	4.10%	4.10%
Average remaining service life of active employees	13 years 2 months	14 years 1 month 6 days
Significant actuarial assumptions used in measuring benefit obligations
Rate of compensation increase (percent)	3.50%	4.10%
Post- Retirement Benefits | Minimum
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate (percent)	3.90%	3.60%
Expected long-term rate of return on plan assets (percent)	4.66%	3.75%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate (percent)	3.10%	3.90%
Post- Retirement Benefits | Maximum
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate (percent)	4.50%	4.30%
Expected long-term rate of return on plan assets (percent)	7.15%	7.60%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate (percent)	3.60%	4.50%

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Consolidated Statements of Equity - CAD ($) $ in Millions		Total	Total shareholders' equity	Common shares (note 25)	Preferred shares (note 25)	Contributed surplus	Accumulated deficit	AOCI (note 22)	Non-controlling interests
Net Income (Loss) Attributable to Parent		$ (435.1)
Balance, beginning of year at Dec. 31, 2017				$ 4,007.9	$ 1,277.7	$ 22.3	$ (933.6)	$ 199.1	$ 65.8
Increase (Decrease) in Stockholders' Equity
Exercise of share options				1.3		(0.1)
Shares issued under DRIP	[1]			325.8
Deferred taxes on share issuance costs				13.3
Shares issued on conversion of subscription receipts, net of issuance costs				2,305.6
Shares acquired through WGL Acquisition					41.1				9.0
Share options expense						0.9
Forfeiture of share options						(0.1)
Sale of non-controlling interest						350.2			498.4
Net income (loss) applicable to controlling interests		(453.7)					(435.1)		(18.6)
Common share dividends							(462.9)
Preferred share dividends							(66.6)
Gain on redemption of preferred shares		0.0
Other comprehensive income (loss)		379.9						379.9
Contributions from non-controlling interests to subsidiaries									96.3
Distributions by subsidiaries to non-controlling interests									(30.3)
Balance, end of year at Dec. 31, 2018		7,640.2	$ 7,019.6	6,653.9	1,318.8	373.2	(1,905.3)	579.0	620.6
Net Income (Loss) Attributable to Parent		833.5					833.5
Increase (Decrease) in Stockholders' Equity
Exercise of share options				1.2		(0.1)
Shares issued under DRIP	[1]			67.8
Deferred taxes on share issuance costs				(3.9)	(0.6)
Redemption of WGL preferred shares					(41.1)
Share options expense						3.7
Forfeiture of share options						(0.1)
Net income (loss) applicable to controlling interests		840.3							6.8
Common share dividends							(266.0)
Preferred share dividends							(68.5)
Gain on redemption of preferred shares		3.5					3.5
Other comprehensive income (loss)		(334.1)						(334.1)
Adjustment on disposition of assets									(508.0)
Contributions from non-controlling interests to subsidiaries									47.9
Distributions by subsidiaries to non-controlling interests									(13.4)
Balance, end of year at Dec. 31, 2019		$ 7,368.8	$ 7,214.9	$ 6,719.0	$ 1,277.1	$ 376.7	$ (1,402.8)	$ 244.9	$ 153.9

[1] Premium Dividend™, Dividend Reinvestment and Optional Cash Purchase Plan.

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Variable Interest Entities - Narratives (Details)	Nov. 12, 2019	May 05, 2017
Meade Pipeline Co LLC
Variable Interest Entity
VIE ownership percentage	55.00%
Central Penn
Variable Interest Entity
VIE inderect ownership percentage	21.00%
Altagas LPG | RILE LP
Variable Interest Entity
VIE ownership percentage		70.00%
Vopak | RILE LP
Variable Interest Entity
VIE ownership percentage		30.00%

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Consolidated Balance Sheets - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents (note 31)	$ 57.1	$ 101.6
Accounts receivable, net of allowances (note 23)	1,222.4	1,547.5
Inventory (note 7)	505.6	515.9
Restricted cash holdings from customers (note 31)	4.0	4.1
Regulatory assets (note 21)	12.8	21.0
Risk management assets (note 23)	86.6	114.1
Prepaid expenses and other current assets (notes 28 and 31)	280.2	199.9
Assets held for sale (note 5)	27.5	1,528.9
Total current assets	2,196.2	4,033.0
Property, plant and equipment (note 8)	10,125.5	10,929.6
Intangible assets (note 9)	585.6	711.9
Operating right-of-use assets (note 10)	169.8
Goodwill (note 11)	3,942.1	4,068.2
Regulatory assets (note 21)	486.7	663.0
Risk management assets (note 23)	39.1	57.7
Restricted cash holdings from customers (note 31)	3.9	6.1
Prepaid post-retirement benefits (note 28)	487.5	342.7
Long-term investments and other assets (notes 12, 28, and 31)	296.5	283.1
Investments accounted for by the equity method (note 14)	1,461.6	2,392.4
Total assets	19,794.5	23,487.7
Current liabilities
Accounts payable and accrued liabilities (notes 17, 18, 23, and 28)	1,324.9	1,488.2
Dividends payable (note 23)	22.3	22.0
Short-term debt (notes 15 and 23)	460.0	1,209.9
Current portion of long-term debt (notes 16 and 23)	922.9	890.2
Customer deposits	76.6	98.0
Regulatory liabilities (note 21)	145.5	114.9
Risk management liabilities (note 23)	124.8	89.3
Operating lease liabilities (note 10)	27.3
Other current liabilities (note 23)	17.0	18.1
Liabilities associated with assets held for sale (note 5)	3.8	171.4
Total current liabilities	3,125.1	4,102.0
Long-term debt (notes 16 and 23)	5,927.8	8,066.9
Asset retirement obligations (note 17)	362.0	500.6
Unamortized investment tax credits (note 20)	3.8	190.1
Deferred income taxes (note 20)	959.1	957.9
Regulatory liabilities (note 21)	1,383.2	1,392.8
Risk management liabilities (note 23)	167.0	213.0
Operating lease liabilities (note 10)	153.4
Other long-term liabilities (notes 19 and 23)	101.8	122.0
Future employee obligations (note 28)	242.5	302.2
Total liabilities	12,425.7	15,847.5
Shareholders' equity
Common shares, no par values, unlimited shares authorized; 2019 - 279.1 million and 2018 - 275.2 million issued and outstanding (note 25)	6,719.0	6,653.9
Preferred shares (note 25)	1,277.1	1,318.8
Contributed surplus	376.7	373.2
Accumulated deficit	(1,402.8)	(1,905.3)
Accumulated other comprehensive income (AOCI) (note 22)	244.9	579.0
Total shareholders' equity	7,214.9	7,019.6
Non-controlling interests	153.9	620.6
Total equity	7,368.8	7,640.2
Total liabilities and shareholders' equity	$ 19,794.5	$ 23,487.7

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2019

Related Party Transactions [Abstract]

Summary of Related Party Amounts Included in Balance Sheets

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, 2019		December 31, 2018
Due from related parties
Accounts receivable (a)	$	17.8	$	60.8
Long-term investments and other assets (b)	45.0		45.0
	$	62.8	$	105.8
Due to related parties
Accounts payable (c)	$	2.7	$	6.3
Risk management liabilities - current (d)	—		0.9
	$	2.7	$	7.2

(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, 2019, Petrogas had drawn $45.0 million (December 31, 2018 - $45.0 million) under the facility.

(c) Payables to joint venture.

(d) Foreign exchange hedge with ACI.

Schedule of Related Party Transactions

The following transactions with related parties have been recorded on the Consolidated Statements of Income (Loss) for the years ended December 31, 2019 and 2018:

Year Ended December 31	2019			2018
Revenue (a)	$	114.9		$	68.4
Cost of sales (b)	$	12.8		$	4.2
Operating and administrative recoveries (c)	$	(1.8	)	$	(1.3	)
Other income (d)	$	3.2		$	9.2

(a) In the ordinary course of business, AltaGas sold natural gas and natural gas liquids to a joint venture and ACI. For the year ended December 31, 2018, revenue also includes an unrealized loss on a foreign exchange hedge with ACI of $0.2 million.

(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 addition, subsequent to the initial public offering (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.

(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 2018. Loans to ACI were fully repaid by December 31, 2018.

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Leases - Components of Lease Cost (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 CAD ($)
Lease, Cost
Operating lease cost (includes variable lease payments)	$ 29.2
Amortization of right-of-use assets	3.4
Interest on lease liabilities	0.3
Total finance lease cost	3.7
Total lease cost	$ 32.9

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Accumulated Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2019

Accumulated Other Comprehensive Income (Loss), Net of Tax [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, 2019	$	—		$	(19.0	)	$	(209.2	)	$	801.4		$	5.8		$	579.0
OCI before reclassification	—			15.2			68.2			(406.2		)	(0.7		)	(323.5		)
Amounts reclassified from OCI	—			1.1			—			—			—			1.1
Current period OCI (pre-tax)	—			16.3			68.2			(406.2		)	(0.7		)	(322.4		)
Income tax on amounts retained in AOCI	—			(3.2		)	(8.2		)	—			—			(11.4		)
Income tax on amounts reclassified to earnings	—			(0.3		)	—			—			—			(0.3		)
Net current period OCI	—			12.8			60.0			(406.2		)	(0.7		)	(334.1		)
Ending balance, December 31, 2019	$	—		$	(6.2	)	$	(149.2	)	$	395.2		$	5.1		$	244.9
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 AOCI	—			0.7			—			—			—			0.7
Adoption of ASU No. 2016-01	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

Summary of Reclassification from Accumulated Other Comprehensive Income

Reclassification From Accumulated Other Comprehensive Income

AOCI components reclassified	Income statement line item	Year Ended December 31, 2019			Year Ended December 31, 2018
Defined benefit pension and PRB plans	Other income	$	1.1		$	0.7
Deferred income taxes	Income tax expense – deferred	(0.3		)	(0.2		)
		$	0.8		$	0.5

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- Schedule of Preferred Shares Issued and Outstanding (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 CAD ($)	Dec. 31, 2018 CAD ($) shares	Dec. 31, 2019 $ / shares	Dec. 31, 2019 CAD ($) shares
Class of Stock
Preferred stock, value		$ 7,019.6		$ 7,214.9
Fair value adjustment on WGL Acquisition (note 3)		$ 89.0		$ 84.3
Preferred shares
Class of Stock
Preferred stock, shares | shares		52,280,600		52,000,000
Preferred stock, value		$ 1,318.8		$ 1,277.1
Share issuance costs, net of taxes	$ (28.5)	(27.9)
Fair value adjustment on WGL Acquisition (note 3)		$ 4.1		$ 0.0
Preferred shares | Series A
Class of Stock
Preferred stock, shares | shares		5,511,220		5,511,220
Preferred stock, value		$ 137.8		$ 137.8
Preferred shares | Series B
Class of Stock
Preferred stock, shares | shares		2,488,780		2,488,780
Preferred stock, value		$ 62.2		$ 62.2
Preferred shares | Series C
Class of Stock
Preferred stock, shares | shares		8,000,000		8,000,000
Preferred stock, value		$ 205.6		$ 205.6
Preferred shares | Series E
Class of Stock
Preferred stock, shares | shares		8,000,000		8,000,000
Preferred stock, value		$ 200.0		$ 200.0
Preferred shares | Series G
Class of Stock
Preferred stock, shares | shares		8,000,000		6,885,823
Preferred stock, value		$ 200.0		$ 172.1
Preferred shares | Series H
Class of Stock
Preferred stock, shares | shares		0		1,114,177
Preferred stock, value		$ 0.0		$ 27.9
Preferred shares | Series I
Class of Stock
Preferred stock, shares | shares		8,000,000		8,000,000
Preferred stock, value		$ 200.0		$ 200.0
Preferred shares | Series K
Class of Stock
Preferred stock, shares | shares		12,000,000		12,000,000
Preferred stock, value		$ 300.0		$ 300.0
Preferred shares | $4.80 series | Washington Gas
Class of Stock
Preferred stock, shares | shares		150,000		0
Preferred stock, value		$ 19.7		$ 0.0
Preferred stock par value (usd per share) | $ / shares			$ 4.80
Preferred shares | $4.25 series | Washington Gas
Class of Stock
Preferred stock, shares | shares		70,600		0
Preferred stock, value		$ 9.4		$ 0.0
Preferred stock par value (usd per share) | $ / shares			4.25
Preferred shares | $5.00 series | Washington Gas
Class of Stock
Preferred stock, shares | shares		60,000		0
Preferred stock, value		$ 7.9		$ 0.0
Preferred stock par value (usd per share) | $ / shares			$ 5.00

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Revenue - Narrative (Details) - CAD ($) $ in Millions		12 Months Ended
	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue
Contract term	20 years
Contract asset, non current		$ 30.0	$ 11.5
Contract asset, current		58.6	47.3
Contract liability		$ 1.7	$ 2.2
Midstream | Operating Segments | Commodity sales contracts
Disaggregation of Revenue
Contract term		1 year
Midstream | Operating Segments | Commodity sales contracts | Residential, commercial, and industrial | Minimum
Disaggregation of Revenue
Contract term			1 year
Midstream | Operating Segments | Commodity sales contracts | Residential, commercial, and industrial | Maximum
Disaggregation of Revenue
Contract term			5 years
Power | Operating Segments | Commodity sales contracts
Disaggregation of Revenue
Long-term Purchase Commitment, Period		20 years

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Net Income (Loss) Per Common Share (Tables)

12 Months Ended

Dec. 31, 2019

Earnings Per Share [Abstract]

Summary of Net Income per Common Share

The following table summarizes the computation of net income (loss) per common share:

	Year Ended December 31
	2019			2018
Numerator:
Net income (loss) applicable to controlling interests	$	833.5		$	(435.1	)
Less: Preferred share dividends	(68.5		)	(66.6		)
Gain on redemption of preferred shares (note 25)	3.5			—
Net income (loss) applicable to common shares	$	768.5		$	(501.7	)
Denominator:
(millions)
Weighted average number of common shares outstanding	276.9			222.6
Dilutive equity instruments (a)	0.5			—
Weighted average number of common shares outstanding - diluted	277.4			222.6
Basic net income (loss) per common share	$	2.78		$	(2.25	)
Diluted net income (loss) per common share	$	2.77		$	(2.25	)

(a) Includes all options that have a strike price lower than the average share price of AltaGas' common shares during the periods noted.

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Leases - Narratives (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Operating Leased Assets
Operating leases that have yet to commence	$ 4.8
Operating leases that have yet to commence (term)	6 years
Property, plant and equipment	$ 10,125.5	$ 10,929.6
Assets leased to others
Operating Leased Assets
Property, plant and equipment	$ 500.0

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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, 2019	Dec. 31, 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	$ 86.6	$ 114.1
Risk management assets - non-current	39.1	57.7
Risk management liabilities - current	124.8	89.3
Risk management liabilities - non-current	167.0	213.0
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Loans and receivables	45.0	45.0
Financial assets	175.0	225.2
Current portion of long-term debt	922.9	890.2
Long-term debt	5,927.8	8,066.9
Other current liabilities	15.4	11.2
Other long-term liabilities		2.0
Financial liabilities	7,157.9	9,272.6
Carrying Amount | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	81.4	99.0
Risk management assets - non-current	30.9	49.0
Equity securities	4.3	8.4
Risk management liabilities - current	120.6	72.0
Risk management liabilities - non-current	77.0	103.4
Carrying Amount | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	5.2	15.1
Risk management assets - non-current	8.2	8.7
Risk management liabilities - current	4.2	17.3
Risk management liabilities - non-current	90.0	109.6
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Loans and receivables	46.1	45.2
Financial assets	176.1	225.4
Current portion of long-term debt	922.9	884.4
Long-term debt	6,263.8	8,040.3
Other current liabilities	15.4	11.2
Other long-term liabilities		2.0
Financial liabilities	7,493.9	9,240.2
Fair Value | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	81.4	99.0
Risk management assets - non-current	30.9	49.0
Equity securities	4.3	8.4
Risk management liabilities - current	120.6	72.0
Risk management liabilities - non-current	77.0	103.4
Fair Value | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	5.2	15.1
Risk management assets - non-current	8.2	8.7
Risk management liabilities - current	4.2	17.3
Risk management liabilities - non-current	90.0	109.6
Fair Value | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Loans and receivables	0.0	0.0
Financial assets	4.3	8.4
Current portion of long-term debt	0.0	0.0
Long-term debt	0.0	0.0
Other current liabilities	0.0	0.0
Other long-term liabilities		0.0
Financial liabilities	0.0	0.0
Fair Value | Level 1 | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	0.0	0.0
Risk management assets - non-current	0.0	0.0
Equity securities	4.3	8.4
Risk management liabilities - current	0.0	0.0
Risk management liabilities - non-current	0.0	0.0
Fair Value | Level 1 | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	0.0	0.0
Risk management assets - non-current	0.0	0.0
Risk management liabilities - current	0.0	0.0
Risk management liabilities - non-current	0.0	0.0
Fair Value | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Loans and receivables	46.1	45.2
Financial assets	83.6	134.2
Current portion of long-term debt	922.9	884.4
Long-term debt	6,263.8	8,040.3
Other current liabilities	15.4	11.2
Other long-term liabilities		2.0
Financial liabilities	7,320.6	8,997.5
Fair Value | Level 2 | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	30.4	68.3
Risk management assets - non-current	6.7	18.0
Equity securities	0.0	0.0
Risk management liabilities - current	98.7	41.3
Risk management liabilities - non-current	19.2	15.3
Fair Value | Level 2 | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	0.0	2.7
Risk management assets - non-current	0.4	0.0
Risk management liabilities - current	0.6	2.9
Risk management liabilities - non-current	0.0	0.1
Fair Value | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Loans and receivables	0.0	0.0
Financial assets	88.2	82.8
Current portion of long-term debt	0.0	0.0
Long-term debt	0.0	0.0
Other current liabilities	0.0	0.0
Other long-term liabilities		0.0
Financial liabilities	173.3	242.7
Fair Value | Level 3 | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	51.0	30.7
Risk management assets - non-current	24.2	31.0
Equity securities	0.0	0.0
Risk management liabilities - current	21.9	30.7
Risk management liabilities - non-current	57.8	88.1
Fair Value | Level 3 | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	5.2	12.4
Risk management assets - non-current	7.8	8.7
Risk management liabilities - current	3.6	14.4
Risk management liabilities - non-current	$ 90.0	$ 109.5

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2019

Property, Plant and Equipment [Abstract]

Schedule of Property, Plant and Equipment

The range of useful lives for AltaGas’ PP&E is as follows:

Utilities assets	4 to 69 years
Midstream assets	2 to 45 years
Power generation assets	3 to 46 years
Corporate assets	3 to 7 years

As at	December 31, 2019									December 31, 2018
	Cost			Accumulated amortization			Net book value			Cost			Accumulated amortization			Net book value
Utilities	$	7,316.1		$	(155.0	)	$	7,161.1		$	7,090.5		$	(89.7	)	$	7,000.8
Midstream	3,182.0			(585.4		)	2,596.6			3,178.2			(845.7		)	2,332.5
Power	976.7			(594.6		)	382.1			4,633.9			(1,858.3		)	2,775.6
Corporate	49.5			(40.9		)	8.6			49.4			(39.1		)	10.3
Reclassified to assets held for sale	(25.2		)	2.3			(22.9		)	(2,999.3		)	1,809.7			(1,189.6		)
	$	11,499.1		$	(1,373.6	)	$	10,125.5		$	11,952.7		$	(1,023.1	)	$	10,929.6

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Other Long-term Liabilities - Schedule of Other Long-Term Liabilities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2019	Dec. 31, 2018
Other Long-Term Liabilities [Line Items]
Deferred lease payable		$ 0.0	$ 13.1
Deferred revenue		4.0	3.9
Customer advances for construction		63.9	58.6
Sundance B PPA's termination expense		0.0	2.0
Lease inducement			2.7
Merger commitments		14.0	21.4
Other long-term liabilities		19.9	20.3
Other long-term liabilities		$ 101.8	$ 122.0
ASTC
Other Long-Term Liabilities [Line Items]
Sundance B PPA's termination expense	$ 6.0
Settlement payment period	3 years
Accounts payable and accrued liabilities | ASTC
Other Long-Term Liabilities [Line Items]
Sundance B PPA's termination expense	$ 2.0

XML

Income Taxes - Schedule of Uncertain Tax Positions (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of Unrecognized Tax Benefits
Balance, beginning of year	$ 2.2	$ 5.9
Net changes during the year	(0.2)	(3.7)
Balance, end of year	$ 2.0	$ 2.2

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Acquisition of WGL Holdings, Inc. (Tables)

12 Months Ended

Dec. 31, 2019

Business Combinations [Abstract]

Schedule of Final Purchase Price Allocation

Purchase consideration	$	5,973
Fair value assigned to net assets
Current assets	$	1,220
Property, plant and equipment	5,884
Intangible assets	577
Regulatory assets	408
Long-term investments	1,475
Other long-term assets	462
Current liabilities	(1,916		)
Long-term debt	(2,548		)
Preferred shares	(41		)
Regulatory liabilities	(1,126		)
Deferred income taxes	(741		)
Other long-term liabilities	(959		)
Non-controlling interest	(9		)
Accumulated other comprehensive income	(2		)
Fair value of net assets acquired	$	2,684
Goodwill	$	3,289

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Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment
Cost	$ 11,499.1	$ 11,952.7
Accumulated amortization	(1,373.6)	(1,023.1)
Net book value	10,125.5	10,929.6
Held for sale
Property, Plant and Equipment
Cost	25.2	2,999.3
Accumulated amortization	(2.3)	(1,809.7)
Net book value	22.9	1,189.6
Utilities
Property, Plant and Equipment
Cost	7,316.1	7,090.5
Accumulated amortization	(155.0)	(89.7)
Net book value	7,161.1	7,000.8
Midstream
Property, Plant and Equipment
Cost	3,182.0	3,178.2
Accumulated amortization	(585.4)	(845.7)
Net book value	2,596.6	2,332.5
Power
Property, Plant and Equipment
Cost	976.7	4,633.9
Accumulated amortization	(594.6)	(1,858.3)
Net book value	382.1	2,775.6
Corporate
Property, Plant and Equipment
Cost	49.5	49.4
Accumulated amortization	(40.9)	(39.1)
Net book value	$ 8.6	$ 10.3

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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, 2019	Dec. 31, 2018
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	$ (85.3)	$ 80.8
Natural gas
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	22.5	(2.2)
Energy exports
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	(86.7)	0.0
NGL frac spread
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	(17.4)	40.0
Power
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	(4.9)	9.3
Foreign exchange
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	$ 1.2	$ 33.7

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Summary of Significant Accounting Policies - Pension Plan and Post Retirement Benefits (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit
Defined Benefit Plan Disclosure
Average remaining service life of active employees	9 years	9 years 7 months 6 days
Post- Retirement Benefits
Defined Benefit Plan Disclosure
Average remaining service life of active employees	13 years 2 months	14 years 1 month 6 days

XML

Organization and Overview of the Business - Narratives (Details) customer in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2019 USD ($) jurisdiction pipeline segment customer MW
Organization And Overview Of Business [Line Items]
Number of segments | segment	3
Utilities
Organization And Overview Of Business [Line Items]
Number of customers | customer	1.7
Utilities customers, base rate | $	$ 3.9
Number of regulated pipelines (pipelines)	2
Midstream
Organization And Overview Of Business [Line Items]
Number of regulated pipelines (pipelines)	2
Number of utilities jurisdictions | jurisdiction	5
Midstream | Ridley Island Propane Terminal
Organization And Overview Of Business [Line Items]
Equity method investment, ownership interest (percent)	70.00%
Midstream | AltaGas Idemitsu Joint Venture LP
Organization And Overview Of Business [Line Items]
Equity method investment, ownership interest (percent)	50.00%
Midstream | Petrogas Preferred Shares
Organization And Overview Of Business [Line Items]
Equity method investment, ownership interest (percent)	33.33%
Power
Organization And Overview Of Business [Line Items]
Power capacity | MW	710

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Financial Instruments and Financial Risk Management - Risk Management Liabilities And Maximum Potential Collateral Requirements (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk management liabilities with credit-risk-contingent features	$ 42.2	$ 14.7
Maximum potential collateral requirements	$ 29.0	$ 7.5

XML

Assets Held For Sale - Schedule of Assets Held for Sale (Details) - Held for sale - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Assets held for sale
Cash	$ 0.0	$ 4.9
Accounts receivable	0.0	85.2
Inventory	0.0	0.5
Property, plant and equipment	22.9	1,189.6
Intangible assets	0.0	248.7
Operating right-of-use assets	0.4
Goodwill	1.0	0.0
Other long-term assets	3.2	0.0
Total assets held for sale	27.5	1,528.9
Liabilities associated with assets held for sale
Accounts payable and accrued liabilities	0.0	23.8
Asset retirement obligations	0.2	10.8
Unamortized investment tax credits	3.2	0.0
Disposal Group, Including Discontinued Operation, Operating Lease Liabilities, Non-current	0.4
Other long-term liabilities	0.0	136.8
Total liabilities associated with assets held for sale	$ 3.8	$ 171.4

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Acquisition of WGL Holdings, Inc. - Schedule of Final Purchase Price Allocation (Details) - CAD ($) $ in Millions	Jul. 06, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Fair value assigned to net assets
Goodwill (note 11)		$ 3,942.1	$ 4,068.2	$ 817.3
WGL Holdings
Business Acquisition
Purchase consideration	$ 5,973.0
Fair value assigned to net assets
Current assets	1,220.0
Property, plant and equipment	5,884.0
Intangible assets	577.0
Regulatory assets	408.0
Long-term investments	1,475.0
Other long-term assets	462.0
Current liabilities	(1,916.0)
Long-term debt	(2,548.0)
Preferred shares	(41.0)
Regulatory liabilities	(1,126.0)
Deferred income taxes	(741.0)
Other long-term liabilities	(959.0)
Non-controlling interest	(9.0)
Accumulated other comprehensive income	(2.0)
Fair value of net assets acquired	2,684.0
Goodwill (note 11)	$ 3,289.0

XML

Intangible Assets - Summary of Estimated Amortization Expense of Intangible Assets (Details) $ in Millions	Dec. 31, 2019 CAD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2020	$ 79.1
2021	70.6
2022	69.7
2023	62.3
2024	24.2
Thereafter	$ 95.2

XML

Long-Term Debt - Schedule of Long-Term Debt (Details)	Dec. 31, 2019 USD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2018 CAD ($)
Debt Instrument
Fair value adjustment on WGL Acquisition (note 3)		$ 84,300,000		$ 89,000,000
Finance lease liabilities (note 10)		9,900,000		800,000
Long-term debt including lease obligations		6,887,100,000		8,992,300,000
Less debt issuance costs		(36,400,000)		(35,200,000)
Total long-term debt		6,850,700,000		8,957,100,000
Less current portion		(922,900,000)		(890,200,000)
Long-term debt, noncurrent		5,927,800,000		8,066,900,000
$200 million Senior unsecured - 4.55 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		0		200,000,000
Debt face amount		$ 200,000,000
Debt instrument rate	4.55%	4.55%
$200 million Senior unsecured - 4.07 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
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 | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 350,000,000		350,000,000
Debt face amount		$ 350,000,000
Debt instrument rate	3.72%	3.72%
$500 million Senior unsecured - 2.61 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 500,000,000		0
Debt face amount		$ 500,000,000
Debt instrument rate	2.61%	2.61%
$300 million Senior unsecured - 3.57 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
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 | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
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 | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 300,000,000		299,900,000
Debt face amount		$ 300,000,000
Debt instrument rate	3.84%	3.84%
$350 million Senior unsecured - 4.12 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 349,900,000		349,800,000
Debt face amount		$ 350,000,000
Debt instrument rate	4.12%	4.12%
$200 million Senior unsecured - 3.98 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 199,900,000		199,900,000
Debt face amount		$ 200,000,000
Debt instrument rate	3.98%	3.98%
$100 million Senior unsecured - 5.16 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
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 | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 299,800,000		299,800,000
Debt face amount		$ 300,000,000
Debt instrument rate	4.50%	4.50%
$250 million Senior unsecured - 4.99 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 250,000,000		250,000,000
Debt face amount		$ 250,000,000
Debt instrument rate	4.99%	4.99%
US$450 million Senior unsecured - 2.25 to 4.76 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 0		$ 682,100,000
Debt face amount			$ 450,000,000
US$450 million Senior unsecured - 2.25 to 4.76 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Minimum
Debt Instrument
Debt instrument rate			2.25%	2.25%
US$450 million Senior unsecured - 2.25 to 4.76 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Maximum
Debt Instrument
Debt instrument rate			4.76%	4.76%
US$250 million Senior unsecured - 2.68 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 324,700,000		$ 341,100,000
Debt face amount	$ 250,000,000
Debt instrument rate	2.44%	2.44%
US$20 million Senior unsecured - 6.65 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 26,000,000		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 | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 52,600,000		55,300,000
Debt face amount	$ 40,500,000.0
Debt instrument rate	5.44%	5.44%
US$53 million Senior unsecured - 6.62 to 6.82 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 68,800,000		72,300,000
Debt face amount	$ 53,000,000
US$53 million Senior unsecured - 6.62 to 6.82 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Minimum
Debt Instrument
Debt instrument rate	6.62%	6.62%
US$53 million Senior unsecured - 6.62 to 6.82 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Maximum
Debt Instrument
Debt instrument rate	6.82%	6.82%
US$72 million Senior unsecured - 6.40 to 6.57 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 93,500,000		98,200,000
Debt face amount	$ 72,000,000
US$72 million Senior unsecured - 6.40 to 6.57 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Minimum
Debt Instrument
Debt instrument rate	6.40%	6.40%
US$72 million Senior unsecured - 6.40 to 6.57 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Maximum
Debt Instrument
Debt instrument rate	6.57%	6.57%
US$52 million Senior unsecured - 6.57 to 6.85 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 67,500,000		70,900,000
Debt face amount	$ 52,000,000
US$52 million Senior unsecured - 6.57 to 6.85 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Minimum
Debt Instrument
Debt instrument rate	6.57%	6.57%
US$52 million Senior unsecured - 6.57 to 6.85 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Maximum
Debt Instrument
Debt instrument rate	6.85%	6.85%
US$8.5 million Senior unsecured - 7.50 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 11,000,000		11,600,000
Debt face amount	$ 8,500,000.0
Debt instrument rate	7.50%	7.50%
US$50 million Senior unsecured - 5.70 to 5.78 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 64,900,000		68,200,000
Debt face amount	$ 50,000,000
US$50 million Senior unsecured - 5.70 to 5.78 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Minimum
Debt Instrument
Debt instrument rate	5.70%	5.70%
US$50 million Senior unsecured - 5.70 to 5.78 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Maximum
Debt Instrument
Debt instrument rate	5.78%	5.78%
US$75 million Senior unsecured - 5.21 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 97,400,000		102,300,000
Debt face amount	$ 75,000,000
Debt instrument rate	5.21%	5.21%
US$75 million Senior unsecured - 5.00 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 97,400,000		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 | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 389,600,000		409,300,000
Debt face amount	$ 300,000,000
US$300 million Senior unsecured - 4.22 to 4.60 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Minimum
Debt Instrument
Debt instrument rate	4.22%	4.22%
US$300 million Senior unsecured - 4.22 to 4.60 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs) | Maximum
Debt Instrument
Debt instrument rate	4.60%	4.60%
US$450 million Senior unsecured - 3.80 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 584,500,000		613,900,000
Debt face amount	$ 450,000,000
Debt instrument rate	3.80%	3.80%
US$300 million Senior unsecured - 3.65 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross		$ 389,600,000		0
Debt face amount	$ 300,000,000
Debt instrument rate	3.65%	3.65%
US$300 million SEMCO Senior Secured - 5.15 percent | SEMCO long-term debt
Debt Instrument
Long-term debt, gross		$ 389,600,000		409,300,000
Debt face amount	$ 300,000,000
Debt instrument rate	5.15%	5.15%
US$82 million SEMCO Senior Secured - 4.48 percent | SEMCO long-term debt
Debt Instrument
Long-term debt, gross		$ 76,100,000		86,300,000
Debt face amount	$ 82,000,000
Debt instrument rate	4.48%	4.48%
Credit facilities | $1,400 million unsecured extendible revolving facility
Debt Instrument
Long-term debt, gross		$ 89,600,000		964,700,000
Debt face amount		1,400,000,000
Credit facilities | US$300 million unsecured extendible revolving facility
Debt Instrument
Long-term debt, gross		0		287,800,000
Debt face amount	$ 300,000,000
Credit facilities | Acquisition credit facility
Debt Instrument
Long-term debt, gross		0		113,200,000
Credit facilities | US$1,200 million revolving credit facility
Debt Instrument
Long-term debt, gross		0		1,637,000,000
Debt face amount				1,200,000,000
Credit facilities | US$300 million unsecured term facility
Debt Instrument
Long-term debt, gross		389,600,000		0
Debt face amount		300,000,000
Credit facilities | US$150 million unsecured extendible revolving facility
Debt Instrument
Long-term debt, gross		163,500,000		0
Debt face amount		$ 150,000,000
Credit facilities | Commercial paper
Debt Instrument
Long-term debt, gross				$ 0

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Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2019

VARIABLE INTEREST ENTITIES [Abstract]

Schedule of VIE Amounts in Consolidated Balance Sheets

The following table represents amounts included in the Consolidated Balance Sheets attributable to AltaGas’ consolidated VIEs:

As at	December 31, 2019			December 31, 2018
Current assets	$	6.4		$	1,383.5
Property, plant and equipment	371.1			619.2
Long-term investments and other assets	53.3			48.0
Operating right-of-use assets	0.1			—
Current liabilities	(3.6		)	(161.8		)
Asset retirement obligations	(3.3		)	(0.9		)
Other long-term liabilities	(0.1		)	(3.0		)
Net assets	$	423.9		$	1,885.0

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2019

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Changes in Asset Retirement Obligations

As at December 31	2019			2018
Balance, beginning of year	$	500.6		$	88.3
Obligations acquired (note 3)	—			399.1
New obligations	7.0			3.3
Obligations settled	(2.5		)	(4.2		)
Disposals	(6.2		)	(1.6		)
Revision in estimated cash flow	(128.5		)	3.8
Accretion expense (a)	18.9			12.3
Foreign exchange translation	(20.7		)	20.3
Reclassified to liabilities associated with assets held for sale (note 5)	(0.2		)	(10.8		)
Total	$	368.4		$	510.5
Less current portion (included in accounts payable and accrued liabilities)	(6.4		)	(9.9		)
Balance, end of year	$	362.0		$	500.6

(a) Certain amounts relating to Utility asset retirement obligations are recorded through regulatory assets or liabilities on the Consolidated Balance Sheets due to regulatory treatment. The remaining portion is recorded through the Consolidated Statements of Income (Loss).

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- Narratives (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 CAD ($)	Dec. 31, 2018 CAD ($)	Oct. 21, 2019 $ / shares
Meade Pipeline Co. LLC (Meade)
Schedule of Equity Method Investments
Provision on equity method investments	$ 44.2
Craven County Wood Energy LP
Schedule of Equity Method Investments
Provision on equity method investments	$ 2.2	$ 14.5
AltaGas Canada Inc. | the Consortium
Schedule of Equity Method Investments
Equity Method Investment Proposed Share Acquisition Price | $ / shares			$ 33.50

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Environmental Matters (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 CAD ($) site	Dec. 31, 2018 CAD ($)
Site Contingency
Identified operated manufactured gas plants | site	12
Accrual for environmental loss contingencies	$ 13.8	$ 15.4
Regulatory assets	17.7	19.9
Maximum
Site Contingency
Accrual for environmental loss contingencies	$ 39.9	$ 40.1

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Segmented Information - Geographic Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenues from External Customers and Long-Lived Assets
Revenues	$ 5,570.3	$ 4,179.8
Property, plant and equipment	10,125.5	10,929.6
Canada
Revenues from External Customers and Long-Lived Assets
Revenues	1,244.8	1,626.8
Property, plant and equipment	2,682.2	2,348.2
United States
Revenues from External Customers and Long-Lived Assets
Revenues	4,325.5	2,553.0
Property, plant and equipment	$ 7,443.3	$ 8,581.4

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Commitments, Guarantees, and Contingencies - Narrative (Details)	1 Months Ended
	Jun. 30, 2019 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2019 CAD ($)	Apr. 23, 2019 action	Dec. 31, 2018 CAD ($)
Commitments, Contingencies And Guaranteed [Line Items]
Guarantee obligations			$ 0
Other long term receivables			$ 33,100,000		$ 0
Antero Contract
Commitments, Contingencies And Guaranteed [Line Items]
Damages awarded	$ 96,000,000
Antero Contract | WGL Holdings
Commitments, Contingencies And Guaranteed [Line Items]
Adjustments to working capital	45,000,000
Antero Contract | Washington Gas
Commitments, Contingencies And Guaranteed [Line Items]
Damages awarded	$ 11,000,000
Silver Spring Maryland Incident
Commitments, Contingencies And Guaranteed [Line Items]
Number of civil actions | action				37
Loss accural		$ 300,000
Recommended daily fine		25,000
Minimum | Silver Spring Maryland Incident
Commitments, Contingencies And Guaranteed [Line Items]
Estimated penalties		32,000,000
Maximum | Silver Spring Maryland Incident
Commitments, Contingencies And Guaranteed [Line Items]
Estimated penalties		$ 123,300,000

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Related Party Transactions

12 Months Ended

Dec. 31, 2019

Related Party Transactions [Abstract]

Related Party Transactions

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, 2019		December 31, 2018
Due from related parties
Accounts receivable (a)	$	17.8	$	60.8
Long-term investments and other assets (b)	45.0		45.0
	$	62.8	$	105.8
Due to related parties
Accounts payable (c)	$	2.7	$	6.3
Risk management liabilities - current (d)	—		0.9
	$	2.7	$	7.2

(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, 2019, Petrogas had drawn $45.0 million (December 31, 2018 - $45.0 million) under the facility.

(c) Payables to joint venture.

(d) Foreign exchange hedge with ACI.

The following transactions with related parties have been recorded on the Consolidated Statements of Income (Loss) for the years ended December 31, 2019 and 2018:

Year Ended December 31	2019			2018
Revenue (a)	$	114.9		$	68.4
Cost of sales (b)	$	12.8		$	4.2
Operating and administrative recoveries (c)	$	(1.8	)	$	(1.3	)
Other income (d)	$	3.2		$	9.2

(a) In the ordinary course of business, AltaGas sold natural gas and natural gas liquids to a joint venture and ACI. For the year ended December 31, 2018, revenue also includes an unrealized loss on a foreign exchange hedge with ACI of $0.2 million.

(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 addition, subsequent to the initial public offering (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.

(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 2018. Loans to ACI were fully repaid by December 31, 2018.

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Net Income (Loss) Per Common Share

12 Months Ended

Dec. 31, 2019

Earnings Per Share [Abstract]

Net Income (Loss) Per Common Share

Net Income (Loss) Per Common Share

The following table summarizes the computation of net income (loss) per common share:

	Year Ended December 31
	2019			2018
Numerator:
Net income (loss) applicable to controlling interests	$	833.5		$	(435.1	)
Less: Preferred share dividends	(68.5		)	(66.6		)
Gain on redemption of preferred shares (note 25)	3.5			—
Net income (loss) applicable to common shares	$	768.5		$	(501.7	)
Denominator:
(millions)
Weighted average number of common shares outstanding	276.9			222.6
Dilutive equity instruments (a)	0.5			—
Weighted average number of common shares outstanding - diluted	277.4			222.6
Basic net income (loss) per common share	$	2.78		$	(2.25	)
Diluted net income (loss) per common share	$	2.77		$	(2.25	)

(a) Includes all options that have a strike price lower than the average share price of AltaGas' common shares during the periods noted.

For the year ended December 31, 2019, 4.3 million share options (2018 – 4.0 million) were excluded from the diluted net income (loss) per share calculation as their effects were anti‑dilutive.

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Supplemental Cash Flow Information - Schedule of Supplemental Cash Payments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Supplemental Cash Flow Elements [Abstract]
Interest paid (net of capitalized interest)	$ 351.7	$ 288.9
Income taxes paid	$ 67.2	$ 36.9

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Goodwill

12 Months Ended

Dec. 31, 2019

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill

Goodwill

As at	December 31, 2019			December 31, 2018
Balance, beginning of year	$	4,068.2		$	817.3
Provisions on assets	—			(124.2		)
Business acquisition (note 3)	—			3,196.4
Adjustment to goodwill on business acquisition (note 3)	92.2			—
Goodwill included in dispositions (note 4)	(29.1		)	—
Reclassified to assets held for sale (note 5)	(1.0		)	—
Foreign exchange translation	(188.2		)	178.7
Balance, end of year	$	3,942.1		$	4,068.2

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Pension Plans and Retiree Benefits - Summary of Defined Benefit Plans (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Plan assets
Plan assets, Fair value, end of year	$ 2,424.7
United States
Plan assets
Plan assets, Fair value, end of year	2,409.8
Defined Benefit
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	1,669.6	$ 469.4
Plans disposed		(132.1)
Actuarial loss (gain)	184.1	(68.5)
Current service cost	26.4	18.6
Member contributions	0.0	0.0
Interest cost	69.0	39.2
Benefits paid	(81.3)	(45.9)
Expenses paid	(0.7)	(0.9)
Settlements	(24.7)
Plan combinations		1,312.4
Plan amendments	0.3	0.0
Other	0.0
Foreign exchange translation	(82.0)	77.4
Balance, end of year	1,760.7	1,669.6
Plan assets
Fair value, beginning of year	1,367.9	363.9
Plans disposed		(102.1)
Actual return on plan assets	285.1	(55.0)
Employer contributions	43.0	11.0
Member contributions	0.0	0.0
Benefits paid	(81.3)	(45.9)
Expenses paid	(0.7)	(0.9)
Settlements	(25.7)
Other	0.0
Plan combinations		1,133.5
Foreign exchange translation	(69.5)	63.4
Plan assets, Fair value, end of year	1,518.8	1,367.9
Funded status	(241.9)	(301.7)
Defined Benefit | Canada
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	34.3	165.6
Plans disposed		(132.1)
Actuarial loss (gain)	2.1	(0.8)
Current service cost	2.6	2.4
Member contributions	0.0	0.0
Interest cost	1.2	1.2
Benefits paid	(4.0)	(2.7)
Expenses paid	(0.1)	0.0
Settlements	0.0
Plan combinations		0.7
Plan amendments	0.0	0.0
Other	0.0
Foreign exchange translation	0.0	0.0
Balance, end of year	36.1	34.3
Plan assets
Fair value, beginning of year	13.8	115.2
Plans disposed		(102.1)
Actual return on plan assets	0.9	(0.3)
Employer contributions	4.3	3.4
Member contributions	0.0	0.0
Benefits paid	(4.0)	(2.7)
Expenses paid	(0.1)	0.0
Settlements	0.0
Other	0.0
Plan combinations		0.3
Foreign exchange translation	0.0	0.0
Plan assets, Fair value, end of year	14.9	13.8
Funded status	(21.2)	(20.5)
Defined Benefit | United States
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	1,635.3	303.8
Plans disposed		0.0
Actuarial loss (gain)	182.0	(67.7)
Current service cost	23.8	16.2
Member contributions	0.0	0.0
Interest cost	67.8	38.0
Benefits paid	(77.3)	(43.2)
Expenses paid	(0.6)	(0.9)
Settlements	(24.7)
Plan combinations		1,311.7
Plan amendments	0.3	0.0
Other	0.0
Foreign exchange translation	(82.0)	77.4
Balance, end of year	1,724.6	1,635.3
Plan assets
Fair value, beginning of year	1,354.1	248.7
Plans disposed		0.0
Actual return on plan assets	284.2	(54.7)
Employer contributions	38.7	7.6
Member contributions	0.0	0.0
Benefits paid	(77.3)	(43.2)
Expenses paid	(0.6)	(0.9)
Settlements	(25.7)
Other	0.0
Plan combinations		1,133.2
Foreign exchange translation	(69.5)	63.4
Plan assets, Fair value, end of year	1,503.9	1,354.1
Funded status	(220.7)	(281.2)
Post- Retirement Benefits
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	459.9	98.5
Plans disposed		(13.6)
Actuarial loss (gain)	(14.6)	(33.9)
Current service cost	8.5	5.4
Member contributions	2.2	2.1
Interest cost	19.2	11.0
Benefits paid	(24.5)	(13.4)
Expenses paid	(0.1)	(0.1)
Settlements	0.0
Plan combinations		382.9
Plan amendments	0.0	(0.4)
Other	1.0
Foreign exchange translation	(21.8)	21.4
Balance, end of year	429.8	459.9
Plan assets
Fair value, beginning of year	791.2	78.9
Plans disposed		(8.1)
Actual return on plan assets	177.4	(37.2)
Employer contributions	0.2	2.5
Member contributions	2.2	2.1
Benefits paid	(23.8)	(13.4)
Expenses paid	(0.1)	(0.1)
Settlements	0.0
Other	0.1
Plan combinations		732.7
Foreign exchange translation	(41.3)	33.8
Plan assets, Fair value, end of year	905.9	791.2
Funded status	476.1	331.3
Post- Retirement Benefits | Canada
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	1.9	15.8
Plans disposed		(13.6)
Actuarial loss (gain)	0.2	(0.1)
Current service cost	0.0	0.1
Member contributions	0.0	0.0
Interest cost	0.1	0.1
Benefits paid	(0.1)	0.0
Expenses paid	0.0	0.0
Settlements	0.0
Plan combinations		0.0
Plan amendments	0.0	(0.4)
Other	0.0
Foreign exchange translation	0.0	0.0
Balance, end of year	2.1	1.9
Plan assets
Fair value, beginning of year	0.0	8.1
Plans disposed		(8.1)
Actual return on plan assets	0.0	0.0
Employer contributions	0.1	0.0
Member contributions	0.0	0.0
Benefits paid	(0.1)	0.0
Expenses paid	0.0	0.0
Settlements	0.0
Other	0.0
Plan combinations		0.0
Foreign exchange translation	0.0	0.0
Plan assets, Fair value, end of year	0.0	0.0
Funded status	(2.1)	(1.9)
Post- Retirement Benefits | United States
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	458.0	82.7
Plans disposed		0.0
Actuarial loss (gain)	(14.8)	(33.8)
Current service cost	8.5	5.3
Member contributions	2.2	2.1
Interest cost	19.1	10.9
Benefits paid	(24.4)	(13.4)
Expenses paid	(0.1)	(0.1)
Settlements	0.0
Plan combinations		382.9
Plan amendments	0.0	0.0
Other	1.0
Foreign exchange translation	(21.8)	21.4
Balance, end of year	427.7	458.0
Plan assets
Fair value, beginning of year	791.2	70.8
Plans disposed		0.0
Actual return on plan assets	177.4	(37.2)
Employer contributions	0.1	2.5
Member contributions	2.2	2.1
Benefits paid	(23.7)	(13.4)
Expenses paid	(0.1)	(0.1)
Settlements	0.0
Other	0.1
Plan combinations		732.7
Foreign exchange translation	(41.3)	33.8
Plan assets, Fair value, end of year	905.9	791.2
Funded status	$ 478.2	$ 333.2

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Acquisition of WGL Holdings, Inc.

12 Months Ended

Dec. 31, 2019

Business Combinations [Abstract]

Acquisition of WGL Holdings, Inc.

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. The WGL Acquisition was 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 was recognized as goodwill at the acquisition date.

The following table summarizes the final 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 was finalized on June 30, 2019 and reflects Management’s best estimate of the fair value of WGL’s assets and liabilities. In the first half of 2019, based on new information obtained in the period and further refinement of assumptions, adjustments to the purchase price allocation included amounts relating to intangible assets, deferred income taxes, pension liabilities, current liabilities, other long-term liabilities, valuation of equity investments in Midstream pipelines, and deferred rent, resulting in a net increase to goodwill of approximately $92.2 million (Note 11).

Purchase consideration	$	5,973
Fair value assigned to net assets
Current assets	$	1,220
Property, plant and equipment	5,884
Intangible assets	577
Regulatory assets	408
Long-term investments	1,475
Other long-term assets	462
Current liabilities	(1,916		)
Long-term debt	(2,548		)
Preferred shares	(41		)
Regulatory liabilities	(1,126		)
Deferred income taxes	(741		)
Other long-term liabilities	(959		)
Non-controlling interest	(9		)
Accumulated other comprehensive income	(2		)
Fair value of net assets acquired	$	2,684
Goodwill	$	3,289

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Inventory

12 Months Ended

Dec. 31, 2019

Inventory Disclosure [Abstract]

Inventory

Inventory

As at December 31	2019		2018
Natural gas held in storage (a)	$	359.0	$	418.0
Materials and supplies	56.3		53.3
Renewable energy credits and emission compliance instruments	64.1		38.2
Natural gas liquids	26.2		6.4
	$	505.6	$	515.9

(a) As at December 31, 2019, $214.3 million of the natural gas held in storage was held by rate-regulated utilities(2018 - $270.4 million).

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Shareholders’ Equity - Schedule of MTIP and DSUP Activity (Details) - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
PUs, RUs, and DSUs (number of units)
Balance, beginning of year (units)	9,908,154	564,549
Acquired (units)	0	5,291,621
Converted to cash (units)		(5,291,621)
Granted (units)	674,971	9,502,347
Vested and paid out (units)	(677,667)	(148,154)
Exercised (units)	(113,668)
Forfeited (units)	(3,377,962)	(66,522)
Units in lieu of dividends (units)	71,003	55,934
Outstanding, end of year (units)	6,484,831	9,908,154

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Acquisition of WGL Holdings, Inc. - Narratives (Details) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2019 CAD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2018 CAD ($)	Jul. 06, 2018 $ / $
Business Acquisition
Currency exchange rate (usd/cad) | $ / $				1.31
Adjustment to goodwill on business acquisition		$ 92.2	$ 0.0
WGL Holdings
Business Acquisition
Adjustment to goodwill on business acquisition	$ 92.2

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Intangible Assets - Narratives (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Amortization expense	$ 80.2	$ 69.7
Assets excluded from asset base subject to amortization	$ 184.5	$ 196.4

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Inventory - Schedule of Inventory (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Inventory
Natural gas held in storage	$ 359.0	$ 418.0
Materials and supplies	56.3	53.3
Renewable energy credits and emission compliance instruments	64.1	38.2
Natural gas liquids	26.2	6.4
Total inventory	505.6	515.9
Rate Regulated Utilities
Inventory
Natural gas held in storage	$ 214.3	$ 270.4

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Summary of Significant Accounting Policies - Share Options and Other Compensation Plans (Details)	12 Months Ended
	Dec. 31, 2019 multiple $ / shares
Share-based Compensation Arrangement by Share-based Payment Award
Other portions of RU's and PSU's (per share) | $ / shares	$ 1
Performance units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award
Performance multiplier	0
Performance units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award
Performance multiplier	2.4

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Financial Instruments and Financial Risk Management - Schedule of Offsetting Assets and Liabilities (Details) - CAD ($)	Dec. 31, 2019	Dec. 31, 2018
Offsetting Assets And Liabilities
Netting of collateral	$ 5,500,000	$ 0
Risk management assets - current	86,600,000	114,100,000
Risk management assets - non-current	39,100,000	57,700,000
Risk management liabilities - current	124,800,000	89,300,000
Risk management liabilities - non-current	167,000,000	213,000,000
Risk management contracts
Offsetting Assets And Liabilities
Gross amounts of recognized assets	184,700,000	262,300,000
Gross amounts offset in balance sheet	(63,400,000)	(90,500,000)
Netting of collateral	4,400,000	0
Net amount of assets presented in balance sheet	125,700,000	171,800,000
Gross amounts of recognized liabilities	386,000,000	394,900,000
Gross amounts offset in balance sheet	(63,400,000)	(90,500,000)
Netting of collateral	(30,800,000)	(2,100,000)
Net amount of liabilities presented in balance sheet	291,800,000	302,300,000
Natural gas
Offsetting Assets And Liabilities
Gross amounts of recognized assets	121,200,000	200,800,000
Gross amounts offset in balance sheet	(53,700,000)	(82,000,000)
Netting of collateral	0	0
Net amount of assets presented in balance sheet	67,500,000	118,800,000
Gross amounts of recognized liabilities	226,100,000	340,400,000
Gross amounts offset in balance sheet	(53,700,000)	(82,000,000)
Netting of collateral	(27,700,000)	(3,300,000)
Net amount of liabilities presented in balance sheet	144,700,000	255,100,000
Energy exports
Offsetting Assets And Liabilities
Gross amounts of recognized assets	9,700,000
Gross amounts offset in balance sheet	(2,700,000)
Netting of collateral	4,400,000
Net amount of assets presented in balance sheet	11,400,000
Gross amounts of recognized liabilities	89,500,000
Gross amounts offset in balance sheet	(2,700,000)
Netting of collateral	0
Net amount of liabilities presented in balance sheet	86,800,000
NGL frac spread
Offsetting Assets And Liabilities
Gross amounts of recognized assets	300,000	18,700,000
Gross amounts offset in balance sheet	(200,000)	(700,000)
Netting of collateral	0	0
Net amount of assets presented in balance sheet	100,000	18,000,000
Gross amounts of recognized liabilities	1,700,000	2,700,000
Gross amounts offset in balance sheet	(200,000)	(700,000)
Netting of collateral	0	0
Net amount of liabilities presented in balance sheet	1,500,000	2,000,000
Foreign exchange
Offsetting Assets And Liabilities
Gross amounts of recognized liabilities		1,200,000
Gross amounts offset in balance sheet		0
Netting of collateral		0
Net amount of liabilities presented in balance sheet		1,200,000
Power
Offsetting Assets And Liabilities
Gross amounts of recognized assets	53,500,000	42,800,000
Gross amounts offset in balance sheet	(6,800,000)	(7,800,000)
Netting of collateral	0	0
Net amount of assets presented in balance sheet	46,700,000	35,000,000
Gross amounts of recognized liabilities	68,700,000	50,600,000
Gross amounts offset in balance sheet	(6,800,000)	(7,800,000)
Netting of collateral	(3,100,000)	1,200,000
Net amount of liabilities presented in balance sheet	$ 58,800,000	$ 44,000,000

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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, 2019 CAD ($) kJ MWh $ / gigajoule $ / MWh $ / barrel bbl	Dec. 31, 2018 CAD ($) kJ MWh $ / gigajoule $ / MWh $ / barrel bbl
Natural gas | Sales
Derivative
Notional volume (GJ) | kJ	698,126,985	858,640,810
Fair Value ($)	$ 28.9	$ 19.0
Natural gas | Sales | Minimum
Derivative
Fixed price | $ / gigajoule	1.32	1.07
Period (months)	1 month	1 month
Natural gas | Sales | Maximum
Derivative
Fixed price | $ / gigajoule	6.81	12.19
Period (months)	166 months	178 months
Natural gas | Purchases
Derivative
Notional volume (GJ) | kJ	1,406,991,689	1,638,207,391
Fair Value ($)	$ (104.4)	$ (179.5)
Natural gas | Purchases | Minimum
Derivative
Fixed price | $ / gigajoule	0.22	0.69
Period (months)	1 month	1 month
Natural gas | Purchases | Maximum
Derivative
Fixed price | $ / gigajoule	6.81	16.26
Period (months)	167 months	179 months
Natural gas | Swaps
Derivative
Notional volume (GJ) | kJ	541,652,374	621,578,572
Fair Value ($)	$ (1.7)	$ 20.9
Natural gas | Swaps | Minimum
Derivative
Fixed price | $ / gigajoule	0.22	2.56
Period (months)	1 month	1 month
Natural gas | Swaps | Maximum
Derivative
Fixed price | $ / gigajoule	10.24	15.37
Period (months)	51 months	231 months
Energy exports | Swaps
Derivative
Notional volume (Bbl) | bbl	9,374,826
Fair Value ($)	$ (75.4)
Energy exports | Swaps | Minimum
Derivative
Fixed price | $ / barrel	21.49
Period (months)	1 month
Energy exports | Swaps | Maximum
Derivative
Fixed price | $ / barrel	29.71
Period (months)	27 months
NGL frac spread | Swaps | Propane
Derivative
Notional volume (Bbl) | bbl		1,725,114
Fair Value ($)		$ 12.6
NGL frac spread | Swaps | Butane swaps
Derivative
Notional volume (Bbl) | bbl	346,852	74,371
Fair Value ($)	$ (0.5)	$ 1.2
NGL frac spread | Swaps | Crude oil swaps
Derivative
Notional volume (Bbl) | bbl	212,587	329,230
Fair Value ($)	$ (0.9)	$ 6.0
NGL frac spread | Swaps | Gas purchase
Derivative
Notional volume (GJ) | kJ	3,883,992	9,490,365
Fair Value ($)	$ 0.0	$ (3.8)
NGL frac spread | Swaps | Minimum | Propane
Derivative
Fixed price | $ / barrel		38.89
Period (months)		1 month
NGL frac spread | Swaps | Minimum | Butane swaps
Derivative
Fixed price | $ / barrel	73.02	52.95
Period (months)	1 month	1 month
NGL frac spread | Swaps | Minimum | Crude oil swaps
Derivative
Fixed price | $ / barrel	73.02	79.64
Period (months)	1 month	1 month
NGL frac spread | Swaps | Minimum | Gas purchase
Derivative
Fixed price | $ / gigajoule	1.58	1.38
Period (months)	1 month	1 month
NGL frac spread | Swaps | Maximum | Propane
Derivative
Fixed price | $ / barrel		47.63
Period (months)		12 months
NGL frac spread | Swaps | Maximum | Butane swaps
Derivative
Fixed price | $ / barrel	75.15	55.26
Period (months)	12 months	12 months
NGL frac spread | Swaps | Maximum | Crude oil swaps
Derivative
Fixed price | $ / barrel	75.15	86.28
Period (months)	12 months	12 months
NGL frac spread | Swaps | Maximum | Gas purchase
Derivative
Fixed price | $ / gigajoule	1.86	1.68
Period (months)	12 months	12 months
Power | Sales
Derivative
Notional volume (GJ) | MWh	8,034,024	11,881,575,000,000
Fair Value ($)	$ 39.0	$ (1.9)
Power | Sales | Minimum
Derivative
Fixed price | $ / MWh	31.63	26.90
Period (months)	1 month	1 month
Power | Sales | Maximum
Derivative
Fixed price | $ / MWh	66.76	95.03
Period (months)	42 months	60 months
Power | Purchases
Derivative
Notional volume (GJ) | MWh	8,552,467	8,507,874,000,000
Fair Value ($)	$ (27.3)	$ 16.4
Power | Purchases | Minimum
Derivative
Fixed price | $ / MWh	31.63	25.50
Period (months)	1 month	1 month
Power | Purchases | Maximum
Derivative
Fixed price | $ / MWh	66.76	50.25
Period (months)	60 months	42 months
Power | Swaps
Derivative
Notional volume (GJ) | MWh	25,058,577	20,957,180,000,000
Fair Value ($)	$ (23.8)	$ (22.3)
Power | Swaps | Minimum
Derivative
Fixed price | $ / MWh	(7.88)	(6.07)
Period (months)	1 month	1 month
Power | Swaps | Maximum
Derivative
Fixed price | $ / MWh	74.26	76.18
Period (months)	48 months	48 months

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Segmented Information (Tables)

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Reconciliation Of Segment Revenue

The following table provides a reconciliation of segment revenue to the disaggregated revenue table as disclosed under Note 24:

	Year Ended December 31, 2019
	Utilities		Midstream		Power		Corporate		Total
External revenue (note 24)	$	2,564.2	$	1,574.3	$	1,356.3	$	0.2	$	5,495.0
Intersegment revenue	26.6		6.9		10.9		—		$	44.4
Segment revenue	$	2,590.8	$	1,581.2	$	1,367.2	$	0.2	$	5,539.4

	Year Ended December 31, 2018
	Utilities		Midstream		Power		Corporate			Total
External revenue (note 24)	$	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

Geographic Information

Year Ended December 31	2019		2018
Revenue (a)
Canada	$	1,244.8	$	1,626.8
United States	4,325.5		2,553.0
TOTAL	$	5,570.3	$	4,179.8

(a) Operating revenue from external customers, excluding unrealized gains (losses) or risk management contracts.

As at December 31	2019		2018
Property, plant and equipment
Canada	$	2,682.2	$	2,348.2
United States	7,443.3		8,581.4
TOTAL	$	10,125.5	$	10,929.6

Schedule of Segment Composition

The following tables show the composition by segment:

	Year Ended December 31, 2019
	Utilities			Midstream			Power			Corporate			Intersegment Elimination (a)			Total
Segment revenue	$	2,590.8		$	1,581.2		$	1,367.2		$	0.2		$	(44.4	)	$	5,495.0
Cost of sales	(1,117.9		)	(1,057.7		)	(1,084.4		)	—			32.9			(3,227.1		)
Operating and administrative	(860.7		)	(249.1		)	(159.8		)	(40.6		)	11.5			(1,298.7		)
Accretion expenses	(0.1		)	(3.9		)	(1.1		)	—			—			(5.1		)
Depreciation and amortization	(261.6		)	(92.1		)	(72.3		)	(12.0		)	—			(438.0		)
Provisions on assets (note 6)	—			(35.2		)	(380.6		)	—			—			(415.8		)
Income from equity investments	18.3			122.4			0.4			—			—			141.1
Other income (loss)	27.0			28.7			853.8			(1.4		)	—			908.1
Foreign exchange gains (losses)	—			(4.5		)	—			3.5			—			(1.0		)
Interest expense	—			—			—			(345.8		)	—			(345.8		)
Income (loss) before income taxes	$	395.8		$	289.8		$	523.2		$	(396.1	)	$	—		$	812.7
Net additions (reductions) to:
Property, plant and equipment(b)	$	839.6		$	350.3		$	(2,281.3	)	$	1.2		$	—		$	(1,090.2	)
Intangible assets	$	22.6		$	4.9		$	—		$	9.0		$	—		$	36.5

(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 Statements of Cash Flows due to classification of business acquisition and foreign exchange changes on U.S. assets.

	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		)
Provision on assets (note 6)	(193.7		)	(153.7		)	(381.3		)	—			—			(728.7		)
Income (loss) 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 (losses)	—			(0.2		)	(0.1		)	4.8			—			4.5
Interest expense	(103.9		)	(10.6		)	(8.9		)	(185.6		)	—			(309.0		)
Income (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 Statements of Cash Flows due to classification of business acquisition and foreign exchange changes on U.S. assets.

Schedule of Goodwill and Total Assets by Segment

The following table shows goodwill and total assets by segment:

	Utilities		Midstream		Power		Corporate		Total
As at December 31, 2019
Goodwill	$	3,573.0	$	246.5	$	122.6	$	—	$	3,942.1
Segmented assets	$	13,097.1	$	5,471.4	$	1,019.9	$206.1		$	19,794.5
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

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Dispositions (Details) $ in Millions											1 Months Ended	3 Months Ended		12 Months Ended
	Nov. 13, 2019 USD ($)	Nov. 13, 2019 CAD ($)	Sep. 26, 2019 USD ($)	Sep. 26, 2019 CAD ($)	Aug. 13, 2019 USD ($)	Aug. 13, 2019 CAD ($)	May 31, 2019 USD ($)	May 31, 2019 CAD ($)	Feb. 01, 2019 CAD ($)	Jan. 31, 2019 CAD ($)	Feb. 28, 2019 CAD ($)	Sep. 30, 2019 USD ($)	Sep. 30, 2019 CAD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2019 CAD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Gains (losses) from sale of assets														$ 875,800,000	$ (10,600,000)
Proceeds from disposition of financing receivable														73,500,000	0
Meade Pipeline Co. LLC (Meade)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Provision on equity method investments														44,200,000
Disposal by sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Proceeds from disposition of financing receivable											$ 73,500,000
Loss on sales of receivables														1,300,000
Disposal by sale | Northwest Hydro
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Ownership percentage (percent)										55.00%
Proceeds from disposition										$ 1,300,000,000
Gain (loss) on disposal														687,600,000
Disposal by sale | Non-Core Midstream and Power
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Proceeds from asset dispositions									$ 87,800,000
Gains (losses) from sale of assets														(1,200,000)
Disposal by sale | Stonewall Gas Gathering System
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Proceeds from disposition							$ 280.0	$ 379,200,000
Gain (loss) on disposal														34,100,000
Disposal by sale | Craven County Wood Energy LP and Grayling Generation Station LP
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Proceeds from disposition					$ 18.5	$ 24,500,000
Gain (loss) on disposal						$ 0
Disposal by sale | US Portfolio
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Proceeds from asset dispositions			$ 735.0	$ 975,000,000
Gains (losses) from sale of assets														167,500,000
Disposal by sale | Meade
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Proceeds from disposition	$ 610.8	$ 811,500,000
Gains (losses) from sale of assets														(11,100,000)
Held for sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Liabilities held for sale															$ 171,400,000		$ 3,800,000
Held for sale | US Portfolio
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Liabilities held for sale																$ 24.8	$ 32,200,000
Assets held for sale disposed of by sale | Capital Spare
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Proceeds from disposition												$ 3.5	$ 4,600,000
Gain (loss) on disposal														$ 0

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Asset Retirement Obligations - Narrative (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligations
Undiscounted cash required to settle the asset retirement obligations, excluding growth for inflation	$ 727,000,000	$ 770,000,000
Legally restricted assets	$ 2,137
Minimum
Asset Retirement Obligations
Discount rate for asset retirement obligations (percent)	2.00%	1.50%
Maximum
Asset Retirement Obligations
Discount rate for asset retirement obligations (percent)	8.50%	8.50%

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Investments Accounted for by the Equity Method (Tables)

12 Months Ended

Dec. 31, 2019

Equity Method Investments and Joint Ventures [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	2019		2018		2019			2018
AltaGas Canada Inc. (ACI) (a)	Canada	37	$	163.9	$	112.5	$	17.0		$	5.4
AltaGas Idemitsu Joint Venture LP	Canada	50	431.3		342.9		62.5			2.1
Constitution Pipeline, LLC (Constitution) (b)	United States	10	0.1		—		(0.5		)	(0.2		)
Craven County Wood Energy LP (c)	United States	50	—		7.8		0.1			(14.1		)
Eaton Rapids Gas Storage System	United States	50	27.0		29.4		1.3			2.0
Grayling Generating Station LP (c)	United States	50	—		29.0		0.3			3.6
Inuvik Gas Ltd. (d)	Canada	33	—		—		—			(0.2		)
Meade Pipeline Co. LLC (c) (e)	United States	55	—		757.8		(3.6		)	12.2
Mountain Valley Pipeline, LLC (Mountain Valley) (f)	United States	10	671.3		532.5		42.8			11.5
Sarnia Airport Storage Pool LP	Canada	50	18.0		18.7		1.0			1.0
Petrogas Preferred Shares	Canada	n/a	150.0		150.0		12.8			12.8
Stonewall Gas Gathering Systems LLC (c)	United States	30	—		411.8		7.4			11.8
			$	1,461.6	$	2,392.4	$	141.1		$	47.9

(a) As at December 31, 2019, the aggregate market value of AltaGas' investment in ACI was $367.9 million (11,025,000 shares at the quoted closing market price of $33.37 on December 31, 2019). As at December 31, 2018, the aggregate market value was $178.8 million (11,025,000 shares at the quoted closing market price of $16.22 on December 31, 2018).

(b) The equity method is considered appropriate because Constitution is a Limited Liability Company (LLC) with specific ownership accounts and ownership between five and fifty percent, resulting in WGL Midstream exercising a more than minor influence over the investee's operating and financing policies. In February 2020, the partners of Constitution elected not to proceed with the pipeline project (Note 33).

(c) Disposed of in 2019 (Note 4).

(d) Inuvik Gas Ltd. was sold to AltaGas Canada Inc. in October 2018.

(e) Meade was a VIE prior to disposition in November 2019 (Notes 4 and 13).

(f) The equity method is considered appropriate because Mountain Valley is an LLC with specific ownership accounts and ownership between five and fifty percent, resulting in WGL Midstream exercising a more than minor influence over the investee's operating and financing policies.

Schedule of Combined Financial Information of Equity Method Investments

Summarized combined financial information, assuming a 100 percent ownership interest in AltaGas’ equity investments listed above, is as follows ^(a):

Year Ended December 31	2019			2018
Revenues	$	1,109.3		$	351.6
Expenses	(355.0		)	(142.7		)
	$	754.3		$	208.9
As at December 31	2019			2018
Current assets	$	411.1		$	1,204.6
Property, plant and equipment	$	8,033.8		$	7,602.5
Intangible assets	$	21.9		$	22.9
Long-term investments and other assets	$	1,458.8		$	1,326.6
Current liabilities	$	(393.8	)	$	(1,015.2	)
Other long-term liabilities	$	(992.1	)	$	(949.6	)

(a) For equity investments that were disposed of in the year (Note 4), revenues and expenses reflect the period prior to disposition and balance sheet amounts as at December 31 are $nil.

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Short-term Debt - Narrative (Details)	12 Months Ended
	Dec. 31, 2019 USD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2018 CAD ($)
Short-term Debt
Project financing		$ 71,000,000		$ 64,500,000
Commercial paper	$ 299,500,000	389,000,000	$ 839,500,000	1,145,200,000
Unsecured Extendible Revolving Facility | Letter of Credit
Short-term Debt
Credit facility maximum borrowing capacity		150,000,000		150,000,000.0
Debt instrument term (years)	4 years
Amount outstanding		25,500,000		117,000,000
Unsecured Bilateral Demand Facility | Letter of Credit
Short-term Debt
Credit facility maximum borrowing capacity	$ 200,000,000		200,000,000.0
Amount outstanding		156,400,000		147,300,000
Unsecured Extendible Revolving Facility II | Letter of Credit
Short-term Debt
Credit facility maximum borrowing capacity	$ 300,000,000		$ 300,000,000.0
Amount outstanding		124,600,000.0		0
Parent Company | Unsecured Demand Revolving Operating Credit Facility
Short-term Debt
Credit facility maximum borrowing capacity		70,000,000		70,000,000.0
Amount outstanding		$ 0		$ 0

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Investments Accounted for by the Equity Method - Schedule of Equity Method Investments (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Schedule of Equity Method Investments
Equity method investment	$ 1,461.6	$ 2,392.4
Income (loss) from equity investments	$ 141.1	47.9
Canada | AltaGas Canada Inc. (ACI) (a)
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	37.00%
Equity method investment	$ 163.9	112.5
Income (loss) from equity investments	17.0	5.4
Equity method investment fair value	$ 367.9	$ 178.8
Shares owned (shares)	11,025,000	11,025,000
Share price (per share)	$ 33.37	$ 16.22
Canada | AltaGas Idemitsu Joint Venture LP
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	50.00%
Equity method investment	$ 431.3	$ 342.9
Income (loss) from equity investments	$ 62.5	2.1
Canada | Inuvik Gas Ltd.
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	33.00%
Equity method investment	$ 0.0	0.0
Income (loss) from equity investments	$ 0.0	(0.2)
Canada | Sarnia Airport Storage Pool LP
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	50.00%
Equity method investment	$ 18.0	18.7
Income (loss) from equity investments	1.0	1.0
Canada | Petrogas Preferred Shares
Schedule of Equity Method Investments
Equity method investment	150.0	150.0
Income (loss) from equity investments	$ 12.8	12.8
United States | Constitution Pipeline, LLC (Constitution)
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	10.00%
Equity method investment	$ 0.1	0.0
Income (loss) from equity investments	$ (0.5)	(0.2)
United States | Craven County Wood Energy LP
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	50.00%
Equity method investment	$ 0.0	7.8
Income (loss) from equity investments	$ 0.1	(14.1)
United States | Eaton Rapids Gas Storage System
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	50.00%
Equity method investment	$ 27.0	29.4
Income (loss) from equity investments	$ 1.3	2.0
United States | Grayling Generating Station LP
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	50.00%
Equity method investment	$ 0.0	29.0
Income (loss) from equity investments	$ 0.3	3.6
United States | Meade Pipeline Co. LLC (Meade)
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	55.00%
Equity method investment	$ 0.0	757.8
Income (loss) from equity investments	$ (3.6)	12.2
United States | Mountain Valley Pipeline, LLC
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	10.00%
Equity method investment	$ 671.3	532.5
Income (loss) from equity investments	$ 42.8	11.5
United States | Stonewall Gas Gathering System LLC
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	30.00%
Equity method investment	$ 0.0	411.8
Income (loss) from equity investments	$ 7.4	$ 11.8

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Other Long-term Liabilities (Tables)

12 Months Ended

Dec. 31, 2019

Other Liabilities Disclosure [Abstract]

Schedule of Other Long-Term Liabilities

As at	December 31, 2019		December 31, 2018
Deferred lease payable	$	—	$	13.1
Deferred revenue	4.0		3.9
Customer advances for construction	63.9		58.6
Sundance B PPAs termination expense (a)	—		2.0
Lease inducement	—		2.7
Merger commitments	14.0		21.4
Other long-term liabilities	19.9		20.3
	$	101.8	$	122.0

(a) In 2016, AltaGas Pipeline Partnership and the Government of Alberta reached a definitive settlement agreement regarding the termination of the Sundance B Power Purchase Arrangements (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”.

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Commitments, Guarantees, and Contingencies

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments, Guarantees, and Contingencies

Commitments, Guarantees, and Contingencies

Commitments

AltaGas has long-term natural gas purchase and transportation arrangements, propane purchase agreements, electricity purchase arrangements, service agreements, pipeline and storage contracts, capital commitments, environmental commitments, merger 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.

Future payments of these commitments as at December 31, 2019 are estimated as follows:

	2020		2021		2022		2023		2024		2025 & beyond		Total
Gas purchase (a)	$	2,374.0	$	2,488.2	$	2,323.6	$	2,076.1	$	1,959.5	$	22,772.0	$	33,993.4
Propane purchase (b)	220.2		127.2		94.9		86.5		58.4		127.1		714.3
Electricity purchase (c)	567.2		318.1		160.0		56.4		11.0		0.4		1,113.1
Service agreements (d) (e) (f)	58.7		44.0		28.2		23.4		22.9		309.1		486.3
Pipeline and storage services (g)	721.2		652.5		627.8		600.4		550.5		3,876.7		7,029.1
Capital projects (h)	6.9		—		—		—		—		—		6.9
Operating leases (i)	27.8		27.1		26.5		24.5		20.1		100.1		226.1
Environmental (j)	6.5		4.3		1.0		1.0		0.6		0.4		13.8
Merger commitments (k)	8.2		3.8		1.9		1.9		1.9		4.3		22.0
	$	3,990.7	$	3,665.2	$	3,263.9	$	2,870.2	$	2,624.9	$	27,190.1	$	43,605.0

(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) AltaGas enters into contracts to purchase propane for its operations at RIPET. These contracts are used to ensure that there is an adequate supply of propane to meet shipment commitments and to minimize exposure to market price fluctuations. Propane purchase commitments are valued based on forward prices, which may fluctuate significantly from period to period.

(c) AltaGas enters into contracts to purchase electricity from various suppliers for its non-utility business. Electricity purchase commitments are based on existing fixed price and fixed volume contracts, and include US$17.4 million of commitments related to renewable energy credits.

(d) In 2014, AltaGas' Blythe facility entered into a Long-Term Service Agreement (LTSA) with Siemens to complete various upgrade and maintenance services on the Combustion Turbines (CT) at the Blythe facility over 124,000 equivalent operating hours per CT, or 25 years, whichever comes first. The LTSA has variable fees on a per equivalent operating hour basis. As at December 31, 2019, the total commitment was $167.9 million payable over the next 16 years, of which $45.4 million is expected to be paid over the next five years.

(e) In 2017, AltaGas entered into a 12-year service agreement for tug services to support the marine operations of RIPET.

(f) In 2015, AltaGas entered into a Project Agreement that contemplated the sublease of lands from Ridley Terminals Inc. (RTI), provision of certain terminal services, and access to RTI's terminal facilities to support RIPET's operations for an initial term of 20 years ending in 2039. In 2019, RILE LP and RTI executed a Terminal Services Agreement that formalized the concepts outlined in the Project Agreement.

(g) Pipeline and storage commitments include minimum payments for natural gas transportation, storage and peaking contracts that have expiration dates through 2044.

(h) Commitments for capital projects. Estimated amounts are subject to variability depending on the actual construction costs.

(i) Operating leases include lease arrangements for office spaces, vehicles, rail cars, land, and office and other equipment.

(j) Environmental commitments include committed payments related to certain environmental response costs.

(k) Represents the estimated future payments of merger commitments that have been accrued but not paid. In addition, there are certain additional merger commitments that will be expensed when costs are incurred in the future, including the investment of up toUS$70 millionover atenyear period to further extend natural gas service, investment ofUS$8 millionfor leak mitigation withinthreeyears of the merger, hiring damage prevention trainers in each jurisdiction for a total ofUS$2 millionoverfiveyears, and developing15megawatts of either electric grid energy storage or Tier 1 renewable resources within five years. As at December 31, 2019, the cumulative amount of merger commitments that have been expensed but not yet paid is approximatelyUS$17 million.

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, 2019, 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.

Antero Contract

In June 2019, a jury trial was held in the County Court for Denver, Colorado to consider a contractual dispute relating to gas pricing between Washington Gas and WGL Midstream (together, the Companies) and Antero Resources Corporation (Antero). Following the trial, the jury returned a verdict in favor of Antero for approximately US$96 million, of which approximately US$11 million was against Washington Gas with the remainder against WGL Midstream. Following the official entry of the judgment, the Companies filed an appeal on August 16, 2019.

AltaGas recorded a net reduction to the acquired working capital of WGL of approximately US$45 million to account for the verdict in favor of Antero net of tax and other expected recoveries. Expected recoveries include a $33.1 million receivable recorded in "Long-term investments and other assets" on the Consolidated Balance Sheets for amounts expected to be recovered under a commercial arrangement with a third party.

Silver Spring, Maryland Incident

On April 23, 2019, the National Transportation and Safety Board (NTSB) held a hearing during which it found, among other things, that the probable cause of the August 10, 2016, explosion and fire at an apartment complex on Arliss Street in Silver Spring, Maryland “was the failure of an indoor mercury service regulator with an unconnected vent line that allowed natural gas into the meter room where it accumulated and ignited from an unknown ignition source. Contributing to the accident was the location of the mercury service regulators where leak detection by odor was not readily available.” Washington Gas disagrees with the NTSB’s probable cause findings. Following this hearing, on June 10, 2019, the NTSB issued an accident report.

A total of 37 civil actions related to the incident were filed against WGL and Washington Gas in the Circuit Court for Montgomery County, Maryland. All of these suits sought unspecified damages for personal injury and/or property damage. All personal injury and property damage claims asserted by residents at the Flower Branch Apartments have been settled and paid. Washington Gas has been reimbursed by its insurers for the amounts paid in the settlements.

In connection with the incident, on September 5, 2019, the PSC of MD ordered Washington Gas, within 30 days, to (i) provide a detailed response to the NTSB’s probable cause findings and (ii) provide evidence regarding the status of a 2003 mercury regulator replacement program and, if the program was not completed, to show cause why the PSC of MD should not impose a civil penalty on Washington Gas. On November 18, 2019, the Technical Staff of the PSC of MD, the MD Office of People’s Counsel (OPC), Montgomery County, MD and the Apartment and Office Building Association of Metropolitan Washington (AOBA) filed written comments on Washington Gas' response to the Show-Cause Order. Technical Staff commented that the PSC of MD may impose a civil penalty but did not expressly recommend same. Montgomery County, MD, OPC and AOBA requested that the PSC of MD impose a civil penalty on Washington Gas. On December 17, 2019, the PSC of MD held a public hearing near the apartment complex at Arliss Street, at which some residents requested that Washington Gas accelerate and complete its mercury service regulator program and that Washington Gas absorb the cost of same. Washington Gas intends to file comments with the PSC of MD responding to all written comments and resident testimony. Management believes that the likelihood of a civil penalty is probable and has accrued US$0.3 million to reflect the minimum liability expected to result from the proceeding. Though Washington Gas is unable to estimate the maximum possible penalty, other parties recommended penalties ranging from US$32 million (AOBA, which argued that Washington Gas should absorb all costs of removal and relocation of mercury service regulators) to US$123.3 million (OPC, which argued that Washington Gas should absorb all costs of removal and relocation of mercury service regulators and pay a fine of US$25,000 per day for each day mercury service regulators remain on Washington Gas’ system).

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Related Party Transactions - Summary of Related Party Amounts Included in Balance Sheets (Details) - CAD ($)	Dec. 31, 2019	Dec. 31, 2018
Related Party Transaction
Due from related parties, Accounts receivable	$ 17,800,000	$ 60,800,000
Due from related parties, Long-term investments and other assets	45,000,000	45,000,000
Due from related parties	62,800,000	105,800,000
Due to related parties, Accounts payable	2,700,000	6,300,000
Due to related parties, Risk management liabilities - current	0	900,000
Due to related parties	2,700,000	7,200,000
Petrogas | AltaGas
Related Party Transaction
Due from related parties, Long-term investments and other assets	45,000,000	$ 45,000,000
Credit facility maximum borrowing capacity	100,000,000.0
Committed amount	$ 50,000,000.0

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- Reconciliation of Cash and Restricted Cash Balances (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Supplemental Cash Flow Elements [Abstract]
Cash and cash equivalents	$ 57.1	$ 101.6
Restricted cash holdings from customers - current	4.0	4.1
Restricted cash holdings from customers - non-current	3.9	6.1
Restricted cash included in prepaid expenses and other current assets	25.4	27.6
Restricted cash included in long-term investments and other assets	32.0	61.7
Cash, cash equivalents and restricted cash per consolidated statement of cash flow	$ 122.4	$ 201.1	$ 43.7

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Shareholders’ Equity

12 Months Ended

Dec. 31, 2019

Stockholders' Equity Note [Abstract]

Shareholders’ Equity

Shareholders’ Equity

Authorization

AltaGas is authorized to issue an unlimited number of voting common shares. AltaGas is also authorized to issue such number of Preferred Shares 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.

Dividend Reinvestment and Optional Cash Purchase Plan (DRIP or the Plan)

The Plan consists oftwocomponents:a Dividend Reinvestment component and an Optional Cash Purchase component. The Premium Dividend™ component of the plan was suspended in December 2018. The Dividend Reinvestment and Optional Cash Purchase component was suspended in December 2019, with the December dividend (payable January 2020) being the last dividend payment eligible for reinvestment by participating shareholders under the DRIP. The Plan in its entirety will remain suspended until further notice.

The Plan provided eligible holders of common shares with the opportunity to, at their election, reinvest the cash dividends paid by AltaGas on their common shares towards the purchase of new common shares at a3 percentdiscount 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).

In addition, the Plan provided 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 was 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 the10 business daysimmediately 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 (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, 2018	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 cost	—	13.3
Shares issued under DRIP	15,377,575	325.8
December 31, 2018	275,224,066	$	6,653.9
Shares issued for cash on exercise of options	76,177	1.2
Deferred taxes on share issuance cost	—	(3.9		)
Shares issued under DRIP	3,774,442	67.8
Issued and outstanding at December 31, 2019	279,074,685	$	6,719.0

Preferred Shares

As at	December 31, 2019				December 31, 2018
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	6,885,823	172.1			8,000,000	200.0
Series H	1,114,177	27.9			—	—
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		(28.5		)		(27.9		)
Fair value adjustment on WGL Acquisition (note 3)		—				4.1
	52,000,000	$	1,277.1		52,280,600	$	1,318.8

On December 20, 2019, all outstanding Washington Gas preferred shares (US$4.25 series, US$4.80 series, and US$5.00 series) were redeemed. A gain of $3.5 million was recognized upon redemption.

.

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)
Series A (e)	3.380	%	$0.84500	$25	September 30, 2020	Series B
Series B (f) (g)	Floating		Floating	$25	September 30, 2020	Series A
Series C (h)	5.290	%	US$1.32250	US$25	September 30, 2022	Series D
Series E (e)	5.393	%	$1.34825	$25	December 31, 2023	Series F
Series G (e)	4.620	%	$1.15575	$25	September 30, 2024	Series H
Series H (f) (g)	Floating		Floating	$25	September 30, 2024	Series G
Series I (i)	5.250	%	$1.31250	$25	December 31, 2020	Series J
Series K (j)	5.000	%	$1.25000	$25	March 31, 2022	Series L

(a) This table only includes those series of preferred shares that are currently issued and outstanding. The Corporation is authorized to issue up to8,000,000of each of Series D Shares, Series F Shares, and Series J Shares, and up to12,000,000of 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 J Shares, and Series L Shares are also redeemable for$25.50, and Series D Shares are redeemable forUS$25.50on 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 and Series H 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 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 of Series A Shares, Series E Shares, and Series G Shares 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 plus2.66 percent(Series A Shares),3.17 percent(Series E Shares), and3.06 percent(Series G Shares).

(f) Holders of Series B Shares and Series H 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 plus2.66 percent(Series B Shares) and3.06 percent(Series H Shares). 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, 2019, the floating quarterly dividend rate is$0.26803per share for Series B Shares and$0.29289per share for Series H Shares for the period starting December 31, 2019 to, but excluding, March 31, 2020.

(g) Series B Shares can be redeemed for$25.50per 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. Series H Shares can be redeemed for$25.50per share on any date after September 30, 2019 that is not a Series H 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 plus3.58 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 plus4.19 percent, provided that, in any event, such rate shall not be less than5.25 percentper 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 plus3.80 percent, provided that, in any event, such rate shall not be less than5.00 percentper annum.

Share Option Plan

AltaGas has an employee share option plan under which officers, employees, and service providers (as defined by the TSX) are eligible to receive grants. As at December 31, 2019, 13,915,160 shares were reserved for issuance under the plan. As at December 31, 2019, share 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, 2019, the unexpensed fair value of share option compensation cost associated with future periods was$4.5 million (December 31, 2018 ‑ $3.7 million).

The following table summarizes information about the Corporation’s share options:

	December 31, 2019				December 31, 2018
As at	Options outstanding				Options outstanding
	Number of options		Exercise price (a)		Number of options		Exercise price (a)
Share options outstanding, beginning of year	6,309,183		$	25.18	4,533,761		$	32.35
Granted	2,287,385		19.12		2,811,460		16.69
Exercised	(76,177	)	14.52		(57,275	)	20.68
Forfeited	(1,165,435	)	27.31		(878,013	)	36.47
Expired	(311,000	)	36.16		(100,750	)	14.60
Share options outstanding, end of year	7,043,956		$	22.49	6,309,183		$	25.18
Share options exercisable, end of year	2,921,642		$	27.70	2,897,723		$	32.01

(a) Weighted average.

As at December 31, 2019, the aggregate intrinsic value of the total share options exercisable was $3.3 million (December 31, 2018 - $nil), the total intrinsic value of share options outstanding was $12.1 million (December 31, 2018 - $nil) and the total intrinsic value of share options exercised was $0.4 million (December 31, 2018 - $0.3 million).

The following table summarizes the employee share option plan as at December 31, 2019:

	Options outstanding				Options exercisable
	Number outstanding	Weighted average exercise price		Weighted average remaining contractual life	Number exercisable	Weighted average exercise price		Weighted average remaining contractual life
$14.52 to $18.00	2,557,328	$	15.19	4.98	638,385	$	14.62	4.79
$18.01 to $25.08	1,961,805	19.78		4.77	305,750	21.05		0.96
$25.09 to $46.70	2,524,823	32.00		2.72	1,977,507	32.95		2.39
	7,043,956	$	22.49	4.11	2,921,642	$	27.70	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	2019	2018
Fair value per options ($)	2.30	1.27
Risk-free interest rate (%)	1.48	1.99
Expected life (years)	6	6
Expected volatility (%)	24.84	23.23
Annual dividend per share ($) (a)	0.96	1.18
Forfeiture rate (%)	—	—

(a) Annual dividend per share is calculated based on a weighted average share price and forward dividend yields as the grant dates.

Phantom Unit Plan (Phantom Plan) and Deferred Share Unit Plan (DSUP)

AltaGas has a Phantom Plan for employees and executive officers, which includes restricted units (RUs) and performance units (PUs) with vesting periods of 36 months from the grant date. In addition, AltaGas has a DSUP, which allows granting of deferred share units (DSUs) to directors. DSUs granted under the DSUP vest immediately but settlement of the DSUs occur when the individual ceases to be a director.

PUs, RUs, and DSUs (number of units)	2019		2018
Balance, beginning of year	9,908,154		564,549
Acquired (a)	—		5,291,621
Converted to cash (a)	—		(5,291,621	)
Granted	674,971		9,502,347
Exercised	(113,668	)	—
Vested and paid out	(677,667	)	(148,154	)
Forfeited	(3,377,962	)	(66,522	)
Units in lieu of dividends	71,003		55,934
Outstanding, end of year	6,484,831		9,908,154

(a) Upon close of the WGL Acquisition in 2018, AltaGas acquired WGL’s PUs. These were converted to a fixed cash amount at a value of US$1.00 per unit. At December 31, 2019, the WGL PUs comprised approximately 4.9 million of the outstanding units (December 31, 2018 - 8.9 million).

For the year ended December 31, 2019, the compensation expense recorded for the Phantom Plan and DSUP was $21.7 million (2018 – $16.6 million). As at December 31, 2019, the unrecognized compensation expense relating to the remaining vesting period for the Phantom Plan was $21.8 million (December 31, 2018 ‑ $26.9 million) and is expected to be recognized over the vesting period.

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Segmented Information - Schedule of Segment Composition (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information
Revenues	$ 5,495.0	$ 4,256.7
Cost of sales	(3,227.1)	(2,455.3)
Operating and administrative	(1,298.7)	(1,129.0)
Accretion expenses	(5.1)	(10.9)
Depreciation and amortization	(438.0)	(394.0)
Provision on assets (note 6)	(415.8)	(728.7)
Income (loss) from equity investments	141.1	47.9
Other income (loss)	908.1	0.9
Foreign exchange gains (losses)	(1.0)	4.5
Interest expense	(345.8)	(309.0)
Income (loss) before income taxes	812.7	(716.9)
Net additions (reductions) to property, plant and equipment	(1,090.2)	572.5
Net additions (reductions) to intangible assets	36.5	45.7
Utilities
Segment Reporting Information
Revenues	2,564.2	1,752.6
Provision on assets (note 6)	0.0	(193.7)
Midstream
Segment Reporting Information
Revenues	1,574.3	1,344.6
Power
Segment Reporting Information
Revenues	1,356.3	1,162.0
Provision on assets (note 6)	(380.6)	(381.3)
Corporate
Segment Reporting Information
Revenues	0.2	(2.5)
Operating Segments
Segment Reporting Information
Revenues	5,539.4	4,369.2
Operating Segments | Utilities
Segment Reporting Information
Revenues	2,590.8	1,765.6
Cost of sales	(1,117.9)	(838.3)
Operating and administrative	(860.7)	(727.4)
Accretion expenses	(0.1)	(0.1)
Depreciation and amortization	(261.6)	(165.8)
Provision on assets (note 6)	0.0	(193.7)
Income (loss) from equity investments	18.3	7.2
Other income (loss)	27.0	4.5
Foreign exchange gains (losses)	0.0	0.0
Interest expense	0.0	(103.9)
Income (loss) before income taxes	395.8	(251.9)
Net additions (reductions) to property, plant and equipment	839.6	507.0
Net additions (reductions) to intangible assets	22.6	21.8
Operating Segments | Midstream
Segment Reporting Information
Revenues	1,581.2	1,435.0
Cost of sales	(1,057.7)	(976.4)
Operating and administrative	(249.1)	(201.7)
Accretion expenses	(3.9)	(4.0)
Depreciation and amortization	(92.1)	(84.4)
Provision on assets (note 6)	(35.2)	(153.7)
Income (loss) from equity investments	122.4	51.1
Other income (loss)	28.7	0.7
Foreign exchange gains (losses)	(4.5)	(0.2)
Interest expense	0.0	(10.6)
Income (loss) before income taxes	289.8	55.8
Net additions (reductions) to property, plant and equipment	350.3	383.4
Net additions (reductions) to intangible assets	4.9	4.7
Operating Segments | Power
Segment Reporting Information
Revenues	1,367.2	1,171.0
Cost of sales	(1,084.4)	(743.7)
Operating and administrative	(159.8)	(159.1)
Accretion expenses	(1.1)	(6.8)
Depreciation and amortization	(72.3)	(130.5)
Provision on assets (note 6)	(380.6)	(381.3)
Income (loss) from equity investments	0.4	(10.4)
Other income (loss)	853.8	(5.9)
Foreign exchange gains (losses)	0.0	(0.1)
Interest expense	0.0	(8.9)
Income (loss) before income taxes	523.2	(275.7)
Net additions (reductions) to property, plant and equipment	(2,281.3)	(321.9)
Net additions (reductions) to intangible assets	0.0	12.5
Operating Segments | Corporate
Segment Reporting Information
Revenues	0.2	(2.4)
Cost of sales	0.0	0.0
Operating and administrative	(40.6)	(50.6)
Accretion expenses	0.0	0.0
Depreciation and amortization	(12.0)	(13.3)
Provision on assets (note 6)	0.0	0.0
Income (loss) from equity investments	0.0	0.0
Other income (loss)	(1.4)	2.0
Foreign exchange gains (losses)	3.5	4.8
Interest expense	(345.8)	(185.6)
Income (loss) before income taxes	(396.1)	(245.1)
Net additions (reductions) to property, plant and equipment	1.2	4.0
Net additions (reductions) to intangible assets	9.0	6.7
Intersegment Elimination
Segment Reporting Information
Revenues	(44.4)	(112.5)
Cost of sales	32.9	103.1
Operating and administrative	11.5	9.8
Accretion expenses	0.0	0.0
Depreciation and amortization	0.0	0.0
Provision on assets (note 6)	0.0	0.0
Income (loss) from equity investments	0.0	0.0
Other income (loss)	0.0	(0.4)
Foreign exchange gains (losses)	0.0	0.0
Interest expense	0.0	0.0
Income (loss) before income taxes	0.0	0.0
Net additions (reductions) to property, plant and equipment	0.0	0.0
Net additions (reductions) to intangible assets	0.0	0.0
Intersegment Elimination | Utilities
Segment Reporting Information
Revenues	(26.6)	(13.0)
Intersegment Elimination | Midstream
Segment Reporting Information
Revenues	(6.9)	(90.4)
Intersegment Elimination | Power
Segment Reporting Information
Revenues	(10.9)	(9.0)
Intersegment Elimination | Corporate
Segment Reporting Information
Revenues	$ 0.0	$ (0.1)

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Dispositions

12 Months Ended

Dec. 31, 2019

Discontinued Operations and Disposal Groups [Abstract]

Dispositions

Dispositions

Northwest Hydro Electric Facilities

On January 31, 2019, AltaGas completed the disposition of its remaining 55 percent indirect interest in the Northwest Hydro Electric facilities in British Columbia (Northwest Hydro) for net cash proceeds of approximately $1.3 billion. The disposition was completed through the sale of 55 percent of Northwest Hydro Limited Partnership, a subsidiary of AltaGas which indirectly held the Northwest Hydro facilities. As a result, AltaGas recognized a pre-tax gain on disposition of approximately $687.6 million in the Consolidated Statements of Income (Loss) under the line item “other income” for the year ended December 31, 2019.

Non-Core Midstream and Power Assets in Canada

On February 1, 2019, AltaGas completed the disposition of certain non-core Midstream and Power assets for gross cash proceeds of approximately $87.8 million. As a result, AltaGas recognized a pre-tax loss on disposition of approximately $1.2 million in the Consolidated Statements of Income (Loss) under the line item “other income” for the year ended December 31, 2019.

Architect of the Capitol (AOC) Project

In February 2019, AltaGas completed the disposition of a financing receivable related to the construction of an energy management services project for gross cash proceeds of approximately $73.5 million. As a result, AltaGas recognized a pre-tax loss on disposition of approximately $1.3 million in the Consolidated Statements of Income (Loss) under the line item “other income” for the year ended December 31, 2019.

Stonewall Gas Gathering System

On May 31, 2019, AltaGas completed the disposition of WGL Midstream's entire interest in the Stonewall Gas Gathering System (Stonewall) to a wholly-owned subsidiary of DTE Energy Company for gross cash proceeds of approximately $379.2 million (US$280 million). As a result, AltaGas recognized a pre-tax gain on disposition of $34.1 million in the Consolidated Statements of Income (Loss) under the line item “other income” for the year ended December 31, 2019.

Biomass Assets

On August 13, 2019, AltaGas completed the disposition of its equity ownership interests in Craven County Wood Energy LP and Grayling Generation Station LP for net proceeds of approximately $24.5 million (US$18.5 million). There was no gain or loss resulting from this disposition.

Distributed Generation Assets

On September 26, 2019, AltaGas closed the disposition of its portfolio of U.S. distributed generation assets for gross cash proceeds of approximately $975.0 million (US$735.0 million).As a result, AltaGas recognized a pre-tax gain on disposition of approximately $167.5 millionin the Consolidated Statements of Income (Loss) under the line item "other income" for the year ended December 31, 2019. There are certain projects for which ownership will not legally transfer to the purchaser until various consents and approvals are obtained. As such, the carrying value of the assets and liabilities relating to these projects remain classified as held for sale on the Consolidated Balance Sheets as at December 31, 2019 (Note 5). The portion of the purchase price relating to these projects is approximately $32.2 million(US$24.8 million)and is recorded within "accounts payable and accrued liabilities" on the Consolidated Balance Sheets until these projects are legally transferred to the purchaser. The pre-tax gain related to these remaining projects has also been deferred and will be recognized as these projects are legally transferred. The purchaser is entitled to after-tax earnings from the distributed generation projects, including those awaiting consent, beginning September 1, 2019.

Capital Spare

In the third quarter of 2019, AltaGas completed the sale of a capital spare turbine in the Power segment for gross cash proceeds of $4.6 million (US$3.5 million). There was no gain or loss resulting from this disposition in the year ended December 31, 2019.

Investment in Meade

On November 13, 2019, AltaGas completed the disposition of its investment in Meade Pipeline Co. LLC (Meade) which held WGL Midstream's indirect, non-operating interest in the Central Penn pipeline (Central Penn), for cash proceeds of approximately $811.5 million (US$610.8 million). As a result, AltaGas recognized a pre-tax loss on disposition of $11.1 millionin the Consolidated Statements of Income (Loss) under the line item “other income” for the year ended December 31, 2019. During 2019, AltaGas also recognized a pre-tax provision of $44.2 million against AltaGas' investment in Meade Pipeline Co. LLC (Note 14).

Assets Held For Sale

As at	December 31, 2019		December 31, 2018
Assets held for sale
Cash	$	—	$	4.9
Accounts receivable	—		85.2
Inventory	—		0.5
Property, plant and equipment	22.9		1,189.6
Intangible assets	—		248.7
Operating right-of-use assets	0.4		—
Goodwill	1.0		—
Other long-term assets	3.2		—
	$	27.5	$	1,528.9
Liabilities associated with assets held for sale
Accounts payable and accrued liabilities	$	—	$	23.8
Asset retirement obligations	0.2		10.8
Unamortized investment tax credits	3.2		—
Operating lease liabilities - long-term	0.4		—
Other long-term liabilities	—		136.8
	$	3.8	$	171.4

Distributed Generation Assets

In September 2019, AltaGas closed the sale of its portfolio of U.S. distributed generation assets (Note 4). However, there are certain projects for which ownership will not legally transfer to the purchaser until various consents and approvals are obtained. As such, the carrying value of the assets and liabilities related to these projects remain classified as held for sale at December 31, 2019. These assets are recorded in the Power segment.

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Pension Plans and Retiree Benefits - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 CAD ($) plan age	Dec. 31, 2018 CAD ($)
Defined Benefit Plan Disclosure
Defined contribution plan cost recorded | $	$ 19.8	$ 15.4
Rabbi trust | $	$ 57.4	$ 89.3
Assumed initial healthcare cost trend rate	6.30%
Minimum
Defined Benefit Plan Disclosure
Plan assets investment objective period	3 years
Ultimate trend rate	2.00%
Maximum
Defined Benefit Plan Disclosure
Plan assets investment objective period	5 years
Ultimate trend rate	4.50%
Defined Benefit | Canada
Defined Benefit Plan Disclosure
Number of pension plans	5
Defined Benefit | Canada | Fully funded
Defined Benefit Plan Disclosure
Number of pension plans	2
Defined Benefit | United States
Defined Benefit Plan Disclosure
Number of pension plans	6
Defined Benefit | United States | Fully funded
Defined Benefit Plan Disclosure
Number of pension plans	1
Post- Retirement Benefits | Canada
Defined Benefit Plan Disclosure
Number of pension plans	1
Post- Retirement Benefits | United States
Defined Benefit Plan Disclosure
Number of pension plans	4
Medical benefit eligibility age | age	65
Post- Retirement Benefits | United States | Partially funded
Defined Benefit Plan Disclosure
Number of pension plans	1
Post- Retirement Benefits | United States | Fully funded
Defined Benefit Plan Disclosure
Number of pension plans	3

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Label	Element	Value
Retained Earnings [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ (7,100,000)

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Shareholders’ Equity - Summary of Fair Value Options Granted (Details) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Stockholders' Equity Note [Abstract]
Fair value per option (per share)	$ 2.30	$ 1.27
Risk-free interest rate (percent)	1.48%	1.99%
Expected life (years)	6 years	6 years
Expected volatility (percent)	24.84%	23.23%
Annual dividend per share (per share)	$ 0.96253	$ 1.18
Forfeiture rate (percent)	0.00%	0.00%

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2019

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, Plant and Equipment

As at	December 31, 2019									December 31, 2018
	Cost			Accumulated amortization			Net book value			Cost			Accumulated amortization			Net book value
Utilities	$	7,316.1		$	(155.0	)	$	7,161.1		$	7,090.5		$	(89.7	)	$	7,000.8
Midstream	3,182.0			(585.4		)	2,596.6			3,178.2			(845.7		)	2,332.5
Power	976.7			(594.6		)	382.1			4,633.9			(1,858.3		)	2,775.6
Corporate	49.5			(40.9		)	8.6			49.4			(39.1		)	10.3
Reclassified to assets held for sale	(25.2		)	2.3			(22.9		)	(2,999.3		)	1,809.7			(1,189.6		)
	$	11,499.1		$	(1,373.6	)	$	10,125.5		$	11,952.7		$	(1,023.1	)	$	10,929.6

Interest capitalized on long-term capital construction projects for the year ended December 31, 2019 was $14.5 million(2018 - $12.6 million).

As at December 31, 2019, the Corporation had approximately $725.2 million (December 31, 2018 - $872.7 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, 2019 was $357.8 million (2018 - $324.3 million).

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Long-Term Investments and Other Assets

12 Months Ended

Dec. 31, 2019

Investments, All Other Investments [Abstract]

Long-Term Investments and Other Assets

Long-Term Investments and Other Assets

As at	December 31, 2019		December 31, 2018
Investments in publicly-traded entities	$	4.3	$	8.4
Loan to affiliate	45.0		45.0
Deferred lease receivable	17.4		24.4
Debt issuance costs associated with credit facilities	6.2		7.9
Refundable deposits	8.9		16.2
Prepayment on long-term service agreements	80.6		82.5
Cash calls from joint venture partners	9.5		—
Contract asset (note 24)	30.0		11.5
Rabbi trust (notes 28 and 31)	32.0		61.7
Other long-term receivables (note 29)	33.1		—
Other	29.5		25.5
	$	296.5	$	283.1

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Long-Term Debt

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

As at	Maturity date	December 31, 2019			December 31, 2018
Credit facilities
$1,400 million unsecured extendible revolving facility (a)	15-May-2023	$	89.6		$	964.7
US$300 million unsecured extendible revolving facility (b)	15-May-2022	—			287.8
Acquisition credit facility (c)	6-Jan-2020	—			113.2
US$1,200 million unsecured revolving credit facility (d)	28-Dec-2021	—			1,637.0
US$300 million unsecured term facility	27-Feb-2021	389.6			—
US$150 million unsecured extendible revolving facility	20-Dec-2023	163.5			—
Commercial paper (e)	Various	367.4			—
AltaGas Ltd. medium-term notes (MTNs)
$200 million Senior unsecured - 4.55 percent	17-Jan-2019	—			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
$500 million Senior unsecured - 2.61 percent	16-Dec-2022	500.0			—
$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	300.0			299.9
$350 million Senior unsecured - 4.12 percent	7-Apr-2026	349.9			349.8
$200 million Senior unsecured - 3.98 percent	4-Oct-2027	199.9			199.9
$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
$250 million Senior unsecured - 4.99 percent	4-Oct-2047	250.0			250.0
WGL and Washington Gas MTNs
US$450 million Senior unsecured - 2.25 to 4.76 percent (f)	Nov 2019	—			682.1
US$250 million Senior unsecured - 2.44 percent (g)	12-Mar-2020	324.7			341.1
US$20 million Senior unsecured - 6.65 percent	20-Mar-2023	26.0			27.3
US$40.5 million Senior unsecured - 5.44 percent	11-Aug-2025	52.6			55.3
US$53 million Senior unsecured - 6.62 to 6.82 percent	Oct - 2026	68.8			72.3
US$72 million Senior unsecured - 6.40 to 6.57 percent	Feb - Sep 2027	93.5			98.2
US$52 million Senior unsecured - 6.57 to 6.85 percent	Jan - Mar 2028	67.5			70.9
US$8.5 million Senior unsecured - 7.50 percent	1-Apr-2030	11.0			11.6
US$50 million Senior unsecured - 5.70 to 5.78 percent	Jan - Mar 2036	64.9			68.2
US$75 million Senior unsecured - 5.21 percent	3-Dec-2040	97.4			102.3
US$75 million Senior unsecured - 5.00 percent	15-Dec-2043	97.4			102.3
US$300 million Senior unsecured - 4.22 to 4.60 percent	Sep - Dec 2044	389.6			409.3
US$450 million Senior unsecured - 3.80 percent	15-Sep-2046	584.5			613.9
US$300 million Senior unsecured - 3.65 percent	16-Sep-2049	389.6			—
SEMCO long-term debt
US$300 million SEMCO Senior Secured - 5.15 percent (h)	21-Apr-2020	389.6			409.3
US$82 million SEMCO Senior Secured - 4.48 percent (i)	2-Mar-2032	76.1			86.3
Fair value adjustment on WGL Acquisition (note 3)		84.3			89.0
Finance lease liabilities (note 10)		9.9			0.8
		$	6,887.1		$	8,992.3
Less debt issuance costs		(36.4		)	(35.2		)
		$	6,850.7		$	8,957.1
Less current portion		(922.9		)	(890.2		)
		$	5,927.8		$	8,066.9

(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) The acquisition facility was repaid in full and canceled on February 1, 2019.

(d) Borrowings on the facility can be by way of U.S. base-rate loans, U.S. prime loans, or LIBOR loans.

(e) Commercial paper is supported by the availability of long-term committed credit facilities with maturity dates ranging from 2022 to 2024.

(f) Certain MTNs have a floating rate per annum reset quarterly based on terms set forth in the prospectus supplement filed by WGL pursuant to Securities Act Rule 424 on November 27, 2017.

(g) Floating rate per annum reset quarterly based on terms set forth in the prospectus filed by WGL pursuant to Securities Act Rule 424 on March 13, 2018.

(h) Collateral for the U.S. dollar MTNs is certain SEMCO assets.

(i) 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.

Other Credit Facilities

As at December 31, 2019, WGL held a US$250.0 million (December 31, 2018 - 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, 2019 or December 31, 2018.

As at December 31, 2019, Washington Gas held a US$450.0 million (December 31, 2018 - US$350.0 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, 2019 or December 31, 2018.

WGL and Washington Gas use short-term debt in the form of commercial paper and advances under its syndicated bank credit facilities 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. As at December 31, 2019, outstanding commercial paper classified as long-term debt totaled US$283.5 million (December 31, 2018 - $nil).

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Income Taxes

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Year Ended December 31	2019			2018
Income (loss) before income taxes - consolidated	$	812.7		$	(716.9	)
Statutory income tax rate (%)	26.5			27.0
Expected taxes at statutory rates	$	215.4		$	(193.6	)
Add (deduct) the tax effect of:
Permanent differences	$	10.9		$	(1.0	)
Statutory and other rate differences	(51.6		)	(19.6		)
Rate adjustment for change in tax rates	(10.7		)	1.3
Deferred income tax recovery on regulated assets	(24.8		)	(7.3		)
Tax differences on divestitures and transactions	(158.2		)	(32.3		)
Non-controlling interests	3.5			4.7
Change in valuation allowance	(11.1		)	(22.3		)
Other	(1.0		)	6.9
	$	(27.6	)	$	(263.2	)
Income tax provision
Current
Canada	$	26.7		$	23.7
United States	36.6			0.7
	$	63.3		$	24.4
Deferred
Canada	$	11.6		$	(166.1	)
United States	(102.5		)	(121.5		)
	$	(90.9	)	$	(287.6	)
Effective income tax rate (%)	(3.4		)	36.7

Net deferred income tax liabilities were composed of the following:

As at	December 31, 2019			December 31, 2018
PP&E and intangible assets	$	1,450.6		$	1,764.6
Regulatory assets	(204.1		)	(166.3		)
Tax pools, deferred financing, and compensation	(138.2		)	(453.6		)
Other	(161.2		)	(209.9		)
Valuation allowance	12.0			23.1
	$	959.1		$	957.9

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 Alberta government passed the Job Creation Tax Cut in 2019 which reduced Alberta's corporate tax rate from 12 percent to 11 percent on July 1, 2019. The tax rate will further be reduced from 11 percent to 10 percent on January 1, 2020 and by 1 percent each year until 2022. The rate from 2022 onwards will ultimately be 8 percent.

The B.C. government increased the corporate tax rate to 12 percent from 11 percent beginning in 2018.

As at December 31, 2019, the Corporation had tax-effected non-capital losses of approximately $170.4 million, which will be available to offset future taxable income. If not used, these losses will expire between 2024 and 2039.

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 2018 remain subject to examination by taxation authorities. In the United States, both the federal and state tax returns filed for the years 2013 to 2018 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	2019			2018
Balance, beginning of year	$	2.2		$	5.9
Net changes during the year	(0.2		)	(3.7		)
Balance, end of year	$	2.0		$	2.2

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Segmented Information - Schedule of Goodwill and Total Assets by Segment (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information
Goodwill (note 11)	$ 3,942.1	$ 4,068.2	$ 817.3
Segmented assets	19,794.5	23,487.7
Operating Segments | Utilities
Segment Reporting Information
Goodwill (note 11)	3,573.0	3,450.8
Segmented assets	13,097.1	12,991.3
Operating Segments | Midstream
Segment Reporting Information
Goodwill (note 11)	246.5	426.4
Segmented assets	5,471.4	6,398.8
Operating Segments | Power
Segment Reporting Information
Goodwill (note 11)	122.6	191.0
Segmented assets	1,019.9	3,814.7
Operating Segments | Corporate
Segment Reporting Information
Goodwill (note 11)	0.0	0.0
Segmented assets	$ 206.1	$ 282.9

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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, 2019 CAD ($)
Defined Benefit
Defined Benefit Plan Disclosure
Past service credit (cost)	$ (0.2)
Actuarial gain (loss)	(17.1)
Total	(17.3)
Post- Retirement Benefits
Defined Benefit Plan Disclosure
Past service credit (cost)	16.7
Actuarial gain (loss)	0.5
Total	$ 17.2

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Pension Plans and Retiree Benefits - Summary of Assumed Health Care Cost Trend Rates (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 CAD ($)
Retirement Benefits [Abstract]
Increase, Service and interest costs	$ 1.9
Decrease, Service and interest costs	(1.5)
Increase, Accrued benefit obligations	22.7
Decrease, Accrued benefit obligation	$ (18.4)

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Leases - Supplemental Cashflow Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 CAD ($)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from finance leases	$ (0.3)
Operating cash flows from operating leases	(20.6)
Financing cash flows from finance leases	(3.7)
Right-of-use assets obtained in exchange for new lease liabilities
Operating leases	50.4
Finance leases	$ 5.4

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Shareholders’ Equity - Schedule of Common Shares Issued and Outstanding (Details) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Increase (Decrease) in Stockholders' Equity
Balance, beginning of year		$ 7,019.6
Beginning balance (shares)		275,200,000
Shares issued for cash on exercise of options (shares)		76,177.000000	57,275
Ending balance (shares)		279,100,000	275,200,000
Balance at end of year		$ 7,214.9	$ 7,019.6
Common stock
Increase (Decrease) in Stockholders' Equity
Balance, beginning of year		$ 6,653.9	$ 4,007.9
Beginning balance (shares)		275,224,066	175,279,216
Shares issued on conversion of subscription receipts, net of issuance costs			$ 2,305.6
Shares issued on conversion of subscription receipts, net of issuance costs (shares)			84,510,000
Shares issued for cash on exercise of options, Amount		$ 1.2	$ 1.3
Shares issued for cash on exercise of options (shares)		76,177	57,275
Deferred taxes on share issuance cost		$ (3.9)	$ 13.3
Shares issued under DRIP	[1]	$ 67.8	$ 325.8
Shares issued under DRIP (shares)		3,774,442	15,377,575
Ending balance (shares)		279,074,685	275,224,066
Balance at end of year		$ 6,719.0	$ 6,653.9

[1] Premium Dividend™, Dividend Reinvestment and Optional Cash Purchase Plan.

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Financial Instruments and Financial Risk Management (Tables)

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Fair Value of Risk Management Assets and Liabilities

As at	December 31, 2019
	Carrying Amount		Level 1		Level 2		Level 3		Total Fair Value
Financial assets
Fair value through net income (a)
Risk management assets - current	$	81.4	$	—	$	30.4	$	51.0	$	81.4
Risk management assets - non-current	30.9		—		6.7		24.2		30.9
Equity securities (b)	4.3		4.3		—		—		4.3
Fair value through regulatory assets (a)
Risk management assets - current	5.2		—		—		5.2		5.2
Risk management assets - non-current	8.2		—		0.4		7.8		8.2
Amortized cost
Loans and receivables (b)	45.0		—		46.1		—		46.1
	$	175.0	$	4.3	$	83.6	$	88.2	$	176.1
Financial liabilities
Fair value through net income (a)
Risk management liabilities - current	$	120.6	$	—	$	98.7	$	21.9	$	120.6
Risk management liabilities - non-current	77.0		—		19.2		57.8		77.0
Fair value through regulatory liabilities (a)
Risk management liabilities - current	4.2		—		0.6		3.6		4.2
Risk management liabilities - non-current	90.0		—		—		90.0		90.0
Amortized cost
Current portion of long-term debt	922.9		—		922.9		—		922.9
Long-term debt	5,927.8		—		6,263.8		—		6,263.8
Other current liabilities (c)	15.4		—		15.4		—		15.4
	$	7,157.9	$	—	$	7,320.6	$	173.3	$	7,493.9

(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.

As at	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 (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 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		—		8,040.3		—		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	$	—	$	8,997.5	$	242.7	$	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.

Quantitative Information About the Significant Unobservable Inputs Used In The Fair Value Measurement Of Level 3

The following table includes quantitative information about the significant unobservable inputs used in the fair value measurement of Level 3 financial instruments as at December 31, 2019:

	Net Fair Value			Valuation Technique	Unobservable Inputs	Range
Natural gas	$	(83.8	)	Discounted Cash Flow	Natural Gas Basis Price (per dekatherm)	$	(1.18	)	-	$	3.27
Natural gas	$	(1.4	)	Option Model	Natural Gas Basis Price (per dekatherm)	$	(1.19	)	-	$	3.30
					Annualized Volatility of Spot Market Natural Gas	29		%	-	906		%
Electricity	$	0.1		Discounted Cash Flow	Electricity Congestion Price (per megawatt hour)	$	(6.73	)	-	$	65.26

Changes In Net Fair Value Of Derivative Assets And Liabilities Classified As Level 3

The following tables provide 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	2019									2018
	Natural Gas			Electricity			Total			Natural Gas			Electricity			Total
Balance, beginning of year	$	(148.5	)	$	(14.7	)	$	(163.2	)	$	—		$	—		$	—
Acquired (note 3)	—			—			—			(136.1		)	(10.6		)	(146.7		)
Realized and unrealized gains (losses):
Recorded in income	47.6			1.4			49.0			(8.3		)	(6.5		)	(14.8		)
Recorded in regulatory assets	23.6			—			23.6			(5.9		)	—			(5.9		)
Transfers into Level 3	(9.0		)	—			(9.0		)	—			—			—
Transfers out of Level 3	12.3			—			12.3			7.3			—			7.3
Purchases	—			(11.4		)	(11.4		)	—			6.4			6.4
Settlements	(17.1		)	24.4			7.3			0.3			(3.4		)	(3.1		)
Foreign exchange translation	5.9			0.4			6.3			(5.8		)	(0.6		)	(6.4		)
Balance, end of year	$	(85.2	)	$	0.1		$	(85.1	)	$	(148.5	)	$	(14.7	)	$	(163.2	)

Realized and Unrealized Losses Recorded To Income For Level 3 Measurements

Realized and Unrealized Gains (Losses) Recorded to Income for Level 3 Measurements

Year Ended December 31	2019			2018
Recorded to revenue	$	75.2		$	(11.1	)
Recorded to cost of sales	(26.2		)	(3.7		)
	$	49.0		$	(14.8	)

Summary of Unrealized Gains (Losses) on Risk Management Contracts

Summary of Unrealized Gains (Losses) on Risk Management Contracts Recognized in Net Income (Loss)

Year Ended December 31	2019			2018
Natural gas	$	22.5		$	(2.2	)
Energy exports	(86.7		)	—
NGL frac spread	(17.4		)	40.0
Power	(4.9		)	9.3
Foreign exchange	1.2			33.7
	$	(85.3	)	$	80.8

Schedule of Offsetting Assets and Liabilities

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 specific credit-risk-related contingent features underlying these agreements were triggered:

As at	December 31, 2019		December 31, 2018
Risk management liabilities with credit-risk-contingent features	$	42.2	$	14.7
Maximum potential collateral requirements	$	29.0	$	7.5

As at	December 31, 2019
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	$	121.2	$	(53.7	)	$	—		$	67.5
Energy exports	9.7		(2.7		)	4.4			11.4
NGL frac spread	0.3		(0.2		)	—			0.1
Power	53.5		(6.8		)	—			46.7
	$	184.7	$	(63.4	)	$	4.4		$	125.7
Risk management liabilities (b)
Natural gas	$	226.1	$	(53.7	)	$	(27.7	)	$	144.7
Energy exports	89.5		(2.7		)	—			86.8
NGL frac spread	1.7		(0.2		)	—			1.5
Power	68.7		(6.8		)	(3.1		)	58.8
	$	386.0	$	(63.4	)	$	(30.8	)	$	291.8

(a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $86.6 million and risk management assets (non‑current) balance of $39.1 million.

(b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $124.8 million and risk management liabilities (non‑current) balance of $167.0 million.

As at	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.

Cash Collateral

The following table presents collateral not offset against risk management assets and liabilities:

As at	December 31, 2019		December 31, 2018
Collateral posted with counterparties	$	29.1	$	27.6
Cash collateral held representing an obligation	$	0.3	$	0.8

Schedule of Notional Amounts of Outstanding Derivative Positions

AltaGas had the following power commodity forward contracts and commodity swaps outstanding as at December 31, 2019 and 2018:

December 31, 2019	Fixed price (per MWh)	Period (months)	Notional volume (MWh)	Fair Value
Power sales	31.63 to 66.76	1-42	8,034,024	$	39.0
Power purchases	31.63 to 66.76	1-60	8,552,467	$	(27.3	)
Swap purchases	(7.88) to 74.26	1-48	25,058,577	$	(23.8	)
December 31, 2018	Fixed price (per MWh)	Period (months)	Notional volume (MWh)	Fair Value
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	)

AltaGas had the following contracts outstanding as at December 31, 2019:

December 31, 2019	Fixed price (per Bbl)	Period (months)	Notional volume (Bbl)	Fair Value
Propane	21.49 to 29.71	1-27	9,374,826	$	(75.4	)

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, 2019 and 2018:

December 31, 2019	Fixed price	Period (months)	Notional volume		Fair Value
Butane swaps	73.02 to 75.15/Bbl	1-12	346,852	Bbl	$	(0.5	)
Crude oil swaps	73.02 to 75.15/Bbl	1-12	212,587	Bbl	$	(0.9	)
Natural gas swaps	1.58 to 1.86/GJ	1-12	3,883,992	GJ	$	—
December 31, 2018	Fixed price	Period (months)	Notional volume		Fair Value
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	)

AltaGas had the following forward contracts and commodity swaps outstanding related to the activities in the energy services business as at December 31, 2019 and 2018:

December 31, 2019	Fixed price (per GJ)	Period (months)	Notional volume (GJ)	Fair Value
Sales	1.32 to 6.81	1-166	698,126,985	$	28.9
Purchases	0.22 to 6.81	1-167	1,406,991,689	$	(104.4	)
Swaps	0.22 to 10.24	1-51	541,652,374	$	(1.7	)
December 31, 2018	Fixed price (per GJ)	Period (months)	Notional volume (GJ)	Fair Value
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

Summary of Potential Impact on Pre-Tax Income Due to Change in Fair Value of Price Risk Derivatives

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, 2019:

Factor	Increase or decrease to forward prices	Increase or decrease to income before tax ($ millions)
Alberta power price	$1/MWh	2.3
PJM power price	US$1/MWh	1.9
AECO natural gas price	$0.50/GJ	1.1
NYMEX natural gas price	US$0.50/GJ	2.6
Energy Exports:
Propane Far East Index to Mont Belvieu spread	$1/Bbl	3.4
Baltic LPG Freight	$1/Bbl	6.1
NGL frac spread:
Western Texas Intermediate (WTI) crude oil	$1/Bbl	0.6
Natural gas	$0.50/GJ	1.9

Schedule of Accounts Receivable Past Due or Impaired

AltaGas had the following past due or impaired accounts receivable (AR):

As at December 31, 2019	Total			AR accruals		Receivables impaired			Less than 30 days		31 to 60 days		61 to 90 days		Over 90 days
Trade receivable	$	1,238.2		$	343.5	$	33.2		$	757.9	$	61.2	$	11.6	$	30.8
Other	17.4			—		—			17.3		—		—		0.1
Allowance for credit losses	(33.2		)	—		(33.2		)	—		—		—		—
	$	1,222.4		$	343.5	$	—		$	775.2	$	61.2	$	11.6	$	30.9

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

Allowance for credit losses	December 31, 2019			December 31, 2018
Balance, beginning of year	$	54.7		$	2.4
Foreign exchange translation	(2.6		)	0.1
New allowance (a)	27.5			53.1
Change in allowance (b)	(9.2		)	(0.9		)
Allowance applied to uncollectible customer accounts	(37.2		)	—
Balance, end of year	$	33.2		$	54.7

(a) Upon close of the WGL Acquisition in 2018, AltaGas acquired WGL’s allowance for credit losses of approximately $52.9 million.

(b) Includes removal of allowance related to asset disposals of approximately $8.1 million in 2019.

Schedule of Contractual Maturities for Financial Liabilities

AltaGas had the following contractual maturities with respect to financial liabilities:

	Contractual maturities by period
As at December 31, 2019	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Accounts payable and accrued liabilities	$	1,324.9	$	1,324.9	$	—	$	—	$	—
Dividends payable	22.3		22.3		—		—		—
Short-term debt	460.0		460.0		—		—		—
Other current liabilities (a)	15.4		15.4		—		—		—
Risk management contract liabilities	291.8		124.8		34.1		13.2		119.7
Current portion of long-term debt (b)	920.4		920.4		—		—		—
Long-term debt (b)	5,872.5		—		1,489.2		921.3		3,462.0
	$	8,907.3	$	2,867.8	$	1,523.3	$	934.5	$	3,581.7

(a) Excludes non-financial liabilities.

(b) Excludes deferred financing costs, discounts, finance lease liabilities, and the fair value adjustment on the WGL Acquisition.

	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, discounts, finance lease liabilities, and the fair value adjustment on the WGL Acquisition.

XML

Other Income (Tables)

12 Months Ended

Dec. 31, 2019

Other Income and Expenses [Abstract]

Schedule of Other Income

Year Ended December 31	2019			2018
Gains (losses) from sale of assets	$	875.8		$	(10.6	)
Other components of net benefit cost (note 28)	27.4			18.9
Interest income and other revenue	9.0			2.7
Losses on investments	(4.1		)	(10.1		)
	$	908.1		$	0.9

XML

Revenue - Disaggregation of Revenue by Major Sources (Details) - CAD ($) $ in Millions		12 Months Ended
	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue
Revenue from contracts with customers		$ 4,940.5	$ 3,123.8
Other sources of revenue		554.5	1,132.9
Total revenue		5,495.0	4,256.7
Contract term	20 years
Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers		2,225.1	1,162.7
Midstream service contracts
Disaggregation of Revenue
Revenue from contracts with customers		145.0	205.0
Gas sales and transportation services
Disaggregation of Revenue
Revenue from contracts with customers		2,501.4	1,684.3
Storage services
Disaggregation of Revenue
Revenue from contracts with customers		28.1	35.4
Other
Disaggregation of Revenue
Revenue from contracts with customers		40.9	36.4
Revenue from alternative revenue programs
Disaggregation of Revenue
Other sources of revenue		29.5	21.7
Leasing revenue
Disaggregation of Revenue
Other sources of revenue		242.6	452.1
Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue		262.3	644.2
Other
Disaggregation of Revenue
Other sources of revenue		20.1	14.9
Utilities
Disaggregation of Revenue
Total revenue		2,564.2	1,752.6
Midstream
Disaggregation of Revenue
Total revenue		1,574.3	1,344.6
Midstream | Risk management and trading activities | GAIL
Disaggregation of Revenue
Total revenue		504.5	264.2
Power
Disaggregation of Revenue
Total revenue		1,356.3	1,162.0
Corporate
Disaggregation of Revenue
Total revenue		0.2	(2.5)
Operating Segments
Disaggregation of Revenue
Total revenue		5,539.4	4,369.2
Operating Segments | Utilities
Disaggregation of Revenue
Revenue from contracts with customers		2,538.7	1,730.4
Other sources of revenue		25.5	22.2
Total revenue		2,590.8	1,765.6
Operating Segments | Utilities | Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers		0.0	0.0
Operating Segments | Utilities | Midstream service contracts
Disaggregation of Revenue
Revenue from contracts with customers		0.0	0.0
Operating Segments | Utilities | Gas sales and transportation services
Disaggregation of Revenue
Revenue from contracts with customers		2,501.4	1,684.3
Operating Segments | Utilities | Storage services
Disaggregation of Revenue
Revenue from contracts with customers		28.1	35.4
Operating Segments | Utilities | Other
Disaggregation of Revenue
Revenue from contracts with customers		9.2	10.7
Operating Segments | Utilities | Revenue from alternative revenue programs
Disaggregation of Revenue
Other sources of revenue		29.5	21.7
Operating Segments | Utilities | Leasing revenue
Disaggregation of Revenue
Other sources of revenue		0.9	0.6
Operating Segments | Utilities | Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue		0.0	1.0
Operating Segments | Utilities | Other
Disaggregation of Revenue
Other sources of revenue		(4.9)	(1.1)
Operating Segments | Midstream
Disaggregation of Revenue
Revenue from contracts with customers		1,241.4	870.8
Other sources of revenue		332.9	473.8
Total revenue		1,581.2	1,435.0
Operating Segments | Midstream | Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers		$ 1,093.7	665.2
Contract term		1 year
Operating Segments | Midstream | Midstream service contracts
Disaggregation of Revenue
Revenue from contracts with customers		$ 145.0	205.0
Operating Segments | Midstream | Gas sales and transportation services
Disaggregation of Revenue
Revenue from contracts with customers		0.0	0.0
Operating Segments | Midstream | Storage services
Disaggregation of Revenue
Revenue from contracts with customers		0.0	0.0
Operating Segments | Midstream | Other
Disaggregation of Revenue
Revenue from contracts with customers		2.7	0.6
Operating Segments | Midstream | Revenue from alternative revenue programs
Disaggregation of Revenue
Other sources of revenue		0.0	0.0
Operating Segments | Midstream | Leasing revenue
Disaggregation of Revenue
Other sources of revenue		136.6	96.6
Operating Segments | Midstream | Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue		196.2	377.6
Operating Segments | Midstream | Other
Disaggregation of Revenue
Other sources of revenue		0.1	(0.4)
Operating Segments | Power
Disaggregation of Revenue
Revenue from contracts with customers		1,160.4	522.6
Other sources of revenue		195.9	639.4
Total revenue		1,367.2	1,171.0
Operating Segments | Power | Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers		1,131.4	497.5
Operating Segments | Power | Midstream service contracts
Disaggregation of Revenue
Revenue from contracts with customers		0.0	0.0
Operating Segments | Power | Gas sales and transportation services
Disaggregation of Revenue
Revenue from contracts with customers		0.0	0.0
Operating Segments | Power | Storage services
Disaggregation of Revenue
Revenue from contracts with customers		0.0	0.0
Operating Segments | Power | Other
Disaggregation of Revenue
Revenue from contracts with customers		29.0	25.1
Operating Segments | Power | Revenue from alternative revenue programs
Disaggregation of Revenue
Other sources of revenue		0.0	0.0
Operating Segments | Power | Leasing revenue
Disaggregation of Revenue
Other sources of revenue		105.1	354.9
Operating Segments | Power | Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue		65.9	268.5
Operating Segments | Power | Other
Disaggregation of Revenue
Other sources of revenue		24.9	16.0
Operating Segments | Corporate
Disaggregation of Revenue
Revenue from contracts with customers		0.0	0.0
Other sources of revenue		0.2	(2.5)
Total revenue		0.2	(2.4)
Operating Segments | Corporate | Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers		0.0	0.0
Operating Segments | Corporate | Midstream service contracts
Disaggregation of Revenue
Revenue from contracts with customers		0.0	0.0
Operating Segments | Corporate | Gas sales and transportation services
Disaggregation of Revenue
Revenue from contracts with customers		0.0	0.0
Operating Segments | Corporate | Storage services
Disaggregation of Revenue
Revenue from contracts with customers		0.0	0.0
Operating Segments | Corporate | Other
Disaggregation of Revenue
Revenue from contracts with customers		0.0	0.0
Operating Segments | Corporate | Revenue from alternative revenue programs
Disaggregation of Revenue
Other sources of revenue		0.0	0.0
Operating Segments | Corporate | Leasing revenue
Disaggregation of Revenue
Other sources of revenue		0.0	0.0
Operating Segments | Corporate | Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue		0.2	(2.9)
Operating Segments | Corporate | Other
Disaggregation of Revenue
Other sources of revenue		$ 0.0	$ 0.4

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Leases - Schedule of Operating Lease Receivables (Details) $ in Millions	Dec. 31, 2019 CAD ($)
Operating Leases
2020	$ 118.3
2021	115.4
2022	115.6
2023	115.9
2024	47.8
Thereafter	477.5
Total	$ 990.5

XML

Consolidated Statements of Cash Flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Cash from (used by) operations
Net income (loss) after taxes	$ 840.3	$ (453.7)
Items not involving cash:
Depreciation and amortization	438.0	394.0
Provisions on assets (note 6)	415.8	728.7
Accretion expenses	5.1	10.9
Share-based compensation (note 25)	3.5	0.8
Deferred income tax recovery (note 20)	(90.9)	(287.6)
Losses (gains) on sale of assets (notes 4 and 27)	(875.8)	10.6
Income from equity investments (note 14)	(141.1)	(47.9)
Unrealized losses (gains) on risk management contracts (note 23)	85.3	(80.8)
Realized loss on expiry of foreign exchange options	0.0	36.0
Losses on investments (note 27)	4.1	10.1
Amortization of deferred financing costs	11.5	29.7
Provision for doubtful accounts	26.7	17.0
Net change in pension and other post-retirement benefits (note 28)	8.1	(3.8)
Other	9.2	3.6
Asset retirement obligations settled (note 17)	(2.5)	(4.2)
Distributions from equity investments	109.7	44.5
Changes in operating assets and liabilities (note 31)	(231.5)	(486.5)
Net cash provided (required) by operating activities	615.5	(78.6)
Investing activities
Business acquisitions, net of cash acquired	0.0	(5,931.0)
Acquisition of property, plant and equipment	(1,296.8)	(990.4)
Acquisition of intangible assets	(37.7)	(38.1)
Contributions to equity investments	(178.7)	(235.4)
Loan to affiliate, net of repayment (note 30)	0.0	30.0
Financing receivable	0.0	(8.7)
Proceeds from disposition of investments	0.0	76.5
Proceeds from initial public offering of AltaGas Canada Inc.	0.0	858.9
Proceeds from disposition of assets, net of transaction costs (note 4)	3,623.4	403.8
Proceeds from disposition of financing receivable (note 4)	73.5	0.0
Net cash provided (required) by investing activities	2,183.7	(5,834.4)
Financing activities
Net issuance (repayment) of short-term debt	(700.9)
Net issuance (repayment) of short-term debt		497.7
Issuance of long-term debt, net of debt issuance costs	888.6	1,851.9
Repayment of long-term debt	(873.3)	(278.8)
Net borrowing (repayment) under credit facilities	(1,919.7)	846.2
Dividends - common shares	(265.7)	(472.9)
Dividends - preferred shares	(68.5)	(66.6)
Distributions to non-controlling interest	(13.4)	(30.3)
Contributions from non-controlling interests	47.9	96.3
Net proceeds from shares issued on exercise of options	1.1	1.2
Net proceeds from issuance of common shares	67.8	2,633.7
Redemption of preferred shares (note 25)	(37.6)	0.0
Net proceeds from sale of non-controlling interest	0.0	908.6
Net cash provided (required) by financing activities	(2,873.7)	5,987.0
Change in cash, cash equivalents, and restricted cash	(74.5)	74.0
Effect of exchange rate changes on cash, cash equivalents, and restricted cash	(9.1)	7.3
Net change in cash classified within assets held for sale	4.9	(4.9)
Restricted cash acquired (note 31)	0.0	81.0
Cash, cash equivalents, and restricted cash beginning of year	201.1	43.7
Cash, cash equivalents, and restricted cash end of year (note 31)	$ 122.4	$ 201.1

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Variable Interest Entities - Schedule of VIE Amounts in Consolidated Balance Sheets (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Variable Interest Entity
Current assets	$ 2,196.2	$ 4,033.0
Property, plant and equipment	10,125.5	10,929.6
Long-term investments and other assets	296.5	283.1
Total operating lease right-of-use assets	170.2
Current liabilities	(3,125.1)	(4,102.0)
Asset retirement obligations	(368.4)	(510.5)
Other long-term liabilities	(101.8)	(122.0)
VIE
Variable Interest Entity
Current assets	6.4	1,383.5
Property, plant and equipment	371.1	619.2
Long-term investments and other assets	53.3	48.0
Total operating lease right-of-use assets	0.1	0.0
Current liabilities	(3.6)	(161.8)
Asset retirement obligations	(3.3)	(0.9)
Other long-term liabilities	(0.1)	(3.0)
Net assets	$ 423.9	$ 1,885.0

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Consolidated Balance Sheets (Parenthetical) - shares shares in Millions	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Common shares issued (shares)	279.1	275.2
Common shares outstanding (shares)	279.1	275.2

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2019

Supplemental Cash Flow Elements [Abstract]

Schedule of Changes in Operating Assets and Liabilities

The following table details the changes in operating assets and liabilities from operating activities:

	Year Ended December 31
	2019			2018
Source (use) of cash:
Accounts receivable	$	168.4		$	(526.9	)
Inventory	(2.1		)	(100.8		)
Other current assets	(85.5		)	12.5
Regulatory assets - current	7.1			(15.8		)
Accounts payable and accrued liabilities	(280.2		)	237.9
Customer deposits	(16.9		)	(13.3		)
Regulatory liabilities - current	34.2			69.2
Risk management liabilities - current	1.1			—
Other current liabilities	(5.6		)	(5.9		)
Other operating assets and liabilities	(52.0		)	(143.4		)
Changes in operating assets and liabilities	$	(231.5	)	$	(486.5	)

Schedule of Supplemental Cash Payments

The following cash payments have been included in the determination of earnings:

	Year Ended December 31
	2019		2018
Interest paid (net of capitalized interest)	$	351.7	$	288.9
Income taxes paid	$	67.2	$	36.9

Reconciliation of Cash and Restricted Cash Balances

he following table is a reconciliation of cash and restricted cash balances:

As at December 31	2019		2018
Cash and cash equivalents	$	57.1	$	101.6
Restricted cash holdings from customers - current	4.0		4.1
Restricted cash holdings from customers - non-current	3.9		6.1
Restricted cash included in prepaid expenses and other current assets (a)	25.4		27.6
Restricted cash included in long-term investments and other assets (a)	32.0		61.7
Cash, cash equivalents, and restricted cash per Consolidated Statements of Cash Flows	$	122.4	$	201.1

(a) The restricted cash balances included in prepaid expenses and other current assets and long-term investments and other assets relate to Rabbi trusts associated with WGL’s pension plans (seeNote 28).

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Income Taxes - Schedule of Income Tax Provision (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income (loss) before income taxes - consolidated	$ 812.7	$ (716.9)
Statutory income tax rate (percent)	26.50%	27.00%
Expected taxes at statutory rates	$ 215.4	$ (193.6)
Permanent differences	10.9	(1.0)
Statutory and other rate differences	(51.6)	(19.6)
Rate adjustment for change in tax rates	(10.7)	1.3
Deferred income tax recovery on regulated assets	(24.8)	(7.3)
Tax differences on divestitures and transactions	(158.2)	(32.3)
Non-controlling interests	3.5	4.7
Change in valuation allowance	(11.1)	(22.3)
Other	(1.0)	6.9
Income tax expense, total	(27.6)	(263.2)
Current
Canada	26.7	23.7
United States	36.6	0.7
Current income tax provision	63.3	24.4
Deferred
Canada	11.6	(166.1)
United States	(102.5)	(121.5)
Deferred income tax expense	$ (90.9)	$ (287.6)
Effective income tax rate (percent)	(3.40%)	36.70%

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Inventory (Tables)

12 Months Ended

Dec. 31, 2019

Inventory Disclosure [Abstract]

Schedule of Inventory

As at December 31	2019		2018
Natural gas held in storage (a)	$	359.0	$	418.0
Materials and supplies	56.3		53.3
Renewable energy credits and emission compliance instruments	64.1		38.2
Natural gas liquids	26.2		6.4
	$	505.6	$	515.9

(a) As at December 31, 2019, $214.3 million of the natural gas held in storage was held by rate-regulated utilities(2018 - $270.4 million).

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(Tables)

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Summary of Estimated Useful Lives of Property, Plant and Equipment

The range of useful lives for AltaGas’ PP&E is as follows:

Utilities assets	4 to 69 years
Midstream assets	2 to 45 years
Power generation assets	3 to 46 years
Corporate assets	3 to 7 years

As at	December 31, 2019									December 31, 2018
	Cost			Accumulated amortization			Net book value			Cost			Accumulated amortization			Net book value
Utilities	$	7,316.1		$	(155.0	)	$	7,161.1		$	7,090.5		$	(89.7	)	$	7,000.8
Midstream	3,182.0			(585.4		)	2,596.6			3,178.2			(845.7		)	2,332.5
Power	976.7			(594.6		)	382.1			4,633.9			(1,858.3		)	2,775.6
Corporate	49.5			(40.9		)	8.6			49.4			(39.1		)	10.3
Reclassified to assets held for sale	(25.2		)	2.3			(22.9		)	(2,999.3		)	1,809.7			(1,189.6		)
	$	11,499.1		$	(1,373.6	)	$	10,125.5		$	11,952.7		$	(1,023.1	)	$	10,929.6

Summary of Estimated Useful Lives of Finite-Lived Intangible Assets

The range of useful lives for intangible assets with a finite life is as follows:

Energy services relationships	5 to 19 years
Electricity service agreements	2 to 60 years
Software	3 to 10 years
Land rights	5 to 64 years
Franchises and consents	9 to 25 years
Extraction and Transmission (E&T) Contracts	25 years
Commodity contracts	5 to 20 years

As at	December 31, 2019							December 31, 2018
	Cost		Accumulated amortization			Net book value		Cost			Accumulated amortization			Net book value
E&T contracts	$	26.6	$	(15.2	)	$	11.4	$	26.6		$	(14.3	)	$	12.3
Electricity service agreements	8.5		(7.8		)	0.7		269.5			(25.9		)	243.6
Energy services relationships	91.6		(27.4		)	64.2		176.1			(33.8		)	142.3
Software	303.7		(101.2		)	202.5		293.9			(77.7		)	216.2
Land rights	1.1		(0.1		)	1.0		1.4			(0.2		)	1.2
Commodity contracts	327.1		(21.3		)	305.8		346.3			(6.3		)	340.0
Franchises and consents	—		—			—		5.0			—			5.0
Reclassified to assets held for sale (note 5)	—		—			—		(277.4		)	28.7			(248.7		)
	$	758.6	$	(173.0	)	$	585.6	$	841.4		$	(129.5	)	$	711.9

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Regulatory Assets and Liabilities - Schedule of Regulatory Assets and Liabilities (Details) $ in Millions, $ in Millions		12 Months Ended
	Sep. 18, 2013 USD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2018 CAD ($)
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current		$ 12.8	$ 21.0
Regulatory assets - non-current		486.7	663.0
Regulatory liabilities - current		145.5	114.9
Regulatory liabilities - non-current		1,383.2	1,392.8
Fair value adjustment		79.8	87.3
Deferred cost of gas
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		$ 60.2	71.2
Recovery period (years)		1 year
Refundable tax credit
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		$ 1.9	3.8
Regulatory liabilities - non-current		$ 3.9	6.1
Gas storage facility tax credit	$ 15.0
Recovery period (years)		1 year
Virginia Rate Refund
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		$ 40.4	0.0
Recovery period (years)		1 year
Federal income tax rate change
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		$ 33.1	26.2
Regulatory liabilities - non-current		$ 628.3	698.4
Recovery period (years)		1 year
Future recovery of pension and other retirement benefits
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - non-current		$ 261.2	166.7
Future removal and site restoration costs
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - non-current		483.9	514.7
Deferred gain on debt transactions and derivative instruments
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - non-current		1.6	1.8
Accelerated replacement recovery mechanisms
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		$ 0.4	5.2
Recovery period (years)		1 year
Interruptible sharing
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		$ 0.4	2.3
Recovery period (years)		1 year
Other
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		$ 9.1	6.2
Regulatory liabilities - non-current		$ 4.3	5.1
Recovery period (years)		1 year
Refundable tax credit noncurrent
Schedule Of Regulatory Assets And Liabilities
Recovery period (years)		2 years
Deferred cost of gas
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current		$ 7.6	20.4
Recovery period (years)		1 year
Accelerated replacement recovery mechanisms
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current		$ 2.5	0.0
Recovery period (years)		1 year
Interruptible sharing
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current		$ 2.7	0.6
Recovery period (years)		1 year
Deferred regulatory costs and rate stabilization adjustment mechanism
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		$ 149.5	215.5
Deferred regulatory costs and rate stabilization adjustment mechanism | Minimum
Schedule Of Regulatory Assets And Liabilities
Recovery period (years)		1 year
Deferred regulatory costs and rate stabilization adjustment mechanism | Maximum
Schedule Of Regulatory Assets And Liabilities
Recovery period (years)		51 years
Future recovery of pension and other retirement benefits
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		$ 128.2	192.9
Future recovery of non-retirement employee benefits
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		19.4	21.3
Deferred pension costs
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		0.0	7.8
Deferred environmental costs
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		17.7	19.9
Deferred loss on debt transactions and derivative instruments
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		99.2	109.3
Deferred future income taxes
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		42.7	67.0
Energy efficiency program - Maryland
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		12.1	4.6
Other
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		$ 17.9	$ 24.7

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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, 2019 CAD ($) $ / MW $ / dekatherm
Natural Gas | Minimum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Percent	29.00%
Natural Gas | Maximum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Percent	906.00%
Natural Gas | Discounted Cash Flow
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability) | $	$ (83.8)
Natural Gas | Discounted Cash Flow | Minimum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Dekatherm	(1.18)
Natural Gas | Discounted Cash Flow | Maximum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Dekatherm	3.27
Natural Gas | Option Model
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability) | $	$ (1.4)
Natural Gas | Option Model | Minimum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Dekatherm	(1.19)
Natural Gas | Option Model | Maximum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Dekatherm	3.30
Electricity | Discounted Cash Flow
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability) | $	$ 0.1
Electricity | Discounted Cash Flow | Minimum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Megawatt Hour | $ / MW	(6.73)
Electricity | Discounted Cash Flow | Maximum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Megawatt Hour | $ / MW	65.26