40-F

U.S. SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 40-F

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

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

For the fiscal year ended: December 31, 2020 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	None
(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

1700, 355-4th Avenue SW

Calgary, Alberta T2P 0J1

(403) 691-7575

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

AltaGas Services (U.S.) Inc.

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:

☒   Annual information form ☒  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 279,494,299 Common Shares, of no par value, outstanding as of December 31, 2020.

Indicate by check mark whether the Registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to filing requirements for the past 90 days.

Yes ☒ No o

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 ☒ No o

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

Emerging growth company ☐

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. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

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. 333-253122) 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, 2020 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, 2020 and audited consolidated financial statements for the fiscal year ended December 31, 2020, 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, 2020 and concluded that the Registrant’s internal control over financial reporting is effective as at December 31, 2020.

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, 2020, 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 the chair of the Registrant’s audit committee, Robert B. Hodgins, qualifies as an audit committee financial expert for purposes of paragraph (8) of General Instruction B to Form 40-F. Details of his relevant experience is included under the heading “Audit Committee - Relevant Education and Experience” at page 58 of the Registrant’s Annual Information Form for the fiscal year ended December 31, 2020, filed as part of this Annual Report on Form 40-F in Exhibit 13.1. The Commission has indicated that the designation of Robert B. Hodgins as an audit committee financial expert does not make him an “expert” for any purpose, impose any duties, obligations or liabilities on him 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. 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 independent, as that term is defined in the Corporate Governance Listing Standards of the New York Stock Exchange (the “NYSE”).

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 2020, 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 59 of the Registrant’s Annual Information Form for the fiscal year ended December 31, 2020, 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, 2020 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, 2020, 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 26, 2021

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

EXHIBIT INDEX

13.1	2020 Annual Information Form dated February 25, 2021 for the fiscal year ended December 31, 2020
13.2	Management's Discussion and Analysis for the year ended December 31, 2020 and audited consolidated financial statements for the fiscal year ended December 31, 2020
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, 2020

Dated: February 25, 2021

TABLE OF CONTENTS

GENERAL INFORMATION	2
FORWARD-LOOKING INFORMATION AND STATEMENTS	2
GLOSSARY	3
METRIC CONVERSION	11
CORPORATE STRUCTURE	11
OVERVIEW OF THE BUSINESS	13
ALTAGAS’ GEOGRAPHIC FOOTPRINT	14
OUTLOOK	15
GENERAL DEVELOPMENT OF ALTAGAS' BUSINESS	15
DEVELOPMENT OF THE UTILITIES BUSINESS OF ALTAGAS	16
DEVELOPMENT OF THE MIDSTREAM BUSINESS OF ALTAGAS	17
DEVELOPMENT OF THE CORPORATE/OTHER BUSINESS OF ALTAGAS	18
BUSINESS OF THE CORPORATION	19
UTILITIES BUSINESS	19
MIDSTREAM BUSINESS	33
CORPORATE/OTHER SEGMENT	49
CAPITAL STRUCTURE	50
GENERAL	53
EMPLOYEES	53
DIRECTORS AND OFFICERS	53
EXECUTIVE OFFICERS	56
AUDIT COMMITTEE	57
RISK FACTORS	59
ENVIRONMENTAL, SOCIAL, AND GOVERNANCE	75
DIVIDENDS	78
MARKET FOR SECURITIES	79
CREDIT RATINGS	82
MATERIAL CONTRACTS	84
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	85
LEGAL PROCEEDINGS	85
REGULATORY ACTIONS	86
INTERESTS OF EXPERTS	86
ADDITIONAL INFORMATION	86
TRANSFER AGENTS AND REGISTRARS	86
SCHEDULE A: AUDIT COMMITTEE MANDATE	87

AltaGas Ltd. – 2020 Annual Information Form – 1

GENERAL INFORMATION

Unless otherwise noted, the information contained in this AIF is stated as at December 31, 2020 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 strategy, priorities and focus with regard to its Utilities and Midstream segments; the Corporation’s 2021 strategic priorities; timing of material regulatory filings, proceedings and decisions in the Utilities business; duration of orders by Utilities regulators addressing the COVID-19 public health emergency; expected timing of costs related to merger commitments; Washington Gas’ potential remediation obligations related to real property; 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: the expected duration and impacts of the COVID-19 pandemic; expected commodity supply, demand and pricing; volumes and rates; exchange rates; inflation; interest rates; credit ratings; regulatory approvals and policies; future operating and capital costs; project completion dates; capacity expectations; 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: risk related to COVID-19; health and safety risks; risks related to the integration of Petrogas; operating risks; regulatory risks; cyber security, information, and control systems; litigation risk; climate-related risks, including carbon pricing; changes in law; political uncertainty and civil unrest; infrastructure risks; service interruptions; decommissioning, abandonment and reclamation costs; reputation risk; weather data; Indigenous land and rights claims; crown duty to consult with Indigenous peoples; capital market and liquidity risks; general economic conditions; internal credit risk; foreign exchange risk; debt financing, refinancing, and debt service risk; interest rates; technical systems and processes incidents; dependence on certain partners; growth strategy risk; construction and development; transportation of petroleum products; impact of competition in AltaGas' businesses; counterparty credit risk; market risk; composition risk; collateral; rep agreements; delays in U.S. Federal Government budget appropriations; 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; commitments associated with regulatory approvals for the acquisition of WGL; 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; and the other factors discussed under the heading "Risk Factors" in this AIF.

AltaGas Ltd. – 2020 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., which has since been renamed TriSummit Utilities 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;

AltaGas Ltd. – 2020 Annual Information Form – 3

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

"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;

AltaGas Ltd. – 2020 Annual Information Form – 4

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

"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;

"COVID-19" means the 2019 novel coronavirus;

"CPI" means the Consumer Price Index;

"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;

"Enerchem" means Enerchem International Inc., a wholly owned subsidiary of Petrogas;

"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;

"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.;

"g" means grams;

"GHG" means greenhouse gas;

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

AltaGas Ltd. – 2020 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;

"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;

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

AltaGas Ltd. – 2020 Annual Information Form – 6

"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;

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

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

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

"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 previously owned run-of-river hydroelectric facilities in northwest British Columbia;

"Nova Chemicals" means NOVA Chemicals Corporation;

"NOx" means nitrogen oxides;

"NTSB" means the National Transportation Safety Board;

"O2" means oxygen;

"Painted Pony" means Painted Pony Energy Ltd.;

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

AltaGas Ltd. – 2020 Annual Information Form – 7

"Pembina" means Pembina Infrastructure and Logistics LP;

"Petrogas" means Petrogas Energy Corp., a North American integrated midstream company in which AltaGas acquired a controlling interest on December 15, 2020;

"Petrogas Acquisition" means AltaGas' acquisition of a controlling interest in Petrogas on December 15, 2020;

"Plan" means the Premium DividendTM, 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, which was sold during 2020;

"Pomona Energy Storage facility" means the 20 MW lithium ion battery storage facility in Pomona, California, which was sold during 2020;

"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 E Shares, Series G Shares, Series H Shares, Series I Shares, and Series K 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;

"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;

AltaGas Ltd. – 2020 Annual Information Form – 8

"Ripon" means the 49.5 MW gas-fired generation facility in Ripon, California, which was sold during 2020;

"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 E Shares" means the cumulative redeemable 5-year fixed rate reset preferred shares, Series E, 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, which were redeemed by AltaGas on December 31, 2020;

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

"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;

AltaGas Ltd. – 2020 Annual Information Form – 9

"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 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;

"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;

"USEPA" means United States Environmental Protection Agency;

"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 PSC of DC, the PSC of MD and the SCC of VA;

"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;

AltaGas Ltd. – 2020 Annual Information Form – 10

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

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

"WCSB" means Western Canada Sedimentary Basin;

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

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

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

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

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

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

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

METRIC CONVERSION

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

To Convert From	To	Multiply by	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
metric tonnes	Bbls (propane)	12.40	metric tonnes	Bbls (butane)	10.90

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".

AltaGas Ltd. – 2020 Annual Information Form – 11

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, 2020.

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

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

AltaGas Ltd. – 2020 Annual Information Form – 12

OVERVIEW OF THE BUSINESS

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 North America 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.

In 2020, AltaGas revised its reportable segments to align with the structure of its business following asset sales 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. Consistent with Management’s strategic view of the business and the basis on which it assesses performance and allocates resources, beginning in 2020, AltaGas has two operating segments: Utilities (which now includes the WGL retail marketing business) and Midstream. These operating segments have not been aggregated in the determination of AltaGas' reportable segments. All other assets are included in the Corporate/Other segment. AltaGas' operating segments include the following:

▪Utilities, which serves approximately 1.7 million customers with a rate base of approximately US$4.3 billion through ownership of regulated natural gas distribution utilities across five jurisdictions in the United States and two regulated natural gas storage utilities in the United States, delivering affordable natural gas to homes and businesses. The Utilities business also includes storage facilities and contracts for interstate natural gas transportation and storage services, as well as the affiliated retail energy marketing business, which serves approximately 0.5 million customers; and

▪Midstream, which includes a 70 percent interest in RIPET and an approximate 74 percent interest in the Ferndale terminal, allowing AltaGas to leverage its assets along the energy value chain in Western Canada and the Western United States including natural gas gathering and processing, NGL extraction and fractionation, and natural gas and NGL marketing. The Midstream segment also includes transmission, storage, and an interest in a regulated pipeline in the Marcellus/Utica gas formation in the northeastern United States. Upon close of the acquisition of Petrogas, the Midstream business also includes a 74 percent interest in Petrogas' other operations, which include LPG exports and distribution, domestic terminals, wellsite fluids and fuels, and trucking and liquids handling.

The Corporate/Other segment consists of AltaGas' corporate activities and a small portfolio of remaining power assets, certain of which are pending sale.

AltaGas Ltd. – 2020 Annual Information Form – 13

ALTAGAS’ GEOGRAPHIC FOOTPRINT

AltaGas Ltd. – 2020 Annual Information Form – 14

OUTLOOK

In 2021, AltaGas plans to focus on progressing its long-term strategy of building a diversified Utilities and Midstream business designed to provide resilient and durable value for its stakeholders that compounds over the long-term. Specific 2021 strategic priorities include to:

▪Continue to deliver affordable natural gas and LPGs to domestic and global markets in a safe, reliable, and efficient manner;

▪Advance AltaGas' operational excellence model to improve business processes and aggressively manage costs to improve the customer experience and returns;

▪Build a world class Midstream and energy export business by maximizing the utilization of existing assets and integrating and optimizing the Petrogas business to advance AltaGas' distinctive energy export strategy; and

▪Maintain a disciplined approach to capital allocation within a self-funding model that continues to de-lever the balance sheet and increase financial flexibility over time, with incremental de-leveraging opportunities being possible from potential non-core asset sales.

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.

AltaGas Ltd. – 2020 Annual Information Form – 15

Development of the Utilities Business of AltaGas

On July 6, 2018, the WGL Acquisition closed and the operations of Washington Gas and Hampshire Gas, as well as the retail energy marketing business of WGL Energy Services, 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 ceased to be subsidiaries of AltaGas.

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 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".

On March 16, 2020, the Council of the District of Columbia passed legislation prohibiting the disconnection of electric and gas services for non-payment of fees during a public health emergency. See "Business of the Corporation - Utilities Business - Washington Gas - Material Regulatory Developments and Approvals".

On March 16, 2020, the Governor of Maryland issued an Executive Order which ordered regulated utilities to cease disconnections and billing of late fees for residential customers. See "Business of the Corporation - Utilities Business - Washington Gas - Material Regulatory Developments and Approvals".

On March 16, 2020, the SCC of VA issued an order which prohibited disconnections of electricity, gas, water, and sewer utility services during the coronavirus public health emergency. See "Business of the Corporation - Utilities Business - Washington Gas - Material Regulatory Developments and Approvals".

On March 31, 2020, the Public Sector Pension Investment Board and the Alberta Teachers' Retirement Fund Board acquired all the issued and outstanding common shares of ACI for $33.50 per share. AltaGas owned 11,025,000 (approximately 37 percent) of ACI's common shares and received cash proceeds of approximately $369 million upon close.

On April 10, 2020, the Governor of Alaska signed Senate Bill 241, which allows certificated utilities to record a regulatory asset for extraordinary costs and uncollectible residential utility bills that result from the COVID-19 public health disaster emergency declared by the governor on March 11, 2020. See "Business of the Corporation - Utilities Business - ENSTAR - Material Regulatory Developments and Approvals".

On April 15, 2020, the MPSC issued an order for all utilities which allows for regulatory asset accounting to capture bad debts in excess of what is in approved rates. See "Business of the Corporation - Utilities Business - SEMCO Gas - Material Regulatory Developments and Approvals".

AltaGas Ltd. – 2020 Annual Information Form – 16

On August 28, 2020, Washington Gas filed an application with the PSC of MD 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

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) 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. In the third quarter of 2020, ConocoPhillips acquired oil and gas assets in the Inga/Fireweed/Stoddard division in the Montney area from Kelt. All operating agreements of AltaGas remain in effect.

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 23, 2019, the first shipment of propane to Asia departed from RIPET, the first propane marine export facility in Canada. On August 21, 2020, the Canada Energy Regulator increased AltaGas a 25-year license to export an additional 46,000 Bbls/d of propane. By December 2020, RIPET's physical volumes were approximately 54,000 Bbls/d. For further details on this project see below under the heading "Business of the Corporation – Midstream Business – Global Exports".

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 pursuant to which SAM exercised the Put Option with respect to SAM's approximate one-third interest in Petrogas effective December 31, 2019. On October 16, 2020, AltaGas announced that AIJVLP and SAM had entered into a definitive agreement whereby AltaGas would acquire SAM's 37 percent of Petrogas' equity for total consideration of $715 million. On December 15, 2020, AltaGas completed the acquisition, increasing its indirectly held ownership interest in Petrogas to approximately 74 percent with Idemitsu owning the remaining interest of approximately 26 percent.

On February 14, 2020, AltaGas executed a 15-year Asset Management Agreement, effective April 1, 2020, with Consolidated Edison, giving it the rights to AltaGas' 50,000 Dth per day of transportation capacity on the Transco Pipeline System in the U.S., providing additional stability to the Midstream business.

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.

AltaGas Ltd. – 2020 Annual Information Form – 17

In the first half of 2020, the Company expanded its integrated northeast B.C. strategy with the completion of the North Pine and Townsend 2B expansions. The 10,000 Bbls/d North Pine expansion was completed and placed into service in the first quarter with additional capacity for the rail terminal to handle the additional volume. The Townsend 2B expansion was commissioned in the second quarter and began flowing gas in early May. In March 2020, Townsend Complex licensed capacity was increased to 550 Mmcf/d.

Development of the Corporate/Other Segment 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, the business of WGL Energy Systems was added to AltaGas’ Corporate/Other segment.

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 remained operator of the facilities until the expiration of an operating and maintenance agreement on 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 $25 million (US$19 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 is one remaining project for which legal title has not yet transferred as various consents and approvals remain outstanding. Accordingly, assets of approximately $4 million and liabilities of $1 million remain held for sale at December 31, 2020.

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.

In the third quarter of 2020, AltaGas closed the dispositions of AltaGas Pomona Energy Storage Inc. and land related to a gas fired power generation facility in the U.S., as well as AltaGas Ripon Energy Inc. Aggregate gross proceeds for these dispositions, before working capital and other adjustments, were approximately $67 million, resulting in a pre-tax gain of $8 million.

AltaGas Ltd. – 2020 Annual Information Form – 18

BUSINESS OF THE CORPORATION

AltaGas’ revenue for the year ended December 31, 2020 was approximately $5.6 billion compared to $5.5 billion for the year ended December 31, 2019.

Note: Excluding Corporate/Other segment and intersegment eliminations

In 2020, AltaGas revised its reportable segments to align with the structure of its business following asset sales 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, each of which is more particularly described in the respective sections that follow. AltaGas’ business also includes the Corporate/Other segment, which consists primarily of a small portfolio of remaining power assets, certain risk management contract results, and revenues and expenses not directly identifiable with the operating businesses.

UTILITIES BUSINESS

The Utilities business contributed revenue of $3.8 billion for the year ended December 31, 2020 (2019 - $4.0 billion), representing approximately 70 percent (2019 – 76 percent) of AltaGas’ total revenue before Corporate/Other segment and intersegment eliminations.

Utilities Business

The Utilities segment owns utility assets that deliver natural gas to end-users in the United States, as well as operates a retail energy marketing business. The Utilities business 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; a 65 percent interest in CINGSA, a regulated natural gas storage utility in Alaska; and WGL Energy Services, which sells natural gas and electricity to retail customers on an unregulated basis.

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

AltaGas Ltd. – 2020 Annual Information Form – 19

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 conditions and regulatory review and approval in multi-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, 2020 and 2019:

(US$ millions)	2020	2019
Rate base (1) (2)	4,291	3,865

(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, 2020 and 2019:

(US$ millions)	2020	2019
New business	109	252
System betterment and gas supply	191	165
General plant	29	30
Accelerated Replacement Programs	227	200
Total	556	647

AltaGas Ltd. – 2020 Annual Information Form – 20

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, 2020	Allowed Common Equity (%)	Allowed ROE (%) 2019	Allowed ROE (%) 2020	Significant Features/ Material Regulatory Developments
Washington Gas	PSC of MD SCC of VA PSC of DC	75%	53.5 - 55.7	9.2 - 9.7	9.2 - 9.7	nDistribution rates approved under cost of service model. nRate 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. nRate case filed in January 2020 with the PSC of DC for an increase in rates. Settlement agreement filed December 2020, pending PSC of DC approval. nRate case filed in August 2020 with the PSC of MD for an increase in rates. Evidentiary hearing took place January 2021. Commission decision expected around late Q1 2021.
SEMCO Gas	MPSC	17%	45.86	10.35	9.87	nDistribution rates approved under cost of service model. nUse of projected test year for rate cases with 10-month limit to issue a rate order. nRate 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.
ENSTAR	RCA	6%	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. nIn December 2020, RCA approved ENSTAR motion to extend the filing of the next rate case to June 2022 based on 2021 historical test year.
CINGSA	RCA	2%	53.04	10.25	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. – 2020 Annual Information Form – 21

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 (~165,000; 14 percent), Maryland (~500,000; 41 percent), and Virginia (~540,000; 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 average number of customers at Washington Gas has increased by approximately 1 percent annually during the past two years (with an increase of 1 percent in 2020).

Operations

Washington Gas obtains natural gas supplies that originate from multiple regions throughout the U.S. At December 31, 2020, it had service agreements with five pipeline companies that provided firm transportation and storage services, with contract expiration dates ranging from 2021 to 2039. 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:

	2020	2019
Deliveries: (MDth)
Residential	62,672	69,660
Commercial	18,845	21,997
Transport	79,424	85,658
Total deliveries	160,941	177,315
	2020	2019
Customers at Year End:
Residential	978,635	973,549
Commercial	48,464	47,677
Transport	178,430	171,236
Total customers	1,205,529	1,192,462

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. See "Business of the Corporation - Utilities Business - Washington Gas - Material Regulatory Developments and Approvals - District of Columbia Jurisdiction".

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Material Regulatory Developments and Approvals

District of Columbia Jurisdiction

Washington Gas has an Accelerated Pipe Replacement Plan (PROJECTpipes) for the replacement of higher-risk pipe associated with an aging infrastructure in its distribution system in the District of Columbia. The first phase of this plan expired in September 2019. In 2018, Washington Gas filed a request with the PSC of DC for the approval of the second phase of this plan (PROJECTpipes 2). Given the length of the proceeding, the PSC of DC approved additional extensions of the plan for the period from October 2019 to December 2020. On December 11, 2020, the PSC of DC approved a 3-year, US$150 million plan covering the period from January 1, 2021 to December 31, 2023.

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. On December 8, 2020, Washington Gas filed, for PSC of DC approval, a settlement agreement to resolve all issues in the case. The settling parties agreed to a US$20 million increase in base rates including PROJECTpipes surcharges previously collected as a rider and return on equity of 9.25 percent. The settling parties agree that this settlement is limited to resolving PROJECTpipes costs that are completed and in service, as of the date of Washington Gas' filed rebuttal testimony (i.e., September 14, 2020). Washington Gas' rebuttal testimony included an amount of up to approximately US$100 million of PROJECTpipes plant in service being transferred to base rates. This settlement does not set any precedent with respect to any future requests for PROJECTpipes cost recovery. Washington Gas agrees it will not file for a distribution rate increase or request any new rate or tariff mechanisms that have a related customer rate increase in the District of Columbia before August 31, 2021. On February 24, 2021, the PSC of DC approved the US$20 million base rate case recommended in the settlement agreement. The new rates will become effective on April 1, 2021.

On March 16, 2020, the Council of the District of Columbia (DC Council) passed legislation prohibiting the disconnection of electric and gas services for non-payment of fees during a public health emergency. The Mayor of the District of Columbia's public health emergency declaration and all related orders have been further extended to March 31, 2021, and the prohibition on disconnection is effective for 15 days following the end of the public health emergency. On April 15, 2020, the PSC of DC issued an order authorizing Washington Gas to establish a regulatory asset to capture and track the incremental costs related to COVID-19 that were prudently incurred beginning March 11, 2020.

Maryland Jurisdiction

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 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 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 rendered beginning October 15, 2019.

Following the National Transportation and Safety Board (NTSB) hearing that examined the August 10, 2016, explosion and fire at an apartment complex in Silver Spring, Maryland, on September 5, 2019, the PSC of MD ordered Washington Gas 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

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PSC of MD should not impose a civil penalty on Washington Gas (Show-Cause Order). Following several hearings throughout the course of 2019 and 2020, on December 18, 2020, the PSC of MD found that Washington Gas failed to file annual reports informing the PSC of MD of the status of Washington Gas' program and imposed a US$750,000 penalty on Washington Gas for reporting violations. The PSC of MD ruled that the NTSB probable cause finding constituted hearsay and could not be admitted into the record of the case and did not undertake its own inquiry into the source of the explosion. The PSC of MD did not make any safety-related findings in the case but did find that Washington Gas made an enforceable regulatory commitment to replace all mercury regulators. The US$750,000 penalty was paid in January 2021 and Washington Gas believes that there is no additional liability as a result of the ruling from the PSC of MD. In its December 18, 2020 order, the PSC of MD also found that Washington Gas’s proposed implementation plan to replace all remaining mercury regulators within five years of completing an mercury regulator survey adequately addresses the need to replace all remaining mercury regulators in Maryland, and is in the public interest. The costs of the proposed implementation program are not yet known, and the recovery of these costs must be deferred until a future rate case.

On March 16, 2020, the Governor of Maryland issued an Executive Order which ordered regulated utilities to cease disconnections and billing of late fees for residential customers through May 1, 2020, which was subsequently amended to extend the order through August 31, 2020. On September 22, 2020, the PSC of MD took action that had the effect of extending the moratorium on service disconnections through November 15, 2020. Due to the winter moratorium on disconnections (November 1 to March 31), this has the effect of delaying residential terminations until April 1, 2021. On April 9, 2020, the PSC of MD issued an order and authorized each utility company to establish a regulatory asset to record the effects of incremental collection and other costs related to COVID-19 prudently incurred beginning on March 16, 2020. On August 27 and 28, 2020, the PSC of MD held Public Conference (PC) 53 to review the impacts of the Executive Order on utilities and the services they provide. On August 31, 2020, the PSC of MD issued an order directing that: (1) Utilities may not engage in service terminations and/or charge late fees until October 1, 2020 and any notices of termination for residential accounts sent before October 1, 2020 are invalid; (2) a Public Service Company must give notice of at least 45 days before terminating service on a residential account; (3) structured payment plans offered by Public Service Companies to residential customers in arrears or unable to pay must allow a minimum of 12 months to repay, with that period extending to 24 months for customers certified as low income; (4) Public Service Companies are prohibited from collecting or requiring down payments or deposits as a condition of beginning a payment plan by any residential customer; and (5) Public Service Companies are prohibited from refusing to negotiate or denying a payment plan to a residential customer receiving service because the customer failed to meet the terms and conditions of an alternate payment plan during the past 18 months. As requested by the PSC of MD, investor-owned utilities in Maryland filed a joint proposed Arrearage Management Program (AMP) plan on October 7, 2020, which was followed by a legislative style hearing in November 2020. On December 21, 2020, the PSC of MD rejected the proposed AMP plan. It will continue to monitor the customer arrearage data provided by utilities, and may revisit this issue in the future.

On August 28, 2020, Washington Gas filed an application with the PSC of MD to increase its base rates by approximately US$28 million, including approximately US$6 million currently collected through the Strategic Infrastructure Development Enhancement Plan (STRIDE) surcharges for system upgrades. The proposed rates reflect a 10.45 percent return on equity and a 7.73 percent return on an average rate base. On December 8, 2020, Washington Gas filed rebuttal testimony with a revised revenue requirement of approximately US$27 million. On February 12, 2021, the PULJ issued a Proposed Order in the Case and an ERRATA filing correcting of the Proposed Order on February 19, 2021. The Proposed Order, as corrected, authorizes Washington Gas increase its Maryland natural gas distribution rates by approximately US$13 million (including US$5 million for the STRIDE surcharge), reflecting a return of equity of 9.70 percent. Appeals are due February 26, 2021 with an order following. Washington Gas expects new rates to be implemented in late March of 2021.

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

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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.

On March 16, 2020, the State Corporation Commission of Virginia (SCC of VA) issued an order which prohibited disconnections of electricity, gas, water, and sewer utility services during the coronavirus public health emergency, and established certain consumer protection measures. While the SCC of VA order was extended, the disconnection order, but not the consumer protections expired on October 5, 2020. However, following the expiration of the disconnection order, on October 16, 2020, the Virginia General assembly approved legislation that would extend the disconnection prohibition for residential customers for nonpayment of bills or fees until the Governor determines the prohibition does not need to remain in place or until at least 60 days after the state of emergency declared on March 12, 2020 ends, whichever is sooner. The legislation also codified the consumer protection plans, requiring utilities to offer customers in arrears fee-free repayment plans without deposit or eligibility requirements. The legislation became effective in November 2020. On April 29, 2020, the SCC of VA issued an order approving a request from Washington Gas and other Virginia utilities to create a regulatory asset to record incremental prudently incurred costs and suspended late payment fees attributable to the COVID-19 pandemic. The October 16, 2020 legislation approved by the general assembly established certain reporting requirements for utilities to report bad debt information and provides utilities with certain exemptions from such requirements based on a utilities' particular facts and circumstances. On December 8, 2020, Washington Gas was awarded $US7.7 million under the Virginia CARES Relief Funding Award, to use for customer arrearages. Virginia customers need to meet the criteria established by the program to get the funds. Any unused funds will be returned to the SCC of VA by December 10, 2021.

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, 2020, approximately US$12 million of these merger commitments have been expensed but not paid. In addition, there are certain additional regulatory commitments which were and will be expensed as the costs are incurred, 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 US$8 million for leak mitigation, which has been paid as of December 31, 2020.

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 the 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

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ownership interest in CINGSA, a regulated natural gas storage utility in Alaska. The gas utility business accounts forapproximately 99 percentof SEMCO Energy’s 2020 consolidated revenues. The gas utility business purchases, transports, distributes, stores 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 approximately313,000regulated customers located in both southern Michigan and Michigan’s Upper Peninsula, approximately92 percentof 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 approximately1 percentannually during the past three years (with an increase of 1 percent in 2020). 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:

	2020	2019
Deliveries: (MDth)
Residential	24,973	26,841
Commercial	14,072	15,976
Transport	21,422	22,712
Gas Customer Choice (1)	3,219	3,719
Total deliveries	63,686	69,248
	2020	2019
Customers at Year End (2):
Residential	265,168	262,598
Commercial	24,113	23,926
Transport	255	249
Gas Customer Choice (1)	22,988	22,758
Total customers	312,524	309,531

(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.

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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 captured 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 included 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 were 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.

On April 15, 2020, the MPSC issued an order for all utilities which allows for regulatory asset accounting to capture bad debts in excess of what is in approved rates. Incremental cost recovery was not addressed in the order; however, utilities filed comments and reply on April 30, 2020 and May 13, 2020, respectively, on what extraordinary costs, costs savings, and incremental revenues related to COVID-19 should be considered by the MPSC and how those costs should be tracked. In addition, the order included a list of additional customer protection requirements. On July 23, 2020, the MPSC issued an order asking that any rate-regulated utility seeking recovery of COVID-19 related expenses beyond uncollectible expenses make an informational filing with the MPSC no later than November 2, 2020. SEMCO Gas did not establish a regulatory asset for bad debts since the bad debt expense is not expected to exceed the level approved in the last rate case proceeding. Furthermore, SEMCO Gas determined that the benefit would be de minimis to proceed with filing for the recovery for the incremental COVID-19 costs considering the legal fees associated with completing such a regulatory filing.

ENSTAR

In Alaska, ENSTAR distributes natural gas to approximately 149,000 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 2020). While there may occasionally be variations in this pattern,

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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 444 miles of gas transmission pipelines and 3,181 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 or intrastate pipelines and thus does not have access to natural gas supplies elsewhere in Alaska, Canada, or the lower 48 states. As a result, ENSTAR must procure its natural gas supplies under gas supply agreements from producers in and near the Cook Inlet area. Natural gas production in Cook Inlet has decreased significantly in recent years as has the amount of deliverability available from Cook Inlet producers. The majority of ENSTAR’s gas supply and deliverability needs are provided by long-term contracts with Cook Inlet producers into 2033.

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:

	2020	2019
Deliveries: (Mmcf)
Residential	20,738	16,308
Commercial	13,887	13,367
Transport	22,046	24,473
Total deliveries	56,671	54,148
	2020	2019
Customers at Year End:
Residential	135,782	134,423
Commercial	13,096	13,017
Transport	13	23
Total customers	148,891	147,463

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 4, 2020, ENSTAR filed a motion requesting relief from the obligation to file a rate

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case on June 1, 2021 based on a 2020 test year, requesting that filing deadline be moved to June 1, 2022 based on a 2021 test year. Three ENSTAR customers filed joinders in the motion and the Attorney General filed a non-opposition. The RCA issued an order on December 15 extending the filing deadline of the next ENSTAR rate case to June 1, 2022 based on a 2021 test year.

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.On October 20, 2020, the RCA approved creation of a regulatory asset in the amount of approximately US$1 million, to be amortized and recovered through rates over a period of time to be determined at ENSTAR's next rate case.

On April 10, 2020, the Governor of Alaska signed Senate Bill 241, which allows certificated utilities to record a regulatory asset for extraordinary costs and uncollectible residential utility bills that result from the COVID-19 public health disaster emergency declared by the governor on March 11, 2020. The determination as to whether an extraordinary expense resulted from the COVID-19 emergency is subject to approval by the RCA before recovery occurs through future rates. In response to Senate Bill 241, on April 15, 2020, the RCA opened an information docket to gather information including how utilities are dealing with COVID-19 and its effects. It will also discuss specific sections of Senate Bill 241 regarding deadlines for Commission actions and regulatory assets in a later public meeting.

CINGSA

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

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

Material Regulatory Developments and Approvals

In 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 RCA denied the petition on November 4, 2019. CINGSA filed an appeal with the Superior Court challenging one decision in the rate order. CINGSA filed its Brief and Reply Brief in June and November 2020, respectively. This matter is currently ongoing.

On March 2, 2020, CINGSA filed a formula rate methodology (FRM) proposal as required by the RCA in the August 2019 CINGSA rate case decision. CINGSA submitted its direct testimonies in August 2020 and other parties filed their responsive testimonies in November 2020. CINGSA filed its reply testimony on January 15, 2021. On February 11, 2021, the RCA extended the hearing date from February 16 to March 1, 2021, and the statutory timeline for issuance of a final order until June 9, 2021.

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Retail Energy Marketing

AltaGas' retail energy marketing business consists of the operations of WGL Energy Services, which sells natural gas and electricity directly to residential, commercial, and industrial customers located in Maryland, Virginia, Delaware, Pennsylvania, Ohio, and the District of Columbia.

WGL Energy Services has a secured supply arrangement with Shell Energy North America (US), L.P. 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.

Natural Gas

As of December 31, 2020, WGL Energy Services served approximately 97,200 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.

Electricity

As of December 31, 2020, WGL Energy Services served approximately 96,800 residential, commercial, and industrial electricity customer accounts located in Maryland, Delaware, Pennsylvania, Ohio, and the District of Columbia. WGL Energy Services does not own or operate any other electric generation, transmission, or distribution assets.

Competition

WGL Energy Services competes with wholesale energy suppliers, 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.

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.

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.

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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.

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 by the DOEE. The property was subject to a July 12, 2019 Administrative Order from the DOEE. That Administrative Order was withdrawn, and Washington Gas entered into a negotiated Administrative Order on Consent with the DOEE that was effective on March 11, 2020. Under the terms of the Administrative Order on Consent, Washington Gas plans to submit a Remedial Investigative Report on February 26, 2021.

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 issued an Interim Record of Decision for remediation of "Early Action Areas" (that do not include the East Station property) in the Anacostia River on 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

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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 2035. 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, 2020, 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.

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 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.

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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 – Corporate/Other Segment – Environmental Considerations Impacting the Corporate/Other Segment".

MIDSTREAM BUSINESS

AltaGas’ Midstream business contributed revenue of $1.6 billion for the year ended December 31, 2020 (2019 - $1.3 billion), representing approximately 30 percent (2019 – 24 percent) of AltaGas’ total revenue before Corporate/Other segment and intersegment eliminations.

Midstream Business

The Midstream business is comprised of global export assets and strategically located processing, fractionation, and logistics infrastructure, as well as hydrocarbon storage in North America that connects North American producers from wellhead to offshore global export markets and North American consumers. The Midstream business also includes integrated hydrocarbons handling services that are comprised of storage, rail logistics, pipeline, transportation services, and wellsite fluids; natural gas and NGL marketing initiatives that support the Midstream infrastructure; and three gas-fired cogeneration plants. In addition, AltaGas' Midstream business is comprised of contracted underground natural gas and LPG storage and a pipeline investment.

Upon close of the Petrogas Acquisition on December 15, 2020, the Midstream business includes AltaGas' controlling interest in Petrogas, an integrated midstream and logistics company operating in North America. Petrogas operates a large scale fully-integrated NGL and crude oil infrastructure business providing sourcing, storage, marketing, and transportation services to upstream and downstream energy companies operating throughout the United States and Canada, and providing waterborne LPG export capability to Asian markets from its Ferndale, Washington terminal. The terminal is capable of loading VLGCs, has 800,000 Bbls of on-site LPG storage capacity, and currently can flow approximately 50,000 Bbls/d. The terminal is pipeline connected to two regional refineries, providing additional supply, sales, and fee-for-service opportunities.

Global Exports

AltaGas' global export assets are focused on providing North American producers global market access and incremental value for 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 with LPG export capacity in excess of 130,000Bbls/d to Asian markets.

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 in May 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 ended the year with physical volumes in December of approximately 54,000 Bbls/d.

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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 of propane. AltaGas expects to increase throughput from RIPET as it builds on the operational capabilities and global counterparty networks for RIPET. On August 21, 2020, the Canada Energy Regulator granted AltaGas an additional 25 year license to export up to 46,000 Bbls/d of propane to North American and global markets from RIPET, bringing the aggregate propane export capacity under 25 year export licenses to 92,000 Bbls/d. In December 2020, the Minister of Natural Resources approved the additional license.

Ferndale LPG Export Facility

Located approximately 100 miles north of Seattle, the Ferndale export terminal represents a strategic outlet point for North American LPG volumes. Like RIPET, as it is competitively situated to serve the high-demand Far East market with shorter average shipping times and competitive arbitrage vs. the U.S. Gulf Coast.

Terminal demand is supported through various long-term purchase agreements with Canadian and American suppliers, primarily from key Northern British Columbia & Alberta gathering facilities and American producing regions, primarily the Bakken. Petrogas also maintains service agreements with numerous Tier 1 rail providers in order to leverage existing railway networks to take advantage of competitively priced product across North America. The terminal is also pipeline connected to two regional refineries, providing additional supply, sales and fee-for-service opportunities for the terminal. The terminal is capable of handling up to 50,000 Bbls/d of throughput capacity, with 800,000 Bbls of on-site storage capacity and rail siding capacity for up to 40 railcars.

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 2.4 Bcf/d, of which approximately 15 percent is capable of processing sour gas. 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.

AltaGas' significant processing facilities are as follows:

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2020 Licensed Capacity (Net)
Facility	Location	Interest (%)		Operated / Non-Operated	Licensed Capacity Gas Processing - Net (Mmcf/d)
Townsend	North of Fort St. John, BC	100	%	Operated	550
Gordondale	Bonanza, AB	100	%	Operated	150
Blair Creek	North of Fort St. John, BC	100	%	Operated	120
Aitken Creek (1) (2)	Aitken, BC	50	%	Non-Operated	105
JEEP	Joffre, AB	100	%	Operated	250
EEEP	Edmonton, AB	100	%	Operated	390
Empress Pembina (PEEP)	Empress, AB	11	%	Non-Operated	135
Harmattan	Sundre, AB	100	%	Operated	490
Younger	Taylor, BC	28	%	Non-Operated	213
Total					2,403

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

(2)Includes Aitken Creek North and Nig Creek.

Townsend Complex

The Townsend facility, which is wholly owned by AltaGas, is a 550 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 Logistics" section below.

A 25 km gas gathering line connects the Blair Creek field gathering area to the Townsend facility.

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. In the second quarter of 2020, Townsend 2B and a gas gathering pipeline that connects upstream fields to AltaGas facilities were commissioned, which added 198 Mmcf/d C3+ deep cut gas processing capacity at the Townsend Complex. The expanded facility provided Kelt with firm processing of 75 Mmcf/d of raw gas under an initial 10 year take-or-pay agreement. In the third quarter of 2020, ConocoPhillips acquired oil and gas assets in the Inga/Fireweed/Stoddard division in the Montney area from Kelt. All operating agreements of AltaGas remain in effect.

Gordondale

AltaGas owns 100 percent of the Gordondale facility which has licensed capacity of 150 Mmcf/d for processing sour 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. The plant also has peaking power plant generators which serve as emergency back-up generation for the plant as well as power supply to the grid when demand is high or supply is low.

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.

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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. Phase 1 of Nig Creek GP2B will increase inlet capacity by 55 Mmcf/d (28 Mmcf/d net). Phase 1 of Nig Creek GP2B is expected to be commissioned in the third quarter of 2021. The Aitken 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 contract with Nova Chemicals. AltaGas delivers its NGL production to the 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 30,500 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.

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 Logistics" 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 approximately70 producers under contracts with a variety of commercial arrangements and terms. Approximately 17 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

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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.

AltaGas has 45 MW of cogeneration capacity in Alberta through three co-generation facilities, each of which can generate 15 MW of power. The co-generation 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. Excess electricity from the co-generation units are delivered to the Alberta power market.

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 Logistics" section below). Younger has licensed 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 Logistics

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 logistics 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' logistics 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. Following the acquisition of Petrogas, the liquids handling infrastructure also includes Petrogas' core business lines including marketing and distribution, terminals, wellsite fluids and fuels, and trucking and liquids handling.

In the NEBC area, a network of NGL pipelines connects upstream gas plant producers to the AltaGas North Pine facility. The NEBC NGL pipelines consist of three liquids egress lines, with the third line commissioned in the third quarter of 2020, connecting the Townsend facility to the Townsend truck terminal on the Alaska Highway (30 km) and AltaGas' North Pine facility (70 km). In addition, NGL and spec propane lines that connect the Townsend complex in the North, to the Aitken Creek facilities through a 60 km NGL pipeline (Aitken Connector), Storm Resources Nig plant through a lateral, and to the Tourmaline Gundy facility in the West, through a 15 km spec propane line were all commissioned in the first half of 2020.AltaGas' logistics infrastructure also 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.

AltaGas' significant fractionation facilities are as follows:

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2020 Licensed Capacity (Net)
Facility	Location	Interest (%)		Operated / Non-Operated	Licensed Capacity NGL Fractionation - Net (Bbls/d)
Harmattan	Sundre, AB	100	%	Operated	35,000
Younger	Taylor, BC	50	%	Non-Operated	9,750
North Pine	Fort St. John, BC	100	%	Operated	20,000
Total					64,750

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.

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 in 2017. The first train of the North Pine facility is capable of processing up to 10,000 Bbls/d of NGL mix. The second train, commissioned in the first quarter of 2020, provides 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 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.

Aitken

AltaGas and Black Swan have entered into long-term processing, transportation and marketing agreements including the AltaGas liquids handling infrastructure at the Townsend complex and North Pine facility. In March 2020, the Aitken liquids pipeline was placed in service, and connected to the Townsend North Liquids pipelines to transport NGL volumes from the Aitken Creek and Nig Creek facilities to the Townsend Complex.

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Terminals and Storage Business

With the acquisition of Petrogas, AltaGas' Midstream business now includes Petrogas' terminals business, which provides support to its marketing and distribution business by providing the ability to source, transport, process, store, and deliver products through strategically located fixed assets throughout North America. In addition, the terminals business provides various terminalling services to third party customers through take-or-pay or fee-for-service agreements which provide earnings stability through volatile commodity price environments.

The terminals business consists of strategically located crude oil and NGL assets which provide storage, blending, rail and truck logistical support and waterborne LPG export capabilities.

AltaGas' significant terminals are as follows:

2020 Licensed Capacity
Facility	Location	Interest (%)		Operated / Non-Operated	Operational Capacity LPG/NGL/Crude - Gross (Bbls/d)	Storage Capacity - Gross (Bbls)
Griffith LPG Terminal (1)	Griffith, IN	74	%	Operated	12,000	700,000
Fort Sask. NGL Terminal (1)	Fort Saskatchewan, AB	74	%	Operated	25,000	180,000
Sarnia Crude Oil JV (1)	Sarnia, ON	37	%	Non-Operated	110,000	2,100,000
Strathcona Storage JV (1)	Fort Saskatchewan, AB	30	%	Non-Operated	—	2,516,000
Petrogas Blending Terminals (1)	Various	74	%	Operated	12,900	20,000
Total					159,900	5,516,000

(1)Acquired as part of the Petrogas Acquisition on December 15, 2020.

2020 Licensed Capacity
Facility	Location	Interest (%)		Operated / Non-Operated	Storage Capacity - Gross (Bcf)
Sarnia Gas Storage	Sarnia, ON	50	%	Non-Operated	5.3

Griffith LPG Terminal

100 percent owned and operated by Petrogas, the Griffith LPG terminal directly supports domestic propane and butane marketing efforts. Equipped with inbound and outbound truck and rail infrastructure, the terminal is capable of handling approximately 12,000 Bbls/d, and can be easily expandable to 30,000 Bbls/d. Underground caverns provide 700,000 barrels of storage and rail siding capacity exists for up to 220 railcars. Storage services are provided on a fee for service basis including to pipeline connected refiners.

Fort Saskatchewan NGL Terminal

100 percent owned and operated by Petrogas, this greenfield facility was built by Petrogas and provides multiproduct storage and handling support to the marketing business while also generating fee-for-service revenues through third party agreements.

Pipeline connected to a regional fractionation facility and to the Strathcona Storage Caverns through a 10 km Petrogas constructed and owned pipeline, the Fort Saskatchewan facility is equipped with truck and rail loading and offloading infrastructure, providing 25,000 Bbls/d of throughput capacity. The terminal is unit-train compatible, with rail siding capacity for up to 265 railcars and on-site tank storage for 180,000 Bbls. The terminal is an important staging area for Ferndale destined product, providing key export exposure optionality to regional producers.

Sarnia Storage and Crude Oil Terminal JV

The Sarnia storage and crude oil terminal is a joint venture with Nova Chemicals, providing Petrogas with crude oil storage and crude-to-rail infrastructure accessibility. Situated in southern Ontario, this terminal provides the ability to

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service crude oil demand needs to eastern refiners and end users through regional rail networks and Enbridge pipeline infrastructure. The joint venture partner supplies and manages the terminal assets, while Petrogas manages the marketing and commercial agreements for the terminal. The right to access the terminal assets under the joint venture arrangement have been recorded as a lease by Petrogas. This terminal provides up to 2.1 million Bbls of crude oil and refined product storage capacity with outbound throughput supported by 10,000 Bbls/d of rail loading capacity. The terminal generates revenue through storage contracts and storage tank leases, rail loading, and term commitments for crude oil supply. The joint venture agreement expires in 2028 and can be renewed at the discretion of the parties.

Strathcona Storage JV

The Strathcona Storage facility is a joint venture with ATCO Energy Solutions Ltd.. Petrogas holds a 40 percent working interest in the facility which is located near Fort Saskatchewan. The facility is strategically positioned to help satisfy storage needs from increased liquids rich production from the Duvernay and Montney shale basins, while also supporting petrochemical requirements in the Edmonton area. The terminal currently has four underground storage salt caverns in service, with a fifth cavern under development. Each cavern provides approximately 629,000 Bbls of storage capacity.

Crude Blending Terminals

100 percent owned and operated by Petrogas, the crude blending terminals consist of five blending terminals located throughout Alberta and Southern Saskatchewan. These terminals blend heavier grade crude oil to meet pipeline specification requirements and are designed to operate at an average capacity of 15,300 Bbls/d. Feedstock is sourced through trucking infrastructure and pipeline connected batteries, with offloading capability through connections to regional pipelines.

Other

Petrogas maintains an assortment of ancillary owned and leased storage assets across North America to support marketing and distribution and terminal efforts. Locations include the Yahk BC propane truck terminal, Scranton propane terminal, Guernsey and Edmonton leased crude tanks and various other strategic leased NGL storage at key hubs.

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.

Trucking and Wellsite Fluids

Trucking Business

With the acquisition of a controlling interest in Petrogas, AltaGas' Midstream business now includes Petrogas' three primary trucking entities, which provide transportation related services within the Western Canadian Sedimentary Basin and the United States Pacific Northwest by hauling frac fluid, produced water, crude oil and NGLs between producers, terminals, customers and end users. Trucking operations are instrumental in connecting suppliers and customers to either the Petrogas infrastructure assets, third party terminals, or long-haul transportation to domestic wholesale markets.

In addition to first party volumes, the trucking business maintains various agreements with regional oil and gas production companies for hauling services from remote drilling locations. Agreements could include master service agreements, evergreen term contracts or spot loadings. Third party hauling rates are determined by receipt location, delivery point and length of haul.

Wellsite Fluids and Fuels

Enerchem International Inc., a wholly owned subsidiary of Petrogas, is a Canadian corporation which focuses on the production of drilling and wellsite fluids, and consumer fuels. Through the fractionation of crude oil feedstock, Enerchem produces and distributes proprietary hydrocarbon fluids for fracturing and drilling of oil and gas wells to improve productivity and to resolve oilfield production challenges for downstream producers.

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Enerchem has branded and trademarked various produced products, including Fracsol®, Drillsol®, Drillsol Plus®, Envirosol®, Xysol®, Waxsol®, Unisol® and EZsol®. These products provide solutions for drilling efficiency and well-bore integrity, hydraulic fracturing and solvents for wellsite maintenance, well-bore clean ups and heavy oil dilution.

In addition to its proprietary fluids, Enerchem also produces various consumer fuel products. This segment provides diversification to the Enerchem portfolio and is not tied to drilling cycles. Product types include furnace fuel, Jet-A, Jet-B, and various diesel and marine grade fuels. Enerchem is the only producer of Jet-B in Canada.

Enerchem operates two primary facilities located in Sundre and Slave Lake Alberta, which are capable of processing over 1.5 million Bbls of finished products per year. These plants are supported by various ancillary storage and distribution facilities located across the Western Canadian Sedimentary Basin providing over 150,000 Bbls of storage capacity, strategically placed within the vicinity of active drilling regions.

Other Liquids Handling Services

To support LPG and NGL handling, AltaGas manages a rail logistics network consisting of approximately4,600rail 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.

Petrogas' marketing business is focused on the purchase, sale, exchange, and distribution of NGLs and crude oil, primarily in proximity to its strategically owned and leased asset base. By leveraging Petrogas' fully integrated infrastructure base and extensive logistical capabilities, the marketing team is able to source competitively priced supply at the key hubs and across various hydrocarbon basins in order to capture arbitrage opportunities derived through regional pricing differentials. Marketing efforts are driven by two primary focuses: 1) domestic NGL and crude oil wholesale, and 2) LPG waterborne exports. Additionally, this business provides operational support to the Ferndale export terminal by providing product supply and export sales agreement negotiation services. Petrogas supports its distribution efforts by maintaining an extensive leased rail fleet. Leases are established on a staggered maturity schedule with multiple lessors, to ensure railcar integrity and up-to-date DOT classification and all leases are on a full-service basis.

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. On August 25, 2020, Mountain Valley Pipeline, LLC requested a two-year extension to complete the pipeline to October 30, 2022. On November 9, 2020, the 4th U.S. Circuit of Appeals granted a request from certain environmental groups and issued a stay pending litigation over the U.S. Army Corps of Engineers' verification of water crossings for the project, under a general permit known as Nationwide Permit 12. As a result, the targeted in-service date is now expected in late 2021. As of

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December 31, 2020, approximately 92 percent of the project is complete, which includes construction of all original interconnects and compressor stations. Despite the 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. Construction is expected to begin in the third quarter of 2021, despite the North Carolina Department of Environmental Quality's decision to deny MVP Southgate's request for state certification under the Clean Water Act Section 401. The decision is expected to be appealed. Expenditures to date relate to land surveys, land acquisition, and obtaining permits and regulatory approvals.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 the second half of 2022 due to ongoing legal and regulatory challenges.

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.

Through its integrated infrastructure value chain, AltaGas is able to connect North American producers from the wellhead to the global LPG markets via RIPET and Ferndale.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 130,000Bbls/d capacity, account for approximately 37 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 2020, 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 NGLs.

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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. Global export volumes are driven by production at AltaGas' Midstream facilities, LPG supply from the WCSB, and various long-term purchase agreements with Canadian and American suppliers.

Global Exports

Average global exports utilization at RIPET increased to 63 percent in 2020 from 57 percent in 2019, mainly due to higher volumes sold on the spot market and a semi-term contract effective September 2019. Ferndale utilization for the period from acquisition on December 15, 2020 to December 31, 2020 was approximately 68 percent.

Gas Processing

Average processing facility utilization of core assets decreased to 57 percent in 2020 from 62 percent in 2019 primarily due to reduced producer upstream activities, outages at AltaGas and producer facilities, and a planned turnaround at Younger, resulting in lower processed volumes at the extraction facilities, partially offset by full year operations at the Nig Creek facility and in-service of the Townsend 2B expansion in the second quarter of 2020.

Fractionation

Average fractionation utilization of 38 percent in 2020 is higher than 31 percent utilization in 2019 due to the North Pine expansion project being placed in-service in the first quarter of 2020 and additional liquids volumes from the NEBC facilities including the Townsend Deep Cut facility, partially offset by lower volumes at Younger due to a scheduled turnaround, and lower trucked-in volumes at Harmattan.

Significant Operating Areas and Customers

Global Exports

As the only 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 46 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.

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Midstream Contractual Arrangements

Global Exports

RIPET and Ferndale annual capacity is currently managed through a combination of merchant supply agreements and tolling arrangements for both propane and butane. AltaGas' plans are to have the majority of RIPET and Ferndale's capacity underpinned by tolling arrangements with focus on creating an integrated value chain for AltaGas' customers and suppliers in the WCSB from the wellhead to the global export markets.

In 2021, AltaGas has in place multi-year agreements for the purchase of approximately 33 percent of the propane expected to be shipped from RIPET each year. RIPET propane volumes are exported under term, semi-term, strip or spot contracts. Approximately 48 percent of the export volumes are under term and semi-term contracts.

AltaGas has in place multi-year agreements, for propane and butane offtake volumes from Pacific North West refineries and WCSB producers, for the purchase of approximately 27 percent of the product expected to be shipped from Ferndale each year. Ferndale propane and butane volumes are exported under term, semi-term, and spot contracts through third party marketing arrangements. In 2021, approximately 61 percent of the export volumes are under term and semi-term contracts.

Processing and Fractionation

AltaGas gathers, processes and fractionates natural gas and NGL under contracts with natural gas producers. There are approximately 115 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, 2020 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

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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.

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 limit of 4g/kWh for 50 percent of the total rated brake power of AltaGas' regulated engines, with the goal of achieving a NOx limit of 4g/kWh for all pre-existing engines by 2026.

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, 2020, 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.

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The carbon pricing schemes in both Alberta and British Columbia have been granted equivalency by the federal government and meet the requirements to the federal benchmark.

The federal 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 heard arguments regarding the federal carbon levy in September 2020, no ruling has been made to date.

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 was reduced from 50,000 tonnes CO2e to 10,000 tonnes CO2e.

As of June 1, 2020, ten facilities within the Midstream segment reported to the GHGRP as a result of the lower reporting threshold.

Alberta

TIER

On January 1, 2020 the TIER replaced the CCIR. TIER automatically applies 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 compliance obligation 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. Both AltaGas' Harmattan and Gordondale facilities produce 100,000 tonnes or more of emission per year and will be regulated under the TIER program.

The Government of Canada applied 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 was 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. AltaGas facilities under 100,000 tonnes of emissions in Alberta have voluntarily opted in to the TIER program as an aggregate facility. Each opted in facility will be required to meet the compliance requirements under the TIER program, but will be exempt from paying the federal fuel charge under the GGPPA.

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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, RIPET, and other assets in B.C. are subject to the reporting obligations and as at December 31, 2020, are in compliance with the Greenhouse Gas Emission Reporting Regulation.

Methane Reduction

The amended Oil and Gas Commission Drilling and Production Regulation in B.C took effect on 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.

Carbon Tax Act

B.C.’s carbon tax is currently set at $40 per tonne of CO2e emissions. The carbon tax in B.C was set to increase to $45 per tonnes of CO2e emissions, but in response to COVID-19, B.C.’s carbon tax rate will remain at its current level of $40 per tCO2e until further notice. 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.

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Effective Date	BC Carbon Tax Rate ($/tonne CO2e)
Prior to 2018	$30
April 1, 2018	$35
April 1, 2019	$40
April 1, 2020	$40 (Held at $40 due to COVID-19)

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 2020 provincial budget provided an additional $419 million in funding for Clean BC, bringing the total to approximately 1.3 billion. The funds will continue to be used to provide electric vehicle rebates, incentives for making homes and businesses more energy efficient, and an enhanced climate action tax credit.

Washington State

Department of Ecology Reporting of Emissions of Greenhouse Gases

The Department of Ecology has established Greenhouse Gas Reporting requirements for any facility that exceeds the threshold of 10,000 metrics tonnes of CO2e or more per calendar year in total GHG emissions from applicable source categories. If the reporting threshold is exceeded, an annual GHG report must be filed with ecology annually.

The Ferndale LPG Export facility is subject to this reporting obligation and as at December 31, 2020, is in compliance with the reporting requirements.

U.S. Federal Air and GHG Regulations

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 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 located in the U.S. operate under and comply with requirements set forth by the U.S. GHGRP.

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CORPORATE/OTHER SEGMENT

The Corporate/Other business consists of power assets and AltaGas' corporate activities, including general corporate investments 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, 2020, the revenue for the Corporate/Other business was $135 million excluding intersegment eliminations and risk management and trading activities (2019 – $201 million).

Power Assets

AltaGas' power assets are engaged in the generation and sale of capacity, electricity, ancillary services, and related products inCalifornia, and Colorado. After the sale of Pomona and Ripon in the third quarter of 2020, AltaGas has 582MW of installed power capacity from a combination of gas-fired 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.	2022
Distributed Generation	100	5	Various	Various regions in the U.S.	Various
TOTAL		582

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 an El Paso Gas Company natural gas pipeline for its primary supply and a Southern California Gas Company pipeline as a secondary 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. The agreement became effective on August 1, 2020 and runs through December 31, 2023.

Competition

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.

Environmental Considerations Impacting the Corporate/Other Segment

AltaGas' power assets included in the Corporate/Other segment are 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.

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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, 2020, 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, 2020, AltaGas’ Blythe facility in California was 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 depletion 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 Blythe.

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, 2020, AltaGas had 279,494,299 outstanding Common Shares, 6,746,679 outstanding Series A Shares, 1,253,321 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, and 12,000,000 outstanding Series K Shares.

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On December 31, 2020, AltaGas redeemed all its 8,000,000 issued and outstanding Series I Shares for a redemption price equal to $25.00 per Series I Share, in accordance with the terms of the Cumulative Redeemable 5-Year Minimum Rate Reset Preferred Shares, Series I.

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

Common Shares

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

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Preferred Shares (1)

	Current Yield		Annual dividend per share (2)	Redemption price per share	Redemption and conversion option date (3) (4)	Right to convert into (4)
Series A Shares (5)	3.06	%	$0.765	$25	September 30, 2025	Series B
Series B Shares (6) (7)	Floating		Floating	$25	September 30, 2025	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)	4.24	%	$1.0605	$25	September 30, 2024	Series H
Series H Shares (6) (7)	Floating		Floating	$25	September 30, 2024	Series G
Series K Shares (9)	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 to 8,000,000 of each of Series D Shares, Series F Shares, and up to 12,000,000 of Series L Shares, subject to certain conditions, upon conversion by the holders of the applicable currently issued and outstanding series of preferred shares noted opposite such series in the table on the applicable conversion option date. If issued upon the conversion of the applicable series of preferred shares, Series F Shares, and Series L Shares are also redeemable for $25.50, and Series D Shares are redeemable for US$25.50 on any date after the applicable conversion option date, plus all accrued but unpaid dividends to, but excluding, the date fixed for redemption.

(2)The holders of Series A Shares, Series C Shares, Series E Shares, Series G Shares, Series H 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, 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 plus 2.66 percent (Series A Shares), 3.17 percent (Series E Shares), and 3.06 percent (Series G Shares).

(6)Holders of Series B Shares 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 plus 2.66 percent (Series B Shares) and 3.06 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, 2020, the floating quarterly dividend rate is$0.17069per share for Series B Shares and$0.195349per share for Series H Shares for the period starting December 31, 2020 to, but excluding, March 31, 2021.

(7)Series B Shares can be redeemed for $25.50 per share on any date after September 30, 2015 that is not a Series B conversion date, plus all accrued and unpaid dividends to, but excluding, the date fixed for redemption. Series H Shares can be redeemed for $25.50 per 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 plus 3.58 percent.

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

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

The Board of Directors may divide any unissued Preferred Shares into series and fix the number of shares in each series and the designation, rights, privileges, restrictions, and conditions thereof. The Preferred Shares of each series will rank on parity with Preferred Shares of every other series with respect to accumulated dividends and return of capital and the holders of Preferred Shares will rank prior to the holders of Common Shares and any other shares of AltaGas ranking junior to the Preferred Shares with respect to the payment of dividends and the distribution of assets in the event of liquidation, dissolution or winding-up of AltaGas, whether voluntary or involuntary.

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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, 2020 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 of AltaGas’ audited Consolidated Financial Statements as at and for the year ended December 31, 2020.

GENERAL

Employees

At December 31, 2020, there were 2,984 individuals employed by AltaGas.

	December 31, 2020
Utilities	2,236
Midstream	552
Corporate/Other	196
Total	2,984

Directors and Officers

As at February 19, 2021, the directors and executive officers of AltaGas Ltd., as a group, owned beneficially, directly or indirectly, or exercised control or direction over 1,923,274 of the outstanding Common Shares, or approximately 0.69 percent of the 279,533,433 Common Shares issued and outstanding.

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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 19, 2021, 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. Prior to this, she held corporate positions at Hudson's Bay Oil and Gas and the Bank of Nova Scotia.	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) Naples, Florida,USA 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
Jon-Al Duplantier(1)(4) Houston, Texas, USA Director	Mr. Duplantier retired from Parker Drilling Company in July 2020, where he held a number of executive roles since joining in 2009, most recently as President, Rental Tools and Well Services from April 2018. Prior thereto, he served as Senior Vice President, Chief Administrative Officer and General Counsel from April 2014 to March 2018.	February 2, 2021
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
Robert B. Hodgins (1) (5) Calgary, Alberta, Canada Director	Mr. Hodgins is a CA , CPA 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 also held the positions of Chief Financial Officer of Pengrowth Energy Trust, 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

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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 various positions, including Executive Vice President, Enterprise Risk and Corporate Services and Executive Vice President Corporate Services. Prior thereto, Ms. Johnston held various executive leadership positions with TransAlta and FortisAlberta.	July 25, 2018
Pentti O. Karkkainen (1) West Vancouver, B.C., Canada Chair of the Board	Mr. Karkkainen is the Chair of the Board. He was a co-founder and General Partner of KERN Partners from 2000 to 2014, and was the firm’s Senior Strategy Advisor from 2014 until 2015. Prior thereto, Mr. Karkkainen was the Managing Director and Head of Oil and Gas Equity Research at RBC Capital Markets.	July 25, 2018
Phillip R. Knoll (1)(2) Kelowna, B.C., Canada Director	Mr. Knoll is a Professional Engineer and has been the President of Knoll Energy Inc. since 2006. Mr. Knoll served as interim Co-CEO of AltaGas 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 Chair and Chief Executive Officer of WGL and 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) Moneta, Virginia, 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 currently serves as Chief Executive Officer of Tampa Electric Company, a regulated electric utility and a subsidiary of Emera Incorporated in Tampa, Florida, and is transitioning her role in connection with her planned retirement in mid-2021. She was President and Chief Executive Officer of Tampa Electric Company from December 2017 to February 2021. 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.

(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. 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.

(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. Duplantier was an officer of Parker Drilling Company (Parker) from 2009 until July 2020. Parker and certain of its U.S. subsidiaries (collectively, the Debtors) commenced voluntary Chapter 11 proceedings and filed a prearranged Joint Chapter 11 Plan of Reorganization under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern

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District of Texas, Houston Division. The Plan was subsequently amended and was confirmed by the Bankruptcy Court on March 7, 2019. The Plan became effective on March 26, 2019 and the Debtors emerged from the Chapter 11 Cases.

(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 19, 2021 are identified below:

Director	Audit Committee	Governance Committee	HRC Committee	EH&S Committee
Victoria A. Calvert		n	n
David W. Cornhill
Jon-Al Duplantier		n
Allan L. Edgeworth	n		Chair
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

Executive Officers

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

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Name of Officer, Municipality of Residence, and Position with AltaGas Ltd.	Principal Occupation During the Past Five Years
Randall L. Crawford Naples, Florida, USA President and Chief Executive Officer Director	President and 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.
Shaheen Amirali Calgary, Alberta, Canada Executive Vice President, Chief External Affairs and Sustainability Officer and Corporate Secretary	Executive Vice President, Chief External Affairs and Sustainability Officer and Corporate Secretary since October 2020. Prior thereto, Senior Vice President and Corporate Secretary from May 2019, Vice President and Corporate Secretary from October 2017, Associate General Counsel from Jan 2017 and Senior Corporate Counsel from 2007 to 2016.

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.

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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. In these roles, Mr. Edgeworth had direct financial oversight responsibilities. He has served on a number of public company audit committees.

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 CA, CPA 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. In these roles, she had financial oversight responsibilities and actively supervised financial officers. 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, a U.S. public company.

Ms. Tower currently serves as Chief Executive Officer of Tampa Electric Company, a regulated electric utility and a subsidiary of Emera Incorporated in Tampa, Florida, and is transitioning her role in connection with her planned retirement in mid-2021. She was President and Chief Executive Officer of Tampa Electric Company from December 2017 to February 2021. 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 2020 and 2019 were as follows:

Category of External Auditor Service Fee (1) ($ millions)	2020		2019
Audit fees	$	4.9	$	7.8
Audit-related fees (2)	1.2		0.8
Tax compliance fees (3)	0.1		0.3
All other fees (4)	0.7		0.4
Total	$	6.9	$	9.3

(1)Due to the timing of invoices received, $1.7 million of fees relating to 2019 were paid in 2020.

(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 2020 and 2019, the nature of the services provided included: review of prospectuses and security filings; research of accounting and audit-related issues; review of pro forma consolidated financial statements; specified audit procedures on RIPET; review of the change in accounting principle related to pensions; 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 2020 and 2019, the nature of the services provided was for tax consultations, 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, as well as any out-of-pocket costs incurred. During 2020 and 2019, 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 1, 2020 and will also be included in AltaGas’ management information circular for its 2021 annual meeting of the Shareholders.

COVID-19

As the COVID-19 pandemic continues, governments in the jurisdictions where AltaGas operates have maintained measures designed to contain the outbreak, including business closures and restrictions, travel limitations and border closings, quarantines, and restrictions on gatherings and events. The magnitude, outcome, and duration of the pandemic remains uncertain. As a result, it is not currently possible to accurately quantify the total potential impact of the pandemic on AltaGas’ operations or financial results.

AltaGas, with its subsidiaries, activated its pandemic response team to monitor developments related to COVID-19 and to ensure the Corporation was responding swiftly and appropriately. Continuity plans and preparedness measures have been implemented at each of AltaGas’ businesses, with safeguarding the well-being of its personnel as the primary concern. To date, AltaGas has been able to respond to the COVID-19 related challenges with minimal disruption to its operations and business.

AltaGas has identified the following as potential direct or indirect impacts to its business and operations from the pandemic:

▪Key employees and personnel: Widespread inability of AltaGas' workforce or that of the Corporation's contractors to perform their duties would have an adverse impact on AltaGas' ability to continue normal

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operations in the Utilities, Midstream and Corporate/Other segments. To date, AltaGas has not experienced unavailability of a significant portion of its personnel as a result of COVID-19 related concerns;

▪Return to work: As AltaGas reintegrates its personnel to its workplace, it may incur additional costs to adapt the workplace to meet applicable health and safety requirements. Shortages in personal protective equipment (PPE), the occurrence of additional waves of the virus, or delays in the availability or rollout of vaccines may require AltaGas to revise or delay such reintegration plans. To the extent that it is unable to effectively protect its workforce against the transmission of the virus, AltaGas may be forced to slow or reverse its reintegration efforts and could face allegations of liability;

▪IT infrastructure, privacy and cyber security: Increased volume and sophistication of targeted cyber-attacks have been seen since the declaration of the global pandemic. Pandemic-adjusted operations, such as work from home arrangements and remote access to the Corporation's systems, may pose heightened risk of cyber security and privacy breaches and may put additional stress on the Corporation's IT infrastructure. A failure of such infrastructure could severely limit AltaGas' ability to conduct ordinary operations. To date, AltaGas’ systems have functioned capably, and it has not experienced a material impact to its operations as a result of an IT infrastructure issue;

▪Adverse impacts on market fundamentals and access to capital: AltaGas has seen an impact from COVID-19 related factors in relation to lower margins in the Retail Energy Marketing business, cancellation of late fees and related charges along with the inability to disconnect customers, impacts to income from Petrogas due to lower commodity prices, and increased cost with regard to COVID-19 related costs to the business. The impact of these factors was not material to AltaGas' 2020 financial performance and is currently not expected to be material to the 2021 financial performance of AltaGas. While access to capital could be negatively impacted by the global impact of the virus, at this point, AltaGas anticipates that it has adequate access to capital to execute its 2021 business plans; and

▪Counterparty and supplier risk: AltaGas could face increased exposure that contract counterparties and suppliers could fail to meet their obligations to AltaGas. Such non-performance by a significant counterparty or supplier could adversely affect AltaGas' operations and financial results. To date, any cases of force majeure invoked by counterparties related to the AltaGas’ assets as a result of COVID-19 have not been material.

To the extent these risks materialize, the Corporation’s ability to carry out its business plans for 2021 may be adversely impacted.

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.

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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 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 light 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.

Integration of Petrogas

AltaGas acquired its controlling interest in Petrogas with the expectation that the acquisition will be accretive to certain financial metrics and result in other operational benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the acquisition of Petrogas is subject to a number of uncertainties, including whether the businesses, processes, and systems of Petrogas 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 Petrogas’ and AltaGas’ business practices and operations. This process may disrupt both AltaGas’ and Petrogas’ 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 the anticipated benefits or the incurrence of unanticipated expenses and liabilities could materially adversely affect AltaGas’ business, financial condition, operating results and prospects.

Operating Risk

AltaGas’ businesses are subject to the risks normally associated with the operation and development, and storage and transportation 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, 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.

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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 definitively predict the future course of regulations. Changes in the regulatory environment may be beyond AltaGas’ control and may significantly affect AltaGas' businesses, results of operations, and financial conditions. Pipelines and facilities can be subject to common carrier and common processor applications and to rate setting by the regulatory authorities in the event an agreement on fees or tariffs cannot be reached with producers. The export and import of energy is also subject to regulatory approvals. Power facilities are subject to regulatory approvals and regulatory changes in tariffs, market structure, and penalties. Washington Gas, SEMCO Gas, ENSTAR, and CINGSA operate in regulated marketplaces where regulatory approval is required 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.

Cyber Security, Information, and Control Systems

AltaGas’ business processes are increasingly reliant upon information systems and 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 is increasing, with strong evidence of the energy 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 or operational technology infrastructure, including, without limitation, cyber-attacks and cyber-terrorism, or other failures of AltaGas’ information technology and operational 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, financial, 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. If any of AltaGas' systems are damaged, fail to function properly, or otherwise become unavailable, AltaGas may incur substantial costs to repair or replace them.

AltaGas’ cybersecurity strategy focuses on identifying, detecting, and protecting information technology assets, and responding and recovering when an incident occurs, which includes, without limitation, continuous security event and incident management monitoring, ongoing cybersecurity training and awareness, conducting third-party vulnerability and penetration testing, and cyber incident response planning and testing. 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

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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.

AltaGas relies on third parties and managed service providers for various services. If these third parties undergo cyber-attacks, the services they provide AltaGas could be disrupted. The disruption could interfere with AltaGas’ ability to conduct its business, which it turn could negatively affect AltaGas’ financial condition and reputation. Additionally, the theft, damage, or improper disclosure of sensitive data held by these third parties may subject AltaGas to adverse consequences.

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.

Climate-Related Risks including Carbon Pricing

AltaGas may be subject to both transition and physical risks related to climate change. 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 – Corporate/Other Segment - Environmental Regulations Impacting the Corporate/Other Segment" of this AIF. The direct or indirect costs of compliance with these regulations, including carbon pricing, 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. 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. 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. As well, climate-related physical hazards such as wildfires, floods, and storms or from progressive shifts in climate patterns such as increasing temperatures, sea level rise, and changes in precipitation may impact AltaGas' assets or operations or its supply chain or lower aggregate customer demand from affected markets.

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. 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.

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Income tax laws relating to AltaGas may be changed in a manner that adversely affects its shareholders. This includes, without limitation, taxation and tax policy changes, tax rate changes, new tax laws, and revised tax law interpretations that may individually or collectively cause an increase in AltaGas’ effective tax rate.

AltaGas may face regulatory and financial risks related to pipeline safety legislation seeking to require increased oversight over pipeline operations and increased investment in and inspections of pipeline. 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 AltaGas' businesses. AltaGas' utilities may be unable to recover from customers through the regulatory process all or some of these costs which could impact the ability to earn its authorized rate of return on these costs.

Political Uncertainty and Civil Unrest

Uncertainty exists with regard to the political climate in the jurisdictions where AltaGas operates. Changes in social, political, regulatory, or economic conditions, or in laws and policies governing environment, development, tax, foreign trade, investment or energy could materially adversely affect AltaGas' business and operations.

Recently there have been significant incidents of civil unrest in areas where AltaGas operates. To the extent that civil unrest is accompanied by disruption to transportation routes, damage to infrastructure, violence or destruction, AltaGas' personnel, physical facilities, and operations may be placed at risk and financial and operational results may be adversely impacted.

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.

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 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.

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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".

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" above. Publicity adverse to AltaGas’ operations, AltaGas’ partners, or others operating in the energy industry generally, could have an adverse effect on AltaGas and its operations. While AltaGas is committed to operating in a socially responsible manner, there can be no assurance that its efforts in this respect will mitigate this potential risk.

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, 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 and Ferndale in Washington State, 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.

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.

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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 below an investment grade rating 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 to, (i) enter into ordinary course derivative or hedging transactions and may require AltaGas to post additional collateral under certain of its contracts, and (ii) enter into and maintain 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 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 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.

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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 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, 2020.

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’ 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.

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 AltaGas' 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.

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 co-owns certain facilities with joint venture partners. Failure by the operators of these facilities to operate at the cost or in the manner projected by AltaGas could negatively affect AltaGas’ results. In addition, for non-wholly owned subsidiaries, AltaGas relies on other investors to fulfill their commitments and obligations in respect of the project or facility. AltaGas has entered into various types of arrangements with joint venture partners for any or all of the construction, operation or ownership of certain facilities. Certain of these partners may have or develop interests or objectives which are different from or even in conflict with the objectives of AltaGas. AltaGas does not have the sole power

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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.

Growth Strategy Risk

It is possible that the strategy AltaGas has implemented and plans to continue implementing in 2021 and onwards will not be as successful as projected. A failure to fully realize the anticipated benefits of AltaGas' strategy could have a negative impact on AltaGas' results, including causing the failure to achieve all or any targets provided in its financial guidance.

Construction and Development

The construction and development of AltaGas’ 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 to 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.

Transportation of Petroleum Products

AltaGas' operations include transportation by truck and rail of petroleum products, including NGLs, crude oil, and other refined products.Natural Gas Liquids are transported from natural gas producers to RIPET and Ferndale by rail and truck and are delivered to customers by marine transport. Shipments may be impacted by protests, activist activities, strikes, service delays, inclement weather, rail car availability, rail car derailment, or other 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 transportation incident involving petroleum products 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 relating to rail or marine transport of petroleum products, and for which insurance is not available, or increased costs or obligations are imposed on AltaGas as a result of new regulations, AltaGas’ business, operations, and financial condition may be adversely impacted. In addition, in instances where 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, Ferndale or other assets.

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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.

Impact of Competition in AltaGas’ 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’ Corporate/Other segment 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.

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 the majority 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.

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 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.

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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.

Collateral

AltaGas is able to obtain unsecured credit limits from its counterparties in order 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 facilities that are owned 100 percent by AltaGas.

Delays in U.S. Federal Government Budget Appropriations

The Energy Efficiency and Energy Management operations of AltaGas’ Corporate/Other segment are sensitive to U.S. federal government agencies’ receipt of funding in a timely manner. A portion of the Corporate/Other segment's 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.

Market Value of Common Shares and Other Securities

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

Variability of Dividends

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

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Potential Sales of Additional Shares

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

Volume Throughput

AltaGas’ businesses process, transport, and store natural gas, ethane, NGLs, and other commodities. Throughput within the business is dependent on a number of factors, including the level of exploration and development activity within the WCSB, the long-term supply and demand dynamics for the applicable commodities, and the regulatory 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 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.

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.

AltaGas Ltd. – 2020 Annual Information Form – 72

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, certain Canadian securities regulatory authorities have 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.

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.

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.

AltaGas Ltd. – 2020 Annual Information Form – 73

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.

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.

AltaGas Ltd. – 2020 Annual Information Form – 74

ENVIRONMENTAL, SOCIAL AND GOVERNANCE

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 values provide the foundation for AltaGas' approach to its Environmental, Social and Governance (ESG) practices. At AltaGas, we are committed to maintaining safe and reliable operations, delivering the critical energy our customers need, and honoring the social and moral contract that we have with the communities we serve. Our mission is to improve quality of life by safely and reliably connecting customers to affordable sources of energy for today and tomorrow.

In December 2020, AltaGas released its ESG Update, highlighting its 2019 performance against material ESG performance indicators covering AltaGas’ consolidated enterprise-wide ESG performance inclusive of Washington Gas presenting a consolidated look at several key areas relevant to the long-term sustainability of AltaGas’ business, and demonstrating AltaGas' ongoing commitment to improving performance and transparency. The ESG Update can be accessed at www.altagas.ca.

Governance

Our governance, policies, and procedures are the framework and foundation that supports sound decision making. The Board oversees social and environmental strategies, initiatives, goals and risk management and each committee of the Board plays a role in defining ESG strategies and managing related risks within their mandates and functional areas of responsibility.

Further demonstrating its commitment to ESG, in October 2020, AltaGas created a senior executive position to guide its initiatives across the enterprise in support of the sustainability of AltaGas’ business and operations enterprise-wide and to oversee AltaGas’ ESG strategy and execution.

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;

▪ Alcohol and Drug;

▪ Information Security;

AltaGas Ltd. – 2020 Annual Information Form – 75

▪ Social Media and Acceptable Use;

▪ Disclosure;

▪ Conflicts of Interest;

▪ Anti-Bribery and Anti-Corruption; and

▪ Securities Trading and Reporting.

Environment, Health and Safety

Every day AltaGas is focused on reducing our carbon footprint and increasing the positive impact we are having on our global society. The Board of Directors has established the Environment, Health and Safety (EHS) Committee to review, monitor, and make recommendations to the Board of Directors regarding Environment, Health and Safety strategy, policy, compliance, and risk (including climate related risk).

AltaGas' 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. 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.

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 Midstream and Utilities segments 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 Utilities and Midstream 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.

AltaGas Ltd. – 2020 Annual Information Form – 76

Please also refer to the "Risk Factors – Reputation", "Risk Factors – Regulatory", "Risk Factors – Climate-Related Risks including Carbon Pricing", "Risk Factors - Changes in Laws" 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 – Corporate/Other – Environmental Regulations Impacting the Corporate/Other Business" of this AIF.

AltaGas also proactively discloses its climate change risks through the CDP (formerly the Carbon Disclosure Project), a globally respected disclosure system on sustainability. In 2020, CDP rated AltaGas Ltd. as -A on its Climate Change 2020 questionnaire, an improvement from a B rating in 2019.

Social

AltaGas’ mission is to improve quality of life by safely and reliably connecting customers to affordable sources of energy for today and tomorrow.

Indigenous Groups

AltaGas recognizes the value of building enduring and trusting relationships with Indigenous Groups. AltaGas is committed to working with Indigenous Groups in proximity to its developments in an effort to develop relationships based on mutual respect and trust, a shared understanding of the issues, and collaborative problem-solving to attain mutually beneficial outcomes.

AltaGas’ approach is underscored by principles that help to enable strong relationships, including:

▪Establishing and building of mutually beneficial long-term relationships with Indigenous Groups based on the principles of respect, transparency, inclusiveness, shared understanding and open communication;

▪Ensuring that AltaGas’ engagement with Indigenous Groups respects their rights and interests as governed by applicable law within the jurisdictions in which AltaGas operates, as well as AltaGas’ commitment to responsible development; and

▪Fostering opportunities for Indigenous Groups to participate in the economic and social benefits of AltaGas’ energy infrastructure projects and operations.

Communities

AltaGas believes that giving back to the community fosters relationships and builds trust and communication with stakeholders. Furthering that view, AltaGas has focused its giving on three pillars: healthy and safe communities, bright futures, and environmental champions. Some of our local initiatives include:

AltaGas Ltd. – 2020 Annual Information Form – 77

▪The Day of Weatherization is dedicated to weatherizing low-income homes in the Washington D.C. area, helping to keep families warm through the winter. Each year, its employees take part to ensure that participants' homes are winterized;

▪Our Utilities often operate energy assistance programs within the communities in which they operate to support residents who struggle from “energy poverty” and cannot afford utilities; and

▪In 2020, AltaGas deployed an additional $1 million across several organizations to provide COVID-19 relief funds. In some cases, these groups were able to leverage this investment to raise additional funds totaling $500,000.

Workforce

Our employees are critical to our success and are the reason we continue to fulfill our mission and meet our other corporate objectives. We believe our continued focus on making employee engagement a top priority will help us provide high quality services to our customers and communities. To facilitate talent attraction and retention, we strive to create a diverse, inclusive and safe workplace, with opportunities for our employees to grow and develop in their careers, supported by market-competitive compensation, benefits and health and wellness programs, and by programs that build connections between our employees and their communities.

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 (prior to redemption), and Series K Shares are paid quarterly.

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.

AltaGas Ltd. – 2020 Annual Information Form – 78

$ per share	2020	2019	2018
Common Shares	0.963300	0.960000	2.190000
Series A Shares	0.825000	0.845000	0.845000
Series B Shares	0.894890	1.084641	0.968620
Series C Shares (1)	1.322500	1.322500	1.322500
Series E Shares	1.348252	1.348252	1.250000
Series G Shares	1.060500	1.155750	1.187500
Series H Shares	0.994890	0.296040	—
Series I Shares (2)	1.312500	1.312500	1.312500
Series K Shares	1.250000	1.250000	1.250000
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.

(2)Series I shares were redeemed on December 31, 2020.

On December 10, 2020, AltaGas announced that its Board of Directors approved a 4 percent increase to its annual common share dividends. Monthly dividends to common shareholders will be increased to $0.0833 per common share ($1.00 per common share annually), effective for the December 2020 dividend.

Dividend Reinvestment And Optional Cash Purchase Plan

Effective May 17, 2016, AltaGas replaced, in its entirety, its dividend reinvestment plan with the Premium DividendTM, Dividend Reinvestment and Optional Cash Purchase Plan (the Plan). The Plan consisted of two components: 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 (paid 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.

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 2020 as reported by the TSX:

Month	High	Low	Volume Traded
January	21.84	19.31	34,804,758
February	22.74	19.55	22,458,890
March	21.82	8.71	54,862,863
April	17.89	11.55	27,965,615
May	16.91	14.70	24,319,832
June	16.94	14.55	26,389,232
July	17.13	15.31	23,080,248
August	18.35	16.76	12,660,809
September	17.53	15.87	12,677,231
October	17.75	15.53	16,327,819
November	19.13	16.81	17,571,111
December	19.56	18.25	16,959,674

AltaGas Ltd. – 2020 Annual Information Form – 79

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 2020 as reported by the TSX:    

Month	High	Low	Volume Traded
January	16.09	14.75	94,069
February	15.30	12.57	41,094
March	13.90	7.51	216,249
April	11.14	9.07	203,225
May	10.97	10.05	70,894
June	11.53	10.20	144,966
July	12.30	10.61	122,780
August	12.74	11.50	44,009
September	12.79	11.73	62,868
October	12.55	11.50	117,485
November	13.74	12.05	178,393
December	14.07	13.49	227,280

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 2020 as reported by the TSX:

Month	High	Low	Volume Traded
January	16.01	14.86	31,985
February	15.22	13.70	15,852
March	13.61	7.52	62,235
April	11.23	9.08	98,320
May	10.90	10.05	36,988
June	11.50	10.20	61,654
July	12.19	10.53	29,245
August	12.54	11.40	65,095
September	12.75	11.60	45,075
October	12.31	11.40	21,382
November	13.10	11.50	49,028
December	14.00	12.80	38,697

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 2020 as reported by the TSX:

Month	High	Low	Volume Traded
January	20.27	20.00	3,200
February	19.59	19.00	12,230
March	12.78	12.00	1,400
April	15.00	14.80	11,972
May	14.00	13.89	4,570
June	14.65	14.51	4,700
July	16.05	16.00	200
August	16.39	16.25	1,586
September	16.74	16.50	2,100
October	16.39	16.04	1,350
November	18.15	17.85	2,092
December	19.34	18.55	1,500

AltaGas Ltd. – 2020 Annual Information Form – 80

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 2020 as reported by the TSX:

Month	High	Low	Volume Traded
January	20.18	19.02	178,920
February	19.94	18.33	364,778
March	18.53	10.30	207,809
April	16.19	12.56	388,309
May	16.20	14.46	97,344
June	16.48	14.50	159,889
July	16.70	14.70	62,764
August	17.39	15.64	68,490
September	17.70	16.40	76,224
October	17.12	15.98	462,816
November	18.33	15.75	108,748
December	19.17	18.05	215,581

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 2020 as reported by the TSX:

Month	High	Low	Volume Traded
January	18.05	17.21	112,547
February	17.66	16.35	120,451
March	16.35	8.51	231,392
April	13.45	10.73	336,330
May	13.41	12.16	95,884
June	13.81	12.26	172,737
July	15.01	12.85	126,512
August	16.49	14.08	107,275
September	16.15	14.69	61,153
October	15.65	14.54	244,659
November	16.71	14.42	105,306
December	18.07	16.21	316,979

Series H Shares are traded on the TSX under the symbol ALA.PR.H. The following table sets forth the monthly price range and volume traded for Series H Shares for the period of January to December 2020 as reported by the TSX:

Month	High	Low	Volume Traded
January	18.00	16.17	5,000
February	18.00	15.75	9,200
March	18.00	10.00	6,423
April	14.00	10.10	4,900
May	13.00	10.72	200
June	13.19	11.75	155,100
July	15.00	11.83	1,600
August	15.00	12.30	300
September	14.50	12.70	2,700
October	15.10	12.75	900
November	18.00	13.00	4,000
December	18.00	13.85	2,700

AltaGas Ltd. – 2020 Annual Information Form – 81

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 2020 to redemption on December 31, 2020 as reported by the TSX:

Month	High	Low	Volume Traded
January	24.70	24.18	91,983
February	24.70	23.75	181,461
March	24.05	12.00	211,830
April	19.92	16.53	171,661
May	21.56	19.41	107,815
June	21.73	20.35	90,501
July	23.71	20.59	70,356
August	23.91	22.01	96,871
September	24.40	21.67	194,573
October	23.96	23.09	120,883
November	25.30	23.20	289,739
December	25.34	24.97	586,463

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 2020 as reported by the TSX:

Month	High	Low	Volume Traded
January	23.31	22.72	416,492
February	23.25	22.00	123,110
March	22.30	12.40	348,428
April	19.09	16.00	125,220
May	20.25	18.70	117,799
June	20.24	18.85	99,757
July	22.46	19.34	252,669
August	22.80	20.86	94,384
September	23.40	21.72	159,904
October	23.39	21.79	201,162
November	24.30	22.10	219,680
December	24.60	24.05	380,108

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. – 2020 Annual Information Form – 82

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 2, 2020.
		Senior unsecured	BBB-	Affirmed on December 2, 2020.
		Preferred shares	P-3	Affirmed on December 2, 2020.
	DBRS	Issuer	BBB(low)	Affirmed on December 8, 2020.
		Preferred shares	Pfd-3(low)	Affirmed on December 8, 2020.
	Fitch	Issuer	BBB	Affirmed on April 3, 2020.
		Preferred shares	BB+	Affirmed on April 3, 2020.
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 April 3, 2020.
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 April 3, 2020.
SEMCO	Moody's	Long-term issuer	A3	Raised from Baa1 to A3 on January 22, 2021 with stable outlook.
		Senior secured notes	A1	Raised from A2 to A1 on January 22, 2021 with stable outlook.
	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.

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

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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 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;

▪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; and

▪The letter agreement dated October 15, 2020 among AIJVLP, SAM and Petrogas, related to AltaGas' acquisition of SAM's approximately 37 percent interest in Petrogas.

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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. On December 10, 2020, the Colorado Court of Appeals issued an unpublished opinion affirming the judgement of the trial court. The judgment was paid in full in February 2021, and a satisfaction has been filed with the court.

•Following the National Transportation and Safety Board hearing that examined the August 10, 2016, explosion and fire at an apartment complex in Silver Spring, Maryland, on September 5, 2019, the PSC of MD ordered Washington Gas 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 (Show-Cause Order). Following several hearings throughout the course of 2019 and 2020, on December 18, 2020, the PSC of MD found that Washington Gas failed to file annual reports informing the PSC of MD of the status of Washington Gas' program and imposed a US$750,000 penalty on Washington Gas for reporting violations. The PSC of MD ruled that the NTSB probable cause finding constituted hearsay and could not be admitted into the record of the case and did not undertake its own inquiry into the source of the explosion. The PSC of MD did not make any safety-related findings in the case but did find that Washington Gas made an enforceable regulatory commitment to replace all mercury regulators. The US$750,000 penalty was paid in January 2021 and Washington Gas believes that there is no additional liability as a result of the ruling from the PSC of MD. It its December 18, 2020 order, the PSC of MD also found that Washington Gas’s proposed implementation plan to replace all remaining mercury regulators within five years of completing an mercury regulator survey adequately addresses the need to replace all remaining mercury regulators in Maryland, and is in the public interest. The costs of the proposed implementation program are not yet known, and the recovery of these costs must be deferred until a future rate case.

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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, 2020 and Management’s Discussion and Analysis for the year ended December 31, 2020.

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

TRANSFER AGENTS AND REGISTRARS

The registrar and transfer agent for the Common Shares and the Preferred Shares is Computershare Investor Services Inc., Home Oil Tower 800, 324-8th Avenue SW, Calgary, Alberta T2P 2Z2,, Tel: 1-800-564-6253.

The registrar and trustee for AltaGas’ MTNs is Computershare Trust Company of Canada, Home Oil Tower 800, 324-8th Avenue SW, Calgary, Alberta T2P 2Z2, Tel: 1-800-564-6253.

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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.

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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 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 and financial related matters 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.

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

8.Approve and recommend to the Board for approval the 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 determine the degree of coordination with the internal audit plan.

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.Approve the Internal Audit Charter and the internal audit plan and any changes thereto.

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

21.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.

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

23.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

24.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.

25.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.

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

27.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.

Risk Management

28.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.

29.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.

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

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

32.Review the Corporation's processes for identifying and managing data, cyber and other information technology related risk and processes for the development of data security programs and practices.

33.Review the Corporation's insurance programs.

Policies and Mandate

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

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

Pension and Benefits

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

37.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.

38.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.

39.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

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

41.Review asset retirement obligations in relation to decommissioning, reclamation and remediation.

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

43.Review management’s process for certification under the Extractive Sector Transparency Measures Act (Canada), if applicable.

44.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.

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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 July 29, 2020.

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EX-13.2

MANAGEMENT'S DISCUSSION AND ANALYSIS

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This Management's Discussion and Analysis (MD&A) dated February 25, 2021 is provided to enable readers to assess the results of operations, liquidity, and capital resources of AltaGas Ltd. ("AltaGas", the "Company" or the "Corporation") as at and for the year ended December 31, 2020. 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, 2020.

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, 2020 or the Annual Information Form for the year ended December 31, 2020.

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: potential post-acquisition contingent payments with regard to the Petrogas acquisition; upcoming director retirement; AltaGas' core strategy, including with regard to plans for dividend payments; 2021 strategic priorities; expectation of 2021 annual consolidated normalized EBITDA of approximately $1.4 to $1.5 billion; anticipated 2021 normalized earnings per share of approximately $1.45 to $1.55 per share; assumed effective tax rate of approximately 23 percent in 2021; expectation that the Utilities segment will contribute approximately 60 percent of normalized EBITDA for 2021; expected growth drivers of normalized EBITDA in the Utilities segment; drivers of expected growth in the Midstream segment; expected lower normalized EBITDA from the Corporate/Other segment in 2021; estimated NGLs exposed to frac spreads prior to hedging activities; plans to manage frac exposed NGL volumes; expected net capital expenditures of approximately $910 million in 2021; anticipated segment allocation of capital expenditures; expectation for 2021 committed capital program to be funded through internally-generated cash flow and normal course borrowings on existing committed credit facilities; the estimated cost, status and expected in-service dates for growth capital projects in the Midstream and Utilities businesses; expected filing, procedure and decision dates for rate cases in the Utilities business; expected impact of the COVID-19 pandemic on AltaGas’ business, operations and results in 2021; 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 2021, effective tax rate of approximately 23 percent, U.S./Canadian dollar exchange rates; expected impact of the COVID-19 pandemic; propane price differentials; degree day variance from normal; pension discount 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’ forward-looking statements are subject to certain risks and uncertainties which could cause results or events to differ from current expectations, including, without limitation: risk related to COVID -19; health and safety risks; risks related to the integration of Petrogas; operating risks; regulatory risks; cyber security, information, and control systems; litigation risk;

AltaGas Ltd. – 2020 MD&A and Financial Statements - 1

climate-related risks, including carbon pricing; changes in law; political uncertainty and civil unrest; infrastructure risks; service interruptions; decommissioning, abandonment and reclamation costs; reputation risk; weather data; Indigenous land and rights claims; crown duty to consult with Indigenous peoples; capital market and liquidity risks; general economic conditions; internal credit risk; foreign exchange risk; debt financing, refinancing, and debt service risk; interest rates; technical systems and processes incidents; dependence on certain partners; growth strategy risk; construction and development; transportation of petroleum products; impact of competition in AltaGas' businesses; counterparty credit risk; market risk; composition risk; collateral; rep agreements; delays in U.S. Federal Government budget appropriations; 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; commitments associated with regulatory approvals for the acquisition of WGL; 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; and the other factors discussed under the heading "Risk Factors" in the Corporation’s Annual Information Form for the year ended December 31, 2020 (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 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 Business Overview and Organization

AltaGas is a leading North American energy infrastructure company that connects natural gas and natural gas liquids (NGLs) to domestic and global markets. The Company operates a diversified, low-risk, high-growth Utilities and Midstream business that is focused on delivering resilient and durable value for its stakeholders.

Within the Company’s Utilities segment, AltaGas owns and operates rate regulated Utilities assets that provide natural gas to 1.7 million end-users across five U.S. jurisdictions (Virginia, Maryland, Michigan, the District of Columbia, and Alaska). The principal focus of the segment is to provide its customers with safe, reliable and affordable energy to heat and power their homes and places of work in order to carry out everyday life. The segment provides AltaGas with stable earnings and cash flow with approximately 70 percent of the Company’s Utilities customers being residential and the balance being commercial and industrial users.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 2

Within AltaGas’ Midstream segment, the Company owns and operates a number of large energy infrastructure assets that are principally focused on: 1) gathering, processing, and fractionating raw natural gas production into pipeline quality natural gas and NGLs; and 2) connecting natural gas and NGLs to domestic and global downstream markets. This includes AltaGas operating two large LPG export terminals on the North American west coast that ship propane and butane to key Asian markets.

The businesses of AltaGas are operated by the Company 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 regard to the Utilities business, Washington Gas Light Company (Washington Gas), Hampshire Gas Company, and SEMCO Energy, Inc. (SEMCO); in regard 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); and, in regard to remaining assets in the Corporate/Other segment, AltaGas Power Holdings (U.S.) Inc., WGL Energy Systems, Inc. (WGL Energy Systems), and Blythe Energy Inc. (Blythe). 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). Petrogas Energy Corporation (Petrogas) was also added as a subsidiary of AltaGas upon the close of the acquisition on December 15, 2020.

Acquisition of Petrogas

On December 15, 2020, following the receipt of all required approvals, AltaGas acquired an additional 37 percent of Petrogas Energy Corp. (the Petrogas Acquisition) for total cash consideration upon close of approximately $715 million. Additional post-acquisition contingent payments of up to $16 million may be paid no later than 2022 based on certain criteria, including earnings targets being met. AltaGas funded the transaction through draws on its existing credit facilities. As a result of the transaction, AltaGas' ownership in Petrogas has increased to approximately 74 percent with Idemitsu Kosan Co., Ltd. (Idemitsu) owning the remaining approximately 26 percent. Subsequent to the transaction, AltaGas controls Petrogas and as such, Petrogas results have been consolidated for the period subsequent to close.

Petrogas Energy Corp. is a midstream and logistics company in North America with operations dating back to 1986. Petrogas operates a large scale fully integrated natural gas liquids (NGLs) and crude oil platform that provides sourcing, storage, marketing, and transportation services for NGLs and LPGs to customers throughout Canada, the U.S. and Asia, and crude oil throughout Canada and the U.S.

Petrogas' business was principally underpinned by four primary business lines:

▪LPG Exports and Distribution: Comprised of the Ferndale LPG export facility and engages in the purchase, sale, and distribution of NGLs and LPGs throughout North America and Asia.

▪Domestic Terminals: Operates various North American storage terminals that support the LPG exports and distribution activities. This business line also enters into long-term take-or-pay contracts for management, logistics, and optimization services.

▪Trucking and Liquids Handling: Provides internal and third-party trucking services in Western Canada and the Pacific Northwest. Includes hauling LPGs, crude, drilling fluids, and produced water.

▪Wellsite Fluids and Fuels: Operates two production facilities focused on the development and production of proprietary drilling fluids, jet fuel, furnace fuel and heating oil.

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The LPG Exports and Distribution and Domestic Terminals business lines are Petrogas' most significant assets and historically, have represented the vast majority of Petrogas' trailing normalized EBITDA.

The Ferndale terminal is an LPG export facility located on the U.S. west coast near Ferndale, Washington, which is approximately 100 miles north of Seattle. Shipping times to Asia average approximately 11 days using Very Large Gas Carriers (VLGCs) from the facility and, as such, this origin has a similar structural shipping advantage as AltaGas' Ridley Island Propane Export Terminal (RIPET) facility compared to various LPG export terminals located on the U.S. Gulf Coast. Ferndale has refrigerated storage capacity, and is pipeline connected to local refineries. Similar to AltaGas' RIPET export facility, LPG export volumes being shipped from Ferndale are delivered into various Asian markets and provide a cleaner, lower-carbon feedstock option for these key importing regions.

Petrogas' Fort Saskatchewan rail loading and truck facility, together with other storage facilities in Canada and the U.S., expands AltaGas' NGL supply sourcing area and enhances the Company's NGL storage and logistics capabilities. With the close of the acquisition, AltaGas now has access to a fleet of approximately 3,000 additional rail cars, five incremental rail and pipeline connected terminals, and approximately 6.3 million barrels of additional above ground and cavern storage. Fort Saskatchewan is pipeline connected to fractionation facilities and to multi-product storage facilities in Canada. Petrogas' Canadian storage facilities, which are located in Fort Saskatchewan, Alberta, Sarnia, Ontario, and Strathcona, Alberta, have a combined capacity of approximately 4.8 million barrels of on-site storage handling for oil, propane, butane, and ethylene and are pipeline connected to refiners. Petrogas' largest U.S. storage and terminal facility, located in Indiana, has two underground storage caverns for propane and butane. This facility is situated near several refineries, tank farms, pipeline connections to area refiners and chemical facilities, and has inbound and outbound truck and rail capabilities.

2020 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

▪On December 15, 2020, AltaGas closed the Petrogas Acquisition for total cash consideration of approximately $715 million and additional post-acquisition contingent payments of up to $16 million. AltaGas' ownership in Petrogas is now approximately 74 percent with Idemitsu Kosan Co., Ltd. indirectly owning the remaining approximately 26 percent;

▪On August 21, 2020, the Canada Energy Regulator (CER) granted AltaGas an additional 25 year license to export up to 46,000 Bbls/d of propane to North American and global markets from RIPET, bringing the aggregate propane export capacity under 25 year export licenses to 92,000 Bbls/d. In December 2020, the Minister of Natural Resources approved the additional license;

▪On February 14, 2020, WGL Midstream executed an Asset Management Agreement (AMA) with Consolidated Edison Company of New York, Inc. (ConEd) that gives ConEd the rights to use WGL Midstream’s 50,000 Dth per day of transportation capacity on the MarketLink Expansion Project for the period from April 1, 2020 through April 1, 2035; and

▪On January 16, 2020, AltaGas received approval from the California Public Utilities Commission for the 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.

Asset Sales Completed

▪On March 31, 2020, the Public Sector Pension Investment Board and the Alberta Teachers' Retirement Fund Board acquired all the issued and outstanding common shares of AltaGas Canada Inc. (ACI) for $33.50 per share. AltaGas owned 11,025,000 (approximately 37 percent) of ACI's common shares and received cash proceeds of approximately

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$369 million upon close. A pre-tax gain on disposition of approximately $206 million was recorded in the first quarter of 2020; and

▪In the third quarter of 2020, AltaGas closed the dispositions of AltaGas Pomona Energy Storage Inc. (Pomona) and land related to a battery storage facility, as well as AltaGas Ripon Energy Inc. (Ripon), a small natural gas power facility, both located in California. Aggregate gross proceeds for these dispositions, before working capital and other adjustments, were approximately $67 million, resulting in a pre-tax gain of $8 million.

Regulatory Developments

▪On December 11, 2020, the PSC of DC approved a three-year US$150 million PROJECTpipes 2 plan for Washington Gas for the period from 2021 to 2023, and the associated surcharge recovery;

▪On August 28, 2020, Washington Gas filed a rate case in Maryland requesting US$28 million increase in base rates, including US$6 million currently collected through the Strategic Infrastructure Development Enhancement Plan (STRIDE) surcharges for system upgrades. Evidentiary hearings took place between January 7 and January 11, 2021. The Commission is expected to issue a final decision around the end of March 2021;

▪In April 2020, the Alaskan legislature passed legislation and the regulatory commissions of the District of Columbia, Maryland, Virginia, and Michigan issued orders allowing utilities to establish regulatory assets to record incremental COVID-19 related costs that will be evaluated for recovery in future proceedings; and

▪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. On December 8, 2020, Washington Gas filed, for PSC of DC approval, a settlement agreement to resolve all issues in the case. Evidentiary hearings were suspended, and the PSC of DC held a public interest hearing on January 27, 2021 to address the settlement agreement. On February 24, 2021, the PSC of DC approved the US$20 million base rate case recommended in the settlement agreement. The new rates will become effective on April 1, 2021.

Other Highlights

▪AltaGas continues to closely monitor developments related to COVID-19, including the existing and potential impact on global and local economies in the jurisdictions where it operates. The executive team and cross-functional response teams that were established in late January continue to meet regularly to align response strategy and efforts within all areas of the Corporation. AltaGas' approach has been, and will continue to be, risk-based and guided by its core values. The health and safety of AltaGas' employees, customers, contractors, and the communities in which it operates is the top priority and is integrated into each aspect of AltaGas' response efforts;

▪On April 1, 2020, AltaGas announced it would donate $1 million to help community partners in its operating regions respond to the COVID-19 pandemic. The assistance funds, provided by AltaGas, were distributed to partner organizations on the front lines supporting local communities and providing critical support to our health care workers addressing the health crisis;

▪In the first quarter of 2020, AltaGas revised its reportable segments to align with the structure of its business following asset sales 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. Consistent with Management’s strategic view of the business and the basis on which it assesses performance and allocates resources, beginning in 2020, AltaGas has two operating segments: Utilities, which now includes the WGL retail marketing business, and Midstream. These operating segments have not been aggregated in the determination of AltaGas' reportable segments. All other assets are included in the Corporate/Other segment. Prior period segment information has been restated to conform to the current reporting segment presentation;

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▪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, which was effective following the conclusion of AltaGas' annual meeting of shareholders in May 2020;

▪In the third quarter of 2020, Painted Pony Energy Ltd. (Painted Pony), one of AltaGas' significant counterparties in the Northeast British Columbia (NEBC) region, announced that it had entered into an agreement to be acquired by Canadian Natural Resources Limited. The shareholders of Painted Pony approved the plan of arrangement on October 1, 2020, and the transaction was completed on October 6, 2020. In addition, in the third quarter of 2020, ConocoPhillips acquired oil and gas assets in the Inga/Fireweed/Stoddard division in the Montney area from another of AltaGas' counterparties, Kelt Exploration Ltd. All operating agreements of AltaGas remain in effect. These transactions resulted in a significant increase in the credit worthiness of AltaGas' counterparties in the NEBC region;

▪On April 21, 2020, SEMCO completed the private placement of US$450 million of first mortgage bonds, in two tranches of US$225 million each. One of the tranches has a term of ten years with a coupon rate of 2.45 percent, and the other has a term of 30 years with a coupon rate of 3.15 percent. The proceeds were used to repay debt drawn on credit facilities and the US$300 million notes that matured in April 2020;

▪On June 10, 2020, AltaGas completed the issuance of $500 million of senior unsecured medium term notes with a coupon rate of 2.157 percent, maturing on June 10, 2025. 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 $6 million per annum;

▪On September 30, 2020, 35,180 of the outstanding 5,511,220 Cumulative Redeemable Five-Year Fixed Rate Reset Preferred Shares, Series A (Series A Preferred Shares) were converted into Cumulative Floating Rate Preferred Shares, Series B (Series B Preferred Shares), and 1,270,639 of the outstanding 2,488,780 Series B Preferred Shares were converted into Series A Preferred Shares. As a result of the conversions, AltaGas has 6,746,679 Series A Preferred Shares and 1,253,321 Series B Preferred Shares;

▪On November 30, 2020, AltaGas completed the issuance of $500 million of senior unsecured medium term notes with a coupon rate of 2.075 percent, maturing on May 30, 2028, and $200 million of senior unsecured medium term notes with a coupon rate of 2.477 percent, maturing on November 30, 2030. The net proceeds were used to pay down existing indebtedness under AltaGas' credit facility, to fund the redemption of all of the issued and outstanding Cumulative Redeemable 5-Year Minimum Rate Reset Preferred Shares, Series I of AltaGas, and for general corporate purposes. As a result of the issuance, AltaGas expects annual average cash savings of approximately $12 million per year;

▪On December 10, 2020, Washington Gas completed the issuance of US$100 million of medium term notes with a coupon rate of 3.65 percent due September 15, 2049; and

▪On December 31, 2020, AltaGas redeemed all of it's 8,000,000 issued and outstanding Cumulative Redeemable 5-Year Minimum Rate Reset Preferred Shares, Series I for a redemption price equal to $25 per share.

Financial Highlights

▪Normalized EBITDA was $1,310 million compared to $1,302 million in 2019;

▪Cash from operations was $773 million ($2.77 per share) compared to $616 million (2.22 per share) in 2019;

▪Normalized funds from operations were $1,003 million ($3.59 per share) compared to $895 million ($3.23 per share) in 2019;

▪Net income applicable to common shares was $486 million ($1.74 per share) compared to $769 million ($2.78 per share) in 2019;

▪Normalized net income was $396 million ($1.42 per share) compared to $347 million ($1.25 per share) in 2019;

▪Net debt was $8.2 billion as at December 31, 2020, compared to $7.2 billion at December 31, 2019; and

▪Net debt‑to‑total capitalization ratio was 52 percent as at December 31, 2020, compared to 49 percent as at December 31, 2019.

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Highlights Subsequent to Year End

▪On February 2, 2021, AltaGas announced the appointment of a new Independent Director, Jon-Al Duplantier, to AltaGas' Board of Directors, effective immediately. AltaGas also announced the planned retirement of Allan Edgeworth from AltaGas' Board of Directors effective upon the conclusion of AltaGas' next Annual General Meeting, to be held in late April 2021.

AltaGas' Vision, Mission, and Focus

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 Company’s Mission is to improve quality of life by safely and reliably connecting customers to affordable sources of energy for today and tomorrow. To advance these pursuits, AltaGas’ team of approximately 3,000 people is guided by the Company's core values. These values form the foundations for how the Company treats each other, its customers, its Indigenous partners and other stakeholders, and serve as a blueprint for a sustainable future. AltaGas views access to reliable and affordable energy as fundamental in the pursuit of improved quality of life, reduced physical barriers, improved access to education, and to fuel economic expansion. As such, the Company is committed to its foundational principals of maintaining safe and reliable operations, delivering the critical energy its customers need, and honoring the social and moral contract that AltaGas has with the communities it serves.

Core Strategy

AltaGas' long-term strategy is to build a diversified low-risk, high-growth Utilities and Midstream business that is focused on delivering resilient and durable value for our stakeholders. This includes a focus on providing the Company’s shareholders with regular returns of capital through dividend payments and the prospect for capital appreciation through steady and sustainable growth.

AltaGas' forward plan to regularly return capital is to deliver regular, sustainable, and annual dividend increases that compound in the years ahead and are supported by durable growth in earnings per share, declining leverage ratios, and reduced payout ratios. The Company’s growth is expected to be generated by optimizing AltaGas’ existing assets for appropriate returns and deploying new capital that is principally focused on organic expansion initiatives that are underpinned by meeting base return thresholds.

AltaGas believes that its current asset base is well-positioned to achieve this feat. This includes operating a large rate regulated Utilities platform that provides stable earnings and cash flow and that operates across a diversified geographic footing, heavily weighted to residential usage. The Utilities platform also provides steady growth opportunities focused on Accelerated Pipeline Replacement Programs (ARPs) that replace aging infrastructure, reduce methane emissions through leak remediation, and improve the safety and reliability of the delivery of affordable energy. This also includes operating a concentrated and modern Midstream platform that AltaGas views as being well-positioned for where the market is heading over the next three to five years. This includes a significant footprint in the Montney in NEBC and LPG exports with the only two west coast terminals in North America.

In 2021, AltaGas plans to focus on progressing its long-term strategy of building a diversified Utilities and Midstream business designed to provide resilient and durable value for its stakeholders that compounds over the long-term. Specific 2021 strategic priorities include to:

▪Continue to deliver affordable natural gas and LPGs to domestic and global markets in a safe, reliable, and efficient manner;

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▪Advance AltaGas' operational excellence model to improve business processes and aggressively manage costs to improve the customer experience and returns;

▪Build a world class Midstream and energy export business by maximizing the utilization of existing assets and integrating and optimizing the Petrogas business to advance AltaGas' distinctive energy export strategy; and

▪Maintain a disciplined approach to capital allocation within a self-funding model that continues to de-lever the balance sheet and increase financial flexibility over time, with incremental de-leveraging opportunities being possible from potential non-core asset sales.

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 and protect value for its 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.

2021 Outlook

In 2021, AltaGas expects to achieve annual consolidated normalized EBITDA of approximately $1.4 to $1.5 billion, and normalized earnings per share of approximately $1.45 to $1.55 per share assuming an effective tax rate of approximately 23 percent.

The Utilities segment is expected to contribute approximately 60 percent of normalized EBITDA, with growth driven primarily by revenue growth from previously settled rate cases, increased spend on accelerated capital programs, the impact of Washington Gas' District of Columbia rate case which has settled, the expected impact of Maryland's rate case which is expected to be completed in the near-term, ongoing operational cost optimization activities, and modest customer growth, partially offset by the one-time favorable impact from the pension accounting change in 2020. Expected growth in the Midstream segment, primarily driven by the integration and optimization of Petrogas operations, higher export volumes from RIPET, and increased volumes at NEBC facilities, is expected to be partially offset by lower commodity prices and the impacts of a blend and extend contract that was entered into in 2018 and takes effect in 2021. Midstream segment earnings are approximately 60 percent underpinned through take-or-pay, cost-of-service, and fee-for-service contracts at the Midstream facilities and tolling agreements at the export facilities. Normalized EBITDA from the Corporate/Other segment, which includes AltaGas' remaining power assets, is expected to be lower in 2021 mainly due to asset sales completed in 2020 and recoveries related to the Canada Emergency Wage Subsidy (CEWS) in 2020. Overall growth is expected to offset lost normalized EBITDA from a full year impact of asset sales completed in 2020 and the impact of expected 2021 asset sales.

The overall forecasted normalized EBITDA and earnings per share include assumptions around the U.S./Canadian dollar exchange rate. The impact of the COVID-19 pandemic on AltaGas business segments is expected to be less pronounced than in 2020. 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. Please refer to the Risk Management section of this MD&A for further discussions of the risks to AltaGas arising from the COVID-19 pandemic.

AltaGas estimates an average of approximately 9,000 Bbls/d of NGLs will be exposed to frac spreads prior to hedging activities. AltaGas plans to manage the 2021 frac exposed NGL volumes with an active hedging program and is currently approximately 97 percent hedged for 2021.

At RIPET and Ferndale, NGL price margins are protected through AltaGas' comprehensive hedging programs. For volumes not contracted under tolling arrangements at RIPET, approximately 67 percent are currently financially hedged at an FEI to Mont Belvieu spread of approximately US$10/Bbl. At Ferndale, approximately 12 percent of exposed propane and butane volumes are currently hedged, at an FEI to Conway spread of approximately US$14/Bbl for propane and an approximately US$28/Bbl FEI spread to butane purchase price. Collectively, approximately 60 percent of AltaGas' propane export volumes

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are hedged for 2021. AltaGas plans to manage the export facilities such that a growing portion 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 2021:

Factor	Increase or decrease	Approximate impact on  normalized annual EBITDA ($ millions)
Degree day variance from normal - Utilities (1)	5 percent	10
Change in Canadian dollar per U.S. dollar exchange rate	0.05	35
Propane Far East Index to Mont Belvieu spread (2)	US$1/Bbl	19
Pension discount rate	1 percent	20

(1)Degree days – Utilities relate to SEMCO Gas, ENSTAR, and District of Columbia 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 sensitivity is net of hedges currently in place. The impact on EBITDA due to changes in the spread will vary and is being managed through an active hedging program.

Growth Capital

Based on projects currently under review, development, or construction, AltaGas expects net capital expenditures of approximately $910 million in 2021. The majority of capital expenditures are expected to focus on projects within the Utilities platform 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 80 to 85 percent of total capital expenditures, while the Midstream segment is expected to account for approximately 15 to 20 percent and the Corporate/Other segment is expected to account for any remainder. In 2021, 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 construction of the Nig Creek expansion, maintenance and administrative capital, optimization of existing assets, and new business development. Maintenance capital related to Midstream assets and remaining power assets in the Corporate/Other segment is expected to be approximately $45 to $55 million of the total capital expenditures in 2021. The Corporation continues to focus on capital efficient organic growth and disciplined capital allocation while improving balance sheet strength and flexibility.

AltaGas' 2021 committed capital program is expected to be funded through internally-generated cash flow and normal course borrowings on existing committed credit facilities.

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Growth Capital Project Updates

The following table summarizes the status of AltaGas’ significant growth projects:

Project	AltaGas' Ownership Interest			Estimated Cost (1)	Expenditures to Date (2)		Status	Expected In-Service Date
Midstream Projects
Nig Creek Expansion		50%	$58 million		$16 million	The Nig Creek facility is being expanded in two phases. Phase one will expand designed capacity by 55 Mmcf/d gross (27.5 Mmcf/d net) by adding inlet compression, sales compression, and other plant equipment. The second phase will increase capacity by an additional 25 Mmcf/d gross (12.5 Mmcf/d net) and will include a deep cut plant for additional liquids recoveries.		Phase I expected to be in-service early Q3 2021 and phase II in Q2 2022
Mountain Valley Pipeline (Mountain Valley)		10%	US$352 million		US$352 million	As of December 31, 2020, approximately 92 percent of the project is complete, which includes construction of all original interconnects and compressor stations. On November 9, 2020, the 4th US Circuit of Appeals granted a request from certain environmental groups and issued a stay pending litigation over the U.S. Army Corps of Engineers' verification of water crossings for the project, under a general permit know as Nationwide Permit 12. As a result, the targeted in-service date is now expected in the second half of 2021. Despite the delays, AltaGas' exposure is contractually capped to the original estimated contributions of approximately US$352 million.		Q4 2021 due to ongoing legal and regulatory challenges
MVP Southgate Project		5%	US$20 million		US$4 million	Construction is expected to begin in the third quarter of 2021, despite the North Carolina Department of Environmental Quality's decision to deny MVP Southgate's request for state certification under the Clean Water Act Section 401. The decision is expected to be appealed. Expenditures to date relate to land surveys, land acquisition, and obtaining permits and regulatory approvals.		Q3 2022 due to ongoing legal and regulatory challenges

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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$150 million over the three year period from January 2021 to December 2023, plus additional expenditures in subsequent periods.			$nil (3)	Washington Gas has submitted an application for the second phase of PROJECTpipes to the PSC of DC. In the interim, in March 2020, the PSC of DC approved an additional extension of the first phase of the plan for the six month period from April 1, 2020 to September 30, 2020 for an amount not to exceed approximately US$13 million. On August 11, 2020, the PSC of DC suspended the procedural schedule and on September 10, 2020, the first phase of PROJECTpipes was extended for an additional three month period to December 30, 2020, or until a decision is rendered in this case, for an amount not to exceed approximately US$6 million. After determining that there were no material issues of fact in dispute, the PSC of DC decided that there will be no evidentiary hearings and extended the PROJECTpipes surcharge to the end of December 2020. On December 11, 2020, the PSC of DC approved a 3-year, US$150 million plan covering the period from January 1, 2021 to December 31, 2023. The PSC of DC also approved the continuation of the PROJECTpipes surcharge which is currently in place.		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$125 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$275 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 Replacement Programs – Michigan		100%	Estimated US$115 million over five year period from 2021 to 2026.			$nil (3)	A new Main Replacement Program (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.

(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, 2020. 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 multi-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.

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Utilities

Description of Assets

AltaGas owns and operates utility assets that store and deliver natural gas to end-users in Virginia, Maryland, Michigan, the District of Columbia, and Alaska, serving approximately 1.7 million customers and with a combined rate base of approximately US$4.3 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 operating a diversified low-risk, high-growth energy infrastructure business that is focused on delivering resilient and durable value for its stakeholders with long-life assets.

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

▪WGL's Retail Marketing business, which sells power and natural gas directly to residential, commercial, and industrial customers in Maryland, Virginia, Delaware, Pennsylvania, Ohio, and the District of Columbia.

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All of AltaGas' regulated 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 gas 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 that has been engaged in the natural gas distribution business since 1848, and provides regulated gas distribution services to end users in Virginia, Maryland, and the District of Columbia. At the end of 2020, Washington Gas had approximately 1.2 million customers, of which approximately 81 percent were residential. The number of customers at Washington Gas increased approximately 1 percent in 2020. The rate base at December 31, 2020 was approximately US$3.3 billion. At the end of 2020, the approved regulated ROE for Washington Gas in its various jurisdictions ranged from 9.2 - 9.7 percent based on an equity ratio ranging from 53.5 - 55.7 percent.

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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 Utilities 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 three- to 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, 2020, approximately 15 percent of its customers have chosen to purchase gas from marketers. This does not negatively impact Washington Gas’ net income as the Corporation does not earn a margin on the sale of natural gas to firm customers, but only from the delivery and distribution of the gas.

Washington Gas obtains natural gas supplies that originate from multiple regions throughout the United States. At December 31, 2020, it had service agreements with five pipeline companies that provided firm transportation and storage services with contract expiration dates ranging from 2021 to 2039. 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.

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 the 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 2020, SEMCO Gas had approximately 313,000 customers. Of these customers, approximately 92 percent are residential. In 2020, 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 compared to other heating sources. The rate base at year end was approximately US$719 million. In 2020, the approved regulated ROE for SEMCO Gas was 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 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

AltaGas Ltd. – 2020 MD&A and Financial Statements - 14

renewed for an additional five years in 2015. 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. Any MRP revenue associated with unspent capital will be placed into a regulatory liability account to be addressed in the next general rate base case. Additionally, a new IRIP was approved in the 2019 rate case, pursuant to which 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 2020, ENSTAR had approximately 149,000 customers including residential, commercial, and transportation, and of these customers, approximately 91 percent are residential. In 2020, ENSTAR experienced customer growth of approximately 1 percent reflecting growth in the franchise areas and customer conversions with the favorable price of natural gas compared to other heating sources. The rate base at year end was approximately US$256 million for ENSTAR and US$66 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.

Retail Energy Marketing

The U.S. retail gas marketing business sells natural gas directly to residential, commercial, and industrial customers in Maryland, Virginia, Delaware, Pennsylvania, and the District of Columbia.

The U.S. retail power marketing business sells power to end users in Maryland, 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 these states and jurisdictions.

Natural gas and electricity are 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 deliveries, and thus, a secured supply arrangement expiring in 2022 has been entered into with Shell Energy North America (US), L.P, which reduces credit requirements.

Capitalize on Opportunities

While providing safe and reliable service, AltaGas pursues opportunities in the Utilities segment to deliver value to its customers while enhancing long-term shareholder returns. 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;

▪Continue to grow the consolidated Utilities rate base;

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

▪Maintain strong community and regulatory relationships while ensuring appropriate 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 annual rate base growth averaging approximately 74 percent 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: 1) the Company's global export assets, which connect North American production into key downstream markets in Asia; 2) strategically-located processing, fractionation, extraction and liquids handling infrastructure assets that convert raw production into usable products and link output from wellheads to downstream markets; 3) a natural gas transportation and storage platform, which includes AltaGas' 10 percent stake in the Mountain Valley Pipeline; and 4) various above and underground natural gas and liquids storage assets that are leveraged across the North American energy value chain. The Midstream segment also includes AltaGas' increased ownership stake in the Petrogas assets and operations.

In Canada, AltaGas serves customers primarily in the Western Canada Sedimentary Basin (WCSB), with a strong weighting in the Montney play in NEBC. This includes gas gathering, processing, fractionating and delivery of natural gas and NGLs into downstream pipeline systems. It also includes connecting producers LPG output to key consuming regions in Asia. In total, AltaGas transacts on more than 1.4 Bcf/d of natural gas and NGLs, including 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 certain hydrocarbon components are separated, and impurities 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 additional NGLs. AltaGas has a total net licensed processing capacity of approximately 2.4 Bcf/d.

Through the RIPET and Ferndale LPG export terminals, AltaGas connects North American producers and aggregators with global markets and provides incremental opportunities for improved pricing for propane and butane. On December 15, 2020, AltaGas completed the acquisition of Petrogas, increasing its indirectly held ownership in Petrogas to approximately 74 percent with Idemitsu owning the remaining 26 percent (please refer to the Acquisition of Petrogas section of this MD&A for additional information). Subsequent to the transaction, AltaGas controls Petrogas and as such, AltaGas has the capability to export LPGs to Asia through the Ferndale facility. See the Global Exports section below for further details.

AltaGas' logistics services include NGL pipelines, treating, storage, truck, and rail terminal infrastructure 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 and storage capacity to earn a profit. With the emergence of the global exports business, the logistics platform provides integral support for managing AltaGas' waterborne and rail capacity as well as marketing the supply and offtake of LPG volumes at RIPET and Ferndale. In support of the liquids handling operations, AltaGas manages a rail car fleet of approximately 4,600 rail cars. With the acquisition of Petrogas, the Midstream logistics infrastructure also includes Petrogas' core businesses including LPG exports and distribution, domestic terminals, wellsite fluids and fuels, and trucking and liquids handling. See the Fractionation and Logistics section below for more details.

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

Global Exports

AltaGas’ global export assets include the Company's RIPET and Ferndale export terminals, which are located in Northern B.C. and Washington State, respectively. These terminals facilitate North American producers and aggregators to access global markets and provides incremental opportunities for improved price realization for propane and butane production. Between the two facilities, AltaGas has the ability to ship in excess of 130,000 Bbl/d.

RIPET commenced commercial operations on May 23, 2019, with the first propane shipment departing from the terminal to Asia. RIPET has storage of 600,000 Bbls and throughput capacity of up to 80,000 Bbls/d at the terminal. As AltaGas builds on the Company's operational capabilities and continues to align with leading North American producers and global customers in Asia through long-term tolling agreements, it expects to continue to increase throughput from RIPET. On August 21, 2020, AltaGas was granted an additional 25-year license to export an additional 46,000 bbl/d of propane to North American and global markets, bringing its aggregate propane export capacity under 25-year export licenses to 92,000 Bbls/d. For 2021, AltaGas has in place multi-year agreements for the purchase of approximately 33 percent of the propane expected to be shipped from RIPET. The RIPET dock offers deep draft, sufficient to accommodate loading VLGCs.

With the acquisition of Petrogas, AltaGas also operates the Ferndale LPG terminal, which is capable of loading VLGCs, has 800,000 Bbls of on-site storage, and currently can flow approximately 50,000 Bbls/d. Located approximately 100 miles north of Seattle, the terminal is also pipeline connected to two regional refineries, providing additional supply, sales, and fee-for-service opportunities for the facility.

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The RIPET and Ferndale export terminals represent strategic outlet points for North American LPG volumes as they are competitively situated to serve the high-demand Far East market with shorter average shipping times and competitive arbs as compared to the U.S. Gulf Coast or Arabian Gulf.

Terminal demand is supported through various long-term purchase agreements with Canadian and U.S. suppliers, primarily from key Northern British Columbia and Alberta gathering facilities and select U.S. producing regions, including the Bakken in North Dakota. Petrogas also maintains service agreements with numerous Tier 1 rail providers in order to leverage existing rail networks and secure competitively priced LPGs across North America.

Gas Processing

Gas processing activities are comprised of gathering systems that move raw natural gas and NGLs from producing wells to processing facilities, where impurities and certain hydrocarbon components are removed, and the product moves down the energy value chain. The gas is then compressed to meet downstream pipelines' operating specifications for transportation to North American natural gas markets. All of AltaGas' processing facilities are capable of extracting NGLs and converting the throughput into usable products. The facilities provide revenues based on take-or-pay contracts and fee-for-service arrangements with its customers, with the latter based on volumes processed. A significant portion of AltaGas' Midstream contracts flow the Company's operating costs through to the producers. AltaGas' processing infrastructure includes:

▪The Townsend facility, a 550 Mmcf/d gas processing facility, along with the related egress pipelines, truck terminal, and NGL treatment infrastructure (the Townsend complex), which is wholly owned and operated 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 NEBC. In the second quarter of 2020, Townsend 2B and a gas gathering pipeline that connects upstream fields to AltaGas facilities were commissioned, which added 198 Mmcf/d C3+ deep cut gas processing capacity at the Townsend Complex. In the third quarter of 2020, ConocoPhillips acquired oil and gas assets in the Inga/Fireweed/Stoddard division in the Montney area from Kelt. All operating agreements of AltaGas remain in effect;

▪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, currently a shallow gas plant with capacity of 100 Mmcf/d (50 Mmcf/d net) that came on-stream in the third quarter of 2019. Phase 1 of Nig Creek GP2B will increase inlet capacity by 55 Mmcf/d (28 Mmcf/d net). Phase 1 of Nig Creek GP2B is expected to be commissioned in the third quarter of 2021. The Aitken processing facilities are located in the liquids rich Montney resource play in 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 straddle processing, and

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NGL extraction. In addition, Harmattan has fractionation and terminalling facilities (see Fractionation and Logistics section below); 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 NEBC.

Fractionation and Logistics

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 logistics 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' logistics 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. With the close of the Petrogas acquisition, AltaGas' fractionation and logistics business also includes Petrogas' terminals, wellsite fluids and fuels, and trucking and liquids handling.

AltaGas’ fractionation and logistics 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, Alberta. The first train of the North Pine facility is capable of processing up to 10,000 Bbls/d of NGL mix. The second train, commissioned in the first quarter of 2020, provides 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 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 (CN) rail network, allowing the transportation of propane, butane, and condensate to North American markets and propane to global markets via RIPET and butane via Ferndale;

▪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) and is operated by Pembina. AltaGas has a 50 percent interest in Younger's fractionation, storage, loading, treating, and terminalling of NGL and 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 three liquids egress lines. The third line, which connects the Townsend facility to the Townsend truck terminal on the Alaska Highway (30 km) and AltaGas' North Pine facility (70 km), was commissioned in the third quarter of 2020;

▪NGL and spec propane lines that connect the Townsend complex in the North, to the Aitken Creek facilities through a 60 km NGL pipeline (Aitken Connector), Storm Resources Nig plant through a lateral, and to the Tourmaline Gundy facility in the West, through a 15 km spec propane line were all commissioned in the first half of 2020;

▪A rail logistics network consisting of approximately 4,600 rail cars that AltaGas manages to support LPG and NGL handling, including approximately 3,000 rail cars from Petrogas;

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▪Petrogas' terminals and storage business, which provides support to the LPG exports and distribution business by providing the ability to source, transport, process, store, and deliver products through strategically located fixed assets throughout North America. In addition, the terminals business provides various storage and handling services to third-party customers through take-or-pay and fee-for-service agreements, which provide earnings stability through volatile commodity price environments. The terminals business consists of strategically located crude and NGL assets which provide storage, blending, rail, and truck logistical support and waterborne LPG export capabilities. Petrogas' terminal business includes Griffith LPG Terminal, which is capable of handling approximately 12,000 Bbls/d of NGLs, 700,000 barrels of underground cavern storage and up to 220 railcars rail siding capacity; the Strathcona Storage JV, which has four underground storage salt caverns in service and a fifth cavern under development with each cavern providing approximately 629,000 Bbls of storage capacity; and Sarnia Storage and Crude Oil Terminal JV, which provides up to 2.1 million barrels of crude oil and refined product storage capacity with outbound throughput supported by 10,000 Bbls/d of rail loading capacity. The right to access the terminal assets under the joint venture arrangement have been recorded as a lease by Petrogas;

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

▪Three primary trucking entities which Petrogas operates, providing transportation related services within the WCSB and the Pacific Northwest in the U.S. by hauling frac fluid, produced water, crude oil, and NGLs between producers, terminals, customers and end users; and

▪Enerchem International Inc., a wholly owned subsidiary of Petrogas, is a Canadian corporation which focuses on the production of drilling and wellsite fluids and consumer fuels. Through the fractionation of crude oil feedstock, Enerchem produces and distributes proprietary hydrocarbon fluids for fracturing and drilling of oil and gas wells to improve productivity and to resolve oilfield production challenges for downstream producers. Enerchem operates two primary facilities located in Sundre and Slave Lake, Alberta, which are capable of processing over 1.5 million barrels of finished products per year. These plants are supported by various ancillary storage and distribution facilities located across the WCSB, providing over 150,000 barrels of storage capacity, strategically placed within the vicinity of active drilling regions.

Energy Services

In addition to supporting the other Midstream activities within AltaGas, the logistics business identifies opportunities to buy and resell NGLs for producers, and exchange, reallocate or resell pipeline and storage capacity 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 utilities gas users and manages the third-party pipeline transportation requirements for many of its gas marketing customers.

Petrogas' marketing business is focused on the purchase, sale, exchange, and distribution of NGLs and crude oil, primarily in proximity to its strategically owned and leased asset base. By leveraging Petrogas' fully integrated infrastructure base and extensive logistical capabilities, the marketing team is able to source competitively priced supply at the key hubs and across various hydrocarbon basins in order to capture arbitrage opportunities derived through regional pricing differentials. Marketing efforts are driven by two primary focuses: 1) domestic NGL and crude oil wholesale, and 2) LPG waterborne exports. Additionally, this business provides operational support to the Ferndale export terminal by providing product supply and export sales agreement negotiation services. Petrogas supports its distribution efforts by maintaining an extensive leased rail fleet. Leases are established on a staggered maturity schedule with multiple lessors, to ensure railcar integrity and up-to-date DOT classification and all leases are on a full-service basis.

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Pipeline Investments

AltaGas has a 10 percent equity interest in the Mountain Valley Pipeline. MVP will transport approximately 2.0 Bcf/d of natural gas and is expected to be placed into service in the second half of 2021. 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 MVP. The MVP Southgate pipeline is expected to be placed into service in the second half of 2022 due to ongoing legal and regulatory challenges.

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 of Constitution Pipeline Company, LLC elected not to proceed with the project.

Capitalize on Opportunities

To take advantage of opportunities, including the 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 platform. New infrastructure consists of 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 while enhancing 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/Ferndale and the integrated value chain to attract volumes;

▪Increase utilization and export volumes, optimize commercial and operational capability at RIPET and Ferndale, and continue to build on export competency;

▪Develop and maintain 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;

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

▪Mitigate counterparty risk through customer base growth and diversification.

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Corporate/Other

Description of Assets

In addition to Corporate activities and assets, AltaGas' Corporate/Other segment includes 582 MW of operational gross capacity from remaining natural gas-fired and distributed generation power assets located in the U.S., primarily California and Colorado.

Specifically, the core remaining power assets in the Corporate/Other segment include:

▪Two natural gas-fired plants with 577 MW of generating capacity in the United States: the 507 MW Blythe Energy Center (Blythe) in California and the 70 MW Brush II Facility (Brush) in Colorado. Blythe and Brush are both under Power Purchase Arrangements (PPA) with a creditworthy utilities; 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 Southern California Edison (SCE), the majority of the revenue from the facility is derived from being available to produce and not from actual production, which reduces risk and provides stable cash flow. The facility is directly connected to an El Paso Gas Company natural gas pipeline for its primary supply and a Southern California Gas Company pipeline as a secondary 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 received by the California Public Utilities Commission in January 2020, Blythe is contracted under a PPA until December 31, 2023. Under the tolling agreement, SCE has exclusive rights to all capacity, energy, ancillary services, and resource adequacy benefits during the PPA term. In addition, AltaGas is in the initial stages of permitting a new 40 MW stand-alone energy storage project in Goleta, California.

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Consolidated Financial Review

	Three Months Ended December 31		Year Ended December 31
($ millions, except where noted)	2020	2019	2020	2019
Revenue	1,689	1,534	5,587	5,495
Normalized EBITDA (1) (2)	392	436	1,310	1,302
Net income (loss) applicable to common shares	48	(103)	486	769
Normalized net income (1)	147	194	396	347
Total assets	21,532	19,795	21,532	19,795
Total long-term liabilities	11,264	9,301	11,264	9,301
Net additions (dispositions) of property, plant and equipment	295	239	825	(1,089)
Dividends declared (3)	67	67	268	266
Cash from operations	7	16	773	616
Normalized funds from operations (1)	327	332	1,003	895
Normalized adjusted funds from operations (1)	289	307	880	836
Normalized utility adjusted funds from operations (1)	216	236	585	560
Normalized effective income tax rate (%) (1)	21.5	12.9	22.3	16.0

	Three Months Ended December 31		Year Ended December 31
($ per share, except shares outstanding)	2020	2019	2020	2019
Net income (loss) per common share - basic	0.17	(0.37)	1.74	2.78
Net income (loss) per common share - diluted	0.17	(0.37)	1.74	2.77
Normalized net income - basic (1)	0.53	0.70	1.42	1.25
Normalized net income - diluted (1)	0.53	0.69	1.42	1.25
Dividends declared (3)	0.24	0.24	0.96	0.96
Cash from operations	0.03	0.06	2.77	2.22
Normalized funds from operations (1)	1.17	1.19	3.59	3.23
Normalized adjusted funds from operations (1)	1.04	1.10	3.15	3.02
Normalized utility adjusted funds from operations (1)	0.77	0.85	2.10	2.02
Shares outstanding - basic (millions)
During the period (4)	279	278	279	277
End of period	279	279	279	279

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

(2)Beginning in 2020, Management no longer adjusts normalized EBITDA or normalized net income for changes in the fair value of natural gas optimization inventory. Please see the Non-GAAP Financial Measures section of this MD&A for additional detail. As such, comparative periods have been adjusted to reflect the before and after-tax impacts of this change to normalized EBITDA and normalized net income, respectively.

(3)Dividends declared per common share per month: $0.08 beginning December 2018, increased to $0.0833 per share beginning December 2020.

(4)Weighted average.

Three Months Ended December 31

Normalized EBITDA for the fourth quarter of 2020 was $392 million, compared to $436 million for the same quarter in 2019. Factors negatively impacting AltaGas' normalized EBITDA in the fourth quarter of 2020 included lower realized storage spreads at WGL Midstream, lower realized merchant margins at RIPET, lower equity earnings from Petrogas for the period prior to the acquisition of Petrogas on December 15, 2020, lower NGL marketing margins, warmer weather at certain of AltaGas' Utilities, higher expenses related to employee benefits and incentive plans, and lower frac exposed NGL volumes. Other factors negatively impacting normalized EBITDA included the impact of asset sales, including WGL Midstream's indirect non-operating interest in the Central Penn Pipeline (Central Penn) in November 2019, and ACI in March 2020. Factors positively impacting normalized EBITDA included higher contributions from NEBC assets primarily due to growth capital projects placed in service in 2020, higher rates and gas margins at SEMCO, higher gas margins from WGL's Retail Energy

AltaGas Ltd. – 2020 MD&A and Financial Statements - 23

Marketing business due to favorable pricing, higher revenue from ARP program spend, and contributions from the consolidation of Petrogas after closing the acquisition on December 15, 2020. Petrogas equity income for the period prior to acquisition was lower primarily due to lower commodity prices in 2020 as well as the absence of a one-time payment related to the termination of a customer contract in the fourth quarter of 2019. On December 15, 2020, AltaGas acquired an additional 37 percent of Petrogas, resulting in AltaGas' ownership of Petrogas being increased to approximately 74 percent. As such, Petrogas' results have been consolidated for the period subsequent to close (please refer to the Acquisition of Petrogas section of this MD&A for additional information). For the three months ended December 31, 2020, the average Canadian/U.S. dollar exchange rate decreased to 1.30 from an average of 1.32 in the same quarter of 2019, resulting in a decrease in normalized EBITDA of approximately $5 million.

Net income applicable to common shares for the fourth quarter of 2020 was $48 million ($0.17 per share), compared to a net loss of $103 million ($0.37 per share) for the same quarter in 2019. The increase was mainly due to lower provisions on assets, the gain recorded on the re-measurement of AltaGas' previously held equity investment in AltaGas Idemitsu Joint Venture LP (AIJVLP) upon acquisition of Petrogas, lower unrealized losses on risk management contracts, and lower interest expense, partially offset by the same previously referenced factors impacting normalized EBITDA, the absence of the gain on the sale of the U.S. distributed generation assets in the third quarter of 2019, the dilution loss and other adjustments to equity income related to the acquisition of Petrogas, and higher income tax expense.

Normalized funds from operations for the fourth quarter of 2020 were $327 million ($1.17 per share), compared to $332 million ($1.19 per share) for the same quarter in 2019. The decrease was mainly due to the same factors impacting normalized EBITDA, partially offset by lower interest expense. In the fourth quarter of 2020, prior to the acquisition of Petrogas, AltaGas received $3 million of dividend income from the Petrogas Preferred Shares (2019 - $3 million).

In the fourth quarter of 2020, upon the acquisition of Petrogas, AltaGas recorded a gain on the re-measurement of the Company's previously held equity investment in AIJVLP of approximately $22 million. In addition, in the fourth quarter of 2020, AltaGas recorded pre-tax provisions on assets of approximately $104 million ($79 million after-tax) primarily related to the Alton Natural Gas Storage Project, which was impaired as AltaGas does not believe that the future expected cash generation from the project aligns with the current carrying value. In the fourth quarter of 2019, AltaGas recorded pre-tax gains on dispositions of assets of approximately $56 million. This was comprised of a pre-tax gain of $68 million on certain U.S. distributed generation projects which were sold in the third quarter of 2019 but transferred to the purchaser in the fourth quarter of 2019, and a pre-tax loss of approximately $12 million on the disposition of equity investments, primarily related to WGL Midstream's indirect non-operating interest in Central Penn. In addition, in the fourth quarter of 2019, AltaGas recorded pre-tax provisions on assets of approximately $415 million ($319 million after-tax), primarily related to various assets in the Corporate/Other segment and a sour gas treatment facility in Alberta.

Operating and administrative expenses for the fourth quarter of 2020 were $342 million, compared to $340 million for the same quarter in 2019. The slight increase was mainly due to increased costs related to operations at the NEBC pipeline projects which were placed in service in the second and third quarters of 2020 and increased professional and consulting fees. Depreciation and amortization expense for the fourth quarter of 2020 was $108 million, compared to $109 million for the same quarter in 2019. The slight decrease was mainly due to the impact of provisions recorded against property, plant, and equipment in the fourth quarter of 2019, partially offset by new assets placed in-service in 2020. Interest expense for the fourth quarter of 2020 was $68 million, compared to $77 million for the same quarter in 2019. The decrease was predominantly due to lower average interest rates compared to 2019.

AltaGas recorded an income tax expense of $5 million for the fourth quarter of 2020 compared to an income tax recovery of $87 million in the same quarter in 2019. The increase in income tax expense was mainly due to higher tax recoveries on asset provisions in the fourth quarter of 2019. Current tax expense of $14 million was recorded in the fourth quarter of 2020, of which approximately $2 million related to a tax recovery on asset sales.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 24

Normalized net income was $147 million ($0.53 per share) for the fourth quarter of 2020, compared to $194 million ($0.70 per share) reported for the same quarter in 2019. The decrease was mainly due to the same factors impacting normalized EBITDA and higher income tax expense, partially offset by lower interest expense and lower depreciation and amortization expense. Normalizing items in the fourth quarter of 2020 increased normalized net income by $99 million and included after‑tax amounts related to transaction costs related to acquisitions and dispositions, restructuring costs, provisions on assets, unrealized losses on risk management contracts, dilution loss and other adjustments to equity income related to the acquisition of Petrogas, and the gain recorded on the re-measurement of AltaGas' previously held equity investment in AIJVLP upon acquisition of Petrogas. Normalizing items in the fourth quarter of 2019 increased normalized net income by $297 million and included after‑tax amounts related to gains on sale of assets, 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, provisions on assets, provisions on investments accounted for by the equity method, gain on redemption of Washington Gas preferred shares, unitary tax adjustment related to the acquisition of WGL and U.S. asset sales, and the impact of a statutory tax rate change in Alberta. 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, 2020 was $1,310 million, compared to $1,302 million in 2019. Factors positively impacting normalized EBITDA included the impact of Washington Gas' 2019 Maryland and Virginia rate cases, higher contributions from NEBC assets primarily due to growth capital projects placed in service in 2020, the impact of a change in accounting principle relating to Washington Gas' net periodic pension and other post-retirement benefit plan costs (please refer to the Critical Accounting Estimates section of this MD&A for additional information), higher rates effective January 2020 at SEMCO due to the 2019 rate case application, higher revenue from ARP spend, higher Allowance for Funds Used During Construction (AFUDC) related to MVP, additional contracted ethane volumes at the extraction facilities, contributions from Petrogas for the period after acquisition, contributions from RIPET, which was placed into service in May 2019, and a shorter planned spring outage at Blythe compared to 2019. These were partially offset by the impact of asset sales, including the U.S. distributed generation assets in September 2019, WGL Midstream's indirect non-operating interest in Central Penn in November 2019, WGL Midstream's interest in the Stonewall Gas Gathering System (Stonewall) in May 2019, ACI in March 2020, Pomona in July 2020, as well as lower equity earnings from Petrogas prior to the acquisition of the additional interest in Petrogas on December 15, 2020, lower U.S. Midstream financial hedge gains and storage withdrawals, lower frac exposed volumes and lower realized frac spreads, lower usage at certain of the utilities, and the cancellation of late fees and related charges by AltaGas' Utilities due to COVID-19. Petrogas equity income for the period prior to acquisition was lower primarily due to lower commodity prices during 2020. Export deliveries up until the month of April were lower than planned due to industry conditions and subsequently have resumed to planned levels. In addition, in the fourth quarter of 2019, Petrogas earnings included a large one-time payment related to the termination of a customer contract. On December 15, 2020, AltaGas acquired an additional 37 percent of Petrogas, resulting in AltaGas' ownership of Petrogas being increased to approximately 74 percent. As such, Petrogas' results have been consolidated for the period subsequent to close (please refer to the Acquisition of Petrogas section of this MD&A for additional information). For the year ended December 31, 2020, the average Canadian/U.S. dollar exchange rate increased to 1.34 from an average of 1.33 in 2019, resulting in an increase in normalized EBITDA of approximately $4 million.

Net income applicable to common shares for the year ended December 31, 2020 was $486 million ($1.74 per share), compared to $769 million ($2.78 per share) in 2019. The decrease was mainly due to the absence of gains on asset sales recorded in 2019 (including Northwest Hydro, Stonewall, and distributed generation assets), dilution loss and other adjustments to equity income related to the acquisition of Petrogas, and higher income tax expense, partially offset by lower provisions on assets, the gain on the disposition of AltaGas Canada Inc. (ACI, now named TriSummit Utilities Inc.), the gain recorded on the re-measurement of AltaGas' previously held equity investment in AIJVLP upon the acquisition of Petrogas,

AltaGas Ltd. – 2020 MD&A and Financial Statements - 25

gains on the sales of Pomona and Ripon, higher unrealized gains on risk management contracts, the same previously referenced factors impacting normalized EBITDA, lower interest expense, and lower depreciation and amortization expense.

Normalized funds from operations for the year ended December 31, 2020 were $1,003 million ($3.59 per share), compared to $895 million ($3.23 per share) in 2019. The increase was mainly due to the same drivers as normalized EBITDA and lower interest expense. In 2020, prior to the acquisition of Petrogas, AltaGas received $13 million of dividend income from the Petrogas Preferred Shares (2019 - $13 million) and $5 million of common share dividends from Petrogas (2019 - $6 million).

In 2020, AltaGas recorded pre-tax gains on dispositions of assets of approximately $223 million. This was comprised of a pre-tax gain of $206 million on the disposition of AltaGas' equity investment in ACI, a pre-tax gain of $9 million related to certain distributed generation projects which were transferred to the purchaser in 2020, a pre-tax gain of $5 million on the disposition of Pomona, and a pre-tax gain of $3 million on the disposition of Ripon. In 2020, upon the acquisition of Petrogas, AltaGas also recorded the previously mentioned gain on the re-measurement of it's previously held equity investment in AIJVLP of approximately $22 million. In 2020, AltaGas recorded pre-tax provisions on assets of approximately $109 million ($81 million after-tax) primarily related to the Alton Natural Gas Storage Project, certain U.S. distributed generation projects which had not yet transferred to the purchaser, and land parcels located near the Harmattan gas processing plant. In addition, in 2020, AltaGas recorded a pre-tax provision on equity investments of approximately $7 million ($6 million after-tax) for costs associated with the Constitution pipeline project (Constitution) which was canceled in February 2020. In 2019, AltaGas recorded pre-tax gains on dispositions of assets of approximately $875 million. This was mainly comprised of a pre-tax gain of $688 million on the sale of the remaining interest in the Northwest Hydro facilities, a pre-tax gain of $100 million on the disposition of the U.S. distributed generation assets, a pre-tax gain of $34 million on the disposition of WGL Midstream's interest in Stonewall, a pre-tax loss of $6 million on the sale of Canadian non-core power assets, a pre-tax loss of $1 million on the sale of a WGL Energy Systems financing receivable, a pre-tax gain of $5 million on the sale of certain non-core Midstream processing facilities, and the previously mentioned losses recorded in the fourth quarter of 2019. In 2019, AltaGas recorded pre-tax provisions on assets of approximately $416 million ($320 million after-tax) primarily related to the previously mentioned provisions recorded in the fourth quarter of 2019 and $1 million related to a capital spare turbine in storage which was sold in the third quarter of 2019. In addition, in 2019, 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.

Operating and administrative expenses for the year ended December 31, 2020 were $1,267 million, compared to $1,299 million in 2019. The decrease was mainly due to the impact of asset sales in the second half of 2019, recoveries related to CEWS, and lower employee salary expenses, partially offset by the impact of RIPET coming online in May 2019 and increased costs related to operations at the NEBC pipeline projects, which were placed in service in the second and third quarters of 2020. Depreciation and amortization expense for the year ended December 31, 2020 was $414 million, compared to $438 million in 2019. The decrease was mainly due to an amortization adjustment related to the derecognition of an intangible liability, the impact of the sale of U.S. distributed generation assets in September 2019 and the impact of provisions recorded against property, plant, and equipment in the fourth quarter of 2019, partially offset by RIPET coming online in May 2019 and new assets placed in-service. Interest expense for the year ended December 31, 2020 was $274 million, compared to $346 million in 2019. The decrease was predominantly due to lower average interest rates compared to 2019.

AltaGas recorded an income tax expense of $127 million for the year ended December 31, 2020 compared to an income tax recovery of $28 million in 2019. The increase in tax expense was mainly due the absence of tax recoveries on the disposition of the U.S. distributed generation assets in the third quarter of 2019, unitary tax rate adjustments, and a one-time tax recovery related to the Alberta Job Creation Tax Cut in the second quarter of 2019, partially offset by lower tax expense on dispositions in Canada in 2020. Current tax expense of approximately $1 million was recorded in 2020, of which approximately $2 million related to a tax recovery on asset sales.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 26

Normalized net income was $396 million ($1.42 per share) for the year ended December 31, 2020, compared to $347 million ($1.25 per share) in 2019. The increase was mainly due to the same previously referenced factors impacting normalized EBITDA, lower interest expense, and lower depreciation and amortization expense, partially offset by higher income tax expense. Normalizing items in the year ended December 31, 2020 reduced normalized net income by $90 million and included after‑tax amounts related to gains on sale of assets, transaction costs related to acquisitions and dispositions, restructuring costs, provisions on assets, provisions on investments accounted for by the equity method, dilution loss and other adjustments to equity income related to the acquisition of Petrogas, COVID-19 related costs, gain recorded on the re-measurement of AltaGas' previously held equity investment in AIJVLP upon acquisition of Petrogas, and unrealized gains on risk management contracts. Normalizing items in the year ended December 31, 2019 reduced normalized net income by $422 million and included after‑tax amounts related to gains on sale of assets, 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. 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 (AFFO), normalized utility adjusted funds from operations (UAFFO), 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.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 27

Normalized EBITDA

	Three Months Ended December 31				Year Ended December 31
($ millions)	2020		2019 (1)		2020		2019 (1)
Net income (loss) after taxes (GAAP financial measure)	$	69	$	(85)	$	572	$	840
Add (deduct):
Depreciation and amortization	108		109		414		438
Interest expense	68		77		274		346
Income tax expense (recovery)	5		(87)		127		(28)
EBITDA	$	250	$	14	$	1,387	$	1,596
Add (deduct):
Transaction costs (recoveries) related to acquisitions and dispositions	5		(4)		22		12
Merger commitment costs (recoveries)	—		1		—		(4)
Unrealized losses (gains) on risk management contracts	24		64		(21)		85
Non-controlling interest related to HLBV investments	—		—		—		8
Losses on investments	—		—		—		5
Gains on sale of assets	—		(56)		(223)		(875)
Gain on re-measurement of previously held equity investment in AIJVLP	(22)		—		(22)		—
Dilution loss and other adjustments to equity investments	26		—		42		—
Restructuring costs	4		—		6		—
COVID-19 related costs	—		—		2		—
Provisions on assets	104		415		109		416
Provisions on investments accounted for by the equity method	—		—		7		46
Investment tax credits related to distributed generation assets	—		—		—		7
Accretion expenses	2		1		5		5
Foreign exchange losses (gains)	(1)		1		(4)		1
Normalized EBITDA	$	392	$	436	$	1,310	$	1,302

(1)In prior years, normalized EBITDA also included adjustments for changes in fair value of natural gas optimization inventory; however, beginning in 2020, this is no longer adjusted for as Management believes this more accurately represents AltaGas' operating profitability. Instead, normalized EBITDA is now adjusted for unrealized gains or losses on hedges related to this optimization inventory which is included in unrealized losses (gains) on risk management contracts. Comparative periods have been restated to reflect this change. As a result of this change, 2019 normalized EBITDA is now $1,302 million, compared to $1,271 million disclosed in the MD&A for the year ended December 31, 2019.

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 using net income (loss) after taxes adjusted for pre‑tax depreciation and amortization, interest expense, and income taxes.

Normalized EBITDA includes additional adjustments for transaction costs (recoveries) related to acquisitions and dispositions, merger commitment costs (recoveries) due to a change in timing related to certain WGL merger commitments, unrealized losses (gains) on risk management contracts, non-controlling interest of certain investments to which HLBV accounting is applied, losses on investments, gains on sale of assets, restructuring costs, dilution loss and other adjustments to equity income related to the acquisition of Petrogas, gain on re-measurement of previously held equity investment in AIJVLP, COVID-19 related costs, provisions on assets, provisions on investments accounted for by the equity method, distributed generation asset related investment tax credits, foreign exchange losses (gains), and accretion expenses related to asset retirement obligations. In addition to the dilution loss, the other adjustments to equity income primarily included amounts related to severance, transaction costs, and impairment losses related to the acquisition of Petrogas. COVID-19 related costs normalized in 2020 were primarily comprised of credit losses that were incremental and directly attributable to the COVID-19 pandemic and charges incurred to support remote work arrangements. AltaGas presents normalized EBITDA as a supplemental measure. Normalized EBITDA is used by Management to enhance the understanding of AltaGas' earnings over periods. The metric is frequently used by analysts and investors in the evaluation of entities within the industry as it excludes

AltaGas Ltd. – 2020 MD&A and Financial Statements - 28

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)	2020		2019 (1)		2020		2019 (1)
Net income (loss) applicable to common shares (GAAP financial measure)	$	48	$	(103)	$	486	$	769
Add (deduct) after-tax:
Transaction costs (recoveries) related to acquisitions and dispositions	3		(3)		18		10
Merger commitment costs (recoveries)	—		1		—		(5)
Unrealized losses (gains) on risk management contracts	17		49		(18)		65
Losses on investments	—		—		—		5
Gains on sale of assets	(7)		(42)		(204)		(814)
Gain on re-measurement of previously held equity investment in AIJVLP	(22)		—		(22)		—
Dilution loss and other adjustments to equity investments	26		—		42		—
Restructuring costs	3		—		5		—
COVID-19 related costs	—		—		2		—
Provisions on assets	79		319		81		320
Provisions on investments accounted for by the equity method	—		(6)		6		29
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)
Normalized net income	$	147	$	194	$	396	$	347

(1)In prior years, normalized EBITDA also included adjustments for changes in fair value of natural gas optimization inventory; however, beginning in 2020, this is no longer adjusted for as Management believes this more accurately represents AltaGas' operating profitability. Instead, normalized EBITDA is now adjusted for unrealized gains or losses on hedges related to this optimization inventory which is included in unrealized gains on risk management contracts. Comparative periods have been restated to reflect this change. As a result of this change, 2019 normalized net income is now $347 million, compared to $324 million disclosed in the MD&A for the year ended December 31, 2019.

Normalized net income represents net income (loss) applicable to common shares adjusted for the after-tax impact of transaction costs (recoveries) related to acquisitions and dispositions, merger commitment costs (recoveries) due to a change in timing related to certain WGL merger commitments, unrealized losses (gains) on risk management contracts, losses on investments, gains on sale of assets, provisions on assets, provisions on investments accounted for by the equity method, restructuring costs, dilution loss and other adjustments to equity income related to the acquisition of Petrogas, gain on re-measurement of previously held equity investment in AIJVLP, COVID-19 related costs, gain on redemption of preferred shares, unitary tax adjustment related to the acquisition of WGL and U.S. asset sales, and statutory tax rate change. Normalized net income is used by Management to enhance the comparability of AltaGas’ earnings, as it reflects the underlying performance of AltaGas’ business activities.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 29

Normalized Funds From Operations, AFFO, and UAFFO

	Three Months Ended December 31				Year Ended December 31
($ millions)	2020		2019		2020		2019
Cash from operations (GAAP financial measure)	$	7	$	16	$	773	$	616
Add (deduct):
Net change in operating assets and liabilities	311		281		203		232
Asset retirement obligations settled	2		1		4		2
Funds from operations	$	320	$	298	$	980	$	850
Add (deduct):
Transaction costs (recoveries) related to acquisitions and dispositions (1)	5		(4)		17		12
Merger commitment costs (recoveries)	—		1		—		(4)
Current tax expense (recovery) on asset sales	(2)		37		(2)		37
Restructuring costs	4		—		6		—
COVID-19 related costs	—		—		2		—
Normalized funds from operations	$	327	$	332	$	1,003	$	895
Add (deduct):
Net cash received from (paid to) non-controlling interests	(4)		(4)		(21)		35
Non-utility maintenance capital	(18)		(4)		(36)		(26)
Preferred dividends paid	(16)		(17)		(66)		(68)
Normalized adjusted funds from operations	$	289	$	307	$	880	$	836
Deduct:
Utilities depreciation and amortization	(73)		(71)		(295)		(276)
Normalized utility adjusted funds from operations	$	216	$	236	$	585	$	560

(1)Excluding non-cash amounts.

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 operations, adjusted for net changes in operating assets and liabilities and expenditures incurred to settle asset retirement obligations. Normalized funds from operations is based on funds from operations, further adjusted for non‑operating related expenses (net of current taxes) such as transaction costs (recoveries) related to acquisitions and dispositions, merger commitment costs (recoveries), current tax expense (recovery) on asset sales, COVID-19 related costs, and restructuring costs. 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, non-utility 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 adjusted funds from operations as presented should not be viewed as an alternative to cash from operations or other cash flow measures calculated in accordance with GAAP.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 30

Normalized Income Tax Expense

	Three Months Ended December 31				Year Ended December 31
($ millions)	2020		2019		2020		2019
Income tax expense (recovery) (GAAP financial measure)	$	5	$	(87)	$	127	$	(28)
Add (deduct) tax impact of:
Transaction costs (recoveries) related to acquisitions and dispositions	2		(1)		4		2
Unrealized losses (gains) on risk management contracts	6		13		(4)		19
Gains on sale of assets	7		(14)		(19)		(61)
Restructuring costs	1		—		1		—
Provisions on assets	25		96		28		96
Provisions on investments accounted for by the equity method	—		6		1		18
Statutory tax rate change	—		(1)		—		10
Unitary tax adjustment on acquisition of WGL and U.S. asset sales	—		19		—		19
Investment tax credits related to distributed generation assets	—		1		—		7
Normalized income tax expense	$	46	$	32	$	138	$	82

Normalized income tax expense represents income tax recovery (expense) adjusted for the tax impact of transaction costs (recoveries) related to acquisitions and dispositions, unrealized losses (gains) on risk management contracts, gains on sale of assets, restructuring costs, provisions on assets, provisions on investments accounted for by the equity method, unitary tax adjustment related to the acquisition of WGL and U.S. asset sales, statutory tax rate change, and distributed generation asset related investment tax credits. 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 and is presented to provide this perspective to analysts and investors. 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. – 2020 MD&A and Financial Statements - 31

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)	2020		2019		2020		2019
Normalized EBITDA	$	392	$	436	$	1,310	$	1,302
Add (deduct):
Depreciation and amortization	(108)		(109)		(414)		(438)
Interest expense	(68)		(77)		(274)		(346)
Income tax recovery (expense)	(5)		87		(127)		28
Normalizing items impacting tax recovery	(42)		(119)		(12)		(110)
Accretion expenses	(2)		(1)		(5)		(5)
Foreign exchange gains (losses)	1		(1)		4		(1)
Non-controlling interest related to HLBV investments	—		—		—		(8)
Net income applicable to non-controlling interests	(5)		(5)		(20)		(7)
Preferred share dividends	(16)		(17)		(66)		(68)
Normalized net income	$	147	$	194	$	396	$	347

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)	2020		2019		2020		2019
Normalized net income	$	147	$	194	$	396	$	347
Add (deduct):
Normalized income tax expense	46		32		138		82
Net income applicable to non-controlling interests	5		5		20		7
Non-controlling interest related to HLBV investments	—		—		—		8
Preferred share dividends	16		17		66		68
Normalized net income before taxes	$	214	$	248	$	620	$	512
Normalized effective income tax rate (%) (1)	21.5		12.9		22.3		16.0

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

AltaGas Ltd. – 2020 MD&A and Financial Statements - 32

Results of Operations by Reporting Segment

In 2020, AltaGas revised its reportable segments to align with the structure of its business following asset sales 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. Consistent with Management’s strategic view of the business and the basis on which it assesses performance and allocates resources, beginning in 2020, AltaGas has two operating segments: Utilities (which now includes the WGL Retail Marketing business) and Midstream. These operating segments have not been aggregated in the determination of AltaGas' reportable segments.

Normalized EBITDA (1) (2)	Three Months Ended December 31				Year Ended December 31
($ millions)	2020		2019		2020		2019
Utilities	$	259	$	260	$	788	$	698
Midstream	128		179		473		531
Sub-total: Operating Segments	$	387	$	439	$	1,261	$	1,229
Corporate/Other	5		(3)		49		73
	$	392	$	436	$	1,310	$	1,302

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

(2)Beginning in 2020, Management no longer adjusts normalized EBITDA or normalized net income for changes in the fair value of natural gas optimization inventory. Please see the Non-GAAP Financial Measures section of this MD&A for additional detail. As such, comparative periods have been adjusted to reflect the before and after-tax impacts of this change to normalized EBITDA and normalized net income, respectively.

Revenue	Three Months Ended December 31				Year Ended December 31
($ millions)	2020		2019		2020		2019
Utilities	$	1,092	$	1,179	$	3,817	$	4,044
Midstream	572		326		1,636		1,260
Sub-total: Operating Segments	$	1,664	$	1,505	$	5,453	$	5,304
Corporate/Other	34		34		135		223
Intersegment eliminations	(9)		(5)		(1)		(32)
	$	1,689	$	1,534	$	5,587	$	5,495

AltaGas Ltd. – 2020 MD&A and Financial Statements - 33

Utilities

Operating Statistics

	Three Months Ended December 31		Year Ended December 31
	2020	2019	2020	2019
Natural gas deliveries - end-use (Bcf) (1)	50.0	52.2	151.7	159.4
Natural gas deliveries - transportation (Bcf) (1)	35.6	38.3	124.1	134.4
Service sites (thousands) (2)	1,672	1,653	1,672	1,653
Degree day variance from normal - SEMCO Gas (%) (3)	(4.4)	4.3	(4.6)	5.0
Degree day variance from normal - ENSTAR (%) (3)	0.2	(20.6)	5.6	(17.7)
Degree day variance from normal - Washington Gas (%) (3) (4)	(10.6)	(3.2)	(11.2)	(7.9)
Retail energy marketing - gas sales volumes (Mmcf)	18,053	20,131	59,782	64,460
Retail energy marketing - electricity sales volumes (GWh)	3,257	3,291	13,607	13,218

(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.

Regulatory Metrics

	Year Ended December 31
	2020	2019
Approved ROE (%) (1)	10.0	10.1
Approved return on debt (%) (1)	5.4	5.4
Rate base ($ millions) (2) (3) (4)	4,291	3,865

(1)Average of all the regulated 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 2020, AltaGas’ Utilities segment experienced warmer weather at SEMCO, colder weather at ENSTAR, and warmer at Washington Gas compared to the same quarter of 2019.

For the year ended December 31, 2020, AltaGas' Utilities segment experienced warmer weather at SEMCO, colder weather at ENSTAR, and warmer weather at Washington Gas compared to 2019.

Service sites at December 31, 2020 increased by approximately 20 thousand sites compared to December 31, 2019 due to growth in customer base.

In the fourth quarter of 2020, U.S. Retail Energy Marketing gas sales volumes were 18,053 Mmcf, compared to 20,131 Mmcf in the same quarter of 2019. The decrease was primarily due to COVID-19 impacts. In the fourth quarter of 2020, U.S. Retail

AltaGas Ltd. – 2020 MD&A and Financial Statements - 34

Energy Marketing electricity sales volumes were 3,257 GWh compared to 3,291 GWh in the same quarter of 2019. The decrease was primarily due to COVID-19 impacts, partially offset by an increase in customers served by the business.

For the year ended December 31, 2020, U.S. Retail Energy Marketing gas sales volumes were 59,782 Mmcf, compared to 64,460 Mmcf in the same period in 2019. The decrease was primarily due to COVID-19 impacts. For the year ended December 31, 2020, U.S. Retail Energy Marketing electricity sales volumes were 13,607 GWh compared to 13,218 GWh in the same period in 2019. The increase was primarily due to an increase in customers served by the business, partially offset by COVID-19 impacts.

Three Months Ended December 31

The Utilities segment reported normalized EBITDA of $259 million in the fourth quarter of 2020, compared to $260 million in the same quarter in 2019. Factors positively impacting normalized EBITDA included higher rates and gas margins at SEMCO, higher revenue from accelerated pipe replacement program spend, higher gas margins from WGL's Retail Energy Marketing business due to favorable pricing which was partially offset by COVID-19 impacts, and colder weather in Alaska. These were partially offset by the cancellation of late fees and related charges by the utilities due to COVID-19, the impact of the sale of ACI, and lower power margins from WGL's Retail Energy Marketing business as a result of COVID-19 impacts which were partially offset by lower capacity charges in 2020, higher expenses related to employee benefits and incentive plans, a residential energy credit adjustment received in 2019, final Virginia rate case adjustments in 2019, and warmer weather in Michigan.

Year Ended December 31

The Utilities segment reported normalized EBITDA of $788 million in the year ended December 31, 2020, compared to $698 million in 2019. The increase in normalized EBITDA was mainly due to the impact of Washington Gas' Maryland and Virginia rate cases, the impact of a change in accounting principle relating to Washington Gas' net periodic pension and other post-retirement benefit plan costs (please refer to the Critical Accounting Estimates section of this MD&A for additional information), higher rates effective January 2020 at SEMCO due to the 2019 rate case application, higher revenue from accelerated pipe replacement program spend, colder weather in Alaska, lower operating expenses at WGL's Retail Energy Marketing business, and the favorable impact of the stronger U.S. dollar. This increase was partially offset by warmer weather in Michigan and in the District of Columbia, lower customer usage primarily as a result of COVID-19, the cancellation of late fees and related charges by the utilities due to COVID-19, lower margins from WGL's Retail power marketing operations as a result of COVID-19 impacts which were partially offset by lower capacity charges in 2020, lower margins and volumes from WGL's Retail gas marketing operations as a result of warmer weather and COVID-19 impacts which were partially offset by favorable pricing, and the impact of the sale of ACI.

In 2020, the Utilities segment recognized a pre-tax gain of $206 million on the disposition of ACI. There were no dispositions in the Utilities segment in the year ended December 31, 2019.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 35

Rate Case Updates

Utility/Jurisdiction	Date Filed	Request	Status	Expected Timing of Decision
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. Therefore, the incremental amount of the base rate increase requested is approximately US$26 million.	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. On April 29, 2020, the PSC of DC issued an Order which established a procedural schedule and identified issues to be addressed in the Washington Gas' supplemental direct testimony to be filed May 15, 2020. On September 14, 2020, Washington Gas filed rebuttal testimony. On December 8, 2020, Washington Gas filed, for PSC of DC approval, a settlement agreement to resolve all issues in the case. The settling parties agreed to a US$20 million increase in base rates including PROJECTpipes surcharges previously collected as a rider and return on equity of 9.25 percent. The settling parties agree that this settlement is limited to resolving PROJECTpipes costs that are completed and in service, as of the date of Washington Gas' filed rebuttal testimony (i.e., September 14, 2020). Washington Gas' rebuttal testimony included an amount of up to approximately US$100 million of PROJECTpipes plant in service being transferred to base rates. This settlement does not set any precedent with respect to any future requests for PROJECTpipes cost recovery. Washington Gas agrees it will not file for a distribution rate increase or request any new rate or tariff mechanisms that have a related customer rate increase in the District of Columbia before August 31, 2021. On February 24, 2021, the PSC of DC approved the US$20 million base rate case recommended in the settlement agreement. The new rates will become effective on April 1, 2021.	Settlement agreement approved February 2021
Washington Gas - Maryland	August 2020	US$27 million increase in base rates, including US$6 million currently collected through the Strategic Infrastructure Development Enhancement Plan (STRIDE) surcharges for system upgrades. Therefore, the incremental amount of the base rate increase requested is approximately US$21 million.	Washington Gas filed this rate case on August 28, 2020. On August 31, 2020, the PSC of MD docketed the application and assigned the case to the Public Utility Law Judge (PULJ) division. On September 28, 2020, the PULJ division held a prehearing conference and established a procedural schedule which anticipates a final decision on or about March 26, 2021. On December 8, 2020, Washington Gas filed rebuttal testimony. On February 12, 2021, the PULJ issued a Proposed Order in the Case and an ERRATA filing correcting of the Proposed Order on February 19, 2021. The Proposed Order, as corrected, authorizes Washington Gas increase its Maryland natural gas distribution rates by approximately US$13 million (including US$5 million for the STRIDE surcharge), reflecting a return of equity of 9.70 percent. Appeals are due February 26, 2021 with an order following. Washington Gas expects new rates to be implemented in late March of 2021.	Expected late Q1 2021

AltaGas Ltd. – 2020 MD&A and Financial Statements - 36

COVID-19 Related Orders

On March 16, 2020, the Council of the District of Columbia (DC Council) passed legislation prohibiting the disconnection of electric and gas services for non-payment of fees during a public health emergency. The Mayor of the District of Columbia's public health emergency declaration and all related orders have been further extended to March 31, 2021, and the prohibition on disconnection is effective for 15 days following the end of the public health emergency. On April 15, 2020, the PSC of DC issued an order authorizing Washington Gas to establish a regulatory asset to capture and track the incremental costs related to COVID-19 that were prudently incurred beginning March 11, 2020.

On March 16, 2020, the Governor of Maryland issued an Executive Order which ordered regulated utilities to cease disconnections and billing of late fees for residential customers through May 1, 2020, which was subsequently amended to extend the order through August 31, 2020. On September 22, 2020, the PSC of MD took action that had the effect of extending the moratorium on service disconnections through November 15, 2020. Due to the winter moratorium on disconnections (November 1 to March 31), this has the effect of delaying residential terminations until April 1, 2021. On April 9, 2020, the PSC of MD issued an order and authorized each utility company to establish a regulatory asset to record the effects of incremental collection and other costs related to COVID-19 prudently incurred beginning on March 16, 2020. On August 27 and 28, 2020, the PSC of MD held Public Conference (PC) 53 to review the impacts of the Executive Order on utilities and the services they provide. On August 31, 2020, the PSC of MD issued an order directing that: (1) Utilities may not engage in service terminations and/or charge late fees until October 1, 2020 and any notices of termination for residential accounts sent before October 1, 2020 are invalid; (2) a Public Service Company must give notice of at least 45 days before terminating service on a residential account; (3) structured payment plans offered by Public Service Companies to residential customers in arrears or unable to pay must allow a minimum of 12 months to repay, with that period extending to 24 months for customers certified as low income; (4) Public Service Companies are prohibited from collecting or requiring down payments or deposits as a condition of beginning a payment plan by any residential customer; and (5) Public Service Companies are prohibited from refusing to negotiate or denying a payment plan to a residential customer receiving service because the customer failed to meet the terms and conditions of an alternate payment plan during the past 18 months. As requested by the PSC of MD, investor-owned utilities in Maryland filed a joint proposed Arrearage Management Program (AMP) plan on October 7, 2020, which was followed by a legislative style hearing in November 2020. On December 21, 2020, the PSC of MD rejected the proposed AMP plan. It will continue to monitor the customer arrearage data provided by utilities, and may revisit this issue in the future.

On March 16, 2020, the State Corporation Commission of Virginia (SCC of VA) issued an order which prohibited disconnections of electricity, gas, water, and sewer utility services during the coronavirus public health emergency, and established certain consumer protection measures. While the SCC of VA order was extended, the disconnection order, but not the consumer protections expired on October 5, 2020. However, following the expiration of the disconnection order, on October 16, 2020, the Virginia General assembly approved legislation that would extend the disconnection prohibition for residential customers for nonpayment of bills or fees until the Governor determines the prohibition does not need to remain in place or until at least 60 days after the state of emergency declared on March 12, 2020 ends, whichever is sooner. The legislation also codified the consumer protection plans, requiring utilities to offer customers in arrears fee-free repayment plans without deposit or eligibility requirements. The legislation became effective in November 2020. On April 29, 2020, the SCC of VA issued an order approving a request from Washington Gas and other Virginia utilities to create a regulatory asset to record incremental prudently incurred costs and suspended late payment fees attributable to the COVID-19 pandemic. The October 16, 2020 legislation approved by the general assembly established certain reporting requirements for utilities to report bad debt information and provides utilities with certain exemptions from such requirements based on a utilities' particular facts and circumstances. On December 8, 2020, Washington Gas was awarded $US7.7 million under the Virginia CARES Relief Funding Award, to use for customer arrearages. Virginia customers need to meet the criteria established by the program to get the funds. Any unused funds will be returned to the SCC of VA by December 10, 2021.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 37

On April 10, 2020, the Governor of Alaska signed Senate Bill 241, which allows certificated utilities to record a regulatory asset for extraordinary costs and uncollectible residential utility bills that result from the COVID-19 public health disaster emergency declared by the governor on March 11, 2020. The determination as to whether an extraordinary expense resulted from the COVID-19 emergency is subject to approval by the RCA before recovery occurs through future rates. In response to Senate Bill 241, on April 15, 2020, the RCA opened an information docket to gather information including how utilities are dealing with COVID-19 and its effects. It will also discuss specific sections of Senate Bill 241 regarding deadlines for Commission actions and regulatory assets in a later public meeting.

On April 15, 2020, the MPSC issued an order for all utilities which allows for regulatory asset accounting to capture bad debts in excess of what is in approved rates. Incremental cost recovery was not addressed in the order; however, utilities filed comments and reply on April 30, 2020 and May 13, 2020, respectively, on what extraordinary costs, costs savings, and incremental revenues related to COVID-19 should be considered by the MPSC and how those costs should be tracked. In addition, the order included a list of additional customer protection requirements. On July 23, 2020, the MPSC issued an order asking that any rate-regulated utility seeking recovery of COVID-19 related expenses beyond uncollectible expenses make an informational filing with the MPSC no later than November 2, 2020. SEMCO Gas did not establish a regulatory asset for bad debts since the bad debt expense is not expected to exceed the level approved in the last rate case proceeding. Furthermore, SEMCO Gas determined that the benefit would be de minimis to proceed with filing for the recovery for the incremental COVID-19 costs considering the legal fees associated with completing such a regulatory filing.

Midstream

Operating Statistics

	Three Months Ended December 31		Year Ended December 31
	2020	2019	2020	2019
RIPET export volumes (Bbls/d) (1) (3)	37,782	36,394	39,285	35,446
Ferndale export volumes (Bbls/d) (2) (3)	33,979	—	33,979	—
Total inlet gas processed (Mmcf/d) (3)	1,409	1,413	1,357	1,407
Extraction ethane volumes (Bbls/d) (3)	30,766	25,951	28,018	23,826
Extraction NGL volumes (Bbls/d) (3) (4)	34,199	32,313	32,206	34,054
Fractionated volumes (Bbls/d) (3)	27,026	20,310	23,559	20,159
Frac spread - realized ($/Bbl) (3) (5)	13.95	16.54	14.37	17.47
Frac spread - average spot price ($/Bbl) (3) (6)	9.33	8.29	5.42	11.05
Propane Far East Index (FEI) to Mont Belvieu spread (US$/Bbl) (7)	15.01	17.95	11.72	14.88
Natural gas optimization inventory (Bcf)	39.3	41.4	39.3	41.4

(1)Represents propane volumes exported at RIPET since facility was placed into service in May 2019.

(2)Represents propane and butane volumes exported at Ferndale for the period after close of the Petrogas Acquisition on December 15, 2020.

(3)Average for the period.

(4)NGL volumes refer to propane, butane, and condensate.

(5)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.

(6)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.

(7)Average propane price spread between FEI and Mont Belvieu TET commercial index for the period beginning May 2019.

Propane volumes exported to Asia at RIPET for the three months ended December 31, 2020 averaged 37,782 Bbls/d compared to 36,394 Bbls/d for the same period in 2019. There were 6 full shipments and one partially loaded shipment in the

AltaGas Ltd. – 2020 MD&A and Financial Statements - 38

fourth quarter of 2020, compared to six shipments in the same period in 2019. Propane and butane export volumes at Ferndale averaged 33,979 Bbls/d, with two shipments to Asia for the period subsequent to close of the Petrogas Acquisition.

Propane volumes exported to Asia at RIPET for the year ended December 31, 2020 averaged 39,285 Bbls/d compared to 35,446 Bbls/d for the same period in 2019. There were 27 shipments during the year ended December 31, 2020 compared to 15 shipments in the same period of 2019. Higher global export volumes and shipments were a result of RIPET operating for the full year in 2020, an increase in the amount of cargoes sold on the spot market, and a new term contract effective September 2019. Propane and butane export volumes at Ferndale averaged 33,979 Bbls/d, with 2 shipments to Asia for the period subsequent to close of the Petrogas Acquisition.

Inlet gas processing volumes for the fourth quarter of 2020 decreased by 4 Mmcf/d compared to the same quarter in 2019. Lower inlet gas processing volumes in the fourth quarter of 2020 were a result of lower inlet volumes at Younger due to a scheduled turnaround in September 2020 which was extended until late October, and lower inlet volumes at EEEP. The decrease was partially offset by additional volumes from the newly constructed Townsend Deep Cut facility, which was placed in-service in May 2020, and higher inlet volumes at JEEP, Gordondale, and the Blair Creek facilities.

Inlet gas processing volumes for the year ended December 31, 2020 decreased by 50 Mmcf/d compared to the same period in 2019. Factors negatively impacting inlet gas processing volumes in the year ended December 31, 2020 included lower inlet volumes at the extraction facilities, lower take-or-pay processed volumes at the Townsend Shallow Cut facilities, and the disposal of certain non-core facilities in February 2019. The decrease was partially offset by volumes from the Townsend Deep Cut facility, which was placed in-service in May 2020, volumes from the Nig Creek facility, which was placed in-service in September 2019, and higher inlet volumes at the Gordondale facility.

Average ethane production volumes for the fourth quarter of 2020 increased by 4,815 Bbls/d, while average NGL production volumes increased by 1,886 Bbls/d compared to the same quarter in 2019. Higher ethane volumes were a result of additional contracted ethane volumes at the extraction facilities. Higher extracted NGL volumes were a result of additional extracted NGL volumes from the Townsend Deep Cut facility, which was placed in-service in May 2020, partially offset by lower inlet volumes at certain extraction facilities, primarily related to the Younger facility due to a planned turnaround, and lower inlet volumes at the Townsend Shallow Cut facilities.

Average ethane production volumes for the year ended December 31, 2020 increased by 4,192 Bbls/d, while average NGL production volumes decreased by 1,848 Bbls/d compared to 2019. Higher ethane volumes were a result of additional contracted ethane volumes at the extraction facilities. Lower extracted NGL volumes were a result of lower inlet volumes at the Townsend Shallow Cut facilities and at the extraction facilities, mainly related to the Younger facility, partially offset by additional extracted NGL volumes from the Townsend Deep Cut facility which was placed in-service in May 2020.

Fractionation volumes for the fourth quarter of 2020 increased by 6,716 Bbls/d compared to the same quarter in 2019. Higher fractionation volumes were a result of the North Pine expansion and additional liquids volumes from the NEBC facilities including the Townsend Deep Cut facility. The increase was partially offset by lower trucked-in volumes at Harmattan, and lower extracted NGLs at Younger due to lower inlet and a turnaround in September that was extended until October.

Fractionation volumes for the year ended December 31, 2020 increased by 3,400 Bbls/d compared to the same period in 2019. Higher fractionation volumes were a result of the North Pine expansion and additional liquids volumes from the NEBC facilities. The increase was partially offset by lower trucked-in volumes at Harmattan, and lower extracted NGLs at the Harmattan and Younger facilities due to lower inlet.

Natural gas optimization inventory as at December 31, 2020 was 39.3 Bcf (December 31, 2019 - 41.4 Bcf). The decrease in natural gas optimization inventory was primarily due to higher withdrawals of inventory in the fourth quarter of 2020 as a result of favorable natural gas prices.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 39

Three Months Ended December 31

The Midstream segment reported normalized EBITDA of $128 million in the fourth quarter of 2020, compared to $179 million in the same quarter in 2019. The decrease in normalized EBITDA was mainly due to unfavorable realized storage margins at WGL Midstream, lower merchant volumes and realized margins at RIPET (inclusive of hedges), lower NGL marketing margins, lower realized frac spreads and exposed NGL volumes, and the impact of the sale of WGL Midstream's indirect non-operating interest in Central Penn in November 2019. These were partially offset by contributions from Petrogas for the period after acquisition, higher tolling volumes at RIPET, higher processed volumes at the NEBC facilities, higher fractionation and liquids handling revenues due to NEBC growth projects placed into service, and additional contracted ethane volumes at the extraction facilities. During the fourth quarter of 2020, for the period prior to close of the Petrogas Acquisition, AltaGas recorded equity earnings of $8 million from Petrogas compared to $31 million in the same quarter in 2019. Petrogas' export deliveries from Ferndale and volumes transacted through the terminals were at similar levels as in the fourth quarter of 2019. Industry conditions continued to impact the commodity margins and activity levels in Petrogas' other business segments. In addition, in the fourth quarter of 2019, Petrogas earnings included a large one-time payment related to the termination of a customer contract. On December 15, 2020, AltaGas acquired an additional 37 percent of Petrogas, resulting in AltaGas' ownership of Petrogas being increased to approximately 74 percent. As such, Petrogas' results have been consolidated for the period subsequent to close (please refer to the Acquisition of Petrogas section of this MD&A for additional information).

In the fourth quarter of 2020, the Midstream segment recognized a gain on it's previously held equity investment in AIJVLP of approximately $22 million, as well as a dilution loss and other adjustments to equity investments related to the acquisition of Petrogas of $26 million. In addition, in the fourth quarter of 2020, the Midstream segment recognized pre-tax provisions on assets of approximately $104 million ($79 million after-tax) primarily related to the Alton Natural Gas Storage Project. In the fourth quarter of 2019, the Midstream segment recognized a pre-tax loss of approximately $12 million on the disposition of equity investments, primarily related to WGL Midstream's indirect non-operating interest in Central Penn. In addition, in the fourth quarter of 2019, the Midstream segment recognized a pre-tax provision of $34 million related to the Pouce Coupe sour gas treatment facility in Alberta.

Midstream Hedges

	Three Months Ended December 31
	2020	2019
Frac exposed volumes (Bbls/d)	9,277	11,525
NGL volumes hedged (Bbls/d)	10,068	6,228
Average price of NGL volumes hedged ($/Bbl) (1)	26	40
Average RIPET volumes hedged (Bbls/d)	25,913	23,070
Average FEI to Mt Belvieu spread for volumes hedged (US$/Bbl)	9.05	10.28
Average Ferndale volumes hedged (Bbls/d) (2)	33,717	—
Average FEI to Conway spread for Ferndale volumes hedged (US$/Bbl) (2)	13.05	—

(1)Excludes basis differential

(2)For the period subsequent to close of the Petrogas Acquisition on December 15, 2020.

In the fourth quarter of 2020, AltaGas’ total frac exposed volumes were 9,277 Bbls/d (2019 - 11,525 Bbls/d) and realized frac spread (inclusive of hedges) was $13.95/bbl (2019 - $16.54/bbl).

Year Ended December 31

The Midstream segment reported normalized EBITDA of $473 million in the year ended December 31, 2020, compared to $531 million in 2019. Factors negatively impacting normalized EBITDA in the year ended December 31, 2020 included the impact of the sale of WGL Midstream's indirect non-operating interest in Central Penn in November 2019, the impact of the

AltaGas Ltd. – 2020 MD&A and Financial Statements - 40

sale of WGL Midstream's interest in Stonewall in May 2019, lower storage spreads and withdrawals at WGL Midstream due to lower commodity prices, lower NGL extracted and trucked in volumes, lower realized frac spreads (inclusive of hedges), and lower NGL marketing margins. These were partially offset by higher AFUDC related to Mountain Valley, higher fractionation and liquids handling revenues due to NEBC growth projects placed into service, higher processed volumes at certain NEBC facilities, additional contracted ethane volumes at the extraction facilities, contributions from Petrogas for the period after acquisition, contributions from RIPET which was placed in-service in May 2019, and favorable transportation margins at WGL Midstream. During the year ended December 31, 2020, for the period prior to close of the Petrogas Acquisition, AltaGas recorded equity earnings of $29 million from Petrogas, compared to $75 million in 2019. The decrease in earnings from Petrogas was primarily due to lower commodity prices in 2020, as well as the absence of a one-time payment related to the termination of a customer contract in the fourth quarter of 2019. On December 15, 2020, AltaGas acquired an additional 37 percent of Petrogas, resulting in AltaGas' ownership of Petrogas being increased to approximately 74 percent. As such, Petrogas' results have been consolidated for the period subsequent to close (please refer to the Acquisition of Petrogas section of this MD&A for additional information).

In 2020, the Midstream segment recognized the previously mentioned gain on the re-measurement of it's previously held equity investment in AIJVLP of approximately $22 million and a dilution loss and other adjustments to equity investments related to the acquisition of Petrogas of $42 million. In 2020, the Midstream segment recognized pre-tax provisions on assets of approximately $106 million related to the previously mentioned provisions recognized in the fourth quarter of 2020 and land parcels located near the Harmattan gas processing plant. In addition, in 2020 the Midstream segment recognized a pre-tax provision on equity investments of approximately $7 million related to the Constitution pipeline project which was cancelled in February 2020. In 2019, the Midstream segment recognized a pre-tax gain of $34 million on the disposition of WGL Midstream's interest in Stonewall, a pre-tax gain of $5 million on the sale of certain non-core Midstream processing facilities, and the previously mentioned loss on equity investments recognized in the fourth quarter of 2019. In 2019, the Midstream segment recognized a pre-tax provision on equity investments of approximately $44 million related to WGL Midstream's indirect, non-operating interest in Central Penn which was sold in November 2019 and the previously mentioned provision on assets recognized in the fourth quarter of 2019.

Midstream Hedges

	Year Ended December 31
	2020	2019
Frac exposed volumes (Bbls/d)	8,952	10,534
NGL volumes hedged (Bbls/d)	9,412	6,228
Average price of NGL volumes hedged ($/Bbl) (1)	29	40
Average RIPET volumes hedged (Bbls/d)	26,801	21,106
Average FEI to Mt Belvieu spread for volumes hedged (US$/Bbl)	9.97	10.56
Average Ferndale volumes hedged (Bbls/d) (2)	33,717	—
Average FEI to Conway spread for Ferndale volumes hedged (US$/Bbl) (2)	13.05	—

(1)Excludes basis differential

(2)For the period after close of the Petrogas Acquisition on December 15, 2020.

For the year ended December 31, 2020, AltaGas’ total frac exposed volumes were 8,952 Bbl/d (2019 - 10,534 Bbl/d) and realized frac spread (inclusive of hedges) was $14.37/bbl (2019 - $17.47/bbl).

AltaGas Ltd. – 2020 MD&A and Financial Statements - 41

Corporate/Other

Three Months Ended December 31

In the Corporate/Other segment, normalized EBITDA for the fourth quarter of 2020 was $5 million, compared to a loss of $3 million in the same quarter in 2019. The increase was mainly due to earnings from WGL's remaining projects in its design build and distributed generation business, which was partially offset by the impact of asset sales, including Pomona in July 2020 and Ripon in August 2020.

In the fourth quarter of 2019, the Corporate/Other segment recognized a pre-tax gain of $68 million on certain U.S. distributed generation projects which were sold in the third quarter of 2019 but transferred to the purchaser in the fourth quarter of 2019. In addition, in the fourth quarter of 2019, the Corporate/Other segment recognized pre-tax provisions of $380 million related to various long-lived assets.

Year Ended December 31

In the Corporate/Other segment, normalized EBITDA for the year ended December 31, 2020 was $49 million, compared to $73 million in 2019. The decrease was mainly due to the impact of asset sales, including the U.S. distributed generation assets in September 2019, certain non-core power assets in February 2019, the Northwest Hydro facilities in January 2019, Pomona in July 2020, Ripon in August 2020, and biomass investments in the third quarter of 2019, partially offset by recoveries related to CEWS, earnings from WGL's remaining projects in its design build and distributed generation business, a shorter planned spring outage at the Blythe facility compared to 2019, lower employee salary expenses, and lower expenses related to employee incentive plans as a result of the decreasing share price in 2020.

In 2020, the Corporate/Other segment recognized a pre-tax gain of $9 million on certain U.S. distributed generation projects which were sold in 2019 but transferred to the purchaser in 2020, a pre-tax gain of $5 million on the disposition of Pomona, and a pre-tax gain of $3 million on the disposition of Ripon. In addition, in 2020, the Corporate/Other segment recognized a pre-tax provision of approximately $3 million related to certain U.S. distributed generation projects which had not yet transferred to the purchaser. In 2019, the Corporate/Other segment recognized a pre-tax gain of $100 million on the disposition of the U.S. distributed generation assets, a pre-tax gain of $688 million on the sale of the remaining interest in the Northwest Hydro facilities, a pre-tax loss of $6 million on the sale of Canadian non-core power assets, a pre-tax loss of $1 million on the sale of a WGL Energy Systems financing receivable, and the previously mentioned gains on dispositions recorded in the fourth quarter of 2019. In addition, in 2019, the Corporate/Other segment recognized a pre-tax provision on equity investments of $2 million related to biomass investments which were sold in the third quarter of 2019, a pre-tax provision of $1 million related to a capital spare turbine in storage which was also sold in the third quarter of 2019, and the previously mentioned provisions on assets recognized in the fourth quarter of 2019.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 42

Invested Capital

	Three Months Ended December 31, 2020
($ millions)	Utilities		Midstream		Corporate/Other		Total
Invested capital:
Property, plant and equipment	$	243	$	50	$	2	$	295
Intangible assets	1		1		1		3
Long-term investments	—		76		—		76
Business acquisition	—		715		—		715
Contributions from non-controlling interest	—		(2)		—		(2)
Net invested capital	$	244	$	840	$	3	$	1,087

	Three Months Ended December 31, 2019
($ millions)	Utilities		Midstream		Corporate/ Other		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		4		260
Disposals:
Property, plant and equipment	(1)		—		—		(1)
Equity method investments	—		(812)		—		(812)
Net invested capital	$	165	$	(722)	$	4	$	(553)

During the fourth quarter of 2020, AltaGas’ invested capital was $1,087 million, compared to $260 million in the same quarter in 2019. The increase in invested capital was primarily due to cash paid for the Petrogas Acquisition, contributions to long-term investments, and higher additions to property, plant and equipment, partially offset by lower additions to intangible assets.

The increase in additions to property, plant and equipment in the fourth quarter of 2020 was mainly due to capital expenditures related to system betterment and accelerated pipeline replacement programs at Washington Gas, construction costs related to the Nig Creek facility expansion project, and a turnaround at the Younger facility, partially offset by the absence of construction costs related to the Marquette Connector Pipeline which was placed in-service in December 2019, and the absence of construction costs relating to the NEBC pipeline projects, most of which were completed in the first half of 2020. The disposal of equity method investments in the fourth quarter of 2019 related to the disposition of Central Penn in November 2019.

The invested capital in the fourth quarter of 2020 included maintenance capital of $18 million (2019 ‑ $3 million) in the Midstream segment and $nil (2019 ‑ $1 million) related to remaining power assets in the Corporate/Other segment. Maintenance capital incurred in the fourth quarter of 2020 primarily related to the turnaround at the Younger facility.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 43

	Year Ended December 31, 2020
($ millions)	Utilities		Midstream		Corporate/Other		Total
Invested capital:
Property, plant and equipment	$	740	$	139	$	20	$	899
Intangible assets	3		3		4		10
Long-term investments	—		140		—		140
Business acquisition	—		715		—		715
Contributions from non-controlling interest	—		(7)		—		(7)
Invested capital	743		990		24		1,757
Disposals:
Property, plant and equipment	—		(3)		(71)		(74)
Equity method investments	(369)		(7)		—		(376)
Net invested capital	$	374	$	980	$	(47)	$	1,307

	Year Ended December 31, 2019
($ millions)	Utilities		Midstream		Corporate/ Other		Total
Invested capital:
Property, plant and equipment	$	841	$	438	$	39	$	1,318
Intangible assets	23		5		9		37
Long-term investments	—		179		—		179
Contributions from non-controlling interest	—		(41)		—		(41)
Invested capital	864		581		48		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)	$	(2,296)	$	(2,130)

During the year ended December 31, 2020, AltaGas’ invested capital was $1.8 billion, compared to $1.5 billion in 2019. The increase in invested capital was primarily due to cash paid for the Petrogas Acquisition, lower contributions from non-controlling interests, and a capital contribution made to AIJVLP related to a cash call in the first quarter of 2020, partially offset by 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 year ended December 31, 2020 was mainly due to the absence of construction costs related to RIPET which was placed in-service in May 2019, the absence of construction costs related to Nig Creek which was placed in-service September 2019, the absence of capital expenditures related to the U.S. distributed generation assets which were sold in September 2019, lower capital expenditures related to the Townsend 2B expansion, North Pine expansion, and NEBC pipeline projects which were placed in-service in the first half of 2020, and the absence of construction costs related to the Marquette Connector Pipeline which was placed in-service in December 2019. These were partially offset by increased expenditures related to the accelerated pipeline replacement programs at Washington Gas and SEMCO, and construction of the Nig Creek expansion project. The disposals of property, plant and equipment in the year ended December 31, 2020 primarily related to the remaining proceeds received from the disposition of the U.S. distributed generation assets and the disposition of Pomona and Ripon in the third quarter of 2020. In the year ended December 31, 2019, disposals of property, plant and equipment primarily related to the disposition of the U.S. distributed generation assets, the Northwest Hydro facilities, and non-core Canadian Midstream and Power assets. The disposal of equity method investments in the year ended December 31, 2020 related to the disposition of ACI, while in the year ended December

AltaGas Ltd. – 2020 MD&A and Financial Statements - 44

31, 2019 the disposals of equity method investments related to the disposition of Stonewall, biomass investments, and the previously mentioned disposal of Central Penn in the fourth quarter of 2019.

The invested capital for the year ended December 31, 2020 included maintenance capital of $22 million (2019 ‑ $6 million) in the Midstream segment and $14 million (2019 ‑ $20 million) related to remaining power assets in the Corporate/Other segment. The increase in maintenance capital for the Midstream segment was primarily due to increased turnaround expenditures. The decrease in maintenance capital for the Corporate/Other segment was primarily due to lower maintenance expenditures at the Blythe facility.

Risk Management

Risks Related to COVID-19

As the COVID-19 pandemic continues, governments in the jurisdictions where AltaGas operates have maintained measures designed to contain the outbreak, including business closures and restrictions, travel limitations and border closings, quarantines, and restrictions on gatherings and events. The magnitude, outcome, and duration of the pandemic remains uncertain. As a result, it is not currently possible to accurately quantify the total potential impact of the pandemic on AltaGas’ operations or financial results.

AltaGas, with its subsidiaries, activated its pandemic response team to monitor developments related to COVID-19 and to ensure the Corporation was responding swiftly and appropriately. Continuity plans and preparedness measures have been implemented at each of AltaGas’ businesses, with safeguarding the well-being of its personnel as the primary concern. To date, AltaGas has been able to respond to the COVID-19 related challenges with minimal disruption to its operations and business.

AltaGas has identified the following as potential direct or indirect impacts to its business and operations from the pandemic:

▪Key employees and personnel: Widespread inability of AltaGas' workforce or that of the Corporation's contractors to perform their duties would have an adverse impact on AltaGas' ability to continue normal operations in the Utilities, Midstream and Corporate/Other segments. To date, AltaGas has not experienced unavailability of a significant portion of its personnel as a result of COVID-19 related concerns;

▪Return to work: As AltaGas reintegrates its personnel to its workplace, it may incur additional costs to adapt the workplace to meet applicable health and safety requirements. Shortages in personal protective equipment (PPE), the occurrence of additional waves of the virus, or delays in the availability or rollout of vaccines may require AltaGas to revise or delay such reintegration plans. To the extent that it is unable to effectively protect its workforce against the transmission of the virus, AltaGas may be forced to slow or reverse its reintegration efforts and could face allegations of liability;

▪IT infrastructure, privacy and cyber security: Increased volume and sophistication of targeted cyber-attacks have been seen since the declaration of the global pandemic. Pandemic-adjusted operations, such as work from home arrangements and remote access to the Corporation's systems, may pose heightened risk of cyber security and privacy breaches and may put additional stress on the Corporation's IT infrastructure. A failure of such infrastructure could severely limit AltaGas' ability to conduct ordinary operations. To date, AltaGas’ systems have functioned capably, and it has not experienced a material impact to its operations as a result of an IT infrastructure issue;

▪Adverse impacts on market fundamentals and access to capital: AltaGas has seen an impact from COVID-19 related factors in relation to lower margins in the Retail Energy Marketing business, cancellation of late fees and related charges along with the inability to disconnect customers, impacts to income from Petrogas due to lower commodity prices, and increased cost with regard to COVID-19 related costs to the business. The impact of these factors was not material to AltaGas' 2020 financial performance and is currently not expected to be material to the 2021 financial

AltaGas Ltd. – 2020 MD&A and Financial Statements - 45

performance of AltaGas. While access to capital could be negatively impacted by the global impact of the virus, at this point, AltaGas anticipates that it has adequate access to capital to execute its 2021 business plans; and

▪Counterparty and supplier risk: increased exposure that contract counterparties and suppliers could fail to meet their obligations to AltaGas. Such non-performance by a significant counterparty or supplier could adversely affect AltaGas' operations and financial results. To date, any cases of force majeure invoked by counterparties related to the AltaGas’ assets as a result of COVID-19 have not been material.

To the extent these risks materialize, the Corporation’s ability to carry out its business plans for 2021 may be adversely impacted.

Political Uncertainty and Civil Unrest

Uncertainty exists with regard to the political climate in the jurisdictions where AltaGas operates. Changes in social, political, regulatory, or economic conditions, or in laws and policies governing environment, development, tax, foreign trade, investment or energy could materially adversely affect AltaGas' business and operations.

Recently there have been significant incidents of civil unrest in areas where AltaGas operates. To the extent that civil unrest is accompanied by disruption to transportation routes, damage to infrastructure, violence or destruction, AltaGas' personnel, physical facilities, and operations may be placed at risk and financial and operational results may be adversely impacted.

Other

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, 2020 and December 31, 2019, the fair values of the Corporation’s derivatives were as follows:

($ millions)	December 31, 2020		December 31, 2019
Natural gas	$	(69)	$	(77)
Energy exports	(31)		(75)
NGL frac spread	(6)		(2)
Power	(29)		(12)
Crude oil and NGLs	1		—
Foreign exchange	23		—
Net derivative liability	$	(111)	$	(166)

Summary of Risk Management Contracts

Commodity Price Contracts

The Corporation executes gas, power, LPG, crude oil, ocean freight, 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: 1) designated as “normal purchases and normal sales”; 2) do not qualify as derivative instruments due to the significance of their notional amount relative to the applicable liquid markets; or 3) 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 commodity contracts that qualify as derivatives was calculated using estimated forward prices based

AltaGas Ltd. – 2020 MD&A and Financial Statements - 46

on published sources for the relevant period. AltaGas has not elected hedge accounting for any of its derivative contracts currently in place. For AltaGas’ Midstream segment, changes in the fair value of these derivative contracts are recorded in the Consolidated Statements of Income in the period in which the change occurs. For the 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 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, 2020 was approximately $5/Bbl (2019 – $11/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, 2020 was approximately $14/Bbl inclusive of basis differentials (2019 - $17/Bbl).

▪For 2021, AltaGas estimates an average of approximately 9,000 Bbls/d of NGL will be exposed to frac spreads prior to hedging activities. Hedges are in place for approximately 97 percent of frac exposed NGL volumes including internal hedges.

▪At RIPET, propane price margins are protected through AltaGas' comprehensive hedging program. Approximately one third of 2021 expected volumes are contracted under tolling arrangements. For the remaining volumes, approximately 67 percent are financially hedged at an FEI to Mont Belvieu spread of approximately US$10/Bbl. Approximately 80 percent of RIPET’s propane export volumes are hedged for 2021.

▪At Ferndale, AltaGas is exposed to the propane and butane price differentials between North American Indices and the Far East Index for contracts not under tolling arrangements or naturally hedged supply agreements. AltaGas estimates an average of approximately 32,000 Bbls/d will be exposed to these price differentials in 2021. To date for 2021, AltaGas has hedges in place for approximately 12 percent of these exposed propane and butane volumes at an average FEI to Conway spread of US$14/Bbl for propane and at an average FEI to purchase price spread of US$28/Bbl for butane. AltaGas estimates that an average of approximately 9,000 Bbls/d or 21 percent of 2021 forecast exports from Ferndale are under tolling arrangements or naturally hedged supply agreements.

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.

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. Additionally, to serve retail customers, AltaGas enters into both physical and financial contracts for the purchase and sale of electricity and natural gas.

The Corporate/Other segment has various fixed-for-floating power purchase and sale contracts in the Alberta market, which are expected to be settled over the next three years.

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.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 47

▪As at December 31, 2020, Management has not designated any outstanding U.S. dollar denominated long-term debt to hedge against the currency translation effect of its foreign investments (December 31, 2019 - US$300 million).

▪For the year ended December 31, 2020, AltaGas incurred an after-tax unrealized loss of $9 million arising from the translation of debt in other comprehensive income (2019 - after-tax unrealized gain of $60 million).

In connection with the Petrogas Acquisition (please refer to the Acquisition of Petrogas section of this MD&A for additional information), AltaGas acquired various commodity and financial derivative instruments, including the following foreign exchange contracts which are outstanding as at December 31, 2020:

Foreign exchange forward contract	Notional Amount (US$ millions)	Duration	Weighted average foreign exchange rate	Fair Value
Forward USD sales	US$29	Less than one year	1.3591	$	3
Forward USD purchases	US$356	Less than one year	1.2824	$	(3)
Foreign exchange swaps (sales)	US$410	Less than one year	1.3322	$	23

For the year ended December 31, 2020, AltaGas recorded an after-tax realized gain of $1 million on all foreign exchange forward contracts.

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, 2020, a pre-tax loss of $3 million (2019 - pre-tax loss of $2 million) was recorded related to heating degree day (HDD) and cooling degree day (CDD) instruments.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 48

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:

	Three Months Ended December 31				Year Ended December 31
($ millions)	2020		2019		2020		2019
Natural gas	$	30	$	14	$	32	$	23
Energy exports	(29)		(65)		10		(87)
Crude oil and NGLs	4		—		4		—
NGL frac spread	(13)		(11)		(5)		(17)
Power	(11)		(2)		(15)		(5)
Foreign exchange	(5)		—		(5)		1
	$	(24)	$	(64)	$	21	$	(85)

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
COVID-19	• Activation of pandemic response team to monitor developments related to COVID-19
	• Implement continuity plans and preparedness measures to ensure safe and reliable operations
	• Monitor and implement compliance with regulatory requirements in all jurisdictions
	• Recovery mechanisms in place to track COVID related incremental costs
	• A phased approach to return to work is being managed in keeping with requirements in all jurisdictions with oversight by EHS and senior leadership
	• Designed and delivered tools and information to support workforce resilience through pandemic
Integration of Petrogas	• Established cross-functional Petrogas integration team focused on effectively integrating operations and realizing efficiencies
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

AltaGas Ltd. – 2020 MD&A and Financial Statements - 49

Risks	Strategies and Organizational Capability to Mitigate Risks
Health and Safety	• Strong process safety management systems
	• Pipeline and asset integrity programs in place
	• Accelerated replacement of mature pipeline infrastructure
	• Preventative and remedial measures to address leak rates within Washington Gas’ distribution system
	• Continuous process improvement strategy employed
	• Comprehensive Environmental, Health and Safety management system
	• Purchase and maintain general liability and business interruption insurance
Environment and Climate-related	• Measure and 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
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

AltaGas Ltd. – 2020 MD&A and Financial Statements - 50

Risks	Strategies and Organizational Capability to Mitigate Risks
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
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, LPG, 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	• Initiatives focused on talent development, employee engagement, and diversity and inclusion among workforce
	• Positive employee relations to retain existing talent and maintain strong relations with labor unions

AltaGas Ltd. – 2020 MD&A and Financial Statements - 51

Risks	Strategies and Organizational Capability to Mitigate Risks
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
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
Political uncertainty and civil unrest	• Monitor changes in law
	• Operational procedures in place including physical security, emergency response
	• Ongoing communication by management with employees in all operational areas

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

AltaGas Ltd. – 2020 MD&A and Financial Statements - 52

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)	2020		2019
Cash from operations	$	773	$	616
Investing activities	(1,211)		2,184
Financing activities	392		(2,874)
Decrease in cash, cash equivalents, and restricted cash	$	(46)	$	(74)

Cash From Operations

Cash from operations increased by $156 million for the year ended December 31, 2020 compared to 2019, primarily due to higher net income after taxes (after adjusting for non-cash items) and favorable variances in the net change in operating assets and liabilities, partly offset by lower distributions from equity investments. The majority of the variance in net change in operating assets and liabilities was due to increased cash flows from accounts payable and accrued liabilities driven by asset sales and fluctuations in volumes and prices, and increased cash flows related to other current assets due to lower cash collateral posted with counterparties and lower prepaid expenses. These increases were partially offset by decreased cash flows from accounts receivable due to fluctuations in commodity prices and sales volumes, regulatory assets and liabilities primarily due to overall warmer weather experienced by the Utilities segment, refunds of certain regulatory liabilities to customers, and increases in non-weather related regulatory liabilities.

Working Capital

($ millions, except working capital ratio)	December 31, 2020		December 31, 2019
Current assets	$	2,497	$	2,196
Current liabilities	2,607		3,125
Working deficiency	$	(110)	$	(929)
Working capital ratio (1)	0.96		0.70

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

The increase in the working capital ratio was primarily due to increases in in accounts receivable, and decreases in short-term debt and the current portion of long-term debt, partially offset by increases in accounts payable and accrued liabilities, and decreases in prepaid expenses and other assets. AltaGas’ working capital will fluctuate in the normal course of business. The working capital deficiency is expected to be funded using cash flow from operations and available credit facilities as required.

Investing Activities

Cash used in investing activities for the year ended December 31, 2020 was $1.2 billion, compared to cash from investing activities of $2.2 billion in 2019. Investing activities for the year ended December 31, 2020 primarily included the cash payment, net of cash acquired, of $675 million for the Petrogas Acquisition, expenditures of approximately $843 million for property, plant, and equipment and intangible assets, $75 million related to the change in loan to an affiliate, and approximately $72 million of contributions to equity investments, which were partially offset by proceeds of $4 million from the sale of investments in publicly-traded entities, $376 million from the disposition of equity investments (primarily for the disposition of ACI), and proceeds of $74 million from the disposition of assets (net of transaction costs). Investing activities for the year ended December 31, 2019 included proceeds of $3.6 billion from asset sales completed in 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

AltaGas Ltd. – 2020 MD&A and Financial Statements - 53

expenditures of approximately $1.3 billion for property, plant, and equipment and intangible assets, and approximately $179 million of contributions to equity investments.

Financing Activities

Cash from financing activities for the year ended December 31, 2020 was $392 million, compared to cash used in financing activities of $2.9 billion in 2019. Financing activities for the year ended December 31, 2020 were primarily comprised of net repayments of short-term debt and repayments of long-term debt of $1.2 billion, dividends of $334 million, $200 million for the redemption of Series I Preferred Shares, and distributions to non-controlling interests of $28 million, partially offset by debt issuances of $2.0 billion, net issuances under credit facilities of $191 million, and contributions from non-controlling interests of $7 million. Financing activities for the year ended December 31, 2019 were primarily comprised of net repayments of short-term debt and repayments of long-term debt of $1.6 billion, net repayments under credit facilities of $1.9 billion, dividends of $334 million, distributions to non-controlling interests of $13 million, and the redemption of preferred shares of $38 million, partially offset by debt issuances of $889 million, net proceeds from the issuance of common shares of $68 million and contributions from non-controlling interests of $48 million. Total dividends paid to common and preferred shareholders of AltaGas for the year ended December 31, 2020 were $334 million (2019 - $334 million), of which $6 million was reinvested through the DRIP (2019 - $68 million). Beginning with the January dividend paid on February 17, 2020, dividend payments are no longer eligible for reinvestment by participating shareholders under the DRIP.

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.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 54

($ millions)	December 31, 2020		December 31, 2019
Short-term debt (1)	$	236	$	389
Current portion of long-term debt	360		923
Long-term debt (2)	7,626		5,928
Total debt	8,222		7,240
Less: cash and cash equivalents	(32)		(57)
Net debt	$	8,190	$	7,183
Shareholders' equity	7,041		7,215
Non-controlling interests	620		154
Total capitalization	$	15,851	$	14,552
Net debt-to-total capitalization (%)	52		49

(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 2020 Annual Consolidated Financial Statements for additional details. At December 31, 2020, the project financing balance excluded from short-term debt in above table was $20 million (December 31, 2019 - $71 million).

(2)Net of debt issuance costs of $43 million as at December 31, 2020 (December 31, 2019 - $36 million).

As at December 31, 2020, AltaGas’ total debt primarily consisted of outstanding medium-term notes (MTNs) of $4.0 billion (December 31, 2019 - $3.0 billion), WGL and Washington Gas long-term debt of $2.1 billion (December 31, 2019 - $2.4 billion), reflecting fair value adjustments on acquisition, SEMCO long‑term debt of $641 million (December 31, 2019 - $466 million), $934 million drawn under the bank credit facilities (December 31, 2019 - $643 million) and short-term debt of $256 million (December 31, 2019 - $460 million). In addition, AltaGas had $230 million of letters of credit outstanding (December 31, 2019 - $307 million).

As at December 31, 2020, AltaGas’ total market capitalization was approximately $5.2 billion based on approximately 279 million common shares outstanding and a closing trading price on December 31, 2020 of $18.72 per common share.

AltaGas' earnings interest coverage for the rolling twelve months ended December 31, 2020 was 2.8 times (twelve months ended December 31, 2019 – 3.2 times).

Credit Facilities ($ millions)	Borrowing capacity		Drawn at December 31, 2020		Drawn at December 31, 2019
AltaGas demand credit facilities (1) (2)	$	70	$	—	$	—
AltaGas revolving credit facilities (1) (2)	3,460		802		90
AltaGas term credit facility (1)	—		—		390
SEMCO Energy US$150 million credit facilities (1) (2)	191		80		163
WGL US$250 million revolving credit facility (1) (2) (3)	318		132		239
Washington Gas US$450 million revolving credit facility (1) (2) (3)	573		363		518
Petrogas revolving credit facilities	258		57		—
	$	4,870	$	1,434	$	1,400

(1)Amount drawn at December 31, 2020 converted at the month‑end rate of 1 U.S. dollar = 1.2732 Canadian dollar (December 31, 2019 - 1 U.S. dollar = 1.2988 Canadian dollar).

(2)All US$ borrowing capacity was converted at the December 31, 2020 U.S./Canadian dollar month-end exchange rate.

(3)Amounts drawn include commercial paper that is supported by the long term facilities. 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.

In addition to the facilities listed above, AltaGas has demand Letter of Credit facilities of $330 million. At December 31, 2020, there were letters of credit for $229 million (December 31, 2019 - $281 million) issued on these facilities and an additional $1 million (December 31, 2019 - $25 million) issued on the company's revolving credit facilities.

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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, 2020, commercial paper outstanding totaled $495 million for WGL and Washington Gas (December 31, 2019 – $757 million).

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, 2020 and December 31, 2019.

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, 2020
Bank debt-to-capitalization (1)	not greater than 65 percent	less than 52%
Bank EBITDA-to-interest expense (1) (2)	not less than 2.5x	greater than	4.5x
Bank debt-to-capitalization (SEMCO) (2) (3)	not greater than 60 percent	less than 45%
Bank EBITDA-to-interest expense (SEMCO) (2) (3)	not less than 2.25x	greater than	9.0x
Bank debt-to-capitalization (WGL) (4)	not greater than 65 percent	less than 46%
Bank debt-to-capitalization (Washington Gas) (4)	not greater than 65 percent	less than 49%

(1)Calculated in accordance with the Corporation’s US$1.2 billion credit facility agreement, which is available on SEDAR at www.sedar.com. The covenants are equivalent and applicable to all the Corporation’s committed credit facilities.

(2)Estimated, subject to final adjustments.

(3)Bank EBITDA-to-interest expense (SEMCO) and Bank debt-to-capitalization (SEMCO) are calculated based on SEMCO’s consolidated financial statements and are calculated similar to Bank debt-to-capitalization and Bank EBITDA-to-interest expense.

(4)WGL’s bank debt-to-capitalization ratio is calculated based on WGL’s consolidated financial statements.

On September 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, 2020, approximately $0.3 billion was available under the base shelf prospectus.

On February 22, 2021, a $2.5 billion base shelf prospectus for the issuance of certain types of future public debt and/or equity issuances was filed to replace the base shelf prospectus dated September 25, 2019. 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.

On January 21, 2020, AltaGas filed a US$2.0 billion 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. As at December 31, 2020, US$2.0 billion was available under the base shelf prospectus. On February 22, 2021, AltaGas filed a US$2.0 billion short form base shelf prospectus in both Alberta and the U.S. to replace the US$2.0 billion short form base shelf prospectus filed on January 21, 2020.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 56

Contractual Obligations

December 31, 2020
($ millions)	Total		Less than 1 year		1 - 3 years		4 - 5 years		After 5 years
Short-term debt (1)	$	256	$	256	$	—	$	—	$	—
Long-term debt (1)	7,937		356		1,771		1,324		4,486
Operating leases (2)	450		96		139		90		125
Purchase obligations	36,158		3,737		6,002		5,133		21,286
Capital project commitments	25		20		2		2		1
Pension plan and retiree benefits (3)	16		16		—		—		—
Merger commitments (4)	15		5		4		3		3
Land purchase commitment (5)	20		20		—		—		—
Environmental commitments	13		7		4		2		—
Post-acquisition contingent payments (6)	16		—		16		—		—
Other liabilities (7)	37		37		—		—		—
Total contractual obligations (8)	$	44,943	$	4,550	$	7,938	$	6,554	$	25,901

(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 2021. 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 were and will be expensed as the costs are incurred, including the investment of up to US$70 million over a ten year period to further extend natural gas service, investment of US$8 million for leak mitigation within three years, which has been paid as of December 31, 2020, hiring damage prevention trainers in each jurisdiction for a total of US$2 million over five years, and developing 15 megawatts of either electric grid energy storage or Tier 1 renewable resources within five years after the merger closed. As at December 31, 2020, the cumulative amount of merger commitments that have been expensed but not yet paid is approximately US$12 million.

(5)As part of the Petrogas Acquisition, AltaGas acquired a commitment to purchase land as part of an agreement for it's continued use of the Ferndale terminal.

(6)Contingent payments of up to $16 million are expected to be paid related to the Petrogas Acquisition.

(7)Excludes non-financial liabilities.

(8)U.S. dollar commitments have been converted to Canadian dollars using the December 31, 2020 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 2020 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.

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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 2, 2020.
		Senior unsecured	BBB-	Affirmed on December 2, 2020.
		Preferred shares	P-3	Affirmed on December 2, 2020.
	DBRS Limited (DBRS)	Issuer	BBB(low)	Affirmed on December 8, 2020.
		Preferred shares	Pfd-3(low)	Affirmed on December 8, 2020.
	Fitch Ratings (Fitch)	Issuer	BBB	Affirmed on April 3, 2020.
		Preferred shares	BB+	Affirmed on April 3, 2020.
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 April 3, 2020.
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 April 3, 2020.
SEMCO	Moody's	Long-term issuer	A3	Raised from Baa1 to A3 on January 22, 2021 with stable outlook.
		Senior secured notes	A1	Raised from A2 to A1 on January 22, 2021 with stable outlook.
	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. 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.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 58

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 19, 2021
Issued and outstanding
Common shares	279,533,433
Preferred Shares
Series A	6,746,679
Series B	1,253,321
Series C	8,000,000
Series E	8,000,000
Series G	6,885,823
Series H	1,114,177
Series K	12,000,000
Issued
Share options	10,174,183
Share options exercisable	4,343,553

AltaGas Ltd. – 2020 MD&A and Financial Statements - 59

Dividends

AltaGas declares and pays a monthly dividend to its common shareholders. Dividends on preferred shares are paid quarterly. Dividends are at the discretion of the Board of Directors and dividend levels are reviewed periodically, giving consideration to the ongoing sustainable cash flow from operating activities, maintenance and growth capital expenditures, and debt repayment requirements of AltaGas.

On December 10, 2020, AltaGas announced that its Board of Directors approved a 4 percent increase to its annual common share dividends. Monthly dividends to common shareholders will be increased to $0.0833 per common share ($1.00 per common share annually), effective for the December 2020 dividend.

The following table summarizes AltaGas’ dividend declaration history:

Common Share Dividends
Year Ended December 31
($ per common share)	2020		2019
First quarter	$	0.240000	$	0.240000
Second quarter	0.240000		0.240000
Third quarter	0.240000		0.240000
Fourth quarter	0.243300		0.240000
Total	$	0.963300	$	0.960000

Series A Preferred Share Dividends
Year Ended December 31
($ per preferred share)	2020		2019
First quarter	$	0.211250	$	0.211250
Second quarter	0.211250		0.211250
Third quarter	0.211250		0.211250
Fourth quarter	0.191250		0.211250
Total	$	0.825000	$	0.845000

Series B Preferred Share Dividends
Year Ended December 31
($ per preferred share)	2020		2019
First quarter	$	0.268030	$	0.269380
Second quarter	0.267160		0.270510
Third quarter	0.183180		0.273921
Fourth quarter	0.176520		0.270830
Total	$	0.894890	$	1.084641

Series C Preferred Share Dividends
Year Ended December 31
(US$ per preferred share)	2020		2019
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

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Series E Preferred Share Dividends
Year Ended December 31
($ per preferred share)	2020		2019
First quarter	$	0.337063	$	0.337063
Second quarter	0.337063		0.337063
Third quarter	0.337063		0.337063
Fourth quarter	0.337063		0.337063
Total	$	1.348252	$	1.348252

Series G Preferred Share Dividends
Year Ended December 31
($ per preferred share)	2020		2019
First quarter	$	0.265125	$	0.296875
Second quarter	0.265125		0.296875
Third quarter	0.265125		0.296875
Fourth quarter	0.265125		0.265125
Total	$	1.060500	$	1.155750

Series H Preferred Share Dividends
Year ended December 31
($ per preferred share)	2020		2019
First quarter	$	0.292890	$	—
Second quarter	0.292020		—
Third quarter	0.208320		—
Fourth quarter	0.201660		0.296040
Total	$	0.994890	$	0.296040

Series I Preferred Share Dividends (1)
Year Ended December 31
($ per preferred share)	2020		2019
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

(1)On December 31, 2020, AltaGas redeemed all of it's outstanding Series I preferred shares.

Series K Preferred Share Dividends
Year Ended December 31
($ per preferred share)	2020		2019
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

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

AltaGas Ltd. – 2020 MD&A and Financial Statements - 61

made using careful judgment. AltaGas’ significant accounting policies are contained in the notes to the 2020 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.

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, 2020 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

AltaGas Ltd. – 2020 MD&A and Financial Statements - 62

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 2020 Annual Consolidated Financial Statements.

Pension Plans and Post-Retirement Benefits

The determination of pension plan obligations and expense is based on a number of actuarial assumptions. Critical assumptions include the expected long-term rate-of-return on plan assets, the discount rate applied to pension plan obligations, 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.

In the third quarter of 2020, AltaGas made a voluntary change in accounting principle for calculating the market-related value of assets (MRVA) used in the determination of Washington Gas' net periodic pension and other post-retirement benefit plan costs This change in accounting principle impacts the calculation of net periodic benefit cost recorded within the line item “other income” on the Consolidated Statements of Income (Loss). The change uses the fair value approach for the fixed income investment asset class of the plan assets, compared to the prior method that utilized a calculated value where gains and losses arising from changes in fair value were deferred and amortized into the calculation of the MRVA over a period of five years. The MRVA is used in the calculation of the expected return on assets and the recognized actuarial gain or loss components of net periodic benefit cost. The approach applied for all other classes of assets remains unchanged. Management believes that using the fair value approach for the fixed income investments in plan assets is preferable as it more closely aligns the recognition of related components within the net periodic benefit cost. The quantitative effect of this change in accounting principle was not considered material to prior periods or the current year; therefore, an increase to net income (loss) applicable to common shares of approximately $19 million was recognized in 2020.

Notes 2 and 28 of the 2020 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

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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, 2020, 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, 2020, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU):

§    In June 2016, FASB issued ASU No. 2016-13 “Financial Instruments – Credit Losses and all related amendments (collectively "ASC 326"): Measurement of Credit Losses on Financial Instruments”. The ASU replaces the current “incurred loss” impairment methodology with an “expected loss” model for financial assets measured at amortized cost. AltaGas has applied ASC 326 using the modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the effective date of the new standard. Prior periods presented for comparative purposes were not adjusted. Upon adoption of ASC 326, "accounts receivable, net of allowances" decreased by $2 million and "long-term investments and other assets" decreased by $5 million, with an offsetting increase to "accumulated deficit". AltaGas has elected to account for its cash equivalents at fair value. Please also refer to Note 23 of the Consolidated Financial statements as at and for the year ended December 31, 2020 for further details;

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

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statements, but resulted in certain minor adjustments to the fair value disclosures. Please also refer to Note 23 of the Consolidated Financial statements as at and for the year ended December 31, 2020 for further details;

§    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 adoption of this ASU did not have a material impact on AltaGas' consolidated financial statements, but resulted in certain modifications to the disclosures in the pension footnote. Please also refer to Note 28 of the Consolidated Financial statements as at and for the year ended December 31, 2020 for further details.

§    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 interests held through related parties under common control are considered on a proportional basis when determining whether fees paid to decision makers and service providers are variable interests. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§    ASU No. 2018-18 "Collaborative Arrangements: Clarifying the Interaction between Topic 808 and Topic 606". The amendments in this ASU clarifies that certain transactions between collaborative arrangement participants should be accounted for as revenue under ASC 606, adds unit-of-account guidance in ASC 808 to align with the guidance in ASC 606, and requires that a transaction with a collaborative arrangement participant that is not directly related to sales to third parties, is precluded from presenting the transaction together with revenue recognized under ASC 606 if the collaborative arrangement participant is not a customer. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§    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, clarifies the presentation of principal payments received under sales-type and direct finance leases for depository and lending institutions, and clarifies that interim transition disclosure requirements related to the change on income statement, net income and related per share amounts for the adoption of ASC 842 are not required. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§    ASU No. 2019-04 “Financial Instruments: Codification Improvements". The amendments in this ASU provide clarification and improve the codification in recently issued accounting standards relating to credit losses, hedge accounting, and financial instruments. The amendments related to credit losses were evaluated in conjunction with ASU 2016-13 above. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and

§    ASU No. 2020-03 "Codification Improvements to Financial Instruments". The amendments in this ASU provide clarification and improve the codification to certain aspects of accounting standards related to financial instruments. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements.

Effective December 31, 2020, AltaGas adopted the following FASB issued ASU:

§    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 adoption of this ASU did not have a material impact on AltaGas' consolidated financial statements, but resulted in certain modifications to the disclosures in the pension footnote. Please also refer to Note 28 of the Consolidated Financial statements as at and for the year ended December 31, 2020 for further details.

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Future Changes in Accounting Principles

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. The adoption of this ASU is not expected to have a material impact on AltaGas’ financial statements.

In January 2020, FASB issued ASU No. 2020-01 "Derivatives and Hedging: Clarifying the Interactions between Topic 321, Topic 323, and Topic 815". The amendments in this ASU clarify the application of the measurement alternative for equity instruments and the measurement of non-derivative forward contracts or purchased call options used to acquire equity securities. 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’ financial statements.

In March 2020, FASB issued ASU No. 2020-04 "Reference Rate Reform: Facilitation of the Effects of Reference Rate Reform on Financial Reporting." The amendments in this ASU provide optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships affected by reference rate reform if certain criteria are met. These apply only to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. The amendments in this ASU are effective as of March 12, 2020 through December 31, 2022. AltaGas may elect to apply the amendments as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020 on a prospective basis. AltaGas has not elected to adopt this ASU as of December 31, 2020, and is assessing the impact of this ASU on its consolidated financial statements.

In August 2020, FASB issued ASU No. 2020-06 "Debt with Conversion and Other Options and Topic 815-40 - Derivatives and Hedging - Contracts in Entity's Own Equity: Accounting for Convertible Instruments and Contract in an Entity's Own Equity." The amendments in this Update simplify the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. The amendments in this Update are effective for public business entities that meet the definition of a Securities and Exchange Commission (SEC) filer, excluding entities eligible to be smaller reporting companies as defined by the SEC, for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. For all other entities, the amendments are effective for fiscal years beginning after December 15, 2023, including 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' 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.

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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).

Management has designed the existing framework to result in both a complete and accurate consolidation of related information. During the year ended December 31, 2020, other than changes in ICFR related to the Petrogas Acquisition, there were no changes made to AltaGas' ICFR that materially affected, or are reasonably likely to materially affect, its ICFR or DCP. AltaGas does not believe that process changes adopted in connection with the COVID‐19 pandemic have materially affected ICFR.

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, 2020 and concluded that as at December 31, 2020 AltaGas' DCP and ICFR were effective.

Limitation on Scope

In accordance with the provisions under National Instrument 52-109, and consistent with SEC-related guidance, the scope of the evaluation does not include ICFR related to Petrogas, which was acquired on December 15, 2020. These provisions allow an issuer to exclude a business which was acquired not more than 365 days before the issuer's financial year-end from the scope of its certifications. As such, the controls, policies, and procedures related to the Petrogas Acquisition were excluded from management's evaluation of the effectiveness of AltaGas' ICFR as at December 31, 2020. Summary financial information of Petrogas included in the audited Consolidated Financial Statements as at and for the year ended December 31, 2020, includes total assets of approximately $2.6 billion and revenues of approximately $143 million.

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.

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

($ millions)	Q4-20	Q3-20	Q2-20	Q1-20	Q4-19	Q3-19	Q2-19	Q1-19
Total revenue	1,689	969	1,059	1,869	1,534	888	1,174	1,898
Normalized EBITDA (2) (3)	392	213	206	499	436	173	211	482
Net income (loss) applicable to common shares	48	(47)	21	464	(103)	22	41	809
($ per share)	Q4-20	Q3-20	Q2-20	Q1-20	Q4-19	Q3-19	Q2-19	Q1-19
Net income (loss) per common share
Basic	0.17	(0.17)	0.08	1.66	(0.37)	0.08	0.15	2.93
Diluted	0.17	(0.17)	0.08	1.66	(0.37)	0.08	0.15	2.93
Dividends declared	0.24	0.24	0.24	0.24	0.24	0.24	0.24	0.24

(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.

(3)Beginning in 2020, Management no longer adjusts normalized EBITDA for changes in the fair value of natural gas optimization inventory. Please see the Non-GAAP Financial Measures section of this MD&A for additional detail. Prior periods have been adjusted to reflect the impact of this change.

AltaGas’ quarter-over-quarter financial results are impacted by seasonality, fluctuations in commodity prices, weather, the U.S./Canadian dollar exchange rate, planned and unplanned plant outages, timing of in-service dates of new projects, and acquisition and divestiture activities.

Revenue for the Utilities is generally the highest in the first and fourth quarters of any given year as the majority of natural gas demand occurs during the winter heating season, which typically extends from November to March.

Other significant items that impacted quarter-over-quarter revenue during the periods noted include:

§    The seasonally colder weather experienced at several of the utilities in the second and third quarters of 2020;

§    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;

§     The impact of the sale of AltaGas Pomona Energy Storage Inc. and AltaGas Ripon Energy Inc. in the third quarter of 2020; and

§     The impact of the acquisition of additional equity interest in Petrogas in the fourth quarter of 2020.

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:

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

§    After-tax transaction costs of approximately $18 million and $10 million incurred throughout 2020 and 2019, respectively, due to asset sales;

§     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;

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

§     The impact of the sale of ACI in the first quarter of 2020;

§     The impact of the sale of AltaGas Pomona Energy Storage Inc. and AltaGas Ripon Energy Inc. in the third quarter of 2020;

§     The impact of the acquisition of additional equity interest in Petrogas in the fourth quarter of 2020;

§     The after-tax provision of approximately $79 million recognized in the fourth quarter of 2020 related to the Alton Natural Gas Storage Project; and

§     The impact of the change in accounting principle relating to Washington Gas' net periodic pension and other post-retirement benefit plan costs in the third quarter of 2020.

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SELECTED ANNUAL FINANCIAL INFORMATION

($ millions, except where noted)	2020	2019	2018
Revenue	5,587	5,495	4,257
Net income (loss) applicable to common shares	486	769	(502)
Net income (loss) per common share - basic	1.74	2.78	(2.25)
Net income (loss) per common share - diluted	1.74	2.77	(2.25)
Total assets	21,532	19,795	23,488
Total long-term liabilities	11,264	9,301	11,746
Weighted average number of common shares outstanding (millions)	279	277	223
Dividends declared per common share ($ per share)	0.963300	0.960000	2.087500
Preferred share dividends declared ($ per share)
Series A	0.825000	0.845000	0.845000
Series B	0.894890	1.084641	0.968620
Series C (US$)	1.322500	1.322500	1.322500
Series E	1.348252	1.348252	1.250000
Series G	1.060500	1.155750	1.187500
Series H	0.994890	0.296040	—
Series I (1)	1.312500	1.312500	1.312500
Series K	1.250000	1.250000	1.250000
Washington Gas $4.80 series (US$) (2)	—	2.400000	2.400000
Washington Gas $4.25 series (US$) (2)	—	2.125000	2.125000
Washington Gas $5.00 series (US$) (2)	—	2.500000	2.500000

(1) Series I preferred shares were redeemed on December 31, 2020.

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

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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, 2020.

In accordance with the provisions under National Instrument 52-109, and consistent with SEC-related guidance, the scope of the evaluation does not include Internal Control over Financial Reporting (ICFR) related to Petrogas Energy Corp. (Petrogas), which was acquired on December 15, 2020. As such, the controls, policies, and procedures related to the Petrogas Acquisition were excluded from management's evaluation of the effectiveness of AltaGas' ICFR as at December 31, 2020. Summary financial information of Petrogas included in the audited Consolidated Financial Statements as at and for the year ended December 31, 2020, includes total assets of approximately $2.6 billion and revenues of approximately $143 million.

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.

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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 25, 2021

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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, 2020 and 2019, and the consolidated statements of income, comprehensive income (loss), equity and cash flows for each of the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of AltaGas Ltd as at December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the years then ended, in conformity with United States generally accepted accounting principles.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company‘s management. Our responsibility is to express an opinion on the Company‘s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (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.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective or complex judgements. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to which it relates.

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	Fair Value Measurement of Level 3 Derivatives
Description of the Matter	As described in Note 23 to the financial statements, AltaGas Ltd. enters into commodity contracts that qualify as derivative instruments and are accounted for under ASC Topic 815, Derivatives and Hedging. The fair value measurements of certain of these contracts are considered Level 3 under the fair value hierarchy as they are determined using significant unobservable inputs. As of December 31, 2020, derivative assets of $69 million and derivative liabilities of $162 million were recorded based on Level 3 fair value measurements. Auditing the fair value measurement of Level 3 derivative instruments was complex given the judgmental nature of the assumptions used as inputs into the valuation models. In particular, the valuation of Level 3 derivative instruments is sensitive to significant unobservable inputs used by the Company such as the assumed natural gas basis prices and implied volatilities of natural gas prices. These unobservable assumptions could be affected by future economic and market conditions.
How We Addressed the Matter in Our Audit	To test the valuation of Level 3 derivative instruments, our audit procedures included, among others, evaluating the valuation methodologies used by the Company and testing significant inputs, assumptions and the mathematical accuracy of the calculations. In certain instances, with involvement of our valuation specialists, we independently determined the significant unobservable assumptions described above, calculated the resulting fair values and compared them to the Company’s estimates. For a sample of instruments, we obtained forward prices from independent sources, including broker quotes, evaluated the Company’s assumptions related to their forward curves and obtained external confirmation of key contract terms from counterparties. We also performed sensitivity analyses using independent sources of market data to evaluate the change in fair value of Level 3 derivative instruments that would result from changes in underlying assumptions.
	Acquisition of Additional Interest in Petrogas Energy Corp. (“Petrogas”)
Description of the Matter	On December 15, 2020, the Group acquired an additional 37% equity interest in Petrogas for a total consideration of approximately $715 million as noted in Note 3 of the consolidated financial statements. The Group now owns a controlling interest in Petrogas of approximately 74%. Business combinations that are achieved in stages are accounted for using the acquisition method as per ASC 805 - Business Combinations. The purchase price allocation is preliminary and reflects management’s best estimate of the fair value of Petrogas’ assets and liabilities based on the analysis of information obtained to date. Auditing the business combination was complex given the significant degree of estimation uncertainty that is inherent in the preliminary nature of the purchase price allocation. Additionally, management was required to exercise significant judgment when determining their best estimate of the fair value of the previously held equity interest, the identified assets and labilities of Petrogas, and the non-controlling interest attributed to the minority shareholder. These valuations are sensitive to future estimated cash flows and discount rates.

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How We Addressed the Matter in Our Audit	To test the Group’s preliminary purchase price allocation, we performed the following procedures, among others: Read the applicable agreements to obtain an understanding of the key terms and conditions of the acquired additional interest to identify the necessary accounting considerations; Assessed the competency, objectivity, and independence of management’s external valuation specialists; Involved our valuation specialists to assess the valuation methodology applied with respect to intangibles, non-controlling interest, previously held interest, and goodwill. They also assessed management’s approach to quantifying the preliminary discount rates utilised by referencing current industry, economic, and comparable company information, as well as company and cash-flow specific risk premiums; Assessed the appropriateness of the preliminary future estimated cash flows by comparing management’s underlying assumptions to historical Petrogas data and the respective contractual terms and conditions; Involved our capital equipment specialists to review selected third-party appraisals to assess the appropriateness of management’s best estimate of the fair value of property, plant, and equipment; and evaluated the adequacy of the related disclosure included in Note 3 of the accompanying consolidated financial statements
	Regulatory Accounting
Description of the Matter	As discussed in Note 21 to the financial statements, AltaGas Ltd. accounts for its regulated operations in accordance with Accounting Standards Codification Topic 980, Regulated Operations. As such, the Company defers certain costs as regulatory assets and records them as expenses on its statements of operations as it collects the revenue designed to recover these costs through customers’ rates. The Company also records regulatory liabilities for gains previously realized or for amounts previously collected from customers for expenses expected to be incurred in the future. As of December 31, 2020, the Company recorded $490 million of regulatory assets and $1,471 million of regulatory liabilities. Auditing the Company’s regulatory assets and liabilities was complex due to significant judgments made by management to support its assertions about the probability of both the recovery of regulatory assets and the refund of regulatory liabilities. In particular, there was subjectivity involved in assessing the impact of current and future regulatory orders on events that have occurred as of December 31, 2020 and judgment required to evaluate the relevance and reliability of audit evidence to support the probability of recovery in future rates of incurred costs or refunds to customers. These assumptions have a significant effect on the recorded amounts of regulatory assets and liabilities, operating revenues and expenses, and related disclosures.
How We Addressed the Matter in Our Audit	We performed audit procedures that included, among others, evaluating the reasonableness of the Company’s assessment of the probability of the recovery of the regulatory assets and the refund of regulatory liabilities. For example, we evaluated the Company’s correspondence with the regulatory commissions, status of regulatory proceedings, past practices, and recent rate orders issued to other regulated entities in the same jurisdictions. In addition, we evaluated the Company’s related disclosures.

We have served as AltaGas Ltd. auditor since 1997.

Calgary, Canada

February 25, 2021

AltaGas Ltd. – 2020 MD&A and Financial Statements - 75

CONSOLIDATED BALANCE SHEETS

As at December 31	2020		2019
ASSETS
Current assets
Cash and cash equivalents (note 31)	$	32	$	57
Accounts receivable (net of credit losses of $41 million) (notes 10 and 23)	1,444		1,222
Inventory (note 7)	636		506
Restricted cash holdings from customers (note 31)	3		4
Regulatory assets (note 21)	46		13
Risk management assets (note 23)	98		87
Prepaid expenses and other current assets (notes 28 and 31)	234		280
Assets held for sale (note 5)	4		27
	2,497		2,196
Property, plant and equipment (note 8)	10,888		10,125
Intangible assets (note 9)	539		586
Operating right-of-use assets (note 10)	372		170
Goodwill (note 11)	5,039		3,942
Regulatory assets (note 21)	444		487
Risk management assets (note 23)	47		39
Restricted cash holdings from customers (note 31)	2		4
Prepaid post-retirement benefits (note 28)	572		487
Long-term investments and other assets (net of credit losses of $3 million)    (notes 12, 28, and 31)	245		297
Investments accounted for by the equity method (note 14)	887		1,462
	$	21,532	$	19,795
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities (notes 17, 18, 23, and 28)	$	1,561	$	1,325
Dividends payable (note 23)	22		22
Short-term debt (notes 15 and 23)	256		460
Current portion of long-term debt (notes 16 and 23)	360		923
Customer deposits	73		76
Regulatory liabilities (note 21)	90		146
Risk management liabilities (note 23)	111		125
Operating lease liabilities (note 10)	95		27
Other current liabilities (note 23)	38		17
Liabilities associated with assets held for sale (note 5)	1		4
	2,607		3,125
Long-term debt (notes 16 and 23)	7,626		5,928
Asset retirement obligations (note 17)	379		362
Unamortized investment tax credits (note 20)	3		4
Deferred income taxes (note 20)	1,118		959
Regulatory liabilities (note 21)	1,381		1,383
Risk management liabilities (note 23)	145		167
Operating lease liabilities (note 10)	304		153
Other long-term liabilities (notes 19 and 23)	153		102
Future employee obligations (note 28)	155		243
	$	13,871	$	12,426

AltaGas Ltd. – 2020 MD&A and Financial Statements - 76

As at December 31	2020		2019
Shareholders' equity
Common shares, no par values, unlimited shares authorized;    2020 - 279.5 million and 2019 - 279.1 million issued and outstanding (note 25)	$	6,723	$	6,719
Preferred shares (note 25)	1,077		1,277
Contributed surplus	383		377
Accumulated deficit	(1,192)		(1,403)
Accumulated other comprehensive income (AOCI) (note 22)	50		245
Total shareholders' equity	7,041		7,215
Non-controlling interests	620		154
Total equity	$	7,661	$	7,369
	$	21,532	$	19,795

Business acquisition (note 3)

Variable interest entities (note 13)

Commitments, guarantees and contingencies (note 29)

Related party transactions (note 30)

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

AltaGas Ltd. – 2020 MD&A and Financial Statements - 77

CONSOLIDATED STATEMENTS OF INCOME

Year Ended December 31	2020		2019
REVENUE (note 24)	$	5,587	$	5,495
EXPENSES
Cost of sales, exclusive of items shown separately	3,178		3,227
Operating and administrative	1,267		1,299
Accretion expenses (note 17)	5		5
Depreciation and amortization (notes 8 and 9)	414		438
Provisions on assets (note 6)	109		416
	4,973		5,385
Income from equity investments (note 14)	49		141
Other income (note 27)	306		908
Foreign exchange gains (losses)	4		(1)
Interest expense	(274)		(346)
Income before income taxes	699		812
Income tax expense (recovery) (note 20)
Current	1		63
Deferred	126		(91)
Net income after taxes	572		840
Net income applicable to non-controlling interests	20		7
Net income applicable to controlling interests	552		833
Preferred share dividends	(66)		(68)
Gain on redemption of preferred shares (note 25)	—		4
Net income applicable to common shares	$	486	$	769
Net income per common share (note 26)
Basic	$	1.74	$	2.78
Diluted	$	1.74	$	2.77
Weighted average number of common shares    outstanding (millions) (note 26)
Basic	279.4		276.9
Diluted	279.7		277.4

See accompanying notes to the Consolidated Financial Statements.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 78

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

Year Ended December 31	2020		2019
Net income after taxes	$	572	$	840
Other comprehensive income (loss), net of taxes
Loss on foreign currency translation	(175)		(406)
Unrealized gain (loss) on net investment hedge (note 23)	(9)		60
Actuarial gain (loss) on pension plans and post-retirement benefit (PRB) plans (note 28)	(8)		12
Reclassification of actuarial gains and prior service credits on defined benefit (DB) and post-retirement benefit plans (PRB) to net income (note 28)	2		1
Other comprehensive loss from equity investees	(5)		(1)
Total other comprehensive loss (OCI), net of taxes (note 22)	(195)		(334)
Comprehensive income attributable to controlling interests and non-controlling interests, net of taxes	$	377	$	506
Comprehensive income attributable to:
Non-controlling interests	$	20	$	7
Controlling interests	357		499
	$	377	$	506

 See accompanying notes to the Consolidated Financial Statements.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 79

CONSOLIDATED STATEMENTS OF EQUITY

Year Ended December 31	2020		2019
Common shares (note 25)
Balance, beginning of year	$	6,719	$	6,654
Shares issued for cash on exercise of options	1		1
Shares issued under DRIP (1)	6		68
Deferred taxes on share issuance costs	(3)		(4)
Balance, end of year	$	6,723	$	6,719
Preferred shares (note 25)
Balance, beginning of year	$	1,277	$	1,319
Redemption of preferred shares	(200)		(41)
Deferred taxes on share issuance costs	—		(1)
Balance, end of year	$	1,077	$	1,277
Contributed surplus
Balance, beginning of year	$	377	$	373
Share options expense	6		4
Balance, end of year	$	383	$	377
Accumulated deficit
Balance, beginning of year	$	(1,403)	$	(1,905)
Net income applicable to controlling interests	552		833
Common share dividends	(268)		(267)
Preferred share dividends	(66)		(68)
Gain on redemption of preferred shares	—		4
Adoption of ASU No. 2016-13 (notes 2 and 23)	(7)		—
Balance, end of year	$	(1,192)	$	(1,403)
AOCI (note 22)
Balance, beginning of year	$	245	$	579
Other comprehensive loss	(195)		(334)
Balance, end of year	$	50	$	245
Total shareholders' equity	$	7,041	$	7,215
Non-controlling interests
Balance, beginning of year	$	154	$	620
Net income applicable to non-controlling interests	20		7
Adjustment on disposition of assets	—		(508)
Contributions from non-controlling interests to subsidiaries	7		48
Distributions by subsidiaries to non-controlling interests	(28)		(13)
Acquisition of non-controlling interests through Petrogas Acquisition (note 3)	467		—
Balance, end of year	$	620	$	154
Total equity	$	7,661	$	7,369

(1)Premium Dividend™, Dividend Reinvestment and Optional Cash Purchase Plan (DRIP). The plan was suspended in December 2019, with the December dividend (paid January 2020) being the last dividend payment eligible for reinvestment by participating shareholders under the DRIP.

See accompanying notes to the Consolidated Financial Statements.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 80

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31	2020		2019
Cash from (used by) operations
Net income after taxes	$	572	$	840
Items not involving cash:
Depreciation and amortization (notes 8 and 9)	414		438
Provisions on assets (note 6)	109		416
Accretion expenses (note 17)	5		5
Share-based compensation (note 25)	6		4
Deferred income tax expense (recovery) (note 20)	126		(91)
Gains on sale of assets (notes 4 and 27)	(223)		(876)
Gain on remeasurement of previously held interest in AIJVLP (note 3)	(22)		—
Income from equity investments (note 14)	(49)		(141)
Unrealized losses (gains) on risk management contracts (note 23)	(21)		85
Losses on investments (note 27)	—		4
Amortization of deferred financing costs	8		12
Provision for doubtful accounts	25		27
Change in pension and other post-retirement benefits (note 28)	(11)		8
Other	15		9
Asset retirement obligations settled (note 17)	(4)		(2)
Distributions from equity investments	26		110
Changes in operating assets and liabilities (note 31)	(203)		(232)
	$	773	$	616
Investing activities
Business acquisitions, net of cash acquired (note 3)	(675)		—
Capital expenditures - property, plant and equipment	(825)		(1,296)
Capital expenditures - intangible assets	(18)		(38)
Contributions to equity investments	(72)		(179)
Change in loan to affiliate	(75)		—
Proceeds from disposition of equity investments (note 14)	376		—
Proceeds from sale of investments in publicly-traded entities	4		—
Proceeds from disposition of assets, net of transaction costs (note 4)	74		3,624
Proceeds from disposition of financing receivable	—		73
	$	(1,211)	$	2,184
Financing activities
Net repayment of short-term debt	(157)		(701)
Issuance of long-term debt, net of debt issuance costs	1,962		889
Repayment of long-term debt	(1,056)		(873)
Net borrowing (repayment) under credit facilities	191		(1,921)
Dividends - common shares	(268)		(266)
Dividends - preferred shares	(66)		(68)
Distributions to non-controlling interest	(28)		(13)
Contributions from non-controlling interests	7		48
Net proceeds from shares issued on exercise of options	1		1
Net proceeds from issuance of common shares	6		68
Redemption of preferred shares (note 25)	(200)		(38)
	$	392	$	(2,874)
Change in cash, cash equivalents, and restricted cash	(46)		(74)
Effect of exchange rate changes on cash, cash equivalents, and restricted cash	(2)		(9)
Net change in cash classified within assets held for sale	—		4
Cash, cash equivalents, and restricted cash beginning of year	122		201
Cash, cash equivalents, and restricted cash end of year (note 31)	$	74	$	122

See accompanying notes to the Consolidated Financial Statements. 

AltaGas Ltd. – 2020 MD&A and Financial Statements - 81

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 the Company 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 regard to the Utilities business, Washington Gas Light Company (Washington Gas), Hampshire Gas Company, and SEMCO Energy, Inc. (SEMCO); in regard 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); and, in regard to remaining assets in the Corporate/Other segment, AltaGas Power Holdings (U.S.) Inc., WGL Energy Systems, Inc. (WGL Energy Systems), and Blythe Energy Inc. (Blythe). 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). Petrogas Energy Corporation (Petrogas) was also added as a subsidiary of AltaGas upon the close of the acquisition on December 15, 2020.

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 North America 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.

In 2020, AltaGas revised its reportable segments to align with the structure of its business following asset sales 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. Consistent with Management’s strategic view of the business and the basis on which it assesses performance and allocates resources, beginning in 2020, AltaGas has two operating segments: Utilities (which now includes the WGL retail marketing business) and Midstream. These operating segments have not been aggregated in the determination of AltaGas' reportable segments. All other assets are included in the Corporate/Other segment. AltaGas' operating segments include the following:

§    Utilities, which serves approximately 1.7 million customers with a rate base of approximately US$4.3 billion through ownership of regulated natural gas distribution utilities across five jurisdictions in the United States and two regulated natural gas storage utilities in the United States, delivering affordable natural gas to homes and businesses. The Utilities business also includes storage facilities and contracts for interstate natural gas transportation and storage services, as well as the affiliated retail energy marketing business, which serves approximately 0.5 million customers; and

§    Midstream, which includes a 70 percent interest in the Ridley Island Propane Export Terminal (RIPET) and an approximate 74 percent interest in the Ferndale terminal, allowing AltaGas to leverage its assets along the energy value chain in Western Canada and the Western United States including natural gas gathering and processing, NGL extraction and fractionation, and natural gas and NGL marketing. The Midstream segment also includes transmission, storage, and an interest in a regulated pipeline in the Marcellus/Utica gas formation in the northeastern United States. Upon close of the acquisition of Petrogas, the Midstream business also includes a 74 percent interest in Petrogas' other operations, which include LPG exports and distribution, domestic terminals, wellsite fluids and fuels, and trucking and liquids handling.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 82

The Corporate/Other segment consists of AltaGas' corporate activities and a small portfolio of remaining power assets, certain of which are pending sale.

2. Summary of Significant Accounting Policies

BASIS OF PRESENTATION

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

Pursuant to National Instrument 52‑107, "Acceptable Accounting Principles and Auditing Standards" (NI 52‑107), financial statements of an “SEC issuer” may be prepared in accordance with U.S. GAAP. On January 21, 2020, 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 of consolidated subsidiaries are shown as an allocation of the consolidated net income and are presented separately in "net income applicable to non-controlling interests".

USE OF ESTIMATES AND MEASUREMENT UNCERTAINTY

The preparation of Consolidated Financial Statements in accordance with U.S. GAAP requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenue and expenses during the period. Key areas where Management has made complex or subjective judgments, when matters are inherently uncertain, include but are not limited to: determining the nature and timing of satisfaction of performance obligations and determining the transaction price and amounts allocated to performance obligations for revenue recognition; depreciation and amortization rates; 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; measurement of credit losses; 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

AltaGas Ltd. – 2020 MD&A and Financial Statements - 83

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. Additionally, cash deposited in an escrow fund related to a cost sharing agreement with a third party has been recorded as restricted cash in “accounts receivable" in the Consolidated Balance Sheets. Please refer to Note 29 for more information.

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.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 84

Inventory

Inventory consists of materials, supplies, natural gas, natural gas liquids, crude oil and condensates, processed finished products, 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, and a small number of assets acquired as part of the acquisition of Petrogas for which depreciation is calculated using the declining balance method.

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	3 to 55 years
Corporate/Other assets	3 to 46 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. 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.

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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 years
Software	3 to 20 years
Land rights	5 to 43 years
Extraction and Transmission (E&T) Contracts	25 years
Commodity contracts	5 to 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.

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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.

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 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.

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 may designate 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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Credit Losses

The following are the Corporation's significant accounting policies upon adoption of ASC 326:

Accounts receivable, contract assets, a loan to an affiliate, and other long-term receivables within the scope of ASC 326 are recorded net of the allowance for credit losses 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 credit losses is adjusted. Accounts are written off when collection efforts are complete and future recovery is unlikely. See below for a description of how expected credit loss estimates are developed.

Utilities Customer Receivables and Contract Assets

AltaGas is exposed to risk through the non-payment of utility bills by customers. To manage this customer credit risk, AltaGas' regulated utilities customers are offered budget billing options or high risk customers may be required to provide a cash deposit until the requirement for deposit refunds are met. AltaGas can recover a portion of non-payments from customers in future periods through the rate-setting process. For accounts receivable generated by the Utilities business, an allowance for credit losses is recorded against revenue and is recognized using a historical loss-rate based on historical payment and collection experience. This rate may be adjusted based on Management’s expectations of unusual macroeconomic conditions and other factors. AltaGas regularly evaluates the reasonableness of the allowance based on a combination of factors, such as: the length of time receivables are past due, historical expected payment, collection experience, financial condition of customers, and other circumstances that could impact customers' ability or desire to make payments. For retail energy marketing customer receivables where AltaGas has enrolled in a regulatory utility purchase of receivable program, the associated utility discount rate is used to determine credit losses.

Midstream Customer Receivables and Contract Assets

AltaGas operates under an existing credit policy that is designed to mitigate credit risk. Credit limits are established for each counterparty and credit enhancements such as letters of credit, parent guarantees, and cash collateral may be required. The creditworthiness of all counterparties is continuously monitored. A credit loss reserve is recorded for receivables with customers and trading counterparties AltaGas considers to be below investment grade by applying an estimated loss rate. The estimated loss rate is based on the historical default rates published by external rating agencies. For accounts receivable, a one-year rate is used. For contract assets, historical loss rates associated with the estimated time frame that the contract asset will be billed to the customer is used. In the event a customer or trading counterparty no longer exhibits similar risk characteristics, the associated receivable is evaluated individually.

Other

For other long-term receivables, associated counterparties are evaluated and assigned internal credit ratings based on AltaGas' credit policy. An allowance for credit losses is recorded based on historical default rates published by external credit rating agencies and a rate commensurate with the period in which the receivables are expected to be collected.

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

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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 midstream and 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 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. 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

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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 RUs 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 10.2 years and 13.0 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.

In 2020, AltaGas made a voluntary change in accounting principle for calculating the market-related value of assets (MRVA) used in the determination of Washington Gas' net periodic pension and other post-retirement benefit plan costs. The change uses the fair value approach for the fixed income investment asset class of the plan assets, compared to the prior method that utilized a calculated value where gains and losses arising from changes in fair value were deferred and amortized into the calculation of the MRVA over a period of five years. The MRVA is used in the calculation of the expected return on assets and

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the recognized actuarial gain or loss components of net periodic benefit cost. The approach applied for all other classes of assets remains unchanged.

Management believes that using the fair value approach for the fixed income investments in plan assets is preferable as it more closely aligns the recognition of related components within the net periodic benefit cost.

This change in accounting principle was not considered material to prior periods or the current year; therefore, the impact of the change was recognized in the current period. On the Consolidated Statements of Income, for the year ended December 31, 2020, the change resulted in an increase to income before income taxes of approximately $25 million (recorded within the line item “other income”) and an increase to net income applicable to common shares of approximately $19 million ($0.07 per basic and diluted common share), net of the tax impact of approximately $6 million recorded within the line item "deferred income tax expense (recovery)". Amounts related to regulated utility operations that are expected to be recoverable from or refunded to customers through the rate-setting process have been reflected as adjustments to regulatory assets or liabilities on the Consolidated Balance Sheets. For further discussion of pension plans and retiree benefits, see Note 28.

Income Taxes

Income taxes for the Corporation and its subsidiaries are calculated using the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are determined based on differences between the carrying value and the tax basis of assets and liabilities and are measured using the enacted tax rates and laws that are in effect in the periods in which the differences are expected to be settled or realized. Deferred income tax assets are routinely reviewed, and a valuation allowance is recorded to reduce the deferred tax assets if it is more likely than not that deferred tax assets will not be realized.

The financial statement effects of an uncertain tax position are recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxing authority. The current and deferred tax impact is equal to the largest amount, considering possible settlement outcomes, that is greater than 50 percent likely of being realized upon settlement with the taxing authorities.

Investment tax credits are recognized as reductions to income tax expense over the estimated service lives of the related properties.

The rate-regulated natural gas distribution subsidiaries recognize a separate regulatory asset or liability for the amount of deferred income taxes expected to be recovered from, or paid to, customers in the future.

Net Income per Share

Basic net income per common share is computed using the weighted average number of common shares outstanding during the period. Dilutive net income per common share is calculated using the weighted average number of common shares outstanding adjusted for dilutive common shares related to the Corporation’s share-based compensation awards.

The potentially dilutive impact of the share-based compensation awards is determined using the treasury stock method. Under the treasury stock method, awards are treated as if they had been exercised with any proceeds used to repurchase common stock at the average market price during the period. Any incremental difference between the assumed number of shares issued and purchased is included in the diluted share computation.

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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:

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 expense recorded related to the collaborative arrangements totaled $21 million for the year ended December 31, 2020 (2019 - income of $1 million).

ADOPTION OF NEW ACCOUNTING STANDARDS

Effective January 1, 2020, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU):

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§    In June 2016, FASB issued ASU No. 2016-13 “Financial Instruments – Credit Losses and all related amendments (collectively "ASC 326"): Measurement of Credit Losses on Financial Instruments”. The ASU replaces the current “incurred loss” impairment methodology with an “expected loss” model for financial assets measured at amortized cost. AltaGas has applied ASC 326 using the modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the effective date of the new standard. Prior periods presented for comparative purposes were not adjusted. Upon adoption of ASC 326, "accounts receivable, net of allowances" decreased by $2 million and "long-term investments and other assets" decreased by $5 million, with an offsetting increase to "accumulated deficit". AltaGas has elected to account for its cash equivalents at fair value. Please also refer to Note 23 of the Consolidated Financial statements as at and for the year ended December 31, 2020 for further details;

§    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 adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements, but resulted in certain minor adjustments to the fair value disclosures. Please also refer to Note 23 of the Consolidated Financial statements as at and for the year ended December 31, 2020 for further details;

§    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 interests held through related parties under common control are considered on a proportional basis when determining whether fees paid to decision makers and service providers are variable interests. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§    ASU No. 2018-18 "Collaborative Arrangements: Clarifying the Interaction between Topic 808 and Topic 606". The amendments in this ASU clarifies that certain transactions between collaborative arrangement participants should be accounted for as revenue under ASC 606, adds unit-of-account guidance in ASC 808 to align with the guidance in ASC 606, and requires that a transaction with a collaborative arrangement participant that is not directly related to sales to third parties, is precluded from presenting the transaction together with revenue recognized under ASC 606 if the collaborative arrangement participant is not a customer. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§    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, clarifies the presentation of principal payments received under sales-type and direct finance leases for depository and lending institutions, and clarifies that interim transition disclosure requirements related to the change on income statement, net income and related per share amounts for the adoption of ASC 842 are not required. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§    ASU No. 2019-04 “Financial Instruments: Codification Improvements". The amendments in this ASU provide clarification and improve the codification in recently issued accounting standards relating to credit losses, hedge accounting, and financial instruments. The amendments related to credit losses were evaluated in conjunction with ASU 2016-13 above. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and

§    ASU No. 2020-03 "Codification Improvements to Financial Instruments". The amendments in this ASU provide clarification and improve the codification to certain aspects of accounting standards related to financial instruments. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements.

Effective December 31, 2020, AltaGas adopted the following FASB issued ASU:

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§    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 adoption of this ASU did not have a material impact on AltaGas' consolidated financial statements, but resulted in certain modifications to the disclosures in the pension footnote. Please also refer to Note 28 of the Consolidated Financial statements as at and for the year ended December 31, 2020 for further details.

FUTURE CHANGES IN ACCOUNTING PRINCIPLES

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. The adoption of this ASU is not expected to have a material impact on AltaGas’ financial statements.

In January 2020, FASB issued ASU No. 2020-01 "Derivatives and Hedging: Clarifying the Interactions between Topic 321, Topic 323, and Topic 815". The amendments in this ASU clarify the application of the measurement alternative for equity instruments and the measurement of non-derivative forward contracts or purchased call options used to acquire equity securities. 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’ financial statements.

In March 2020, FASB issued ASU No. 2020-04 "Reference Rate Reform: Facilitation of the Effects of Reference Rate Reform on Financial Reporting." The amendments in this ASU provide optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships affected by reference rate reform if certain criteria are met. These apply only to contracts, hedging relationships, and other transactions that reference London Interbank Offered Rate (LIBOR) or another reference rate expected to be discontinued because of reference rate reform. The amendments in this ASU are effective as of March 12, 2020 through December 31, 2022. AltaGas may elect to apply the amendments as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020 on a prospective basis. AltaGas has not elected to adopt this ASU as of December 31, 2020, and is assessing the impact of this ASU on its consolidated financial statements.

In August 2020, FASB issued ASU No. 2020-06 "Debt with Conversion and Other Options and Topic 815-40 - Derivatives and Hedging - Contracts in Entity's Own Equity: Accounting for Convertible Instruments and Contract in an Entity's Own Equity." The amendments in this Update simplify the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. The amendments in this Update are effective for public business entities that meet the definition of a Securities and Exchange Commission (SEC) filer, excluding entities eligible to be smaller reporting companies as defined by the SEC, for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. For all other entities, the amendments are effective for fiscal years beginning after December 15, 2023, including 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' financial statements.

3. Acquisition of Petrogas Energy Corporation

On December 15, 2020, following the receipt of all required approvals, AltaGas acquired an additional 37 percent of Petrogas Energy Corp. (the Petrogas Acquisition) for total cash consideration upon close of approximately $715 million. Additional post-acquisition contingent payments of up to $16 million may be paid no later than 2022 based on certain criteria, including earnings targets being met (Note 29). AltaGas funded the transaction through draws on its existing credit facilities. As a result

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of the transaction, AltaGas' ownership in Petrogas has increased to approximately 74 percent with Idemitsu Kosan Co., Ltd. (Idemitsu) owning the remaining approximately 26 percent. Subsequent to the transaction, AltaGas controls Petrogas and as such, Petrogas results have been consolidated for the period subsequent to close.

This acquisition is consistent with AltaGas' global export strategy, growing Midstream operations, and corporate focus on building a diversified, low-risk, high-growth Utilities and Midstream business. The transaction provides AltaGas with operational responsibility of strategic assets that, along with the Ridley Island Propane Export Terminal and existing Midstream assets, position the Company to capture efficiencies that are expected to accrue to shareholders and customers.

AltaGas accounted for the acquisition as a business combination achieved in stages and re-measured it's previously held 37 percent equity investment in Petrogas at an acquisition date fair value of $631 million, resulting in a gain of $22 million. The fair value of assets and liabilities acquired were determined using a combination of income and cost approach. The fair value of the previously held interest and non-controlling interests were derived from the valuation of the assets and liabilities including considerations for expected synergies. Prior to the acquisition, AltaGas' indirect non-controlling interest in Petrogas was accounted for as an investment accounted for by the equity method (Note 14).

The following table summarizes the preliminary purchase price allocation representing the consideration paid and the estimated fair value of the net assets acquired as at December 15, 2020. The purchase price allocation is preliminary and reflects Management’s current best estimate of the fair value of Petrogas' assets and liabilities based on the analysis of information obtained to date. Management is continuing to obtain specific information to support the valuation of property, plant and equipment, intangibles, investments accounted for by the equity method, non-controlling interest, contingencies, income taxes, environmental matters and asset retirement obligations. As additional information becomes available, the purchase price allocation may differ materially from the preliminary purchase price allocation below. The offset to any adjustments made to the aforementioned financial statement captions during the measurement period are expected to be recorded in goodwill. Any adjustments to the purchase price allocation will be made as soon as practicable but no later than one year from the date of acquisition.

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Fair value of previously held interest in AltaGas Idemitsu Joint Venture LP (AIJVLP) on the acquisition date	$	631
Less: Carrying value of previously held interest in AIJVLP	(609)
Gain on re-measurement of previously held interest	$	22
Purchase consideration for an additional 37 percent of Petrogas	$	715
Deemed settlement of intercompany debt	120
Fair value of previously held interest on the acquisition date	631
Less: Fair value assigned to net assets
Current assets	536
Property, plant and equipment	523
Intangible assets	10
Operating right-of-use assets	192
Long-term investments and other assets	4
Investments accounted for by the equity method	125
Current liabilities	(363)
Long-term debt	(53)
Asset retirement obligations	(13)
Deferred income taxes	(21)
Operating lease liabilities	(152)
Other long-term liabilities	(26)
Fair value of net assets acquired	$	762
Fair value of AIJVLP's non-controlling interest in Petrogas on the acquisition date	467
Goodwill	$	1,171

The fair value of AIJVLP's non-controlling interest in Petrogas at the acquisition date was $467 million, which was determined in the same manner described for the previously held investments. Included in the fair value calculation are synergies that AltaGas expects to achieve as part of the acquisition. The synergies are broken down into items that will accrue to Petrogas versus other AltaGas businesses. AltaGas operates businesses that are similar in nature to Petrogas and expects some of the synergies to impact assets such as RIPET and other processing facilities. The allocation of synergies to the various businesses is currently based on the expectations that existed as of the acquisition date. Further refinement of the synergies will occur as the businesses are integrated and assessed by AltaGas’ management. New allocations of synergies will be carefully assessed to determine their impact on the purchase price allocation.

The fair value of property, plant and equipment was estimated using the valuation methodologies described in ASC 820, Fair Value Measurements and Disclosures, to value the property, plant and equipment purchased. The preliminary fair value of Petrogas' property, plant and equipment was determined using both the income and cost approaches.

The acquired intangible assets consist primarily of the fair value of contractual arrangements for the purchase and sale of commodities. These intangibles have been valued using the income approach.

Investments accounted for by the equity method include Petrogas' 50 percent equity interest in Petrogas Terminals Penn LLC, and 40 percent equity interest in Strathcona Storage LP. The preliminary fair value of these investments was determined using an income approach.

The fair value of current assets and current liabilities approximate their carrying values due to their short-term nature, with the exception of inventory. Inventory of $164 million has been recorded at it's fair value using the expected selling prices and reasonable adjustments for the current location of the products. A contingent liability related to a property tax dispute has been recorded as part of the purchase price allocation. This preliminary amount represents management’s best estimate of the fair

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value of the contingent liability and has been included in current liabilities. This item is included in the preliminary purchase price allocation as the hearings on the matter will occur over the next 12 months and the outcome will be settled.

Right of use assets and lease liabilities have been recorded for operating leases. The right of use assets have been adjusted to reflect the market lease rates at the acquisition date and resulted in a reduction of the acquired right of use assets.

Deferred income tax assets and liabilities have been applied on the cumulative amount of tax applicable to temporary differences between the accounting and tax values of assets and liabilities and are considered preliminary.

The preliminary purchase price allocation includes goodwill of approximately $1.2 billion. The goodwill is primarily related to the

opportunities to grow the LPG export business, expanded access to capital and greater financial flexibility as a result of increased scale, and earnings diversification. The goodwill recognized as part of this transaction is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to this goodwill.

Pre-tax acquisition expenses for the year ended December 31, 2020 of approximately $6 million were incurred and included in the Consolidated Statements of Income.

Upon completion of the Petrogas Acquisition, AltaGas began consolidating Petrogas. For the period from close of the transaction through December 31, 2020, Petrogas has generated approximately $143 million in revenues and $3 million in net income after taxes.

The following supplemental unaudited, pro forma consolidated financial information for the years ended December 31, 2020 and 2019 gives effect to the Petrogas Acquisition as if it had closed on January 1, 2019. This pro forma information is presented for information purposes only and does not purport to be indicative of the results that would have occurred had the Petrogas Acquisition taken place at the beginning of 2019, nor is it indicative of the results that may be expected in future periods.

	Year Ended December 31
	2020		2019
Pro forma revenue	$	7,917	$	9,217
Pro forma net income after tax	$	537	$	1,004

Pro forma net income after taxes excludes all non-recurring acquisition-related expenses incurred by AltaGas and Petrogas. Pro forma net income after taxes was also adjusted to exclude AltaGas' equity earnings from Petrogas prior to the acquisition, finance costs associated with credit facilities used to fund the Petrogas Acquisition, as well as the associated tax impacts. For the year ended December 31, 2020, the total after-tax pro forma adjustments decreased net income after taxes by $31 million (2019 – $75 million).

4. Dispositions

AltaGas Canada Inc. (ACI)

On March 31, 2020, the Public Sector Pension Investment Board and the Alberta Teachers' Retirement Fund Board acquired all the issued and outstanding common shares of ACI for $33.50 per share. AltaGas owned 11,025,000 (approximately 37 percent) of ACI's common shares and received cash proceeds of approximately $369 million upon close. For the year ended December 31, 2020, AltaGas recognized a pre-tax gain on disposition of approximately $206 million in the Consolidated Statements of Income under the line item "other income". Following a name change in connection with the arrangement, ACI changed its name to TriSummit Utilities Inc.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 98

Distributed Generation Assets

In 2019, AltaGas closed the disposition of its portfolio of U.S. distributed generation assets. The majority of assets were transferred in 2019, except for one project 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 this project remain classified as held for sale on the Consolidated Balance Sheets as at December 31, 2020 (Note 5). For the year ended December 31, 2020, AltaGas recognized a pre-tax gain on disposition of approximately $9 million in the Consolidated Statements of Income under the line item "other income" related to projects transferred in 2020. In addition, AltaGas recorded a pre-tax provision of $3 million related to the remaining U.S. distributed generation project which has not yet transferred to the purchaser (Note 6). The purchaser was entitled to after-tax earnings from the distributed generation projects, including the project awaiting consent, beginning September 1, 2019.

Harmattan Land Parcels

In the second quarter of 2020, AltaGas completed the sale of land parcels located near the Harmattan gas processing plant for gross cash proceeds of approximately $3 million. There was no gain or loss resulting from this disposition.

Pomona Energy Storage Facility and Ripon Gas-fired Facility

In the third quarter of 2020, AltaGas completed the sales of AltaGas Pomona Energy Storage Inc. and land related to a gas-fired power generation facility in the U.S., as well as a gas fired facility in Ripon, California, for aggregate gross cash proceeds, before working capital and other adjustments, of approximately $67 million. AltaGas recognized a pre-tax gain on these dispositions of approximately $8 million in the Consolidated Statements of Income under the line item "other income".

5. Assets Held For Sale

As at	December 31, 2020		December 31, 2019
Assets held for sale
Property, plant and equipment	$	4	$	22
Operating right-of-use assets	—		1
Goodwill	—		1
Other long-term assets	—		3
	$	4	$	27
Liabilities associated with assets held for sale
Unamortized investment tax credits	$	1	$	3
Operating lease liabilities - long-term	—		1
	$	1	$	4

Distributed Generation Assets

In 2019, AltaGas announced that it entered into a definitive agreement for the sale of its portfolio of U.S. distributed generation assets (Note 4). The transaction closed in September 2019; however, there is one project 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 this project remains classified as held for sale at December 31, 2020, which resulted in the reclassification of $4 million of assets to assets held for sale and $1 million of liabilities to liabilities associated with assets held for sale on the Consolidated Balance Sheets. The portion of the purchase price relating to this project is approximately $4 million (US$3

AltaGas Ltd. – 2020 MD&A and Financial Statements - 99

million) and is recorded within "accounts payable and accrued liabilities" on the Consolidated Balance Sheets until this project is legally transferred to the purchaser. These assets and liabilities are recorded in the Corporate/Other segment.

6. Provisions on Assets

Year Ended December 31	2020		2019
Midstream	$	106	$	34
Corporate/Other	3		382
	$	109	$	416

Midstream

In 2020, AltaGas recorded pre-tax provisions of $106 million. Of this, approximately $104 million related to the Alton Natural Gas Storage Project, which was impaired as AltaGas does not believe that the future expected cash generation from the project aligns with the current carrying value. The remaining $2 million pre-tax provision related to land parcels located near the Harmattan gas processing plant which were sold in the second quarter of 2020 (Note 4). The pre-tax provisions were recorded against property, plant and equipment. In 2019, AltaGas recorded pre-tax provisions of $34 million related to a sour gas treatment facility in Alberta.

Corporate/Other

In 2020, AltaGas recorded pre-tax provisions totaling $3 million related to the remaining U.S. distributed generation projects which have not yet transferred to the purchaser and are classified as held for sale as at December 31, 2020. The pre-tax provisions were recorded against property, plant and equipment. In 2019, AltaGas recorded pre-tax provisions of $382 million related to various assets in the Corporate/Other segment.

7. Inventory

As at December 31	2020		2019
Natural gas held in storage (a)	$	309	$	359
Natural gas liquids	116		26
Materials and supplies	84		57
Renewable energy credits and emission compliance instruments	80		64
Crude oil and condensate	43		—
Processed finished products	4		—
	$	636	$	506

(a)As at December 31, 2020, $193 million of the natural gas held in storage was held by rate-regulated utilities (2019 - $214 million).

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8. Property, Plant and Equipment

As at	December 31, 2020						December 31, 2019
	Cost		Accumulated amortization		Net book value		Cost		Accumulated amortization		Net book value
Utilities	$	7,791	$	(286)	$	7,505	$	7,316	$	(155)	$	7,161
Midstream	4,094		(951)		3,143		3,182		(585)		2,597
Corporate/Other	842		(598)		244		1,025		(636)		389
Reclassified to assets held for sale	(4)		—		(4)		(24)		2		(22)
	$	12,723	$	(1,835)	$	10,888	$	11,499	$	(1,374)	$	10,125

Interest capitalized on long-term capital construction projects for the year ended December 31, 2020 was $6 million (2019 - $15 million).

As at December 31, 2020, the Corporation had approximately $457 million (December 31, 2019 - $725 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, 2020 was $346 million (2019 - $358 million).

9. Intangible Assets

As at	December 31, 2020						December 31, 2019
	Cost		Accumulated amortization		Net book value		Cost		Accumulated amortization		Net book value
E&T contracts	$	26	$	(16)	$	10	$	27	$	(15)	$	12
Electricity service agreements	—		—		—		9		(8)		1
Energy services relationships	90		(45)		45		91		(27)		64
Software	304		(133)		171		304		(102)		202
Land rights	1		—		1		1		—		1
Commodity contracts	332		(20)		312		327		(21)		306
	$	753	$	(214)	$	539	$	759	$	(173)	$	586

Amortization expense related to intangible assets for the year ended December 31, 2020 was $68 million (2019 - $80 million).

As at December 31, 2020, the Corporation excluded $176 million (December 31, 2019 - $185 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.

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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:

2021	$	75
2022	$	72
2023	$	60
2024	$	39
2025	$	15
Thereafter	$	102

10. Leases

Lessee

AltaGas has operating and finance leases for office space, office equipment, field equipment, rail cars, aquatic use, vehicles, power and gas facilities, transmission and distribution assets, and land.

The components of lease expense were as follows:

	Year Ended December 31, 2020		Year Ended December 31, 2019
Operating lease cost (includes variable lease payments)	$	43	$	29
Finance lease cost
Amortization of right-of-use assets	$	4	$	4
Total finance lease cost	$	4	$	4
Total lease cost	$	47	$	33

Supplemental cash flow information related to leases was as follows:

Year Ended December 31	2020		2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	(36)	$	(21)
Financing cash flows from finance leases (a)	$	(4)	$	(4)
Right-of-use assets obtained in exchange for new lease liabilities
Operating leases	$	227	$	50
Finance leases	$	6	$	5

(a)Included within repayment of long-term debt on the Consolidated Statements of Cash Flows.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 102

Supplemental balance sheet information related to leases was as follows:

As at December 31	2020		2019
Operating Leases
Operating lease right-of-use assets
Long-term	$	372	$	170
Total operating lease right-of-use assets	$	372	$	170
Operating lease liabilities
Current	$	(95)	$	(27)
Long-term	(304)		(153)
Total operating lease liabilities	$	(399)	$	(180)
Finance Leases
Property and equipment, gross	$	19	$	13
Accumulated depreciation	(7)		(3)
Property and equipment, net	$	12	$	10
Current portion of long-term debt	$	(4)	$	(4)
Long-term debt	(8)		(6)
Total finance lease liabilities	$	(12)	$	(10)

As at	December 31, 2020	December 31, 2019
Weighted average remaining lease term (years)
Operating leases	7.4	10.9
Finance leases	4.8	5.2
Weighted average discount rate (%)
Operating leases	2.42	3.51
Finance leases	2.89	3.68

Maturity analysis of lease liabilities was as follows:

	Operating Leases		Finance Leases
2021	$	96	$	4
2022	81		4
2023	58		2
2024	50		1
2025	40		1
Thereafter	125		2
Total lease payments	450		14
Less: imputed interest	(51)		(2)
Total	$	399	$	12

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.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 103

Maturity analysis of lease receivables was as follows:

	Operating Leases
2021	$	127
2022	117
2023	108
2024	41
2025	41
Thereafter	404
Total	$	838

The carrying value of property, plant, and equipment associated with these leases was approximately $0.5 billion as at December 31, 2020.

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.

11. Goodwill

As at	December 31, 2020		December 31, 2019
Balance, beginning of year	$	3,942	$	4,068
Business acquisition (note 3)	1,171		—
Adjustment to goodwill on business acquisition	—		92
Goodwill included in dispositions	—		(29)
Reclassified to assets held for sale	—		(1)
Foreign exchange translation	(74)		(188)
Balance, end of year	$	5,039	$	3,942

12. Long-Term Investments and Other Assets

As at	December 31, 2020		December 31, 2019
Investments in publicly-traded entities	$	—	$	4
Loan to affiliate (notes 23 and 30)	—		45
Deferred lease receivable	12		17
Debt issuance costs associated with credit facilities	3		6
Refundable deposits	9		9
Prepayment on long-term service agreements	70		81
Deferred information technology costs	4		—
Cash calls from joint venture partners	26		10
Contract asset (net of credit losses of $1 million) (notes 23 and 24)	50		30
Rabbi trust and other restricted cash (notes 28, 29 and 31)	19		32
Other long-term receivables (net of credit losses of $2 million) (notes 23 and 29)	18		33
Capitalized contract costs	5		—
Financial transmission rights	12		12
Other	17		18
	$	245	$	297

AltaGas Ltd. – 2020 MD&A and Financial Statements - 104

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 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.

The following table represents amounts included in the Consolidated Balance Sheets attributable to AltaGas’ consolidated VIE:

As at	December 31, 2020		December 31, 2019
Current assets	$	7	$	6
Property, plant and equipment	358		371
Long-term investments and other assets	50		53
Current liabilities	(2)		(3)
Asset retirement obligations	(2)		(3)
Net assets	$	411	$	424

Unconsolidated VIE

Strathcona Storage Limited Partnership (SSLP)

Upon the acquisition of Petrogas on December 15, 2020, AltaGas acquired an indirect interest in SSLP, a partnership formed with ATCO Energy Solutions Ltd. to construct, operate, and maintain underground NGL storage caverns at Fort Saskatchewan,

AltaGas Ltd. – 2020 MD&A and Financial Statements - 105

Alberta. The facility currently has four underground NGL storage salt caverns in service, with a fifth cavern under development. As at December 31, 2020, AltaGas held an indirect 30 percent equity investment in SSLP with a carrying value of $124 million, inclusive of fair value adjustments on acquisition date (Note 3). SSLP is not consolidated by Petrogas and instead is accounted for by the equity method of accounting. Petrogas is not the primary beneficiary of SSLP and it does not have the power to direct the activities most significant to the economic performance of SSLP.

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	2020		2019		2020		2019
AltaGas Canada Inc. (ACI) (a)	Canada	—	$	—	$	164	$	3	$	17
AltaGas Idemitsu Joint Venture LP (b)	Canada	—	—		431		(25)		63
Constitution Pipeline, LLC (Constitution) (c)	United States	—	—		—		(7)		—
Eaton Rapids Gas Storage System	United States	50	26		27		2		1
Meade Pipeline Co. LLC (d)	United States	—	—		—		—		(4)
Mountain Valley Pipeline, LLC (Mountain Valley) (e)	United States	10	718		672		62		43
Sarnia Airport Storage Pool LP	Canada	50	18		18		1		1
Petrogas Preferred Shares (f)	Canada	n/a	—		150		13		13
Petrogas Terminals Penn LLC (g)	United States	37	1		—		—		—
Stonewall Gas Gathering Systems LLC (d)	United States	—	—		—		—		7
Strathcona Storage LP (g)	Canada	30	124		—		—		—
			$	887	$	1,462	$	49	$	141

(a)    ACI was acquired by the Public Sector Pension Investment Board and the Alberta Teachers' Retirement Fund Board on March 31, 2020 (Note 4).

(b)    Upon acquisition of Petrogas on December 15, 2020 (Note 3), AltaGas no longer has an equity investment in AIJVLP.

(c)    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 and Constitution was dissolved. The loss recorded in 2020 relates to a provision recorded against the equity investment (see below for further discussion).

(d)    Disposed of in 2019.

(e)    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.

(f)    Petrogas' preferred shares ceased to be an investment accounted for by the equity method after AltaGas acquired a controlling interest in Petrogas on December 15, 2020 (Note 3).

(g)    Acquired on December 15, 2020 as part of the Petrogas Acquisition (Note 3).

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.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 106

Summarized combined financial information, assuming a 100 percent ownership interest in AltaGas’ equity investments listed above, is as follows:

Year Ended December 31 (a)	2020		2019
Revenues	$	828	$	1,109
Expenses	(181)		(355)
	$	647	$	754
As at December 31 (a)	2020		2019
Current assets	$	351	$	411
Property, plant and equipment	$	7,598	$	8,034
Intangible assets	$	—	$	22
Long-term investments and other assets	$	5	$	1,459
Current liabilities	$	(281)	$	(394)
Other long-term liabilities	$	(2)	$	(992)

(a)    For equity investments that were disposed of in the periods presented, revenues and expenses reflect the period prior to disposition and balance sheet amounts are $nil. For equity investments that were acquired in the year (Note 3), revenues and expenses reflect the period subsequent to acquisition and balance sheet amounts are included as at December 31, 2020.

Equity Method Investments Acquired

In connection with the acquisition of Petrogas (Note 3), AltaGas acquired the following investments accounted for by the equity method:

Petrogas Terminals Penn LLC

Petrogas owns a 50 percent equity interest in Petrogas Terminals Penn LLC, a partnership with a regional propane retailer engaged in rail offloading of propane for distribution by truck to customers in Pennsylvania and other nearby states.

Strathcona Storage LP

Petrogas owns a 40 percent equity interest in Strathcona Storage Limited Partnership, a partnership with ATCO Energy Solutions Ltd., which is engaged in the development of underground NGL storage caverns at Fort Saskatchewan, Alberta. SSLP is considered a VIE (Note 13) and is accounted for using the equity method.

AltaGas Canada Inc.

On March 31, 2020, the Public Sector Pension Investment Board and the Alberta Teachers' Retirement Fund Board acquired all the issued and outstanding common shares of ACI for $33.50 per share (Note 4). AltaGas owned 11,025,000 (approximately 37 percent) of ACI's common shares and received cash proceeds of approximately $369 million upon close. AltaGas recognized a pre-tax gain on disposition of approximately $206 million in the Consolidated Statements of Income under the line item "other income" (Note 27). Following a name change in connection with the arrangement, ACI changed its name to TriSummit Utilities Inc.

Petrogas/AIJVLP

At the beginning of 2020, AltaGas held an indirect approximate one-third interest in Petrogas through its equity investment in AIJVLP. In the first quarter of 2020, one of Petrogas' shareholders has converted their preferred shares of Petrogas to common shares resulting in the dilution of AltaGas' indirect ownership in Petrogas common shares from approximately 33.3 percent to approximately 29.2 percent. In addition, prior to the close of the Petrogas Acquisition in the fourth quarter of 2020,

AltaGas Ltd. – 2020 MD&A and Financial Statements - 107

AltaGas converted their preferred shares of Petrogas to common shares. As a result of these transactions, in 2020, AltaGas recognized pre-tax dilution losses totaling approximately $30 million in the Consolidated Statements of Income under the line item "income from equity investments". There were additional expenses of $12 million recorded to "income from equity investments" related to various adjustments to pre-acquisition balances of Petrogas. This primarily included amounts relating to severance, transaction costs and impairment losses related to the acquisition of Petrogas. Upon close of the Petrogas Acquisition on December 15, 2020, AltaGas recognized a pre-tax gain of $22 million in the Consolidated Statements of Income under the line item "other income" on the re-measurement of it's previously held equity investment in AIJVLP. Subsequent to the acquisition, AltaGas no longer has an equity investment in AIJVLP.

Provisions on investments accounted for by the equity method

In the year ended December 31, 2020, AltaGas recorded a pre-tax provision on equity investments of approximately $7 million in the Consolidated Statements of Income under the line item "income from equity investments" for costs associated with AltaGas' equity investment in the Constitution pipeline project which was canceled in February 2020.

In the year ended December 31, 2019, AltaGas recorded a pre-tax provision of $44 million against its investment in Meade as a result of the sale of WGL Midstream's interest in the Central Penn Pipeline. The disposition of the investment in this entity was completed in the fourth quarter of 2019. In addition, AltaGas recorded a pre-tax provision of $2 million against its 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.

15. Short-term Debt

As at	December 31, 2020		December 31, 2019
Commercial paper (a)	$	236	$	389
Project financing	20		71
	$	256	$	460

(a)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.

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 these projects 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, 2020, draws related to project financing were $20 million (December 31, 2019 - $71 million).

Other Credit Facilities

As at December 31, 2020, the AltaGas held a $70 million (December 31, 2019 - $70 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, 2020 were $nil (December 31, 2019 - $nil).

As at December 31, 2020, AltaGas held a $150 million (December 31, 2019 - $150 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,

AltaGas Ltd. – 2020 MD&A and Financial Statements - 108

bankers’ acceptances, or letters of credit. Letters of credit outstanding under this facility as at December 31, 2020 were $nil (December 31, 2019 - $26 million).

As at December 31, 2020, AltaGas held a US$200 million (December 31, 2019 - US$200 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, 2020 were $190 million (December 31, 2019 - $156 million).

As at December 31, 2020, AltaGas held a US$1.2 billion (December 31, 2019 - US$1.2 billion) 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, 2020 or December 31, 2019.

During the year ended December 31, 2020, AltaGas cancelled a US$300 million unsecured extendible revolving letter of credit facility.

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, 2020, commercial paper outstanding classified as short-term debt totaled $236 million (December 31, 2019 - $389 million).

Credit Facilities Acquired in Petrogas Acquisition

As at December 31, 2020, Petrogas held a $30 million revolving letter of credit facility. Letters of credit outstanding under this facility as at December 31, 2020 were $22 million.

As at December 31, 2020, Petrogas held an operating facility of US$15 million. There were no letters of credit outstanding under this facility as at December 31, 2020.

As at December 31, 2020, Petrogas held a US$40 million seasonal bulge 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, 2020.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 109

16. Long-Term Debt

As at	Maturity date	December 31, 2020		December 31, 2019
Credit facilities
$1,400 million unsecured extendible revolving facility (a)	15-May-2023	$	802	$	90
US$300 million unsecured extendible revolving facility	27-Feb-2021	—		390
US$150 million unsecured extendible revolving facility	20-Dec-2023	81		163
Commercial paper (b)	Various	260		367
$175 million secured extendible revolving facility	18-Jun-2022	51		—
AltaGas Ltd. medium-term notes (MTNs)
$200 million Senior unsecured - 4.07 percent	1-Jun-2020	—		200
$350 million Senior unsecured - 3.72 percent	28-Sep-2021	350		350
$500 million Senior unsecured - 2.61 percent	16-Dec-2022	500		500
$300 million Senior unsecured - 3.57 percent	12-Jun-2023	300		300
$200 million Senior unsecured - 4.40 percent	15-Mar-2024	200		200
$300 million Senior unsecured - 3.84 percent	15-Jan-2025	300		300
$500 million Senior unsecured - 2.16 percent	10-Jun-2025	500		—
$350 million Senior unsecured - 4.12 percent	7-Apr-2026	350		350
$200 million Senior unsecured - 3.98 percent	4-Oct-2027	200		200
$500 million Senior unsecured - 2.08 percent	30-May-2028	500		—
$200 million Senior unsecured - 2.48 percent	30-Nov-2030	200		—
$100 million Senior unsecured - 5.16 percent	13-Jan-2044	100		100
$300 million Senior unsecured - 4.50 percent	15-Aug-2044	300		300
$250 million Senior unsecured - 4.99 percent	4-Oct-2047	250		250
WGL and Washington Gas MTNs
US$250 million Senior unsecured - 2.44 percent (c)	12-Mar-2020	—		325
US$20 million Senior unsecured - 6.65 percent	20-Mar-2023	25		26
US$41 million Senior unsecured - 5.44 percent	11-Aug-2025	52		53
US$53 million Senior unsecured - 6.62 to 6.82 percent	Oct 2026	67		69
US$72 million Senior unsecured - 6.40 to 6.57 percent	Feb - Sep 2027	92		93
US$52 million Senior unsecured - 6.57 to 6.85 percent	Jan - Mar 2028	66		67
US$9 million Senior unsecured - 7.50 percent	1-Apr-2030	11		11
US$50 million Senior unsecured - 5.70 to 5.78 percent	Jan - Mar 2036	64		65
US$75 million Senior unsecured - 5.21 percent	3-Dec-2040	95		97
US$75 million Senior unsecured - 5.00 percent	15-Dec-2043	95		97
US$300 million Senior unsecured - 4.22 to 4.60 percent	Sep - Nov 2044	382		390
US$450 million Senior unsecured - 3.80 percent	15-Sep-2046	573		584
US$400 million Senior unsecured - 3.65 percent (d)	15-Sep-2049	530		390
SEMCO long-term debt
US$300 million SEMCO Senior Secured - 5.15 percent (e)	21-Apr-2020	—		390
US$82 million SEMCO Senior Secured - 4.48 percent (f)	2-Mar-2032	69		76
US$225 million First Mortgage Bonds - 3.15 percent	21-Apr-2030	286		—
US$225 million First Mortgage Bonds - 2.45 percent	21-Apr-2050	286		—
Fair value adjustment on WGL Acquisition		80		84
Finance lease liabilities (note 10)		12		10
		$	8,029	$	6,887
Less debt issuance costs		(43)		(36)
		$	7,986	$	6,851
Less current portion		(360)		(923)
		$	7,626	$	5,928

(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)    Commercial paper is supported by the availability of long-term committed credit facilities with maturity dates ranging from 2022 to 2024. Commercial paper intended to be repaid within the next year is recorded as short-term debt (Note 15).

(c)     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. – 2020 MD&A and Financial Statements - 110

(d)     On December 10, 2020, Washington Gas issued MTNs with an aggregate principal amount of $100 million. This offering constituted the reopening of it's $300 million MTNs originally issued in 2019. The total includes a US$17 million premium which will be amortized as a reduction to interest expense over the term of the note.

(e)    Collateral for the U.S. dollar MTNs is certain SEMCO assets.

(f)    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, 2020, AltaGas held a US$300 million (December 31, 2019 - US$300 million) unsecured revolving credit facility. Draws on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, or letters of credit. There were no outstanding bank loans under this facility as at December 31, 2020 or December 31, 2019.

As at December 31, 2020, WGL held a US$250 million (December 31, 2019 - US$250 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, 2020 or December 31, 2019.

As at December 31, 2020, Washington Gas held a US$450 million (December 31, 2019 - US$450 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, 2020 or December 31, 2019.

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, 2020, outstanding commercial paper classified as long-term debt totaled $260 million (December 31, 2019 - $367 million).

Credit Facilities Acquired in Petrogas Acquisition

As at December 31, 2020, Petrogas held a $175 million secured 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. Loans and letters of credit outstanding under this facility as at December 31, 2020 were $57 million.

As at December 31, 2020, Petrogas held a US$10 million operating revolving letter of credit facility. Letters of credit outstanding under this facility as at December 31, 2020 were $nil.

As at December 31, 2020, Petrogas held a $25 million 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. There were no outstanding bank loans under this facility as at December 31, 2020.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 111

17. Asset Retirement Obligations

As at December 31	2020		2019
Balance, beginning of year	$	362	$	500
Obligations acquired (note 3)	13		—
New obligations	14		7
Obligations settled	(4)		(2)
Disposals	(1)		(6)
Revision in estimated cash flow	(10)		(129)
Accretion expense (a)	17		19
Foreign exchange translation	(6)		(21)
Total	$	385	$	368
Less: current portion (included in accounts payable and accrued liabilities)	(6)		(6)
Balance, end of year	$	379	$	362

(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.

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, 2020 was $816 million (December 31, 2019 - $727 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, 2019 - between 2.0 to 8.5 percent) and are expected to be incurred between 2021 and 2138 (December 31, 2019 - between 2020 and 2137). No assets have been legally restricted for settlement of the estimated liability.

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 Ltd. – 2020 MD&A and Financial Statements - 112

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, 2020, a liability of $13 million has been recorded on an undiscounted basis related to future environmental response costs (December 31, 2019 - $14 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, 2020, AltaGas estimated the maximum liability associated with all of its sites to be approximately $39 million (December 31, 2019 - $40 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, 2020, AltaGas reported a regulatory asset of $15 million (December 31, 2019 - $18 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, 2020		December 31, 2019
Deferred revenue	$	8	$	4
Customer advances for construction	60		64
Merger commitments	10		14
Other employee benefits	6		6
Deferred payroll taxes (a)	6		—
Petrogas equalization reserve (b)	5		—
Uncertain tax positions (note 20)	21		2
Non-pension retirement benefits	16		—
Other	21		12
	$	153	$	102

(a)    Represents U.S. federal payroll tax deferrals from the Coronavirus Aid, Relief, and Economic Security (CARES) Act.

(b)    Reserve is held by a wholly owned subsidiary of Petrogas.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 113

20. Income Taxes

Year Ended December 31	2020		2019
Income before income taxes - consolidated	$	699	$	812
Statutory income tax rate (%)	24.0		26.5
Expected taxes at statutory rates	$	168	$	215
Add (deduct) the tax effect of:
Permanent differences	$	2	$	11
Statutory and other rate differences	9		(52)
Rate adjustment for change in tax rates	—		(11)
Deferred income tax recovery on regulated assets	(15)		(25)
Tax differences on divestitures and transactions	(33)		(159)
Change in valuation allowance	(2)		(11)
Other	(2)		4
	$	127	$	(28)
Income tax provision
Current	$	1	$	63
Deferred	126		(91)
	$	127	$	(28)
Effective income tax rate (%)	18.2		(3.4)

Net deferred income tax liabilities were composed of the following:

As at	December 31, 2020		December 31, 2019
PP&E and intangible assets	$	1,645	$	1,450
Regulatory assets	(229)		(204)
Tax pools, deferred financing, and compensation	(208)		(138)
Other	(94)		(161)
Valuation allowance	4		12
	$	1,118	$	959

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 was further reduced from 11 percent to 8 percent on July 1, 2020.

As at December 31, 2020, the Corporation had tax-effected non-capital losses of approximately $293 million, which will be available to offset future taxable income. If not used, these losses will expire between 2023 and 2040.

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.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 114

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 2013 to 2019 remain subject to examination by taxation authorities. In the United States, both the federal and state tax returns for the years 2016 to 2019 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	2020		2019
Balance, beginning of year	$	2	$	2
Gross increases for tax positions of prior year	21		—
Lapses of statute of limitations	(2)		—
Balance, end of year	$	21	$	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 by a non-rate-regulated entity. These deferred regulatory assets and liabilities are included in the Consolidated Statements of Income in future periods when the amounts are reflected in customer rates. If an application is filed to modify customer rates with certain regulatory commissions, AltaGas is permitted to charge customers new rates, subject to refund, until the regulatory commission renders a final decision. During this interim period, a provision is recorded for a rate refund regulatory liability based on the difference between the amount collected in rates and the amount expected to be recovered from a final regulatory decision.

Management’s assessment of the probability of recovery or pass-through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory agency orders, rules, and rate-making conventions. The relevant regulatory bodies are the MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA.

If, for any reason, the Corporation ceases to meet the criteria for application of regulatory accounting for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be de-recognized from the Consolidated Balance Sheets and included in the Consolidated Statements of Income for the period in which the discontinuance of regulatory accounting occurs. Criteria that give rise to the discontinuance of regulatory accounting include: (i) increasing competition that restricts the ability of the Corporation to charge prices sufficient to recover specific costs, and (ii) a significant change in the manner in which rates are set by regulatory agencies from cost-based regulation to another form of regulation. The Corporation’s review of these criteria currently supports the continued application of regulatory accounting for all its utilities.

The following table summarizes the regulatory assets and liabilities recorded in the Consolidated Balance Sheets, as well as the remaining period, as at December 31, 2020 and 2019, over which the Corporation expects to realize or settle the assets or liabilities:

AltaGas Ltd. – 2020 MD&A and Financial Statements - 115

As at December 31	2020		2019		Recovery Period
Regulatory assets - current
Deferred cost of gas (a)	$	18	$	8	Less than one year
Accelerated replacement recovery mechanisms (b)	6		2		Less than one year
Interruptible sharing (a)	2		3		Less than one year
Energy optimization costs	1		—		Less than one year
Virginia and Maryland revenue normalization (a)	19		—		Less than one year
	$	46	$	13
Regulatory assets - non-current
Deferred regulatory costs (a) (c)	$	158	$	150	2 - 55 years
Future recovery of pension and other retirement benefits (a)	68		128		Various
Future recovery of non-retirement employee benefits (a) (d)	22		19		Various
Deferred environmental costs (a) (e)	15		18		Various
Deferred loss on debt transactions and derivative instruments (a) (f)	93		99		Various
Deferred future income taxes (a) (g)	46		43		Various
Energy efficiency program - Maryland (h)	18		12		Various
COVID-19 costs (i)	10		—		Various
Other	14		18		Various
	$	444	$	487
Regulatory liabilities - current
Deferred cost of gas (a)	$	56	$	61	Less than one year
Refundable tax credit (j)	2		2		Less than one year
Federal income tax rate change (k)	20		33		Less than one year
Virginia rate refund (l)	—		41		Less than one year
Interruptible sharing (a)	1		—		Less than one year
Virginia Coronavirus Relief Fund (m)	10		—		Less than one year
Other	1		9		Less than one year
	$	90	$	146
Regulatory liabilities - non-current
Refundable tax credit (j)	2		4		2 years
Future expense of pension and other retirement benefits (a)	335		261		Various
Future removal and site restoration costs (n)	462		484		Various
Deferred gain on debt transactions and derivative instruments (a) (f)	1		2		Various
Federal income tax rate change (k)	578		628		Various
Other	3		4		Various
	$	1,381	$	1,383

(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)    This balance represents allowed environmental remediation expenditures at SEMCO and Washington Gas sites to be recovered through rates.

(f)    The losses or gains on the issuance and extinguishment of debt and interest-rate derivative instruments include unamortized balances from transactions executed in prior 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, 2020, this also includes a fair value adjustment of $76 million (December 31, 2019 - $80 million) recorded on the WGL Acquisition in 2018.

(g)    This balance represents amounts due from customers for deferred tax assets and liabilities related to tax benefits/expenses on deductions flowed directly to customers prior to the adoption of income tax normalizations for ratemaking purposes and to tax rate changes.

(h)    Represents amounts for deferred credits associated with Washington Gas' participation in the energy conservation and efficiency program EmPower in Maryland.

(i)    Regulatory assets established to capture and track incremental COVID-19 related costs.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 116

(j)    On September 18, 2013, CINGSA received a US$15 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)    The Virginia Coronavirus Relief Fund was received by WGL to provide direct assistance to Virginia customers with balances over 30 days in arrears.

(n)    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)	Defined benefit pension and PRB plans		Hedge net investments		Translation foreign operations		Equity investee		Total
Opening balance, January 1, 2020	$	(6)	$	(149)	$	395	$	5	$	245
OCI before reclassification	(11)		(10)		(175)		(5)		(201)
Amounts reclassified from OCI	3		—		—		—		3
Current period OCI (pre-tax)	(8)		(10)		(175)		(5)		(198)
Income tax on amounts retained in AOCI	3		1		—		—		4
Income tax on amounts reclassified to earnings	(1)		—		—		—		(1)
Net current period OCI	(6)		(9)		(175)		(5)		(195)
Ending balance, December 31, 2020	$	(12)	$	(158)	$	220	$	—	$	50
Opening balance, January 1, 2019	$	(19)	$	(209)	$	801	$	6	$	579
OCI before reclassification	15		68		(406)		(1)		(324)
Amounts reclassified from OCI	1		—		—		—		1
Current period OCI (pre-tax)	16		68		(406)		(1)		(323)
Income tax on amounts retained in AOCI	(3)		(8)		—		—		(11)
Net current period OCI	13		60		(406)		(1)		(334)
Ending balance, December 31, 2019	$	(6)	$	(149)	$	395	$	5	$	245

Reclassification From Accumulated Other Comprehensive Income

AOCI components reclassified	Income statement line item	Year Ended December 31, 2020		Year Ended December 31, 2019
Defined benefit pension and PRB plans	Other income	$	3	$	1
Deferred income taxes	Income tax expense – deferred	(1)		—
		$	2	$	1

AltaGas Ltd. – 2020 MD&A and Financial Statements - 117

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.

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, NGL, LPG, ocean freight, and oil 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 were 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. 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. A significant change to any one of these inputs in isolation could result in a significant upward or downward fluctuation in the fair value measurement.

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, LPG, ocean freight, and oil 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.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 118

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, 2020
	Carrying Amount		Level 1		Level 2		Level 3		Total Fair Value
Financial assets
Fair value through net income (a)
Risk management assets - current	$	94	$	—	$	73	$	21	$	94
Risk management assets - non-current	38		—		2		36		38
Fair value through regulatory assets (a)
Risk management assets - current	4		—		1		3		4
Risk management assets - non-current	9		—		—		9		9
	$	145	$	—	$	76	$	69	$	145
Financial liabilities
Fair value through net income (a)
Risk management liabilities - current	$	102	$	—	$	78	$	24	$	102
Risk management liabilities - non-current	66		—		15		51		66
Fair value through regulatory liabilities (a)
Risk management liabilities - current	9		—		—		9		9
Risk management liabilities - non-current	79		—		1		78		79
Amortized cost
Current portion of long-term debt	360		—		360		—		360
Long-term debt	7,626		—		8,451		—		8,451
Other current liabilities (b)	37		—		37		—		37
	$	8,279	$	—	$	8,942	$	162	$	9,104

(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)    Excludes non-financial liabilities.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 119

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	$	82	$	—	$	31	$	51	$	82
Risk management assets - non-current	31		—		7		24		31
Equity securities(b)	4		4		—		—		4
Fair value through regulatory assets (a)
Risk management assets - current	5		—		—		5		5
Risk management assets - non-current	8		—		—		8		8
Amortized cost
Loans and receivables (b)	45		—		46		—		46
	$	175	$	4	$	84	$	88	$	176
Financial liabilities
Fair value through net income(a)
Risk management liabilities - current	$	121	$	—	$	99	$	22	$	121
Risk management liabilities - non-current	77		—		19		58		77
Fair value through regulatory liabilities (a)
Risk management liabilities - current	4		—		1		3		4
Risk management liabilities - non-current	90		—		—		90		90
Amortized cost
Current portion of long-term debt	923		—		923		—		923
Long-term debt	5,928		—		6,264		—		6,264
Other current liabilities (c)	15		—		15		—		15
	$	7,158	$	—	$	7,321	$	173	$	7,494

(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.

Financial assets and liabilities not included in the fair value hierarchy table include money market funds, short term debt, commercial paper, and a long-term receivable (Note 12). The carrying value of these financial instruments approximate their fair value, which reflects the short-term maturity and/or normal credit terms of these financial instruments.

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, 2020:

	Net Fair Value		Valuation Technique	Unobservable Inputs	Range							Weighted Average (a)
Natural gas	$	(73)	Discounted Cash Flow	Natural Gas Basis Price (per Dth)	$	(1.27)		-	$	2.64		$	(0.37)
Natural gas	$	(1)	Option Model	Natural Gas Basis Price (per Dth)	$	(1.27)		-	$	2.58		$	(0.01)
				Annualized Volatility of Spot Market Natural Gas	13		%	-	917		%	73		%
Electricity	$	(19)	Discounted Cash Flow	Electricity Congestion Price (per MWh)	$	(6.26)		-	$	61.88		$	13.57

(a) Unobservable inputs were weighted by transaction volume.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 120

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	2020						2019
	Natural Gas		Electricity		Total		Natural Gas		Electricity		Total
Balance, beginning of year	$	(85)	$	—	$	(85)	$	(149)	$	(14)	$	(163)
Realized and unrealized gains (losses):
Recorded in income	8		(55)		(47)		48		1		49
Recorded in regulatory assets	(1)		—		(1)		24		—		24
Transfers into Level 3	(1)		—		(1)		(9)		—		(9)
Transfers out of Level 3	1		—		1		12		—		12
Purchases	—		3		3		—		(11)		(11)
Settlements	4		32		36		(17)		24		7
Foreign exchange translation	—		1		1		6		—		6
Balance, end of year	$	(74)	$	(19)	$	(93)	$	(85)	$	—	$	(85)

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, 2020 were due to an increase in valuations using observable market inputs. Transfers into Level 3 during the year ended December 31, 2020 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	2020		2019
Recorded to revenue	$	(79)	$	75
Recorded to cost of sales	32		(26)
	$	(47)	$	49

Summary of Unrealized Gains (Losses) on Risk Management Contracts Recognized in Net Income

Year Ended December 31	2020		2019
Natural gas	$	32	$	23
Energy exports	10		(87)
Crude oil and NGLs	4		—
NGL frac spread	(5)		(17)
Power	(15)		(5)
Foreign exchange	(5)		1
	$	21	$	(85)

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. – 2020 MD&A and Financial Statements - 121

As at	December 31, 2020
	Gross amounts of recognized assets/liabilities		Gross amounts offset in balance sheet		Netting of collateral		Net amounts presented in balance sheet
Risk management assets (a)
Natural gas	$	104	$	(38)	$	(3)	$	63
Energy exports	86		(86)		36		36
Crude oil and NGLs	1		—		—		1
Power	30		(8)		—		22
Foreign exchange	27		(3)		(1)		23
	$	248	$	(135)	$	32	$	145
Risk management liabilities (b)
Natural gas	$	173	$	(38)	$	(3)	$	132
Energy exports	153		(86)		—		67
NGL frac spread	6		—		—		6
Power	58		(8)		1		51
Foreign exchange	3		(3)		—		—
	$	393	$	(135)	$	(2)	$	256

(a)Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $98 million and risk management assets (non‑current) balance of $47 million.

(b)Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $111 million and risk management liabilities (non‑current) balance of $145 million.

As at	December 31, 2019
	Gross amounts of recognized assets/liabilities		Gross amounts offset in balance sheet		Netting of collateral		Net amounts presented in balance sheet
Risk management assets (a)
Natural gas	$	121	$	(54)	$	—	$	67
Energy exports	10		(3)		5		12
Power	54		(7)		—		47
	$	185	$	(64)	$	5	$	126
Risk management liabilities (b)
Natural gas	$	226	$	(54)	$	(28)	$	144
Energy exports	90		(3)		—		87
NGL frac spread	2		—		—		2
Power	69		(7)		(3)		59
	$	387	$	(64)	$	(31)	$	292

(a)Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $87 million and risk management assets (non‑current) balance of $39 million.

(b)Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $125 million and risk management liabilities (non‑current) balance of $167 million.

Cash Collateral

The following table presents collateral not offset against risk management assets and liabilities:

As at	December 31, 2020		December 31, 2019
Collateral posted with counterparties	$	4	$	29
Cash collateral held representing an obligation	$	—	$	—

AltaGas Ltd. – 2020 MD&A and Financial Statements - 122

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, 2020, AltaGas has posted $nil (December 31, 2019 - $6 million) 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, 2020		December 31, 2019
Risk management liabilities with credit-risk-contingent features	$	32	$	42
Maximum potential collateral requirements	$	26	$	29

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 2040. 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, 2020 and 2019:

December 31, 2020	Fixed price (per GJ)	Period (months)	Notional volume (GJ)	Fair Value
Sales	1.58 to 7.86	1-157	590,054,996	$	32
Purchases	1.58 to 6.47	1-240	1,522,958,497	$	(106)
Swaps	2.29 to 7.86	1-60	288,613,586	$	5
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	$	29
Purchases	0.22 to 6.81	1-167	1,406,991,689	$	(104)
Swaps	0.22 to 10.24	1-51	541,652,374	$	(2)

AltaGas Ltd. – 2020 MD&A and Financial Statements - 123

Crude Oil and NGLs

In the normal course of business, AltaGas purchases and sells crude oil, condensates, and LPGs. The fixed price and market price contracts for both the purchase and sale of crude oil, condensates, and LPGs extend to 2021.

December 31, 2020	Fixed price (per Bbl)	Period (months)	Notional volume (Bbl)	Fair Value
Sales	37.43 to 62.59	1	680,000	$	(1)
Purchases	19.92 to 59.01	1-9	221,000	$	2

Energy Exports

AltaGas entered into a series of swaps to lock in a portion of the volumes exposed to the propane and butane price differentials between North American Indices and the Far East Index for contracts not under tolling arrangements at RIPET and Ferndale. AltaGas had the following contracts outstanding as at December 31, 2020:

December 31, 2020	Fixed price (per Bbl)	Period (months)	Notional volume (Bbl)	Fair Value
Propane and butane swaps	3.57 to 61.46	1-36	37,425,488	$	(31)
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)

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, 2020 and 2019:

December 31, 2020	Fixed price	Period (months)	Notional volume		Fair Value
Propane swaps	28.83 to 35.36/Bbl	1-12	1,270,350	Bbl	$	(5)
Butane swaps	32.45 to 34.02/Bbl	1-12	307,784	Bbl	$	(1)
Crude oil swaps	60.08 to 61.95/Bbl	1-12	123,120	Bbl	$	—
Natural gas swaps	1.58 to 1.86/GJ	1-12	7,281,570	GJ	$	—
December 31, 2019	Fixed price	Period (months)	Notional volume		Fair Value
Butane swaps	73.02 to 75.15/Bbl	1-12	346,852	Bbl	$	(1)
Crude oil swaps	73.02 to 75.15/Bbl	1-12	212,587	Bbl	$	(1)
Natural gas swaps	1.58 to 1.86/GJ	1-12	3,883,992	GJ	$	—

AltaGas Ltd. – 2020 MD&A and Financial Statements - 124

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 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 2025. As at December 31, 2020, 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, 2020 and 2019:

December 31, 2020	Fixed price (per MWh)	Period (months)	Notional volume (MWh)	Fair Value
Power sales	24.56 to 61.75	1-33	5,482,242	$	13
Power purchases	24.56 to 61.88	1-63	8,848,007	$	(18)
Swap purchases	(6.26) to 74.26	1-44	24,081,519	$	(24)
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
Power purchases	31.63 to 66.76	1-60	8,552,467	$	(27)
Swap purchases	(7.88) to 74.26	1-48	25,058,577	$	(24)

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, 2020:

Factor	Increase or decrease to forward prices	Increase or decrease to income before tax ($ millions)
PJM power price	US$1/MWh	2
AECO natural gas price	$0.50/GJ	1
NYMEX natural gas price	US$0.50/GJ	36
Energy Exports:
Propane Far East Index to domestic supply	$1/Bbl	10
Baltic LPG Freight	$1/Bbl	11
NGL frac spread:
Propane	$1/Bbl	1
Natural gas	$0.50/GJ	4
Foreign exchange swaps	$0.01 CAD to USD	1

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.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 125

AltaGas may designate its U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. As at December 31, 2020, AltaGas has not designated any outstanding debt as a net investment hedge (December 31, 2019 - US$300 million). For the year ended December 31, 2020, AltaGas incurred an after-tax unrealized loss of $9 million arising from the translation of debt in OCI (2019 ‑ after-tax unrealized gains of $60 million).

In connection with the Petrogas Acquisition, AltaGas acquired various commodity and financial derivative instruments, including the following foreign exchange forward contracts which are outstanding as at December 31, 2020:

Foreign exchange forward contract	Notional Amount	Duration	Weighted average foreign exchange rate	Fair Value
Forward USD sales	US$29	Less than one year	1.3591	$	3
Forward USD purchases	US$356	Less than one year	1.2824	$	(3)
Foreign exchange swaps (purchases)	US$410	Less than one year	1.3322	$	23

For the year ended December 31, 2020, AltaGas recorded an after-tax realized gain of $1 million on all foreign exchange forward contracts.

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, 2020, approximately 83 percent of AltaGas’ total outstanding short-term and long-term debt was at fixed rates (December 31, 2019 - 76 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, 2020.

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, 2020, 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, 2020, a pre-tax loss of $3 million was recorded related to these instruments (2019 - pre-tax loss of $2 million).

AltaGas Ltd. – 2020 MD&A and Financial Statements - 126

Accounts Receivable Past Due or Impaired

With the exception of accounts receivable which are due in one year or less as summarized in the following table, AltaGas does not have any past due or impaired accounts receivables (AR) as at December 31, 2020:

As at December 31, 2020	Total		AR accruals		Receivables impaired		Less than 30 days		31 to 60 days		61 to 90 days		Over 90 days
Trade receivable	$	1,465	$	396	$	41	$	906	$	52	$	17	$	53
Other	20		—		—		20		—		—		—
Allowance for credit losses	(41)		—		(41)		—		—		—		—
	$	1,444	$	396	$	—	$	926	$	52	$	17	$	53

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	$	343	$	33	$	758	$	61	$	12	$	31
Other	17		—		—		17		—		—		—
Allowance for credit losses	(33)		—		(33)		—		—		—		—
	$	1,222	$	343	$	—	$	775	$	61	$	12	$	31

AltaGas Ltd. – 2020 MD&A and Financial Statements - 127

The following table provides a summary of changes to the allowance for credit losses by segment and major type:

	Year Ended December 31, 2020
	Accounts Receivable		Contract Assets (a)		Other long-term investments and other assets (b)		Total
Utilities
Balance, beginning of period	$	31	$	—	$	—	$	31
Adjustment upon adoption of ASC 326 (c)	2		—		—		2
Foreign exchange translation	(1)		—		—		(1)
New allowance (d)	32		—		—		32
Written off	(28)		—		—		(28)
Recoveries collected	4		—		—		4
Balance, end of period	$	40	$	—	$	—	$	40
Midstream
Balance, beginning of period	$	1	$	—	$	—	1
Adjustment upon adoption of ASC 326	—		1		3		4
Recoveries collected	—		—		(1)		(1)
Balance, end of period	$	1	$	1	$	2	$	4
Corporate/Other
Balance, beginning of period	$	2	$	—	$	—	$	2
Adjustment upon adoption of ASC 326	—		—		1		1
Written off	(2)		—		—		(2)
Recoveries collected	—		—		(1)		(1)
Balance, end of period	$	—	$	—	$	—	$	—
Total	$	41	$	1	$	2	$	44

(a)An allowance for credit loss is assessed quarterly and is recorded based on historical default rates published by external credit rating agencies and a rate associated with the estimated time frame that the contract asset will be billed to the customer.

(b)Includes loan to affiliate, which is no longer outstanding at December 31, 2020, and other long-term receivables (Notes 12 and 29). An allowance for credit loss is assessed quarterly and is recorded based on historical default rates published by external credit rating agencies and a rate commensurate with the period in which the receivable is expected to be collected.

(c)Based on previous collection experience, AltaGas did not record an allowance for credit losses for its contract assets associated with its energy management services projects with the U.S. federal government.

(d)Includes $8 million recorded to a regulatory asset relating to the impact of COVID-19 on uncollectible accounts.

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. – 2020 MD&A and Financial Statements - 128

AltaGas had the following contractual maturities with respect to financial liabilities:

	Contractual maturities by period
As at December 31, 2020	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Accounts payable and accrued liabilities	$	1,561	$	1,561	$	—	$	—	$	—
Dividends payable	22		22		—		—		—
Short-term debt	256		256		—		—		—
Other current liabilities (a)	37		37		—		—		—
Risk management contract liabilities	256		111		51		22		72
Current portion of long-term debt (b)	356		356		—		—		—
Long-term debt (b)	7,581		—		1,771		1,324		4,486
	$	10,069	$	2,343	$	1,822	$	1,346	$	4,558

(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, 2019	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Accounts payable and accrued liabilities	$	1,325	$	1,325	$	—	$	—	$	—
Dividends payable	22		22		—		—		—
Short-term debt	460		460		—		—		—
Other current liabilities (a)	15		15		—		—		—
Risk management contract liabilities	292		125		34		13		120
Current portion of long-term debt (b)	920		920		—		—		—
Long-term debt (b)	5,873		—		1,489		922		3,462
	$	8,907	$	2,867	$	1,523	$	935	$	3,582

(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. – 2020 MD&A and Financial Statements - 129

24. Revenue

The following tables disaggregate revenue by major sources for the year:

	Year Ended December 31, 2020
	Utilities		Midstream		Corporate/Other		Total (a)
Revenue from contracts with customers
Commodity sales contracts	$	1,338	$	1,097	$	1	$	2,436
Midstream service contracts	—		277		—		277
Gas sales and transportation services	2,394		—		—		2,394
Storage services	25		—		—		25
Other	9		—		20		29
Total revenue from contracts with customers	$	3,766	$	1,374	$	21	$	5,161
Other sources of revenue
Revenue from alternative revenue programs (b)	$	96	$	—	$	—	$	96
Leasing revenue (c)	1		139		100		240
Risk management and trading activities (d) (e)	(31)		112		—		81
Other	(15)		10		14		9
Total revenue from other sources	$	51	$	261	$	114	$	426
Total revenue	$	3,817	$	1,635	$	135	$	5,587

(a)    In the first quarter of 2020, AltaGas revised its reportable segments. Comparative period numbers have been adjusted to reflect this change. Refer to Note 32 for additional information.

(b)    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.

(c)    Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Corporate/Other segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases.

(d)    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. A portion of revenue generated by the Utilities segment is from the physical sale and delivery of natural gas and power to end users.

(e)    Trading margins in the Midstream segment are reported in risk management and trading activities. AltaGas 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, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues for the year ended December 31, 2020 of $437 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract and an Asset Management Agreement (AMA), which are in scope of ASC 606, are reported within risk management and trading activities. Revenue from the GAIL contract 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 from the AMA is recognized based on the amount WGL Midstream has the right to invoice the customer in accordance with ASC 606. WGL executed the AMA in April 2020.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 130

	Year Ended December 31, 2019
	Utilities		Midstream		Corporate/Other		Total (a)
Revenue from contracts with customers
Commodity sales contracts	$	1,428	$	746	$	51	$	2,225
Midstream service contracts	—		145		—		145
Gas sales and transportation services	2,501		—		—		2,501
Storage services	28		—		—		28
Other	9		3		29		41
Total revenue from contracts with customers	$	3,966	$	894	$	80	$	4,940
Other sources of revenue
Revenue from alternative revenue programs (b)	$	30	$	—	$	—	$	30
Leasing revenue (c)	1		137		105		243
Risk management and trading activities (d) (e)	52		188		22		262
Other	(5)		9		16		20
Total revenue from other sources	$	78	$	334	$	143	$	555
Total revenue	$	4,044	$	1,228	$	223	$	5,495

(a)In the first quarter of 2020, AltaGas revised its reportable segments. Comparative period numbers have been adjusted to reflect this change. Refer to Note 32 for additional information.

(b)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.

(c)Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Corporate/Other segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases.

(d)Risk management activities involve the use of derivative instruments such as physical and financial swaps, and forward contracts. These derivatives are accounted for under ASC 815 and ASC 825. A portion of revenue generated by the Utilities segment is from the physical sale and delivery of natural gas and power to end users.

(e)Trading margins in the Midstream segment are reported in risk management and trading activities. AltaGas 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, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues for the year ended December 31, 2019 of $505 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract and an Asset Management Agreement (AMA), which are in scope of ASC 606, are reported within risk management and trading activities. Revenue from the GAIL contract 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 from the AMA is recognized based on the amount WGL Midstream has the right to invoice the customer in accordance with ASC 606. WGL executed the AMA in April 2020.

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.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 131

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.

Commodity Sales

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 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 RIPET and Ferndale generate revenue from the sale and delivery of LPGs to customers in Asia shipped from offshore export terminals. Revenue is recognized when LPGs are 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 LPGs loaded on a vessel. Petrogas' commodity sales also include the sale of upgraded crude oil, processed finished products, and various fuels. Delivery takes place when there is a sales contract in place, specifying delivery volumes and sales prices. The consideration received under these contracts is variable based on commodity prices.

Midstream Service Contracts

AltaGas earns revenue from its field gathering and processing facilities, extraction facilities, storage facilities, truck hauling services, rail and truck loading and unloading terminalling, 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

AltaGas Ltd. – 2020 MD&A and Financial Statements - 132

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.

Petrogas' storage fees are typically recognized in revenue ratably over the term of the contract and rail and truck loading and unloading fees are recognized when the volumes are delivered or received.

Corporate/Other Segment

For the Corporate/Other segment, the majority of revenue relates to remaining power assets, from which revenue is primarily earned 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. This includes energy generated from combined heating and power assets that are 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.

Contract Balances

As at December 31, 2020, a contract asset of $51 million ($50 million net of credit losses) has been recorded within long-term investments and other assets on the Consolidated Balance Sheets (December 31, 2019 – $30 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, 2020 there is a contract asset of $21 million (December 31, 2019 - $59 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, 2020, contract liabilities of $nil (December 31, 2019 - $2 million) have been recorded within accounts payable and accrued liabilities on the Consolidated Balance Sheets. The contract liabilities consisted 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.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 133

Contract Assets

As at	December 31, 2020		December 31, 2019
Balance, beginning of year	$	89	$	59
Additions	30		32
Transfers to accounts receivable	(49)		—
Foreign exchange translation	1		(2)
Balance, end of year	$	71	$	89

Contract Liabilities

As at	December 31, 2020		December 31, 2019
Balance, beginning of year	$	2	$	2
Additions	2		2
Revenue recognized from contract liabilities (a)	(4)		(2)
Balance, end of year	$	—	$	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, 2020:

	2021		2022		2023		2024		2025		2026 & beyond		Total
Midstream service contracts	$	125	$	131	$	128	$	128	$	125	$	1,037	$	1,674
Storage services	24		23		23		23		23		142		258
Other	7		2		2		2		2		9		24
	$	156	$	156	$	153	$	153	$	150	$	1,188	$	1,956

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.

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.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 134

Dividend Reinvestment and Optional Cash Purchase Plan (DRIP or the Plan)

The Plan consisted of two components: 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 (paid 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.

Common Shares Issued and Outstanding	Number of  shares	Amount
January 1, 2019	275,224,066	$	6,654
Shares issued for cash on exercise of options	76,177	1
Deferred taxes on share issuance cost	—	(4)
Shares issued under DRIP	3,774,442	68
December 31, 2019	279,074,685	$	6,719
Shares issued for cash on exercise of options	88,082	1
Deferred taxes on share issuance cost	—	(3)
Shares issued under DRIP	331,532	6
Issued and outstanding at December 31, 2020	279,494,299	$	6,723

Preferred Shares

As at	December 31, 2020			December 31, 2019
Issued and Outstanding	Number of shares	Amount		Number of shares	Amount
Series A	6,746,679	$	169	5,511,220	$	138
Series B	1,253,321	31		2,488,780	62
Series C	8,000,000	206		8,000,000	206
Series E	8,000,000	200		8,000,000	200
Series G	6,885,823	172		6,885,823	172
Series H	1,114,177	28		1,114,177	28
Series I	—	—		8,000,000	200
Series K	12,000,000	300		12,000,000	300
Share issuance costs, net of taxes		(29)			(29)
	44,000,000	$	1,077	52,000,000	$	1,277

On December 31, 2020, all outstanding Series I shares were redeemed. No gain or loss was recognized upon redemption. In 2019, all outstanding Washington Gas preferred shares were redeemed. A gain of $4 million was recognized upon redemption.

.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 135

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)	3.060	%	$0.76500	$25	September 30, 2025	Series B
Series B (f) (g)	Floating		Floating	$25	September 30, 2025	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)	4.240	%	$1.06050	$25	September 30, 2024	Series H
Series H (f) (g)	Floating		Floating	$25	September 30, 2024	Series G
Series K (i)	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 to 8,000,000 of each of Series D Shares, Series F Shares, and up to 12,000,000 of Series L Shares, subject to certain conditions, upon conversion by the holders of the applicable currently issued and outstanding series of preferred shares noted opposite such series in the table on the applicable conversion option date. If issued upon the conversion of the applicable series of preferred shares, Series F Shares, and Series L Shares are also redeemable for $25.50, and Series D Shares are redeemable for US$25.50 on any date after the applicable conversion option date, plus all accrued but unpaid dividends to, but excluding, the date fixed for redemption.

(b)The holders of Series A Shares, Series C Shares, Series E Shares, Series G Shares, Series H 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, 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 plus 2.66 percent (Series A Shares), 3.17 percent (Series E Shares), and 3.06 percent (Series G Shares).

(f)Holders of Series B Shares 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 plus 2.66 percent (Series B Shares) and 3.06 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, 2020, the floating quarterly dividend rate is $0.17069 per share for Series B Shares and $0.195349 per share for Series H Shares for the period starting December 31, 2020 to, but excluding, March 31, 2021.

(g)Series B Shares can be redeemed for $25.50 per share on any date after September 30, 2015 that is not a Series B conversion date, plus all accrued and unpaid dividends to, but excluding, the date fixed for redemption. Series H Shares can be redeemed for $25.50 per 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 plus 3.58 percent.

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

Share Option Plan

AltaGas has an employee share option plan under which officers, employees, and service providers (as defined by the TSX) are eligible to receive grants. As at December 31, 2020, 13,915,160 shares were reserved for issuance under the plan.

As at December 31, 2020, 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, 2020, the unexpensed fair value of share option compensation cost associated with future periods was $4 million (December 31, 2019 ‑ $5 million).

AltaGas Ltd. – 2020 MD&A and Financial Statements - 136

The following table summarizes information about the Corporation’s share options:

	December 31, 2020			December 31, 2019
As at	Options outstanding			Options outstanding
	Number of options	Exercise price (a)		Number of options	Exercise price (a)
Share options outstanding, beginning of year	7,043,956	$	22.49	6,309,183	$	25.18
Granted	2,501,755	19.46		2,287,385	19.12
Exercised	(88,082)	14.89		(76,177)	14.52
Forfeited	(631,549)	26.00		(1,165,435)	27.31
Expired	(463,869)	27.69		(311,000)	36.16
Share options outstanding, end of year	8,362,211	$	21.06	7,043,956	$	22.49
Share options exercisable, end of year	3,607,391	$	23.59	2,921,642	$	27.70

(a)Weighted average.

As at December 31, 2020, the aggregate intrinsic value of the total share options exercisable was $5 million (December 31, 2019 - $3 million), the total intrinsic value of share options outstanding was $9 million (December 31, 2019 - $12 million) and the total intrinsic value of share options exercised was less than $1 million (December 31, 2019 - less than $1 million).

The following table summarizes the employee share option plan as at December 31, 2020:

	Options outstanding				Options exercisable
	Number outstanding	Weighted average exercise price		Weighted average remaining contractual life (years)	Number exercisable	Weighted average exercise price		Weighted average remaining contractual life (years)
$14.52 to $18.00	2,446,392	$	15.24	4.07	1,359,457	$	14.92	4.00
$18.01 to $25.08	3,930,345	19.56		4.80	528,252	19.54		4.47
$25.09 to $41.00	1,985,474	31.21		1.82	1,719,682	31.68		1.64
	8,362,211	$	21.06	3.88	3,607,391	$	23.59	2.95

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	2020	2019
Fair value per options ($)	2.61	2.30
Risk-free interest rate (%)	1.54	1.48
Expected life (years)	6	6
Expected volatility (%)	25.40	24.84
Annual dividend per share ($) (a)	0.96	0.96
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 to 44 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. – 2020 MD&A and Financial Statements - 137

PUs, RUs, and DSUs (number of units)	2020	2019
Balance, beginning of year	6,484,831	9,908,154
Granted	1,158,547	674,971
Vested and paid out	(681,841)	(791,335)
Forfeited	(1,342,832)	(3,377,962)
Units in lieu of dividends	113,429	71,003
Outstanding, end of year	5,732,134	6,484,831

For the year ended December 31, 2020, the compensation expense recorded for the Phantom Plan and DSUP was $16 million (2019 – $22 million). As at December 31, 2020, the unrecognized compensation expense relating to the remaining vesting period for the Phantom Plan was $23 million (December 31, 2019 ‑ $22 million) and is expected to be recognized over the vesting period.

26. Net Income Per Common Share

The following table summarizes the computation of net income per common share:

	Year Ended December 31
	2020		2019
Numerator:
Net income applicable to controlling interests	$	552	$	833
Less: Preferred share dividends	(66)		(68)
Gain on redemption of preferred shares (note 25)	—		4
Net income applicable to common shares	$	486	$	769
Denominator:
(millions of shares)
Weighted average number of common shares outstanding	279.4		276.9
Dilutive equity instruments (a)	0.3		0.5
Weighted average number of common shares outstanding - diluted	279.7		277.4
Basic net income per common share	$	1.74	$	2.78
Diluted net income per common share	$	1.74	$	2.77

(a)Determined using the treasury stock method.

For the year ended December 31, 2020, 7.0 million share options (2019 – 4.3 million) were excluded from the diluted net income per share calculation as their effects were anti‑dilutive.

27. Other Income

Year Ended December 31	2020		2019
Gains on asset sales (note 4)	$	223	$	876
Gain on remeasurement of previously held interest in AIJVLP (note 3)	22		—
Other components of net benefit cost (note 28)	52		27
Interest income and other revenue	9		9
Losses on investments	—		(4)
Total	$	306	$	908

AltaGas Ltd. – 2020 MD&A and Financial Statements - 138

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.

In 2020, AltaGas made a voluntary change in accounting principle for calculating the market-related value of assets used in the determination of Washington Gas' net periodic pension and other post-retirement benefit plan costs. This change in accounting principle impacts the calculation of net periodic benefit cost recorded within the line item “other income” on the Consolidated Statements of Income. Refer to Note 2 for additional information.

Defined Contribution Plan

AltaGas has a defined contribution (DC) pension plan for substantially all employees. The pension cost recorded for the DC plan was $21 million for the year ended December 31, 2020 (2019 - $20 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 six in 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 three 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 for the year ended December 31, 2019. 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, 2022, and will be filed with the pension regulators in 2023. 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.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 139

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 are fully funded.

Rabbi Trusts

Rabbi trusts of $28 million as at December 31, 2020 have been funded to satisfy the employee benefit obligations associated with WGL’s various pension plans (December 31, 2019 - $57 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, 2020	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	$	36	$	2	$	1,725	$	428	$	1,761	$	430
Actuarial loss	1		—		137		32		138		32
Current service cost	3		—		27		9		30		9
Member contributions	—		—		—		2		—		2
Interest cost	1		—		60		15		61		15
Benefits paid	(4)		—		(82)		(24)		(86)		(24)
Expenses paid	—		—		(1)		—		(1)		—
Settlements	—		—		(25)		—		(25)		—
Foreign exchange translation	—		—		(41)		(10)		(41)		(10)
Balance, end of year	$	37	$	2	$	1,800	$	452	$	1,837	$	454
Plan assets
Fair value, beginning of year	$	15	$	—	$	1,504	$	906	$	1,519	$	906
Actual return on plan assets	1		—		275		157		276		157
Employer contributions	4		—		37		—		41		—
Member contributions	—		—		—		2		—		2
Benefits paid	(4)		—		(82)		(24)		(86)		(24)
Expenses paid	—		—		(1)		—		(1)		—
Settlements	—		—		(25)		—		(25)		—
Foreign exchange translation	—		—		(41)		(25)		(41)		(25)
Fair value, end of year	$	16	$	—	$	1,667	$	1,016	$	1,683	$	1,016
Funded status	$	(21)	$	(2)	$	(133)	$	564	$	(154)	$	562

(a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 140

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	$	2	$	1,635	$	458	$	1,669	$	460
Actuarial loss (gain)	2		—		182		(15)		184		(15)
Current service cost	3		—		24		9		27		9
Member contributions	—		—		—		2		—		2
Interest cost	1		—		68		19		69		19
Benefits paid	(4)		—		(77)		(24)		(81)		(24)
Expenses paid	—		—		(1)		—		(1)		—
Settlements	—		—		(24)		—		(24)		—
Other	—		—		—		1		—		1
Foreign exchange translation	—		—		(82)		(22)		(82)		(22)
Balance, end of year	$	36	$	2	$	1,725	$	428	$	1,761	$	430
Plan assets
Fair value, beginning of year	$	14	$	—	$	1,354	$	791	$	1,368	$	791
Actual return on plan assets	1		—		284		177		285		177
Employer contributions	4		—		39		—		43		—
Member contributions	—		—		—		2		—		2
Benefits paid	(4)		—		(77)		(23)		(81)		(23)
Expenses paid	—		—		(1)		—		(1)		—
Settlements	—		—		(25)		—		(25)		—
Foreign exchange translation	—		—		(70)		(41)		(70)		(41)
Fair value, end of year	$	15	$	—	$	1,504	$	906	$	1,519	$	906
Funded status	$	(21)	$	(2)	$	(221)	$	478	$	(242)	$	476

(a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation.

For the year ended December 31, 2020, AltaGas' pension plans incurred actuarial losses primarily due to the decrease in discount rates, which were the result of a decline in high-quality corporate bond yield curves in the Canadian and U.S. markets. For the year ended December, 31, 2019, AltaGas' defined benefit plans incurred actuarial losses for the same reason as mentioned above. AltaGas' post-retirement benefits plans incurred actuarial gains primarily due to updated census data and assumptions related to the HRA, partially offset by the decrease in discount rates.

The following amounts were included in the Consolidated Balance Sheets:

	December 31, 2020						December 31, 2019
	Defined Benefit		Post- Retirement Benefits		Total		Defined Benefit		Post-Retirement Benefits		Total (a)
Prepaid post-retirement benefits	$	—	$	572	$	572	$	—	$	487	$	487
Accounts payable and accrued liabilities (a)	(9)		—		(9)		(26)		—		(26)
Future employee obligations	(145)		(10)		(155)		(216)		(11)		(227)
	$	(154)	$	562	$	408	$	(242)	$	476	$	234

(a) Account balances on the Consolidated Balance Sheets also include certain non-pension related amounts.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 141

The accumulated benefit obligation for all defined benefit plans were:

As at	December 31, 2020				December 31, 2019
	Canada		United States		Canada		United States
Accumulated benefit obligation (a)	$	36	$	1,704	$	35	$	1,616

(a)Accumulated benefit obligation differs from projected benefit obligation in that it does not include an assumption with respect to future compensation levels.

For those pension plans where the projected benefit obligation exceeded the fair value of plan assets as at December 31, 2020, the cumulative obligation and asset balances were:

As at	December 31, 2020				December 31, 2019
	Defined Benefit		Post-Retirement Benefits		Defined Benefit		Post-Retirement Benefits
Projected benefit obligation	$	1,824	$	14	$	1,757	$	13
Plan assets	$	1,670	$	3	$	1,515	$	3

For those pension plans where the accumulated benefit obligation exceeded the fair value of plan assets as at December 31, 2020, the cumulative obligation and asset balances were:

As at	December 31, 2020				December 31, 2019
	Defined Benefit		Post-Retirement Benefits		Defined Benefit		Post-Retirement Benefits
Accumulated benefit obligation	$	427	$	14	$	1,648	$	13
Plan assets	$	329	$	3	$	1,515	$	3

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, 2020	Canada				United States				Total
	Defined Benefit		Post- Retirement Benefits		Defined Benefit		Post-Retirement Benefits		Defined Benefit		Post-Retirement Benefits
Past service cost	$	—	$	—	$	—	$	(3)	$	—	$	(3)
Net actuarial gain (loss)	(9)		(1)		6		(8)		(3)		(9)
Recognized in AOCI pre-tax	$	(9)	$	(1)	$	6	$	(11)	$	(3)	$	(12)
Increase (decrease) by the amount included in deferred tax liabilities	2		—		(2)		3		—		3
Net amount in AOCI after-tax	$	(7)	$	(1)	$	4	$	(8)	$	(3)	$	(9)

Year Ended December 31, 2019	Canada				United States				Total
	Defined Benefit		Post- Retirement Benefits		Defined Benefit		Post- Retirement Benefits		Defined Benefit		Post- Retirement Benefits
Net actuarial gain (loss)	$	(9)	$	—	$	(15)	$	18	$	(24)	$	18
Recognized in AOCI pre-tax	$	(9)	$	—	$	(15)	$	18	$	(24)	$	18
Increase (decrease) by the amount included in deferred tax liabilities	2		—		7		(9)		9		(9)
Net amount in AOCI after-tax	$	(7)	$	—	$	(8)	$	9	$	(15)	$	9

AltaGas Ltd. – 2020 MD&A and Financial Statements - 142

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, 2020	Canada				United States				Total
	Defined Benefit		Post- Retirement Benefits		Defined Benefit		Post- Retirement Benefits		Defined Benefit		Post- Retirement Benefits
Past service credit	$	—	$	—	$	—	$	(94)	$	—	$	(94)
Net actuarial loss (gain)	—		—		68		(241)		68		(241)
Recognized in regulatory asset (liability)	$	—	$	—	$	68	$	(335)	$	68	$	(335)

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	$	(105)	$	1	$	(105)
Net actuarial loss (gain)	—		—		127		(156)		127		(156)
Recognized in regulatory asset (liability)	$	—	$	—	$	128	$	(261)	$	128	$	(261)

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.

The net pension expense by plan was as follows:

	Year Ended December 31, 2020
	Canada				United States				Total
	Defined Benefit		Post-Retirement Benefits		Defined Benefit		Post-Retirement Benefits		Defined Benefit		Post-Retirement Benefits
Current service cost (a)	$	3	$	—	$	27	$	9	$	30	$	9
Interest cost (b)	1		—		60		15		61		15
Expected return on plan assets (b) (c)	(1)		—		(81)		(40)		(82)		(40)
Amortization of past service credit (b)	—		—		—		(19)		—		(19)
Amortization of net actuarial loss (gain) (b) (c)	1		—		10		(5)		11		(5)
Plan settlements (b)	—		—		7		—		7		—
Net benefit cost (income) recognized	$	4	$	—	$	23	$	(40)	$	27	$	(40)

(a)Recorded under the line item “operating and administrative” expenses on the Consolidated Statements of Income.

(b)Recorded under the line item “other income” on the Consolidated Statements of Income.

(c)Includes the impact of the voluntary change in accounting principle implemented in 2020. Refer to Note 2 for additional information.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 143

	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)	$	3	$	—	$	24	$	9	$	27	$	9
Interest cost (b)	1		—		68		19		69		19
Expected return on plan assets (b)	(1)		—		(75)		(37)		(76)		(37)
Amortization of past service credit (b)	—		—		—		(22)		—		(22)
Amortization of net actuarial loss (b)	1		—		12		—		13		—
Plan settlements (b)	—		—		4		—		4		—
Other (b)	—		—		—		1		—		1
Net benefit cost (income) recognized	$	4	$	—	$	33	$	(30)	$	37	$	(30)

(a)Recorded under the line item “operating and administrative” expenses on the Consolidated Statements of Income.

(b)Recorded under the line item “other income” on the Consolidated Statements of Income.

The objective 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 70 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, 2020:

Canada	Fair value		Level 1		Level 2		Percentage of Plan Assets (%)
Cash and short-term equivalents	$	2	$	2	$	—	13
Canadian equities	3		3		—		19
Foreign equities	4		4		—		25
Fixed income	6		6		—		38
Real estate	1		—		1		5
	$	16	$	15	$	1	100

AltaGas Ltd. – 2020 MD&A and Financial Statements - 144

United States	Fair value		Level 1		Level 2		Percentage of Plan Assets (%)
Cash and short-term equivalents	$	14	$	14	$	—	1
Canadian equities	1		1		—		—
Foreign equities (a)	357		357		—		13
Fixed income	1,002		129		873		37
Other (b)	23		—		23		1
Total investments in the fair value hierarchy	$	1,397	$	501	$	896	52
Investments measured at net asset value using the NAV practical expedient (c)
Commingled funds (d)	$	728					27
Private equity/limited partnership (e)	56						2
Pooled separate accounts (f)	32						1
Collective trust fund (g)	476						18
Total fair value of plan investments	$	2,689					100
Net payable (h)	(6)						—
	$	2,683					100

(a)Investments in foreign equities include U.S. and international securities.

(b)As at December 31, 2020, 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, 2020, investments in commingled funds consisted of approximately 50 percent common stock of large-cap U.S. companies, 20 percent U.S. Government fixed income securities, and 30 percent corporate bonds for WGL’s post-retirement benefit plans.

(e)As at December 31, 2020, investments in a private equity/limited partnership consisted of common stock of international companies.

(f)As at December 31, 2020, investments in pooled separate accounts consisted of income producing properties located in the United States.

(g)As at December 31, 2020, investments in collective trust funds consisted primarily of 90 percent common stock of U.S, companies, 7 percent income producing properties located in the United States, and 3 percent short-term money market investments.

(h)As at December 31, 2020, 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	$	16	$	16	$	—	1
Canadian equities	4		4		—		—
Foreign equities (a)	361		361		—		13
Fixed income	1,008		135		873		37
Real estate	1		—		1		—
Other (b)	23		—		23		1
Total investments in the fair value hierarchy	$	1,413	$	516	$	897	52
Investments measured at net asset value using the NAV practical expedient (c)
Commingled funds(d)	$	728					27
Private equity/limited partnership (e)	56						2
Pooled separate accounts (f)	32						1
Collective trust fund (g)	476						18
Total fair value of plan investments	$	2,705					100
Net payable (h)	(6)						—
	$	2,699					100

(a)Investments in foreign equities include U.S. and international securities.

(b)As at December 31, 2020, 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.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 145

(d)As at December 31, 2020, investments in commingled funds consisted of approximately 50 percent common stock of large-cap U.S. companies, 20 percent U.S. Government fixed income securities, and 30 percent corporate bonds for WGL’s post-retirement benefit plans.

(e)As at December 31, 2020, investments in a private equity/limited partnership consisted of common stock of international companies.

(f)As at December 31, 2020, investments in pooled separate accounts consisted of income producing properties located in the United States.

(g)As at December 31, 2020, investments in collective trust funds consisted primarily of 90 percent common stock of U.S, companies, 7 percent income producing properties located in the United States, and 3 percent short-term money market investments.

(h)As at December 31, 2020, this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable.

Year Ended December 31	2020		2019
Significant actuarial assumptions used in measuring net benefit plan costs	Defined Benefit	Post-Retirement Benefits	Defined Benefit	Post-Retirement Benefits
Discount rate (%)	2.30 - 3.50	3.10 - 3.60	2.90 - 4.40	3.90 - 4.50
Expected long-term rate of return on plan assets (%) (a)	5.25 - 7.05	4.03 - 7.05	5.75 - 7.15	4.66 - 7.15
Rate of compensation increase (%)	2.75 - 4.00	3.50	2.75 - 4.10	4.10
Average remaining service life of active employees (years)	10.2	13.0	9.0	13.2

(a)Only applicable for funded plans

As at December 31	2020		2019
Significant actuarial assumptions used in measuring benefit obligations	Defined Benefit	Post-Retirement Benefits	Defined Benefit	Post-Retirement Benefits
Discount rate (%)	1.90 - 2.80	2.50 - 2.90	2.90 - 3.50	3.10 - 3.60
Rate of compensation increase (%)	1.73 - 3.93	2.50 - 3.00	2.75 - 4.00	3.50

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 between 2.2 and 6.0 percent. The health care cost trend rates were assumed to decline to between 2.2 and 4.5 percent by 2027.

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:
2021	$	16	$	—
Expected benefit payments:
2021	$	90	$	25
2022	$	91	$	22
2023	$	88	$	22
2024	$	89	$	21
2025	$	90	$	21
2026 - 2030	$	466	$	110

AltaGas Ltd. – 2020 MD&A and Financial Statements - 146

29. Commitments, Guarantees, and Contingencies

Commitments

AltaGas has long-term natural gas purchase and transportation arrangements, LPG purchase agreements, crude oil and condensate purchase agreements, electricity purchase arrangements, service agreements, pipeline and storage service contracts, capital commitments, environmental commitments, merger commitments, and operating leases for office space, office equipment, vehicles, rail cars, land, storage, aquatic surface use, and other 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, 2020 are estimated as follows:

	2021		2022		2023		2024		2025		2026 & beyond		Total
Gas purchase (a)	$	1,974	$	2,075	$	1,858	$	1,863	$	1,901	$	17,612	$	27,283
LPG purchase (b)	407		199		161		108		83		258		1,216
Crude oil and condensate purchase (c)	184		—		—		—		—		—		184
Electricity purchase (d)	463		287		106		29		3		—		888
Service agreements (e) (f) (g)	48		32		26		27		27		282		442
Pipeline and storage services (h)	661		637		621		564		528		3,134		6,145
Capital projects (i)	20		1		1		1		1		1		25
Operating leases (j)	96		81		58		50		40		125		450
Environmental (k)	7		3		1		1		1		—		13
Merger commitments (l)	5		2		2		2		1		3		15
Land purchase commitment (m)	20		—		—		—		—		—		20
Post-acquisition contingent payments (n)	—		16		—		—		—		—		16
	$	3,885	$	3,333	$	2,834	$	2,645	$	2,585	$	21,415	$	36,697

(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 fixed prices and forward prices, which may fluctuate significantly from period to period.

(b)AltaGas enters into contracts to purchase LPGs for its operations at RIPET and Ferndale. These contracts are used to ensure that there is an adequate supply of LPGs to meet shipment commitments and to minimize exposure to market price fluctuations. LPG purchase commitments are valued based on forward prices, which may fluctuate significantly from period to period.

(c)As part of the Petrogas Acquisition (Note 3), AltaGas acquired contracts to purchase crude oil and condensates for marketing, sale, and distribution. These contracts are used to ensure that there is an adequate supply of crude oil and condensates to meet the needs of customers and to minimize exposure to market price fluctuations. Crude oil and condensate commitments are valued based on forward prices, which may fluctuate significantly from period to period.

(d)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$21 million of commitments related to renewable energy credits.

(e)In 2014, AltaGas' Blythe facility entered into a Long-Term Service Agreement (LTSA) with a service pro 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, 2020, the total commitment was $153 million payable over the next 15 years, of which $44 million is expected to be paid over the next 5 years.

(f)In 2017, AltaGas entered into a 12-year service agreement commencing in 2019 for tug services to support the marine operations of RIPET.

(g)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.

(h)Pipeline and storage commitments include minimum payments for natural gas transportation, storage and peaking contracts that have expiration dates through 2044.

(i)Commitments for capital projects. Estimated amounts are subject to variability depending on the actual construction costs.

(j)Operating leases include lease arrangements for office space, office equipment, field equipment, rail cars, aquatic use, vehicles, power and gas facilities, transmission and distribution assets, and land.

(k)Environmental commitments include committed payments related to certain environmental response costs.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 147

(l)Represents the estimated future payments of WGL merger commitments that have been accrued but not paid. In addition, there are certain additional merger commitments that were and will be expensed as the costs are incurred, including the investment of up to US$70 million over a ten year period to further extend natural gas service, investment of US$8 million for leak mitigation within three years, which has been paid as of December 31, 2020, hiring damage prevention trainers in each jurisdiction for a total of US$2 million over five years, and developing 15 megawatts of either electric grid energy storage or Tier 1 renewable resources within five years after the merger closed. As at December 31, 2020, the cumulative amount of merger commitments that have been expensed but not yet paid is approximately US$12 million.

(m)As part of the Petrogas Acquisition (Note 3), AltaGas acquired a commitment to purchase land as part of an agreement for it's continued use of the Ferndale terminal.

(n)Contingent payments of up to $16 million are expected to be paid related to the Petrogas Acquisition (Note 3).

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, 2020, 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. On December 10, 2020, the Colorado Court of Appeals issued an unpublished opinion affirming the judgement of the trial court. No further appeal has been taken. The judgment was paid in full in February 2021, and a satisfaction has been filed with the court.

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 $18 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 and $7 million recorded in "regulatory assets" on the Consolidated Balance Sheets for amounts expected to be recovered from customers in future periods through the rate-setting process.

During 2020, AltaGas entered into an Escrow Agreement and a Letter Agreement with the third party to share the cost related to the judgment. Following the execution of the agreements, $9 million funded by the third party was deposited into an escrow fund and recorded as restricted cash in “accounts receivable". The previously recorded receivable was reduced accordingly.

Maryland Show-Cause Order

Following the National Transportation and Safety Board (NTSB) hearing that examined the August 10, 2016, explosion and fire at an apartment complex in Silver Spring, Maryland, on September 5, 2019, the PSC of MD ordered Washington Gas 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 (Show-Cause Order). Following several hearings throughout the course of 2019 and

AltaGas Ltd. – 2020 MD&A and Financial Statements - 148

2020, on December 18, 2020, the PSC of MD found that Washington Gas failed to file annual reports informing the PSC of MD of the status of Washington Gas' program and imposed a US$750,000 penalty on Washington Gas for reporting violations. The PSC of MD ruled that the NTSB probable cause finding constituted hearsay and could not be admitted into the record of the case and did not undertake its own inquiry into the source of the explosion. The PSC of MD did not make any safety-related findings in the case but did find that Washington Gas made an enforceable regulatory commitment to replace all mercury regulators. The US$750,000 penalty was paid in January 2021 and Washington Gas believes that there is no additional liability as a result of the ruling from the PSC of MD. In its December 18, 2020 order, the PSC of MD also found that Washington Gas’s proposed implementation plan to replace all remaining mercury regulators within five years of completing an mercury regulator survey adequately addresses the need to replace all remaining mercury regulators in Maryland, and is in the public interest. The costs of the proposed implementation program are not yet known, and the recovery of these costs must be deferred until a future rate case.

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, 2020		December 31, 2019
Due from related parties
Accounts receivable (a)	$	5	$	18
Long-term investments and other assets (b)	—		45
	$	5	$	63
Due to related parties
Accounts payable (c)	$	3	$	3

(a)Receivables from joint ventures and from a former affiliate of Petrogas.

(b)For the period prior to December 15, 2020, AltaGas provided a $100 million interest bearing secured loan facility to Petrogas of which $50 million was committed. The facility was available for Petrogas to draw upon from time to time for general corporate purposes until the close of the Petrogas Acquisition on December 15, 2020. 

(c)Payables to a joint venture and a former affiliate of Petrogas.

The following transactions with related parties have been recorded on the Consolidated Statements of Income for the years ended December 31, 2020 and 2019:

Year Ended December 31	2020		2019
Revenue (a)	$	92	$	115
Cost of sales (b)	$	12	$	13
Operating and administrative expenses (recoveries) (c)	$	1	$	(2)
Other income (d)	$	3	$	3

(a)In the ordinary course of business, AltaGas sold commodities to TriSummit Utilities Inc. and Petrogas.

(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)Subsequent to the close of the Petrogas Acquisition, certain operating and administrative expenses were paid on behalf of Petrogas by a former affiliate. In 2019, administrative cost recoveries included those from joint ventures and from TriSummit Utilities Inc. under a Transition Services Agreement.

(d)Interest income from loans to Petrogas (secured loan facility) prior to the acquisition of Petrogas.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 149

31. Supplemental Cash Flow Information

The following table details the changes in operating assets and liabilities from operating activities:

	Year Ended December 31
	2020		2019
Source (use) of cash:
Accounts receivable	$	21	$	168
Inventory	32		(2)
Other current assets	1		(85)
Regulatory assets - current	(33)		7
Accounts payable and accrued liabilities	(41)		(280)
Customer deposits	(2)		(17)
Regulatory liabilities - current	(55)		34
Risk management liabilities - current	(1)		1
Other current liabilities	4		(6)
Other operating assets and liabilities	(129)		(52)
Changes in operating assets and liabilities	$	(203)	$	(232)

The following table details the changes in non-cash investing and financing activities:

	Year Ended December 31
	2020		2019
(Increase) of balance:
Common shares issued under DRIP	$	(6)	$	(68)
Net right-of-use assets obtained in exchange for new operating lease liabilities	$	227	$	50
Net right-of-use assets obtained in exchange for new finance lease liabilities	$	6	$	5
Capital expenditures included in accounts payable and accrued liabilities	$	(33)	$	(7)

The following cash payments have been included in the determination of earnings:

	Year Ended December 31
	2020		2019
Interest paid (net of capitalized interest)	$	276	$	352
Income taxes paid	$	23	$	67

The following table is a reconciliation of cash and restricted cash balances:

As at December 31	2020		2019
Cash and cash equivalents	$	32	$	57
Restricted cash holdings from customers - current	3		4
Restricted cash holdings from customers - non-current	2		4
Restricted cash included in prepaid expenses and other current assets (a)	9		25
Restricted cash included in long-term investments and other assets (note 12) (a)	19		32
Restricted cash included in accounts receivable (note 29)	9		—
Cash, cash equivalents, and restricted cash per Consolidated Statements of Cash Flows	$	74	$	122

(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 (see Note 28).

AltaGas Ltd. – 2020 MD&A and Financial Statements - 150

32. Segmented Information

AltaGas owns and operates a portfolio of assets and services used to move energy from the source to the end‑user. In 2020, AltaGas revised its reportable segments to align with the structure of its business following asset sales 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. Consistent with Management’s strategic view of the business and the basis on which it assesses performance and allocates resources, beginning in 2020, AltaGas has two operating segments: Utilities (which now includes the WGL retail marketing business) and Midstream. These operating segments have not been aggregated in the determination of AltaGas' reportable segments. All other assets are included in the Corporate/Other segment. Prior period segment information has been restated to conform to the current reporting segment presentation.

The following describes the Corporation’s reporting segments:

Utilities	n rate-regulated natural gas distribution assets in Michigan, Alaska, the District of Columbia,     Maryland, and Virginia; n rate-regulated natural gas storage in the United States; and n sale of natural gas to residential, commercial and industrial customers in Washington D.C.,     Maryland, Virginia, Delaware, Pennsylvania and Ohio.
Midstream	n NGL processing and extraction plants; n natural gas storage facilities; n liquefied petroleum gas (LPG) terminals; n transmission pipelines to transport natural gas and NGL; n natural gas gathering lines and field processing facilities; n purchase and sale of natural gas; n natural gas and NGL marketing; n marketing, storage and distribution of wellsite fluids and fuels, crude oil and condensate diluents; and n interest in a regulated pipeline in the Marcellus/Utica gas formation;
Corporate/Other	n the cost of providing corporate services, financing and general corporate overhead,     investments in certain public and private entities, corporate assets, financing other segments and     the effects of changes in the fair value of certain risk management contracts; and n a small portfolio of remaining power assets, certain of which are pending sale.

The following table provides a reconciliation of segment revenue to the disaggregated revenue table disclosed in Note 24:

	Year Ended December 31, 2020
	Utilities		Midstream		Corporate/Other		Total
External revenue (note 24)	$	3,817	$	1,635	$	135	$	5,587
Intersegment revenue	—		1		—		1
Segment revenue	$	3,817	$	1,636	$	135	$	5,588

	Year Ended December 31, 2019
	Utilities		Midstream		Corporate/Other		Total
External revenue (note 24)	$	4,044	$	1,228	$	223	$	5,495
Intersegment revenue	—		32		—		32
Segment revenue	$	4,044	$	1,260	$	223	$	5,527

AltaGas Ltd. – 2020 MD&A and Financial Statements - 151

Geographic Information

Year Ended December 31	2020		2019
Revenue (a)
Canada	$	1,512	$	1,245
United States	4,053		4,325
TOTAL	$	5,565	$	5,570

(a)Operating revenue from external customers, excluding unrealized gains or losses on risk management contracts.

As at December 31	2020		2019
Property, plant and equipment
Canada	$	3,149	$	2,682
United States	7,739		7,443
TOTAL	$	10,888	$	10,125
Operating right-of-use assets
Canada	$	293	$	85
United States	79		85
TOTAL	$	372	$	170

The following tables show the composition by segment:

	Year Ended December 31, 2020
	Utilities		Midstream		Corporate/Other		Intersegment Elimination (a)		Total
Segment revenue (note 24)	$	3,817	$	1,636	$	135	$	(1)	$	5,587
Cost of sales	(2,156)		(994)		(29)		1		(3,178)
Operating and administrative	(942)		(254)		(71)		—		(1,267)
Accretion expenses	—		(4)		(1)		—		(5)
Depreciation and amortization	(295)		(86)		(33)		—		(414)
Provisions on assets (note 6)	(1)		(105)		(3)		—		(109)
Income from equity investments	5		44		—		—		49
Other income	259		24		23		—		306
Foreign exchange gains (losses)	—		(26)		30		—		4
Interest expense	—		—		(274)		—		(274)
Income (loss) before income taxes	$	687	$	235	$	(223)	$	—	$	699
Net additions (reductions) to:
Property, plant and equipment(b)	$	740	$	136	$	(51)	$	—	$	825
Intangible assets	$	3	$	3	$	4	$	—	$	10

(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. – 2020 MD&A and Financial Statements - 152

	Year Ended December 31, 2019
	Utilities		Midstream		Corporate/Other		Intersegment Elimination (a)		Total
Segment revenue (note 24)	$	4,044	$	1,260	$	223	$	(32)	$	5,495
Cost of sales	(2,448)		(760)		(51)		32		(3,227)
Operating and administrative	(960)		(213)		(126)		—		(1,299)
Accretion expenses	—		(4)		(1)		—		(5)
Depreciation and amortization	(276)		(89)		(73)		—		(438)
Provision on assets (note 6)	—		(34)		(382)		—		(416)
Income from equity investments	19		122		—		—		141
Other income	29		28		851		—		908
Foreign exchange gains (losses)	—		(5)		4		—		(1)
Interest expense	—		—		(346)		—		(346)
Income before income taxes	$	408	$	305	$	99	$	—	$	812
Net additions (reductions) to:
Property, plant and equipment (b)	$	840	$	351	$	(2,280)	$	—	$	(1,089)
Intangible assets	$	23	$	5	$	9	$	—	$	37

(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		Corporate/Other		Total
As at December 31, 2020
Goodwill	$	3,706	$	1,333	$	—	$	5,039
Segmented assets	$	13,675	$	7,320	$	537	$	21,532
As at December 31, 2019
Goodwill	$	3,781	$	161	$	—	$	3,942
Segmented assets	$	13,719	$	5,265	$	811	$	19,795

33. Subsequent Events

Subsequent events have been reviewed through February 25, 2021, the date on which these audited Consolidated Financial Statements were issued.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 153

SUPPLEMENTAL QUARTERLY OPERATING INFORMATION

	Q4-20	Q3-20	Q2-20	Q1-20	Q4-19
OPERATING HIGHLIGHTS
UTILITIES
Natural gas deliveries - end use (Bcf) (1)	50.0	14.2	23.1	66.6	52.2
Natural gas deliveries - transportation (Bcf) (1)	35.6	28.3	24.1	40.5	38.3
Service sites (thousands) (2)	1,672	1,667	1,664	1,661	1,653
Degree day variance from normal - SEMCO Gas (%) (3)	(4.4)	1.8	20.2	(11.4)	4.3
Degree day variance from normal - ENSTAR (%) (3)	0.2	(13.3)	0.5	16.1	(20.6)
Degree day variance from normal - Washington Gas (%) (3) (4)	(10.6)	233.0	45.6	(17.1)	(3.2)
WGL retail energy marketing - gas sales volumes (Mmcf)	18,053	8,393	11,419	21,916	20,131
WGL retail energy marketing - electricity sales volumes (GWh)	3,257	3,688	3,151	3,511	3,291
MIDSTREAM
RIPET export volumes (Bbls/d) (5) (6)	37,782	42,736	41,460	35,141	36,394
Ferndale export volumes (Bbls/d) (5) (7)	33,979	—	—	—	—
Total inlet gas processed (Mmcf/d) (5)	1,409	1,328	1,300	1,393	1,413
Extraction ethane volumes (Bbls/d) (5)	30,766	24,681	26,699	29,932	25,951
Extraction NGL volumes (Bbls/d) (5) (8)	34,199	32,165	29,946	32,495	32,313
Fractionated volumes (Bbls/d) (5)	27,026	25,430	20,641	21,079	20,310
Frac spread - realized ($/Bbl) (5) (9)	13.95	15.90	16.61	11.76	16.54
Frac spread - average spot price ($/Bbl) (5) (10)	9.33	7.11	3.73	2.04	8.29
Propane Far East Index to Mont Belvieu spread (US$/Bbl) (11)	15.01	8.00	8.08	16.23	17.95
Natural gas optimization inventory (Bcf)	39.3	51.1	49.1	34.3	41.4

(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)Represents propane volumes exported at RIPET since facility was placed into service in May 2019.

(7)Represents propane and butane volumes exported at Ferndale for the period after close of the Petrogas Acquisition on December 15, 2020.

(8)NGL volumes refer to propane, butane, and condensate.

(9)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.

(10)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.

(11)Average propane price spread between FEI and Mont Belvieu TET commercial index for the period beginning May 2019.

AltaGas Ltd. – 2020 MD&A and Financial Statements - 154

OTHER INFORMATION

DEFINITIONS

Bbls/d    barrels per day

Bcf        billion cubic feet

Dth        dekatherm

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. – 2020 MD&A and Financial Statements - 155

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. 333-253122 pertaining to the registration of Preferred Shares and Debt Securities of AltaGas Ltd. and the use herein of our report dated February 25, 2021, with respect to the consolidated balance sheets as at December 31, 2020 and 2019 and the consolidated statements of income, 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, 2020, included in this Annual Report on Form 40-F.

Calgary, Alberta                                      /s/ Ernst & Young LLP

February 25, 2021                          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 26, 2021

/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 26, 2021

/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, 2020, 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 26, 2021

/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, 2020, 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 26, 2021

/s/ D. James Harbilas_____________________________

Name: D. James Harbilas

Title: Executive Vice President and Chief Financial Officer

XML

Cover Page	12 Months Ended
	Dec. 31, 2020 shares
Document Information [Line Items]
Document Type	40-F
Document Annual Report	true
Current Fiscal Year End Date	--12-31
Document Period End Date	Dec. 31, 2020
Entity File Number	333-225606
Entity Registrant Name	ALTAGAS LTD.
Entity Incorporation, State or Country Code	Z4
Entity Address, Address Line One	1700, 355-4th Avenue SW
Entity Address, City or Town	Calgary
Entity Address, State or Province	AB
Entity Address, Postal Zip Code	T2P 0J1
City Area Code	403
Local Phone Number	691-7575
Annual Information Form	true
Audited Annual Financial Statements	true
Entity Common Stock, Shares Outstanding	279,494,299
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	false
Amendment Flag	false
Entity Central Index Key	0001695519
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Document Registration Statement	false
Entity Primary SIC Number	1311
Business Contact
Document Information [Line Items]
Entity Address, Address Line One	1000 Maine Ave.
Entity Address, City or Town	Washington
Entity Address, State or Province	DC
Entity Address, Postal Zip Code	20024
City Area Code	703
Local Phone Number	750-4400
Contact Personnel Name	AltaGas Services (U.S.) Inc.

XML

Consolidated Balance Sheets - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Current assets
Cash and cash equivalents (note 31)	$ 32	$ 57
Accounts receivable (net of credit losses of $41 million) (notes 10 and 23)	1,444	1,222
Inventory (note 7)	636	506
Restricted cash holdings from customers (note 31)	3	4
Regulatory assets (note 21)	46	13
Risk management assets (note 23)	98	87
Prepaid expenses and other current assets (notes 28 and 31)	234	280
Assets held for sale (note 5)	4	27
Total current assets	2,497	2,196
Property, plant and equipment (note 8)	10,888	10,125
Intangible assets (note 9)	539	586
Operating right-of-use assets (note 10)	372	170
Goodwill (note 11)	5,039	3,942
Regulatory assets (note 21)	444	487
Risk management assets (note 23)	47	39
Restricted cash holdings from customers (note 31)	2	4
Prepaid post-retirement benefits (note 28)	572	487
Long-term investments and other assets (net of credit losses of $3 million) (notes 12, 28, and 31)	245	297
Investments accounted for by the equity method (note 14)	887	1,462
Total assets	21,532	19,795
Current liabilities
Accounts payable and accrued liabilities (notes 17, 18, 23, and 28)	1,561	1,325
Dividends payable (note 23)	22	22
Short-term debt (notes 15 and 23)	256	460
Current portion of long-term debt (notes 16 and 23)	360	923
Customer deposits	73	76
Regulatory liabilities (note 21)	90	146
Risk management liabilities (note 23)	111	125
Operating lease liabilities (note 10)	95	27
Other current liabilities (note 23)	38	17
Liabilities associated with assets held for sale (note 5)	1	4
Total current liabilities	2,607	3,125
Long-term debt (notes 16 and 23)	7,626	5,928
Asset retirement obligations (note 17)	379	362
Unamortized investment tax credits (note 20)	3	4
Deferred income taxes (note 20)	1,118	959
Regulatory liabilities (note 21)	1,381	1,383
Risk management liabilities (note 23)	145	167
Operating lease liabilities (note 10)	304	153
Other long-term liabilities (notes 19 and 23)	153	102
Future employee obligations (note 28)	155	243
Total liabilities	13,871	12,426
Shareholders' equity
Common shares, no par values, unlimited shares authorized;    2020 - 279.5 million and 2019 - 279.1 million issued and outstanding (note 25)	6,723	6,719
Preferred shares (note 25)	1,077	1,277
Contributed surplus	383	377
Accumulated deficit	(1,192)	(1,403)
Accumulated other comprehensive income (AOCI) (note 22)	50	245
Total shareholders' equity	7,041	7,215
Non-controlling interests	620	154
Total equity	7,661	7,369
Total liabilities and shareholders' equity	$ 21,532	$ 19,795

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Consolidated Balance Sheets (Parenthetical) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Accounts receivable, allowance for credit loss, current	$ 41	$ 41
Long-term investments and other assets, credit losses	$ 3	$ 3
Common shares (note 25)
Common shares outstanding (shares)	279,500,000	279,074,685
Common shares issued (shares)	279,500,000	279,100,000

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Consolidated Statements of Income - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Income Statement [Abstract]
REVENUE (note 24)	$ 5,587	$ 5,495
EXPENSES
Cost of sales, exclusive of items shown separately	3,178	3,227
Operating and administrative	1,267	1,299
Accretion expenses (note 17)	5	5
Depreciation and amortization (notes 8 and 9)	414	438
Provisions on assets (note 6)	109	416
Total expenses	4,973	5,385
Income from equity investments (note 14)	49	141
Other income (note 27)	306	908
Foreign exchange gains (losses)	4	(1)
Interest expense	(274)	(346)
Income before income taxes	699	812
Income tax expense (recovery) (note 20)
Current	1	63
Deferred	126	(91)
Net income after taxes	572	840
Net income applicable to non-controlling interests	20	7
Net income applicable to controlling interests	552	833
Preferred share dividends	(66)	(68)
Gain on redemption of preferred shares (note 25)	0
Net income applicable to common shares	$ 486	$ 769
Net income per common share (note 26)
Basic (per share)	$ 1.74	$ 2.78
Diluted (per share)	$ 1.74	$ 2.77
Weighted average number of common shares    outstanding (millions) (note 26)
Basic (shares)	279.4	276.9
Diluted (shares)	279.7	277.4

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Consolidated Statements of Comprehensive Income (Loss) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Net income after taxes	$ 572	$ 840
Other comprehensive income (loss), net of taxes
Loss on foreign currency translation	(175)	(406)
Unrealized gain (loss) on net investment hedge (note 23)	(9)	60
Actuarial gain (loss) on pension plans and post-retirement benefit (PRB) plans (note 28)	(8)	12
Reclassification of actuarial gains and prior service credits on defined benefit (DB) and post-retirement benefit plans (PRB) to net income (note 28)	2	1
Other comprehensive loss from equity investees	(5)	(1)
Total other comprehensive loss (OCI), net of taxes (note 22)	(195)	(334)
Comprehensive income attributable to controlling interests and non-controlling interests, net of taxes	377	506
Comprehensive income attributable to:
Non-controlling interests	20	7
Controlling interests	$ 357	$ 499

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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	Accumulated deficit Cumulative Effect, Period of Adoption, Adjustment	AOCI (note 22)	Non-controlling interests
Balance, beginning of year at Dec. 31, 2018				$ 6,654	$ 1,319	$ 373	$ (1,905)		$ 579	$ 620
Increase (Decrease) in Stockholders' Equity
Exercise of share options				1
Shares issued under DRIP	[1]			68
Deferred taxes on share issuance costs				(4)	(1)
Redemption of preferred shares					(41)
Share options expense						4
Net income applicable to controlling interests		$ 833					833
Common share dividends							(267)
Preferred share dividends							(68)
Gain on redemption of preferred shares							4
Accounting Standards Update [Extensible List]		us-gaap:AccountingStandardsUpdate201613Member
Other comprehensive loss		$ (334)							(334)
Net income applicable to non-controlling interests		7								7
Adjustment on disposition of assets										(508)
Contributions from non-controlling interests to subsidiaries										48
Distributions by subsidiaries to non-controlling interests										(13)
Balance, end of year at Dec. 31, 2019		7,369	$ 7,215	6,719	1,277	377	(1,403)	$ (7)	245	154
Increase (Decrease) in Stockholders' Equity
Exercise of share options				1
Shares issued under DRIP	[1]			6
Deferred taxes on share issuance costs				(3)
Redemption of preferred shares					(200)
Share options expense						6
Net income applicable to controlling interests		552					552
Common share dividends							(268)
Preferred share dividends							(66)
Gain on redemption of preferred shares		0
Other comprehensive loss		(195)							(195)
Net income applicable to non-controlling interests		20								20
Contributions from non-controlling interests to subsidiaries										7
Distributions by subsidiaries to non-controlling interests										(28)
Acquisition of non-controlling interests through Petrogas Acquisition (note 3)										467
Balance, end of year at Dec. 31, 2020		$ 7,661	$ 7,041	$ 6,723	$ 1,077	$ 383	$ (1,192)		$ 50	$ 620

[1] Premium Dividend™, Dividend Reinvestment and Optional Cash Purchase Plan (DRIP). The plan was suspended in December 2019, with the December dividend (paid January 2020) being the last dividend payment eligible for reinvestment by participating shareholders under the DRIP.

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Consolidated Statements of Cash Flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Cash from (used by) operations
Net income after taxes	$ 572.0	$ 840.0
Items not involving cash:
Depreciation and amortization (notes 8 and 9)	414.0	438.0
Provisions on assets (note 6)	109.0	416.0
Accretion expenses (note 17)	5.0	5.0
Share-based compensation (note 25)	6.0	4.0
Deferred income tax expense (recovery) (note 20)	126.0	(91.0)
Gains on sale of assets (notes 4 and 27)	(223.0)	(876.0)
Gain on remeasurement of previously held interest in AIJVLP (note 3)	(22.0)	0.0
Income from equity investments (note 14)	(49.0)	(141.0)
Unrealized losses (gains) on risk management contracts (note 23)	(21.0)	85.0
Losses on investments (note 27)	0.0	4.0
Amortization of deferred financing costs	8.0	12.0
Provision for doubtful accounts	25.0	27.0
Change in pension and other post-retirement benefits (note 28)	(11.0)	8.0
Other	15.0	9.0
Asset retirement obligations settled (note 17)	(4.0)	(2.0)
Distributions from equity investments	26.0	110.0
Changes in operating assets and liabilities (note 31)	(203.0)	(232.0)
Net cash provided (required) by operating activities	773.0	616.0
Investing activities
Business acquisitions, net of cash acquired (note 3)	(675.0)	0.0
Capital expenditures - property, plant and equipment	(825.0)	(1,296.0)
Capital expenditures - intangible assets	(18.0)	(38.0)
Contributions to equity investments	(72.0)	(179.0)
Change in loan to affiliate	(75.0)	0.0
Proceeds from disposition of equity investments (note 14)	376.0	0.0
Proceeds from sale of investments in publicly-traded entities	4.0	0.0
Proceeds from disposition of assets, net of transaction costs (note 4)	74.0	3,624.0
Proceeds from disposition of financing receivable	0.0	73.0
Net cash provided (required) by investing activities	(1,211.0)	2,184.0
Financing activities
Net repayment of short-term debt	(157.0)	(701.0)
Issuance of long-term debt, net of debt issuance costs	1,962.0	889.0
Repayment of long-term debt	(1,056.0)	(873.0)
Net borrowing (repayment) under credit facilities	191.0	(1,921.0)
Dividends - common shares	(268.0)	(266.0)
Dividends - preferred shares	(66.0)	(68.0)
Distributions to non-controlling interest	(28.0)	(13.0)
Contributions from non-controlling interests	7.0	48.0
Net proceeds from shares issued on exercise of options	1.0	1.0
Net proceeds from issuance of common shares	6.0	68.0
Redemption of preferred shares (note 25)	(200.0)	(38.0)
Net cash provided (required) by financing activities	392.0	(2,874.0)
Change in cash, cash equivalents, and restricted cash	(46.0)	(74.0)
Effect of exchange rate changes on cash, cash equivalents, and restricted cash	(2.0)	(9.0)
Net change in cash classified within assets held for sale	0.0	4.0
Cash, cash equivalents, and restricted cash beginning of year	122.0	201.0
Cash, cash equivalents, and restricted cash end of year (note 31)	$ 74.0	$ 122.0

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Organization and Overview of the Business

12 Months Ended

Dec. 31, 2020

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 the Company 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 regard to the Utilities business, Washington Gas Light Company (Washington Gas), Hampshire Gas Company, and SEMCO Energy, Inc. (SEMCO); in regard 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); and, in regard to remaining assets in the Corporate/Other segment, AltaGas Power Holdings (U.S.) Inc., WGL Energy Systems, Inc. (WGL Energy Systems), and Blythe Energy Inc. (Blythe). 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). Petrogas Energy Corporation (Petrogas) was also added as a subsidiary of AltaGas upon the close of the acquisition on December 15, 2020.

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 North America 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.

In 2020, AltaGas revised its reportable segments to align with the structure of its business following asset sales 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. Consistent with Management’s strategic view of the business and the basis on which it assesses performance and allocates resources, beginning in 2020, AltaGas has two operating segments: Utilities (which now includes the WGL retail marketing business) and Midstream. These operating segments have not been aggregated in the determination of AltaGas' reportable segments. All other assets are included in the Corporate/Other segment. AltaGas' operating segments include the following:

§    Utilities, which serves approximately 1.7 million customers with a rate base of approximately US$4.3 billion through ownership of regulated natural gas distribution utilities across five jurisdictions in the United States and two regulated natural gas storage utilities in the United States, delivering affordable natural gas to homes and businesses. The Utilities business also includes storage facilities and contracts for interstate natural gas transportation and storage services, as well as the affiliated retail energy marketing business, which serves approximately 0.5 million customers; and

§    Midstream, which includes a 70 percent interest in the Ridley Island Propane Export Terminal (RIPET) and an approximate 74 percent interest in the Ferndale terminal, allowing AltaGas to leverage its assets along the energy value chain in Western Canada and the Western United States including natural gas gathering and processing, NGL extraction and fractionation, and natural gas and NGL marketing. The Midstream segment also includes transmission, storage, and an interest in a regulated pipeline in the Marcellus/Utica gas formation in the northeastern United States. Upon close of the acquisition of Petrogas, the Midstream business also includes a 74 percent interest in Petrogas' other operations, which include LPG exports and distribution, domestic terminals, wellsite fluids and fuels, and trucking and liquids handling.

The Corporate/Other segment consists of AltaGas' corporate activities and a small portfolio of remaining power assets, certain of which are pending sale.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2020

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 January 21, 2020, 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 of consolidated subsidiaries are shown as an allocation of the consolidated net income and are presented separately in "net income applicable to non-controlling interests".

USE OF ESTIMATES AND MEASUREMENT UNCERTAINTY

The preparation of Consolidated Financial Statements in accordance with U.S. GAAP requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenue and expenses during the period. Key areas where Management has made complex or subjective judgments, when matters are inherently uncertain, include but are not limited to: determining the nature and timing of satisfaction of performance obligations and determining the transaction price and amounts allocated to performance obligations for revenue recognition; depreciation and amortization rates; 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; measurement of credit losses; 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. Additionally, cash deposited in an escrow fund related to a cost sharing agreement with a third party has been recorded as restricted cash in “accounts receivable" in the Consolidated Balance Sheets. Please refer to Note 29 for more information.

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, crude oil and condensates, processed finished products, 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, and a small number of assets acquired as part of the acquisition of Petrogas for which depreciation is calculated using the declining balance method.

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	3 to 55 years
Corporate/Other assets	3 to 46 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. 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.

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 years
Software	3 to 20 years
Land rights	5 to 43 years
Extraction and Transmission (E&T) Contracts	25 years
Commodity contracts	5 to 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.

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.

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 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.

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 may designate 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.

Credit Losses

The following are the Corporation's significant accounting policies upon adoption of ASC 326:

Accounts receivable, contract assets, a loan to an affiliate, and other long-term receivables within the scope of ASC 326 are recorded net of the allowance for credit losses 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 credit losses is adjusted. Accounts are written off when collection efforts are complete and future recovery is unlikely. See below for a description of how expected credit loss estimates are developed.

Utilities Customer Receivables and Contract Assets

AltaGas is exposed to risk through the non-payment of utility bills by customers. To manage this customer credit risk, AltaGas' regulated utilities customers are offered budget billing options or high risk customers may be required to provide a cash deposit until the requirement for deposit refunds are met. AltaGas can recover a portion of non-payments from customers in future periods through the rate-setting process. For accounts receivable generated by the Utilities business, an allowance for credit losses is recorded against revenue and is recognized using a historical loss-rate based on historical payment and collection experience. This rate may be adjusted based on Management’s expectations of unusual macroeconomic conditions and other factors. AltaGas regularly evaluates the reasonableness of the allowance based on a combination of factors, such as: the length of time receivables are past due, historical expected payment, collection experience, financial condition of customers, and other circumstances that could impact customers' ability or desire to make payments. For retail energy marketing customer receivables where AltaGas has enrolled in a regulatory utility purchase of receivable program, the associated utility discount rate is used to determine credit losses.

Midstream Customer Receivables and Contract Assets

AltaGas operates under an existing credit policy that is designed to mitigate credit risk. Credit limits are established for each counterparty and credit enhancements such as letters of credit, parent guarantees, and cash collateral may be required. The creditworthiness of all counterparties is continuously monitored. A credit loss reserve is recorded for receivables with customers and trading counterparties AltaGas considers to be below investment grade by applying an estimated loss rate. The estimated loss rate is based on the historical default rates published by external rating agencies. For accounts receivable, a one-year rate is used. For contract assets, historical loss rates associated with the estimated time frame that the contract asset will be billed to the customer is used. In the event a customer or trading counterparty no longer exhibits similar risk characteristics, the associated receivable is evaluated individually.

Other

For other long-term receivables, associated counterparties are evaluated and assigned internal credit ratings based on AltaGas' credit policy. An allowance for credit losses is recorded based on historical default rates published by external credit rating agencies and a rate commensurate with the period in which the receivables are expected to be collected.

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 midstream and 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 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. 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 RUs 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 10.2 years and 13.0 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.

In 2020, AltaGas made a voluntary change in accounting principle for calculating the market-related value of assets (MRVA) used in the determination of Washington Gas' net periodic pension and other post-retirement benefit plan costs. The change uses the fair value approach for the fixed income investment asset class of the plan assets, compared to the prior method that utilized a calculated value where gains and losses arising from changes in fair value were deferred and amortized into the calculation of the MRVA over a period of five years. The MRVA is used in the calculation of the expected return on assets and

the recognized actuarial gain or loss components of net periodic benefit cost. The approach applied for all other classes of assets remains unchanged.

Management believes that using the fair value approach for the fixed income investments in plan assets is preferable as it more closely aligns the recognition of related components within the net periodic benefit cost.

This change in accounting principle was not considered material to prior periods or the current year; therefore, the impact of the change was recognized in the current period. On the Consolidated Statements of Income, for the year ended December 31, 2020, the change resulted in an increase to income before income taxes of approximately $25 million (recorded within the line item “other income”) and an increase to net income applicable to common shares of approximately $19 million ($0.07 per basic and diluted common share), net of the tax impact of approximately $6 million recorded within the line item "deferred income tax expense (recovery)". Amounts related to regulated utility operations that are expected to be recoverable from or refunded to customers through the rate-setting process have been reflected as adjustments to regulatory assets or liabilities on the Consolidated Balance Sheets. For further discussion of pension plans and retiree benefits, see Note 28.

Income Taxes

Income taxes for the Corporation and its subsidiaries are calculated using the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are determined based on differences between the carrying value and the tax basis of assets and liabilities and are measured using the enacted tax rates and laws that are in effect in the periods in which the differences are expected to be settled or realized. Deferred income tax assets are routinely reviewed, and a valuation allowance is recorded to reduce the deferred tax assets if it is more likely than not that deferred tax assets will not be realized.

The financial statement effects of an uncertain tax position are recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxing authority. The current and deferred tax impact is equal to the largest amount, considering possible settlement outcomes, that is greater than 50 percent likely of being realized upon settlement with the taxing authorities.

Investment tax credits are recognized as reductions to income tax expense over the estimated service lives of the related properties.

The rate-regulated natural gas distribution subsidiaries recognize a separate regulatory asset or liability for the amount of deferred income taxes expected to be recovered from, or paid to, customers in the future.

Net Income per Share

Basic net income per common share is computed using the weighted average number of common shares outstanding during the period. Dilutive net income per common share is calculated using the weighted average number of common shares outstanding adjusted for dilutive common shares related to the Corporation’s share-based compensation awards.

The potentially dilutive impact of the share-based compensation awards is determined using the treasury stock method. Under the treasury stock method, awards are treated as if they had been exercised with any proceeds used to repurchase common stock at the average market price during the period. Any incremental difference between the assumed number of shares issued and purchased is included in the diluted share computation.

Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Any such accruals are adjusted thereafter as additional information becomes available or circumstances change.

Leases

The following are the Corporation’s significant accounting policies:

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 expense recorded related to the collaborative arrangements totaled $21 million for the year ended December 31, 2020 (2019 - income of $1 million).

ADOPTION OF NEW ACCOUNTING STANDARDS

Effective January 1, 2020, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU):

§    In June 2016, FASB issued ASU No. 2016-13 “Financial Instruments – Credit Losses and all related amendments (collectively "ASC 326"): Measurement of Credit Losses on Financial Instruments”. The ASU replaces the current “incurred loss” impairment methodology with an “expected loss” model for financial assets measured at amortized cost. AltaGas has applied ASC 326 using the modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the effective date of the new standard. Prior periods presented for comparative purposes were not adjusted. Upon adoption of ASC 326, "accounts receivable, net of allowances" decreased by $2 million and "long-term investments and other assets" decreased by $5 million, with an offsetting increase to "accumulated deficit". AltaGas has elected to account for its cash equivalents at fair value. Please also refer to Note 23 of the Consolidated Financial statements as at and for the year ended December 31, 2020 for further details;

§    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 adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements, but resulted in certain minor adjustments to the fair value disclosures. Please also refer to Note 23 of the Consolidated Financial statements as at and for the year ended December 31, 2020 for further details;

§    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 interests held through related parties under common control are considered on a proportional basis when determining whether fees paid to decision makers and service providers are variable interests. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§    ASU No. 2018-18 "Collaborative Arrangements: Clarifying the Interaction between Topic 808 and Topic 606". The amendments in this ASU clarifies that certain transactions between collaborative arrangement participants should be accounted for as revenue under ASC 606, adds unit-of-account guidance in ASC 808 to align with the guidance in ASC 606, and requires that a transaction with a collaborative arrangement participant that is not directly related to sales to third parties, is precluded from presenting the transaction together with revenue recognized under ASC 606 if the collaborative arrangement participant is not a customer. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§    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, clarifies the presentation of principal payments received under sales-type and direct finance leases for depository and lending institutions, and clarifies that interim transition disclosure requirements related to the change on income statement, net income and related per share amounts for the adoption of ASC 842 are not required. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§    ASU No. 2019-04 “Financial Instruments: Codification Improvements". The amendments in this ASU provide clarification and improve the codification in recently issued accounting standards relating to credit losses, hedge accounting, and financial instruments. The amendments related to credit losses were evaluated in conjunction with ASU 2016-13 above. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and

§    ASU No. 2020-03 "Codification Improvements to Financial Instruments". The amendments in this ASU provide clarification and improve the codification to certain aspects of accounting standards related to financial instruments. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements.

Effective December 31, 2020, AltaGas adopted the following FASB issued ASU:

§    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 adoption of this ASU did not have a material impact on AltaGas' consolidated financial statements, but resulted in certain modifications to the disclosures in the pension footnote. Please also refer to Note 28 of the Consolidated Financial statements as at and for the year ended December 31, 2020 for further details.

FUTURE CHANGES IN ACCOUNTING PRINCIPLES

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. The adoption of this ASU is not expected to have a material impact on AltaGas’ financial statements.

In January 2020, FASB issued ASU No. 2020-01 "Derivatives and Hedging: Clarifying the Interactions between Topic 321, Topic 323, and Topic 815". The amendments in this ASU clarify the application of the measurement alternative for equity instruments and the measurement of non-derivative forward contracts or purchased call options used to acquire equity securities. 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’ financial statements.

In March 2020, FASB issued ASU No. 2020-04 "Reference Rate Reform: Facilitation of the Effects of Reference Rate Reform on Financial Reporting." The amendments in this ASU provide optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships affected by reference rate reform if certain criteria are met. These apply only to contracts, hedging relationships, and other transactions that reference London Interbank Offered Rate (LIBOR) or another reference rate expected to be discontinued because of reference rate reform. The amendments in this ASU are effective as of March 12, 2020 through December 31, 2022. AltaGas may elect to apply the amendments as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020 on a prospective basis. AltaGas has not elected to adopt this ASU as of December 31, 2020, and is assessing the impact of this ASU on its consolidated financial statements.

In August 2020, FASB issued ASU No. 2020-06 "Debt with Conversion and Other Options and Topic 815-40 - Derivatives and Hedging - Contracts in Entity's Own Equity: Accounting for Convertible Instruments and Contract in an Entity's Own Equity." The amendments in this Update simplify the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. The amendments in this Update are effective for public business entities that meet the definition of a Securities and Exchange Commission (SEC) filer, excluding entities eligible to be smaller reporting companies as defined by the SEC, for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. For all other entities, the amendments are effective for fiscal years beginning after December 15, 2023, including 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' financial statements.

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Acquisition of Petrogas Energy Corporation

12 Months Ended

Dec. 31, 2020

Business Combinations [Abstract]

Acquisition of Petrogas Energy Corporation

Acquisition of Petrogas Energy Corporation On December 15, 2020, following the receipt of all required approvals, AltaGas acquired an additional 37 percent of Petrogas Energy Corp. (the Petrogas Acquisition) for total cash consideration upon close of approximately $715 million. Additional post-acquisition contingent payments of up to $16 million may be paid no later than 2022 based on certain criteria, including earnings targets being met (Note 29). AltaGas funded the transaction through draws on its existing credit facilities. As a result

of the transaction, AltaGas' ownership in Petrogas has increased to approximately 74 percent with Idemitsu Kosan Co., Ltd. (Idemitsu) owning the remaining approximately 26 percent. Subsequent to the transaction, AltaGas controls Petrogas and as such, Petrogas results have been consolidated for the period subsequent to close.

This acquisition is consistent with AltaGas' global export strategy, growing Midstream operations, and corporate focus on building a diversified, low-risk, high-growth Utilities and Midstream business. The transaction provides AltaGas with operational responsibility of strategic assets that, along with the Ridley Island Propane Export Terminal and existing Midstream assets, position the Company to capture efficiencies that are expected to accrue to shareholders and customers.

AltaGas accounted for the acquisition as a business combination achieved in stages and re-measured it's previously held 37 percent equity investment in Petrogas at an acquisition date fair value of $631 million, resulting in a gain of $22 million. The fair value of assets and liabilities acquired were determined using a combination of income and cost approach. The fair value of the previously held interest and non-controlling interests were derived from the valuation of the assets and liabilities including considerations for expected synergies. Prior to the acquisition, AltaGas' indirect non-controlling interest in Petrogas was accounted for as an investment accounted for by the equity method (Note 14).

The following table summarizes the preliminary purchase price allocation representing the consideration paid and the estimated fair value of the net assets acquired as at December 15, 2020. The purchase price allocation is preliminary and reflects Management’s current best estimate of the fair value of Petrogas' assets and liabilities based on the analysis of information obtained to date. Management is continuing to obtain specific information to support the valuation of property, plant and equipment, intangibles, investments accounted for by the equity method, non-controlling interest, contingencies, income taxes, environmental matters and asset retirement obligations. As additional information becomes available, the purchase price allocation may differ materially from the preliminary purchase price allocation below. The offset to any adjustments made to the aforementioned financial statement captions during the measurement period are expected to be recorded in goodwill. Any adjustments to the purchase price allocation will be made as soon as practicable but no later than one year from the date of acquisition.

Fair value of previously held interest in AltaGas Idemitsu Joint Venture LP (AIJVLP) on the acquisition date	$	631
Less: Carrying value of previously held interest in AIJVLP	(609)
Gain on re-measurement of previously held interest	$	22
Purchase consideration for an additional 37 percent of Petrogas	$	715
Deemed settlement of intercompany debt	120
Fair value of previously held interest on the acquisition date	631
Less: Fair value assigned to net assets
Current assets	536
Property, plant and equipment	523
Intangible assets	10
Operating right-of-use assets	192
Long-term investments and other assets	4
Investments accounted for by the equity method	125
Current liabilities	(363)
Long-term debt	(53)
Asset retirement obligations	(13)
Deferred income taxes	(21)
Operating lease liabilities	(152)
Other long-term liabilities	(26)
Fair value of net assets acquired	$	762
Fair value of AIJVLP's non-controlling interest in Petrogas on the acquisition date	467
Goodwill	$	1,171

The fair value of AIJVLP's non-controlling interest in Petrogas at the acquisition date was $467 million, which was determined in the same manner described for the previously held investments. Included in the fair value calculation are synergies that AltaGas expects to achieve as part of the acquisition. The synergies are broken down into items that will accrue to Petrogas versus other AltaGas businesses. AltaGas operates businesses that are similar in nature to Petrogas and expects some of the synergies to impact assets such as RIPET and other processing facilities. The allocation of synergies to the various businesses is currently based on the expectations that existed as of the acquisition date. Further refinement of the synergies will occur as the businesses are integrated and assessed by AltaGas’ management. New allocations of synergies will be carefully assessed to determine their impact on the purchase price allocation.

The fair value of property, plant and equipment was estimated using the valuation methodologies described in ASC 820, Fair Value Measurements and Disclosures, to value the property, plant and equipment purchased. The preliminary fair value of Petrogas' property, plant and equipment was determined using both the income and cost approaches.

The acquired intangible assets consist primarily of the fair value of contractual arrangements for the purchase and sale of commodities. These intangibles have been valued using the income approach.

Investments accounted for by the equity method include Petrogas' 50 percent equity interest in Petrogas Terminals Penn LLC, and 40 percent equity interest in Strathcona Storage LP. The preliminary fair value of these investments was determined using an income approach.

The fair value of current assets and current liabilities approximate their carrying values due to their short-term nature, with the exception of inventory. Inventory of $164 million has been recorded at it's fair value using the expected selling prices and reasonable adjustments for the current location of the products. A contingent liability related to a property tax dispute has been recorded as part of the purchase price allocation. This preliminary amount represents management’s best estimate of the fair

value of the contingent liability and has been included in current liabilities. This item is included in the preliminary purchase price allocation as the hearings on the matter will occur over the next 12 months and the outcome will be settled.

Right of use assets and lease liabilities have been recorded for operating leases. The right of use assets have been adjusted to reflect the market lease rates at the acquisition date and resulted in a reduction of the acquired right of use assets.

Deferred income tax assets and liabilities have been applied on the cumulative amount of tax applicable to temporary differences between the accounting and tax values of assets and liabilities and are considered preliminary.

The preliminary purchase price allocation includes goodwill of approximately $1.2 billion. The goodwill is primarily related to the

opportunities to grow the LPG export business, expanded access to capital and greater financial flexibility as a result of increased scale, and earnings diversification. The goodwill recognized as part of this transaction is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to this goodwill.

Pre-tax acquisition expenses for the year ended December 31, 2020 of approximately $6 million were incurred and included in the Consolidated Statements of Income.

Upon completion of the Petrogas Acquisition, AltaGas began consolidating Petrogas. For the period from close of the transaction through December 31, 2020, Petrogas has generated approximately $143 million in revenues and $3 million in net income after taxes.

The following supplemental unaudited, pro forma consolidated financial information for the years ended December 31, 2020 and 2019 gives effect to the Petrogas Acquisition as if it had closed on January 1, 2019. This pro forma information is presented for information purposes only and does not purport to be indicative of the results that would have occurred had the Petrogas Acquisition taken place at the beginning of 2019, nor is it indicative of the results that may be expected in future periods.

	Year Ended December 31
	2020		2019
Pro forma revenue	$	7,917	$	9,217
Pro forma net income after tax	$	537	$	1,004

Pro forma net income after taxes excludes all non-recurring acquisition-related expenses incurred by AltaGas and Petrogas. Pro forma net income after taxes was also adjusted to exclude AltaGas' equity earnings from Petrogas prior to the acquisition, finance costs associated with credit facilities used to fund the Petrogas Acquisition, as well as the associated tax impacts. For the year ended December 31, 2020, the total after-tax pro forma adjustments decreased net income after taxes by $31 million (2019 – $75 million).

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Dispositions

12 Months Ended

Dec. 31, 2020

Discontinued Operations and Disposal Groups [Abstract]

Dispositions

Dispositions

AltaGas Canada Inc. (ACI)

On March 31, 2020, the Public Sector Pension Investment Board and the Alberta Teachers' Retirement Fund Board acquired all the issued and outstanding common shares of ACI for $33.50 per share. AltaGas owned 11,025,000 (approximately 37 percent) of ACI's common shares and received cash proceeds of approximately $369 million upon close. For the year ended December 31, 2020, AltaGas recognized a pre-tax gain on disposition of approximately $206 million in the Consolidated Statements of Income under the line item "other income". Following a name change in connection with the arrangement, ACI changed its name to TriSummit Utilities Inc.

Distributed Generation Assets

In 2019, AltaGas closed the disposition of its portfolio of U.S. distributed generation assets. The majority of assets were transferred in 2019, except for one project 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 this project remain classified as held for sale on the Consolidated Balance Sheets as at December 31, 2020 (Note 5). For the year ended December 31, 2020, AltaGas recognized a pre-tax gain on disposition of approximately $9 million in the Consolidated Statements of Income under the line item "other income" related to projects transferred in 2020. In addition, AltaGas recorded a pre-tax provision of $3 million related to the remaining U.S. distributed generation project which has not yet transferred to the purchaser (Note 6). The purchaser was entitled to after-tax earnings from the distributed generation projects, including the project awaiting consent, beginning September 1, 2019.

Harmattan Land Parcels

In the second quarter of 2020, AltaGas completed the sale of land parcels located near the Harmattan gas processing plant for gross cash proceeds of approximately $3 million. There was no gain or loss resulting from this disposition.

Pomona Energy Storage Facility and Ripon Gas-fired Facility

In the third quarter of 2020, AltaGas completed the sales of AltaGas Pomona Energy Storage Inc. and land related to a gas-fired power generation facility in the U.S., as well as a gas fired facility in Ripon, California, for aggregate gross cash proceeds, before working capital and other adjustments, of approximately $67 million. AltaGas recognized a pre-tax gain on these dispositions of approximately $8 million in the Consolidated Statements of Income under the line item "other income".

Assets Held For Sale

As at	December 31, 2020		December 31, 2019
Assets held for sale
Property, plant and equipment	$	4	$	22
Operating right-of-use assets	—		1
Goodwill	—		1
Other long-term assets	—		3
	$	4	$	27
Liabilities associated with assets held for sale
Unamortized investment tax credits	$	1	$	3
Operating lease liabilities - long-term	—		1
	$	1	$	4

Distributed Generation Assets

In 2019, AltaGas announced that it entered into a definitive agreement for the sale of its portfolio of U.S. distributed generation assets (Note 4). The transaction closed in September 2019; however, there is one project 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 this project remains classified as held for sale at December 31, 2020, which resulted in the reclassification of $4 million of assets to assets held for sale and $1 million of liabilities to liabilities associated with assets held for sale on the Consolidated Balance Sheets. The portion of the purchase price relating to this project is approximately $4 million (US$3

million) and is recorded within "accounts payable and accrued liabilities" on the Consolidated Balance Sheets until this project is legally transferred to the purchaser. These assets and liabilities are recorded in the Corporate/Other segment.

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Assets Held For Sale

12 Months Ended

Dec. 31, 2020

Discontinued Operations and Disposal Groups [Abstract]

Assets Held For Sale

Dispositions

AltaGas Canada Inc. (ACI)

On March 31, 2020, the Public Sector Pension Investment Board and the Alberta Teachers' Retirement Fund Board acquired all the issued and outstanding common shares of ACI for $33.50 per share. AltaGas owned 11,025,000 (approximately 37 percent) of ACI's common shares and received cash proceeds of approximately $369 million upon close. For the year ended December 31, 2020, AltaGas recognized a pre-tax gain on disposition of approximately $206 million in the Consolidated Statements of Income under the line item "other income". Following a name change in connection with the arrangement, ACI changed its name to TriSummit Utilities Inc.

Distributed Generation Assets

In 2019, AltaGas closed the disposition of its portfolio of U.S. distributed generation assets. The majority of assets were transferred in 2019, except for one project 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 this project remain classified as held for sale on the Consolidated Balance Sheets as at December 31, 2020 (Note 5). For the year ended December 31, 2020, AltaGas recognized a pre-tax gain on disposition of approximately $9 million in the Consolidated Statements of Income under the line item "other income" related to projects transferred in 2020. In addition, AltaGas recorded a pre-tax provision of $3 million related to the remaining U.S. distributed generation project which has not yet transferred to the purchaser (Note 6). The purchaser was entitled to after-tax earnings from the distributed generation projects, including the project awaiting consent, beginning September 1, 2019.

Harmattan Land Parcels

In the second quarter of 2020, AltaGas completed the sale of land parcels located near the Harmattan gas processing plant for gross cash proceeds of approximately $3 million. There was no gain or loss resulting from this disposition.

Pomona Energy Storage Facility and Ripon Gas-fired Facility

In the third quarter of 2020, AltaGas completed the sales of AltaGas Pomona Energy Storage Inc. and land related to a gas-fired power generation facility in the U.S., as well as a gas fired facility in Ripon, California, for aggregate gross cash proceeds, before working capital and other adjustments, of approximately $67 million. AltaGas recognized a pre-tax gain on these dispositions of approximately $8 million in the Consolidated Statements of Income under the line item "other income".

Assets Held For Sale

As at	December 31, 2020		December 31, 2019
Assets held for sale
Property, plant and equipment	$	4	$	22
Operating right-of-use assets	—		1
Goodwill	—		1
Other long-term assets	—		3
	$	4	$	27
Liabilities associated with assets held for sale
Unamortized investment tax credits	$	1	$	3
Operating lease liabilities - long-term	—		1
	$	1	$	4

Distributed Generation Assets

In 2019, AltaGas announced that it entered into a definitive agreement for the sale of its portfolio of U.S. distributed generation assets (Note 4). The transaction closed in September 2019; however, there is one project 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 this project remains classified as held for sale at December 31, 2020, which resulted in the reclassification of $4 million of assets to assets held for sale and $1 million of liabilities to liabilities associated with assets held for sale on the Consolidated Balance Sheets. The portion of the purchase price relating to this project is approximately $4 million (US$3

million) and is recorded within "accounts payable and accrued liabilities" on the Consolidated Balance Sheets until this project is legally transferred to the purchaser. These assets and liabilities are recorded in the Corporate/Other segment.

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Provisions on Assets

12 Months Ended

Dec. 31, 2020

Goodwill and Intangible Assets Disclosure [Abstract]

Provisions on Assets

Provisions on Assets

Year Ended December 31	2020		2019
Midstream	$	106	$	34
Corporate/Other	3		382
	$	109	$	416

Midstream

In 2020, AltaGas recorded pre-tax provisions of $106 million. Of this, approximately $104 million related to the Alton Natural Gas Storage Project, which was impaired as AltaGas does not believe that the future expected cash generation from the project aligns with the current carrying value. The remaining $2 million pre-tax provision related to land parcels located near the Harmattan gas processing plant which were sold in the second quarter of 2020 (Note 4). The pre-tax provisions were recorded against property, plant and equipment. In 2019, AltaGas recorded pre-tax provisions of $34 million related to a sour gas treatment facility in Alberta.

Corporate/Other

In 2020, AltaGas recorded pre-tax provisions totaling $3 million related to the remaining U.S. distributed generation projects which have not yet transferred to the purchaser and are classified as held for sale as at December 31, 2020. The pre-tax provisions were recorded against property, plant and equipment. In 2019, AltaGas recorded pre-tax provisions of $382 million related to various assets in the Corporate/Other segment.

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Inventory

12 Months Ended

Dec. 31, 2020

Inventory Disclosure [Abstract]

Inventory

Inventory

As at December 31	2020		2019
Natural gas held in storage (a)	$	309	$	359
Natural gas liquids	116		26
Materials and supplies	84		57
Renewable energy credits and emission compliance instruments	80		64
Crude oil and condensate	43		—
Processed finished products	4		—
	$	636	$	506

(a)As at December 31, 2020, $193 million of the natural gas held in storage was held by rate-regulated utilities (2019 - $214 million).

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2020

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, Plant and Equipment

As at	December 31, 2020						December 31, 2019
	Cost		Accumulated amortization		Net book value		Cost		Accumulated amortization		Net book value
Utilities	$	7,791	$	(286)	$	7,505	$	7,316	$	(155)	$	7,161
Midstream	4,094		(951)		3,143		3,182		(585)		2,597
Corporate/Other	842		(598)		244		1,025		(636)		389
Reclassified to assets held for sale	(4)		—		(4)		(24)		2		(22)
	$	12,723	$	(1,835)	$	10,888	$	11,499	$	(1,374)	$	10,125

Interest capitalized on long-term capital construction projects for the year ended December 31, 2020 was $6 million (2019 - $15 million).

As at December 31, 2020, the Corporation had approximately $457 million (December 31, 2019 - $725 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, 2020 was $346 million (2019 - $358 million).

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Intangible Assets

12 Months Ended

Dec. 31, 2020

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets

Intangible Assets

As at	December 31, 2020						December 31, 2019
	Cost		Accumulated amortization		Net book value		Cost		Accumulated amortization		Net book value
E&T contracts	$	26	$	(16)	$	10	$	27	$	(15)	$	12
Electricity service agreements	—		—		—		9		(8)		1
Energy services relationships	90		(45)		45		91		(27)		64
Software	304		(133)		171		304		(102)		202
Land rights	1		—		1		1		—		1
Commodity contracts	332		(20)		312		327		(21)		306
	$	753	$	(214)	$	539	$	759	$	(173)	$	586

Amortization expense related to intangible assets for the year ended December 31, 2020 was $68 million (2019 - $80 million).

As at December 31, 2020, the Corporation excluded $176 million (December 31, 2019 - $185 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:

2021	$	75
2022	$	72
2023	$	60
2024	$	39
2025	$	15
Thereafter	$	102

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Leases

12 Months Ended

Dec. 31, 2020

Leases [Abstract]

Leases

Leases

Lessee

AltaGas has operating and finance leases for office space, office equipment, field equipment, rail cars, aquatic use, vehicles, power and gas facilities, transmission and distribution assets, and land.

The components of lease expense were as follows:

	Year Ended December 31, 2020		Year Ended December 31, 2019
Operating lease cost (includes variable lease payments)	$	43	$	29
Finance lease cost
Amortization of right-of-use assets	$	4	$	4
Total finance lease cost	$	4	$	4
Total lease cost	$	47	$	33

Supplemental cash flow information related to leases was as follows:

Year Ended December 31	2020		2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	(36)	$	(21)
Financing cash flows from finance leases (a)	$	(4)	$	(4)
Right-of-use assets obtained in exchange for new lease liabilities
Operating leases	$	227	$	50
Finance leases	$	6	$	5

(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	2020		2019
Operating Leases
Operating lease right-of-use assets
Long-term	$	372	$	170
Total operating lease right-of-use assets	$	372	$	170
Operating lease liabilities
Current	$	(95)	$	(27)
Long-term	(304)		(153)
Total operating lease liabilities	$	(399)	$	(180)
Finance Leases
Property and equipment, gross	$	19	$	13
Accumulated depreciation	(7)		(3)
Property and equipment, net	$	12	$	10
Current portion of long-term debt	$	(4)	$	(4)
Long-term debt	(8)		(6)
Total finance lease liabilities	$	(12)	$	(10)

As at	December 31, 2020	December 31, 2019
Weighted average remaining lease term (years)
Operating leases	7.4	10.9
Finance leases	4.8	5.2
Weighted average discount rate (%)
Operating leases	2.42	3.51
Finance leases	2.89	3.68

Maturity analysis of lease liabilities was as follows:

	Operating Leases		Finance Leases
2021	$	96	$	4
2022	81		4
2023	58		2
2024	50		1
2025	40		1
Thereafter	125		2
Total lease payments	450		14
Less: imputed interest	(51)		(2)
Total	$	399	$	12

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
2021	$	127
2022	117
2023	108
2024	41
2025	41
Thereafter	404
Total	$	838

The carrying value of property, plant, and equipment associated with these leases was approximately $0.5 billion as at December 31, 2020.

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, aquatic use, vehicles, power and gas facilities, transmission and distribution assets, and land.

The components of lease expense were as follows:

	Year Ended December 31, 2020		Year Ended December 31, 2019
Operating lease cost (includes variable lease payments)	$	43	$	29
Finance lease cost
Amortization of right-of-use assets	$	4	$	4
Total finance lease cost	$	4	$	4
Total lease cost	$	47	$	33

Supplemental cash flow information related to leases was as follows:

Year Ended December 31	2020		2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	(36)	$	(21)
Financing cash flows from finance leases (a)	$	(4)	$	(4)
Right-of-use assets obtained in exchange for new lease liabilities
Operating leases	$	227	$	50
Finance leases	$	6	$	5

(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	2020		2019
Operating Leases
Operating lease right-of-use assets
Long-term	$	372	$	170
Total operating lease right-of-use assets	$	372	$	170
Operating lease liabilities
Current	$	(95)	$	(27)
Long-term	(304)		(153)
Total operating lease liabilities	$	(399)	$	(180)
Finance Leases
Property and equipment, gross	$	19	$	13
Accumulated depreciation	(7)		(3)
Property and equipment, net	$	12	$	10
Current portion of long-term debt	$	(4)	$	(4)
Long-term debt	(8)		(6)
Total finance lease liabilities	$	(12)	$	(10)

As at	December 31, 2020	December 31, 2019
Weighted average remaining lease term (years)
Operating leases	7.4	10.9
Finance leases	4.8	5.2
Weighted average discount rate (%)
Operating leases	2.42	3.51
Finance leases	2.89	3.68

Maturity analysis of lease liabilities was as follows:

	Operating Leases		Finance Leases
2021	$	96	$	4
2022	81		4
2023	58		2
2024	50		1
2025	40		1
Thereafter	125		2
Total lease payments	450		14
Less: imputed interest	(51)		(2)
Total	$	399	$	12

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
2021	$	127
2022	117
2023	108
2024	41
2025	41
Thereafter	404
Total	$	838

The carrying value of property, plant, and equipment associated with these leases was approximately $0.5 billion as at December 31, 2020.

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, aquatic use, vehicles, power and gas facilities, transmission and distribution assets, and land.

The components of lease expense were as follows:

	Year Ended December 31, 2020		Year Ended December 31, 2019
Operating lease cost (includes variable lease payments)	$	43	$	29
Finance lease cost
Amortization of right-of-use assets	$	4	$	4
Total finance lease cost	$	4	$	4
Total lease cost	$	47	$	33

Supplemental cash flow information related to leases was as follows:

Year Ended December 31	2020		2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	(36)	$	(21)
Financing cash flows from finance leases (a)	$	(4)	$	(4)
Right-of-use assets obtained in exchange for new lease liabilities
Operating leases	$	227	$	50
Finance leases	$	6	$	5

(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	2020		2019
Operating Leases
Operating lease right-of-use assets
Long-term	$	372	$	170
Total operating lease right-of-use assets	$	372	$	170
Operating lease liabilities
Current	$	(95)	$	(27)
Long-term	(304)		(153)
Total operating lease liabilities	$	(399)	$	(180)
Finance Leases
Property and equipment, gross	$	19	$	13
Accumulated depreciation	(7)		(3)
Property and equipment, net	$	12	$	10
Current portion of long-term debt	$	(4)	$	(4)
Long-term debt	(8)		(6)
Total finance lease liabilities	$	(12)	$	(10)

As at	December 31, 2020	December 31, 2019
Weighted average remaining lease term (years)
Operating leases	7.4	10.9
Finance leases	4.8	5.2
Weighted average discount rate (%)
Operating leases	2.42	3.51
Finance leases	2.89	3.68

Maturity analysis of lease liabilities was as follows:

	Operating Leases		Finance Leases
2021	$	96	$	4
2022	81		4
2023	58		2
2024	50		1
2025	40		1
Thereafter	125		2
Total lease payments	450		14
Less: imputed interest	(51)		(2)
Total	$	399	$	12

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
2021	$	127
2022	117
2023	108
2024	41
2025	41
Thereafter	404
Total	$	838

The carrying value of property, plant, and equipment associated with these leases was approximately $0.5 billion as at December 31, 2020.

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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Goodwill

12 Months Ended

Dec. 31, 2020

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill

Goodwill

As at	December 31, 2020		December 31, 2019
Balance, beginning of year	$	3,942	$	4,068
Business acquisition (note 3)	1,171		—
Adjustment to goodwill on business acquisition	—		92
Goodwill included in dispositions	—		(29)
Reclassified to assets held for sale	—		(1)
Foreign exchange translation	(74)		(188)
Balance, end of year	$	5,039	$	3,942

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Long-Term Investments and Other Assets

12 Months Ended

Dec. 31, 2020

Investments, All Other Investments [Abstract]

Long-Term Investments and Other Assets

Long-Term Investments and Other Assets

As at	December 31, 2020		December 31, 2019
Investments in publicly-traded entities	$	—	$	4
Loan to affiliate (notes 23 and 30)	—		45
Deferred lease receivable	12		17
Debt issuance costs associated with credit facilities	3		6
Refundable deposits	9		9
Prepayment on long-term service agreements	70		81
Deferred information technology costs	4		—
Cash calls from joint venture partners	26		10
Contract asset (net of credit losses of $1 million) (notes 23 and 24)	50		30
Rabbi trust and other restricted cash (notes 28, 29 and 31)	19		32
Other long-term receivables (net of credit losses of $2 million) (notes 23 and 29)	18		33
Capitalized contract costs	5		—
Financial transmission rights	12		12
Other	17		18
	$	245	$	297

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Variable Interest Entities

12 Months Ended

Dec. 31, 2020

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.

The following table represents amounts included in the Consolidated Balance Sheets attributable to AltaGas’ consolidated VIE:

As at	December 31, 2020		December 31, 2019
Current assets	$	7	$	6
Property, plant and equipment	358		371
Long-term investments and other assets	50		53
Current liabilities	(2)		(3)
Asset retirement obligations	(2)		(3)
Net assets	$	411	$	424

Unconsolidated VIE

Strathcona Storage Limited Partnership (SSLP)

Upon the acquisition of Petrogas on December 15, 2020, AltaGas acquired an indirect interest in SSLP, a partnership formed with ATCO Energy Solutions Ltd. to construct, operate, and maintain underground NGL storage caverns at Fort Saskatchewan,

Alberta. The facility currently has four underground NGL storage salt caverns in service, with a fifth cavern under development. As at December 31, 2020, AltaGas held an indirect 30 percent equity investment in SSLP with a carrying value of $124 million, inclusive of fair value adjustments on acquisition date (Note 3). SSLP is not consolidated by Petrogas and instead is accounted for by the equity method of accounting. Petrogas is not the primary beneficiary of SSLP and it does not have the power to direct the activities most significant to the economic performance of SSLP.

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Investments Accounted for by the Equity Method

12 Months Ended

Dec. 31, 2020

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	2020		2019		2020		2019
AltaGas Canada Inc. (ACI) (a)	Canada	—	$	—	$	164	$	3	$	17
AltaGas Idemitsu Joint Venture LP (b)	Canada	—	—		431		(25)		63
Constitution Pipeline, LLC (Constitution) (c)	United States	—	—		—		(7)		—
Eaton Rapids Gas Storage System	United States	50	26		27		2		1
Meade Pipeline Co. LLC (d)	United States	—	—		—		—		(4)
Mountain Valley Pipeline, LLC (Mountain Valley) (e)	United States	10	718		672		62		43
Sarnia Airport Storage Pool LP	Canada	50	18		18		1		1
Petrogas Preferred Shares (f)	Canada	n/a	—		150		13		13
Petrogas Terminals Penn LLC (g)	United States	37	1		—		—		—
Stonewall Gas Gathering Systems LLC (d)	United States	—	—		—		—		7
Strathcona Storage LP (g)	Canada	30	124		—		—		—
			$	887	$	1,462	$	49	$	141

(a)    ACI was acquired by the Public Sector Pension Investment Board and the Alberta Teachers' Retirement Fund Board on March 31, 2020 (Note 4).

(b)    Upon acquisition of Petrogas on December 15, 2020 (Note 3), AltaGas no longer has an equity investment in AIJVLP.

(c)    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 and Constitution was dissolved. The loss recorded in 2020 relates to a provision recorded against the equity investment (see below for further discussion).

(d)    Disposed of in 2019.

(e)    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.

(f)    Petrogas' preferred shares ceased to be an investment accounted for by the equity method after AltaGas acquired a controlling interest in Petrogas on December 15, 2020 (Note 3).

(g)    Acquired on December 15, 2020 as part of the Petrogas Acquisition (Note 3).

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:

Year Ended December 31 (a)	2020		2019
Revenues	$	828	$	1,109
Expenses	(181)		(355)
	$	647	$	754
As at December 31 (a)	2020		2019
Current assets	$	351	$	411
Property, plant and equipment	$	7,598	$	8,034
Intangible assets	$	—	$	22
Long-term investments and other assets	$	5	$	1,459
Current liabilities	$	(281)	$	(394)
Other long-term liabilities	$	(2)	$	(992)

(a)    For equity investments that were disposed of in the periods presented, revenues and expenses reflect the period prior to disposition and balance sheet amounts are $nil. For equity investments that were acquired in the year (Note 3), revenues and expenses reflect the period subsequent to acquisition and balance sheet amounts are included as at December 31, 2020.

Equity Method Investments Acquired

In connection with the acquisition of Petrogas (Note 3), AltaGas acquired the following investments accounted for by the equity method:

Petrogas Terminals Penn LLC

Petrogas owns a 50 percent equity interest in Petrogas Terminals Penn LLC, a partnership with a regional propane retailer engaged in rail offloading of propane for distribution by truck to customers in Pennsylvania and other nearby states.

Strathcona Storage LP

Petrogas owns a 40 percent equity interest in Strathcona Storage Limited Partnership, a partnership with ATCO Energy Solutions Ltd., which is engaged in the development of underground NGL storage caverns at Fort Saskatchewan, Alberta. SSLP is considered a VIE (Note 13) and is accounted for using the equity method.

AltaGas Canada Inc.

On March 31, 2020, the Public Sector Pension Investment Board and the Alberta Teachers' Retirement Fund Board acquired all the issued and outstanding common shares of ACI for $33.50 per share (Note 4). AltaGas owned 11,025,000 (approximately 37 percent) of ACI's common shares and received cash proceeds of approximately $369 million upon close. AltaGas recognized a pre-tax gain on disposition of approximately $206 million in the Consolidated Statements of Income under the line item "other income" (Note 27). Following a name change in connection with the arrangement, ACI changed its name to TriSummit Utilities Inc.

Petrogas/AIJVLP

At the beginning of 2020, AltaGas held an indirect approximate one-third interest in Petrogas through its equity investment in AIJVLP. In the first quarter of 2020, one of Petrogas' shareholders has converted their preferred shares of Petrogas to common shares resulting in the dilution of AltaGas' indirect ownership in Petrogas common shares from approximately 33.3 percent to approximately 29.2 percent. In addition, prior to the close of the Petrogas Acquisition in the fourth quarter of 2020,

AltaGas converted their preferred shares of Petrogas to common shares. As a result of these transactions, in 2020, AltaGas recognized pre-tax dilution losses totaling approximately $30 million in the Consolidated Statements of Income under the line item "income from equity investments". There were additional expenses of $12 million recorded to "income from equity investments" related to various adjustments to pre-acquisition balances of Petrogas. This primarily included amounts relating to severance, transaction costs and impairment losses related to the acquisition of Petrogas. Upon close of the Petrogas Acquisition on December 15, 2020, AltaGas recognized a pre-tax gain of $22 million in the Consolidated Statements of Income under the line item "other income" on the re-measurement of it's previously held equity investment in AIJVLP. Subsequent to the acquisition, AltaGas no longer has an equity investment in AIJVLP.

Provisions on investments accounted for by the equity method

In the year ended December 31, 2020, AltaGas recorded a pre-tax provision on equity investments of approximately $7 million in the Consolidated Statements of Income under the line item "income from equity investments" for costs associated with AltaGas' equity investment in the Constitution pipeline project which was canceled in February 2020.

In the year ended December 31, 2019, AltaGas recorded a pre-tax provision of $44 million against its investment in Meade as a result of the sale of WGL Midstream's interest in the Central Penn Pipeline. The disposition of the investment in this entity was completed in the fourth quarter of 2019. In addition, AltaGas recorded a pre-tax provision of $2 million against its 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.

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Short-term Debt

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Short-term Debt

Short-term Debt

As at	December 31, 2020		December 31, 2019
Commercial paper (a)	$	236	$	389
Project financing	20		71
	$	256	$	460

(a)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.

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 these projects 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, 2020, draws related to project financing were $20 million (December 31, 2019 - $71 million).

Other Credit Facilities

As at December 31, 2020, the AltaGas held a $70 million (December 31, 2019 - $70 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, 2020 were $nil (December 31, 2019 - $nil).

As at December 31, 2020, AltaGas held a $150 million (December 31, 2019 - $150 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, 2020 were $nil (December 31, 2019 - $26 million).

As at December 31, 2020, AltaGas held a US$200 million (December 31, 2019 - US$200 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, 2020 were $190 million (December 31, 2019 - $156 million).

As at December 31, 2020, AltaGas held a US$1.2 billion (December 31, 2019 - US$1.2 billion) 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, 2020 or December 31, 2019.

During the year ended December 31, 2020, AltaGas cancelled a US$300 million unsecured extendible revolving letter of credit facility.

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, 2020, commercial paper outstanding classified as short-term debt totaled $236 million (December 31, 2019 - $389 million).

Credit Facilities Acquired in Petrogas Acquisition

As at December 31, 2020, Petrogas held a $30 million revolving letter of credit facility. Letters of credit outstanding under this facility as at December 31, 2020 were $22 million.

As at December 31, 2020, Petrogas held an operating facility of US$15 million. There were no letters of credit outstanding under this facility as at December 31, 2020.

As at December 31, 2020, Petrogas held a US$40 million seasonal bulge 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, 2020.

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Long-Term Debt

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

As at	Maturity date	December 31, 2020		December 31, 2019
Credit facilities
$1,400 million unsecured extendible revolving facility (a)	15-May-2023	$	802	$	90
US$300 million unsecured extendible revolving facility	27-Feb-2021	—		390
US$150 million unsecured extendible revolving facility	20-Dec-2023	81		163
Commercial paper (b)	Various	260		367
$175 million secured extendible revolving facility	18-Jun-2022	51		—
AltaGas Ltd. medium-term notes (MTNs)
$200 million Senior unsecured - 4.07 percent	1-Jun-2020	—		200
$350 million Senior unsecured - 3.72 percent	28-Sep-2021	350		350
$500 million Senior unsecured - 2.61 percent	16-Dec-2022	500		500
$300 million Senior unsecured - 3.57 percent	12-Jun-2023	300		300
$200 million Senior unsecured - 4.40 percent	15-Mar-2024	200		200
$300 million Senior unsecured - 3.84 percent	15-Jan-2025	300		300
$500 million Senior unsecured - 2.16 percent	10-Jun-2025	500		—
$350 million Senior unsecured - 4.12 percent	7-Apr-2026	350		350
$200 million Senior unsecured - 3.98 percent	4-Oct-2027	200		200
$500 million Senior unsecured - 2.08 percent	30-May-2028	500		—
$200 million Senior unsecured - 2.48 percent	30-Nov-2030	200		—
$100 million Senior unsecured - 5.16 percent	13-Jan-2044	100		100
$300 million Senior unsecured - 4.50 percent	15-Aug-2044	300		300
$250 million Senior unsecured - 4.99 percent	4-Oct-2047	250		250
WGL and Washington Gas MTNs
US$250 million Senior unsecured - 2.44 percent (c)	12-Mar-2020	—		325
US$20 million Senior unsecured - 6.65 percent	20-Mar-2023	25		26
US$41 million Senior unsecured - 5.44 percent	11-Aug-2025	52		53
US$53 million Senior unsecured - 6.62 to 6.82 percent	Oct 2026	67		69
US$72 million Senior unsecured - 6.40 to 6.57 percent	Feb - Sep 2027	92		93
US$52 million Senior unsecured - 6.57 to 6.85 percent	Jan - Mar 2028	66		67
US$9 million Senior unsecured - 7.50 percent	1-Apr-2030	11		11
US$50 million Senior unsecured - 5.70 to 5.78 percent	Jan - Mar 2036	64		65
US$75 million Senior unsecured - 5.21 percent	3-Dec-2040	95		97
US$75 million Senior unsecured - 5.00 percent	15-Dec-2043	95		97
US$300 million Senior unsecured - 4.22 to 4.60 percent	Sep - Nov 2044	382		390
US$450 million Senior unsecured - 3.80 percent	15-Sep-2046	573		584
US$400 million Senior unsecured - 3.65 percent (d)	15-Sep-2049	530		390
SEMCO long-term debt
US$300 million SEMCO Senior Secured - 5.15 percent (e)	21-Apr-2020	—		390
US$82 million SEMCO Senior Secured - 4.48 percent (f)	2-Mar-2032	69		76
US$225 million First Mortgage Bonds - 3.15 percent	21-Apr-2030	286		—
US$225 million First Mortgage Bonds - 2.45 percent	21-Apr-2050	286		—
Fair value adjustment on WGL Acquisition		80		84
Finance lease liabilities (note 10)		12		10
		$	8,029	$	6,887
Less debt issuance costs		(43)		(36)
		$	7,986	$	6,851
Less current portion		(360)		(923)
		$	7,626	$	5,928

(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)    Commercial paper is supported by the availability of long-term committed credit facilities with maturity dates ranging from 2022 to 2024. Commercial paper intended to be repaid within the next year is recorded as short-term debt (Note 15).

(c)     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.

(d)     On December 10, 2020, Washington Gas issued MTNs with an aggregate principal amount of $100 million. This offering constituted the reopening of it's $300 million MTNs originally issued in 2019. The total includes a US$17 million premium which will be amortized as a reduction to interest expense over the term of the note.

(e)    Collateral for the U.S. dollar MTNs is certain SEMCO assets.

(f)    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, 2020, AltaGas held a US$300 million (December 31, 2019 - US$300 million) unsecured revolving credit facility. Draws on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, or letters of credit. There were no outstanding bank loans under this facility as at December 31, 2020 or December 31, 2019.

As at December 31, 2020, WGL held a US$250 million (December 31, 2019 - US$250 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, 2020 or December 31, 2019.

As at December 31, 2020, Washington Gas held a US$450 million (December 31, 2019 - US$450 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, 2020 or December 31, 2019.

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, 2020, outstanding commercial paper classified as long-term debt totaled $260 million (December 31, 2019 - $367 million).

Credit Facilities Acquired in Petrogas Acquisition

As at December 31, 2020, Petrogas held a $175 million secured 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. Loans and letters of credit outstanding under this facility as at December 31, 2020 were $57 million.

As at December 31, 2020, Petrogas held a US$10 million operating revolving letter of credit facility. Letters of credit outstanding under this facility as at December 31, 2020 were $nil.

As at December 31, 2020, Petrogas held a $25 million 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. There were no outstanding bank loans under this facility as at December 31, 2020.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2020

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

As at December 31	2020		2019
Balance, beginning of year	$	362	$	500
Obligations acquired (note 3)	13		—
New obligations	14		7
Obligations settled	(4)		(2)
Disposals	(1)		(6)
Revision in estimated cash flow	(10)		(129)
Accretion expense (a)	17		19
Foreign exchange translation	(6)		(21)
Total	$	385	$	368
Less: current portion (included in accounts payable and accrued liabilities)	(6)		(6)
Balance, end of year	$	379	$	362

(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.

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, 2020 was $816 million (December 31, 2019 - $727 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, 2019 - between 2.0 to 8.5 percent) and are expected to be incurred between 2021 and 2138 (December 31, 2019 - between 2020 and 2137). No assets have been legally restricted for settlement of the estimated liability.

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Environmental Matters

12 Months Ended

Dec. 31, 2020

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, 2020, a liability of $13 million has been recorded on an undiscounted basis related to future environmental response costs (December 31, 2019 - $14 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, 2020, AltaGas estimated the maximum liability associated with all of its sites to be approximately $39 million (December 31, 2019 - $40 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, 2020, AltaGas reported a regulatory asset of $15 million (December 31, 2019 - $18 million) for the portion of environmental response costs that are expected to be recoverable in future rates (Note 21).

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Other Long-term Liabilities

12 Months Ended

Dec. 31, 2020

Other Liabilities Disclosure [Abstract]

Other Long-term Liabilities

Other Long-term Liabilities

As at	December 31, 2020		December 31, 2019
Deferred revenue	$	8	$	4
Customer advances for construction	60		64
Merger commitments	10		14
Other employee benefits	6		6
Deferred payroll taxes (a)	6		—
Petrogas equalization reserve (b)	5		—
Uncertain tax positions (note 20)	21		2
Non-pension retirement benefits	16		—
Other	21		12
	$	153	$	102

(a)    Represents U.S. federal payroll tax deferrals from the Coronavirus Aid, Relief, and Economic Security (CARES) Act.

(b)    Reserve is held by a wholly owned subsidiary of Petrogas.

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Income Taxes

12 Months Ended

Dec. 31, 2020

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Year Ended December 31	2020		2019
Income before income taxes - consolidated	$	699	$	812
Statutory income tax rate (%)	24.0		26.5
Expected taxes at statutory rates	$	168	$	215
Add (deduct) the tax effect of:
Permanent differences	$	2	$	11
Statutory and other rate differences	9		(52)
Rate adjustment for change in tax rates	—		(11)
Deferred income tax recovery on regulated assets	(15)		(25)
Tax differences on divestitures and transactions	(33)		(159)
Change in valuation allowance	(2)		(11)
Other	(2)		4
	$	127	$	(28)
Income tax provision
Current	$	1	$	63
Deferred	126		(91)
	$	127	$	(28)
Effective income tax rate (%)	18.2		(3.4)

Net deferred income tax liabilities were composed of the following:

As at	December 31, 2020		December 31, 2019
PP&E and intangible assets	$	1,645	$	1,450
Regulatory assets	(229)		(204)
Tax pools, deferred financing, and compensation	(208)		(138)
Other	(94)		(161)
Valuation allowance	4		12
	$	1,118	$	959

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 was further reduced from 11 percent to 8 percent on July 1, 2020.

As at December 31, 2020, the Corporation had tax-effected non-capital losses of approximately $293 million, which will be available to offset future taxable income. If not used, these losses will expire between 2023 and 2040.

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 2013 to 2019 remain subject to examination by taxation authorities. In the United States, both the federal and state tax returns for the years 2016 to 2019 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	2020		2019
Balance, beginning of year	$	2	$	2
Gross increases for tax positions of prior year	21		—
Lapses of statute of limitations	(2)		—
Balance, end of year	$	21	$	2

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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2020

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 by a non-rate-regulated entity. These deferred regulatory assets and liabilities are included in the Consolidated Statements of Income in future periods when the amounts are reflected in customer rates. If an application is filed to modify customer rates with certain regulatory commissions, AltaGas is permitted to charge customers new rates, subject to refund, until the regulatory commission renders a final decision. During this interim period, a provision is recorded for a rate refund regulatory liability based on the difference between the amount collected in rates and the amount expected to be recovered from a final regulatory decision.

Management’s assessment of the probability of recovery or pass-through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory agency orders, rules, and rate-making conventions. The relevant regulatory bodies are the MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA.

If, for any reason, the Corporation ceases to meet the criteria for application of regulatory accounting for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be de-recognized from the Consolidated Balance Sheets and included in the Consolidated Statements of Income for the period in which the discontinuance of regulatory accounting occurs. Criteria that give rise to the discontinuance of regulatory accounting include: (i) increasing competition that restricts the ability of the Corporation to charge prices sufficient to recover specific costs, and (ii) a significant change in the manner in which rates are set by regulatory agencies from cost-based regulation to another form of regulation. The Corporation’s review of these criteria currently supports the continued application of regulatory accounting for all its utilities.

The following table summarizes the regulatory assets and liabilities recorded in the Consolidated Balance Sheets, as well as the remaining period, as at December 31, 2020 and 2019, over which the Corporation expects to realize or settle the assets or liabilities:

As at December 31	2020		2019		Recovery Period
Regulatory assets - current
Deferred cost of gas (a)	$	18	$	8	Less than one year
Accelerated replacement recovery mechanisms (b)	6		2		Less than one year
Interruptible sharing (a)	2		3		Less than one year
Energy optimization costs	1		—		Less than one year
Virginia and Maryland revenue normalization (a)	19		—		Less than one year
	$	46	$	13
Regulatory assets - non-current
Deferred regulatory costs (a) (c)	$	158	$	150	2 - 55 years
Future recovery of pension and other retirement benefits (a)	68		128		Various
Future recovery of non-retirement employee benefits (a) (d)	22		19		Various
Deferred environmental costs (a) (e)	15		18		Various
Deferred loss on debt transactions and derivative instruments (a) (f)	93		99		Various
Deferred future income taxes (a) (g)	46		43		Various
Energy efficiency program - Maryland (h)	18		12		Various
COVID-19 costs (i)	10		—		Various
Other	14		18		Various
	$	444	$	487
Regulatory liabilities - current
Deferred cost of gas (a)	$	56	$	61	Less than one year
Refundable tax credit (j)	2		2		Less than one year
Federal income tax rate change (k)	20		33		Less than one year
Virginia rate refund (l)	—		41		Less than one year
Interruptible sharing (a)	1		—		Less than one year
Virginia Coronavirus Relief Fund (m)	10		—		Less than one year
Other	1		9		Less than one year
	$	90	$	146
Regulatory liabilities - non-current
Refundable tax credit (j)	2		4		2 years
Future expense of pension and other retirement benefits (a)	335		261		Various
Future removal and site restoration costs (n)	462		484		Various
Deferred gain on debt transactions and derivative instruments (a) (f)	1		2		Various
Federal income tax rate change (k)	578		628		Various
Other	3		4		Various
	$	1,381	$	1,383

(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)    This balance represents allowed environmental remediation expenditures at SEMCO and Washington Gas sites to be recovered through rates.

(f)    The losses or gains on the issuance and extinguishment of debt and interest-rate derivative instruments include unamortized balances from transactions executed in prior 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, 2020, this also includes a fair value adjustment of $76 million (December 31, 2019 - $80 million) recorded on the WGL Acquisition in 2018.

(g)    This balance represents amounts due from customers for deferred tax assets and liabilities related to tax benefits/expenses on deductions flowed directly to customers prior to the adoption of income tax normalizations for ratemaking purposes and to tax rate changes.

(h)    Represents amounts for deferred credits associated with Washington Gas' participation in the energy conservation and efficiency program EmPower in Maryland.

(i)    Regulatory assets established to capture and track incremental COVID-19 related costs.

(j)    On September 18, 2013, CINGSA received a US$15 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)    The Virginia Coronavirus Relief Fund was received by WGL to provide direct assistance to Virginia customers with balances over 30 days in arrears.

(n)    This amount and timing of draw down is dependent upon the cost of removal of underlying utility property, plant and equipment and the life of property, plant and equipment.

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Accumulated Other Comprehensive Income

12 Months Ended

Dec. 31, 2020

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

Accumulated Other Comprehensive Income

Accumulated Other Comprehensive Income

($ millions)	Defined benefit pension and PRB plans		Hedge net investments		Translation foreign operations		Equity investee		Total
Opening balance, January 1, 2020	$	(6)	$	(149)	$	395	$	5	$	245
OCI before reclassification	(11)		(10)		(175)		(5)		(201)
Amounts reclassified from OCI	3		—		—		—		3
Current period OCI (pre-tax)	(8)		(10)		(175)		(5)		(198)
Income tax on amounts retained in AOCI	3		1		—		—		4
Income tax on amounts reclassified to earnings	(1)		—		—		—		(1)
Net current period OCI	(6)		(9)		(175)		(5)		(195)
Ending balance, December 31, 2020	$	(12)	$	(158)	$	220	$	—	$	50
Opening balance, January 1, 2019	$	(19)	$	(209)	$	801	$	6	$	579
OCI before reclassification	15		68		(406)		(1)		(324)
Amounts reclassified from OCI	1		—		—		—		1
Current period OCI (pre-tax)	16		68		(406)		(1)		(323)
Income tax on amounts retained in AOCI	(3)		(8)		—		—		(11)
Net current period OCI	13		60		(406)		(1)		(334)
Ending balance, December 31, 2019	$	(6)	$	(149)	$	395	$	5	$	245

Reclassification From Accumulated Other Comprehensive Income

AOCI components reclassified	Income statement line item	Year Ended December 31, 2020		Year Ended December 31, 2019
Defined benefit pension and PRB plans	Other income	$	3	$	1
Deferred income taxes	Income tax expense – deferred	(1)		—
		$	2	$	1

XML

Financial Instruments and Financial Risk Management

12 Months Ended

Dec. 31, 2020

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, NGL, LPG, ocean freight, and oil 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 were 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. 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. A significant change to any one of these inputs in isolation could result in a significant upward or downward fluctuation in the fair value measurement.

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, LPG, ocean freight, and oil 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, 2020
	Carrying Amount		Level 1		Level 2		Level 3		Total Fair Value
Financial assets
Fair value through net income (a)
Risk management assets - current	$	94	$	—	$	73	$	21	$	94
Risk management assets - non-current	38		—		2		36		38
Fair value through regulatory assets (a)
Risk management assets - current	4		—		1		3		4
Risk management assets - non-current	9		—		—		9		9
	$	145	$	—	$	76	$	69	$	145
Financial liabilities
Fair value through net income (a)
Risk management liabilities - current	$	102	$	—	$	78	$	24	$	102
Risk management liabilities - non-current	66		—		15		51		66
Fair value through regulatory liabilities (a)
Risk management liabilities - current	9		—		—		9		9
Risk management liabilities - non-current	79		—		1		78		79
Amortized cost
Current portion of long-term debt	360		—		360		—		360
Long-term debt	7,626		—		8,451		—		8,451
Other current liabilities (b)	37		—		37		—		37
	$	8,279	$	—	$	8,942	$	162	$	9,104

(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)    Excludes non-financial 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	$	82	$	—	$	31	$	51	$	82
Risk management assets - non-current	31		—		7		24		31
Equity securities(b)	4		4		—		—		4
Fair value through regulatory assets (a)
Risk management assets - current	5		—		—		5		5
Risk management assets - non-current	8		—		—		8		8
Amortized cost
Loans and receivables (b)	45		—		46		—		46
	$	175	$	4	$	84	$	88	$	176
Financial liabilities
Fair value through net income(a)
Risk management liabilities - current	$	121	$	—	$	99	$	22	$	121
Risk management liabilities - non-current	77		—		19		58		77
Fair value through regulatory liabilities (a)
Risk management liabilities - current	4		—		1		3		4
Risk management liabilities - non-current	90		—		—		90		90
Amortized cost
Current portion of long-term debt	923		—		923		—		923
Long-term debt	5,928		—		6,264		—		6,264
Other current liabilities (c)	15		—		15		—		15
	$	7,158	$	—	$	7,321	$	173	$	7,494

(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.

Financial assets and liabilities not included in the fair value hierarchy table include money market funds, short term debt, commercial paper, and a long-term receivable (Note 12). The carrying value of these financial instruments approximate their fair value, which reflects the short-term maturity and/or normal credit terms of these financial instruments.

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, 2020:

	Net Fair Value		Valuation Technique	Unobservable Inputs	Range							Weighted Average (a)
Natural gas	$	(73)	Discounted Cash Flow	Natural Gas Basis Price (per Dth)	$	(1.27)		-	$	2.64		$	(0.37)
Natural gas	$	(1)	Option Model	Natural Gas Basis Price (per Dth)	$	(1.27)		-	$	2.58		$	(0.01)
				Annualized Volatility of Spot Market Natural Gas	13		%	-	917		%	73		%
Electricity	$	(19)	Discounted Cash Flow	Electricity Congestion Price (per MWh)	$	(6.26)		-	$	61.88		$	13.57

(a) Unobservable inputs were weighted by transaction volume.

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	2020						2019
	Natural Gas		Electricity		Total		Natural Gas		Electricity		Total
Balance, beginning of year	$	(85)	$	—	$	(85)	$	(149)	$	(14)	$	(163)
Realized and unrealized gains (losses):
Recorded in income	8		(55)		(47)		48		1		49
Recorded in regulatory assets	(1)		—		(1)		24		—		24
Transfers into Level 3	(1)		—		(1)		(9)		—		(9)
Transfers out of Level 3	1		—		1		12		—		12
Purchases	—		3		3		—		(11)		(11)
Settlements	4		32		36		(17)		24		7
Foreign exchange translation	—		1		1		6		—		6
Balance, end of year	$	(74)	$	(19)	$	(93)	$	(85)	$	—	$	(85)

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, 2020 were due to an increase in valuations using observable market inputs. Transfers into Level 3 during the year ended December 31, 2020 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	2020		2019
Recorded to revenue	$	(79)	$	75
Recorded to cost of sales	32		(26)
	$	(47)	$	49

Summary of Unrealized Gains (Losses) on Risk Management Contracts Recognized in Net Income

Year Ended December 31	2020		2019
Natural gas	$	32	$	23
Energy exports	10		(87)
Crude oil and NGLs	4		—
NGL frac spread	(5)		(17)
Power	(15)		(5)
Foreign exchange	(5)		1
	$	21	$	(85)

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, 2020
	Gross amounts of recognized assets/liabilities		Gross amounts offset in balance sheet		Netting of collateral		Net amounts presented in balance sheet
Risk management assets (a)
Natural gas	$	104	$	(38)	$	(3)	$	63
Energy exports	86		(86)		36		36
Crude oil and NGLs	1		—		—		1
Power	30		(8)		—		22
Foreign exchange	27		(3)		(1)		23
	$	248	$	(135)	$	32	$	145
Risk management liabilities (b)
Natural gas	$	173	$	(38)	$	(3)	$	132
Energy exports	153		(86)		—		67
NGL frac spread	6		—		—		6
Power	58		(8)		1		51
Foreign exchange	3		(3)		—		—
	$	393	$	(135)	$	(2)	$	256

(a)Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $98 million and risk management assets (non‑current) balance of $47 million.

(b)Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $111 million and risk management liabilities (non‑current) balance of $145 million.

As at	December 31, 2019
	Gross amounts of recognized assets/liabilities		Gross amounts offset in balance sheet		Netting of collateral		Net amounts presented in balance sheet
Risk management assets (a)
Natural gas	$	121	$	(54)	$	—	$	67
Energy exports	10		(3)		5		12
Power	54		(7)		—		47
	$	185	$	(64)	$	5	$	126
Risk management liabilities (b)
Natural gas	$	226	$	(54)	$	(28)	$	144
Energy exports	90		(3)		—		87
NGL frac spread	2		—		—		2
Power	69		(7)		(3)		59
	$	387	$	(64)	$	(31)	$	292

(a)Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $87 million and risk management assets (non‑current) balance of $39 million.

(b)Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $125 million and risk management liabilities (non‑current) balance of $167 million.

Cash Collateral

The following table presents collateral not offset against risk management assets and liabilities:

As at	December 31, 2020		December 31, 2019
Collateral posted with counterparties	$	4	$	29
Cash collateral held representing an obligation	$	—	$	—

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, 2020, AltaGas has posted $nil (December 31, 2019 - $6 million) 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, 2020		December 31, 2019
Risk management liabilities with credit-risk-contingent features	$	32	$	42
Maximum potential collateral requirements	$	26	$	29

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 2040. 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, 2020 and 2019:

December 31, 2020	Fixed price (per GJ)	Period (months)	Notional volume (GJ)	Fair Value
Sales	1.58 to 7.86	1-157	590,054,996	$	32
Purchases	1.58 to 6.47	1-240	1,522,958,497	$	(106)
Swaps	2.29 to 7.86	1-60	288,613,586	$	5
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	$	29
Purchases	0.22 to 6.81	1-167	1,406,991,689	$	(104)
Swaps	0.22 to 10.24	1-51	541,652,374	$	(2)

Crude Oil and NGLs

In the normal course of business, AltaGas purchases and sells crude oil, condensates, and LPGs. The fixed price and market price contracts for both the purchase and sale of crude oil, condensates, and LPGs extend to 2021.

December 31, 2020	Fixed price (per Bbl)	Period (months)	Notional volume (Bbl)	Fair Value
Sales	37.43 to 62.59	1	680,000	$	(1)
Purchases	19.92 to 59.01	1-9	221,000	$	2

Energy Exports

AltaGas entered into a series of swaps to lock in a portion of the volumes exposed to the propane and butane price differentials between North American Indices and the Far East Index for contracts not under tolling arrangements at RIPET and Ferndale. AltaGas had the following contracts outstanding as at December 31, 2020:

December 31, 2020	Fixed price (per Bbl)	Period (months)	Notional volume (Bbl)	Fair Value
Propane and butane swaps	3.57 to 61.46	1-36	37,425,488	$	(31)
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)

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, 2020 and 2019:

December 31, 2020	Fixed price	Period (months)	Notional volume		Fair Value
Propane swaps	28.83 to 35.36/Bbl	1-12	1,270,350	Bbl	$	(5)
Butane swaps	32.45 to 34.02/Bbl	1-12	307,784	Bbl	$	(1)
Crude oil swaps	60.08 to 61.95/Bbl	1-12	123,120	Bbl	$	—
Natural gas swaps	1.58 to 1.86/GJ	1-12	7,281,570	GJ	$	—
December 31, 2019	Fixed price	Period (months)	Notional volume		Fair Value
Butane swaps	73.02 to 75.15/Bbl	1-12	346,852	Bbl	$	(1)
Crude oil swaps	73.02 to 75.15/Bbl	1-12	212,587	Bbl	$	(1)
Natural gas swaps	1.58 to 1.86/GJ	1-12	3,883,992	GJ	$	—

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 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 2025. As at December 31, 2020, 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, 2020 and 2019:

December 31, 2020	Fixed price (per MWh)	Period (months)	Notional volume (MWh)	Fair Value
Power sales	24.56 to 61.75	1-33	5,482,242	$	13
Power purchases	24.56 to 61.88	1-63	8,848,007	$	(18)
Swap purchases	(6.26) to 74.26	1-44	24,081,519	$	(24)
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
Power purchases	31.63 to 66.76	1-60	8,552,467	$	(27)
Swap purchases	(7.88) to 74.26	1-48	25,058,577	$	(24)

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, 2020:

Factor	Increase or decrease to forward prices	Increase or decrease to income before tax ($ millions)
PJM power price	US$1/MWh	2
AECO natural gas price	$0.50/GJ	1
NYMEX natural gas price	US$0.50/GJ	36
Energy Exports:
Propane Far East Index to domestic supply	$1/Bbl	10
Baltic LPG Freight	$1/Bbl	11
NGL frac spread:
Propane	$1/Bbl	1
Natural gas	$0.50/GJ	4
Foreign exchange swaps	$0.01 CAD to USD	1

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.

AltaGas may designate its U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. As at December 31, 2020, AltaGas has not designated any outstanding debt as a net investment hedge (December 31, 2019 - US$300 million). For the year ended December 31, 2020, AltaGas incurred an after-tax unrealized loss of $9 million arising from the translation of debt in OCI (2019 ‑ after-tax unrealized gains of $60 million).

In connection with the Petrogas Acquisition, AltaGas acquired various commodity and financial derivative instruments, including the following foreign exchange forward contracts which are outstanding as at December 31, 2020:

Foreign exchange forward contract	Notional Amount	Duration	Weighted average foreign exchange rate	Fair Value
Forward USD sales	US$29	Less than one year	1.3591	$	3
Forward USD purchases	US$356	Less than one year	1.2824	$	(3)
Foreign exchange swaps (purchases)	US$410	Less than one year	1.3322	$	23

For the year ended December 31, 2020, AltaGas recorded an after-tax realized gain of $1 million on all foreign exchange forward contracts.

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, 2020, approximately 83 percent of AltaGas’ total outstanding short-term and long-term debt was at fixed rates (December 31, 2019 - 76 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, 2020.

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, 2020, 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, 2020, a pre-tax loss of $3 million was recorded related to these instruments (2019 - pre-tax loss of $2 million).

Accounts Receivable Past Due or Impaired

With the exception of accounts receivable which are due in one year or less as summarized in the following table, AltaGas does not have any past due or impaired accounts receivables (AR) as at December 31, 2020:

As at December 31, 2020	Total		AR accruals		Receivables impaired		Less than 30 days		31 to 60 days		61 to 90 days		Over 90 days
Trade receivable	$	1,465	$	396	$	41	$	906	$	52	$	17	$	53
Other	20		—		—		20		—		—		—
Allowance for credit losses	(41)		—		(41)		—		—		—		—
	$	1,444	$	396	$	—	$	926	$	52	$	17	$	53

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	$	343	$	33	$	758	$	61	$	12	$	31
Other	17		—		—		17		—		—		—
Allowance for credit losses	(33)		—		(33)		—		—		—		—
	$	1,222	$	343	$	—	$	775	$	61	$	12	$	31

The following table provides a summary of changes to the allowance for credit losses by segment and major type:

	Year Ended December 31, 2020
	Accounts Receivable		Contract Assets (a)		Other long-term investments and other assets (b)		Total
Utilities
Balance, beginning of period	$	31	$	—	$	—	$	31
Adjustment upon adoption of ASC 326 (c)	2		—		—		2
Foreign exchange translation	(1)		—		—		(1)
New allowance (d)	32		—		—		32
Written off	(28)		—		—		(28)
Recoveries collected	4		—		—		4
Balance, end of period	$	40	$	—	$	—	$	40
Midstream
Balance, beginning of period	$	1	$	—	$	—	1
Adjustment upon adoption of ASC 326	—		1		3		4
Recoveries collected	—		—		(1)		(1)
Balance, end of period	$	1	$	1	$	2	$	4
Corporate/Other
Balance, beginning of period	$	2	$	—	$	—	$	2
Adjustment upon adoption of ASC 326	—		—		1		1
Written off	(2)		—		—		(2)
Recoveries collected	—		—		(1)		(1)
Balance, end of period	$	—	$	—	$	—	$	—
Total	$	41	$	1	$	2	$	44

(a)An allowance for credit loss is assessed quarterly and is recorded based on historical default rates published by external credit rating agencies and a rate associated with the estimated time frame that the contract asset will be billed to the customer.

(b)Includes loan to affiliate, which is no longer outstanding at December 31, 2020, and other long-term receivables (Notes 12 and 29). An allowance for credit loss is assessed quarterly and is recorded based on historical default rates published by external credit rating agencies and a rate commensurate with the period in which the receivable is expected to be collected.

(c)Based on previous collection experience, AltaGas did not record an allowance for credit losses for its contract assets associated with its energy management services projects with the U.S. federal government.

(d)Includes $8 million recorded to a regulatory asset relating to the impact of COVID-19 on uncollectible accounts.

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, 2020	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Accounts payable and accrued liabilities	$	1,561	$	1,561	$	—	$	—	$	—
Dividends payable	22		22		—		—		—
Short-term debt	256		256		—		—		—
Other current liabilities (a)	37		37		—		—		—
Risk management contract liabilities	256		111		51		22		72
Current portion of long-term debt (b)	356		356		—		—		—
Long-term debt (b)	7,581		—		1,771		1,324		4,486
	$	10,069	$	2,343	$	1,822	$	1,346	$	4,558

(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, 2019	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Accounts payable and accrued liabilities	$	1,325	$	1,325	$	—	$	—	$	—
Dividends payable	22		22		—		—		—
Short-term debt	460		460		—		—		—
Other current liabilities (a)	15		15		—		—		—
Risk management contract liabilities	292		125		34		13		120
Current portion of long-term debt (b)	920		920		—		—		—
Long-term debt (b)	5,873		—		1,489		922		3,462
	$	8,907	$	2,867	$	1,523	$	935	$	3,582

(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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Revenue

12 Months Ended

Dec. 31, 2020

Revenue from Contract with Customer [Abstract]

Revenue

Revenue

The following tables disaggregate revenue by major sources for the year:

	Year Ended December 31, 2020
	Utilities		Midstream		Corporate/Other		Total (a)
Revenue from contracts with customers
Commodity sales contracts	$	1,338	$	1,097	$	1	$	2,436
Midstream service contracts	—		277		—		277
Gas sales and transportation services	2,394		—		—		2,394
Storage services	25		—		—		25
Other	9		—		20		29
Total revenue from contracts with customers	$	3,766	$	1,374	$	21	$	5,161
Other sources of revenue
Revenue from alternative revenue programs (b)	$	96	$	—	$	—	$	96
Leasing revenue (c)	1		139		100		240
Risk management and trading activities (d) (e)	(31)		112		—		81
Other	(15)		10		14		9
Total revenue from other sources	$	51	$	261	$	114	$	426
Total revenue	$	3,817	$	1,635	$	135	$	5,587

(a)    In the first quarter of 2020, AltaGas revised its reportable segments. Comparative period numbers have been adjusted to reflect this change. Refer to Note 32 for additional information.

(b)    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.

(c)    Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Corporate/Other segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases.

(d)    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. A portion of revenue generated by the Utilities segment is from the physical sale and delivery of natural gas and power to end users.

(e)    Trading margins in the Midstream segment are reported in risk management and trading activities. AltaGas 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, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues for the year ended December 31, 2020 of $437 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract and an Asset Management Agreement (AMA), which are in scope of ASC 606, are reported within risk management and trading activities. Revenue from the GAIL contract 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 from the AMA is recognized based on the amount WGL Midstream has the right to invoice the customer in accordance with ASC 606. WGL executed the AMA in April 2020.

	Year Ended December 31, 2019
	Utilities		Midstream		Corporate/Other		Total (a)
Revenue from contracts with customers
Commodity sales contracts	$	1,428	$	746	$	51	$	2,225
Midstream service contracts	—		145		—		145
Gas sales and transportation services	2,501		—		—		2,501
Storage services	28		—		—		28
Other	9		3		29		41
Total revenue from contracts with customers	$	3,966	$	894	$	80	$	4,940
Other sources of revenue
Revenue from alternative revenue programs (b)	$	30	$	—	$	—	$	30
Leasing revenue (c)	1		137		105		243
Risk management and trading activities (d) (e)	52		188		22		262
Other	(5)		9		16		20
Total revenue from other sources	$	78	$	334	$	143	$	555
Total revenue	$	4,044	$	1,228	$	223	$	5,495

(a)In the first quarter of 2020, AltaGas revised its reportable segments. Comparative period numbers have been adjusted to reflect this change. Refer to Note 32 for additional information.

(b)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.

(c)Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Corporate/Other segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases.

(d)Risk management activities involve the use of derivative instruments such as physical and financial swaps, and forward contracts. These derivatives are accounted for under ASC 815 and ASC 825. A portion of revenue generated by the Utilities segment is from the physical sale and delivery of natural gas and power to end users.

(e)Trading margins in the Midstream segment are reported in risk management and trading activities. AltaGas 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, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues for the year ended December 31, 2019 of $505 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract and an Asset Management Agreement (AMA), which are in scope of ASC 606, are reported within risk management and trading activities. Revenue from the GAIL contract 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 from the AMA is recognized based on the amount WGL Midstream has the right to invoice the customer in accordance with ASC 606. WGL executed the AMA in April 2020.

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.

Commodity Sales

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 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 RIPET and Ferndale generate revenue from the sale and delivery of LPGs to customers in Asia shipped from offshore export terminals. Revenue is recognized when LPGs are 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 LPGs loaded on a vessel. Petrogas' commodity sales also include the sale of upgraded crude oil, processed finished products, and various fuels. Delivery takes place when there is a sales contract in place, specifying delivery volumes and sales prices. The consideration received under these contracts is variable based on commodity prices.

Midstream Service Contracts

AltaGas earns revenue from its field gathering and processing facilities, extraction facilities, storage facilities, truck hauling services, rail and truck loading and unloading terminalling, 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.

Petrogas' storage fees are typically recognized in revenue ratably over the term of the contract and rail and truck loading and unloading fees are recognized when the volumes are delivered or received.

Corporate/Other Segment

For the Corporate/Other segment, the majority of revenue relates to remaining power assets, from which revenue is primarily earned 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. This includes energy generated from combined heating and power assets that are 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.

Contract Balances

As at December 31, 2020, a contract asset of $51 million ($50 million net of credit losses) has been recorded within long-term investments and other assets on the Consolidated Balance Sheets (December 31, 2019 – $30 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, 2020 there is a contract asset of $21 million (December 31, 2019 - $59 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, 2020, contract liabilities of $nil (December 31, 2019 - $2 million) have been recorded within accounts payable and accrued liabilities on the Consolidated Balance Sheets. The contract liabilities consisted 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, 2020		December 31, 2019
Balance, beginning of year	$	89	$	59
Additions	30		32
Transfers to accounts receivable	(49)		—
Foreign exchange translation	1		(2)
Balance, end of year	$	71	$	89

Contract Liabilities

As at	December 31, 2020		December 31, 2019
Balance, beginning of year	$	2	$	2
Additions	2		2
Revenue recognized from contract liabilities (a)	(4)		(2)
Balance, end of year	$	—	$	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, 2020:

	2021		2022		2023		2024		2025		2026 & beyond		Total
Midstream service contracts	$	125	$	131	$	128	$	128	$	125	$	1,037	$	1,674
Storage services	24		23		23		23		23		142		258
Other	7		2		2		2		2		9		24
	$	156	$	156	$	153	$	153	$	150	$	1,188	$	1,956

AltaGas applies the practical expedient available under ASC 606 and does not disclose information about the remaining performance obligations for (i) contracts with an original expected length of one year or less, (ii) contracts for which revenue is recognized at the amount to which AltaGas has the right to invoice for performance completed, and (iii) contracts with variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation. In addition, the table above does not include any estimated amounts of variable consideration that are constrained. The majority of midstream service contracts, gas sales and transportation service contracts, and storage service contracts contain variable consideration whereby uncertainty related to the associated variable consideration will be resolved (usually on a daily basis) as volumes are processed, gas is delivered or as service is provided.

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Shareholders’ Equity

12 Months Ended

Dec. 31, 2020

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 consisted of two components: 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 (paid 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.

Common Shares Issued and Outstanding	Number of  shares	Amount
January 1, 2019	275,224,066	$	6,654
Shares issued for cash on exercise of options	76,177	1
Deferred taxes on share issuance cost	—	(4)
Shares issued under DRIP	3,774,442	68
December 31, 2019	279,074,685	$	6,719
Shares issued for cash on exercise of options	88,082	1
Deferred taxes on share issuance cost	—	(3)
Shares issued under DRIP	331,532	6
Issued and outstanding at December 31, 2020	279,494,299	$	6,723

Preferred Shares

As at	December 31, 2020			December 31, 2019
Issued and Outstanding	Number of shares	Amount		Number of shares	Amount
Series A	6,746,679	$	169	5,511,220	$	138
Series B	1,253,321	31		2,488,780	62
Series C	8,000,000	206		8,000,000	206
Series E	8,000,000	200		8,000,000	200
Series G	6,885,823	172		6,885,823	172
Series H	1,114,177	28		1,114,177	28
Series I	—	—		8,000,000	200
Series K	12,000,000	300		12,000,000	300
Share issuance costs, net of taxes		(29)			(29)
	44,000,000	$	1,077	52,000,000	$	1,277

On December 31, 2020, all outstanding Series I shares were redeemed. No gain or loss was recognized upon redemption. In 2019, all outstanding Washington Gas preferred shares were redeemed. A gain of $4 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)	3.060	%	$0.76500	$25	September 30, 2025	Series B
Series B (f) (g)	Floating		Floating	$25	September 30, 2025	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)	4.240	%	$1.06050	$25	September 30, 2024	Series H
Series H (f) (g)	Floating		Floating	$25	September 30, 2024	Series G
Series K (i)	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 to 8,000,000 of each of Series D Shares, Series F Shares, and up to 12,000,000 of Series L Shares, subject to certain conditions, upon conversion by the holders of the applicable currently issued and outstanding series of preferred shares noted opposite such series in the table on the applicable conversion option date. If issued upon the conversion of the applicable series of preferred shares, Series F Shares, and Series L Shares are also redeemable for $25.50, and Series D Shares are redeemable for US$25.50 on any date after the applicable conversion option date, plus all accrued but unpaid dividends to, but excluding, the date fixed for redemption.

(b)The holders of Series A Shares, Series C Shares, Series E Shares, Series G Shares, Series H 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, 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 plus 2.66 percent (Series A Shares), 3.17 percent (Series E Shares), and 3.06 percent (Series G Shares).

(f)Holders of Series B Shares 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 plus 2.66 percent (Series B Shares) and 3.06 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, 2020, the floating quarterly dividend rate is $0.17069 per share for Series B Shares and $0.195349 per share for Series H Shares for the period starting December 31, 2020 to, but excluding, March 31, 2021.

(g)Series B Shares can be redeemed for $25.50 per share on any date after September 30, 2015 that is not a Series B conversion date, plus all accrued and unpaid dividends to, but excluding, the date fixed for redemption. Series H Shares can be redeemed for $25.50 per 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 plus 3.58 percent.

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

Share Option Plan

AltaGas has an employee share option plan under which officers, employees, and service providers (as defined by the TSX) are eligible to receive grants. As at December 31, 2020, 13,915,160 shares were reserved for issuance under the plan.

As at December 31, 2020, 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, 2020, the unexpensed fair value of share option compensation cost associated with future periods was $4 million (December 31, 2019 ‑ $5 million).

The following table summarizes information about the Corporation’s share options:

	December 31, 2020			December 31, 2019
As at	Options outstanding			Options outstanding
	Number of options	Exercise price (a)		Number of options	Exercise price (a)
Share options outstanding, beginning of year	7,043,956	$	22.49	6,309,183	$	25.18
Granted	2,501,755	19.46		2,287,385	19.12
Exercised	(88,082)	14.89		(76,177)	14.52
Forfeited	(631,549)	26.00		(1,165,435)	27.31
Expired	(463,869)	27.69		(311,000)	36.16
Share options outstanding, end of year	8,362,211	$	21.06	7,043,956	$	22.49
Share options exercisable, end of year	3,607,391	$	23.59	2,921,642	$	27.70

(a)Weighted average.

As at December 31, 2020, the aggregate intrinsic value of the total share options exercisable was $5 million (December 31, 2019 - $3 million), the total intrinsic value of share options outstanding was $9 million (December 31, 2019 - $12 million) and the total intrinsic value of share options exercised was less than $1 million (December 31, 2019 - less than $1 million).

The following table summarizes the employee share option plan as at December 31, 2020:

	Options outstanding				Options exercisable
	Number outstanding	Weighted average exercise price		Weighted average remaining contractual life (years)	Number exercisable	Weighted average exercise price		Weighted average remaining contractual life (years)
$14.52 to $18.00	2,446,392	$	15.24	4.07	1,359,457	$	14.92	4.00
$18.01 to $25.08	3,930,345	19.56		4.80	528,252	19.54		4.47
$25.09 to $41.00	1,985,474	31.21		1.82	1,719,682	31.68		1.64
	8,362,211	$	21.06	3.88	3,607,391	$	23.59	2.95

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	2020	2019
Fair value per options ($)	2.61	2.30
Risk-free interest rate (%)	1.54	1.48
Expected life (years)	6	6
Expected volatility (%)	25.40	24.84
Annual dividend per share ($) (a)	0.96	0.96
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 to 44 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)	2020	2019
Balance, beginning of year	6,484,831	9,908,154
Granted	1,158,547	674,971
Vested and paid out	(681,841)	(791,335)
Forfeited	(1,342,832)	(3,377,962)
Units in lieu of dividends	113,429	71,003
Outstanding, end of year	5,732,134	6,484,831

For the year ended December 31, 2020, the compensation expense recorded for the Phantom Plan and DSUP was $16 million (2019 – $22 million). As at December 31, 2020, the unrecognized compensation expense relating to the remaining vesting period for the Phantom Plan was $23 million (December 31, 2019 ‑ $22 million) and is expected to be recognized over the vesting period.

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Net Income Per Common Share

12 Months Ended

Dec. 31, 2020

Earnings Per Share [Abstract]

Net Income Per Common Share

Net Income Per Common Share

The following table summarizes the computation of net income per common share:

	Year Ended December 31
	2020		2019
Numerator:
Net income applicable to controlling interests	$	552	$	833
Less: Preferred share dividends	(66)		(68)
Gain on redemption of preferred shares (note 25)	—		4
Net income applicable to common shares	$	486	$	769
Denominator:
(millions of shares)
Weighted average number of common shares outstanding	279.4		276.9
Dilutive equity instruments (a)	0.3		0.5
Weighted average number of common shares outstanding - diluted	279.7		277.4
Basic net income per common share	$	1.74	$	2.78
Diluted net income per common share	$	1.74	$	2.77

(a)Determined using the treasury stock method.

For the year ended December 31, 2020, 7.0 million share options (2019 – 4.3 million) were excluded from the diluted net income per share calculation as their effects were anti‑dilutive.

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Other Income

12 Months Ended

Dec. 31, 2020

Other Income and Expenses [Abstract]

Other Income

Other Income

Year Ended December 31	2020		2019
Gains on asset sales (note 4)	$	223	$	876
Gain on remeasurement of previously held interest in AIJVLP (note 3)	22		—
Other components of net benefit cost (note 28)	52		27
Interest income and other revenue	9		9
Losses on investments	—		(4)
Total	$	306	$	908

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Pension Plans and Retiree Benefits

12 Months Ended

Dec. 31, 2020

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.

In 2020, AltaGas made a voluntary change in accounting principle for calculating the market-related value of assets used in the determination of Washington Gas' net periodic pension and other post-retirement benefit plan costs. This change in accounting principle impacts the calculation of net periodic benefit cost recorded within the line item “other income” on the Consolidated Statements of Income. Refer to Note 2 for additional information.

Defined Contribution Plan

AltaGas has a defined contribution (DC) pension plan for substantially all employees. The pension cost recorded for the DC plan was $21 million for the year ended December 31, 2020 (2019 - $20 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 six in 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 three 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 for the year ended December 31, 2019. 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, 2022, and will be filed with the pension regulators in 2023. 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 are fully funded.

Rabbi Trusts

Rabbi trusts of $28 million as at December 31, 2020 have been funded to satisfy the employee benefit obligations associated with WGL’s various pension plans (December 31, 2019 - $57 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, 2020	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	$	36	$	2	$	1,725	$	428	$	1,761	$	430
Actuarial loss	1		—		137		32		138		32
Current service cost	3		—		27		9		30		9
Member contributions	—		—		—		2		—		2
Interest cost	1		—		60		15		61		15
Benefits paid	(4)		—		(82)		(24)		(86)		(24)
Expenses paid	—		—		(1)		—		(1)		—
Settlements	—		—		(25)		—		(25)		—
Foreign exchange translation	—		—		(41)		(10)		(41)		(10)
Balance, end of year	$	37	$	2	$	1,800	$	452	$	1,837	$	454
Plan assets
Fair value, beginning of year	$	15	$	—	$	1,504	$	906	$	1,519	$	906
Actual return on plan assets	1		—		275		157		276		157
Employer contributions	4		—		37		—		41		—
Member contributions	—		—		—		2		—		2
Benefits paid	(4)		—		(82)		(24)		(86)		(24)
Expenses paid	—		—		(1)		—		(1)		—
Settlements	—		—		(25)		—		(25)		—
Foreign exchange translation	—		—		(41)		(25)		(41)		(25)
Fair value, end of year	$	16	$	—	$	1,667	$	1,016	$	1,683	$	1,016
Funded status	$	(21)	$	(2)	$	(133)	$	564	$	(154)	$	562

(a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation.

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	$	2	$	1,635	$	458	$	1,669	$	460
Actuarial loss (gain)	2		—		182		(15)		184		(15)
Current service cost	3		—		24		9		27		9
Member contributions	—		—		—		2		—		2
Interest cost	1		—		68		19		69		19
Benefits paid	(4)		—		(77)		(24)		(81)		(24)
Expenses paid	—		—		(1)		—		(1)		—
Settlements	—		—		(24)		—		(24)		—
Other	—		—		—		1		—		1
Foreign exchange translation	—		—		(82)		(22)		(82)		(22)
Balance, end of year	$	36	$	2	$	1,725	$	428	$	1,761	$	430
Plan assets
Fair value, beginning of year	$	14	$	—	$	1,354	$	791	$	1,368	$	791
Actual return on plan assets	1		—		284		177		285		177
Employer contributions	4		—		39		—		43		—
Member contributions	—		—		—		2		—		2
Benefits paid	(4)		—		(77)		(23)		(81)		(23)
Expenses paid	—		—		(1)		—		(1)		—
Settlements	—		—		(25)		—		(25)		—
Foreign exchange translation	—		—		(70)		(41)		(70)		(41)
Fair value, end of year	$	15	$	—	$	1,504	$	906	$	1,519	$	906
Funded status	$	(21)	$	(2)	$	(221)	$	478	$	(242)	$	476

(a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation.

For the year ended December 31, 2020, AltaGas' pension plans incurred actuarial losses primarily due to the decrease in discount rates, which were the result of a decline in high-quality corporate bond yield curves in the Canadian and U.S. markets. For the year ended December, 31, 2019, AltaGas' defined benefit plans incurred actuarial losses for the same reason as mentioned above. AltaGas' post-retirement benefits plans incurred actuarial gains primarily due to updated census data and assumptions related to the HRA, partially offset by the decrease in discount rates.

The following amounts were included in the Consolidated Balance Sheets:

	December 31, 2020						December 31, 2019
	Defined Benefit		Post- Retirement Benefits		Total		Defined Benefit		Post-Retirement Benefits		Total (a)
Prepaid post-retirement benefits	$	—	$	572	$	572	$	—	$	487	$	487
Accounts payable and accrued liabilities (a)	(9)		—		(9)		(26)		—		(26)
Future employee obligations	(145)		(10)		(155)		(216)		(11)		(227)
	$	(154)	$	562	$	408	$	(242)	$	476	$	234

(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, 2020				December 31, 2019
	Canada		United States		Canada		United States
Accumulated benefit obligation (a)	$	36	$	1,704	$	35	$	1,616

(a)Accumulated benefit obligation differs from projected benefit obligation in that it does not include an assumption with respect to future compensation levels.

For those pension plans where the projected benefit obligation exceeded the fair value of plan assets as at December 31, 2020, the cumulative obligation and asset balances were:

As at	December 31, 2020				December 31, 2019
	Defined Benefit		Post-Retirement Benefits		Defined Benefit		Post-Retirement Benefits
Projected benefit obligation	$	1,824	$	14	$	1,757	$	13
Plan assets	$	1,670	$	3	$	1,515	$	3

For those pension plans where the accumulated benefit obligation exceeded the fair value of plan assets as at December 31, 2020, the cumulative obligation and asset balances were:

As at	December 31, 2020				December 31, 2019
	Defined Benefit		Post-Retirement Benefits		Defined Benefit		Post-Retirement Benefits
Accumulated benefit obligation	$	427	$	14	$	1,648	$	13
Plan assets	$	329	$	3	$	1,515	$	3

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, 2020	Canada				United States				Total
	Defined Benefit		Post- Retirement Benefits		Defined Benefit		Post-Retirement Benefits		Defined Benefit		Post-Retirement Benefits
Past service cost	$	—	$	—	$	—	$	(3)	$	—	$	(3)
Net actuarial gain (loss)	(9)		(1)		6		(8)		(3)		(9)
Recognized in AOCI pre-tax	$	(9)	$	(1)	$	6	$	(11)	$	(3)	$	(12)
Increase (decrease) by the amount included in deferred tax liabilities	2		—		(2)		3		—		3
Net amount in AOCI after-tax	$	(7)	$	(1)	$	4	$	(8)	$	(3)	$	(9)

Year Ended December 31, 2019	Canada				United States				Total
	Defined Benefit		Post- Retirement Benefits		Defined Benefit		Post- Retirement Benefits		Defined Benefit		Post- Retirement Benefits
Net actuarial gain (loss)	$	(9)	$	—	$	(15)	$	18	$	(24)	$	18
Recognized in AOCI pre-tax	$	(9)	$	—	$	(15)	$	18	$	(24)	$	18
Increase (decrease) by the amount included in deferred tax liabilities	2		—		7		(9)		9		(9)
Net amount in AOCI after-tax	$	(7)	$	—	$	(8)	$	9	$	(15)	$	9

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, 2020	Canada				United States				Total
	Defined Benefit		Post- Retirement Benefits		Defined Benefit		Post- Retirement Benefits		Defined Benefit		Post- Retirement Benefits
Past service credit	$	—	$	—	$	—	$	(94)	$	—	$	(94)
Net actuarial loss (gain)	—		—		68		(241)		68		(241)
Recognized in regulatory asset (liability)	$	—	$	—	$	68	$	(335)	$	68	$	(335)

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	$	(105)	$	1	$	(105)
Net actuarial loss (gain)	—		—		127		(156)		127		(156)
Recognized in regulatory asset (liability)	$	—	$	—	$	128	$	(261)	$	128	$	(261)

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.

The net pension expense by plan was as follows:

	Year Ended December 31, 2020
	Canada				United States				Total
	Defined Benefit		Post-Retirement Benefits		Defined Benefit		Post-Retirement Benefits		Defined Benefit		Post-Retirement Benefits
Current service cost (a)	$	3	$	—	$	27	$	9	$	30	$	9
Interest cost (b)	1		—		60		15		61		15
Expected return on plan assets (b) (c)	(1)		—		(81)		(40)		(82)		(40)
Amortization of past service credit (b)	—		—		—		(19)		—		(19)
Amortization of net actuarial loss (gain) (b) (c)	1		—		10		(5)		11		(5)
Plan settlements (b)	—		—		7		—		7		—
Net benefit cost (income) recognized	$	4	$	—	$	23	$	(40)	$	27	$	(40)

(a)Recorded under the line item “operating and administrative” expenses on the Consolidated Statements of Income.

(b)Recorded under the line item “other income” on the Consolidated Statements of Income.

(c)Includes the impact of the voluntary change in accounting principle implemented in 2020. Refer to Note 2 for additional information.

	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)	$	3	$	—	$	24	$	9	$	27	$	9
Interest cost (b)	1		—		68		19		69		19
Expected return on plan assets (b)	(1)		—		(75)		(37)		(76)		(37)
Amortization of past service credit (b)	—		—		—		(22)		—		(22)
Amortization of net actuarial loss (b)	1		—		12		—		13		—
Plan settlements (b)	—		—		4		—		4		—
Other (b)	—		—		—		1		—		1
Net benefit cost (income) recognized	$	4	$	—	$	33	$	(30)	$	37	$	(30)

(a)Recorded under the line item “operating and administrative” expenses on the Consolidated Statements of Income.

(b)Recorded under the line item “other income” on the Consolidated Statements of Income.

The objective 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 70 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, 2020:

Canada	Fair value		Level 1		Level 2		Percentage of Plan Assets (%)
Cash and short-term equivalents	$	2	$	2	$	—	13
Canadian equities	3		3		—		19
Foreign equities	4		4		—		25
Fixed income	6		6		—		38
Real estate	1		—		1		5
	$	16	$	15	$	1	100

United States	Fair value		Level 1		Level 2		Percentage of Plan Assets (%)
Cash and short-term equivalents	$	14	$	14	$	—	1
Canadian equities	1		1		—		—
Foreign equities (a)	357		357		—		13
Fixed income	1,002		129		873		37
Other (b)	23		—		23		1
Total investments in the fair value hierarchy	$	1,397	$	501	$	896	52
Investments measured at net asset value using the NAV practical expedient (c)
Commingled funds (d)	$	728					27
Private equity/limited partnership (e)	56						2
Pooled separate accounts (f)	32						1
Collective trust fund (g)	476						18
Total fair value of plan investments	$	2,689					100
Net payable (h)	(6)						—
	$	2,683					100

(a)Investments in foreign equities include U.S. and international securities.

(b)As at December 31, 2020, 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, 2020, investments in commingled funds consisted of approximately 50 percent common stock of large-cap U.S. companies, 20 percent U.S. Government fixed income securities, and 30 percent corporate bonds for WGL’s post-retirement benefit plans.

(e)As at December 31, 2020, investments in a private equity/limited partnership consisted of common stock of international companies.

(f)As at December 31, 2020, investments in pooled separate accounts consisted of income producing properties located in the United States.

(g)As at December 31, 2020, investments in collective trust funds consisted primarily of 90 percent common stock of U.S, companies, 7 percent income producing properties located in the United States, and 3 percent short-term money market investments.

(h)As at December 31, 2020, 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	$	16	$	16	$	—	1
Canadian equities	4		4		—		—
Foreign equities (a)	361		361		—		13
Fixed income	1,008		135		873		37
Real estate	1		—		1		—
Other (b)	23		—		23		1
Total investments in the fair value hierarchy	$	1,413	$	516	$	897	52
Investments measured at net asset value using the NAV practical expedient (c)
Commingled funds(d)	$	728					27
Private equity/limited partnership (e)	56						2
Pooled separate accounts (f)	32						1
Collective trust fund (g)	476						18
Total fair value of plan investments	$	2,705					100
Net payable (h)	(6)						—
	$	2,699					100

(a)Investments in foreign equities include U.S. and international securities.

(b)As at December 31, 2020, 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, 2020, investments in commingled funds consisted of approximately 50 percent common stock of large-cap U.S. companies, 20 percent U.S. Government fixed income securities, and 30 percent corporate bonds for WGL’s post-retirement benefit plans.

(e)As at December 31, 2020, investments in a private equity/limited partnership consisted of common stock of international companies.

(f)As at December 31, 2020, investments in pooled separate accounts consisted of income producing properties located in the United States.

(g)As at December 31, 2020, investments in collective trust funds consisted primarily of 90 percent common stock of U.S, companies, 7 percent income producing properties located in the United States, and 3 percent short-term money market investments.

(h)As at December 31, 2020, this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable.

Year Ended December 31	2020		2019
Significant actuarial assumptions used in measuring net benefit plan costs	Defined Benefit	Post-Retirement Benefits	Defined Benefit	Post-Retirement Benefits
Discount rate (%)	2.30 - 3.50	3.10 - 3.60	2.90 - 4.40	3.90 - 4.50
Expected long-term rate of return on plan assets (%) (a)	5.25 - 7.05	4.03 - 7.05	5.75 - 7.15	4.66 - 7.15
Rate of compensation increase (%)	2.75 - 4.00	3.50	2.75 - 4.10	4.10
Average remaining service life of active employees (years)	10.2	13.0	9.0	13.2

(a)Only applicable for funded plans

As at December 31	2020		2019
Significant actuarial assumptions used in measuring benefit obligations	Defined Benefit	Post-Retirement Benefits	Defined Benefit	Post-Retirement Benefits
Discount rate (%)	1.90 - 2.80	2.50 - 2.90	2.90 - 3.50	3.10 - 3.60
Rate of compensation increase (%)	1.73 - 3.93	2.50 - 3.00	2.75 - 4.00	3.50

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 between 2.2 and 6.0 percent. The health care cost trend rates were assumed to decline to between 2.2 and 4.5 percent by 2027.

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:
2021	$	16	$	—
Expected benefit payments:
2021	$	90	$	25
2022	$	91	$	22
2023	$	88	$	22
2024	$	89	$	21
2025	$	90	$	21
2026 - 2030	$	466	$	110

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Commitments, Guarantees, and Contingencies

12 Months Ended

Dec. 31, 2020

Commitments and Contingencies Disclosure [Abstract]

Commitments, Guarantees, and Contingencies

Commitments, Guarantees, and Contingencies

Commitments

AltaGas has long-term natural gas purchase and transportation arrangements, LPG purchase agreements, crude oil and condensate purchase agreements, electricity purchase arrangements, service agreements, pipeline and storage service contracts, capital commitments, environmental commitments, merger commitments, and operating leases for office space, office equipment, vehicles, rail cars, land, storage, aquatic surface use, and other 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, 2020 are estimated as follows:

	2021		2022		2023		2024		2025		2026 & beyond		Total
Gas purchase (a)	$	1,974	$	2,075	$	1,858	$	1,863	$	1,901	$	17,612	$	27,283
LPG purchase (b)	407		199		161		108		83		258		1,216
Crude oil and condensate purchase (c)	184		—		—		—		—		—		184
Electricity purchase (d)	463		287		106		29		3		—		888
Service agreements (e) (f) (g)	48		32		26		27		27		282		442
Pipeline and storage services (h)	661		637		621		564		528		3,134		6,145
Capital projects (i)	20		1		1		1		1		1		25
Operating leases (j)	96		81		58		50		40		125		450
Environmental (k)	7		3		1		1		1		—		13
Merger commitments (l)	5		2		2		2		1		3		15
Land purchase commitment (m)	20		—		—		—		—		—		20
Post-acquisition contingent payments (n)	—		16		—		—		—		—		16
	$	3,885	$	3,333	$	2,834	$	2,645	$	2,585	$	21,415	$	36,697

(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 fixed prices and forward prices, which may fluctuate significantly from period to period.

(b)AltaGas enters into contracts to purchase LPGs for its operations at RIPET and Ferndale. These contracts are used to ensure that there is an adequate supply of LPGs to meet shipment commitments and to minimize exposure to market price fluctuations. LPG purchase commitments are valued based on forward prices, which may fluctuate significantly from period to period.

(c)As part of the Petrogas Acquisition (Note 3), AltaGas acquired contracts to purchase crude oil and condensates for marketing, sale, and distribution. These contracts are used to ensure that there is an adequate supply of crude oil and condensates to meet the needs of customers and to minimize exposure to market price fluctuations. Crude oil and condensate commitments are valued based on forward prices, which may fluctuate significantly from period to period.

(d)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$21 million of commitments related to renewable energy credits.

(e)In 2014, AltaGas' Blythe facility entered into a Long-Term Service Agreement (LTSA) with a service pro 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, 2020, the total commitment was $153 million payable over the next 15 years, of which $44 million is expected to be paid over the next 5 years.

(f)In 2017, AltaGas entered into a 12-year service agreement commencing in 2019 for tug services to support the marine operations of RIPET.

(g)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.

(h)Pipeline and storage commitments include minimum payments for natural gas transportation, storage and peaking contracts that have expiration dates through 2044.

(i)Commitments for capital projects. Estimated amounts are subject to variability depending on the actual construction costs.

(j)Operating leases include lease arrangements for office space, office equipment, field equipment, rail cars, aquatic use, vehicles, power and gas facilities, transmission and distribution assets, and land.

(k)Environmental commitments include committed payments related to certain environmental response costs.

(l)Represents the estimated future payments of WGL merger commitments that have been accrued but not paid. In addition, there are certain additional merger commitments that were and will be expensed as the costs are incurred, including the investment of up to US$70 million over a ten year period to further extend natural gas service, investment of US$8 million for leak mitigation within three years, which has been paid as of December 31, 2020, hiring damage prevention trainers in each jurisdiction for a total of US$2 million over five years, and developing 15 megawatts of either electric grid energy storage or Tier 1 renewable resources within five years after the merger closed. As at December 31, 2020, the cumulative amount of merger commitments that have been expensed but not yet paid is approximately US$12 million.

(m)As part of the Petrogas Acquisition (Note 3), AltaGas acquired a commitment to purchase land as part of an agreement for it's continued use of the Ferndale terminal.

(n)Contingent payments of up to $16 million are expected to be paid related to the Petrogas Acquisition (Note 3).

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, 2020, 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. On December 10, 2020, the Colorado Court of Appeals issued an unpublished opinion affirming the judgement of the trial court. No further appeal has been taken. The judgment was paid in full in February 2021, and a satisfaction has been filed with the court.

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 $18 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 and $7 million recorded in "regulatory assets" on the Consolidated Balance Sheets for amounts expected to be recovered from customers in future periods through the rate-setting process.

During 2020, AltaGas entered into an Escrow Agreement and a Letter Agreement with the third party to share the cost related to the judgment. Following the execution of the agreements, $9 million funded by the third party was deposited into an escrow fund and recorded as restricted cash in “accounts receivable". The previously recorded receivable was reduced accordingly.

Maryland Show-Cause Order

Following the National Transportation and Safety Board (NTSB) hearing that examined the August 10, 2016, explosion and fire at an apartment complex in Silver Spring, Maryland, on September 5, 2019, the PSC of MD ordered Washington Gas 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 (Show-Cause Order). Following several hearings throughout the course of 2019 and

2020, on December 18, 2020, the PSC of MD found that Washington Gas failed to file annual reports informing the PSC of MD of the status of Washington Gas' program and imposed a US$750,000 penalty on Washington Gas for reporting violations. The PSC of MD ruled that the NTSB probable cause finding constituted hearsay and could not be admitted into the record of the case and did not undertake its own inquiry into the source of the explosion. The PSC of MD did not make any safety-related findings in the case but did find that Washington Gas made an enforceable regulatory commitment to replace all mercury regulators. The US$750,000 penalty was paid in January 2021 and Washington Gas believes that there is no additional liability as a result of the ruling from the PSC of MD. In its December 18, 2020 order, the PSC of MD also found that Washington Gas’s proposed implementation plan to replace all remaining mercury regulators within five years of completing an mercury regulator survey adequately addresses the need to replace all remaining mercury regulators in Maryland, and is in the public interest. The costs of the proposed implementation program are not yet known, and the recovery of these costs must be deferred until a future rate case.

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Related Party Transactions

12 Months Ended

Dec. 31, 2020

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, 2020		December 31, 2019
Due from related parties
Accounts receivable (a)	$	5	$	18
Long-term investments and other assets (b)	—		45
	$	5	$	63
Due to related parties
Accounts payable (c)	$	3	$	3

(a)Receivables from joint ventures and from a former affiliate of Petrogas.

(b)For the period prior to December 15, 2020, AltaGas provided a $100 million interest bearing secured loan facility to Petrogas of which $50 million was committed. The facility was available for Petrogas to draw upon from time to time for general corporate purposes until the close of the Petrogas Acquisition on December 15, 2020. 

(c)Payables to a joint venture and a former affiliate of Petrogas.

The following transactions with related parties have been recorded on the Consolidated Statements of Income for the years ended December 31, 2020 and 2019:

Year Ended December 31	2020		2019
Revenue (a)	$	92	$	115
Cost of sales (b)	$	12	$	13
Operating and administrative expenses (recoveries) (c)	$	1	$	(2)
Other income (d)	$	3	$	3

(a)In the ordinary course of business, AltaGas sold commodities to TriSummit Utilities Inc. and Petrogas.

(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)Subsequent to the close of the Petrogas Acquisition, certain operating and administrative expenses were paid on behalf of Petrogas by a former affiliate. In 2019, administrative cost recoveries included those from joint ventures and from TriSummit Utilities Inc. under a Transition Services Agreement.

(d)Interest income from loans to Petrogas (secured loan facility) prior to the acquisition of Petrogas.

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2020

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
	2020		2019
Source (use) of cash:
Accounts receivable	$	21	$	168
Inventory	32		(2)
Other current assets	1		(85)
Regulatory assets - current	(33)		7
Accounts payable and accrued liabilities	(41)		(280)
Customer deposits	(2)		(17)
Regulatory liabilities - current	(55)		34
Risk management liabilities - current	(1)		1
Other current liabilities	4		(6)
Other operating assets and liabilities	(129)		(52)
Changes in operating assets and liabilities	$	(203)	$	(232)

The following table details the changes in non-cash investing and financing activities:

	Year Ended December 31
	2020		2019
(Increase) of balance:
Common shares issued under DRIP	$	(6)	$	(68)
Net right-of-use assets obtained in exchange for new operating lease liabilities	$	227	$	50
Net right-of-use assets obtained in exchange for new finance lease liabilities	$	6	$	5
Capital expenditures included in accounts payable and accrued liabilities	$	(33)	$	(7)

The following cash payments have been included in the determination of earnings:

	Year Ended December 31
	2020		2019
Interest paid (net of capitalized interest)	$	276	$	352
Income taxes paid	$	23	$	67

The following table is a reconciliation of cash and restricted cash balances:

As at December 31	2020		2019
Cash and cash equivalents	$	32	$	57
Restricted cash holdings from customers - current	3		4
Restricted cash holdings from customers - non-current	2		4
Restricted cash included in prepaid expenses and other current assets (a)	9		25
Restricted cash included in long-term investments and other assets (note 12) (a)	19		32
Restricted cash included in accounts receivable (note 29)	9		—
Cash, cash equivalents, and restricted cash per Consolidated Statements of Cash Flows	$	74	$	122

(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 (see Note 28).

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Segmented Information

12 Months Ended

Dec. 31, 2020

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. In 2020, AltaGas revised its reportable segments to align with the structure of its business following asset sales 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. Consistent with Management’s strategic view of the business and the basis on which it assesses performance and allocates resources, beginning in 2020, AltaGas has two operating segments: Utilities (which now includes the WGL retail marketing business) and Midstream. These operating segments have not been aggregated in the determination of AltaGas' reportable segments. All other assets are included in the Corporate/Other segment. Prior period segment information has been restated to conform to the current reporting segment presentation.

The following describes the Corporation’s reporting segments:

Utilities	n rate-regulated natural gas distribution assets in Michigan, Alaska, the District of Columbia,     Maryland, and Virginia; n rate-regulated natural gas storage in the United States; and n sale of natural gas to residential, commercial and industrial customers in Washington D.C.,     Maryland, Virginia, Delaware, Pennsylvania and Ohio.
Midstream	n NGL processing and extraction plants; n natural gas storage facilities; n liquefied petroleum gas (LPG) terminals; n transmission pipelines to transport natural gas and NGL; n natural gas gathering lines and field processing facilities; n purchase and sale of natural gas; n natural gas and NGL marketing; n marketing, storage and distribution of wellsite fluids and fuels, crude oil and condensate diluents; and n interest in a regulated pipeline in the Marcellus/Utica gas formation;
Corporate/Other	n the cost of providing corporate services, financing and general corporate overhead,     investments in certain public and private entities, corporate assets, financing other segments and     the effects of changes in the fair value of certain risk management contracts; and n a small portfolio of remaining power assets, certain of which are pending sale.

The following table provides a reconciliation of segment revenue to the disaggregated revenue table disclosed in Note 24:

	Year Ended December 31, 2020
	Utilities		Midstream		Corporate/Other		Total
External revenue (note 24)	$	3,817	$	1,635	$	135	$	5,587
Intersegment revenue	—		1		—		1
Segment revenue	$	3,817	$	1,636	$	135	$	5,588

	Year Ended December 31, 2019
	Utilities		Midstream		Corporate/Other		Total
External revenue (note 24)	$	4,044	$	1,228	$	223	$	5,495
Intersegment revenue	—		32		—		32
Segment revenue	$	4,044	$	1,260	$	223	$	5,527

Geographic Information

Year Ended December 31	2020		2019
Revenue (a)
Canada	$	1,512	$	1,245
United States	4,053		4,325
TOTAL	$	5,565	$	5,570

(a)Operating revenue from external customers, excluding unrealized gains or losses on risk management contracts.

As at December 31	2020		2019
Property, plant and equipment
Canada	$	3,149	$	2,682
United States	7,739		7,443
TOTAL	$	10,888	$	10,125
Operating right-of-use assets
Canada	$	293	$	85
United States	79		85
TOTAL	$	372	$	170

The following tables show the composition by segment:

	Year Ended December 31, 2020
	Utilities		Midstream		Corporate/Other		Intersegment Elimination (a)		Total
Segment revenue (note 24)	$	3,817	$	1,636	$	135	$	(1)	$	5,587
Cost of sales	(2,156)		(994)		(29)		1		(3,178)
Operating and administrative	(942)		(254)		(71)		—		(1,267)
Accretion expenses	—		(4)		(1)		—		(5)
Depreciation and amortization	(295)		(86)		(33)		—		(414)
Provisions on assets (note 6)	(1)		(105)		(3)		—		(109)
Income from equity investments	5		44		—		—		49
Other income	259		24		23		—		306
Foreign exchange gains (losses)	—		(26)		30		—		4
Interest expense	—		—		(274)		—		(274)
Income (loss) before income taxes	$	687	$	235	$	(223)	$	—	$	699
Net additions (reductions) to:
Property, plant and equipment(b)	$	740	$	136	$	(51)	$	—	$	825
Intangible assets	$	3	$	3	$	4	$	—	$	10

(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, 2019
	Utilities		Midstream		Corporate/Other		Intersegment Elimination (a)		Total
Segment revenue (note 24)	$	4,044	$	1,260	$	223	$	(32)	$	5,495
Cost of sales	(2,448)		(760)		(51)		32		(3,227)
Operating and administrative	(960)		(213)		(126)		—		(1,299)
Accretion expenses	—		(4)		(1)		—		(5)
Depreciation and amortization	(276)		(89)		(73)		—		(438)
Provision on assets (note 6)	—		(34)		(382)		—		(416)
Income from equity investments	19		122		—		—		141
Other income	29		28		851		—		908
Foreign exchange gains (losses)	—		(5)		4		—		(1)
Interest expense	—		—		(346)		—		(346)
Income before income taxes	$	408	$	305	$	99	$	—	$	812
Net additions (reductions) to:
Property, plant and equipment (b)	$	840	$	351	$	(2,280)	$	—	$	(1,089)
Intangible assets	$	23	$	5	$	9	$	—	$	37

(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		Corporate/Other		Total
As at December 31, 2020
Goodwill	$	3,706	$	1,333	$	—	$	5,039
Segmented assets	$	13,675	$	7,320	$	537	$	21,532
As at December 31, 2019
Goodwill	$	3,781	$	161	$	—	$	3,942
Segmented assets	$	13,719	$	5,265	$	811	$	19,795

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Subsequent Events	12 Months Ended
	Dec. 31, 2020
Subsequent Events [Abstract]
Subsequent Events	Subsequent EventsSubsequent events have been reviewed through February 25, 2021, the date on which these audited Consolidated Financial Statements were issued.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2020

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 January 21, 2020, 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 of consolidated subsidiaries are shown as an allocation of the consolidated net income and are presented separately in "net income applicable to non-controlling interests".

USE OF ESTIMATES AND MEASUREMENT UNCERTAINTY

USE OF ESTIMATES AND MEASUREMENT UNCERTAINTY

The preparation of Consolidated Financial Statements in accordance with U.S. GAAP requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenue and expenses during the period. Key areas where Management has made complex or subjective judgments, when matters are inherently uncertain, include but are not limited to: determining the nature and timing of satisfaction of performance obligations and determining the transaction price and amounts allocated to performance obligations for revenue recognition; depreciation and amortization rates; 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; measurement of credit losses; 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. Additionally, cash deposited in an escrow fund related to a cost sharing agreement with a third party has been recorded as restricted cash in “accounts receivable" in the Consolidated Balance Sheets. Please refer to Note 29 for more information.

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, crude oil and condensates, processed finished products, 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, and a small number of assets acquired as part of the acquisition of Petrogas for which depreciation is calculated using the declining balance method.

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	3 to 55 years
Corporate/Other assets	3 to 46 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. 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.

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 years
Software	3 to 20 years
Land rights	5 to 43 years
Extraction and Transmission (E&T) Contracts	25 years
Commodity contracts	5 to 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.

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.

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 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.

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 may designate 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.

Credit Losses

Credit Losses

The following are the Corporation's significant accounting policies upon adoption of ASC 326:

Accounts receivable, contract assets, a loan to an affiliate, and other long-term receivables within the scope of ASC 326 are recorded net of the allowance for credit losses 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 credit losses is adjusted. Accounts are written off when collection efforts are complete and future recovery is unlikely. See below for a description of how expected credit loss estimates are developed.

Utilities Customer Receivables and Contract Assets

AltaGas is exposed to risk through the non-payment of utility bills by customers. To manage this customer credit risk, AltaGas' regulated utilities customers are offered budget billing options or high risk customers may be required to provide a cash deposit until the requirement for deposit refunds are met. AltaGas can recover a portion of non-payments from customers in future periods through the rate-setting process. For accounts receivable generated by the Utilities business, an allowance for credit losses is recorded against revenue and is recognized using a historical loss-rate based on historical payment and collection experience. This rate may be adjusted based on Management’s expectations of unusual macroeconomic conditions and other factors. AltaGas regularly evaluates the reasonableness of the allowance based on a combination of factors, such as: the length of time receivables are past due, historical expected payment, collection experience, financial condition of customers, and other circumstances that could impact customers' ability or desire to make payments. For retail energy marketing customer receivables where AltaGas has enrolled in a regulatory utility purchase of receivable program, the associated utility discount rate is used to determine credit losses.

Midstream Customer Receivables and Contract Assets

AltaGas operates under an existing credit policy that is designed to mitigate credit risk. Credit limits are established for each counterparty and credit enhancements such as letters of credit, parent guarantees, and cash collateral may be required. The creditworthiness of all counterparties is continuously monitored. A credit loss reserve is recorded for receivables with customers and trading counterparties AltaGas considers to be below investment grade by applying an estimated loss rate. The estimated loss rate is based on the historical default rates published by external rating agencies. For accounts receivable, a one-year rate is used. For contract assets, historical loss rates associated with the estimated time frame that the contract asset will be billed to the customer is used. In the event a customer or trading counterparty no longer exhibits similar risk characteristics, the associated receivable is evaluated individually.

Other

For other long-term receivables, associated counterparties are evaluated and assigned internal credit ratings based on AltaGas' credit policy. An allowance for credit losses is recorded based on historical default rates published by external credit rating agencies and a rate commensurate with the period in which the receivables are expected to be collected.

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 midstream and 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 storage services.

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. 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 RUs 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 10.2 years and 13.0 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.

In 2020, AltaGas made a voluntary change in accounting principle for calculating the market-related value of assets (MRVA) used in the determination of Washington Gas' net periodic pension and other post-retirement benefit plan costs. The change uses the fair value approach for the fixed income investment asset class of the plan assets, compared to the prior method that utilized a calculated value where gains and losses arising from changes in fair value were deferred and amortized into the calculation of the MRVA over a period of five years. The MRVA is used in the calculation of the expected return on assets and

the recognized actuarial gain or loss components of net periodic benefit cost. The approach applied for all other classes of assets remains unchanged.

Management believes that using the fair value approach for the fixed income investments in plan assets is preferable as it more closely aligns the recognition of related components within the net periodic benefit cost.

This change in accounting principle was not considered material to prior periods or the current year; therefore, the impact of the change was recognized in the current period. On the Consolidated Statements of Income, for the year ended December 31, 2020, the change resulted in an increase to income before income taxes of approximately $25 million (recorded within the line item “other income”) and an increase to net income applicable to common shares of approximately $19 million ($0.07 per basic and diluted common share), net of the tax impact of approximately $6 million recorded within the line item "deferred income tax expense (recovery)". Amounts related to regulated utility operations that are expected to be recoverable from or refunded to customers through the rate-setting process have been reflected as adjustments to regulatory assets or liabilities on the Consolidated Balance Sheets.

Income Taxes

Income Taxes

Income taxes for the Corporation and its subsidiaries are calculated using the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are determined based on differences between the carrying value and the tax basis of assets and liabilities and are measured using the enacted tax rates and laws that are in effect in the periods in which the differences are expected to be settled or realized. Deferred income tax assets are routinely reviewed, and a valuation allowance is recorded to reduce the deferred tax assets if it is more likely than not that deferred tax assets will not be realized.

The financial statement effects of an uncertain tax position are recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxing authority. The current and deferred tax impact is equal to the largest amount, considering possible settlement outcomes, that is greater than 50 percent likely of being realized upon settlement with the taxing authorities.

Investment tax credits are recognized as reductions to income tax expense over the estimated service lives of the related properties.

The rate-regulated natural gas distribution subsidiaries recognize a separate regulatory asset or liability for the amount of deferred income taxes expected to be recovered from, or paid to, customers in the future.

Net Income per Share

Net Income per Share

Basic net income per common share is computed using the weighted average number of common shares outstanding during the period. Dilutive net income per common share is calculated using the weighted average number of common shares outstanding adjusted for dilutive common shares related to the Corporation’s share-based compensation awards.

The potentially dilutive impact of the share-based compensation awards is determined using the treasury stock method. Under the treasury stock method, awards are treated as if they had been exercised with any proceeds used to repurchase common stock at the average market price during the period. Any incremental difference between the assumed number of shares issued and purchased is included in the diluted share computation.

Contingencies

Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Any such accruals are adjusted thereafter as additional information becomes available or circumstances change.

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, 2020, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU):

§    In June 2016, FASB issued ASU No. 2016-13 “Financial Instruments – Credit Losses and all related amendments (collectively "ASC 326"): Measurement of Credit Losses on Financial Instruments”. The ASU replaces the current “incurred loss” impairment methodology with an “expected loss” model for financial assets measured at amortized cost. AltaGas has applied ASC 326 using the modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the effective date of the new standard. Prior periods presented for comparative purposes were not adjusted. Upon adoption of ASC 326, "accounts receivable, net of allowances" decreased by $2 million and "long-term investments and other assets" decreased by $5 million, with an offsetting increase to "accumulated deficit". AltaGas has elected to account for its cash equivalents at fair value. Please also refer to Note 23 of the Consolidated Financial statements as at and for the year ended December 31, 2020 for further details;

§    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 adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements, but resulted in certain minor adjustments to the fair value disclosures. Please also refer to Note 23 of the Consolidated Financial statements as at and for the year ended December 31, 2020 for further details;

§    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 interests held through related parties under common control are considered on a proportional basis when determining whether fees paid to decision makers and service providers are variable interests. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§    ASU No. 2018-18 "Collaborative Arrangements: Clarifying the Interaction between Topic 808 and Topic 606". The amendments in this ASU clarifies that certain transactions between collaborative arrangement participants should be accounted for as revenue under ASC 606, adds unit-of-account guidance in ASC 808 to align with the guidance in ASC 606, and requires that a transaction with a collaborative arrangement participant that is not directly related to sales to third parties, is precluded from presenting the transaction together with revenue recognized under ASC 606 if the collaborative arrangement participant is not a customer. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§    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, clarifies the presentation of principal payments received under sales-type and direct finance leases for depository and lending institutions, and clarifies that interim transition disclosure requirements related to the change on income statement, net income and related per share amounts for the adoption of ASC 842 are not required. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

§    ASU No. 2019-04 “Financial Instruments: Codification Improvements". The amendments in this ASU provide clarification and improve the codification in recently issued accounting standards relating to credit losses, hedge accounting, and financial instruments. The amendments related to credit losses were evaluated in conjunction with ASU 2016-13 above. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and

§    ASU No. 2020-03 "Codification Improvements to Financial Instruments". The amendments in this ASU provide clarification and improve the codification to certain aspects of accounting standards related to financial instruments. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements.

Effective December 31, 2020, AltaGas adopted the following FASB issued ASU:

§    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 adoption of this ASU did not have a material impact on AltaGas' consolidated financial statements, but resulted in certain modifications to the disclosures in the pension footnote. Please also refer to Note 28 of the Consolidated Financial statements as at and for the year ended December 31, 2020 for further details.

FUTURE CHANGES IN ACCOUNTING PRINCIPLES

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. The adoption of this ASU is not expected to have a material impact on AltaGas’ financial statements.

In January 2020, FASB issued ASU No. 2020-01 "Derivatives and Hedging: Clarifying the Interactions between Topic 321, Topic 323, and Topic 815". The amendments in this ASU clarify the application of the measurement alternative for equity instruments and the measurement of non-derivative forward contracts or purchased call options used to acquire equity securities. 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’ financial statements.

In March 2020, FASB issued ASU No. 2020-04 "Reference Rate Reform: Facilitation of the Effects of Reference Rate Reform on Financial Reporting." The amendments in this ASU provide optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships affected by reference rate reform if certain criteria are met. These apply only to contracts, hedging relationships, and other transactions that reference London Interbank Offered Rate (LIBOR) or another reference rate expected to be discontinued because of reference rate reform. The amendments in this ASU are effective as of March 12, 2020 through December 31, 2022. AltaGas may elect to apply the amendments as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020 on a prospective basis. AltaGas has not elected to adopt this ASU as of December 31, 2020, and is assessing the impact of this ASU on its consolidated financial statements.

In August 2020, FASB issued ASU No. 2020-06 "Debt with Conversion and Other Options and Topic 815-40 - Derivatives and Hedging - Contracts in Entity's Own Equity: Accounting for Convertible Instruments and Contract in an Entity's Own Equity." The amendments in this Update simplify the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. The amendments in this Update are effective for public business entities that meet the definition of a Securities and Exchange Commission (SEC) filer, excluding entities eligible to be smaller reporting companies as defined by the SEC, for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. For all other entities, the amendments are effective for fiscal years beginning after December 15, 2023, including 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' financial statements.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2020

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	3 to 55 years
Corporate/Other assets	3 to 46 years

As at	December 31, 2020						December 31, 2019
	Cost		Accumulated amortization		Net book value		Cost		Accumulated amortization		Net book value
Utilities	$	7,791	$	(286)	$	7,505	$	7,316	$	(155)	$	7,161
Midstream	4,094		(951)		3,143		3,182		(585)		2,597
Corporate/Other	842		(598)		244		1,025		(636)		389
Reclassified to assets held for sale	(4)		—		(4)		(24)		2		(22)
	$	12,723	$	(1,835)	$	10,888	$	11,499	$	(1,374)	$	10,125

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 years
Software	3 to 20 years
Land rights	5 to 43 years
Extraction and Transmission (E&T) Contracts	25 years
Commodity contracts	5 to 20 years

As at	December 31, 2020						December 31, 2019
	Cost		Accumulated amortization		Net book value		Cost		Accumulated amortization		Net book value
E&T contracts	$	26	$	(16)	$	10	$	27	$	(15)	$	12
Electricity service agreements	—		—		—		9		(8)		1
Energy services relationships	90		(45)		45		91		(27)		64
Software	304		(133)		171		304		(102)		202
Land rights	1		—		1		1		—		1
Commodity contracts	332		(20)		312		327		(21)		306
	$	753	$	(214)	$	539	$	759	$	(173)	$	586

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Acquisition of Petrogas Energy Corporation (Tables)

12 Months Ended

Dec. 31, 2020

Business Combinations [Abstract]

Schedule of Final Purchase Price Allocation

The following table summarizes the preliminary purchase price allocation representing the consideration paid and the estimated fair value of the net assets acquired as at December 15, 2020. The purchase price allocation is preliminary and reflects Management’s current best estimate of the fair value of Petrogas' assets and liabilities based on the analysis of information obtained to date. Management is continuing to obtain specific information to support the valuation of property, plant and equipment, intangibles, investments accounted for by the equity method, non-controlling interest, contingencies, income taxes, environmental matters and asset retirement obligations. As additional information becomes available, the purchase price allocation may differ materially from the preliminary purchase price allocation below. The offset to any adjustments made to the aforementioned financial statement captions during the measurement period are expected to be recorded in goodwill. Any adjustments to the purchase price allocation will be made as soon as practicable but no later than one year from the date of acquisition.

Fair value of previously held interest in AltaGas Idemitsu Joint Venture LP (AIJVLP) on the acquisition date	$	631
Less: Carrying value of previously held interest in AIJVLP	(609)
Gain on re-measurement of previously held interest	$	22
Purchase consideration for an additional 37 percent of Petrogas	$	715
Deemed settlement of intercompany debt	120
Fair value of previously held interest on the acquisition date	631
Less: Fair value assigned to net assets
Current assets	536
Property, plant and equipment	523
Intangible assets	10
Operating right-of-use assets	192
Long-term investments and other assets	4
Investments accounted for by the equity method	125
Current liabilities	(363)
Long-term debt	(53)
Asset retirement obligations	(13)
Deferred income taxes	(21)
Operating lease liabilities	(152)
Other long-term liabilities	(26)
Fair value of net assets acquired	$	762
Fair value of AIJVLP's non-controlling interest in Petrogas on the acquisition date	467
Goodwill	$	1,171

Business Acquisition, Pro Forma Information

The following supplemental unaudited, pro forma consolidated financial information for the years ended December 31, 2020 and 2019 gives effect to the Petrogas Acquisition as if it had closed on January 1, 2019. This pro forma information is presented for information purposes only and does not purport to be indicative of the results that would have occurred had the Petrogas Acquisition taken place at the beginning of 2019, nor is it indicative of the results that may be expected in future periods.

	Year Ended December 31
	2020		2019
Pro forma revenue	$	7,917	$	9,217
Pro forma net income after tax	$	537	$	1,004

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Assets Held For Sale (Tables)

12 Months Ended

Dec. 31, 2020

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Assets Held for Sale

As at	December 31, 2020		December 31, 2019
Assets held for sale
Property, plant and equipment	$	4	$	22
Operating right-of-use assets	—		1
Goodwill	—		1
Other long-term assets	—		3
	$	4	$	27
Liabilities associated with assets held for sale
Unamortized investment tax credits	$	1	$	3
Operating lease liabilities - long-term	—		1
	$	1	$	4

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Provisions on Assets (Tables)

12 Months Ended

Dec. 31, 2020

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Provisions on Assets

Year Ended December 31	2020		2019
Midstream	$	106	$	34
Corporate/Other	3		382
	$	109	$	416

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Inventory (Tables)

12 Months Ended

Dec. 31, 2020

Inventory Disclosure [Abstract]

Schedule of Inventory

As at December 31	2020		2019
Natural gas held in storage (a)	$	309	$	359
Natural gas liquids	116		26
Materials and supplies	84		57
Renewable energy credits and emission compliance instruments	80		64
Crude oil and condensate	43		—
Processed finished products	4		—
	$	636	$	506

(a)As at December 31, 2020, $193 million of the natural gas held in storage was held by rate-regulated utilities (2019 - $214 million).

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2020

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	3 to 55 years
Corporate/Other assets	3 to 46 years

As at	December 31, 2020						December 31, 2019
	Cost		Accumulated amortization		Net book value		Cost		Accumulated amortization		Net book value
Utilities	$	7,791	$	(286)	$	7,505	$	7,316	$	(155)	$	7,161
Midstream	4,094		(951)		3,143		3,182		(585)		2,597
Corporate/Other	842		(598)		244		1,025		(636)		389
Reclassified to assets held for sale	(4)		—		(4)		(24)		2		(22)
	$	12,723	$	(1,835)	$	10,888	$	11,499	$	(1,374)	$	10,125

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Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2020

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 years
Software	3 to 20 years
Land rights	5 to 43 years
Extraction and Transmission (E&T) Contracts	25 years
Commodity contracts	5 to 20 years

As at	December 31, 2020						December 31, 2019
	Cost		Accumulated amortization		Net book value		Cost		Accumulated amortization		Net book value
E&T contracts	$	26	$	(16)	$	10	$	27	$	(15)	$	12
Electricity service agreements	—		—		—		9		(8)		1
Energy services relationships	90		(45)		45		91		(27)		64
Software	304		(133)		171		304		(102)		202
Land rights	1		—		1		1		—		1
Commodity contracts	332		(20)		312		327		(21)		306
	$	753	$	(214)	$	539	$	759	$	(173)	$	586

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:

2021	$	75
2022	$	72
2023	$	60
2024	$	39
2025	$	15
Thereafter	$	102

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Leases (Tables)

12 Months Ended

Dec. 31, 2020

Leases [Abstract]

Components of Lease cost

The components of lease expense were as follows:

	Year Ended December 31, 2020		Year Ended December 31, 2019
Operating lease cost (includes variable lease payments)	$	43	$	29
Finance lease cost
Amortization of right-of-use assets	$	4	$	4
Total finance lease cost	$	4	$	4
Total lease cost	$	47	$	33

Supplemental cash flow information related to leases was as follows:

Year Ended December 31	2020		2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	(36)	$	(21)
Financing cash flows from finance leases (a)	$	(4)	$	(4)
Right-of-use assets obtained in exchange for new lease liabilities
Operating leases	$	227	$	50
Finance leases	$	6	$	5

(a)Included within repayment of long-term debt on the Consolidated Statements of Cash Flows.

As at	December 31, 2020	December 31, 2019
Weighted average remaining lease term (years)
Operating leases	7.4	10.9
Finance leases	4.8	5.2
Weighted average discount rate (%)
Operating leases	2.42	3.51
Finance leases	2.89	3.68

Supplemental Balance Sheet Location

Supplemental balance sheet information related to leases was as follows:

As at December 31	2020		2019
Operating Leases
Operating lease right-of-use assets
Long-term	$	372	$	170
Total operating lease right-of-use assets	$	372	$	170
Operating lease liabilities
Current	$	(95)	$	(27)
Long-term	(304)		(153)
Total operating lease liabilities	$	(399)	$	(180)
Finance Leases
Property and equipment, gross	$	19	$	13
Accumulated depreciation	(7)		(3)
Property and equipment, net	$	12	$	10
Current portion of long-term debt	$	(4)	$	(4)
Long-term debt	(8)		(6)
Total finance lease liabilities	$	(12)	$	(10)

Operating Lease Liability, Maturity Analysis

Maturity analysis of lease liabilities was as follows:

	Operating Leases		Finance Leases
2021	$	96	$	4
2022	81		4
2023	58		2
2024	50		1
2025	40		1
Thereafter	125		2
Total lease payments	450		14
Less: imputed interest	(51)		(2)
Total	$	399	$	12

Finance Lease Liability, Maturity Analysis

Maturity analysis of lease liabilities was as follows:

	Operating Leases		Finance Leases
2021	$	96	$	4
2022	81		4
2023	58		2
2024	50		1
2025	40		1
Thereafter	125		2
Total lease payments	450		14
Less: imputed interest	(51)		(2)
Total	$	399	$	12

Maturity Analysis of Lease Receivables

Maturity analysis of lease receivables was as follows:

	Operating Leases
2021	$	127
2022	117
2023	108
2024	41
2025	41
Thereafter	404
Total	$	838

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Goodwill (Tables)

12 Months Ended

Dec. 31, 2020

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill

As at	December 31, 2020		December 31, 2019
Balance, beginning of year	$	3,942	$	4,068
Business acquisition (note 3)	1,171		—
Adjustment to goodwill on business acquisition	—		92
Goodwill included in dispositions	—		(29)
Reclassified to assets held for sale	—		(1)
Foreign exchange translation	(74)		(188)
Balance, end of year	$	5,039	$	3,942

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Long-Term Investments and Other Assets (Tables)

12 Months Ended

Dec. 31, 2020

Investments, All Other Investments [Abstract]

Schedule of Long-Term and Other Investments

As at	December 31, 2020		December 31, 2019
Investments in publicly-traded entities	$	—	$	4
Loan to affiliate (notes 23 and 30)	—		45
Deferred lease receivable	12		17
Debt issuance costs associated with credit facilities	3		6
Refundable deposits	9		9
Prepayment on long-term service agreements	70		81
Deferred information technology costs	4		—
Cash calls from joint venture partners	26		10
Contract asset (net of credit losses of $1 million) (notes 23 and 24)	50		30
Rabbi trust and other restricted cash (notes 28, 29 and 31)	19		32
Other long-term receivables (net of credit losses of $2 million) (notes 23 and 29)	18		33
Capitalized contract costs	5		—
Financial transmission rights	12		12
Other	17		18
	$	245	$	297

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Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2020

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 VIE:

As at	December 31, 2020		December 31, 2019
Current assets	$	7	$	6
Property, plant and equipment	358		371
Long-term investments and other assets	50		53
Current liabilities	(2)		(3)
Asset retirement obligations	(2)		(3)
Net assets	$	411	$	424

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Investments Accounted for by the Equity Method (Tables)

12 Months Ended

Dec. 31, 2020

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	2020		2019		2020		2019
AltaGas Canada Inc. (ACI) (a)	Canada	—	$	—	$	164	$	3	$	17
AltaGas Idemitsu Joint Venture LP (b)	Canada	—	—		431		(25)		63
Constitution Pipeline, LLC (Constitution) (c)	United States	—	—		—		(7)		—
Eaton Rapids Gas Storage System	United States	50	26		27		2		1
Meade Pipeline Co. LLC (d)	United States	—	—		—		—		(4)
Mountain Valley Pipeline, LLC (Mountain Valley) (e)	United States	10	718		672		62		43
Sarnia Airport Storage Pool LP	Canada	50	18		18		1		1
Petrogas Preferred Shares (f)	Canada	n/a	—		150		13		13
Petrogas Terminals Penn LLC (g)	United States	37	1		—		—		—
Stonewall Gas Gathering Systems LLC (d)	United States	—	—		—		—		7
Strathcona Storage LP (g)	Canada	30	124		—		—		—
			$	887	$	1,462	$	49	$	141

(a)    ACI was acquired by the Public Sector Pension Investment Board and the Alberta Teachers' Retirement Fund Board on March 31, 2020 (Note 4).

(b)    Upon acquisition of Petrogas on December 15, 2020 (Note 3), AltaGas no longer has an equity investment in AIJVLP.

(c)    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 and Constitution was dissolved. The loss recorded in 2020 relates to a provision recorded against the equity investment (see below for further discussion).

(d)    Disposed of in 2019.

(e)    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.

(f)    Petrogas' preferred shares ceased to be an investment accounted for by the equity method after AltaGas acquired a controlling interest in Petrogas on December 15, 2020 (Note 3).

(g)    Acquired on December 15, 2020 as part of the Petrogas Acquisition (Note 3).

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:

Year Ended December 31 (a)	2020		2019
Revenues	$	828	$	1,109
Expenses	(181)		(355)
	$	647	$	754
As at December 31 (a)	2020		2019
Current assets	$	351	$	411
Property, plant and equipment	$	7,598	$	8,034
Intangible assets	$	—	$	22
Long-term investments and other assets	$	5	$	1,459
Current liabilities	$	(281)	$	(394)
Other long-term liabilities	$	(2)	$	(992)

(a)    For equity investments that were disposed of in the periods presented, revenues and expenses reflect the period prior to disposition and balance sheet amounts are $nil. For equity investments that were acquired in the year (Note 3), revenues and expenses reflect the period subsequent to acquisition and balance sheet amounts are included as at December 31, 2020.

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Short-term Debt (Tables)

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Schedule of Short-Term Debt

As at	December 31, 2020		December 31, 2019
Commercial paper (a)	$	236	$	389
Project financing	20		71
	$	256	$	460

(a)Washington Gas use short-term debt in the form of commercial paper or unsecured short-term bank loans to fund seasonal cash requirements. Revolving committed credit facilities are maintained in an amount equal to or greater than the expected maximum commercial paper position.

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Schedule of Long-Term Debt

As at	Maturity date	December 31, 2020		December 31, 2019
Credit facilities
$1,400 million unsecured extendible revolving facility (a)	15-May-2023	$	802	$	90
US$300 million unsecured extendible revolving facility	27-Feb-2021	—		390
US$150 million unsecured extendible revolving facility	20-Dec-2023	81		163
Commercial paper (b)	Various	260		367
$175 million secured extendible revolving facility	18-Jun-2022	51		—
AltaGas Ltd. medium-term notes (MTNs)
$200 million Senior unsecured - 4.07 percent	1-Jun-2020	—		200
$350 million Senior unsecured - 3.72 percent	28-Sep-2021	350		350
$500 million Senior unsecured - 2.61 percent	16-Dec-2022	500		500
$300 million Senior unsecured - 3.57 percent	12-Jun-2023	300		300
$200 million Senior unsecured - 4.40 percent	15-Mar-2024	200		200
$300 million Senior unsecured - 3.84 percent	15-Jan-2025	300		300
$500 million Senior unsecured - 2.16 percent	10-Jun-2025	500		—
$350 million Senior unsecured - 4.12 percent	7-Apr-2026	350		350
$200 million Senior unsecured - 3.98 percent	4-Oct-2027	200		200
$500 million Senior unsecured - 2.08 percent	30-May-2028	500		—
$200 million Senior unsecured - 2.48 percent	30-Nov-2030	200		—
$100 million Senior unsecured - 5.16 percent	13-Jan-2044	100		100
$300 million Senior unsecured - 4.50 percent	15-Aug-2044	300		300
$250 million Senior unsecured - 4.99 percent	4-Oct-2047	250		250
WGL and Washington Gas MTNs
US$250 million Senior unsecured - 2.44 percent (c)	12-Mar-2020	—		325
US$20 million Senior unsecured - 6.65 percent	20-Mar-2023	25		26
US$41 million Senior unsecured - 5.44 percent	11-Aug-2025	52		53
US$53 million Senior unsecured - 6.62 to 6.82 percent	Oct 2026	67		69
US$72 million Senior unsecured - 6.40 to 6.57 percent	Feb - Sep 2027	92		93
US$52 million Senior unsecured - 6.57 to 6.85 percent	Jan - Mar 2028	66		67
US$9 million Senior unsecured - 7.50 percent	1-Apr-2030	11		11
US$50 million Senior unsecured - 5.70 to 5.78 percent	Jan - Mar 2036	64		65
US$75 million Senior unsecured - 5.21 percent	3-Dec-2040	95		97
US$75 million Senior unsecured - 5.00 percent	15-Dec-2043	95		97
US$300 million Senior unsecured - 4.22 to 4.60 percent	Sep - Nov 2044	382		390
US$450 million Senior unsecured - 3.80 percent	15-Sep-2046	573		584
US$400 million Senior unsecured - 3.65 percent (d)	15-Sep-2049	530		390
SEMCO long-term debt
US$300 million SEMCO Senior Secured - 5.15 percent (e)	21-Apr-2020	—		390
US$82 million SEMCO Senior Secured - 4.48 percent (f)	2-Mar-2032	69		76
US$225 million First Mortgage Bonds - 3.15 percent	21-Apr-2030	286		—
US$225 million First Mortgage Bonds - 2.45 percent	21-Apr-2050	286		—
Fair value adjustment on WGL Acquisition		80		84
Finance lease liabilities (note 10)		12		10
		$	8,029	$	6,887
Less debt issuance costs		(43)		(36)
		$	7,986	$	6,851
Less current portion		(360)		(923)
		$	7,626	$	5,928

(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)    Commercial paper is supported by the availability of long-term committed credit facilities with maturity dates ranging from 2022 to 2024. Commercial paper intended to be repaid within the next year is recorded as short-term debt (Note 15).

(c)     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.

(d)     On December 10, 2020, Washington Gas issued MTNs with an aggregate principal amount of $100 million. This offering constituted the reopening of it's $300 million MTNs originally issued in 2019. The total includes a US$17 million premium which will be amortized as a reduction to interest expense over the term of the note.

(e)    Collateral for the U.S. dollar MTNs is certain SEMCO assets.

(f)    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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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2020

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Changes in Asset Retirement Obligations

As at December 31	2020		2019
Balance, beginning of year	$	362	$	500
Obligations acquired (note 3)	13		—
New obligations	14		7
Obligations settled	(4)		(2)
Disposals	(1)		(6)
Revision in estimated cash flow	(10)		(129)
Accretion expense (a)	17		19
Foreign exchange translation	(6)		(21)
Total	$	385	$	368
Less: current portion (included in accounts payable and accrued liabilities)	(6)		(6)
Balance, end of year	$	379	$	362

(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.

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Other Long-term Liabilities (Tables)

12 Months Ended

Dec. 31, 2020

Other Liabilities Disclosure [Abstract]

Schedule of Other Long-Term Liabilities

As at	December 31, 2020		December 31, 2019
Deferred revenue	$	8	$	4
Customer advances for construction	60		64
Merger commitments	10		14
Other employee benefits	6		6
Deferred payroll taxes (a)	6		—
Petrogas equalization reserve (b)	5		—
Uncertain tax positions (note 20)	21		2
Non-pension retirement benefits	16		—
Other	21		12
	$	153	$	102

(a)    Represents U.S. federal payroll tax deferrals from the Coronavirus Aid, Relief, and Economic Security (CARES) Act.

(b)    Reserve is held by a wholly owned subsidiary of Petrogas.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2020

Income Tax Disclosure [Abstract]

Schedule of Income Tax Provision

Year Ended December 31	2020		2019
Income before income taxes - consolidated	$	699	$	812
Statutory income tax rate (%)	24.0		26.5
Expected taxes at statutory rates	$	168	$	215
Add (deduct) the tax effect of:
Permanent differences	$	2	$	11
Statutory and other rate differences	9		(52)
Rate adjustment for change in tax rates	—		(11)
Deferred income tax recovery on regulated assets	(15)		(25)
Tax differences on divestitures and transactions	(33)		(159)
Change in valuation allowance	(2)		(11)
Other	(2)		4
	$	127	$	(28)
Income tax provision
Current	$	1	$	63
Deferred	126		(91)
	$	127	$	(28)
Effective income tax rate (%)	18.2		(3.4)

Schedule of Deferred Income Tax Liabilities

Net deferred income tax liabilities were composed of the following:

As at	December 31, 2020		December 31, 2019
PP&E and intangible assets	$	1,645	$	1,450
Regulatory assets	(229)		(204)
Tax pools, deferred financing, and compensation	(208)		(138)
Other	(94)		(161)
Valuation allowance	4		12
	$	1,118	$	959

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	2020		2019
Balance, beginning of year	$	2	$	2
Gross increases for tax positions of prior year	21		—
Lapses of statute of limitations	(2)		—
Balance, end of year	$	21	$	2

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2020

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, 2020 and 2019, over which the Corporation expects to realize or settle the assets or liabilities:

As at December 31	2020		2019		Recovery Period
Regulatory assets - current
Deferred cost of gas (a)	$	18	$	8	Less than one year
Accelerated replacement recovery mechanisms (b)	6		2		Less than one year
Interruptible sharing (a)	2		3		Less than one year
Energy optimization costs	1		—		Less than one year
Virginia and Maryland revenue normalization (a)	19		—		Less than one year
	$	46	$	13
Regulatory assets - non-current
Deferred regulatory costs (a) (c)	$	158	$	150	2 - 55 years
Future recovery of pension and other retirement benefits (a)	68		128		Various
Future recovery of non-retirement employee benefits (a) (d)	22		19		Various
Deferred environmental costs (a) (e)	15		18		Various
Deferred loss on debt transactions and derivative instruments (a) (f)	93		99		Various
Deferred future income taxes (a) (g)	46		43		Various
Energy efficiency program - Maryland (h)	18		12		Various
COVID-19 costs (i)	10		—		Various
Other	14		18		Various
	$	444	$	487
Regulatory liabilities - current
Deferred cost of gas (a)	$	56	$	61	Less than one year
Refundable tax credit (j)	2		2		Less than one year
Federal income tax rate change (k)	20		33		Less than one year
Virginia rate refund (l)	—		41		Less than one year
Interruptible sharing (a)	1		—		Less than one year
Virginia Coronavirus Relief Fund (m)	10		—		Less than one year
Other	1		9		Less than one year
	$	90	$	146
Regulatory liabilities - non-current
Refundable tax credit (j)	2		4		2 years
Future expense of pension and other retirement benefits (a)	335		261		Various
Future removal and site restoration costs (n)	462		484		Various
Deferred gain on debt transactions and derivative instruments (a) (f)	1		2		Various
Federal income tax rate change (k)	578		628		Various
Other	3		4		Various
	$	1,381	$	1,383

(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)    This balance represents allowed environmental remediation expenditures at SEMCO and Washington Gas sites to be recovered through rates.

(f)    The losses or gains on the issuance and extinguishment of debt and interest-rate derivative instruments include unamortized balances from transactions executed in prior 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, 2020, this also includes a fair value adjustment of $76 million (December 31, 2019 - $80 million) recorded on the WGL Acquisition in 2018.

(g)    This balance represents amounts due from customers for deferred tax assets and liabilities related to tax benefits/expenses on deductions flowed directly to customers prior to the adoption of income tax normalizations for ratemaking purposes and to tax rate changes.

(h)    Represents amounts for deferred credits associated with Washington Gas' participation in the energy conservation and efficiency program EmPower in Maryland.

(i)    Regulatory assets established to capture and track incremental COVID-19 related costs.

(j)    On September 18, 2013, CINGSA received a US$15 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)    The Virginia Coronavirus Relief Fund was received by WGL to provide direct assistance to Virginia customers with balances over 30 days in arrears.

(n)    This amount and timing of draw down is dependent upon the cost of removal of underlying utility property, plant and equipment and the life of property, plant and equipment.

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Accumulated Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2020

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

Schedule of Accumulated Other Comprehensive Income

($ millions)	Defined benefit pension and PRB plans		Hedge net investments		Translation foreign operations		Equity investee		Total
Opening balance, January 1, 2020	$	(6)	$	(149)	$	395	$	5	$	245
OCI before reclassification	(11)		(10)		(175)		(5)		(201)
Amounts reclassified from OCI	3		—		—		—		3
Current period OCI (pre-tax)	(8)		(10)		(175)		(5)		(198)
Income tax on amounts retained in AOCI	3		1		—		—		4
Income tax on amounts reclassified to earnings	(1)		—		—		—		(1)
Net current period OCI	(6)		(9)		(175)		(5)		(195)
Ending balance, December 31, 2020	$	(12)	$	(158)	$	220	$	—	$	50
Opening balance, January 1, 2019	$	(19)	$	(209)	$	801	$	6	$	579
OCI before reclassification	15		68		(406)		(1)		(324)
Amounts reclassified from OCI	1		—		—		—		1
Current period OCI (pre-tax)	16		68		(406)		(1)		(323)
Income tax on amounts retained in AOCI	(3)		(8)		—		—		(11)
Net current period OCI	13		60		(406)		(1)		(334)
Ending balance, December 31, 2019	$	(6)	$	(149)	$	395	$	5	$	245

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, 2020		Year Ended December 31, 2019
Defined benefit pension and PRB plans	Other income	$	3	$	1
Deferred income taxes	Income tax expense – deferred	(1)		—
		$	2	$	1

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Financial Instruments and Financial Risk Management (Tables)

12 Months Ended

Dec. 31, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Fair Value of Risk Management Assets and Liabilities

As at	December 31, 2020
	Carrying Amount		Level 1		Level 2		Level 3		Total Fair Value
Financial assets
Fair value through net income (a)
Risk management assets - current	$	94	$	—	$	73	$	21	$	94
Risk management assets - non-current	38		—		2		36		38
Fair value through regulatory assets (a)
Risk management assets - current	4		—		1		3		4
Risk management assets - non-current	9		—		—		9		9
	$	145	$	—	$	76	$	69	$	145
Financial liabilities
Fair value through net income (a)
Risk management liabilities - current	$	102	$	—	$	78	$	24	$	102
Risk management liabilities - non-current	66		—		15		51		66
Fair value through regulatory liabilities (a)
Risk management liabilities - current	9		—		—		9		9
Risk management liabilities - non-current	79		—		1		78		79
Amortized cost
Current portion of long-term debt	360		—		360		—		360
Long-term debt	7,626		—		8,451		—		8,451
Other current liabilities (b)	37		—		37		—		37
	$	8,279	$	—	$	8,942	$	162	$	9,104

(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)    Excludes non-financial 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	$	82	$	—	$	31	$	51	$	82
Risk management assets - non-current	31		—		7		24		31
Equity securities(b)	4		4		—		—		4
Fair value through regulatory assets (a)
Risk management assets - current	5		—		—		5		5
Risk management assets - non-current	8		—		—		8		8
Amortized cost
Loans and receivables (b)	45		—		46		—		46
	$	175	$	4	$	84	$	88	$	176
Financial liabilities
Fair value through net income(a)
Risk management liabilities - current	$	121	$	—	$	99	$	22	$	121
Risk management liabilities - non-current	77		—		19		58		77
Fair value through regulatory liabilities (a)
Risk management liabilities - current	4		—		1		3		4
Risk management liabilities - non-current	90		—		—		90		90
Amortized cost
Current portion of long-term debt	923		—		923		—		923
Long-term debt	5,928		—		6,264		—		6,264
Other current liabilities (c)	15		—		15		—		15
	$	7,158	$	—	$	7,321	$	173	$	7,494

(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, 2020:

	Net Fair Value		Valuation Technique	Unobservable Inputs	Range							Weighted Average (a)
Natural gas	$	(73)	Discounted Cash Flow	Natural Gas Basis Price (per Dth)	$	(1.27)		-	$	2.64		$	(0.37)
Natural gas	$	(1)	Option Model	Natural Gas Basis Price (per Dth)	$	(1.27)		-	$	2.58		$	(0.01)
				Annualized Volatility of Spot Market Natural Gas	13		%	-	917		%	73		%
Electricity	$	(19)	Discounted Cash Flow	Electricity Congestion Price (per MWh)	$	(6.26)		-	$	61.88		$	13.57

(a) Unobservable inputs were weighted by transaction volume.

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	2020						2019
	Natural Gas		Electricity		Total		Natural Gas		Electricity		Total
Balance, beginning of year	$	(85)	$	—	$	(85)	$	(149)	$	(14)	$	(163)
Realized and unrealized gains (losses):
Recorded in income	8		(55)		(47)		48		1		49
Recorded in regulatory assets	(1)		—		(1)		24		—		24
Transfers into Level 3	(1)		—		(1)		(9)		—		(9)
Transfers out of Level 3	1		—		1		12		—		12
Purchases	—		3		3		—		(11)		(11)
Settlements	4		32		36		(17)		24		7
Foreign exchange translation	—		1		1		6		—		6
Balance, end of year	$	(74)	$	(19)	$	(93)	$	(85)	$	—	$	(85)

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	2020		2019
Recorded to revenue	$	(79)	$	75
Recorded to cost of sales	32		(26)
	$	(47)	$	49

Summary of Unrealized Gains (Losses) on Risk Management Contracts

Summary of Unrealized Gains (Losses) on Risk Management Contracts Recognized in Net Income

Year Ended December 31	2020		2019
Natural gas	$	32	$	23
Energy exports	10		(87)
Crude oil and NGLs	4		—
NGL frac spread	(5)		(17)
Power	(15)		(5)
Foreign exchange	(5)		1
	$	21	$	(85)

Schedule of Offsetting Assets and Liabilities

As at	December 31, 2020
	Gross amounts of recognized assets/liabilities		Gross amounts offset in balance sheet		Netting of collateral		Net amounts presented in balance sheet
Risk management assets (a)
Natural gas	$	104	$	(38)	$	(3)	$	63
Energy exports	86		(86)		36		36
Crude oil and NGLs	1		—		—		1
Power	30		(8)		—		22
Foreign exchange	27		(3)		(1)		23
	$	248	$	(135)	$	32	$	145
Risk management liabilities (b)
Natural gas	$	173	$	(38)	$	(3)	$	132
Energy exports	153		(86)		—		67
NGL frac spread	6		—		—		6
Power	58		(8)		1		51
Foreign exchange	3		(3)		—		—
	$	393	$	(135)	$	(2)	$	256

(a)Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $98 million and risk management assets (non‑current) balance of $47 million.

(b)Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $111 million and risk management liabilities (non‑current) balance of $145 million.

As at	December 31, 2019
	Gross amounts of recognized assets/liabilities		Gross amounts offset in balance sheet		Netting of collateral		Net amounts presented in balance sheet
Risk management assets (a)
Natural gas	$	121	$	(54)	$	—	$	67
Energy exports	10		(3)		5		12
Power	54		(7)		—		47
	$	185	$	(64)	$	5	$	126
Risk management liabilities (b)
Natural gas	$	226	$	(54)	$	(28)	$	144
Energy exports	90		(3)		—		87
NGL frac spread	2		—		—		2
Power	69		(7)		(3)		59
	$	387	$	(64)	$	(31)	$	292

(a)Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $87 million and risk management assets (non‑current) balance of $39 million.

(b)Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $125 million and risk management liabilities (non‑current) balance of $167 million.

Cash Collateral

The following table presents collateral not offset against risk management assets and liabilities:

As at	December 31, 2020		December 31, 2019
Collateral posted with counterparties	$	4	$	29
Cash collateral held representing an obligation	$	—	$	—

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, 2020		December 31, 2019
Risk management liabilities with credit-risk-contingent features	$	32	$	42
Maximum potential collateral requirements	$	26	$	29

Schedule of Notional Amounts of Outstanding Derivative Positions

AltaGas had the following forward contracts and commodity swaps outstanding related to the activities in the energy services business as at December 31, 2020 and 2019:

December 31, 2020	Fixed price (per GJ)	Period (months)	Notional volume (GJ)	Fair Value
Sales	1.58 to 7.86	1-157	590,054,996	$	32
Purchases	1.58 to 6.47	1-240	1,522,958,497	$	(106)
Swaps	2.29 to 7.86	1-60	288,613,586	$	5
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	$	29
Purchases	0.22 to 6.81	1-167	1,406,991,689	$	(104)
Swaps	0.22 to 10.24	1-51	541,652,374	$	(2)

December 31, 2020	Fixed price (per Bbl)	Period (months)	Notional volume (Bbl)	Fair Value
Sales	37.43 to 62.59	1	680,000	$	(1)
Purchases	19.92 to 59.01	1-9	221,000	$	2

AltaGas had the following contracts outstanding as at December 31, 2020:

December 31, 2020	Fixed price (per Bbl)	Period (months)	Notional volume (Bbl)	Fair Value
Propane and butane swaps	3.57 to 61.46	1-36	37,425,488	$	(31)
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)

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, 2020 and 2019:

December 31, 2020	Fixed price	Period (months)	Notional volume		Fair Value
Propane swaps	28.83 to 35.36/Bbl	1-12	1,270,350	Bbl	$	(5)
Butane swaps	32.45 to 34.02/Bbl	1-12	307,784	Bbl	$	(1)
Crude oil swaps	60.08 to 61.95/Bbl	1-12	123,120	Bbl	$	—
Natural gas swaps	1.58 to 1.86/GJ	1-12	7,281,570	GJ	$	—
December 31, 2019	Fixed price	Period (months)	Notional volume		Fair Value
Butane swaps	73.02 to 75.15/Bbl	1-12	346,852	Bbl	$	(1)
Crude oil swaps	73.02 to 75.15/Bbl	1-12	212,587	Bbl	$	(1)
Natural gas swaps	1.58 to 1.86/GJ	1-12	3,883,992	GJ	$	—

AltaGas had the following power commodity forward contracts and commodity swaps outstanding as at December 31, 2020 and 2019:

December 31, 2020	Fixed price (per MWh)	Period (months)	Notional volume (MWh)	Fair Value
Power sales	24.56 to 61.75	1-33	5,482,242	$	13
Power purchases	24.56 to 61.88	1-63	8,848,007	$	(18)
Swap purchases	(6.26) to 74.26	1-44	24,081,519	$	(24)
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
Power purchases	31.63 to 66.76	1-60	8,552,467	$	(27)
Swap purchases	(7.88) to 74.26	1-48	25,058,577	$	(24)

In connection with the Petrogas Acquisition, AltaGas acquired various commodity and financial derivative instruments, including the following foreign exchange forward contracts which are outstanding as at December 31, 2020:

Foreign exchange forward contract	Notional Amount	Duration	Weighted average foreign exchange rate	Fair Value
Forward USD sales	US$29	Less than one year	1.3591	$	3
Forward USD purchases	US$356	Less than one year	1.2824	$	(3)
Foreign exchange swaps (purchases)	US$410	Less than one year	1.3322	$	23

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, 2020:

Factor	Increase or decrease to forward prices	Increase or decrease to income before tax ($ millions)
PJM power price	US$1/MWh	2
AECO natural gas price	$0.50/GJ	1
NYMEX natural gas price	US$0.50/GJ	36
Energy Exports:
Propane Far East Index to domestic supply	$1/Bbl	10
Baltic LPG Freight	$1/Bbl	11
NGL frac spread:
Propane	$1/Bbl	1
Natural gas	$0.50/GJ	4
Foreign exchange swaps	$0.01 CAD to USD	1

Schedule of Accounts Receivable Past Due or Impaired

As at December 31, 2020	Total		AR accruals		Receivables impaired		Less than 30 days		31 to 60 days		61 to 90 days		Over 90 days
Trade receivable	$	1,465	$	396	$	41	$	906	$	52	$	17	$	53
Other	20		—		—		20		—		—		—
Allowance for credit losses	(41)		—		(41)		—		—		—		—
	$	1,444	$	396	$	—	$	926	$	52	$	17	$	53

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	$	343	$	33	$	758	$	61	$	12	$	31
Other	17		—		—		17		—		—		—
Allowance for credit losses	(33)		—		(33)		—		—		—		—
	$	1,222	$	343	$	—	$	775	$	61	$	12	$	31

The following table provides a summary of changes to the allowance for credit losses by segment and major type:

	Year Ended December 31, 2020
	Accounts Receivable		Contract Assets (a)		Other long-term investments and other assets (b)		Total
Utilities
Balance, beginning of period	$	31	$	—	$	—	$	31
Adjustment upon adoption of ASC 326 (c)	2		—		—		2
Foreign exchange translation	(1)		—		—		(1)
New allowance (d)	32		—		—		32
Written off	(28)		—		—		(28)
Recoveries collected	4		—		—		4
Balance, end of period	$	40	$	—	$	—	$	40
Midstream
Balance, beginning of period	$	1	$	—	$	—	1
Adjustment upon adoption of ASC 326	—		1		3		4
Recoveries collected	—		—		(1)		(1)
Balance, end of period	$	1	$	1	$	2	$	4
Corporate/Other
Balance, beginning of period	$	2	$	—	$	—	$	2
Adjustment upon adoption of ASC 326	—		—		1		1
Written off	(2)		—		—		(2)
Recoveries collected	—		—		(1)		(1)
Balance, end of period	$	—	$	—	$	—	$	—
Total	$	41	$	1	$	2	$	44

(a)An allowance for credit loss is assessed quarterly and is recorded based on historical default rates published by external credit rating agencies and a rate associated with the estimated time frame that the contract asset will be billed to the customer.

(b)Includes loan to affiliate, which is no longer outstanding at December 31, 2020, and other long-term receivables (Notes 12 and 29). An allowance for credit loss is assessed quarterly and is recorded based on historical default rates published by external credit rating agencies and a rate commensurate with the period in which the receivable is expected to be collected.

(c)Based on previous collection experience, AltaGas did not record an allowance for credit losses for its contract assets associated with its energy management services projects with the U.S. federal government.

(d)Includes $8 million recorded to a regulatory asset relating to the impact of COVID-19 on uncollectible accounts.

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, 2020	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Accounts payable and accrued liabilities	$	1,561	$	1,561	$	—	$	—	$	—
Dividends payable	22		22		—		—		—
Short-term debt	256		256		—		—		—
Other current liabilities (a)	37		37		—		—		—
Risk management contract liabilities	256		111		51		22		72
Current portion of long-term debt (b)	356		356		—		—		—
Long-term debt (b)	7,581		—		1,771		1,324		4,486
	$	10,069	$	2,343	$	1,822	$	1,346	$	4,558

(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, 2019	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Accounts payable and accrued liabilities	$	1,325	$	1,325	$	—	$	—	$	—
Dividends payable	22		22		—		—		—
Short-term debt	460		460		—		—		—
Other current liabilities (a)	15		15		—		—		—
Risk management contract liabilities	292		125		34		13		120
Current portion of long-term debt (b)	920		920		—		—		—
Long-term debt (b)	5,873		—		1,489		922		3,462
	$	8,907	$	2,867	$	1,523	$	935	$	3,582

(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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Revenue (Tables)

12 Months Ended

Dec. 31, 2020

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, 2020
	Utilities		Midstream		Corporate/Other		Total (a)
Revenue from contracts with customers
Commodity sales contracts	$	1,338	$	1,097	$	1	$	2,436
Midstream service contracts	—		277		—		277
Gas sales and transportation services	2,394		—		—		2,394
Storage services	25		—		—		25
Other	9		—		20		29
Total revenue from contracts with customers	$	3,766	$	1,374	$	21	$	5,161
Other sources of revenue
Revenue from alternative revenue programs (b)	$	96	$	—	$	—	$	96
Leasing revenue (c)	1		139		100		240
Risk management and trading activities (d) (e)	(31)		112		—		81
Other	(15)		10		14		9
Total revenue from other sources	$	51	$	261	$	114	$	426
Total revenue	$	3,817	$	1,635	$	135	$	5,587

(a)    In the first quarter of 2020, AltaGas revised its reportable segments. Comparative period numbers have been adjusted to reflect this change. Refer to Note 32 for additional information.

(b)    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.

(c)    Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Corporate/Other segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases.

(d)    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. A portion of revenue generated by the Utilities segment is from the physical sale and delivery of natural gas and power to end users.

(e)    Trading margins in the Midstream segment are reported in risk management and trading activities. AltaGas 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, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues for the year ended December 31, 2020 of $437 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract and an Asset Management Agreement (AMA), which are in scope of ASC 606, are reported within risk management and trading activities. Revenue from the GAIL contract 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 from the AMA is recognized based on the amount WGL Midstream has the right to invoice the customer in accordance with ASC 606. WGL executed the AMA in April 2020.

	Year Ended December 31, 2019
	Utilities		Midstream		Corporate/Other		Total (a)
Revenue from contracts with customers
Commodity sales contracts	$	1,428	$	746	$	51	$	2,225
Midstream service contracts	—		145		—		145
Gas sales and transportation services	2,501		—		—		2,501
Storage services	28		—		—		28
Other	9		3		29		41
Total revenue from contracts with customers	$	3,966	$	894	$	80	$	4,940
Other sources of revenue
Revenue from alternative revenue programs (b)	$	30	$	—	$	—	$	30
Leasing revenue (c)	1		137		105		243
Risk management and trading activities (d) (e)	52		188		22		262
Other	(5)		9		16		20
Total revenue from other sources	$	78	$	334	$	143	$	555
Total revenue	$	4,044	$	1,228	$	223	$	5,495

(a)In the first quarter of 2020, AltaGas revised its reportable segments. Comparative period numbers have been adjusted to reflect this change. Refer to Note 32 for additional information.

(b)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.

(c)Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Corporate/Other segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases.

(d)Risk management activities involve the use of derivative instruments such as physical and financial swaps, and forward contracts. These derivatives are accounted for under ASC 815 and ASC 825. A portion of revenue generated by the Utilities segment is from the physical sale and delivery of natural gas and power to end users.

(e)Trading margins in the Midstream segment are reported in risk management and trading activities. AltaGas 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, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues for the year ended December 31, 2019 of $505 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract and an Asset Management Agreement (AMA), which are in scope of ASC 606, are reported within risk management and trading activities. Revenue from the GAIL contract 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 from the AMA is recognized based on the amount WGL Midstream has the right to invoice the customer in accordance with ASC 606. WGL executed the AMA in April 2020.

Contract with Customer, Asset and Liability

Contract Assets

As at	December 31, 2020		December 31, 2019
Balance, beginning of year	$	89	$	59
Additions	30		32
Transfers to accounts receivable	(49)		—
Foreign exchange translation	1		(2)
Balance, end of year	$	71	$	89

Contract Liabilities

As at	December 31, 2020		December 31, 2019
Balance, beginning of year	$	2	$	2
Additions	2		2
Revenue recognized from contract liabilities (a)	(4)		(2)
Balance, end of year	$	—	$	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, 2020:

	2021		2022		2023		2024		2025		2026 & beyond		Total
Midstream service contracts	$	125	$	131	$	128	$	128	$	125	$	1,037	$	1,674
Storage services	24		23		23		23		23		142		258
Other	7		2		2		2		2		9		24
	$	156	$	156	$	153	$	153	$	150	$	1,188	$	1,956

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Shareholders’ Equity (Tables)

12 Months Ended

Dec. 31, 2020

Stockholders' Equity Note [Abstract]

Schedule of Common Shares Issued and Outstanding

Common Shares Issued and Outstanding	Number of  shares	Amount
January 1, 2019	275,224,066	$	6,654
Shares issued for cash on exercise of options	76,177	1
Deferred taxes on share issuance cost	—	(4)
Shares issued under DRIP	3,774,442	68
December 31, 2019	279,074,685	$	6,719
Shares issued for cash on exercise of options	88,082	1
Deferred taxes on share issuance cost	—	(3)
Shares issued under DRIP	331,532	6
Issued and outstanding at December 31, 2020	279,494,299	$	6,723

Schedule of Preferred Shares Issued and Outstanding

As at	December 31, 2020			December 31, 2019
Issued and Outstanding	Number of shares	Amount		Number of shares	Amount
Series A	6,746,679	$	169	5,511,220	$	138
Series B	1,253,321	31		2,488,780	62
Series C	8,000,000	206		8,000,000	206
Series E	8,000,000	200		8,000,000	200
Series G	6,885,823	172		6,885,823	172
Series H	1,114,177	28		1,114,177	28
Series I	—	—		8,000,000	200
Series K	12,000,000	300		12,000,000	300
Share issuance costs, net of taxes		(29)			(29)
	44,000,000	$	1,077	52,000,000	$	1,277

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)	3.060	%	$0.76500	$25	September 30, 2025	Series B
Series B (f) (g)	Floating		Floating	$25	September 30, 2025	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)	4.240	%	$1.06050	$25	September 30, 2024	Series H
Series H (f) (g)	Floating		Floating	$25	September 30, 2024	Series G
Series K (i)	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 to 8,000,000 of each of Series D Shares, Series F Shares, and up to 12,000,000 of Series L Shares, subject to certain conditions, upon conversion by the holders of the applicable currently issued and outstanding series of preferred shares noted opposite such series in the table on the applicable conversion option date. If issued upon the conversion of the applicable series of preferred shares, Series F Shares, and Series L Shares are also redeemable for $25.50, and Series D Shares are redeemable for US$25.50 on any date after the applicable conversion option date, plus all accrued but unpaid dividends to, but excluding, the date fixed for redemption.

(b)The holders of Series A Shares, Series C Shares, Series E Shares, Series G Shares, Series H 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, 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 plus 2.66 percent (Series A Shares), 3.17 percent (Series E Shares), and 3.06 percent (Series G Shares).

(f)Holders of Series B Shares 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 plus 2.66 percent (Series B Shares) and 3.06 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, 2020, the floating quarterly dividend rate is $0.17069 per share for Series B Shares and $0.195349 per share for Series H Shares for the period starting December 31, 2020 to, but excluding, March 31, 2021.

(g)Series B Shares can be redeemed for $25.50 per share on any date after September 30, 2015 that is not a Series B conversion date, plus all accrued and unpaid dividends to, but excluding, the date fixed for redemption. Series H Shares can be redeemed for $25.50 per 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 plus 3.58 percent.

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

Summary of Share Option Activity

The following table summarizes information about the Corporation’s share options:

	December 31, 2020			December 31, 2019
As at	Options outstanding			Options outstanding
	Number of options	Exercise price (a)		Number of options	Exercise price (a)
Share options outstanding, beginning of year	7,043,956	$	22.49	6,309,183	$	25.18
Granted	2,501,755	19.46		2,287,385	19.12
Exercised	(88,082)	14.89		(76,177)	14.52
Forfeited	(631,549)	26.00		(1,165,435)	27.31
Expired	(463,869)	27.69		(311,000)	36.16
Share options outstanding, end of year	8,362,211	$	21.06	7,043,956	$	22.49
Share options exercisable, end of year	3,607,391	$	23.59	2,921,642	$	27.70

(a)Weighted average.

Summary of Employee Share Option Plan

The following table summarizes the employee share option plan as at December 31, 2020:

	Options outstanding				Options exercisable
	Number outstanding	Weighted average exercise price		Weighted average remaining contractual life (years)	Number exercisable	Weighted average exercise price		Weighted average remaining contractual life (years)
$14.52 to $18.00	2,446,392	$	15.24	4.07	1,359,457	$	14.92	4.00
$18.01 to $25.08	3,930,345	19.56		4.80	528,252	19.54		4.47
$25.09 to $41.00	1,985,474	31.21		1.82	1,719,682	31.68		1.64
	8,362,211	$	21.06	3.88	3,607,391	$	23.59	2.95

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	2020	2019
Fair value per options ($)	2.61	2.30
Risk-free interest rate (%)	1.54	1.48
Expected life (years)	6	6
Expected volatility (%)	25.40	24.84
Annual dividend per share ($) (a)	0.96	0.96
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)	2020	2019
Balance, beginning of year	6,484,831	9,908,154
Granted	1,158,547	674,971
Vested and paid out	(681,841)	(791,335)
Forfeited	(1,342,832)	(3,377,962)
Units in lieu of dividends	113,429	71,003
Outstanding, end of year	5,732,134	6,484,831

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Net Income Per Common Share (Tables)

12 Months Ended

Dec. 31, 2020

Earnings Per Share [Abstract]

Summary of Net Income per Common Share

The following table summarizes the computation of net income per common share:

	Year Ended December 31
	2020		2019
Numerator:
Net income applicable to controlling interests	$	552	$	833
Less: Preferred share dividends	(66)		(68)
Gain on redemption of preferred shares (note 25)	—		4
Net income applicable to common shares	$	486	$	769
Denominator:
(millions of shares)
Weighted average number of common shares outstanding	279.4		276.9
Dilutive equity instruments (a)	0.3		0.5
Weighted average number of common shares outstanding - diluted	279.7		277.4
Basic net income per common share	$	1.74	$	2.78
Diluted net income per common share	$	1.74	$	2.77

(a)Determined using the treasury stock method.

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Other Income (Tables)

12 Months Ended

Dec. 31, 2020

Other Income and Expenses [Abstract]

Schedule of Other Income

Year Ended December 31	2020		2019
Gains on asset sales (note 4)	$	223	$	876
Gain on remeasurement of previously held interest in AIJVLP (note 3)	22		—
Other components of net benefit cost (note 28)	52		27
Interest income and other revenue	9		9
Losses on investments	—		(4)
Total	$	306	$	908

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Pension Plans and Retiree Benefits (Tables)

12 Months Ended

Dec. 31, 2020

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, 2020	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	$	36	$	2	$	1,725	$	428	$	1,761	$	430
Actuarial loss	1		—		137		32		138		32
Current service cost	3		—		27		9		30		9
Member contributions	—		—		—		2		—		2
Interest cost	1		—		60		15		61		15
Benefits paid	(4)		—		(82)		(24)		(86)		(24)
Expenses paid	—		—		(1)		—		(1)		—
Settlements	—		—		(25)		—		(25)		—
Foreign exchange translation	—		—		(41)		(10)		(41)		(10)
Balance, end of year	$	37	$	2	$	1,800	$	452	$	1,837	$	454
Plan assets
Fair value, beginning of year	$	15	$	—	$	1,504	$	906	$	1,519	$	906
Actual return on plan assets	1		—		275		157		276		157
Employer contributions	4		—		37		—		41		—
Member contributions	—		—		—		2		—		2
Benefits paid	(4)		—		(82)		(24)		(86)		(24)
Expenses paid	—		—		(1)		—		(1)		—
Settlements	—		—		(25)		—		(25)		—
Foreign exchange translation	—		—		(41)		(25)		(41)		(25)
Fair value, end of year	$	16	$	—	$	1,667	$	1,016	$	1,683	$	1,016
Funded status	$	(21)	$	(2)	$	(133)	$	564	$	(154)	$	562

(a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation.

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	$	2	$	1,635	$	458	$	1,669	$	460
Actuarial loss (gain)	2		—		182		(15)		184		(15)
Current service cost	3		—		24		9		27		9
Member contributions	—		—		—		2		—		2
Interest cost	1		—		68		19		69		19
Benefits paid	(4)		—		(77)		(24)		(81)		(24)
Expenses paid	—		—		(1)		—		(1)		—
Settlements	—		—		(24)		—		(24)		—
Other	—		—		—		1		—		1
Foreign exchange translation	—		—		(82)		(22)		(82)		(22)
Balance, end of year	$	36	$	2	$	1,725	$	428	$	1,761	$	430
Plan assets
Fair value, beginning of year	$	14	$	—	$	1,354	$	791	$	1,368	$	791
Actual return on plan assets	1		—		284		177		285		177
Employer contributions	4		—		39		—		43		—
Member contributions	—		—		—		2		—		2
Benefits paid	(4)		—		(77)		(23)		(81)		(23)
Expenses paid	—		—		(1)		—		(1)		—
Settlements	—		—		(25)		—		(25)		—
Foreign exchange translation	—		—		(70)		(41)		(70)		(41)
Fair value, end of year	$	15	$	—	$	1,504	$	906	$	1,519	$	906
Funded status	$	(21)	$	(2)	$	(221)	$	478	$	(242)	$	476

(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, 2020						December 31, 2019
	Defined Benefit		Post- Retirement Benefits		Total		Defined Benefit		Post-Retirement Benefits		Total (a)
Prepaid post-retirement benefits	$	—	$	572	$	572	$	—	$	487	$	487
Accounts payable and accrued liabilities (a)	(9)		—		(9)		(26)		—		(26)
Future employee obligations	(145)		(10)		(155)		(216)		(11)		(227)
	$	(154)	$	562	$	408	$	(242)	$	476	$	234

(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, 2020				December 31, 2019
	Canada		United States		Canada		United States
Accumulated benefit obligation (a)	$	36	$	1,704	$	35	$	1,616

(a)Accumulated benefit obligation differs from projected benefit obligation in that it does not include an assumption with respect to future compensation levels.

Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets

For those pension plans where the projected benefit obligation exceeded the fair value of plan assets as at December 31, 2020, the cumulative obligation and asset balances were:

As at	December 31, 2020				December 31, 2019
	Defined Benefit		Post-Retirement Benefits		Defined Benefit		Post-Retirement Benefits
Projected benefit obligation	$	1,824	$	14	$	1,757	$	13
Plan assets	$	1,670	$	3	$	1,515	$	3

For those pension plans where the accumulated benefit obligation exceeded the fair value of plan assets as at December 31, 2020, the cumulative obligation and asset balances were:

As at	December 31, 2020				December 31, 2019
	Defined Benefit		Post-Retirement Benefits		Defined Benefit		Post-Retirement Benefits
Accumulated benefit obligation	$	427	$	14	$	1,648	$	13
Plan assets	$	329	$	3	$	1,515	$	3

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, 2020	Canada				United States				Total
	Defined Benefit		Post- Retirement Benefits		Defined Benefit		Post-Retirement Benefits		Defined Benefit		Post-Retirement Benefits
Past service cost	$	—	$	—	$	—	$	(3)	$	—	$	(3)
Net actuarial gain (loss)	(9)		(1)		6		(8)		(3)		(9)
Recognized in AOCI pre-tax	$	(9)	$	(1)	$	6	$	(11)	$	(3)	$	(12)
Increase (decrease) by the amount included in deferred tax liabilities	2		—		(2)		3		—		3
Net amount in AOCI after-tax	$	(7)	$	(1)	$	4	$	(8)	$	(3)	$	(9)

Year Ended December 31, 2019	Canada				United States				Total
	Defined Benefit		Post- Retirement Benefits		Defined Benefit		Post- Retirement Benefits		Defined Benefit		Post- Retirement Benefits
Net actuarial gain (loss)	$	(9)	$	—	$	(15)	$	18	$	(24)	$	18
Recognized in AOCI pre-tax	$	(9)	$	—	$	(15)	$	18	$	(24)	$	18
Increase (decrease) by the amount included in deferred tax liabilities	2		—		7		(9)		9		(9)
Net amount in AOCI after-tax	$	(7)	$	—	$	(8)	$	9	$	(15)	$	9

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, 2020	Canada				United States				Total
	Defined Benefit		Post- Retirement Benefits		Defined Benefit		Post- Retirement Benefits		Defined Benefit		Post- Retirement Benefits
Past service credit	$	—	$	—	$	—	$	(94)	$	—	$	(94)
Net actuarial loss (gain)	—		—		68		(241)		68		(241)
Recognized in regulatory asset (liability)	$	—	$	—	$	68	$	(335)	$	68	$	(335)

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	$	(105)	$	1	$	(105)
Net actuarial loss (gain)	—		—		127		(156)		127		(156)
Recognized in regulatory asset (liability)	$	—	$	—	$	128	$	(261)	$	128	$	(261)

Schedule of Net Periodic Benefit Expense

The net pension expense by plan was as follows:

	Year Ended December 31, 2020
	Canada				United States				Total
	Defined Benefit		Post-Retirement Benefits		Defined Benefit		Post-Retirement Benefits		Defined Benefit		Post-Retirement Benefits
Current service cost (a)	$	3	$	—	$	27	$	9	$	30	$	9
Interest cost (b)	1		—		60		15		61		15
Expected return on plan assets (b) (c)	(1)		—		(81)		(40)		(82)		(40)
Amortization of past service credit (b)	—		—		—		(19)		—		(19)
Amortization of net actuarial loss (gain) (b) (c)	1		—		10		(5)		11		(5)
Plan settlements (b)	—		—		7		—		7		—
Net benefit cost (income) recognized	$	4	$	—	$	23	$	(40)	$	27	$	(40)

(a)Recorded under the line item “operating and administrative” expenses on the Consolidated Statements of Income.

(b)Recorded under the line item “other income” on the Consolidated Statements of Income.

(c)Includes the impact of the voluntary change in accounting principle implemented in 2020. Refer to Note 2 for additional information.

	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)	$	3	$	—	$	24	$	9	$	27	$	9
Interest cost (b)	1		—		68		19		69		19
Expected return on plan assets (b)	(1)		—		(75)		(37)		(76)		(37)
Amortization of past service credit (b)	—		—		—		(22)		—		(22)
Amortization of net actuarial loss (b)	1		—		12		—		13		—
Plan settlements (b)	—		—		4		—		4		—
Other (b)	—		—		—		1		—		1
Net benefit cost (income) recognized	$	4	$	—	$	33	$	(30)	$	37	$	(30)

(a)Recorded under the line item “operating and administrative” expenses on the Consolidated Statements of Income.

(b)Recorded under the line item “other income” on the Consolidated Statements of Income.

Schedule of Collective Investment Mixes for Plan Assets

The collective investment mixes for the plans are as follows as at December 31, 2020:

Canada	Fair value		Level 1		Level 2		Percentage of Plan Assets (%)
Cash and short-term equivalents	$	2	$	2	$	—	13
Canadian equities	3		3		—		19
Foreign equities	4		4		—		25
Fixed income	6		6		—		38
Real estate	1		—		1		5
	$	16	$	15	$	1	100

United States	Fair value		Level 1		Level 2		Percentage of Plan Assets (%)
Cash and short-term equivalents	$	14	$	14	$	—	1
Canadian equities	1		1		—		—
Foreign equities (a)	357		357		—		13
Fixed income	1,002		129		873		37
Other (b)	23		—		23		1
Total investments in the fair value hierarchy	$	1,397	$	501	$	896	52
Investments measured at net asset value using the NAV practical expedient (c)
Commingled funds (d)	$	728					27
Private equity/limited partnership (e)	56						2
Pooled separate accounts (f)	32						1
Collective trust fund (g)	476						18
Total fair value of plan investments	$	2,689					100
Net payable (h)	(6)						—
	$	2,683					100

(a)Investments in foreign equities include U.S. and international securities.

(b)As at December 31, 2020, 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, 2020, investments in commingled funds consisted of approximately 50 percent common stock of large-cap U.S. companies, 20 percent U.S. Government fixed income securities, and 30 percent corporate bonds for WGL’s post-retirement benefit plans.

(e)As at December 31, 2020, investments in a private equity/limited partnership consisted of common stock of international companies.

(f)As at December 31, 2020, investments in pooled separate accounts consisted of income producing properties located in the United States.

(g)As at December 31, 2020, investments in collective trust funds consisted primarily of 90 percent common stock of U.S, companies, 7 percent income producing properties located in the United States, and 3 percent short-term money market investments.

(h)As at December 31, 2020, 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	$	16	$	16	$	—	1
Canadian equities	4		4		—		—
Foreign equities (a)	361		361		—		13
Fixed income	1,008		135		873		37
Real estate	1		—		1		—
Other (b)	23		—		23		1
Total investments in the fair value hierarchy	$	1,413	$	516	$	897	52
Investments measured at net asset value using the NAV practical expedient (c)
Commingled funds(d)	$	728					27
Private equity/limited partnership (e)	56						2
Pooled separate accounts (f)	32						1
Collective trust fund (g)	476						18
Total fair value of plan investments	$	2,705					100
Net payable (h)	(6)						—
	$	2,699					100

(a)Investments in foreign equities include U.S. and international securities.

(b)As at December 31, 2020, 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, 2020, investments in commingled funds consisted of approximately 50 percent common stock of large-cap U.S. companies, 20 percent U.S. Government fixed income securities, and 30 percent corporate bonds for WGL’s post-retirement benefit plans.

(e)As at December 31, 2020, investments in a private equity/limited partnership consisted of common stock of international companies.

(f)As at December 31, 2020, investments in pooled separate accounts consisted of income producing properties located in the United States.

(g)As at December 31, 2020, investments in collective trust funds consisted primarily of 90 percent common stock of U.S, companies, 7 percent income producing properties located in the United States, and 3 percent short-term money market investments.

(h)As at December 31, 2020, this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable.

Schedule of Significant Actuarial Assumptions Used in Measuring Net Benefit Plan Costs and Benefit Obligations

Year Ended December 31	2020		2019
Significant actuarial assumptions used in measuring net benefit plan costs	Defined Benefit	Post-Retirement Benefits	Defined Benefit	Post-Retirement Benefits
Discount rate (%)	2.30 - 3.50	3.10 - 3.60	2.90 - 4.40	3.90 - 4.50
Expected long-term rate of return on plan assets (%) (a)	5.25 - 7.05	4.03 - 7.05	5.75 - 7.15	4.66 - 7.15
Rate of compensation increase (%)	2.75 - 4.00	3.50	2.75 - 4.10	4.10
Average remaining service life of active employees (years)	10.2	13.0	9.0	13.2

(a)Only applicable for funded plans

As at December 31	2020		2019
Significant actuarial assumptions used in measuring benefit obligations	Defined Benefit	Post-Retirement Benefits	Defined Benefit	Post-Retirement Benefits
Discount rate (%)	1.90 - 2.80	2.50 - 2.90	2.90 - 3.50	3.10 - 3.60
Rate of compensation increase (%)	1.73 - 3.93	2.50 - 3.00	2.75 - 4.00	3.50

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:
2021	$	16	$	—
Expected benefit payments:
2021	$	90	$	25
2022	$	91	$	22
2023	$	88	$	22
2024	$	89	$	21
2025	$	90	$	21
2026 - 2030	$	466	$	110

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Commitments, Guarantees, and Contingencies (Tables)

12 Months Ended

Dec. 31, 2020

Commitments and Contingencies Disclosure [Abstract]

Summary of Future Payment Commitments

Future payments of these commitments as at December 31, 2020 are estimated as follows:

	2021		2022		2023		2024		2025		2026 & beyond		Total
Gas purchase (a)	$	1,974	$	2,075	$	1,858	$	1,863	$	1,901	$	17,612	$	27,283
LPG purchase (b)	407		199		161		108		83		258		1,216
Crude oil and condensate purchase (c)	184		—		—		—		—		—		184
Electricity purchase (d)	463		287		106		29		3		—		888
Service agreements (e) (f) (g)	48		32		26		27		27		282		442
Pipeline and storage services (h)	661		637		621		564		528		3,134		6,145
Capital projects (i)	20		1		1		1		1		1		25
Operating leases (j)	96		81		58		50		40		125		450
Environmental (k)	7		3		1		1		1		—		13
Merger commitments (l)	5		2		2		2		1		3		15
Land purchase commitment (m)	20		—		—		—		—		—		20
Post-acquisition contingent payments (n)	—		16		—		—		—		—		16
	$	3,885	$	3,333	$	2,834	$	2,645	$	2,585	$	21,415	$	36,697

(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 fixed prices and forward prices, which may fluctuate significantly from period to period.

(b)AltaGas enters into contracts to purchase LPGs for its operations at RIPET and Ferndale. These contracts are used to ensure that there is an adequate supply of LPGs to meet shipment commitments and to minimize exposure to market price fluctuations. LPG purchase commitments are valued based on forward prices, which may fluctuate significantly from period to period.

(c)As part of the Petrogas Acquisition (Note 3), AltaGas acquired contracts to purchase crude oil and condensates for marketing, sale, and distribution. These contracts are used to ensure that there is an adequate supply of crude oil and condensates to meet the needs of customers and to minimize exposure to market price fluctuations. Crude oil and condensate commitments are valued based on forward prices, which may fluctuate significantly from period to period.

(d)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$21 million of commitments related to renewable energy credits.

(e)In 2014, AltaGas' Blythe facility entered into a Long-Term Service Agreement (LTSA) with a service pro 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, 2020, the total commitment was $153 million payable over the next 15 years, of which $44 million is expected to be paid over the next 5 years.

(f)In 2017, AltaGas entered into a 12-year service agreement commencing in 2019 for tug services to support the marine operations of RIPET.

(g)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.

(h)Pipeline and storage commitments include minimum payments for natural gas transportation, storage and peaking contracts that have expiration dates through 2044.

(i)Commitments for capital projects. Estimated amounts are subject to variability depending on the actual construction costs.

(j)Operating leases include lease arrangements for office space, office equipment, field equipment, rail cars, aquatic use, vehicles, power and gas facilities, transmission and distribution assets, and land.

(k)Environmental commitments include committed payments related to certain environmental response costs.

(l)Represents the estimated future payments of WGL merger commitments that have been accrued but not paid. In addition, there are certain additional merger commitments that were and will be expensed as the costs are incurred, including the investment of up to US$70 million over a ten year period to further extend natural gas service, investment of US$8 million for leak mitigation within three years, which has been paid as of December 31, 2020, hiring damage prevention trainers in each jurisdiction for a total of US$2 million over five years, and developing 15 megawatts of either electric grid energy storage or Tier 1 renewable resources within five years after the merger closed. As at December 31, 2020, the cumulative amount of merger commitments that have been expensed but not yet paid is approximately US$12 million.

(m)As part of the Petrogas Acquisition (Note 3), AltaGas acquired a commitment to purchase land as part of an agreement for it's continued use of the Ferndale terminal.

(n)Contingent payments of up to $16 million are expected to be paid related to the Petrogas Acquisition (Note 3).

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2020

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, 2020		December 31, 2019
Due from related parties
Accounts receivable (a)	$	5	$	18
Long-term investments and other assets (b)	—		45
	$	5	$	63
Due to related parties
Accounts payable (c)	$	3	$	3

(a)Receivables from joint ventures and from a former affiliate of Petrogas.

(b)For the period prior to December 15, 2020, AltaGas provided a $100 million interest bearing secured loan facility to Petrogas of which $50 million was committed. The facility was available for Petrogas to draw upon from time to time for general corporate purposes until the close of the Petrogas Acquisition on December 15, 2020. 

(c)Payables to a joint venture and a former affiliate of Petrogas.

Schedule of Related Party Transactions

The following transactions with related parties have been recorded on the Consolidated Statements of Income for the years ended December 31, 2020 and 2019:

Year Ended December 31	2020		2019
Revenue (a)	$	92	$	115
Cost of sales (b)	$	12	$	13
Operating and administrative expenses (recoveries) (c)	$	1	$	(2)
Other income (d)	$	3	$	3

(a)In the ordinary course of business, AltaGas sold commodities to TriSummit Utilities Inc. and Petrogas.

(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)Subsequent to the close of the Petrogas Acquisition, certain operating and administrative expenses were paid on behalf of Petrogas by a former affiliate. In 2019, administrative cost recoveries included those from joint ventures and from TriSummit Utilities Inc. under a Transition Services Agreement.

(d)Interest income from loans to Petrogas (secured loan facility) prior to the acquisition of Petrogas.

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2020

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
	2020		2019
Source (use) of cash:
Accounts receivable	$	21	$	168
Inventory	32		(2)
Other current assets	1		(85)
Regulatory assets - current	(33)		7
Accounts payable and accrued liabilities	(41)		(280)
Customer deposits	(2)		(17)
Regulatory liabilities - current	(55)		34
Risk management liabilities - current	(1)		1
Other current liabilities	4		(6)
Other operating assets and liabilities	(129)		(52)
Changes in operating assets and liabilities	$	(203)	$	(232)

Schedule of Supplemental Cash Payments

The following table details the changes in non-cash investing and financing activities:

	Year Ended December 31
	2020		2019
(Increase) of balance:
Common shares issued under DRIP	$	(6)	$	(68)
Net right-of-use assets obtained in exchange for new operating lease liabilities	$	227	$	50
Net right-of-use assets obtained in exchange for new finance lease liabilities	$	6	$	5
Capital expenditures included in accounts payable and accrued liabilities	$	(33)	$	(7)

The following cash payments have been included in the determination of earnings:

	Year Ended December 31
	2020		2019
Interest paid (net of capitalized interest)	$	276	$	352
Income taxes paid	$	23	$	67

Reconciliation of Cash and Restricted Cash Balances

The following table is a reconciliation of cash and restricted cash balances:

As at December 31	2020		2019
Cash and cash equivalents	$	32	$	57
Restricted cash holdings from customers - current	3		4
Restricted cash holdings from customers - non-current	2		4
Restricted cash included in prepaid expenses and other current assets (a)	9		25
Restricted cash included in long-term investments and other assets (note 12) (a)	19		32
Restricted cash included in accounts receivable (note 29)	9		—
Cash, cash equivalents, and restricted cash per Consolidated Statements of Cash Flows	$	74	$	122

(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 (see Note 28).

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Segmented Information (Tables)

12 Months Ended

Dec. 31, 2020

Segment Reporting [Abstract]

Schedule of Description of Reporting Segments

The following describes the Corporation’s reporting segments:

Utilities	n rate-regulated natural gas distribution assets in Michigan, Alaska, the District of Columbia,     Maryland, and Virginia; n rate-regulated natural gas storage in the United States; and n sale of natural gas to residential, commercial and industrial customers in Washington D.C.,     Maryland, Virginia, Delaware, Pennsylvania and Ohio.
Midstream	n NGL processing and extraction plants; n natural gas storage facilities; n liquefied petroleum gas (LPG) terminals; n transmission pipelines to transport natural gas and NGL; n natural gas gathering lines and field processing facilities; n purchase and sale of natural gas; n natural gas and NGL marketing; n marketing, storage and distribution of wellsite fluids and fuels, crude oil and condensate diluents; and n interest in a regulated pipeline in the Marcellus/Utica gas formation;
Corporate/Other	n the cost of providing corporate services, financing and general corporate overhead,     investments in certain public and private entities, corporate assets, financing other segments and     the effects of changes in the fair value of certain risk management contracts; and n a small portfolio of remaining power assets, certain of which are pending sale.

Reconciliation Of Segment Revenue

The following table provides a reconciliation of segment revenue to the disaggregated revenue table disclosed in Note 24:

	Year Ended December 31, 2020
	Utilities		Midstream		Corporate/Other		Total
External revenue (note 24)	$	3,817	$	1,635	$	135	$	5,587
Intersegment revenue	—		1		—		1
Segment revenue	$	3,817	$	1,636	$	135	$	5,588

	Year Ended December 31, 2019
	Utilities		Midstream		Corporate/Other		Total
External revenue (note 24)	$	4,044	$	1,228	$	223	$	5,495
Intersegment revenue	—		32		—		32
Segment revenue	$	4,044	$	1,260	$	223	$	5,527

Schedule of Geographic Information

Geographic Information

Year Ended December 31	2020		2019
Revenue (a)
Canada	$	1,512	$	1,245
United States	4,053		4,325
TOTAL	$	5,565	$	5,570

(a)Operating revenue from external customers, excluding unrealized gains or losses on risk management contracts.

As at December 31	2020		2019
Property, plant and equipment
Canada	$	3,149	$	2,682
United States	7,739		7,443
TOTAL	$	10,888	$	10,125
Operating right-of-use assets
Canada	$	293	$	85
United States	79		85
TOTAL	$	372	$	170

Schedule of Segment Composition

The following tables show the composition by segment:

	Year Ended December 31, 2020
	Utilities		Midstream		Corporate/Other		Intersegment Elimination (a)		Total
Segment revenue (note 24)	$	3,817	$	1,636	$	135	$	(1)	$	5,587
Cost of sales	(2,156)		(994)		(29)		1		(3,178)
Operating and administrative	(942)		(254)		(71)		—		(1,267)
Accretion expenses	—		(4)		(1)		—		(5)
Depreciation and amortization	(295)		(86)		(33)		—		(414)
Provisions on assets (note 6)	(1)		(105)		(3)		—		(109)
Income from equity investments	5		44		—		—		49
Other income	259		24		23		—		306
Foreign exchange gains (losses)	—		(26)		30		—		4
Interest expense	—		—		(274)		—		(274)
Income (loss) before income taxes	$	687	$	235	$	(223)	$	—	$	699
Net additions (reductions) to:
Property, plant and equipment(b)	$	740	$	136	$	(51)	$	—	$	825
Intangible assets	$	3	$	3	$	4	$	—	$	10

(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, 2019
	Utilities		Midstream		Corporate/Other		Intersegment Elimination (a)		Total
Segment revenue (note 24)	$	4,044	$	1,260	$	223	$	(32)	$	5,495
Cost of sales	(2,448)		(760)		(51)		32		(3,227)
Operating and administrative	(960)		(213)		(126)		—		(1,299)
Accretion expenses	—		(4)		(1)		—		(5)
Depreciation and amortization	(276)		(89)		(73)		—		(438)
Provision on assets (note 6)	—		(34)		(382)		—		(416)
Income from equity investments	19		122		—		—		141
Other income	29		28		851		—		908
Foreign exchange gains (losses)	—		(5)		4		—		(1)
Interest expense	—		—		(346)		—		(346)
Income before income taxes	$	408	$	305	$	99	$	—	$	812
Net additions (reductions) to:
Property, plant and equipment (b)	$	840	$	351	$	(2,280)	$	—	$	(1,089)
Intangible assets	$	23	$	5	$	9	$	—	$	37

(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		Corporate/Other		Total
As at December 31, 2020
Goodwill	$	3,706	$	1,333	$	—	$	5,039
Segmented assets	$	13,675	$	7,320	$	537	$	21,532
As at December 31, 2019
Goodwill	$	3,781	$	161	$	—	$	3,942
Segmented assets	$	13,719	$	5,265	$	811	$	19,795

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Organization and Overview of the Business (Details) customer in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2020 USD ($) customer segment
Organization And Overview Of Business [Line Items]
Number of segments | segment	2
Utilities
Organization And Overview Of Business [Line Items]
Number of customers	1.7
Utilities customers, base rate | $	$ 4.3
Utilities | Storage services
Organization And Overview Of Business [Line Items]
Number of customers	0.5
Midstream | Ridley Island Propane Terminal
Organization And Overview Of Business [Line Items]
Equity method investment, ownership interest (percent)	70.00%
Midstream | Ferndale Terminal
Organization And Overview Of Business [Line Items]
Equity method investment, ownership interest (percent)	74.00%
Midstream | Petrogas Preferred Shares
Organization And Overview Of Business [Line Items]
Equity method investment, ownership interest (percent)	74.00%

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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, 2020
Minimum | Corporate
Property, Plant and Equipment
Useful life	3 years
Minimum | Utilities
Property, Plant and Equipment
Useful life	4 years
Minimum | Midstream
Property, Plant and Equipment
Useful life	3 years
Maximum | Corporate
Property, Plant and Equipment
Useful life	46 years
Maximum | Utilities
Property, Plant and Equipment
Useful life	69 years
Maximum | Midstream
Property, Plant and Equipment
Useful life	55 years

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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, 2020
Energy services relationships
Finite-Lived Intangible Assets
Intangible asset, useful life	5 years
Software | Minimum
Finite-Lived Intangible Assets
Intangible asset, useful life	3 years
Software | Maximum
Finite-Lived Intangible Assets
Intangible asset, useful life	20 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	43 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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Summary of Significant Accounting Policies - Share Options and Other Compensation Plans (Details)	12 Months Ended
	Dec. 31, 2020 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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Summary of Significant Accounting Policies - Pension Plan and Post Retirement Benefits (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 CAD ($)	Dec. 31, 2020 $ / shares	Dec. 31, 2019 CAD ($)
Defined Benefit Plan Disclosure
Income before income taxes - consolidated	$ 699		$ 812
Net income applicable to common shares	486		769
Deferred income tax expense (recovery) (note 20)	126		$ (91)
Revision of Prior Period, Change in Accounting Principle, Adjustment
Defined Benefit Plan Disclosure
Income before income taxes - consolidated	25
Net income applicable to common shares	19
Earnings per share basic and diluted (in dollars per share) | $ / shares		$ 0.07
Deferred income tax expense (recovery) (note 20)	$ 6
Defined Benefit
Defined Benefit Plan Disclosure
Average remaining service life of active employees	10 years 2 months 12 days		9 years
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Average remaining service life of active employees	13 years		13 years 2 months 12 days

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Summary of Significant Accounting Policies - Collaborative Agreements (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Income (loss) from collaborative agreements	$ 21	$ 1

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Summary of Significant Accounting Policies - Effects of Adoption of New Accounting Principles (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Jan. 01, 2020	Dec. 31, 2019
New Accounting Pronouncements or Change in Accounting Principle\
Long-term investments and other assets (net of credit losses of $3 million) (notes 12, 28, and 31)	$ (245)		$ (297)
ASU 2016-13 | Cumulative Effect, Period of Adoption, Adjustment
New Accounting Pronouncements or Change in Accounting Principle\
Accounts receivable, net		$ 2
Long-term investments and other assets (net of credit losses of $3 million) (notes 12, 28, and 31)		$ 5

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Acquisition of Petrogas Energy Corporation - Narrative (Details) - CAD ($) $ in Millions		1 Months Ended	12 Months Ended
	Dec. 15, 2020	Dec. 30, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Business Acquisition
Gain on re-measurement of previously held interest			$ 22	$ 0
Goodwill			5,039	3,942	$ 4,068
Petrogas Energy Corporation
Business Acquisition
Additional ownership interest acquired (as a percent)	37.00%
Purchase consideration for an additional 37 percent of Petrogas	$ 715
Consulting fees	$ 16
Total ownership interest in acquiree (as a percent)	74.00%
Previous ownership percentage	37.00%
Acquisition date fair value	$ 631
Gain on re-measurement of previously held interest	22
Fair value of AIJVLP's non-controlling interest in Petrogas on the acquisition date	467
Inventory acquired			164
Goodwill	$ 1,171
Pre-tax acquisition expenses			(6)
Revenues since acquisition		$ 143
Net income after taxes since acquisition		$ 3
Petrogas Energy Corporation | Petrogas Terminals Penn LLC
Business Acquisition
Noncontrolling ownership interest (percent)	50.00%
Petrogas Energy Corporation | Strathcona Storage LP
Business Acquisition
Noncontrolling ownership interest (percent)	40.00%
Petrogas Energy Corporation | Acquisition-related Costs
Business Acquisition
Total after-tax pro forma adjustments, decrease to net income			$ (31)	$ (75)

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Acquisition of Petrogas Energy Corporation - Schedule of Final Purchase Price Allocation (Details) - CAD ($) $ in Millions		12 Months Ended
	Dec. 15, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Business Acquisition
Gain on re-measurement of previously held interest		$ 22	$ 0
Less: Fair value assigned to net assets
Goodwill		$ 5,039	$ 3,942	$ 4,068
Petrogas Energy Corporation
Business Acquisition
Acquisition date fair value	$ 631
Less: Carrying value of previously held interest in AIJVLP	(609)
Gain on re-measurement of previously held interest	22
Purchase consideration for an additional 37 percent of Petrogas	715
Deemed settlement of intercompany debt	120
Less: Fair value assigned to net assets
Current assets	536
Property, plant and equipment	523
Intangible assets	10
Operating right-of-use assets	192
Long-term investments and other assets	4
Investments accounted for by the equity method	125
Current liabilities	(363)
Long-term debt	(53)
Asset retirement obligations	(13)
Deferred income taxes	(21)
Operating lease liabilities	(152)
Other long-term liabilities	(26)
Fair value of net assets acquired	762
Fair value of AIJVLP's non-controlling interest in Petrogas on the acquisition date	467
Goodwill	$ 1,171
Previous ownership percentage	37.00%

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Acquisition of Petrogas Energy Corporation - Pro Forma Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Business Combinations [Abstract]
Pro forma revenue	$ 7,917	$ 9,217
Pro forma net income (loss) after taxes	$ 537	$ 1,004

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Dispositions (Details) shares in Thousands, $ in Millions		3 Months Ended		12 Months Ended
	Mar. 31, 2020 CAD ($)	Sep. 30, 2020 CAD ($)	Jun. 30, 2020 CAD ($)	Dec. 31, 2020 CAD ($)	Dec. 31, 2019 CAD ($)	Mar. 31, 2020 $ / shares shares
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Gain (loss) on disposition of assets				$ 223	$ 876
Provisions on assets (note 6)				109	416
Proceeds from sale of land parcels			$ 3
Corporate/Other
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Provisions on assets (note 6)					$ 382
Distributed Generation Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Gain (loss) on disposition of assets				9
Distributed Generation Assets | Corporate/Other
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Provisions on assets (note 6)				3
Disposal by sale | Altagas Canada Inc.
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Share price of interests disposed of (in dollars per share) | $ / shares						$ 33.50
Shares disposed of (in shares) | shares						11,025
Ownership percentage (percent)						37.00%
Proceeds from disposition of business	$ 369
Gain (loss) on disposal of business				$ 206
Disposal by sale | Pomona Energy Storage Facility and Ripon Gas-fired Facility
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Proceeds from disposition of business		$ 67
Gain (loss) on disposal of business		$ 8

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Assets Held For Sale - Schedule of Assets Held for Sale (Details) - Held for sale $ in Millions, $ in Millions	Dec. 31, 2020 CAD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 CAD ($)
Assets held for sale
Property, plant and equipment	$ 4		$ 22
Operating right-of-use assets	0		1
Goodwill	0		1
Other long-term assets	0		3
Total assets held for sale	4		27
Liabilities associated with assets held for sale
Unamortized investment tax credits	1		3
Operating lease liabilities - long-term	0		1
Total liabilities associated with assets held for sale	1		$ 4
US Portfolio
Liabilities associated with assets held for sale
Total liabilities associated with assets held for sale	$ 4	$ 3

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Provisions on Assets - Schedule of Provisions on Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Provisions On Assets Disclosure
Provisions on assets	$ 109	$ 416
Midstream
Provisions On Assets Disclosure
Provisions on assets	$ 106	34
Corporate/Other
Provisions On Assets Disclosure
Provisions on assets		$ 382

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Provisions on Assets - Narratives (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Provisions On Assets Disclosure
Provisions on assets	$ 109	$ 416
Midstream
Provisions On Assets Disclosure
Provisions on assets	106	34
Midstream | Natural Gas Storage Project
Provisions On Assets Disclosure
Provisions on assets	104
Midstream | Land [Member]
Provisions On Assets Disclosure
Provisions on assets	$ 2
Corporate/Other
Provisions On Assets Disclosure
Provisions on assets		$ 382

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Inventory (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Inventory
Natural gas held in storage	$ 309	$ 359
Natural gas liquids	116	26
Materials and supplies	84	57
Renewable energy credits and emission compliance instruments	80	64
Crude oil and condensate	43	0
Processed finished products	4	0
Total inventory	636	506
Rate Regulated Utilities
Inventory
Natural gas held in storage	$ 193	$ 214

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Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment
Cost	$ 12,723	$ 11,499
Accumulated amortization	1,835	1,374
Net book value	10,888	10,125
Held for sale
Property, Plant and Equipment
Cost	4	24
Accumulated amortization	0	2
Net book value	4	22
Utilities
Property, Plant and Equipment
Cost	7,791	7,316
Accumulated amortization	286	155
Net book value	7,505	7,161
Midstream
Property, Plant and Equipment
Cost	4,094	3,182
Accumulated amortization	951	585
Net book value	3,143	2,597
Corporate/Other
Property, Plant and Equipment
Cost	842	1,025
Accumulated amortization	598	636
Net book value	$ 244	$ 389

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Property, Plant and Equipment - Narratives (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Interest capitalized	$ 6	$ 15
Capital projects under construction	457	725
Depreciation expense	$ 346	$ 358

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Intangible Assets - Summary of Intangible Assets (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Finite-Lived Intangible Assets
Cost	$ 753	$ 759
Accumulated amortization	(214)	(173)
Net book value	539	586
E&T contracts
Finite-Lived Intangible Assets
Cost	26	27
Accumulated amortization	(16)	(15)
Net book value	10	12
Electricity service agreements
Finite-Lived Intangible Assets
Cost	0	9
Accumulated amortization	0	(8)
Net book value	0	1
Energy services relationships
Finite-Lived Intangible Assets
Cost	90	91
Accumulated amortization	(45)	(27)
Net book value	45	64
Software
Finite-Lived Intangible Assets
Cost	304	304
Accumulated amortization	(133)	(102)
Net book value	171	202
Land rights
Finite-Lived Intangible Assets
Cost	1	1
Accumulated amortization	0	0
Net book value	1	1
Commodity contracts
Finite-Lived Intangible Assets
Cost	332	327
Accumulated amortization	(20)	(21)
Net book value	$ 312	$ 306

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Intangible Assets - Narratives (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Amortization expense	$ 68	$ 80
Assets excluded from asset base subject to amortization	$ 176	$ 185

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Intangible Assets - Summary of Estimated Amortization Expense of Intangible Assets (Details) $ in Millions	Dec. 31, 2020 CAD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2021	$ 75
2022	72
2023	60
2024	39
2025	15
Thereafter	$ 102

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Leases - Components of Lease Cost (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Lease, Cost
Operating lease cost (includes variable lease payments)	$ 43	$ 29
Amortization of right-of-use assets	4	4
Total finance lease cost	4	4
Total lease cost	$ 47	$ 33

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Leases - Supplemental Cashflow Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ (36)	$ (21)
Financing cash flows from finance leases	(4)	(4)
Right-of-use assets obtained in exchange for new lease liabilities
Operating leases	227	50
Finance leases	$ 6	$ 5

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Leases - Supplemental Balance Sheet Location (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Operating lease right-of-use assets
Long-term	$ 372	$ 170
Total operating lease right-of-use assets	372	170
Operating lease liabilities
Current	(95)	(27)
Long-term	(304)	(153)
Total operating lease liabilities	(399)	(180)
Finance Leases
Property and equipment, gross	19	13
Accumulated depreciation	(7)	(3)
Property and equipment, net	12	10
Current portion of long-term debt	(4)	(4)
Long-term debt	(8)	(6)
Total finance lease liabilities	$ (12)	$ (10)
Weighted average remaining lease term (years)
Operating leases	7 years 4 months 24 days	10 years 10 months 24 days
Finance leases	4 years 9 months 18 days	5 years 2 months 12 days
Weighted average discount rate (%)
Operating leases	2.42%	3.51%
Finance leases (percent)	2.89%	3.68%

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Leases - Schedule of Future Lease Liability for Operating and Finance Lease (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Operating Leases
2021	$ 96
2022	81
2023	58
2024	50
2025	40
Thereafter	125
Total lease payments	450
Less: imputed interest	(51)
Total	399	$ 180
Finance Leases
2021	4
2022	4
2023	2
2024	1
2025	1
Thereafter	2
Total lease payments	14
Less: imputed interest	(2)
Total	$ 12	$ 10

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Leases - Narrative (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Operating Leased Assets
Property, plant and equipment	$ 10,888	$ 10,125
Assets leased to others
Operating Leased Assets
Property, plant and equipment	$ 500

XML

Leases - Schedule of Operating Lease Receivables (Details) $ in Millions	Dec. 31, 2020 CAD ($)
Operating Leases
2021	$ 127
2022	117
2023	108
2024	41
2025	41
Thereafter	404
Total	$ 838

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Goodwill (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Goodwill
Balance, beginning of year	$ 3,942	$ 4,068
Business acquisition (note 3)	1,171	0
Adjustment to goodwill on business acquisition	0	92
Goodwill included in dispositions	0	(29)
Reclassified to assets held for sale	0	(1)
Foreign exchange translation	(74)	(188)
Balance, end of year	$ 5,039	$ 3,942

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Long-Term Investments and Other Assets (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Investments, All Other Investments [Abstract]
Investments in publicly-traded entities	$ 0	$ 4
Loan to affiliate (notes 23 and 30)	0	45
Deferred lease receivable	12	17
Debt issuance costs associated with credit facilities	3	6
Refundable deposits	9	9
Prepayment on long-term service agreements	70	81
Deferred information technology costs	4	0
Cash calls from joint venture partners	26	10
Contract asset (net of credit losses of $1 million) (notes 23 and 24)	50	30
Rabbi trust and other restricted cash (notes 28, 29 and 31)	19	32
Other long-term receivables (net of credit losses of $2 million) (notes 23 and 29)	18	33
Capitalized contract costs	5	0
Financial transmission rights	12	12
Other	17	18
Long-term investments and other assets	245	297
Contract assets, allowance for credit loss	1	1
Other long-term receivables, allowance for credit loss	$ 2	$ 2

XML

Variable Interest Entities - Narratives (Details) - CAD ($) $ in Millions	May 05, 2017	Dec. 31, 2020	Dec. 31, 2019
Variable Interest Entity
Investments accounted for by the equity method (note 14)		$ 887	$ 1,462
Strathcona Storage LP | CANADA
Variable Interest Entity
Equity method investment, ownership interest (percent)		30.00%
Investments accounted for by the equity method (note 14)		$ 124	$ 0
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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Variable Interest Entities - Schedule of VIE Amounts in Consolidated Balance Sheets (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Variable Interest Entity
Current assets	$ 2,497	$ 2,196
Property, plant and equipment	10,888	10,125
Long-term investments and other assets	245	297
Current liabilities	(2,607)	(3,125)
Asset retirement obligations	(385)	(368)
VIE
Variable Interest Entity
Current assets	7	6
Property, plant and equipment	358	371
Long-term investments and other assets	50	53
Current liabilities	(2)	(3)
Asset retirement obligations	(2)	(3)
Net assets	$ 411	$ 424

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Investments Accounted for by the Equity Method - Schedule of Equity Method Investments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Equity Method Investments
Equity method investment	$ 887	$ 1,462
Income from equity investments	49	141
CANADA | Altagas Canada Inc.
Schedule of Equity Method Investments
Equity method investment	0	164
Income from equity investments	3	17
CANADA | AltaGas Idemitsu Joint Venture LP
Schedule of Equity Method Investments
Equity method investment	0	431
Income from equity investments	$ (25)	63
CANADA | Sarnia Airport Storage Pool LP
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	50.00%
Equity method investment	$ 18	18
Income from equity investments	1	1
CANADA | Petrogas Preferred Shares
Schedule of Equity Method Investments
Equity method investment	0	150
Income from equity investments	$ 13	13
CANADA | Strathcona Storage LP
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	30.00%
Equity method investment	$ 124	0
Income from equity investments	0	0
United States | Constitution Pipeline, LLC (Constitution)
Schedule of Equity Method Investments
Equity method investment	0	0
Income from equity investments	$ (7)	0
United States | Eaton Rapids Gas Storage System
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	50.00%
Equity method investment	$ 26	27
Income from equity investments	2	1
United States | Meade Pipeline Co. LLC (Meade)
Schedule of Equity Method Investments
Equity method investment	0	0
Income from equity investments	$ 0	(4)
United States | Mountain Valley Pipeline, LLC
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	10.00%
Equity method investment	$ 718	672
Income from equity investments	$ 62	43
United States | Petrogas Terminals Penn LLC
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	37.00%
Equity method investment	$ 1	0
Income from equity investments	0	0
United States | Stonewall Gas Gathering System LLC
Schedule of Equity Method Investments
Equity method investment	0	0
Income from equity investments	$ 0	$ 7

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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, 2020	Dec. 31, 2019
Schedule of Equity Method Investments
Revenues	$ 5,587	$ 5,495
Cost of sales	(3,178)	(3,227)
Current assets	2,497	2,196
Property, plant and equipment	10,888	10,125
Intangible assets	539	586
Long-term investments and other assets	245	297
Current liabilities	(2,607)	(3,125)
Other long-term liabilities	(153)	(102)
Equity Method Investment, Nonconsolidated Investee or Group of Investees
Schedule of Equity Method Investments
Revenues	828	1,109
Cost of sales	(181)	(355)
Gross profit	647	754
Current assets	351	411
Property, plant and equipment	7,598	8,034
Intangible assets	0	22
Long-term investments and other assets	5	1,459
Current liabilities	(281)	(394)
Other long-term liabilities	$ (2)	$ (992)

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Investments Accounted for by the Equity Method - Narratives (Details) $ in Millions			12 Months Ended
	Dec. 15, 2020 CAD ($)	Mar. 31, 2020 CAD ($)	Dec. 31, 2020 CAD ($)	Mar. 31, 2020 $ / shares shares	Dec. 31, 2019 CAD ($)
Disposal by sale | Altagas Canada Inc.
Schedule of Equity Method Investments
Gain (loss) on disposal of business			$ 206
Petrogas Terminals Penn LLC | Petrogas Energy Corporation
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)			50.00%
Strathcona Storage LP | Petrogas Energy Corporation
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)			40.00%
AltaGas Canada Inc. | Public Sector Pension Investment Board and Alberta Teachers' Retirement Fund Board
Schedule of Equity Method Investments
Equity method investment, acquired (in dollars per share) | $ / shares				$ 33.50
AltaGas Canada Inc. | AltaGas
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)				37.00%
Equity method investment, shares owned prior to sale | shares				11,025,000
Proceeds from sale of equity method investments		$ 369
Constitution Pipeline
Schedule of Equity Method Investments
Provision on equity method investments			$ (7)
Meade Pipeline Co LLC
Schedule of Equity Method Investments
Provision on equity method investments					$ (44)
Craven County Wood Energy LP
Schedule of Equity Method Investments
Provision on equity method investments					$ 2
Petrogas Energy Corporation
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)				29.20%	33.30%
Pre-tax dilution losses			30
Additional expenses			$ 12
AIJVLP
Schedule of Equity Method Investments
Equity method investment, pre-tax gain on re-measurement of investment	$ (22)

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Short-term Debt - Schedule of Short-Term Debt (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Debt Disclosure [Abstract]
Commercial paper	$ 236	$ 389
Project financing	20	71
Short-term debt	$ 256	$ 460

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Short-term Debt - Narrative (Details)	12 Months Ended
	Dec. 31, 2020 CAD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2019 USD ($)
Short-term Debt
Project financing	$ 20,000,000		$ 71,000,000
Commercial paper	236,000,000		389,000,000
Unsecured Extendible Revolving Facility | Letter of Credit
Short-term Debt
Credit facility maximum borrowing capacity	150,000,000		150,000,000
Amount outstanding	$ 0		26,000,000
Debt instrument term (years)	4 years
Credit facility cancelled	$ 300,000,000
Unsecured Bilateral Demand Facility | Letter of Credit
Short-term Debt
Credit facility maximum borrowing capacity		$ 200,000,000		$ 200,000,000
Amount outstanding	190,000,000		156,000,000
Unsecured Extendible Revolving Facility II | Letter of Credit
Short-term Debt
Credit facility maximum borrowing capacity		1,200,000,000		$ 1,200,000,000
Revolving Letter of Credit Facility
Short-term Debt
Credit facility maximum borrowing capacity	30,000,000
Letters of credit outstanding	22,000,000
Operating Facility
Short-term Debt
Credit facility maximum borrowing capacity		15,000,000
Letters of credit outstanding		0
Seasonal Budget Facility
Short-term Debt
Credit facility maximum borrowing capacity		$ 40,000,000
Amount outstanding	0
Parent Company | Unsecured Demand Revolving Operating Credit Facility
Short-term Debt
Credit facility maximum borrowing capacity	70,000,000		70,000,000
Amount outstanding	$ 0		$ 0

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Long-Term Debt - Schedule of Long-Term Debt (Details)	Dec. 31, 2020 CAD ($)	Dec. 31, 2020 USD ($)	Dec. 10, 2020 CAD ($)	Dec. 31, 2019 CAD ($)
Debt Instrument
Fair value adjustment on WGL Acquisition (note 3)	$ 80,000,000			$ 84,000,000
Finance lease liabilities (note 10)	12,000,000			10,000,000
Long-term debt including lease obligations	8,029,000,000			6,887,000,000
Less debt issuance costs	(43,000,000)			(36,000,000)
Total long-term debt	7,986,000,000			6,851,000,000
Less current portion	(360,000,000)			(923,000,000)
Long-term debt, noncurrent	7,626,000,000			5,928,000,000
WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross			$ 100,000,000	300,000,000
Premium from debt issued			$ 17,000,000
$200 million Senior unsecured - 4.07 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 (as a percent)	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 (as a percent)	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			500,000,000
Debt face amount	$ 500,000,000
Debt instrument rate (as a percent)	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 (as a percent)	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 (as a percent)	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			300,000,000
Debt face amount	$ 300,000,000
Debt instrument rate (as a percent)	3.84%	3.84%
$500 million Senior unsecured - 2.16 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 (as a percent)	2.16%	2.16%
$350 million Senior unsecured - 4.12 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 (as a percent)	4.12%	4.12%
$200 million Senior unsecured - 3.98 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 (as a percent)	3.98%	3.98%
$500 million Senior unsecured - 2.08 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 (as a percent)	2.08%	2.08%
$200 million Senior unsecured - 2.48 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 200,000,000			0
Debt face amount	$ 200,000,000
Debt instrument rate (as a percent)	2.48%	2.48%
$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 (as a percent)	5.16%	5.16%
$300 million Senior unsecured - 4.50 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 (as a percent)	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 (as a percent)	4.99%	4.99%
US$250 million Senior unsecured - 2.44 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 250,000,000
Debt instrument rate (as a percent)	2.44%	2.44%
US$250 million Senior unsecured - 2.44 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 0			325,000,000
US$20 million Senior unsecured - 6.65 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 20,000,000
Debt instrument rate (as a percent)	6.65%	6.65%
US$20 million Senior unsecured - 6.65 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 25,000,000			26,000,000
US$41 million Senior unsecured - 5.44 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 41,000,000
Debt instrument rate (as a percent)	5.44%	5.44%
US$41 million Senior unsecured - 5.44 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 52,000,000			53,000,000
US$53 million Senior unsecured - 6.62 to 6.82 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 53,000,000
US$53 million Senior unsecured - 6.62 to 6.82 percent | WGL And Washington Gas | Minimum
Debt Instrument
Debt instrument rate (as a percent)	6.62%	6.62%
US$53 million Senior unsecured - 6.62 to 6.82 percent | WGL And Washington Gas | Maximum
Debt Instrument
Debt instrument rate (as a percent)	6.82%	6.82%
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	$ 67,000,000			69,000,000
US$72 million Senior unsecured - 6.40 to 6.57 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 72,000,000
US$72 million Senior unsecured - 6.40 to 6.57 percent | WGL And Washington Gas | Minimum
Debt Instrument
Debt instrument rate (as a percent)	6.40%	6.40%
US$72 million Senior unsecured - 6.40 to 6.57 percent | WGL And Washington Gas | Maximum
Debt Instrument
Debt instrument rate (as a percent)	6.57%	6.57%
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	$ 92,000,000			93,000,000
US$52 million Senior unsecured - 6.57 to 6.85 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 52,000,000
US$52 million Senior unsecured - 6.57 to 6.85 percent | WGL And Washington Gas | Minimum
Debt Instrument
Debt instrument rate (as a percent)	6.57%	6.57%
US$52 million Senior unsecured - 6.57 to 6.85 percent | WGL And Washington Gas | Maximum
Debt Instrument
Debt instrument rate (as a percent)	6.85%	6.85%
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	$ 66,000,000			67,000,000
US$9 million Senior unsecured - 7.50 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 9,000,000
Debt instrument rate (as a percent)	7.50%	7.50%
US$9 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			11,000,000
US$50 million Senior unsecured - 5.70 to 5.78 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 50,000,000
US$50 million Senior unsecured - 5.70 to 5.78 percent | WGL And Washington Gas | Minimum
Debt Instrument
Debt instrument rate (as a percent)	5.70%	5.70%
US$50 million Senior unsecured - 5.70 to 5.78 percent | WGL And Washington Gas | Maximum
Debt Instrument
Debt instrument rate (as a percent)	5.78%	5.78%
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	$ 64,000,000			65,000,000
US$75 million Senior unsecured - 5.21 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 75,000,000
Debt instrument rate (as a percent)	5.21%	5.21%
US$75 million Senior unsecured - 5.21 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 95,000,000			97,000,000
US$75 million Senior unsecured - 5.00 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 75,000,000
Debt instrument rate (as a percent)	5.00%	5.00%
US$75 million Senior unsecured - 5.00 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 95,000,000			97,000,000
US$300 million Senior unsecured - 4.22 to 4.60 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 300,000,000
US$300 million Senior unsecured - 4.22 to 4.60 percent | WGL And Washington Gas | Minimum
Debt Instrument
Debt instrument rate (as a percent)	4.22%	4.22%
US$300 million Senior unsecured - 4.22 to 4.60 percent | WGL And Washington Gas | Maximum
Debt Instrument
Debt instrument rate (as a percent)	4.60%	4.60%
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	$ 382,000,000			390,000,000
US$450 million Senior unsecured - 3.80 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 450,000,000
Debt instrument rate (as a percent)	3.80%	3.80%
US$450 million Senior unsecured - 3.80 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 573,000,000			584,000,000
US$400 million Senior unsecured - 3.65 percent (d) | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 400,000,000
Debt instrument rate (as a percent)	3.65%	3.65%
US$400 million Senior unsecured - 3.65 percent (d) | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 530,000,000			390,000,000
US$300 million SEMCO Senior Secured - 5.15 percent | SEMCO long-term debt
Debt Instrument
Long-term debt, gross	$ 0			390,000,000
Debt face amount		$ 300,000,000
Debt instrument rate (as a percent)	5.15%	5.15%
US$82 million SEMCO Senior Secured - 4.48 percent | SEMCO long-term debt
Debt Instrument
Long-term debt, gross	$ 69,000,000			76,000,000
Debt face amount		$ 82,000,000
Debt instrument rate (as a percent)	4.48%	4.48%
US$225 million First Mortgage Bonds - 3.15 percent | SEMCO long-term debt
Debt Instrument
Long-term debt, gross	$ 286,000,000			0
Debt face amount		$ 225,000,000
Debt instrument rate (as a percent)	3.15%	3.15%
US$225 million First Mortgage Bonds - 2.45 percent | SEMCO long-term debt
Debt Instrument
Long-term debt, gross	$ 286,000,000			0
Debt face amount		$ 225,000,000
Debt instrument rate (as a percent)	2.45%	2.45%
Credit facilities | $1,400 million unsecured extendible revolving facility
Debt Instrument
Long-term debt, gross	$ 802,000,000			90,000,000
Debt face amount	1,400,000,000
Credit facilities | US$300 million unsecured extendible revolving facility
Debt Instrument
Long-term debt, gross	0			390,000,000
Debt face amount		$ 300,000,000
Credit facilities | US$150 million unsecured extendible revolving facility
Debt Instrument
Long-term debt, gross	81,000,000			163,000,000
Debt face amount		$ 150,000,000
Credit facilities | Commercial paper
Debt Instrument
Long-term debt, gross	260,000,000			367,000,000
Credit facilities | Secured Extendible Revolving Facility Due June 2022
Debt Instrument
Long-term debt, gross	51,000,000			$ 0
Debt face amount	$ 175,000,000

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Long-Term Debt - Narrative (Details)	Dec. 31, 2020 CAD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2019 USD ($)
Operating Facility
Debt Instrument
Credit facility maximum borrowing capacity		$ 15,000,000
Revolving credit facility
Debt Instrument
Credit facility maximum borrowing capacity		300,000,000		$ 300,000,000
Amount outstanding	$ 0
Revolving credit facility | Commercial paper
Debt Instrument
Long-term debt, gross	260,000,000		$ 367,000,000
Revolving credit facility | Petrogas Energy Corporation
Debt Instrument
Credit facility maximum borrowing capacity	175,000,000
Amount outstanding	0
Revolving credit facility | Petrogas Energy Corporation | Operating Facility
Debt Instrument
Credit facility maximum borrowing capacity		10,000,000
Revolving credit facility | Letter of Credit | WGL Holdings
Debt Instrument
Credit facility maximum borrowing capacity		250,000,000		250,000,000
Amount outstanding	0
Revolving credit facility | Letter of Credit | Washington Gas
Debt Instrument
Credit facility maximum borrowing capacity		$ 450,000,000		$ 450,000,000
Amount outstanding	0
Revolving credit facility | Letter of Credit | Petrogas Energy Corporation
Debt Instrument
Credit facility maximum borrowing capacity	25,000,000
Amount outstanding	57,000,000
Revolving credit facility | Letter of Credit | Petrogas Energy Corporation | Operating Facility
Debt Instrument
Amount outstanding	$ 0

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Asset Retirement Obligations - Schedule of Accumulated Other Comprehensive Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis
Balance, beginning of year	$ 362	$ 500
Obligations acquired (note 3)	13	0
New obligations	14	7
Obligations settled	(4)	(2)
Disposals	(1)	(6)
Revision in estimated cash flow	(10)	(129)
Accretion expense	17	19
Foreign exchange translation	(6)	(21)
Total	385	368
Less: current portion (included in accounts payable and accrued liabilities)	(6)	(6)
Balance, end of year	$ 379	$ 362

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Asset Retirement Obligations - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligations
Undiscounted cash required to settle the asset retirement obligations, excluding growth for inflation	$ 816	$ 727
Minimum
Asset Retirement Obligations
Discount rate for asset retirement obligations (percent)	2.00%	2.00%
Maximum
Asset Retirement Obligations
Discount rate for asset retirement obligations (percent)	8.50%	8.50%

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Environmental Matters (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 CAD ($) site	Dec. 31, 2019 CAD ($)
Site Contingency
Identified operated manufactured gas plants | site	12
Accrual for environmental loss contingencies	$ 13	$ 14
Regulatory assets	15	18
Maximum
Site Contingency
Accrual for environmental loss contingencies	$ 39	$ 40

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Other Long-term Liabilities - Schedule of Other Long-Term Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Other Liabilities Disclosure [Abstract]
Deferred revenue	$ 8	$ 4
Customer advances for construction	60	64
Merger commitments	10	14
Other employee benefits	6	6
Deferred payroll taxes	6	0
Petrogas equalization reserve	5	0
Uncertain tax positions	21	2	$ 2
Non-pension retirement benefits	16	0
Other	21	12
Other long-term liabilities	$ 153	$ 102

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Income Taxes - Schedule of Income Tax Provision (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income before income taxes - consolidated	$ 699	$ 812
Statutory income tax rate (percent)	24.00%	26.50%
Expected taxes at statutory rates	$ 168	$ 215
Permanent differences	2	11
Statutory and other rate differences	9	(52)
Rate adjustment for change in tax rates	0	(11)
Deferred income tax recovery on regulated assets	(15)	(25)
Tax differences on divestitures and transactions	(33)	(159)
Change in valuation allowance	(2)	(11)
Other	(2)	4
Income tax expense, total	127	(28)
Current	1	63
Deferred	$ 126	$ (91)
Effective income tax rate (percent)	18.20%	(3.40%)

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Income Taxes - Schedule of Deferred Income Tax Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
PP&E and intangible assets	$ 1,645	$ 1,450
Regulatory assets	(229)	(204)
Tax pools, deferred financing, and compensation	(208)	(138)
Other	(94)	(161)
Valuation allowance	4	12
Net deferred income tax liabilities	$ 1,118	$ 959

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Income Taxes - Narrative (Details) - CAD ($) $ in Millions			6 Months Ended	12 Months Ended
	Jul. 01, 2020	Jul. 01, 2019	Jun. 30, 2020	Dec. 31, 2020	Dec. 31, 2019
Income Tax Contingency
Statutory income tax rate (percent)				24.00%	26.50%
Tax-affected non-capital losses				$ 293
Canada Revenue Agency
Income Tax Contingency
Statutory income tax rate (percent)	8.00%	11.00%	12.00%

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Income Taxes - Schedule of Uncertain Tax Positions (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Reconciliation of Unrecognized Tax Benefits
Balance, beginning of year	$ 2	$ 2
Gross increases for tax positions of prior year	21	0
Lapses of statute of limitations	(2)	0
Balance, end of year	$ 21	$ 2

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Regulatory Assets and Liabilities (Details) $ in Millions, $ in Millions		12 Months Ended
	Sep. 18, 2013 USD ($)	Dec. 31, 2020 CAD ($)	Dec. 31, 2019 CAD ($)
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current		$ 46	$ 13
Regulatory assets - non-current		444	487
Regulatory liabilities - current		90	146
Regulatory liabilities - non-current		1,381	1,383
Deferred cost of gas
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		56	61
Refundable tax credit
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		2	2
Gas storage facility tax credit	$ 15
Virginia Rate Refund
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		0	41
Federal income tax rate change
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		20	33
Regulatory liabilities - non-current		578	628
Future recovery of pension and other retirement benefits
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - non-current		335	261
Future removal and site restoration costs
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - non-current		462	484
Deferred gain on debt transactions and derivative instruments
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - non-current		1	2
Fair value adjustment		76	80
Interruptible sharing
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		1	0
Virginia Coronavirus Relief Fund
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		10	0
Other
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		1	9
Regulatory liabilities - non-current		3	4
Refundable tax credit noncurrent
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - non-current		$ 2	4
Recovery period (years)		2 years
Deferred cost of gas
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current		$ 18	8
Accelerated replacement recovery mechanisms
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current		6	2
Interruptible sharing
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current		2	3
Energy Optimization Costs
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current		1	0
Virginia and Maryland Revenue Normalization
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current		19	0
Deferred regulatory costs and rate stabilization adjustment mechanism
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		$ 158	150
Deferred regulatory costs and rate stabilization adjustment mechanism | Minimum
Schedule Of Regulatory Assets And Liabilities
Recovery period (years)		2 years
Deferred regulatory costs and rate stabilization adjustment mechanism | Maximum
Schedule Of Regulatory Assets And Liabilities
Recovery period (years)		55 years
Future recovery of pension and other retirement benefits
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		$ 68	128
Future recovery of non-retirement employee benefits
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		22	19
Deferred environmental costs
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		15	18
Deferred loss on debt transactions and derivative instruments
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		93	99
Fair value adjustment		76	80
Deferred future income taxes
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		46	43
Energy efficiency program - Maryland
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		18	12
COVID-19 Costs
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		10	0
Other
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		$ 14	$ 18

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Accumulated Other Comprehensive Income - Schedule of Accumulated Other Comprehensive Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	$ 7,369
Total other comprehensive loss (OCI), net of taxes (note 22)	(195)	$ (334)
Balance, end of year	7,661	7,369
Total
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	245	579
OCI before reclassification	(201)	(324)
Amounts reclassified from OCI	3	1
Current period OCI (pre-tax)	(198)	(323)
Income tax on amounts retained in AOCI	4	(11)
Income tax on amounts reclassified to earnings	(1)	0
Total other comprehensive loss (OCI), net of taxes (note 22)	(195)	(334)
Balance, end of year	50	245
Defined benefit pension and PRB plans
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	(6)	(19)
OCI before reclassification	(11)	15
Amounts reclassified from OCI	3	1
Current period OCI (pre-tax)	(8)	16
Income tax on amounts retained in AOCI	3	(3)
Income tax on amounts reclassified to earnings	(1)
Total other comprehensive loss (OCI), net of taxes (note 22)	(6)	13
Balance, end of year	(12)	(6)
Hedge net investments
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	(149)	(209)
OCI before reclassification	(10)	68
Amounts reclassified from OCI	0	0
Current period OCI (pre-tax)	(10)	68
Income tax on amounts retained in AOCI	1	(8)
Income tax on amounts reclassified to earnings	0
Total other comprehensive loss (OCI), net of taxes (note 22)	(9)	60
Balance, end of year	(158)	(149)
Translation foreign operations
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	395	801
OCI before reclassification	(175)	(406)
Amounts reclassified from OCI	0	0
Current period OCI (pre-tax)	(175)	(406)
Income tax on amounts retained in AOCI	0	0
Income tax on amounts reclassified to earnings	0
Total other comprehensive loss (OCI), net of taxes (note 22)	(175)	(406)
Balance, end of year	220	395
Equity investee
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	5	6
OCI before reclassification	(5)	(1)
Amounts reclassified from OCI	0	0
Current period OCI (pre-tax)	(5)	(1)
Income tax on amounts retained in AOCI	0	0
Income tax on amounts reclassified to earnings	0
Total other comprehensive loss (OCI), net of taxes (note 22)	(5)	(1)
Balance, end of year	$ 0	$ 5

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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, 2020	Dec. 31, 2019
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Defined benefit pension and PRB plans	$ 3	$ 1
Deferred income taxes	(1)	0
Reclassifications from AOCI, net	$ 2	$ 1

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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, 2020	Dec. 31, 2019
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	$ 98	$ 87
Risk management assets - non-current	47	39
Risk management liabilities - current	111	125
Risk management liabilities - non-current	145	167
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Loans and receivables		45
Financial assets	145	175
Current portion of long-term debt	360	923
Long-term debt	7,626	5,928
Other current liabilities	37	15
Financial liabilities	8,279	7,158
Carrying Amount | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	94	82
Risk management assets - non-current	38	31
Equity securities		4
Risk management liabilities - current	102	121
Risk management liabilities - non-current	66	77
Carrying Amount | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	4	5
Risk management assets - non-current	9	8
Risk management liabilities - current	9	4
Risk management liabilities - non-current	79	90
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Loans and receivables		46
Financial assets	145	176
Current portion of long-term debt	360	923
Long-term debt	8,451	6,264
Other current liabilities	37	15
Financial liabilities	9,104	7,494
Fair Value | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	94	82
Risk management assets - non-current	38	31
Equity securities		4
Risk management liabilities - current	102	121
Risk management liabilities - non-current	66	77
Fair Value | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	4	5
Risk management assets - non-current	9	8
Risk management liabilities - current	9	4
Risk management liabilities - non-current	79	90
Fair Value | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Loans and receivables		0
Financial assets	0	4
Current portion of long-term debt	0	0
Long-term debt	0	0
Other current liabilities	0	0
Financial liabilities	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
Risk management assets - non-current	0	0
Equity securities		4
Risk management liabilities - current	0	0
Risk management liabilities - non-current	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
Risk management assets - non-current	0	0
Risk management liabilities - current	0	0
Risk management liabilities - non-current	0	0
Fair Value | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Loans and receivables		46
Financial assets	76	84
Current portion of long-term debt	360	923
Long-term debt	8,451	6,264
Other current liabilities	37	15
Financial liabilities	8,942	7,321
Fair Value | Level 2 | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	73	31
Risk management assets - non-current	2	7
Equity securities		0
Risk management liabilities - current	78	99
Risk management liabilities - non-current	15	19
Fair Value | Level 2 | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	1	0
Risk management assets - non-current	0	0
Risk management liabilities - current	0	1
Risk management liabilities - non-current	1	0
Fair Value | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Loans and receivables		0
Financial assets	69	88
Current portion of long-term debt	0	0
Long-term debt	0	0
Other current liabilities	0	0
Financial liabilities	162	173
Fair Value | Level 3 | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	21	51
Risk management assets - non-current	36	24
Equity securities		0
Risk management liabilities - current	24	22
Risk management liabilities - non-current	51	58
Fair Value | Level 3 | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	3	5
Risk management assets - non-current	9	8
Risk management liabilities - current	9	3
Risk management liabilities - non-current	$ 78	$ 90

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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, 2020 CAD ($) $ / dekatherm $ / MWh
Natural Gas | Discounted Cash Flow
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability) | $	$ (73)
Fair Value, Net Asset (Liability), Per Dekatherm	(0.37)
Natural Gas | Discounted Cash Flow | Minimum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Dekatherm	(1.27)
Natural Gas | Discounted Cash Flow | Maximum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Dekatherm	2.64
Natural Gas | Option Model
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability) | $	$ (1)
Fair Value, Net Asset (Liability), Per Dekatherm	(0.01)
Fair Value, Net Asset (Liability), Percent	73.00%
Natural Gas | Option Model | Minimum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Dekatherm	(1.27)
Fair Value, Net Asset (Liability), Percent	13.00%
Natural Gas | Option Model | Maximum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Dekatherm	2.58
Fair Value, Net Asset (Liability), Percent	917.00%
Electricity | Discounted Cash Flow
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability) | $	$ (19)
Fair Value, Net Asset (Liability), Per Megawatt Hour | $ / MWh	13.57
Electricity | Discounted Cash Flow | Minimum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Megawatt Hour | $ / MWh	(6.26)
Electricity | Discounted Cash Flow | Maximum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Megawatt Hour | $ / MWh	61.88

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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, 2020	Dec. 31, 2019
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance, beginning of year	$ (85)	$ (163)
Recorded in income	(47)	49
Recorded in regulatory assets	(1)	24
Transfers into Level 3	(1)	(9)
Transfers out of Level 3	1	12
Purchases	3	(11)
Settlements	36	7
Foreign exchange translation	1	6
Balance, end of year	(93)	(85)
Natural Gas
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance, beginning of year	(85)	(149)
Recorded in income	8	48
Recorded in regulatory assets	(1)	24
Transfers into Level 3	(1)	(9)
Transfers out of Level 3	1	12
Purchases	0	0
Settlements	4	(17)
Foreign exchange translation	0	6
Balance, end of year	(74)	(85)
Electricity
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance, beginning of year	0	(14)
Recorded in income	(55)	1
Recorded in regulatory assets	0	0
Transfers into Level 3	0	0
Transfers out of Level 3	0	0
Purchases	3	(11)
Settlements	32	24
Foreign exchange translation	1	0
Balance, end of year	$ (19)	$ 0

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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, 2020	Dec. 31, 2019
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation
Realized and Unrealized Losses Recorded to Income for Level 3 Measurements	$ (47)	$ 49
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	(79)	75
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	$ 32	$ (26)

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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, 2020	Dec. 31, 2019
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	$ 21	$ (85)
Natural gas
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	32	23
Energy exports
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	10	(87)
Crude oil and NGLs
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	4	0
NGL frac spread
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	(5)	(17)
Power
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	(15)	(5)
Foreign exchange
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	$ (5)	$ 1

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Financial Instruments and Financial Risk Management - Schedule of Offsetting Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Offsetting Assets And Liabilities
Netting of collateral	$ 0	$ 6
Risk management assets - current	98	87
Risk management assets - non-current	47	39
Risk management liabilities - current	111	125
Risk management liabilities - non-current	145	167
Risk management contracts
Offsetting Assets And Liabilities
Gross amounts of recognized assets	248	185
Gross amounts offset in balance sheet	(135)	(64)
Netting of collateral	32	5
Net amount of assets presented in balance sheet	145	126
Gross amounts of recognized liabilities	393	387
Gross amounts offset in balance sheet	(135)	(64)
Netting of collateral	(2)	(31)
Net amount of liabilities presented in balance sheet	256	292
Natural gas
Offsetting Assets And Liabilities
Gross amounts of recognized assets	104	121
Gross amounts offset in balance sheet	(38)	(54)
Netting of collateral	(3)	0
Net amount of assets presented in balance sheet	63	67
Gross amounts of recognized liabilities	173	226
Gross amounts offset in balance sheet	(38)	(54)
Netting of collateral	(3)	(28)
Net amount of liabilities presented in balance sheet	132	144
Energy exports
Offsetting Assets And Liabilities
Gross amounts of recognized assets	86
Gross amounts offset in balance sheet	(86)
Netting of collateral	36
Net amount of assets presented in balance sheet	36
Gross amounts of recognized liabilities	153	90
Gross amounts offset in balance sheet	(86)	(3)
Netting of collateral	0	0
Net amount of liabilities presented in balance sheet	67	87
Crude oil and NGLs
Offsetting Assets And Liabilities
Gross amounts of recognized assets	1
Gross amounts offset in balance sheet	0
Netting of collateral	0
Net amount of assets presented in balance sheet	1
NGL frac spread
Offsetting Assets And Liabilities
Gross amounts of recognized assets		10
Gross amounts offset in balance sheet		(3)
Netting of collateral		5
Net amount of assets presented in balance sheet		12
Gross amounts of recognized liabilities	6	2
Gross amounts offset in balance sheet	0	0
Netting of collateral	0	0
Net amount of liabilities presented in balance sheet	6	2
Power
Offsetting Assets And Liabilities
Gross amounts of recognized assets	30	54
Gross amounts offset in balance sheet	(8)	(7)
Netting of collateral	0	0
Net amount of assets presented in balance sheet	22	47
Gross amounts of recognized liabilities	58	69
Gross amounts offset in balance sheet	(8)	(7)
Netting of collateral	1	(3)
Net amount of liabilities presented in balance sheet	51	$ 59
Foreign exchange
Offsetting Assets And Liabilities
Gross amounts of recognized assets	27
Gross amounts offset in balance sheet	(3)
Netting of collateral	(1)
Net amount of assets presented in balance sheet	23
Gross amounts of recognized liabilities	3
Gross amounts offset in balance sheet	(3)
Netting of collateral	0
Net amount of liabilities presented in balance sheet	$ 0

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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, 2020	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Collateral posted with counterparties	$ 4	$ 29
Cash collateral held representing an obligation	$ 0	$ 0

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Financial Instruments and Financial Risk Management - Narrative (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020 CAD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2019 USD ($)
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Netting of collateral	$ 0	$ 6
Long term debt	7,986	6,851
Other comprehensive loss	(195)	(334)
Unrealized gain on net investment hedge	(9)	60
Unrealized gains (losses) on risk management contracts	21	$ (85)
Foreign Exchange Forward
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Realized gain on foreign exchange forward contracts	$ 1
Interest rate risk
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Fixed rate debt, percent	83.00%	76.00%	76.00%
Weather related instruments
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Unrealized gains (losses) on risk management contracts	$ (3)	$ (2)
Net investment hedge
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Long term debt			$ 300
Hedge net investments
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Other comprehensive loss	$ (9)	$ 60

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Financial Instruments and Financial Risk Management - Risk Management Liabilities And Maximum Potential Collateral Requirements (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk management liabilities with credit-risk-contingent features	$ 32	$ 42
Maximum potential collateral requirements	$ 26	$ 29

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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, 2020 CAD ($) kJ MWh $ / gigajoule $ / barrel $ / MWh bbl	Dec. 31, 2019 CAD ($) kJ MWh $ / barrel $ / MWh $ / gigajoule bbl
Natural gas | Sales
Derivative
Notional volume (GJ) | kJ	590,054,996	698,126,985
Fair Value ($)	$ 32	$ 29
Natural gas | Sales | Minimum
Derivative
Fixed price | $ / gigajoule	1.58	1.32
Period (months)	1 month	1 month
Natural gas | Sales | Maximum
Derivative
Fixed price | $ / gigajoule	7.86	6.81
Period (months)	157 months	166 months
Natural gas | Purchases
Derivative
Notional volume (GJ) | kJ	1,522,958,497	1,406,991,689
Fair Value ($)	$ (106)	$ (104)
Natural gas | Purchases | Minimum
Derivative
Fixed price | $ / gigajoule	1.58	0.22
Period (months)	1 month	1 month
Natural gas | Purchases | Maximum
Derivative
Fixed price | $ / gigajoule	6.47	6.81
Period (months)	240 months	167 months
Natural gas | Swaps
Derivative
Notional volume (GJ) | kJ	288,613,586	541,652,374
Fair Value ($)	$ 5	$ (2)
Natural gas | Swaps | Minimum
Derivative
Fixed price | $ / gigajoule	2.29	0.22
Period (months)	1 month	1 month
Natural gas | Swaps | Maximum
Derivative
Fixed price | $ / gigajoule	7.86	10.24
Period (months)	60 months	51 months
Crude oil and NGLs | Sales
Derivative
Period (months)	1 month
Notional volume (GJ) | kJ		680,000
Fair Value ($)		$ (1)
Crude oil and NGLs | Sales | Minimum
Derivative
Fixed price | $ / gigajoule	37.43
Crude oil and NGLs | Sales | Maximum
Derivative
Fixed price | $ / gigajoule	62.59
Crude oil and NGLs | Purchases
Derivative
Notional volume (GJ) | kJ		221,000
Fair Value ($)		$ 2
Crude oil and NGLs | Purchases | Minimum
Derivative
Fixed price | $ / gigajoule	19.92
Period (months)	1 month
Crude oil and NGLs | Purchases | Maximum
Derivative
Fixed price | $ / gigajoule	59.01
Period (months)	9 months
Energy exports | Propane and butane swaps
Derivative
Notional volume (Bbl) | bbl	37,425,488
Fair Value ($)	$ (31)
Energy exports | Propane
Derivative
Notional volume (Bbl) | bbl		9,374,826
Fair Value ($)		$ (75)
Energy exports | Minimum | Propane and butane swaps
Derivative
Fixed price | $ / barrel	3.57
Period (months)	1 month
Energy exports | Minimum | Propane
Derivative
Fixed price | $ / barrel	21.49
Period (months)	1 month
Energy exports | Maximum | Propane and butane swaps
Derivative
Fixed price | $ / barrel	61.46
Period (months)	36 months
Energy exports | Maximum | Propane
Derivative
Fixed price | $ / barrel	29.71
Period (months)	27 months
NGL frac spread | Propane
Derivative
Notional volume (Bbl) | bbl	1,270,350
Fair Value ($)	$ (5)
NGL frac spread | Minimum | Propane
Derivative
Fixed price | $ / barrel	28.83
Period (months)	1 month
NGL frac spread | Minimum | Butane swaps
Derivative
Fixed price | $ / barrel	32.45	73.02
Period (months)	1 month	1 month
NGL frac spread | Minimum | Crude oil swaps
Derivative
Fixed price | $ / barrel	60.08	73.02
Period (months)	1 month	1 month
NGL frac spread | Minimum | Gas purchase
Derivative
Fixed price | $ / gigajoule	1.58	1.58
Period (months)	1 month	1 month
NGL frac spread | Maximum | Propane
Derivative
Fixed price | $ / barrel	35.36
Period (months)	12 months
NGL frac spread | Maximum | Butane swaps
Derivative
Fixed price | $ / barrel	34.02	75.15
Period (months)	12 months	12 months
NGL frac spread | Maximum | Crude oil swaps
Derivative
Fixed price | $ / barrel	61.95	75.15
Period (months)	12 months	12 months
NGL frac spread | Maximum | Gas purchase
Derivative
Fixed price | $ / gigajoule	1.86	1.86
Period (months)	12 months	12 months
NGL frac spread | Swaps | Butane swaps
Derivative
Notional volume (Bbl) | bbl	307,784	346,852
Fair Value ($)	$ (1)	$ (1)
NGL frac spread | Swaps | Crude oil swaps
Derivative
Notional volume (Bbl) | bbl	123,120	212,587
Fair Value ($)	$ 0	$ (1)
NGL frac spread | Swaps | Gas purchase
Derivative
Notional volume (GJ) | kJ	7,281,570	3,883,992
Fair Value ($)	$ 0	$ 0
Power | Sales
Derivative
Notional volume (GJ) | MWh	5,482,242	8,034,024
Fair Value ($)	$ 13	$ 39
Power | Sales | Minimum
Derivative
Fixed price | $ / MWh	24.56	31.63
Period (months)	1 month	1 month
Power | Sales | Maximum
Derivative
Fixed price | $ / MWh	61.75	66.76
Period (months)	33 months	42 months
Power | Purchases
Derivative
Notional volume (GJ) | MWh	8,848,007	8,552,467
Fair Value ($)	$ (18)	$ (27)
Power | Purchases | Minimum
Derivative
Fixed price | $ / MWh	24.56	31.63
Period (months)	1 month	1 month
Power | Purchases | Maximum
Derivative
Fixed price | $ / MWh	61.88	66.76
Period (months)	63 months	60 months
Power | Swaps
Derivative
Notional volume (GJ) | MWh	24,081,519	25,058,577
Fair Value ($)	$ (24)	$ (24)
Power | Swaps | Minimum
Derivative
Fixed price | $ / MWh	(6.26)	(7.88)
Period (months)	1 month	1 month
Power | Swaps | Maximum
Derivative
Fixed price | $ / MWh	74.26	74.26
Period (months)	44 months	48 months

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Financial Instruments and Financial Risk Management - Summary of Potential Impact on Pre-Tax Income Due to Change in Fair Value of Price Risk Derivatives (Details)	12 Months Ended
	Dec. 31, 2020 CAD ($) $ / gigajoule $ / gigajoule $ / MWh $ / barrel	Dec. 31, 2019 CAD ($)
Derivative
Unrealized gains (losses) on risk management contracts	$ 21,000,000	$ (85,000,000)
PJM power price
Derivative
Increase or decrease to forward prices, energy | $ / MWh	1
Unrealized gains (losses) on risk management contracts	$ 2,000,000
AECO natural gas price
Derivative
Increase or decrease to forward prices, energy | $ / gigajoule	0.50
Unrealized gains (losses) on risk management contracts	$ 1,000,000
NYMEX natural gas price
Derivative
Increase or decrease to forward prices, energy | $ / gigajoule	0.50
Unrealized gains (losses) on risk management contracts	$ 36,000,000
Energy exports
Derivative
Unrealized gains (losses) on risk management contracts	$ 10,000,000
Energy exports | Propane
Derivative
Increase or decrease to forward prices, volume | $ / barrel	1
Baltic LPG Freight
Derivative
Unrealized gains (losses) on risk management contracts	$ 11,000,000
Baltic LPG Freight | Propane
Derivative
Increase or decrease to forward prices, volume | $ / barrel	1
NGL frac spread
Derivative
Unrealized gains (losses) on risk management contracts	$ (5,000,000)	$ (17,000,000)
NGL frac spread | Propane
Derivative
Increase or decrease to forward prices, volume | $ / barrel	1
Unrealized gains (losses) on risk management contracts	$ 1,000,000
NGL frac spread | Natural Gas
Derivative
Increase or decrease to forward prices, energy | $ / gigajoule	0.50
Unrealized gains (losses) on risk management contracts	$ 4,000,000
Foreign Exchange
Derivative
Increase or decrease to forward prices, foreign exchange swap	0.01
Unrealized gains (losses) on risk management contracts	$ 1,000,000

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Financial Instruments and Financial Risk Management - Acquired Foreign Exchange Contracts (Details) - Foreign Exchange Forward $ in Millions, $ in Millions	Dec. 31, 2020 USD ($)	Dec. 31, 2020 CAD ($)
Sales
Derivative
Notional Amount	$ 29
Weighted average foreign exchange rate	1.3591	1.3591
Fair Value		$ 3
Purchases
Derivative
Notional Amount	$ 356
Weighted average foreign exchange rate	1.2824	1.2824
Fair Value		$ (3)
Swaps
Derivative
Notional Amount	$ 410
Weighted average foreign exchange rate	1.3322	1.3322
Fair Value		$ 23

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Financial Instruments and Financial Risk Management - Schedule of Accounts Receivable Past Due or Impaired (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Accounts, Notes, Loans and Financing Receivable
AR accruals	$ 396	$ 343
Receivables impaired	0	0
Allowance for credit losses	(41)	(41)
Accounts receivable	1,444	1,222
Less than 30 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	926	775
31 to 60 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	52	61
61 to 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	17	12
Over 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	53	31
Trade receivable
Accounts, Notes, Loans and Financing Receivable
Accounts receivable, gross	1,465	1,238
AR accruals	396	343
Receivables impaired	41	33
Trade receivable | Less than 30 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	906	758
Trade receivable | 31 to 60 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	52	61
Trade receivable | 61 to 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	17	12
Trade receivable | Over 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	53	31
Other
Accounts, Notes, Loans and Financing Receivable
Accounts receivable, gross	20	17
AR accruals	0	0
Receivables impaired	0	0
Other | Less than 30 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	20	17
Other | 31 to 60 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	0	0
Other | 61 to 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	0	0
Other | Over 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	0	0
Allowance for credit losses
Accounts, Notes, Loans and Financing Receivable
AR accruals	0	0
Allowance for credit losses	(41)	(33)
Allowance for credit losses | Less than 30 days
Accounts, Notes, Loans and Financing Receivable
Allowance for credit losses	0	0
Allowance for credit losses | 31 to 60 days
Accounts, Notes, Loans and Financing Receivable
Allowance for credit losses	0	0
Allowance for credit losses | 61 to 90 days
Accounts, Notes, Loans and Financing Receivable
Allowance for credit losses	0	0
Allowance for credit losses | Over 90 days
Accounts, Notes, Loans and Financing Receivable
Allowance for credit losses	$ 0	$ 0

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Financial Instruments and Financial Risk Management - Allowance for Credit Loss (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 CAD ($)
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, end of period	$ 44
Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	31
Foreign exchange translation	(1)
New allowance	32
Written off	(28)
Recoveries collected	4
Balance, end of period	40
New allowance from COVID-19	8
Midstream
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	1
Recoveries collected	(1)
Balance, end of period	4
Corporate/Other
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	2
Written off	(2)
Recoveries collected	(1)
Balance, end of period	0
Accounts receivable
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, end of period	41
Accounts receivable | Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	31
Foreign exchange translation	(1)
New allowance	32
Written off	(28)
Recoveries collected	4
Balance, end of period	40
Accounts receivable | Midstream
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	1
Recoveries collected	0
Balance, end of period	1
Accounts receivable | Corporate/Other
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	2
Written off	(2)
Recoveries collected	0
Balance, end of period	0
Contract assets
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, end of period	1
Contract assets | Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Foreign exchange translation	0
New allowance	0
Written off	0
Recoveries collected	0
Balance, end of period	0
Contract assets | Midstream
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Recoveries collected	0
Balance, end of period	1
Contract assets | Corporate/Other
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Written off	0
Recoveries collected	0
Balance, end of period	0
Other Long-Term Investments and Other Assets
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, end of period	2
Other Long-Term Investments and Other Assets | Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Foreign exchange translation	0
New allowance	0
Written off	0
Recoveries collected	0
Balance, end of period	0
Other Long-Term Investments and Other Assets | Midstream
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Recoveries collected	(1)
Balance, end of period	2
Other Long-Term Investments and Other Assets | Corporate/Other
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Written off	0
Recoveries collected	(1)
Balance, end of period	0
Cumulative Effect, Period of Adoption, Adjustment | Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	2
Cumulative Effect, Period of Adoption, Adjustment | Midstream
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	4
Cumulative Effect, Period of Adoption, Adjustment | Corporate/Other
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	1
Cumulative Effect, Period of Adoption, Adjustment | Accounts receivable | Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	2
Cumulative Effect, Period of Adoption, Adjustment | Accounts receivable | Midstream
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Cumulative Effect, Period of Adoption, Adjustment | Accounts receivable | Corporate/Other
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Cumulative Effect, Period of Adoption, Adjustment | Contract assets | Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Cumulative Effect, Period of Adoption, Adjustment | Contract assets | Midstream
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	1
Cumulative Effect, Period of Adoption, Adjustment | Contract assets | Corporate/Other
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Cumulative Effect, Period of Adoption, Adjustment | Other Long-Term Investments and Other Assets | Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Cumulative Effect, Period of Adoption, Adjustment | Other Long-Term Investments and Other Assets | Midstream
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	3
Cumulative Effect, Period of Adoption, Adjustment | Other Long-Term Investments and Other Assets | Corporate/Other
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	$ 1

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Financial Instruments and Financial Risk Management - Schedule of Contractual Maturities for Financial Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Contractual maturities by period
Total	$ 10,069	$ 8,907
Less than 1 year	2,343	2,867
1-3 years	1,822	1,523
4-5 years	1,346	935
After 5 years	4,558	3,582
Accounts payable and accrued liabilities
Contractual maturities by period
Total	1,561	1,325
Less than 1 year	1,561	1,325
1-3 years	0	0
4-5 years	0	0
After 5 years	0	0
Dividends payable
Contractual maturities by period
Total	22	22
Less than 1 year	22	22
1-3 years	0	0
4-5 years	0	0
After 5 years	0	0
Short-term debt
Contractual maturities by period
Total	256	460
Less than 1 year	256	460
1-3 years	0	0
4-5 years	0	0
After 5 years	0	0
Other current liabilities
Contractual maturities by period
Total	37	15
Less than 1 year		15
1-3 years	0	0
4-5 years	0	0
After 5 years	0	0
Risk management contract liabilities
Contractual maturities by period
Total	256	292
Less than 1 year	111	125
1-3 years	51	34
4-5 years	22	13
After 5 years	72	120
Current portion of long-term debt
Contractual maturities by period
Total	356	920
Less than 1 year	356	920
1-3 years	0	0
4-5 years	0	0
After 5 years	0	0
Long-term debt
Contractual maturities by period
Total	7,581	5,873
Less than 1 year	0	0
1-3 years	1,771	1,489
4-5 years	1,324	922
After 5 years	$ 4,486	$ 3,462

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Revenue - Disaggregation of Revenue by Major Sources (Details) - CAD ($) $ in Millions		12 Months Ended
	Mar. 31, 2018	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue
Revenue from contracts with customers		$ 5,161	$ 4,940
Other sources of revenue		426	555
Total revenue		5,587	5,495
Contract term	20 years
Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers		2,436	2,225
Midstream service contracts
Disaggregation of Revenue
Revenue from contracts with customers		277	145
Gas sales and transportation services
Disaggregation of Revenue
Revenue from contracts with customers		2,394	2,501
Storage services
Disaggregation of Revenue
Revenue from contracts with customers		25	28
Other
Disaggregation of Revenue
Revenue from contracts with customers		29	41
Revenue from alternative revenue programs
Disaggregation of Revenue
Other sources of revenue		96	30
Leasing revenue
Disaggregation of Revenue
Other sources of revenue		240	243
Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue		81	262
Risk management and trading activities | GAIL
Disaggregation of Revenue
Other sources of revenue		437	505
Other
Disaggregation of Revenue
Other sources of revenue		9	20
Utilities
Disaggregation of Revenue
Total revenue		3,817	4,044
Midstream
Disaggregation of Revenue
Total revenue		1,635	1,228
Operating Segments
Disaggregation of Revenue
Total revenue		5,588	5,527
Operating Segments | Utilities
Disaggregation of Revenue
Revenue from contracts with customers		3,766	3,966
Other sources of revenue		51	78
Total revenue		3,817	4,044
Operating Segments | Utilities | Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers		1,338	1,428
Operating Segments | Utilities | Midstream service contracts
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Utilities | Gas sales and transportation services
Disaggregation of Revenue
Revenue from contracts with customers		2,394	2,501
Operating Segments | Utilities | Storage services
Disaggregation of Revenue
Revenue from contracts with customers		25	28
Operating Segments | Utilities | Other
Disaggregation of Revenue
Revenue from contracts with customers		9	9
Operating Segments | Utilities | Revenue from alternative revenue programs
Disaggregation of Revenue
Other sources of revenue		96	30
Operating Segments | Utilities | Leasing revenue
Disaggregation of Revenue
Other sources of revenue		1	1
Operating Segments | Utilities | Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue		(31)	52
Operating Segments | Utilities | Other
Disaggregation of Revenue
Other sources of revenue		(15)	(5)
Operating Segments | Midstream
Disaggregation of Revenue
Revenue from contracts with customers		1,374	894
Other sources of revenue		261	334
Total revenue		1,636	1,260
Operating Segments | Midstream | Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers		$ 1,097	746
Contract term		1 year
Operating Segments | Midstream | Midstream service contracts
Disaggregation of Revenue
Revenue from contracts with customers		$ 277	145
Operating Segments | Midstream | Gas sales and transportation services
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Midstream | Storage services
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Midstream | Other
Disaggregation of Revenue
Revenue from contracts with customers		0	3
Operating Segments | Midstream | Revenue from alternative revenue programs
Disaggregation of Revenue
Other sources of revenue		0	0
Operating Segments | Midstream | Leasing revenue
Disaggregation of Revenue
Other sources of revenue		139	137
Operating Segments | Midstream | Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue		112	188
Operating Segments | Midstream | Other
Disaggregation of Revenue
Other sources of revenue		10	9
Operating Segments | Corporate/Other
Disaggregation of Revenue
Revenue from contracts with customers		21	80
Other sources of revenue		114	143
Operating Segments | Corporate/Other | Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers		1	51
Operating Segments | Corporate/Other | Midstream service contracts
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Corporate/Other | Gas sales and transportation services
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Corporate/Other | Storage services
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Corporate/Other | Other
Disaggregation of Revenue
Revenue from contracts with customers		20	29
Operating Segments | Corporate/Other | Revenue from alternative revenue programs
Disaggregation of Revenue
Other sources of revenue		0	0
Operating Segments | Corporate/Other | Leasing revenue
Disaggregation of Revenue
Other sources of revenue		100	105
Operating Segments | Corporate/Other | Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue		0	22
Operating Segments | Corporate/Other | Other
Disaggregation of Revenue
Other sources of revenue		$ 14	$ 16

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Revenue - Narrative (Details) - CAD ($) $ in Millions		12 Months Ended
	Mar. 31, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue
Contract term	20 years
Contract with customer, asset, before allowance		$ 51
Contract asset, non current		50	$ 30
Contract asset, current		21	59
Contract liability		$ 0	$ 2	$ 2
Utilities | Operating Segments | Commodity sales contracts | Minimum
Disaggregation of Revenue
Contract term		1 year
Utilities | Operating Segments | Commodity sales contracts | Maximum
Disaggregation of Revenue
Contract term		5 years
Midstream | Operating Segments | Commodity sales contracts
Disaggregation of Revenue
Contract term		1 year
Corporate/Other
Disaggregation of Revenue
Purchase agreement period		20 years

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Revenue - Contract Assets and Liabilities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Change in Contract with Customer, Asset
Balance, beginning of year	$ 89	$ 59
Additions	30	32
Transfers to accounts receivable	(49)	0
Foreign exchange translation	1	(2)
Balance, end of year	71	89
Change in Contract with Customer, Liability
Balance, beginning of year	2	2
Additions	2	2
Revenue recognized from contract liabilities	(4)	(2)
Balance, end of year	$ 0	$ 2

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Revenue - Schedule of Estimated Revenue Related to Performance Obligations (Details) $ in Millions	Dec. 31, 2020 CAD ($)
Estimated revenue expected to be recognized in the future related to performance obligations	$ 1,956
Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	1,674
Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	258
Other
Estimated revenue expected to be recognized in the future related to performance obligations	24
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	$ 156
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	$ 125
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
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	$ 7
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	$ 156
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	$ 131
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
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
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	$ 153
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	$ 128
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
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
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	$ 153
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	$ 128
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
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
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	$ 150
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	$ 125
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	$ 23
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	$ 2
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Estimated revenue expected to be recognized in the future related to performance obligations	$ 1,188
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	$ 1,037
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	$ 142
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Other
Estimated revenue expected to be recognized in the future related to performance obligations	$ 9
Performance satisfaction period	1 year

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Shareholders’ Equity - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 CAD ($) plan shares	Dec. 31, 2019 CAD ($)
Share-based Compensation Arrangement by Share-based Payment Award
Number of dividend reinvestment plans (plan) | plan	2
Gain on redemption of preferred shares	$ 0
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	$ 4	$ 5
Aggregate intrinsic value of options exercisable	5	3
Intrinsic value of options outstanding	9	12
Mid-Term Incentive And Deferred Share Unit Plans
Share-based Compensation Arrangement by Share-based Payment Award
Compensation expense	16	22
Unrecognized compensation expense	$ 23	22
Minimum | Share Option Plan
Share-based Compensation Arrangement by Share-based Payment Award
Options term	6 years
Minimum | Mid-Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award
Vesting period	36 months
Maximum | Share Option Plan
Share-based Compensation Arrangement by Share-based Payment Award
Options term	10 years
Vesting period	4 years
Intrinsic value of options exercised	$ 1	1
Maximum | Mid-Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award
Vesting period	44 months
Washington Gas
Share-based Compensation Arrangement by Share-based Payment Award
Gain on redemption of preferred shares		$ 4

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Shareholders’ Equity - Schedule of Common Shares Issued and Outstanding (Details) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019
Increase (Decrease) in Stockholders' Equity
Shares issued for cash on exercise of options (shares)		88,082	76,177
Balance, beginning of year		$ 7,215
Balance at end of year		$ 7,041	$ 7,215
Common stock
Increase (Decrease) in Stockholders' Equity
Beginning balance (shares)		279,074,685	275,224,066
Shares issued for cash on exercise of options (shares)		88,082	76,177
Shares issued under DRIP (shares)		331,532	3,774,442
Ending balance (shares)		279,500,000	279,074,685
Balance, beginning of year		$ 6,719	$ 6,654
Shares issued for cash on exercise of options		1	1
Deferred taxes on share issuance cost		(3)	(4)
Shares issued under DRIP	[1]	6	68
Balance at end of year		$ 6,723	$ 6,719

[1] Premium Dividend™, Dividend Reinvestment and Optional Cash Purchase Plan (DRIP). The plan was suspended in December 2019, with the December dividend (paid January 2020) being the last dividend payment eligible for reinvestment by participating shareholders under the DRIP.

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Shareholders' Equity - Schedule of Preferred Shares Issued and Outstanding (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Class of Stock
Preferred stock, value	$ 7,041	$ 7,215
Preferred shares
Class of Stock
Preferred stock, shares	44,000,000	52,000,000
Preferred stock, value	$ 1,077	$ 1,277
Share issuance costs, net of taxes	$ (29)	$ (29)
Preferred shares | Series A
Class of Stock
Preferred stock, shares	6,746,679	5,511,220
Preferred stock, value	$ 169	$ 138
Preferred shares | Series B
Class of Stock
Preferred stock, shares	1,253,321	2,488,780
Preferred stock, value	$ 31	$ 62
Preferred shares | Series C
Class of Stock
Preferred stock, shares	8,000,000	8,000,000
Preferred stock, value	$ 206	$ 206
Preferred shares | Series E
Class of Stock
Preferred stock, shares	8,000,000	8,000,000
Preferred stock, value	$ 200	$ 200
Preferred shares | Series G
Class of Stock
Preferred stock, shares	6,885,823	6,885,823
Preferred stock, value	$ 172	$ 172
Preferred shares | Series H
Class of Stock
Preferred stock, shares	1,114,177	1,114,177
Preferred stock, value	$ 28	$ 28
Preferred shares | Series I
Class of Stock
Preferred stock, shares	0	8,000,000
Preferred stock, value	$ 0	$ 200
Preferred shares | Series K
Class of Stock
Preferred stock, shares	12,000,000	12,000,000
Preferred stock, value	$ 300	$ 300

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Shareholders’ Equity - Summary of Cumulative Redeemable Preferred Shares (Details)	12 Months Ended
	Dec. 31, 2020 $ / shares shares	Dec. 31, 2020 $ / shares shares	Oct. 01, 2019 $ / shares	Oct. 01, 2015 $ / shares
Series A
Class of Stock
Current Yield	3.06%
Annual dividend per share	$ 0.76500
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%
Series B
Class of Stock
Redemption price (per share) | (per share)	$ 25			$ 25.50
Preferred stock floating dividend rate (per share)	$ 0.17069
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%
Series C
Class of Stock
Current Yield	5.29%
Annual dividend per share	$ 1.32250
Redemption price (per share)	$ 25
Series C | Five year United States government bond
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	3.58%	3.58%
Series E
Class of Stock
Current Yield	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%
Series G
Class of Stock
Current Yield	4.24%
Annual dividend per share	$ 1.06050
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%
Series H
Class of Stock
Redemption price (per share) | (per share)	$ 25		$ 25.50
Preferred stock floating dividend rate (per share)	$ 0.195349
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%
Series K
Class of Stock
Current Yield	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%
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%
Series D
Class of Stock
Redemption price (per share)		$ 25.50
Preferred stock shares authorized (shares) | shares	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

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Shareholders’ Equity - Summary of Share Option Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Number of options
Share options outstanding, beginning of year (shares)	7,043,956	6,309,183
Granted (shares)	2,501,755	2,287,385
Exercised (shares)	(88,082)	(76,177)
Forfeited (shares)	(631,549)	(1,165,435)
Expired (in shares)	(463,869)	(311,000)
Share options outstanding, end of year (shares)	8,362,211	7,043,956
Share options exercisable, end of year (shares)	3,607,391	2,921,642,000,000
Exercise price
Share options outstanding, beginning of year (per share)	$ 22.49	$ 25.18
Granted (per share)	19.46	19.12
Exercised (per share)	14.89	14.52
Forfeited (per share)	26.00	27.31
Expired (per share)	27.69	36.16
Share options outstanding, end of year (per share)	21.06	22.49
Share options exercisable, end of year (per share)	$ 23.59	$ 27.70

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Shareholders’ Equity - Summary of Employee Share Option Plan (Details)	12 Months Ended
	Dec. 31, 2020 $ / shares $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award
Options outstanding, Number outstanding (shares) | shares	8,362,211
Options outstanding, Weighted average exercise price (per share)	$ 21.06
Options outstanding, Weighted average remaining contractual life	3 years 10 months 17 days
Options exercisable, Number exercisable (shares) | shares	3,607,391
Options exercisable, Weighted average exercise price (per share)	$ 23.59
Options exercisable, Weighted average remaining contractual life	2 years 11 months 12 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	2,446,392
Options outstanding, Weighted average exercise price (per share)	$ 15.24
Options outstanding, Weighted average remaining contractual life	4 years 25 days
Options exercisable, Number exercisable (shares) | shares	1,359,457
Options exercisable, Weighted average exercise price (per share)	$ 14.92
Options exercisable, Weighted average remaining contractual life	4 years
$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	3,930,345
Options outstanding, Weighted average exercise price (per share)	$ 19.56
Options outstanding, Weighted average remaining contractual life	4 years 9 months 18 days
Options exercisable, Number exercisable (shares) | shares	528,252
Options exercisable, Weighted average exercise price (per share)	$ 19.54
Options exercisable, Weighted average remaining contractual life	4 years 5 months 19 days
$25.09 to $41.00
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)	$ 41.00
Options outstanding, Number outstanding (shares) | shares	1,985,474
Options outstanding, Weighted average exercise price (per share)	$ 31.21
Options outstanding, Weighted average remaining contractual life	1 year 9 months 25 days
Options exercisable, Number exercisable (shares) | shares	1,719,682
Options exercisable, Weighted average exercise price (per share)	$ 31.68
Options exercisable, Weighted average remaining contractual life	1 year 7 months 20 days

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Shareholders’ Equity - Summary of Fair Value Options Granted (Details) - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Stockholders' Equity Note [Abstract]
Fair value per option (per share)	$ 2.61	$ 2.30
Risk-free interest rate (percent)	1.54%	1.48%
Expected life (years)	6 years	6 years
Expected volatility (percent)	25.40%	24.84%
Annual dividend per share (per share)	$ 0.96	$ 0.96
Forfeiture rate (percent)	0.00%	0.00%

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Shareholders’ Equity - Schedule of MTIP and DSUP Activity (Details) - shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
PUs, RUs, and DSUs (number of units)
Balance, beginning of year (units)	6,484,831	9,908,154
Granted (units)	1,158,547	674,971
Vested and paid out (units)	(681,841)	(791,335)
Forfeited (units)	(1,342,832)	(3,377,962)
Units in lieu of dividends (units)	113,429	71,003
Outstanding, end of year (units)	5,732,134	6,484,831

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Net Income Per Common Share - Summary of Net Income per Common Share (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Numerator:
Net income applicable to controlling interests	$ 552	$ 833
Less: Preferred share dividends	(66)	(68)
Gain on redemption of preferred shares (note 25)	0
Net income applicable to common shares	$ 486	$ 769
Denominator:
Weighted average number of common shares outstanding (shares)	279.4	276.9
Dilutive equity instruments (shares)	0.3	0.5
Weighted average number of common shares outstanding - diluted (shares)	279.7	277.4
Basic net income (loss) per common share (per share)	$ 1.74	$ 2.78
Diluted net income (loss) per common share (per share)	$ 1.74	$ 2.77
Anti-dilutive share options excluded from diluted income per share (shares)	7.0	4.3

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Other Income - Schedule of Other Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Other Income and Expenses [Abstract]
Gain (loss) on disposition of assets	$ 223	$ 876
Gain on re-measurement of previously held interest	22	0
Other components of net benefit cost (note 28)	52	27
Interest income and other revenue	9	9
Losses on investments	0	(4)
Total other income	$ 306	$ 908

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Pension Plans and Retiree Benefits - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 CAD ($) division age plan	Dec. 31, 2019 CAD ($)
Defined Benefit Plan Disclosure
Defined contribution plan cost recorded | $	$ 21	$ 20
Rabbi trust | $	$ 28	$ 57
Minimum
Defined Benefit Plan Disclosure
Plan assets investment objective period	3 years
Assumed initial healthcare cost trend rate	2.20%
Ultimate trend rate	2.20%
Maximum
Defined Benefit Plan Disclosure
Plan assets investment objective period	5 years
Assumed initial healthcare cost trend rate	6.00%
Ultimate trend rate	4.50%
Fixed income | SEMCO
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	33.00%
Fixed income | Minimum | WGL Holdings
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	50.00%
Fixed income | Maximum | WGL Holdings
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	70.00%
CANADA | Minimum
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	45.00%
CANADA | Maximum
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	55.00%
Defined Benefit
Defined Benefit Plan Disclosure
Number of divisions | division	5
Defined Benefit | CANADA
Defined Benefit Plan Disclosure
Number of pension plans	1
Defined Benefit | CANADA | Fully funded
Defined Benefit Plan Disclosure
Number of divisions | division	3
Defined Benefit | Foreign Plan
Defined Benefit Plan Disclosure
Number of pension plans	6
Defined Benefit | Foreign Plan | Partially 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 | Foreign Plan
Defined Benefit Plan Disclosure
Number of pension plans	4
Medical benefit eligibility age | age	65
Post-Retirement Benefits | Foreign Plan | Fixed income | WGL Holdings
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	20.00%

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Pension Plans and Retiree Benefits - Summary of Defined Benefit Plans (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Plan assets
Plan assets, Fair value, end of year	$ 2,699
Foreign Plan
Plan assets
Plan assets, Fair value, end of year	2,683
Defined Benefit
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	1,761	$ 1,669
Actuarial loss (gain)	138	184
Current service cost	30	27
Member contributions	0	0
Interest cost	61	69
Benefits paid	(86)	(81)
Expenses paid	(1)	(1)
Settlements	(25)	(24)
Other		0
Foreign exchange translation	(41)	(82)
Balance, end of year	1,837	1,761
Plan assets
Fair value, beginning of year	1,519	1,368
Actual return on plan assets	276	285
Employer contributions	41	43
Member contributions	0	0
Benefits paid	(86)	(81)
Expenses paid	(1)	(1)
Settlements	(25)	(25)
Foreign exchange translation	(41)	(70)
Plan assets, Fair value, end of year	1,683	1,519
Funded status	(154)	(242)
Defined Benefit | CANADA
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	36	34
Actuarial loss (gain)	1	2
Current service cost	3	3
Member contributions	0	0
Interest cost	1	1
Benefits paid	(4)	(4)
Expenses paid	0	0
Settlements	0	0
Other		0
Foreign exchange translation	0	0
Balance, end of year	37	36
Plan assets
Fair value, beginning of year	15	14
Actual return on plan assets	1	1
Employer contributions	4	4
Member contributions	0	0
Benefits paid	(4)	(4)
Expenses paid	0	0
Settlements	0	0
Foreign exchange translation	0	0
Plan assets, Fair value, end of year	16	15
Funded status	(21)	(21)
Defined Benefit | Foreign Plan
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	1,725	1,635
Actuarial loss (gain)	137	182
Current service cost	27	24
Member contributions	0	0
Interest cost	60	68
Benefits paid	(82)	(77)
Expenses paid	(1)	(1)
Settlements	(25)	(24)
Other		0
Foreign exchange translation	(41)	(82)
Balance, end of year	1,800	1,725
Plan assets
Fair value, beginning of year	1,504	1,354
Actual return on plan assets	275	284
Employer contributions	37	39
Member contributions	0	0
Benefits paid	(82)	(77)
Expenses paid	(1)	(1)
Settlements	(25)	(25)
Foreign exchange translation	(41)	(70)
Plan assets, Fair value, end of year	1,667	1,504
Funded status	(133)	(221)
Post-Retirement Benefits
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	430	460
Actuarial loss (gain)	32	(15)
Current service cost	9	9
Member contributions	2	2
Interest cost	15	19
Benefits paid	(24)	(24)
Expenses paid	0	0
Settlements	0	0
Other		1
Foreign exchange translation	(10)	(22)
Balance, end of year	454	430
Plan assets
Fair value, beginning of year	906	791
Actual return on plan assets	157	177
Employer contributions	0	0
Member contributions	2	2
Benefits paid	(24)	(23)
Expenses paid	0	0
Settlements	0	0
Foreign exchange translation	(25)	(41)
Plan assets, Fair value, end of year	1,016	906
Funded status	562	476
Post-Retirement Benefits | CANADA
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	2	2
Actuarial loss (gain)	0	0
Current service cost	0	0
Member contributions	0	0
Interest cost	0	0
Benefits paid	0	0
Expenses paid	0	0
Settlements	0	0
Other		0
Foreign exchange translation	0	0
Balance, end of year	2	2
Plan assets
Fair value, beginning of year	0	0
Actual return on plan assets	0	0
Employer contributions	0	0
Member contributions	0	0
Benefits paid	0	0
Expenses paid	0	0
Settlements	0	0
Foreign exchange translation	0	0
Plan assets, Fair value, end of year	0	0
Funded status	(2)	(2)
Post-Retirement Benefits | Foreign Plan
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	428	458
Actuarial loss (gain)	32	(15)
Current service cost	9	9
Member contributions	2	2
Interest cost	15	19
Benefits paid	(24)	(24)
Expenses paid	0	0
Settlements	0	0
Other		1
Foreign exchange translation	(10)	(22)
Balance, end of year	452	428
Plan assets
Fair value, beginning of year	906	791
Actual return on plan assets	157	177
Employer contributions	0	0
Member contributions	2	2
Benefits paid	(24)	(23)
Expenses paid	0	0
Settlements	0	0
Foreign exchange translation	(25)	(41)
Plan assets, Fair value, end of year	1,016	906
Funded status	$ 564	$ 478

XML

Pension Plans and Retiree Benefits - Schedule of Amount Included in the Consolidated Balance Sheets (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure
Prepaid post-retirement benefits	$ 572	$ 487
Accounts payable and accrued liabilities (a)	(9)	(26)
Future employee obligations	(155)	(227)
Total amounts included in Consolidated Balance Sheets	408	234
Defined Benefit
Defined Benefit Plan Disclosure
Prepaid post-retirement benefits	0	0
Accounts payable and accrued liabilities (a)	(9)	(26)
Future employee obligations	(145)	(216)
Total amounts included in Consolidated Balance Sheets	(154)	(242)
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Prepaid post-retirement benefits	572	487
Accounts payable and accrued liabilities (a)	0	0
Future employee obligations	(10)	(11)
Total amounts included in Consolidated Balance Sheets	$ 562	$ 476

XML

Pension Plans and Retiree Benefits - Schedule of Funded Status Based on Accumulated Benefit Obligation (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
CANADA
Defined Benefit Plan Disclosure
Accumulated benefit obligation	$ (36)	$ (35)
Foreign Plan
Defined Benefit Plan Disclosure
Accumulated benefit obligation	$ (1,704)	$ (1,616)

XML

Pension Plans and Retiree Benefits - Schedule of Benefit Obligation in Excess of Plan Assets (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit
Defined Benefit Plan Disclosure
Projected benefit obligation	$ 1,824	$ 1,757
Plan assets	1,670	1,515
Accumulated benefit obligation	427	1,648
Plan assets	329	1,515
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Projected benefit obligation	14	13
Plan assets	3	3
Accumulated benefit obligation	14	13
Plan assets	$ 3	$ 3

XML

Pension Plans and Retiree Benefits - Summary of Amounts Recorded in Other Comprehensive Income (Loss) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit
Defined Benefit Plan Disclosure
Past service cost	$ 0
Net actuarial gain (loss)	(3)	$ (24)
Recognized in AOCI pre-tax	(3)	(24)
Increase (decrease) by the amount included in deferred tax liabilities	0	9
Net amount in AOCI after-tax	(3)	(15)
Defined Benefit | CANADA
Defined Benefit Plan Disclosure
Past service cost	0
Net actuarial gain (loss)	(9)	(9)
Recognized in AOCI pre-tax	(9)	(9)
Increase (decrease) by the amount included in deferred tax liabilities	2	2
Net amount in AOCI after-tax	(7)	(7)
Defined Benefit | Foreign Plan
Defined Benefit Plan Disclosure
Past service cost	0
Net actuarial gain (loss)	6	(15)
Recognized in AOCI pre-tax	6	(15)
Increase (decrease) by the amount included in deferred tax liabilities	(2)	7
Net amount in AOCI after-tax	4	(8)
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Past service cost	(3)
Net actuarial gain (loss)	(9)	18
Recognized in AOCI pre-tax	(12)	18
Increase (decrease) by the amount included in deferred tax liabilities	3	(9)
Net amount in AOCI after-tax	(9)	9
Post-Retirement Benefits | CANADA
Defined Benefit Plan Disclosure
Past service cost	0
Net actuarial gain (loss)	(1)	0
Recognized in AOCI pre-tax	(1)	0
Increase (decrease) by the amount included in deferred tax liabilities	0	0
Net amount in AOCI after-tax	(1)	0
Post-Retirement Benefits | Foreign Plan
Defined Benefit Plan Disclosure
Past service cost	(3)
Net actuarial gain (loss)	(8)	18
Recognized in AOCI pre-tax	(11)	18
Increase (decrease) by the amount included in deferred tax liabilities	3	(9)
Net amount in AOCI after-tax	$ (8)	$ 9

XML

Pension Plans and Retiree Benefits - Summary of Amounts Recorded in A Regulatory Asset (Liability) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit
Defined Benefit Plan Disclosure
Past service credit	$ 0	$ 1
Net actuarial loss (gain)	68	127
Recognized in regulatory asset (liability)	68	128
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Past service credit	(94)	(105)
Net actuarial loss (gain)	(241)	(156)
Recognized in regulatory asset (liability)	(335)	(261)
CANADA | Defined Benefit
Defined Benefit Plan Disclosure
Past service credit	0	0
Net actuarial loss (gain)	0	0
Recognized in regulatory asset (liability)	0	0
CANADA | Post-Retirement Benefits
Defined Benefit Plan Disclosure
Past service credit	0	0
Net actuarial loss (gain)	0	0
Recognized in regulatory asset (liability)	0	0
Foreign Plan | Defined Benefit
Defined Benefit Plan Disclosure
Past service credit	0	1
Net actuarial loss (gain)	68	127
Recognized in regulatory asset (liability)	68	128
Foreign Plan | Post-Retirement Benefits
Defined Benefit Plan Disclosure
Past service credit	(94)	(105)
Net actuarial loss (gain)	(241)	(156)
Recognized in regulatory asset (liability)	$ (335)	$ (261)

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Pension Plans and Retiree Benefits - Schedule of Net Periodic Benefit Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit
Defined Benefit Plan Disclosure
Current service cost	$ 30	$ 27
Interest cost	61	69
Expected return on plan assets	(82)	(76)
Amortization of past service cost (credit)	0	0
Amortization of net actuarial loss	11	13
Plan settlements	7	4
Other		0
Net benefit cost (income) recognized	27	37
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Current service cost	9	9
Interest cost	15	19
Expected return on plan assets	(40)	(37)
Amortization of past service cost (credit)	(19)	(22)
Amortization of net actuarial loss	(5)	0
Plan settlements	0	0
Other		1
Net benefit cost (income) recognized	(40)	(30)
CANADA | Defined Benefit
Defined Benefit Plan Disclosure
Current service cost	3	3
Interest cost	1	1
Expected return on plan assets	(1)	(1)
Amortization of past service cost (credit)	0	0
Amortization of net actuarial loss	1	1
Plan settlements	0	0
Other		0
Net benefit cost (income) recognized	4	4
CANADA | Post-Retirement Benefits
Defined Benefit Plan Disclosure
Current service cost	0	0
Interest cost	0	0
Expected return on plan assets	0	0
Amortization of past service cost (credit)	0	0
Amortization of net actuarial loss	0	0
Plan settlements	0	0
Other		0
Net benefit cost (income) recognized	0	0
Foreign Plan | Defined Benefit
Defined Benefit Plan Disclosure
Current service cost	27	24
Interest cost	60	68
Expected return on plan assets	(81)	(75)
Amortization of past service cost (credit)	0	0
Amortization of net actuarial loss	10	12
Plan settlements	7	4
Other		0
Net benefit cost (income) recognized	23	33
Foreign Plan | Post-Retirement Benefits
Defined Benefit Plan Disclosure
Current service cost	9	9
Interest cost	15	19
Expected return on plan assets	(40)	(37)
Amortization of past service cost (credit)	(19)	(22)
Amortization of net actuarial loss	(5)	0
Plan settlements	0	0
Other		1
Net benefit cost (income) recognized	$ (40)	$ (30)

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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, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 2,705
Fair value of Plan Assets	$ 2,699
Percentage of Plan Assets	100.00%
Percentage of Plan Asset before net payable	100.00%
Defined Benefit
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 1,683	$ 1,519	$ 1,368
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 1,016	906	791
Fixed income | SEMCO
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	33.00%
Fixed income | Minimum | WGL Holdings
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	50.00%
Fixed income | Maximum | WGL Holdings
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	70.00%
Commingled funds and pooled separate accounts
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 728
Percentage of Plan Asset before net payable	27.00%
Private Equity/Limited Partnership
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 56
Percentage of Plan Asset before net payable	2.00%
Pooled separate accounts
Defined Benefit Plan Disclosure
Total fair value of plan investment		$ 32
Percentage of Plan Asset before net payable		1.00%
Collective trust fund
Defined Benefit Plan Disclosure
Total fair value of plan investment		$ 476
Percentage of Plan Asset before net payable		18.00%
Net payable
Defined Benefit Plan Disclosure
Net payable	$ (6)
Percentage of Plan Assets payable	0.00%
Fair value
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 1,413
Percentage of Plan Assets	52.00%
Fair value | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 16
Percentage of Plan Assets	1.00%
Fair value | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 4
Percentage of Plan Assets	0.00%
Fair value | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 361
Percentage of Plan Assets	13.00%
Fair value | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 1,008
Percentage of Plan Assets	37.00%
Fair value | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 1
Percentage of Plan Assets	0.00%
Fair value | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 23
Percentage of Plan Assets	1.00%
Level 1
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 516
Level 1 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	16
Level 1 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	4
Level 1 | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	361
Level 1 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	135
Level 1 | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Level 1 | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Level 2
Defined Benefit Plan Disclosure
Total fair value of plan investment	897
Level 2 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Level 2 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Level 2 | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Level 2 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	873
Level 2 | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	1
Level 2 | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 23
CANADA
Defined Benefit Plan Disclosure
Percentage of Plan Assets	100.00%
CANADA | Defined Benefit
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 16	$ 15	14
CANADA | Post-Retirement Benefits
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 0	0	0
CANADA | Minimum
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	45.00%
CANADA | Maximum
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	55.00%
CANADA | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Percentage of Plan Assets	13.00%
CANADA | Equities | Canada
Defined Benefit Plan Disclosure
Percentage of Plan Assets	19.00%
CANADA | Equities | Foreign
Defined Benefit Plan Disclosure
Percentage of Plan Assets	25.00%
CANADA | Fixed income
Defined Benefit Plan Disclosure
Percentage of Plan Assets	38.00%
CANADA | Real estate
Defined Benefit Plan Disclosure
Percentage of Plan Assets	5.00%
CANADA | Fair value
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 16
CANADA | Fair value | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	2
CANADA | Fair value | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	3
CANADA | Fair value | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	4
CANADA | Fair value | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	6
CANADA | Fair value | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	1
CANADA | Level 1
Defined Benefit Plan Disclosure
Total fair value of plan investment	15
CANADA | Level 1 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	2
CANADA | Level 1 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	3
CANADA | Level 1 | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	4
CANADA | Level 1 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	6
CANADA | Level 1 | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
CANADA | Level 2
Defined Benefit Plan Disclosure
Total fair value of plan investment	1
CANADA | Level 2 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
CANADA | Level 2 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
CANADA | Level 2 | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
CANADA | Level 2 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
CANADA | Level 2 | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	1
Foreign Plan
Defined Benefit Plan Disclosure
Total fair value of plan investment	2,689
Fair value of Plan Assets	$ 2,683
Percentage of Plan Assets	100.00%
Percentage of Plan Asset before net payable	100.00%
Foreign Plan | Defined Benefit
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 1,667	1,504	1,354
Foreign Plan | Post-Retirement Benefits
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 1,016	$ 906	$ 791
Foreign Plan | Fixed income | WGL Holdings | Post-Retirement Benefits
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	20.00%
Foreign Plan | Commingled funds and pooled separate accounts
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 728
Percentage of Plan Asset before net payable	27.00%
Foreign Plan | Private Equity/Limited Partnership
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 56
Percentage of Plan Asset before net payable	2.00%
Foreign Plan | Pooled separate accounts
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 32
Percentage of Plan Asset before net payable	1.00%
Foreign Plan | Collective trust fund
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 476
Percentage of Plan Asset before net payable	18.00%
Foreign Plan | Collective trust fund | Common stock large cap
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	90.00%
Foreign Plan | Collective trust fund | Income producing property
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	7.00%
Foreign Plan | Collective trust fund | Short term money market
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	3.00%
Foreign Plan | Common stock large cap | WGL Holdings | Defined Benefit
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	50.00%
Foreign Plan | Corporate bonds | WGL Holdings | Post-Retirement Benefits
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	30.00%
Foreign Plan | Net payable
Defined Benefit Plan Disclosure
Net payable	$ (6)
Percentage of Plan Assets payable	0.00%
Foreign Plan | Fair value
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 1,397
Percentage of Plan Assets	52.00%
Foreign Plan | Fair value | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 14
Percentage of Plan Assets	1.00%
Foreign Plan | Fair value | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 1
Percentage of Plan Assets	0.00%
Foreign Plan | Fair value | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 357
Percentage of Plan Assets	13.00%
Foreign Plan | Fair value | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 1,002
Percentage of Plan Assets	37.00%
Foreign Plan | Fair value | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 23
Percentage of Plan Assets	1.00%
Foreign Plan | Level 1
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 501
Foreign Plan | Level 1 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	14
Foreign Plan | Level 1 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	1
Foreign Plan | Level 1 | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	357
Foreign Plan | Level 1 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	129
Foreign Plan | Level 1 | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Foreign Plan | Level 2
Defined Benefit Plan Disclosure
Total fair value of plan investment	896
Foreign Plan | Level 2 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Foreign Plan | Level 2 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Foreign Plan | Level 2 | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Foreign Plan | Level 2 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	873
Foreign Plan | Level 2 | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 23

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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, 2020	Dec. 31, 2019
Defined Benefit
Significant actuarial assumptions used in measuring net benefit plan costs
Average remaining service life of active employees	10 years 2 months 12 days	9 years
Defined Benefit | Minimum
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate (percent)	2.30%	2.90%
Expected long-term rate of return on plan assets (percent)	5.25%	5.75%
Rate of compensation increase (percent)	2.75%	2.75%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate (percent)	1.90%	2.90%
Rate of compensation increase (percent)	1.73%	2.75%
Defined Benefit | Maximum
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate (percent)	3.50%	4.40%
Expected long-term rate of return on plan assets (percent)	7.05%	7.15%
Rate of compensation increase (percent)	4.00%	4.10%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate (percent)	2.80%	3.50%
Rate of compensation increase (percent)	3.93%	4.00%
Post-Retirement Benefits
Significant actuarial assumptions used in measuring net benefit plan costs
Rate of compensation increase (percent)	350.00%	410.00%
Average remaining service life of active employees	13 years	13 years 2 months 12 days
Significant actuarial assumptions used in measuring benefit obligations
Rate of compensation increase (percent)		3.50%
Post-Retirement Benefits | Minimum
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate (percent)	3.10%	3.90%
Expected long-term rate of return on plan assets (percent)	4.03%	4.66%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate (percent)	2.50%	3.10%
Rate of compensation increase (percent)	2.50%
Post-Retirement Benefits | Maximum
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate (percent)	3.60%	4.50%
Expected long-term rate of return on plan assets (percent)	7.05%	7.15%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate (percent)	2.90%	3.60%
Rate of compensation increase (percent)	3.00%

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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, 2020 CAD ($)
Defined Benefit
Defined Benefit Plan Disclosure
Expected employer contributions, 2021	$ 16
Expected benefit payments:
2021	90
2022	91
2023	88
2024	89
2025	90
2026 - 2030	466
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Expected employer contributions, 2021	0
Expected benefit payments:
2021	25
2022	22
2023	22
2024	21
2025	21
2026 - 2030	$ 110

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Commitments, Guarantees, and Contingencies - Summary of Future Payment Commitments (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2015 hour	Dec. 31, 2020 CAD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2016
Other Commitments
Operating leases, 2021			$ 96
Operating leases, 2022			81
Operating leases, 2023			58
Operating leases, 2024			50
Operating leases, 2025			40
Operating leases, 2026 and beyond			125
Total lease payments			450
Commitments, 2021			3,885
Commitments, 2022			3,333
Commitments, 2023			2,834
Commitments, 2024			2,645
Commitments, 2025			2,585
Commitments, 2026 and beyond			21,415
Commitments			36,697
Service agreement payable			153
Service agreement payable in five years			44
Capital projects
Other Commitments
Other commitments, 2021			20
Other commitments, 2022			1
Other commitments, 2023			1
Other commitments, 2024			1
Other commitments, 2025			1
Other commitments, 2026 and beyond			1
Other commitments			25
Environmental
Other Commitments
Other commitments, 2021			7
Other commitments, 2022			3
Other commitments, 2023			1
Other commitments, 2024			1
Other commitments, 2025			1
Other commitments, 2026 and beyond			0
Other commitments			13
Merger commitments
Other Commitments
Other commitments, 2021			5
Other commitments, 2022			2
Other commitments, 2023			2
Other commitments, 2024			2
Other commitments, 2025			1
Other commitments, 2026 and beyond			3
Other commitments			15
Cumulative expenses incurred but not yet paid				$ 12
Land Purchase Commitment
Other Commitments
Other commitments, 2021			20
Other commitments, 2022			0
Other commitments, 2023			0
Other commitments, 2024			0
Other commitments, 2025			0
Other commitments, 2026 and beyond			0
Other commitments			20
Post Acquisition Contingent Payments
Other Commitments
Other commitments, 2021			0
Other commitments, 2022			16
Other commitments, 2023			0
Other commitments, 2024			0
Other commitments, 2025			0
Other commitments, 2026 and beyond			0
Other commitments			16
Contingent payments			16
Natural Gas
Other Commitments
Purchase obligations, 2021			1,974
Purchase obligations, 2022			2,075
Purchase obligations, 2023			1,858
Purchase obligations, 2024			1,863
Purchase obligations, 2025			1,901
Purchase obligations, 2026 and beyond			17,612
Purchase obligations			27,283
Natural Gas | Merger commitments
Other Commitments
Other commitments				70
Propane
Other Commitments
Purchase obligations, 2021			407
Purchase obligations, 2022			199
Purchase obligations, 2023			161
Purchase obligations, 2024			108
Purchase obligations, 2025			83
Purchase obligations, 2026 and beyond			258
Purchase obligations			1,216
Crude Oil and Condensate Purchase
Other Commitments
Purchase obligations, 2021			184
Purchase obligations, 2022			0
Purchase obligations, 2023			0
Purchase obligations, 2024			0
Purchase obligations, 2025			0
Purchase obligations, 2026 and beyond			0
Purchase obligations			184
Electricity purchase
Other Commitments
Purchase obligations, 2021			463
Purchase obligations, 2022			287
Purchase obligations, 2023			106
Purchase obligations, 2024			29
Purchase obligations, 2025			3
Purchase obligations, 2026 and beyond			0
Purchase obligations			888
Service agreements
Other Commitments
Purchase obligations, 2021			48
Purchase obligations, 2022			32
Purchase obligations, 2023			26
Purchase obligations, 2024			27
Purchase obligations, 2025			27
Purchase obligations, 2026 and beyond			282
Purchase obligations			442
Service agreement term, (EOH/CT) | hour		124,000
Service agreement term		25 years
Service agreement payment period	12 years
Service agreements | Ridley Terminals Inc.
Other Commitments
Lease term (years)					20 years
Pipeline and storage services
Other Commitments
Purchase obligations, 2021			661
Purchase obligations, 2022			637
Purchase obligations, 2023			621
Purchase obligations, 2024			564
Purchase obligations, 2025			528
Purchase obligations, 2026 and beyond			3,134
Purchase obligations			6,145
Electricity, renewable energy credits
Other Commitments
Purchase obligations			$ 21
Leak mitigation | Merger commitments
Other Commitments
Other commitments, 2023				8
Other commitments, 2025				$ 2

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Commitments, Guarantees, and Contingencies - Narrative (Details) $ in Thousands	1 Months Ended
	Jan. 31, 2021 USD ($)	Jun. 30, 2019 USD ($)	Dec. 31, 2020 CAD ($)	Dec. 18, 2020 USD ($)	Dec. 31, 2019 CAD ($)
Commitments, Contingencies And Guaranteed [Line Items]
Guarantee obligations			$ 0
Other long term receivables			18,000,000		$ 33,000,000
Regulatory assets			15,000,000		18,000,000
Restricted cash included in accounts receivable (note 29)			9,000,000		$ 0
Antero Contract
Commitments, Contingencies And Guaranteed [Line Items]
Damages awarded		$ 96,000
Regulatory assets			7,000,000
Restricted cash included in accounts receivable (note 29)			$ 9,000,000
Antero Contract | WGL Holdings
Commitments, Contingencies And Guaranteed [Line Items]
Adjustments to working capital		45,000
Antero Contract | Washington Gas
Commitments, Contingencies And Guaranteed [Line Items]
Damages awarded		$ 11,000
Maryland Show-Cause Order | Washington Gas
Commitments, Contingencies And Guaranteed [Line Items]
Estimated penalties				$ 750
Maryland Show-Cause Order | Washington Gas | Subsequent Event
Commitments, Contingencies And Guaranteed [Line Items]
Penalty paid	$ 750

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Related Party Transactions - Summary of Related Party Amounts Included in Balance Sheets (Details) - CAD ($)	Dec. 31, 2020	Dec. 31, 2019
Related Party Transaction
Due from related parties, Accounts receivable	$ 5,000,000	$ 18,000,000
Due from related parties, Long-term investments and other assets	0	45,000,000
Due from related parties	5,000,000	63,000,000
Due to related parties, Accounts payable	3,000,000	$ 3,000,000
Petrogas | AltaGas
Related Party Transaction
Credit facility maximum borrowing capacity	100,000,000
Committed amount	$ 50,000,000

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Related Party Transactions - Schedule of Related Party Transactions (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Related Party Transactions [Abstract]
Revenue	$ 92	$ 115
Cost of sales	12	13
Operating and administrative recoveries	1	(2)
Other income	$ 3	$ 3

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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, 2020	Dec. 31, 2019
Supplemental Cash Flow Elements [Abstract]
Accounts receivable	$ 21	$ 168
Inventory	32	(2)
Other current assets	1	(85)
Regulatory assets - current	(33)	7
Accounts payable and accrued liabilities	(41)	(280)
Customer deposits	(2)	(17)
Regulatory liabilities - current	(55)	34
Risk management liabilities - current	(1)	1
Other current liabilities	4	(6)
Other operating assets and liabilities	(129)	(52)
Changes in operating assets and liabilities	$ (203)	$ (232)

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Supplemental Cash Flow Information - Changes in Non-Cash Activities and Supplemental Cash Payments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Supplemental Cash Flow Elements [Abstract]
Common shares issued under DRIP	$ (6)	$ (68)
Net right-of-use assets obtained in exchange for new operating lease liabilities	(227)	(50)
Net right-of-use assets obtained in exchange for new finance lease liabilities	(6)	(5)
Capital expenditures included in accounts payable and accrued liabilities	(33)	(7)
Interest paid (net of capitalized interest)	276	352
Income taxes paid	$ 23	$ 67

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Supplemental Cash Flow Information - Reconciliation of Cash and Restricted Cash Balances (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Supplemental Cash Flow Elements [Abstract]
Cash and cash equivalents	$ 32	$ 57
Restricted cash holdings from customers - current	3	4
Restricted cash holdings from customers - non-current	2	4
Restricted cash included in prepaid expenses and other current assets	9	25
Restricted cash included in long-term investments and other assets	19	32
Restricted cash included in accounts receivable (note 29)	9	0
Cash, cash equivalents and restricted cash per consolidated statement of cash flow	$ 74	$ 122	$ 201

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Segmented Information - Narrative (Details)	12 Months Ended
	Dec. 31, 2020 segment
Segment Reporting [Abstract]
Number of segments	2

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Segmented Information - Reconciliation Of Segment Revenue (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Revenues	$ 5,587	$ 5,495
Utilities
Revenues	3,817	4,044
Midstream
Revenues	1,635	1,228
Corporate/Other
Revenues	135	223
Intersegment revenue
Revenues	1	32
Intersegment revenue | Utilities
Revenues	0	0
Intersegment revenue | Midstream
Revenues	1	32
Intersegment revenue | Corporate/Other
Revenues	0	0
Operating Segments
Revenues	5,588	5,527
Operating Segments | Utilities
Revenues	3,817	4,044
Operating Segments | Midstream
Revenues	1,636	1,260
Operating Segments | Corporate/Other
Revenues	$ 135	$ 223

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Segmented Information - Geographic Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Revenues from External Customers and Long-Lived Assets
Revenues	$ 5,565	$ 5,570
Property, plant and equipment	10,888	10,125
Operating right-of-use assets	372	170
CANADA
Revenues from External Customers and Long-Lived Assets
Revenues	1,512	1,245
Property, plant and equipment	3,149	2,682
Operating right-of-use assets	293	85
United States
Revenues from External Customers and Long-Lived Assets
Revenues	4,053	4,325
Property, plant and equipment	7,739	7,443
Operating right-of-use assets	$ 79	$ 85

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Segmented Information - Schedule of Segment Composition (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information
Revenues	$ 5,587	$ 5,495
Cost of sales	(3,178)	(3,227)
Operating and administrative	(1,267)	(1,299)
Accretion expenses	(5)	(5)
Depreciation and amortization	(414)	(438)
Provision on assets (note 6)	(109)	(416)
Income from equity investments	49	141
Other income (loss)	306	908
Foreign exchange gains (losses)	4	(1)
Interest expense	(274)	(346)
Income before income taxes	699	812
Net additions (reductions) to property, plant and equipment	825	(1,089)
Net additions (reductions) to intangible assets	10	37
Utilities
Segment Reporting Information
Revenues	3,817	4,044
Midstream
Segment Reporting Information
Revenues	1,635	1,228
Provision on assets (note 6)	(106)	(34)
Corporate/Other
Segment Reporting Information
Revenues	135	223
Provision on assets (note 6)		(382)
Operating Segments
Segment Reporting Information
Revenues	5,588	5,527
Operating Segments | Utilities
Segment Reporting Information
Revenues	3,817	4,044
Cost of sales	(2,156)	(2,448)
Operating and administrative	(942)	(960)
Accretion expenses	0	0
Depreciation and amortization	(295)	(276)
Provision on assets (note 6)	(1)	0
Income from equity investments	5	19
Other income (loss)	259	29
Foreign exchange gains (losses)	0	0
Interest expense	0	0
Income before income taxes	687	408
Net additions (reductions) to property, plant and equipment	740	840
Net additions (reductions) to intangible assets	3	23
Operating Segments | Midstream
Segment Reporting Information
Revenues	1,636	1,260
Cost of sales	(994)	(760)
Operating and administrative	(254)	(213)
Accretion expenses	(4)	(4)
Depreciation and amortization	(86)	(89)
Provision on assets (note 6)	(105)	(34)
Income from equity investments	44	122
Other income (loss)	24	28
Foreign exchange gains (losses)	(26)	(5)
Interest expense	0	0
Income before income taxes	235	305
Net additions (reductions) to property, plant and equipment	136	351
Net additions (reductions) to intangible assets	3	5
Operating Segments | Corporate/Other
Segment Reporting Information
Revenues	135	223
Cost of sales	(29)	(51)
Operating and administrative	(71)	(126)
Accretion expenses	(1)	(1)
Depreciation and amortization	(33)	(73)
Provision on assets (note 6)	(3)	(382)
Income from equity investments	0	0
Other income (loss)	23	851
Foreign exchange gains (losses)	30	4
Interest expense	(274)	(346)
Income before income taxes	(223)	99
Net additions (reductions) to property, plant and equipment	(51)	(2,280)
Net additions (reductions) to intangible assets	4	9
Intersegment Elimination
Segment Reporting Information
Revenues	1	32
Cost of sales	1	32
Operating and administrative	0	0
Accretion expenses	0	0
Depreciation and amortization	0	0
Provision on assets (note 6)	0	0
Income from equity investments	0	0
Other income (loss)	0	0
Foreign exchange gains (losses)	0	0
Interest expense	0	0
Income before income taxes	0	0
Net additions (reductions) to property, plant and equipment	0	0
Net additions (reductions) to intangible assets	0	0
Intersegment Elimination | Utilities
Segment Reporting Information
Revenues	0	0
Intersegment Elimination | Midstream
Segment Reporting Information
Revenues	1	32
Intersegment Elimination | Corporate/Other
Segment Reporting Information
Revenues	$ 0	$ 0

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Segmented Information - Schedule of Goodwill and Total Assets by Segment (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information
Goodwill (note 11)	$ 5,039	$ 3,942	$ 4,068
Segmented assets	21,532	19,795
Operating Segments | Utilities
Segment Reporting Information
Goodwill (note 11)	3,706	3,781
Segmented assets	13,675	13,719
Operating Segments | Midstream
Segment Reporting Information
Goodwill (note 11)	1,333	161
Segmented assets	7,320	5,265
Operating Segments | Corporate/Other
Segment Reporting Information
Goodwill (note 11)	0	0
Segmented assets	$ 537	$ 811