EX-13.1 2 altagasaif-2019.htm EXHIBIT 13.1 Exhibit

























ALTAGAS LTD.
Annual Information Form

For the year ended December 31, 2019

Dated: February 27, 2020


    


TABLE OF CONTENTS
    









 
 
 
AltaGas Ltd. 2019 Annual Information Form 1

    


GENERAL INFORMATION
Unless otherwise noted, the information contained in this AIF is stated as at December 31, 2019 and all dollar amounts
in this AIF are in Canadian dollars. Financial information is presented in accordance with United States generally accepted accounting principles. For an explanation of certain terms and abbreviations used in this AIF, see the "Glossary" of this AIF.
FORWARD-LOOKING INFORMATION AND STATEMENTS
This AIF contains forward-looking information (forward-looking statements). Words such as "may", "can", "would", "could", "should", "will", "intend", "plan", "anticipate", "believe", "aim", "seek", "propose", "contemplate", "estimate", "focus", "strive", "forecast", "expect", "project", "target", "potential", "objective", "continue", "outlook", "vision", "opportunity", and similar expressions suggesting future events or future performance, as they relate to the Corporation or any affiliate of the Corporation, are intended to identify forward-looking statements. In particular, this AIF contains forward-looking statements with respect to, among other things, business objectives, expected growth, results of operations, performance, business projects and opportunities and financial results.
Specifically, such forward-looking statements included in this document include, but are not limited to, statements with respect to the following: the Corporation’s long-term strategy in regard to its Utilities, Midstream and Power segments; expectation that the Corporation will target opportunities to develop high-quality natural gas and NGL assets that complement its existing infrastructure; the Corporation's 2020 priorities; expectations to increase utilization and export volumes at RIPET; expected $900 million growth capital program in 2020; targeted 10 percent increase in Utilities rate base; expiration of the Northwest Hydro operating agreement in January 2021; timing of material regulatory filings, proceedings and decisions in the Utilities business; expected conditions to closing and closing date of the ACI Arrangement; expected in-service and completion dates for current projects in the Midstream business; expected effective dates of material environmental legislation; and duration of the suspension of the DRIP program. .
These statements involve known and unknown risks, uncertainties and other factors that may cause actual results, events, and achievements to differ materially from those expressed or implied by such statements. Such statements reflect AltaGas' current expectations, estimates, and projections based on certain material factors and assumptions at the time the statement was made. Material assumptions include: expected commodity supply, demand and pricing; volumes and rates; exchange rates; inflation; interest rates; credit rating; regulatory approvals and policies; future operating and capital costs; project completion dates; capacity expectations; implications of recent U.S. tax legislation changes; and the outcomes of significant commercial contract negotiation.
AltaGas’ forward-looking statements are subject to certain risks and uncertainties which could cause results or events to differ from current expectations, including, without limitation: health and safety risks; operating risks; infrastructure risks; service interruptions; regulatory risks; litigation risk; decommissioning, abandonment and reclamation costs; climate and carbon tax risks; reputation risk; weather data; Indigenous land and rights claims; crown duty to consult with Indigenous peoples; changes in laws; capital market and liquidity risks; general economic conditions; internal credit risk; foreign exchange risk; debt financing, refinancing, and debt service risk; interest rates; cyber security, information, and control systems; technical systems and processes incidents; dependence on certain partners; growth strategy risk; construction and development; RIPET rail and marine transport; impact of competition in AltaGas' Midstream and Power businesses; commitments associated with regulatory approvals for the acquisition of WGL; counterparty credit risk; composition risk; collateral; reg agreements; non-controlling interests in investments; delays in U.S. federal government budget appropriations; consumption risk; market risk; market value of common shares and other securities; variability of dividends; potential sales of additional shares; volume throughput; natural gas supply risk; risk management costs and limitations; underinsured and uninsured losses; Cook Inlet gas supply; securities class action suits and derivative suits; electricity and resource adequacy prices; cost of providing retirement plan benefits; labor relations; key personnel; failure of service providers; compliance with Section 404(a) of Sarbanes-Oxley Act; integration of WGL; and the other factors discussed under the heading "Risk Factors" in this AIF.

 
 
 
AltaGas Ltd. 2019 Annual Information Form 2

    


Many factors could cause AltaGas' or any particular business segment's actual results, performance, or achievements to vary from those described in this AIF, including, without limitation, those listed above and the assumptions upon which they are based proving incorrect. These factors should not be construed as exhaustive. Should one or more of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary materially from those described in this AIF as intended, planned, anticipated, believed, sought, proposed, estimated, forecasted, expected, projected, or targeted and such forward-looking statements included in this AIF should not be unduly relied upon. The impact of any one assumption, risk, uncertainty, or other factor on a particular forward-looking statement cannot be determined with certainty because they are interdependent and AltaGas’ future decisions and actions will depend on management’s assessment of all information at the relevant time. Such statements speak only as of the date of this AIF. AltaGas does not intend, and does not assume any obligation, to update these forward-looking statements except as required by law. The forward-looking statements contained in this AIF are expressly qualified by these cautionary statements.
Financial outlook information contained in this AIF about prospective results of operations, financial position, or cash flow is based on assumptions about future events, including economic conditions and proposed courses of action, based on management's assessment of the relevant information currently available. Readers are cautioned that such financial outlook information contained in this AIF should not be used for purposes other than for which it is disclosed herein.
GLOSSARY
Unless the context otherwise requires, terms used in this AIF have the following meanings and references to agreements include any amendments, restatements, modifications, or supplements in effect as of the date hereof:

"ACI" means AltaGas Canada Inc.;
"ACI IPO" means initial public offering of common shares of ACI;
"AER" means the Alberta Energy Regulator;
"AESO" means the Alberta Electric System Operator;
"AIF" means this Annual Information Form;
"AIJVLP" means AltaGas Idemitsu Joint Venture Limited Partnership;
"AltaGas", the "Company", or the "Corporation" means AltaGas Ltd., including, where the context requires, the affiliates of AltaGas Ltd.;
"ARB" means the California Air Resources Board;
"ASC" means the Alberta Securities Commission;
"AUI" means AltaGas Utilities Inc.;
"B.C." or "BC" means the province of British Columbia in Canada;
"Bbls" means stock tank barrels of ethane and other NGLs, expressed in standard 42 U.S. gallon barrels or 34.972 imperial gallon barrels;
"Bbls/d" means Bbls per day;
"Bcf" means billion cubic feet or 1,000,000 Mcf of natural gas;

 
 
 
AltaGas Ltd. 2019 Annual Information Form 3

    


"Bcf/d" means Bcf per day;
"Birchcliff" means Birchcliff Energy Ltd.;
"Black Swan" means Black Swan Energy Ltd.;
"Blair Creek facility" means the Blair Creek processing facility located approximately 140 km northwest of Fort St. John, British Columbia, owned by AltaGas’ indirect wholly-owned subsidiary AltaGas Northwest Processing Limited Partnership;
"Blythe" means Blythe Energy Inc.;
"Blythe Energy Center" means the 507 MW gas-fired generation facility located near Blythe, California, together with the related 67 miles transmission lines, owned by AltaGas’ indirect wholly-owned subsidiary Blythe;
"Board of Directors" means the board of directors of AltaGas, as from time to time constituted;
"Brush II" means the 70 MW gas-fired generation facility in Colorado, owned by AltaGas’ indirect wholly-owned subsidiary AltaGas Brush Energy Inc.;
"C&I" means commercial and industrial;
"CAISO" means the California Independent System Operator;
"CBCA" means the Canada Business Corporations Act, R.S.C. 1985, c. C 44, as amended from time to time, including the regulations from time to time promulgated thereunder;
"CCAA" means the Companies’ Creditors Arrangement Act, R.S.C. 1985, c. C 36, as amended from time to time, including the regulations from time to time promulgated thereunder;
"CCEMA" means the Climate Change and Emissions Management Act, S.A. 2003, C-16.7, as amended from time to time, including the regulations from time to time promulgated thereunder;
"CCIR" means the Carbon Competitiveness Incentive Regulation, A.R. 255/2017 under the CCEMA, as amended from time to time;
"Central Penn" means the Central Penn pipeline, a 185-mile pipeline originating in Susquehanna County, Pennsylvania and extending to Lancaster County, Pennsylvania;
"CFIUS" means the Committee on Foreign Investment in the United States;
"CINGSA" means Cook Inlet Natural Gas Storage Alaska, LLC;
"CINGSA Storage facility" means the in-field storage facility in the Cook Inlet area of Alaska owned and operated by CINGSA;
"CN" means Canadian National Railway Company;
"CO2" means carbon dioxide;
"CO2e" means carbon dioxide equivalent;
"Common Shares" means common shares of AltaGas Ltd.;

 
 
 
AltaGas Ltd. 2019 Annual Information Form 4

    


"Constitution" means Constitution Pipeline Company, LLC, an entity formed to create a pipeline to transport natural gas from the Marcellus region in northern Pennsylvania to northeastern markets;
"CPI" means the Consumer Price Index;
"CPUC" means the California Public Utilities Commission;
"DBRS" means DBRS Limited and its successors;
"Degree Day" means the amount that the daily mean temperature deviates below 65 degrees Fahrenheit at SEMCO Gas, ENSTAR, and Washington Gas, such that a one degree difference equates to one Degree Day;
"Dekatherm" means 10 Therms;
"DOEE" means the District of Columbia Department of Energy and Environment;
"EEEP" means the Edmonton ethane extraction plant and related facilities, AltaGas’ interest being owned by its indirect wholly-owned subsidiary AltaGas Extraction and Transmission Limited Partnership;
"EH&S Committee" means the Environment, Health and Safety Committee of the Board of Directors;
"EHS Management System" means AltaGas’ Environmental, Health & Safety Management System;
"ENSTAR" means the natural gas distribution business conducted by SEMCO Energy in Alaska under the name ENSTAR Natural Gas Company;
"EQM" means EQM Gathering Opco, LLC;
"EQT" means EQT Midstream Partners, LP;
"ESA" means Energy Storage Resource Adequacy Purchase Agreement;
"ESG" means Environment, Social & Governance;
"FERC" means the United States Federal Energy Regulatory Commission;
"Ferndale terminal" means the storage, distribution, and export facility for bulk shipments of propane, and butane located on the west coast near Ferndale, Washington, and owned by a subsidiary of Petrogas;
"FID" means final investment decision;
"Fitch" means Fitch Ratings Inc.;
"Forrest Kerr" means the 195 MW run-of-river hydroelectric facility, one of the three run-of-river hydroelectric facilities in northwest British Columbia that forms part of the Northwest Hydro facilities;
"g" means grams;
"GHG" means greenhouse gas;
"GJ" means gigajoule or 1,000,000,000 joules;

 
 
 
AltaGas Ltd. 2019 Annual Information Form 5

    


"Gordondale facility" means the Gordondale Gas processing facility in the Gordondale area of the Montney reserve area approximately 100 km northwest of Grande Prairie, Alberta, owned by AltaGas’ indirect wholly-owned subsidiary AltaGas Northwest Processing Limited Partnership;
"GSAs" means Groundwater Sustainability Agencies;
"GWh" means gigawatt-hour or 1,000,000,000 watt-hours; the watt-hour is equal to one watt of power flowing steadily for one hour;
"Hampshire" or "Hampshire Gas" means Hampshire Gas Company, a subsidiary of WGL that provides regulated interstate natural gas storage services to Washington Gas under a FERC approved interstate storage service tariff;
"Harmattan" means the combined Harmattan gas processing facility and extraction plant and associated facilities, owned by AltaGas’ indirect wholly-owned subsidiary Harmattan Gas Processing Limited Partnership;
"HE" means Hearing Examiner;
"Heritage Gas" means Heritage Gas Limited;
"Idemitsu" means Idemitsu Kosan Co., Ltd.;
"IRIP" means the Infrastructure Reliability Improvement Program;
"JEEP" means the Joffre ethane extraction plant and related facilities;
"Kelt" means Kelt Exploration (LNG) Ltd;
"km" means kilometer;
"kWh" means kilowatt hour;
"LNG" means liquefied natural gas;
"LPG" means liquefied petroleum gas;
"Marquette Connector Pipeline" means the recently completed pipeline that is owned and operated by SEMCO Gas and connects the Great Lakes Gas Transmission pipeline to the Northern Natural Gas pipeline in Marquette, Michigan;
"Mcf" means a thousand cubic feet of natural gas at standard imperial conditions of measurement;
"Mcf/d" means Mcf per day;
"McLymont Creek" means the 66 MW run-of-river hydroelectric facility, one of the three run-of-river hydroelectric facilities in northwest British Columbia that forms part of the Northwest Hydro facilities;
"MDth" means millions of Dekatherms;
"Merger Agreement" means the agreement and plan of merger dated as of January 25, 2017, among AltaGas, Merger Sub and WGL;
"Merger Sub" means Wrangler Inc., a Virginia corporation and an indirect wholly-owned subsidiary of AltaGas;
"MGP" means manufactured gas plant;

 
 
 
AltaGas Ltd. 2019 Annual Information Form 6

    


"Mmcf" means a million cubic feet of natural gas at standard conditions of measurement;
"Mmcf/d" means Mmcf per day;
"Moody's" means Moody's Investor Service;
"Mountain Valley" means Mountain Valley pipeline, an equity investment of WGL Midstream;
"MPSC" means the Michigan Public Service Commission;
"MRP" means Main Replacement Program;
"MRU" means Mount Royal University;
"MTN" means medium term notes issued from time to time under either the amended and restated trust 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 run-of-river hydroelectric facilities in northwest British Columbia, being Forrest Kerr, McLymont Creek, and Volcano Creek;
"Nova Chemicals" means NOVA Chemicals Corporation;
"NOx" means nitrogen oxides;
"NTSB" means the National Transportation Safety Board;
"NYSDEC" means the New York State Department of Environmental Conservation;

 
 
 
AltaGas Ltd. 2019 Annual Information Form 7

    


"O2" means oxygen;
"Painted Pony" means Painted Pony Energy Ltd.;
"PEEP" means the Pembina Empress extraction plant and related facilities;
"Pembina" means Pembina Infrastructure and Logistics LP;
"Petrogas" means Petrogas Energy Corp., a privately held leading North American integrated midstream company in which AltaGas Idemitsu Joint Venture Limited Partnership has an approximate two-thirds ownership interest;
"PG&E" means Pacific Gas & Electric Company;
"Plan" means the Premium 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, owned by AltaGas’ indirect wholly-owned subsidiary AltaGas Pomona Energy Inc.;
"Pomona Energy Storage facility" means the 20 MW lithium ion battery storage facility in Pomona, California, owned by AltaGas’ indirect wholly-owned subsidiary AltaGas Pomona Energy Storage Inc.;
"Pool" means the scheme operated by the AESO for (i) exchanges of electric energy, and (ii) financial settlement for the exchange of electric energy;
"PPA" means power purchase agreement;
"Preferred Shares" means the preferred shares of AltaGas Ltd. as a class, including, without limitation, the Series A Shares, Series B Shares, Series C Shares, Series D Shares, Series E Shares, Series F Shares, Series G Shares, Series H Shares, Series I Shares, Series J Shares, Series K Shares, and Series L Shares;
"PROJECTpipes" means Washington Gas' 40-year accelerated pipeline replacement program, that was launched in 2014 in the District of Columbia and is designed to enhance the safety and reliability of its system;
"PRPA" means Prince Rupert Port Authority;
"PSC of DC" means the Public Service Commission of the District of Columbia;
"PSC of MD" means the Maryland Public Service Commission;
"Put Notice" means the notice received by AIJVLP from SAM of its exercise of a put option with respect to its approximate one-third interest in Petrogas.
"Put Option" means the put option with respect to SAM's approximate one-third interest in Petrogas;
"RCA" means the Regulatory Commission of Alaska;
"Rep Agreements" mean the Representation, Management and Processing Agreements at Harmattan;
"RILE LP" means Ridley Island LPG Export Limited Partnership, a limited partnership of which AltaGas’ subsidiaries hold a 70 percent interest and Vopak holds a 30 percent interest;

 
 
 
AltaGas Ltd. 2019 Annual Information Form 8

    


"Ring Fenced Entities" means Washington Gas and the SPE;
"RIPET" means the Ridley Island Propane Export Terminal, the propane export terminal constructed by AltaGas' subsidiary, Ridley Island LPG Export Limited Partnership, to ship up to 1.2 million tonnes of propane per annum and to be located on a portion of land leased by Ridley Terminals Inc. from the PRPA, located on Ridley Island, near Prince Rupert, British Columbia;
"Ripon" means the 49.5 MW gas-fired generation facility in Ripon, California, owned by AltaGas’ indirect wholly-owned subsidiary AltaGas Ripon Energy Inc.;
"ROE" means return on equity;
"Royal Vopak" means Koninklijke Vopak N.V., a public company incorporated under the laws of the Netherlands;
"RTI" means Ridley Terminals Inc.;
"S&P" means Standard & Poor's Ratings Services and its successors;
"SAM" means Sam Holdings Ltd.;
"Sarbanes-Oxley" means the Sarbanes-Oxley Act of 2002;
"SAVE" means Steps to Advance Virginia's Energy Plan;
"SCC of VA" means the Commonwealth of Virginia State Corporation Commission;
"SCE" means Southern California Edison Company;
"SEDAR" means System for Electronic Document Analysis and Retrieval, at www.sedar.com;
"SEMCO Energy" means SEMCO Energy, Inc.;
"SEMCO Gas" means the Michigan natural gas distribution business conducted by SEMCO Energy in Michigan under the name SEMCO Energy Gas Company;
"Series A Shares" means the cumulative redeemable 5-year fixed rate reset preferred shares, Series A, of AltaGas;
"Series B Shares" means the cumulative redeemable floating rate preferred shares, Series B, of AltaGas
"Series C Shares" means the cumulative redeemable 5-year fixed rate reset preferred shares, Series C, of AltaGas (US dollar);
"Series D Shares" means the cumulative redeemable floating rate preferred shares, Series D, of AltaGas (US dollar);
"Series E Shares" means the cumulative redeemable 5-year fixed rate reset preferred shares, Series E, of AltaGas;
"Series F Shares" means the cumulative redeemable floating rate preferred shares, Series F, of AltaGas;
"Series G Shares" means the cumulative redeemable 5-year fixed rate reset preferred shares, Series G, of AltaGas;
"Series H Shares" means the cumulative redeemable floating rate preferred shares, Series H, of AltaGas;
"Series I Shares" means the cumulative redeemable 5-year minimum fixed rate reset preferred shares, Series I, of AltaGas;

 
 
 
AltaGas Ltd. 2019 Annual Information Form 9

    


"Series J Shares" means the cumulative redeemable floating rate preferred shares, Series J, of AltaGas;
"Series K Shares" means the cumulative redeemable 5-year minimum fixed rate reset preferred shares, Series K, of AltaGas;
"Series L Shares" means the cumulative redeemable floating rate preferred shares, Series L of AltaGas;
"SGER" means the Specified Gas Emitters Regulation under the CCEMA, which was replaced with the CCIR on January 1, 2018;
"SGMA" means the Sustainable Groundwater Management Act;
"Share Options" means options to acquire Common Shares granted pursuant to AltaGas' share option plan;
"Shareholders" mean the holders of Common Shares;
"Shell Energy" means Shell Energy North America (US), LP;
"SOS" means Standard offer Service;
"SPE" means Wrangler SPE LLC, a wholly-owned special purpose entity subsidiary of WGL incorporated as a bankruptcy remote entity;
"Stonewall System" means the Stonewall Gas Gathering System;
"STRIDE" means Strategic Infrastructure Development Enhancement Plan;
"TCJA" means the Tax Cuts and Jobs Act of 2017;
"TIER" means Technology Innovation and Emissions Reduction;
"Tourmaline" means Tourmaline Oil Corp.;
"Townsend 2A" means the first 99 Mmcf/d train of the Townsend expansion, located on the existing Townsend facility site, adjacent to the currently operating Townsend facility;
"Townsend 2B" means the proposed 198 Mmcf/d C3+ deep cut gas processing facility to be located on the existing Townsend facility site, adjacent to the currently operating Townsend facility and anticipated to be on-stream in the fourth quarter of 2020;
"Townsend complex" means, collectively, the Townsend facility, Townsend 2A, and Townsend 2B;
"Townsend facility" means the 198 Mmcf/d Townsend shallow-cut processing facility in northeast British Columbia owned by AltaGas Northwest Processing Limited Partnership;
"Transco" means Transcontinental Gas Pipeline Company LLC;
"TSX" means the Toronto Stock Exchange;
"UESC" means Utility Energy Savings Contracts;
"United States", "US", or "U.S." means the United States of America;
"US dollar" or "US$" means currency in the form of United States dollars;

 
 
 
AltaGas Ltd. 2019 Annual Information Form 10

    


"USEPA" means United States Environmental Protection Agency;
"Volcano Creek" means the 16 MW run-of-river hydroelectric facility, one of the three run-of-river hydroelectric facilities in northwest British Columbia that forms part of the Northwest Hydro facilities;
"Vopak" means Vopak Development Canada Inc., a wholly-owned subsidiary of Royal Vopak;
"Washington Gas" means Washington Gas Light Company, a subsidiary of WGL that sells and delivers natural gas primarily to retail customers in the District of Columbia, Maryland and Virginia in accordance with tariffs approved by the Public Service Commission of the District of Columbia, the Maryland Public Service Commission and the Commonwealth of Virginia State Corporation Commission;
"Washington Gas $4.25 Shares" means the US$4.25 series cumulative preferred shares of Washington Gas that were redeemed by Washington Gas on December 20, 2019;
"Washington Gas $4.80 Shares" means the US$4.80 series cumulative preferred shares of Washington Gas that were redeemed by Washington Gas on December 20, 2019;
"Washington Gas $5.00 Shares" means the US$5.00 series cumulative preferred shares of Washington Gas that were redeemed by Washington Gas on December 20, 2019;
"Washington Gas Preferred Shares" means the preferred shares of Washington Gas as a class, including, without limitation, the Washington Gas $4.25 Shares, Washington Gas $4.80 Shares and Washington Gas $5.00 Shares;
"Washington Gas Resources" means Washington Gas Resources Corporation, a subsidiary of WGL that owns the majority of the non-utility subsidiaries;
"WCSB" means Western Canada Sedimentary Basin;
"WGL" means WGL Holdings, Inc., an indirect subsidiary of AltaGas;
"WGL Acquisition" means the acquisition by AltaGas, indirectly through Merger Sub, of WGL through a merger of Merger Sub with and into WGL pursuant to the Merger Agreement, which closed on July 6, 2018;
"WGL Energy Services" means WGL Energy Services, Inc. (formerly Washington Gas Energy Services, Inc.), a subsidiary of Washington Gas Resources that sells natural gas and electricity to retail customers on an unregulated basis;
"WGL Energy Systems" means WGL Energy Systems, Inc. (formerly Washington Gas Energy Systems, Inc.), a subsidiary of Washington Gas Resources, which provides commercial energy efficient and sustainable solutions to government and commercial clients;
"WGL Midstream" means WGL Midstream, Inc., a subsidiary of Washington Gas Resources that engages in acquiring and optimizing natural gas storage and transportation assets;
"WGSW" means WGSW, Inc., a subsidiary of Washington Gas Resources that was formed to invest in certain renewable energy projects; and
"Younger" means the Younger extraction plant and related facilities, AltaGas’ interest being owned by its indirect wholly-owned subsidiary AltaGas Extraction and Transmission Limited Partnership.

 
 
 
AltaGas Ltd. 2019 Annual Information Form 11

    


METRIC CONVERSION
The following table sets forth certain standard conversions between Standard Imperial Units and the International System of Units (or metric units).                 
To Convert From
To
Multiply by
 
To Convert From
To
Multiply by
Mcf
cubic meters
28.174
 
feet
meters
0.305
cubic meters
cubic feet
35.494
 
meters
feet
3.281
Bbls
cubic meters
0.159
 
miles
km
1.609
cubic meters
Bbls
6.29
 
km
miles
0.621
tonnes
long tons
0.98
 
gigajoule
Mcf
0.9482
million tonnes
Bbls
12.40
 
 
 
 

CORPORATE STRUCTURE
Incorporation
AltaGas is a Canadian corporation amalgamated pursuant to the CBCA on January 1, 2020. AltaGas and/or its predecessors began operations in Calgary, Alberta on April 1, 1994 and AltaGas continues to maintain its head, principal, and registered office in Calgary, Alberta currently located at 1700, 355 – 4th Avenue SW, Calgary, Alberta T2P 0J1. AltaGas is a public company, the Common Shares of which trade on the TSX under the symbol "ALA".
Amended Articles
On July 1, 2010, AltaGas filed articles of arrangement under the CBCA to effect a corporate arrangement and the amalgamation of AltaGas Ltd., AltaGas Conversion Inc., and AltaGas Conversion #2 Inc. to form AltaGas. Subsequent to the filing of the articles of arrangement, AltaGas filed articles of amendment on the following dates in connection with the creation of each series of Preferred Shares: (i) August 13, 2010 to create the first series of Preferred Shares, Series A Shares and the second series of Preferred Shares, Series B Shares; (ii) June 1, 2012 to create the third series of Preferred Shares, Series C Shares and the fourth series of Preferred Shares, Series D Shares; (iii) December 9, 2013 to create the fifth series of Preferred Shares, Series E Shares and the sixth series of Preferred Shares, Series F Shares; (iv) June 27, 2014 to create the seventh series of Preferred Shares, Series G Shares and the eighth series of Preferred Shares, Series H Shares; (v) November 17, 2015 to create the ninth series of Preferred Shares, Series I Shares and the tenth series of Preferred Shares, Series J Shares; and (vi) February 15, 2017 to create the eleventh series of Preferred Shares, Series K Shares and the twelfth series of Preferred Shares, Series L Shares. On January 1, 2020, AltaGas filed articles of amalgamation to effect the amalgamation of AltaGas with its non-operating subsidiaries AltaGas Investment Ltd., 11801376 Canada Ltd., and Northwest Triumph Contracting Ltd.
Intercorporate Relationships
The following organization diagram presents the name and the jurisdiction of incorporation of certain of AltaGas' subsidiaries as at the date of this Annual Information Form. The diagram does not include all of the subsidiaries of AltaGas. The assets and revenues of those subsidiaries omitted from the diagram individually did not exceed 10 percent, and in the aggregate did not exceed 20 percent, of the total consolidated assets or total consolidated revenues of AltaGas as at and for the year ended December 31, 2019.

 
 
 
AltaGas Ltd. 2019 Annual Information Form 12

    


a2020aiforgchart.jpg
(1)    Updated as of the date of this Annual Information Form.
(2)    Unless otherwise stated, ownership is 100%.
OVERVIEW OF THE BUSINESS
AltaGas, a Canadian corporation, is a leading North American energy infrastructure company that connects NGLs and natural gas to domestic and global markets. The Corporation’s long-term strategy is to grow in attractive areas across its Utilities and Midstream business segments seeking optimal capital deployment. In the Midstream business, the Corporation is focused on optimizing the full value chain of energy exports by providing producers with solutions, including global market access off the West Coast of Canada via the Corporation’s footprint in the Montney region. In the Utilities business, the Corporation seeks to grow through rate base investment and the use of accelerated rate recovery programs, while providing effective and cost-efficient service for customers. AltaGas has three business segments:
   
Utilities, which serves approximately 1.7 million customers with a rate base of approximately US$3.9 billion through ownership of regulated natural gas distribution utilities across five jurisdictions in the United States and two regulated natural gas storage utilities in the United States, delivering clean and affordable natural gas to homes and businesses.

 
 
 
AltaGas Ltd. 2019 Annual Information Form 13

    


The Utilities business also includes storage facilities and contracts for interstate natural gas transportation and storage services;
Midstream, which includes a 70 percent interest in the recently completed Ridley Island Propane Export Terminal, allowing AltaGas to leverage its assets along the energy value chain in Western Canada including natural gas gathering and processing, NGL extraction and fractionation, and natural gas and NGL marketing. The Midstream segment also includes transmission, storage, an interest in a regulated pipeline in the Marcellus/Utica gas formation in the northeastern United States, WGL’s retail gas marketing business, the Corporation’s 50 percent interest in AIJVLP, and an indirectly held approximate one-third ownership investment in Petrogas, through which AltaGas’ interest in the Ferndale terminal is held; and
Power, which includes 710 MW of operational gross capacity from natural gas-fired, distributed generation, and energy storage assets, certain of which are pending sale, located in Alberta, Canada and the United States, primarily in California and Colorado. The Power business also includes energy efficiency contracting and WGL’s retail power marketing business.

 
 
 
AltaGas Ltd. 2019 Annual Information Form 14

    


ALTAGAS’ GEOGRAPHIC FOOTPRINT
utilities_mapa02.jpg

 
 
 
AltaGas Ltd. 2019 Annual Information Form 15

    


midstream_mapa03.jpg

 
 
 
AltaGas Ltd. 2019 Annual Information Form 16

    


power_mapa05.jpg
OUTLOOK
In 2019, AltaGas successfully completed its plan to refocus the Company, capture the intrinsic value of its core assets, and regain its financial footing to capitalize on the significant investment opportunities ahead. Since the acquisition of WGL in 2018, AltaGas has integrated the WGL assets, streamlined its business portfolio through approximately $5 billion of non-core asset sales, substantially simplified its business model, and significantly enhanced its financial strength and flexibility, all while continuing to deliver solid operating and financial performance.

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

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

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

 
 
 
AltaGas Ltd. 2019 Annual Information Form 17

    


Enhance returns and capital efficiency through base rate cases, and facilitate timely recovery of expenditures and improve safety through increased utilization of accelerated rate recovery programs;
Enhance the business through asset optimization and operational efficiencies to reduce costs and deliver an improved customer experience;
Maximize the unique structural advantage within AltaGas' integrated platform in the Montney region;
Increase utilization and export volumes at RIPET;
Execute the planned $900 million growth capital program, including a targeted 10 percent increase in the Utilities rate base; and
Pursue capital efficient organic growth through disciplined capital allocation while improving balance sheet strength and flexibility.
GENERAL DEVELOPMENT OF ALTAGAS' BUSINESS
Below is a summary by business segment of certain acquisitions and dispositions, key development and construction projects, and other commercial arrangements not already discussed above, which have influenced the general development of the business segments of the Corporation over the last three completed financial years.
Development of the Utilities Business of AltaGas
In August 2017, the MPSC approved SEMCO Gas’ application to construct, own, and operate the Marquette Connector Pipeline. The Marquette Connector Pipeline is a new pipeline that connects the Great Lakes Gas Transmission pipeline to the Northern Natural Gas pipeline in Marquette, Michigan where it will provide system redundancy and increase deliverability, reliability, and diversity of supply to SEMCO Gas’ approximately 35,000 customers in Michigan’s Western Upper Peninsula. The Marquette Connector Pipeline was completed and placed in-service in December 2019.
On July 6, 2018, the WGL Acquisition closed and the operations of Washington Gas and Hampshire Gas were added to AltaGas’ Utilities business.
With the close of the ACI IPO on October 25, 2018, the Canadian rate-regulated utility assets including PNG, AUI, and Heritage Gas are no longer subsidiaries of AltaGas. AltaGas’ remaining exposure to such Canadian rate-regulated utility assets is through its approximate 37 percent interest in ACI.
On July 31, 2018, Washington Gas filed an application with the SCC of VA to increase its base rates for natural gas service. A Final Order was received in December 2019. On January 9, 2020, Washington Gas filed a petition for reconsideration regarding one of the findings in the Final Order. On January 30, 2020, the SCC of VA denied this request and the rate case is now final. See "Business of the Corporation - Utilities Business - Washington Gas - Material Regulatory Developments and Approvals".

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

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

 
 
 
AltaGas Ltd. 2019 Annual Information Form 18

    


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

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

On January 13, 2020, Washington Gas filed an application with the PSC of DC for an increase in rates. See "Business of the Corporation - Utilities Business - Washington Gas - Material Regulatory Developments and Approvals".
Development of the Midstream Business of AltaGas
In January 2017, AltaGas reached a positive FID on RIPET, the first propane marine export facility in Canada. On May 5, 2017, AltaGas LPG Limited Partnership, a wholly-owned subsidiary of AltaGas, and Vopak formed RILE LP for the development of RIPET. AltaGas’ subsidiaries hold a 70 percent interest in RILE LP, with Vopak holding the remaining 30 percent interest. Construction of RIPET began in April 2017 and the first shipment of propane to Asia departed on May 23, 2019. Based on production from AltaGas Midstream facilities and commercial contracts executed or currently under negotiation, RIPET's physical volumes are currently averaging approximately 40,000 Bbls/d or 1.2 million tonnes annually. For further details on this project see below under the heading "Business of the Corporation – Midstream Business – Global Exports".
In March 2017, AltaGas sold the Ethylene Delivery System and the Joffre Feedstock Pipeline to Nova Chemicals for net proceeds of approximately $67 million.
On April 3, 2018, AltaGas entered into a long-term natural gas processing arrangement with Birchcliff at AltaGas’ deep-cut sour gas processing facility located in Gordondale, Alberta.
As a result of the closing of the WGL Acquisition on July 6, 2018, an interest in four pipelines in the U.S. (two of which have since been sold and one project for which the partners have elected not to proceed) as well as the retail gas marketing business of WGL were added to AltaGas’ Midstream business.
On August 27, 2018, AltaGas entered into definitive agreements with Kelt to provide Kelt with firm processing of 75 MMcf/d of raw gas under an initial 10 year take-or-pay agreement at the Townsend complex.
On September 10, 2018, AltaGas entered into definitive agreements for the sale of non-core Midstream and Power assets in Canada. The sale was completed in February 2019.
In October 2018, AltaGas acquired 50 percent ownership in certain existing and future natural gas processing plants of Black Swan. AltaGas and Black Swan also entered into long-term processing, transportation, and marketing agreements that include new AltaGas liquids handling infrastructure.
On May 31, 2019, AltaGas completed the disposition of WGL Midstream's entire interest in the Stonewall System to a wholly-owned subsidiary of DTE Energy for total gross proceeds of approximately $379 million (US$280 million).
On September 30, 2019, AltaGas announced that it had entered into a definitive agreement for the sale of its indirect, non-operating interest in Central Penn held by its subsidiary WGL Midstream, Inc. to Meade Pipeline Investment, LLC, a subsidiary of NextEra Energy Partners, LP. Total cash proceeds for WGL Midstream's interest were approximately $812 million (US$611 million) and the transaction closed on November 13, 2019.
On January 2, 2020, AltaGas announced that AIJVLP had received the Put Notice from SAM of its exercise of the Put Option with respect to SAM's approximate one-third interest in Petrogas effective December 31, 2019. Pursuant to the Petrogas unanimous shareholders agreement, a valid exercise of the Put Option by SAM after October 1, 2019, triggers a requirement

 
 
 
AltaGas Ltd. 2019 Annual Information Form 19

    


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

In February 2020, following evaluations of the diminished underlying economics for the proposed Constitution pipeline project, the partners of Constitution elected not to proceed with the project. AltaGas held a 10 percent equity interest in Constitution.
Development of the Power Business of AltaGas
On June 13, 2018, AltaGas announced that it had entered into a definitive agreement to indirectly sell 35 percent of its interest in the Northwest Hydro facilities for gross proceeds of $922 million. The transaction closed on June 22, 2018.

On July 6, 2018, as part of the WGL Acquisition, WGL Energy Systems and WGL Energy Services were added to AltaGas’ Power business.

On September 10, 2018, AltaGas entered into definitive agreements for the sale of non-core Midstream and Power assets in Canada. The sale was completed in February 2019.

On October 19, 2018, the Bear Mountain wind facility in British Columbia was sold to ACI. In addition, a 10 percent minority interest in the Northwest Hydro facilities was sold to ACI.

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

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

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

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

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

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


 
 
 
AltaGas Ltd. 2019 Annual Information Form 20

    


BUSINESS OF THE CORPORATION
AltaGas’ revenue for the year ended December 31, 2019 was approximately $5.5 billion compared to $4.3 billion for the year ended December 31, 2018.
chart-520fe89e9ca1a990be2a01.jpg chart-ad5601b3592ac92de90.jpg
Note: Excluding Corporate segment and intersegment eliminations

AltaGas operates its business through three business segments: Utilities, Midstream, and Power, each of which is more particularly described in the respective sections that follow. AltaGas’ business also includes the Corporate segment, which consists primarily of opportunistic investments, certain risk management contract results, and revenues and expenses not directly identifiable with the operating businesses.
UTILITIES BUSINESS
The Utilities business contributed revenue of $2.6 billion for the year ended December 31, 2019 (2018 - $1.7 billion), representing approximately 46 percent (201840 percent) of AltaGas’ total revenue before Corporate segment and intersegment eliminations.
Utilities Business
The Utilities segment owns utility assets that deliver natural gas to end-users in the United States. The Utilities segment in the United States is comprised of Washington Gas (in the District of Columbia, Maryland, and Virginia); Hampshire Gas, a regulated natural gas storage utility in West Virginia; SEMCO Gas in Michigan; ENSTAR in Alaska; and a 65 percent interest in CINGSA, a regulated natural gas storage utility in Alaska.

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

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

 
 
 
AltaGas Ltd. 2019 Annual Information Form 21

    


conditions and regulatory review and approval in five-year increments. These programs enable SEMCO Gas and Washington Gas to accelerate pipe and infrastructure replacement to further enhance the safety and reliability of the natural gas delivery system. SEMCO Gas and Washington Gas are allowed to begin recovering the cost, including a return, for these investments immediately through approved surcharges for each accelerated pipe or infrastructure replacement program outside of a normal rate case process, mitigating regulatory lag. Once new base rates are put into effect in a given jurisdiction following approval of an application to increase rates, expenditures previously being recovered through the surcharge will be collected through the new base rates.

The Utilities business is subject to regulation over, among other things, rates, accounting procedures, and standards of service. The MPSC has jurisdiction over the regulatory matters related, directly or indirectly, to the services that SEMCO Gas provides to its Michigan customers. The RCA has jurisdiction over the regulatory matters related, directly or indirectly, to ENSTAR’s and CINGSA’s services provided to its Alaska customers. Washington Gas is regulated by the PSC of DC, the PSC of MD, and the SCC of VA, which approve its terms of service and the billing rates that it charges to its customers, regulate interactions with affiliates, and regulate retail competition for natural gas supply service. In all jurisdictions, the regulators approve distribution rates based on a cost-of-service regulatory model. In Alaska, the District of Columbia, and Maryland, rates are set using the results from a historical test year plus known and measurable changes. In Michigan and Virginia, rates are set using a projected test year. In all jurisdictions, the rates charged to utility customers are designed to provide the distribution utility with an opportunity to recover all prudently incurred operating, depreciation, income tax, and financing costs. In most jurisdictions, the rates are also designed to earn a reasonable return on its investment in the net assets used in its firm gas sales and delivery service.

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

(US$ millions)
2019

2018

Rate base (1) (2)
3,865

3,684

(1)
Rate base is indicative of the earning potential of each utility over time. Approved revenue requirement for each utility is typically based on the rate base as approved by the regulator for the respective rate application, but may differ from the rate base indicated above.
(2)
Includes SEMCO Energy’s 65 percent interest in CINGSA.

The following table summarizes the capital expenditures for the years ended December 31, 2019 and 2018:
(US$ millions)
2019
2018
New business
252
69
System betterment and gas supply
165
140
General plant
30
64
Accelerated Replacement Programs
200
88
Total
647
361

 
 
 
AltaGas Ltd. 2019 Annual Information Form 22

    


The following table summarizes the nature of regulation applicable to each utility:
Regulated Utility
Regulated Authority
% of AltaGas' Consolidated Rate Base as at December 31, 2019
Allowed Common Equity (%)
Allowed ROE
(%)
2018
Allowed ROE
(%)
2019
Significant Features/
Material Regulatory Developments
Washington Gas
PSC of MD
SCC of VA
PSC of DC
75%
53.5 - 55.7
9.25 - 9.7
9.2 - 9.7
n    Distribution rates approved under cost of service model.
n    Rate cases filed with the PSC of MD in 2018 and 2019 for increase in rates and accelerated pipeline replacement programs. Final Orders were received in 2019.
n    Rate case filed in 2018 with the SCC of VA for an increase in rates. The Final Order was received in December 2019. In January 2020, a petition for reconsideration was filed and denied, and the rate case is now final.
n    Rate case filed in January 2020 with the PSC of DC for an increase in rates.
SEMCO Gas
MPSC
16%
49.04
10.35
10.35
n    Distribution rates approved under cost of service model.
n    Use of projected test year for rate
cases with 10-month limit to issue a rate order.
n    Rate rider provides recovery relating to the Main Replacement Program which allows SEMCO Gas to accelerate the replacement of older portions of its system. New Infrastructure Reliability Improvement Program (IRIP) was approved in the 2019 rate case for the years 2020 - 2025. Customers will be billed a surcharge beginning in 2021 for the IRIP.
n    Rate case filed in May 2019. The settlement was approved in December 2019 and the new rates are effective on January 1, 2020.
ENSTAR
RCA
7%
51.81
11.875
11.875
n    Distribution rates approved under cost of service model using historical test year and allows for known and measurable changes.
n    Rate order approving rate increase issued on September 22, 2017. Final rates effective November 1, 2017.
n    Required to file another rate case no later than June 1, 2021 based upon 2020 test year.
CINGSA
RCA
2%
53.00
11.875
10.25
n    Distribution rates approved under cost of service model using historical test year and allows for known and measurable changes.
n    Rate case filed in 2018 based on 2017 historical test year.
n    Rate 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
n    Pass through cost of service tariff approved by FERC.


 
 
 
AltaGas Ltd. 2019 Annual Information Form 23

    


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

On December 19, 2019, ACI announced that the holders of common shares of ACI approved the arrangement whereby the Consortium would together indirectly acquire all of the issued and outstanding common shares of ACI for $33.50 in cash per common share. The Arrangement is expected to close in the first half of 2020. See "General Development of AltaGas' Business - Development of the Utilities Business of AltaGas".
Washington Gas
Washington Gas has been engaged in the natural gas distribution business since 1848 and provides regulated gas distribution services to end users in District of Columbia, Maryland, and Virginia. The utility has approximately 1.2 million customers across these three jurisdictions: District of Columbia (~164,000; 14 percent), Maryland (~493,000; 41 percent), and Virginia (~535,000; 45 percent). Washington Gas operations are such that the loss of any one customer or group of customers would not have a significant adverse effect on its business.

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

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

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


 
 
 
AltaGas Ltd. 2019 Annual Information Form 24

    


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

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

Forecasted volumes in the District of Columbia are set based on the 30-year rolling average Degree Days expected for the period. In Maryland and Virginia, there are billing mechanisms in place which are designed to eliminate the effects of variance in customer usage caused by weather and other factors such as conservation. In the District of Columbia, there is no weather normalization billing mechanism, nor does Washington Gas hedge to offset the effects of weather. As a result, colder or warmer weather will result in variances to financial results. On January 13, 2020, Washington Gas filed an application with the PSC of DC that requested approval for a weather normalization billing mechanism. See "Business of the Corporation - Utilities Business - Washington Gas - Material Regulatory Developments and Approvals - District of Columbia Jurisdiction".

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

On January 13, 2020, Washington Gas filed an application with the PSC of DC to increase its base rates by approximately US$35 million, including approximately US$9 million pertaining to a PROJECTpipes surcharge that customers are currently paying in the form of a rate rider. The filing requested a return on equity of 10.4 percent on allowed common equity of 52.2 percent, which is based on a US$532 million rate base value. Additionally, Washington Gas requested approval for a Revenue Normalization Adjustment mechanism to reduce customer bill fluctuations due to weather-related and conservation-related usage variations, similar to existing mechanisms in both Maryland and Virginia. Washington Gas requested that new rates be implemented by January 1, 2021. A conference to discuss process schedule is expected to be held in March 2020.
Maryland Jurisdiction
On May 15, 2018, Washington Gas filed an application with the PSC of MD to increase its base rates for natural gas service for approximately US$56 million, including US$15 million pertaining to a STRIDE surcharge it was collecting in the form of a rate rider. The PSC of MD granted Washington Gas US$29 million base rate increase and increased Washington Gas' return on equity to 9.7 percent. On January 10, 2019, Washington Gas filed an application for rehearing with the PSC of MD, alleging two errors in the Commission’s Final Order. On June 25, 2019, the PSC of MD issued an order granting in part and denying in part Washington Gas’ application for a rehearing, resulting in an additional US$1 million increase in annual distribution revenues.
On June 15, 2018, Washington Gas filed an application with the PSC of MD for approval of the second phase of its accelerated natural gas pipeline initiative in Maryland, known as the STRIDE Plan. The application requested approval of approximately US$394 million in accelerated infrastructure replacements for the 2019 to 2023 period. On December 11, 2018, the PSC of MD approved a US$350 million five-year program. On January 9, 2019, Washington Gas applied to supplement its 2019 project list with an additional annual spend of approximately US$65 million. On January 25, 2019, the PSC of MD approved the 2019 revised project list and affirmed the annual spend of approximately US$65 million.

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

 
 
 
AltaGas Ltd. 2019 Annual Information Form 25

    


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

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

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

In connection with the WGL Acquisition, AltaGas and WGL have made commitments related to the terms of the PSC of DC settlement agreement and the conditions of approval from the PSC of MD and the SCC of VA. Among other things, these commitments include rate credits distributable to both residential and non-residential customers, gas expansion and other programs, various public interest commitments, and safety programs. As at December 31, 2019, the cumulative amount expensed to date was approximately US$137 million, of which US$17 million had not been paid. In addition, there are certain additional regulatory commitments which will be expensed when the costs are incurred in the future, including the hiring of damage prevention trainers, investing up to US$70 million over a 10-year period to further extend natural gas service, and investing US$8 million for leak mitigation.
Hampshire Gas
Hampshire owns underground natural gas storage facilities, including pipeline delivery facilities located in and around Hampshire County, West Virginia, and operates these facilities to serve Washington Gas. Hampshire is regulated by FERC. Washington Gas purchases all of the storage services of Hampshire, and includes the cost of the services in the commodity cost of its regulated energy bills to customers. Hampshire operates under a “pass-through” cost-of-service based tariff approved by FERC.
SEMCO Energy
SEMCO Energy’s head office is located in Port Huron, Michigan. SEMCO Energy’s primary business is a gas utility business. It operates regulated natural gas transmission and distribution divisions in Michigan, doing business as SEMCO Gas, and in Alaska, doing business as ENSTAR. SEMCO Energy’s gas utility business also includes a 65 percent ownership interest

 
 
 
AltaGas Ltd. 2019 Annual Information Form 26

    


in CINGSA, a regulated natural gas storage utility in Alaska. The gas utility business accounts for approximately 99 percent of SEMCO Energy’s 2019 consolidated revenues. The gas utility business purchases, transports, distributes and sells natural gas and related gas distribution services to residential and C&I customers and is SEMCO Energy's largest business segment.
SEMCO Gas
In Michigan, SEMCO Gas distributes natural gas to approximately 307,000 regulated customers located in both southern Michigan and Michigan’s Upper Peninsula, approximately 85 percent of which are residential. The remaining customers include power plants, food production facilities, furniture manufacturers, and other industrial customers.

The average number of customers at SEMCO Gas has increased by an average of approximately 1 percent annually during the past three years (with an increase of 1 percent in 2019). While there may occasionally be variations in this pattern, average per customer annual gas consumption in Michigan over the longer-term has been decreasing because of, among other things, the availability of and incentive to invest in more energy efficient homes and appliances.

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

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

SEMCO Gas has access to natural gas supplies throughout the U.S. and Canada via interstate and intrastate pipelines in and near Michigan. To provide gas to SEMCO Gas sales customers, SEMCO Gas has negotiated standard terms and conditions for the purchase of natural gas under the NAESB form of agreement with a variety of suppliers.

The following table sets out, by customer category, SEMCO Gas’ deliveries:
 
2019
2018
Deliveries: (MDth)
   
 
Residential
26,841
27,278
Commercial
15,976
13,595
Transport
22,712
22,248
Gas Customer Choice (1)
3,719
3,394
Total deliveries
69,248
66,515
 
 
 
 
2019
2018
Customers at Year End (2):
 
 
Residential
260,548
258,300
Commercial
23,880
23,523
Transport
249
253
Gas Customer Choice (1)
22,247
21,102
Total customers
306,924
303,178
(1)
In Michigan, the MPSC has a program known as the Gas Customer Choice Program, under which gas sales customers may choose to purchase natural gas from third-party suppliers, while SEMCO Gas continues to charge these customers applicable distribution charges and customer fees, plus a balancing fee.
(2)
Excludes customers from SEMCO Gas’ non-regulated business.


 
 
 
AltaGas Ltd. 2019 Annual Information Form 27

    


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

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

Material Regulatory Developments and Approvals
As required by an order issued by the MPSC in September 2012, SEMCO Gas filed a depreciation study with the MPSC in September 2017, using 2016 data. On April 9, 2018, the MPSC issued an order approving the settlement agreement and new depreciation rates. The new rates reflect an approximately US$2 million upward adjustment to depreciation expense when compared to the current rates and were effective on January 1, 2019. SEMCO Gas is required to file a new depreciation case and updated depreciation study with the MPSC no later than September 30, 2022, using 2021 data.

On May 31, 2019, SEMCO Gas filed a request with the MPSC seeking authority to increase SEMCO Gas' base rates by approximately US$38 million on an annual basis established with a forecasted test year of 2020. The increase in rates requested captures the inflation of operations and maintenance costs from the last rate case in 2010 as well as the investment in the Marquette Connector Pipeline. With the upcoming sunset of the MRP in 2020, this case includes the addition of a new MRP and the introduction of an IRIP to recover the capital costs associated with the replacement of certain mains, services, and other infrastructure through surcharges similar to the currently-enacted MRP program. In November 2019, a settlement agreement was filed for a rate increase of approximately US$20 million and an allowed return on equity of 9.87 percent. The MPSC approved the settlement in December 2019 and the new rates are effective January 1, 2020. Pursuant to the approval of the IRIP, SEMCO Gas will complete certain projects totaling US$55 million to improve the reliability of infrastructure and customers will be billed a surcharge beginning in 2021. SEMCO Gas cannot seek an increase in its general rates to take effect prior to January 1, 2023.
ENSTAR
In Alaska, ENSTAR distributes natural gas to approximately 147,000 customers in the metropolitan Anchorage area and surrounding Cook Inlet area, approximately 91 percent of which are residential. The remaining gas sales customers include hospitals, universities, and government buildings. ENSTAR also provides gas transportation service to power plants and an LNG plant. ENSTAR’s service area encompasses over 50 percent of the population of Alaska.

The average number of customers at ENSTAR has increased by an average of approximately 1 percent annually during the past three years (with an increase of 1 percent in 2019). While there may occasionally be variations in this pattern, average per customer annual gas consumption in Alaska over the longer term has been decreasing due to the availability of and incentive to invest in more energy efficient homes and appliances.

Operations
ENSTAR’s natural gas delivery system (including SEMCO Energy’s Alaska Pipeline Company) includes approximately 446 miles of gas transmission pipelines and 3,149 miles of gas distribution mains. ENSTAR’s pipelines and mains are located in Anchorage and the Cook Inlet area of Alaska.

Historically, ENSTAR has had access to significant natural gas supplies in Cook Inlet, which are within or adjacent to its service territory. ENSTAR’s distribution system, including the Alaska Pipeline Company transmission-level pipeline system, is not linked to major interstate and intrastate pipelines and thus does not have access to natural gas supplies elsewhere in Alaska, Canada, or the lower 48 states. As a result, ENSTAR must procure its natural gas supplies under gas supply agreements from producers in and near the Cook Inlet area. Natural gas production in Cook Inlet has decreased significantly

 
 
 
AltaGas Ltd. 2019 Annual Information Form 28

    


in recent years as has the amount of deliverability available from Cook Inlet producers. The majority of ENSTAR’s gas supply and deliverability needs are provided by long-term contracts with Cook Inlet producers into 2023.

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

The following table sets out, by customer category, ENSTAR’s deliveries:
 
2019
2018
Deliveries: (Mmcf)
 
 
Residential
16,308
18,322
Commercial
13,367
12,415
Transport
24,473
25,041
Total deliveries
54,148
55,778
 
 
 
 
2019
2018
Customers at Year End:
 
 
Residential
133,654
132,270
Commercial
12,940
12,829
Transport
23
22
Total customers
146,617
145,121
Seasonality
The natural gas distribution business in Alaska is seasonal, as the majority of natural gas demand occurs during the winter heating season that extends from November to March. Accordingly, annualized individual quarterly revenues and earnings are not indicative of annual results.

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

Material Regulatory Developments and Approvals
On March 23, 2018, the RCA sent a letter to several investor-owned utilities in Alaska, asking for the utilities’ proposed response to the TCJA. On April 26, 2018, ENSTAR filed its proposed reduction in rates with the RCA, reflecting a US$5 million decrease from the annual revenue requirement that was determined in October 2017. On May 29, 2018, the RCA approved ENSTAR’s proposed rate decrease and the reduced rates went into effect on June 1, 2018. ENSTAR anticipates addressing excess deferred income taxes in its next rate case, which is required to be filed no later than June 1, 2021, with a test year of 2020.

On November 30, 2018, Southcentral Alaska experienced a magnitude 7.1 earthquake with an epicenter close to Anchorage, Alaska. ENSTAR experienced a large number of above and below ground gas leaks in its service territory. On December 2, 2019, ENSTAR filed a request to establish a regulatory deferred asset with the RCA to recover uninsured losses associated with the earthquake in its next rate case, which is required to be filed in 2021. As at December 31, 2019, the associated losses totaled US$2 million. ENSTAR's insurance deductible for this type of claim is US$1 million.
CINGSA
SEMCO Energy, through a subsidiary, holds a 65 percent interest in CINGSA. CINGSA was formed to construct, own, and operate the CINGSA Storage facility. Natural gas is injected into the CINGSA Storage facility during each summer and withdrawn as needed for use each winter.

CINGSA provides firm gas storage service to ENSTAR and to three Cook Inlet area electric utilities and provides interruptible gas storage service to ENSTAR and five other customers. ENSTAR has subscribed for approximately 78 percent of CINGSA’s

 
 
 
AltaGas Ltd. 2019 Annual Information Form 29

    


initial capacity and approximately 66 percent of the associated initial gas injection and withdrawal capability, with the remainder of the capacity and injection and withdrawal capability split among the other customers.

Material Regulatory Developments and Approvals
In April 2018, CINGSA filed a request for an advanced ruling on a redundancy project for approximately US$41 million of capital expenditures and an annual revenue requirement of approximately US$6 million. Reply testimony was filed in September 2018 and a hearing occurred in October 2018. The application was denied on February 28, 2019.

As provided in the certificate of public convenience and necessity stipulations accepted by the RCA for the CINGSA Storage facility, the RCA ordered CINGSA to file a revenue requirement study. The rate case was filed in April 2018 based on a 2017 historical test year, reducing rates by US$4 million due to a lower rate base, lower ROE, and lower federal income tax. A decision was received in August 2019 and included an ROE of 10.25 percent (compared to 11.875 percent requested) and 100 percent of Interruptible Storage Service revenues payable to customers (versus 50 percent requested). CINGSA filed a petition for partial reconsideration on September 3, 2019. The Commission denied the petition on November 4, 2019. CINGSA filed an appeal with the Superior Court challenging one decision in the rate order. This matter is currently ongoing.

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

the complexity of the site;
changes in environmental laws and regulations at the federal, state, and local levels;
the number of regulatory agencies or other parties involved;
new technology that renders previous technology obsolete or experience with existing technology that proves ineffective;
the level of remediation required; and
variations between the estimated and actual period of time that must be dedicated to respond to an environmentally-contaminated site.

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

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

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

 
 
 
AltaGas Ltd. 2019 Annual Information Form 30

    


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

Washington Gas received a letter in February 2016 from the District of Columbia and National Park Service regarding the Anacostia River Sediment Project, indicating that the District of Columbia is conducting a separate remedial investigation and feasibility study of the river to determine if and what cleanup measures may be required and to prepare a natural resource damage assessment. On December 27, 2019, the DOEE issued an Anacostia River Sediment Project Proposed Plan, a River-wide Feasibility Study, and supporting documents for public comment. Although the Proposed Plan identifies the East Station property as one of fifteen potential environmental cleanup sites, the DOEE is proposing to continue remediation of the East Station property under the existing Consent Decree rather than as part of the Anacostia River Sediment Project. The DOEE is proposing to issue an Interim Record of Decision for remediation of "Early Action Areas" (that do not include the East Station property) in the Anacostia River by September 30, 2020. Washington Gas is not able to estimate the total amount of potential damages or timing associated with the District of Columbia's environmental investigation on the Anacostia River at this time. While an allocation method has not been established, Washington Gas has accrued an amount based on a potential range of estimates for its share of the feasibility study costs.

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

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

SEMCO Gas
As of December 31, 2019, SEMCO Gas has completed the investigation and remediation at the two MGP sites it was responsible for and has received NFA letters from the Michigan Department of Environment, Great Lakes, and Energy for both sites. SEMCO Gas will continue to monitor these sites in the future as required by the NFA letters.

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

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

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

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

 
 
 
AltaGas Ltd. 2019 Annual Information Form 31

    



AltaGas' facilities are set out in the table below:
2019 Licensed Capacity (Net)
Facility
Location
Interest
(%)

Operated / Non-Operated
Gas Processing (Mmcf/d)

Fractionation
(Bbls/d)

Export
(Bbls/d)

RIPET
Prince Rupert, BC
70.0
%
Operated


40,000

Ferndale (1)
Washington (US)
33.0
%
Non-Operated


50,000

Townsend
North of Fort St. John, BC
100.0
%
Operated
396



Gordondale
Bonanza, AB
100.0
%
Operated
150



Blair Creek
North of Fort St. John, BC
100.0
%
Operated
120



Aitken Creek (2)
Aitken, BC
50.0
%
Non-Operated
105



JEEP
Joffre, AB
100.0
%
Operated
250



EEEP
Edmonton, AB
100.0
%
Operated
390



PEEP
Empress, AB
11.3
%
Non-Operated
135



North Pine
North of Fort St. John, BC
100.0
%
Operated

20,000


Harmattan
Sundre, AB
100.0
%
Operated
490

35,000


Younger (3)
Taylor, BC
28.3
%
Non-Operated
213

9,750


Total
 
 
 
2,249

64,750

90,000

(1)
Ferndale shown on a gross basis. AltaGas' investment in Ferndale is accounted for as an indirect equity investment.
(2)
Includes Aitken Creek North and Nig Creek.
(3)
AltaGas' interest in Younger is 28.3% in processing and extraction and 50% in fractionation and terminalling assets.

The total actual throughput of AltaGas' above facilities are set out in the table below (1):
 
2019

2018

Export (Bbls/d) (2)
35,446


Gas Processing (Mmcf/d)
1,407

1,378

Fractionation (Bbls/d)
37,546

38,128

(1)
As total actual throughput is included, future capacity associated with projects not yet in-service is excluded.
(2)
Total throughput excludes Ferndale which is accounted for as an indirect equity investment.

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

RIPET
On October 16, 2015, AltaGas entered into a project agreement with RTI for RIPET. This was followed in December 2015 with a sublease and related agreements between AltaGas and RTI. A positive FID was made on RIPET in January 2017 with construction commencing in April 2017. In May 2017, AltaGas entered into a joint venture agreement with Vopak pursuant to which Vopak acquired a 30 percent interest in RIPET. The commercial operations of RIPET commenced on May 23, 2019, with the first propane shipment departing from the terminal to Asia.

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


 
 
 
AltaGas Ltd. 2019 Annual Information Form 32

    


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

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

Petrogas – Ferndale Terminal
AltaGas, through its fifty percent ownership in AIJVLP, has approximate one-third indirect ownership interest in Petrogas, which owns and operates the Ferndale terminal and exports LPG to Asia. The Ferndale terminal is capable of handling LPG exports up to 50,000 Bbls/d with 750,000 Bbls of on-site storage capacity. The Ferndale terminal has rail, truck, and pipeline capability and is connected to two local refineries. In addition, Petrogas owns, operates, and leases storage, blending, and rail and truck terminal facilities that support Petrogas' marketing and distribution activities in Canada and the U.S. along with ownership or access to another nine LPG terminals in North America. Petrogas' logistics network consists of over 3,000 rail car leases used entirely to support its transportation needs.

Gas Processing
Midstream processing activities are comprised of gathering systems that move natural gas on behalf of producers from the wellhead to AltaGas plants where impurities and certain hydrocarbon components are removed, and the gas is compressed to meet the operating specifications of downstream pipeline systems. AltaGas’ Midstream processing facilities serve customers primarily in the WCSB that deliver natural gas into downstream pipeline systems and can connect producers to the global export markets for LPG. AltaGas has a total net licensed processing capacity of approximately 2.2 Bcf/d, of which 18 percent is capable of processing sour gas. AltaGas operates all but three of its Midstream processing facilities. All AltaGas' processing facilities are capable of extracting NGLs. The main drivers of AltaGas' processing activities are throughput, inlet composition, gathering and processing fees, and operating costs, with several facilities having the benefit of take-or-pay contracts. Throughput is impacted by new well tie‑ins, reactivations, recompletions, well optimizations performed by producers, natural production declines in areas served by AltaGas’ processing facilities, and gas available on the main lines.

Townsend Complex
The Townsend facility, which is wholly owned by AltaGas, is a 396 MMcf/d gas processing facility located approximately 100 km north of Fort St. John and 20 km southeast of AltaGas’ Blair Creek facility. The majority of the processing capacity is contracted with Montney producers in the area under long-term take-or-pay agreements. In addition, the Townsend facility is able to provide NGL handling, treatment, and storage services to producers. Refer to the "Fractionation and Liquids Handling" section below.
A 25 km gas gathering line connects the Blair Creek field gathering area to the Townsend facility and Painted Pony has reserved all of the firm service on that line under a 20-year take-or-pay agreement.
In August 2018, AltaGas entered into definitive agreements with Kelt to provide an energy infrastructure solution for the liquids-rich Inga Montney development located in British Columbia. This will add a 198 Mmcf/d C3+ deep cut gas processing capacity. The expanded facility will provide Kelt with firm processing of 75 Mmcf/d of raw gas under an initial 10 year take-or-pay agreement. The estimated project cost is approximately $165 million and includes a gas gathering pipeline that

 
 
 
AltaGas Ltd. 2019 Annual Information Form 33

    


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

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

Blair Creek
AltaGas owns 100 percent of the Blair Creek facility which has licensed capacity of 120 Mmcf/d of natural gas. AltaGas operates the facility which is located approximately 140 km northwest of Fort St. John, British Columbia. The facility processes gas gathered from Montney producers in the area. The plant is equipped with liquids extraction facilities to capture the NGL value for the producer.
Aitken Creek
In October 2018, AltaGas acquired a 50 percent ownership in Black Swan’s Aitken Creek processing facilities, including Aitken Creek North and Nig Creek. Aitken Creek North is an operating shallow gas plant with current capacity of 110 Mmcf/d (55 Mmcf/d net). Nig Creek is a shallow gas plant with capacity of 100 Mmcf/d (50 Mmcf/d net) and came on-stream in the third quarter of 2019. AltaGas and Black Swan have also entered into long-term processing, transportation, and marketing agreements that will include new AltaGas liquids handling infrastructure at the Townsend complex and North Pine facility. The Aitken Creek processing facilities are located in the liquids-rich Montney resource play in NEBC and are operated by Black Swan.
JEEP
AltaGas owns 100 percent of JEEP which has processing capacity of 250 Mmcf/d of natural gas and is capable of producing up to 10,400 Bbls/d of ethane and other NGLs.

The plant is adjacent to Nova Chemicals’ Joffre petrochemical complex and recovers ethane and other NGLs from the fuel gas used at the complex. All ethane production from JEEP is sold under a long-term, cost-of-service type contracts with Nova Chemicals. AltaGas delivers its NGL production to Harmattan Fractionation Plant for further processing. The resulting spec products are sold into markets throughout North America to maximize plant gate netbacks.

EEEP
AltaGas owns 100 percent of EEEP. EEEP is directly connected to the Alberta Ethane Gathering System and to Plains Midstream Canada’s Co-Ed NGL pipeline. The plant has a licensed gross inlet capacity of 390 Mmcf/d of natural gas and gross production capacity of 30,000 Bbls/d of ethane and other NGLs.

The processed gas from the facility supplies end-use markets in the city of Edmonton, Alberta. Almost all of EEEP ethane production capacity is currently sold to ethane buyers under long-term fee-for-service contracts. The NGL production is delivered to a Fort Saskatchewan fractionator for further processing. AltaGas takes the resulting spec products in-kind and sells to North American and global markets, through RIPET, to maximize plant gate netbacks.

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


 
 
 
AltaGas Ltd. 2019 Annual Information Form 34

    


Harmattan
AltaGas owns a 100 percent interest in Harmattan located 100 km north of Calgary, Alberta. Harmattan has natural gas processing capacity of 490 Mmcf/d consisting of sour gas treating, Co-stream processing, and NGL extraction. In addition, Harmattan has fractionation and terminalling facilities (see the "Fractionation and Liquids Handling" section below). Harmattan’s raw natural gas supply is based on producer activity in the west‑central region of Alberta. Harmattan is well-positioned as the high-volume, low-cost processing facility in its service area.

At Harmattan, natural gas processing services are provided to approximately 70 producers under contracts with a variety of commercial arrangements and terms. Approximately 30 percent of the natural gas volume processed at Harmattan is done under the terms of the Rep Agreements which have life-of-reserves dedications. The balance of the raw natural gas processed at Harmattan is processed under contracts with terms varying from one month to life-of-reserves. The majority of the contracts provide for fee escalation based on CPI.

The Co-stream processing allows the extraction of NGLs from gas in the west leg of the NGTL system using unused capacity in the NGL recovery units at Harmattan. The Co‑stream processing has resulted in increased utilization at the plant, with the added benefit that the equipment installed for the Co-stream process increases reliability and efficiency for both gas processing and Co-streaming customers. AltaGas entered into a 250 Mmcf/d cost-of-service Co-stream processing agreement with Nova Chemicals related to ethane and other NGL extraction at Harmattan in 2012 for an initial term of 20 years. AltaGas will deliver all NGLs or Co-stream gas products on a full cost-of-service basis to Nova Chemicals.

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

Younger
Effective April 1, 2018, AltaGas’ ownership was reduced to a 28.33 percent interest in Younger processing and extraction assets and a 50 percent interest in Younger's fractionation and terminalling assets (see the "Fractionation and Liquids Handling" section below). Younger has a license capacity to process up to 750 Mmcf/d of natural gas and AltaGas’ share of such capacity is 213 Mmcf/d. The remaining interest is held by Pembina and Pembina has assumed plant operatorship. Younger processes natural gas transported on the West Coast transmission system and other regional transmission systems to recover NGLs. Natural gas supply to Younger is dependent on the amount of raw gas processed at the McMahon gas plant, which is based on the robust natural gas producing region of northeastern British Columbia.

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

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

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

 
 
 
AltaGas Ltd. 2019 Annual Information Form 35

    


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

North Pine Facility
The North Pine facility is the only custom fractionation plant in B.C., providing area producers with a lower cost, higher netback alternative for their NGLs than transporting and fractionating in Edmonton. Commissioning of the first train of the North Pine facility was completed on December 1, 2017. The first train of the North Pine facility is capable of processing up to 10,000 Bbls/d of NGL mix. The construction is ongoing for the second NGL separation train capable of processing up to an additional 10,000 Bbls/d of NGL mix following execution of agreements with Black Swan and Kelt in the second half of 2018. The additional North Pine capacity is expected to be on-stream in the first quarter of 2020.

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

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

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

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

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

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

Other Liquids Handling Services

To support LPG and NGL handling, AltaGas manages a rail logistics network consisting of approximately 1,200 rail cars. AltaGas is active in identifying opportunities to buy and resell NGLs for producers and exchange, reallocate, or resell pipeline capacity and storage to earn a profit. Net revenues from these activities are derived from low risk opportunities based on transportation cost differentials between pipeline systems and differences in commodity prices from one period to another. Margins are earned by locking in buy and sell transactions in compliance with AltaGas’ credit and commodity risk policies. AltaGas also provides energy procurement services for utility gas users and manages the third-party pipeline transportation requirements for many of its gas marketing customers.


 
 
 
AltaGas Ltd. 2019 Annual Information Form 36

    


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

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

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

Fractionation
Average fractionation utilization of 69 percent in 2019 is lower than 70 percent utilization in 2018 due to lower volumes at Younger, partially offset by higher fractionation volumes at North Pine.
Significant Operating Areas and Customers
Global Exports
As LPG terminals operating on the west coast of North America, RIPET and the Ferndale terminal offer significantly reduced shipping times to the Asian LPG markets compared to the other North American LPG terminals. Both terminals are connected to the key North American hubs with rail networks.

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

AltaGas has also fractionation capacity in the NEBC area through the North Pine and Younger facilities. The North Pine facility is interconnected to the Townsend complex, and is the only custom fractionation plant in British Columbia, providing area producers with a lower cost, higher netback alternative for their NGLs than fractionating in Edmonton.

The JEEP and EEEP facilities are strategically located and take advantage of the gas consumption by the petrochemical industry and the City of Edmonton. Harmattan is a significant service provider with a large capture area in west central Alberta. Many other facilities in the Harmattan area are currently underutilized, providing AltaGas with opportunities to consolidate and increase asset utilization and profitability.

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


 
 
 
AltaGas Ltd. 2019 Annual Information Form 37

    


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

Establish fees for the gathering and processing services offered by AltaGas;
Establish operating costs flow through to the producers for a significant portion of the contracts;
Define the producers’ access rights to gathering and processing services;
Establish minimum throughput commitments with producers and use appropriate fee structures to recover invested capital early in the life of the contract where capital investment is required by AltaGas;
Define the terms and conditions under which future production is processed at an AltaGas facility; and
Establish processing fees at several facilities on a take-or-pay basis.

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

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

Natural gas processing facility owners have the right to extract liquids from the natural gas stream, either directly as the owner of the natural gas, or through NGL extraction agreements. The typical commercial arrangement involves the ethane and NGL extraction plant owner contracting with the gas shipper on a natural gas transmission system for the right to extract NGL from the transporter’s natural gas. Ethane and NGL are extracted from the energy content of the shipper’s natural gas.

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

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

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

On October 13, 2017, the FERC issued the Certificate of Public Convenience and Necessity for the pipeline. In early 2018, the FERC granted several notices to proceed with certain construction activities on the pipeline. In August 2019, certain construction activities were voluntarily suspended, thereby shifting more mainline work into 2020. On October 15, 2019, FERC issued a project-wide order halting forward-construction progress, much of which was already deferred following the August 2019 voluntary suspension or was winding down for the winter season. The project is expected to be placed into service in late 2020.

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

 
 
 
AltaGas Ltd. 2019 Annual Information Form 38

    


the aforementioned delays, AltaGas' exposure is contractually capped to the original estimated contributions of approximately US$352 million. In addition, WGL Midstream has gas purchase commitments to buy approximately 0.5 Bcf/d of natural gas, at index-based prices, for a 20-year term, and will also be a shipper on the proposed pipeline.

In April 2018, WGL Midstream entered into a separate agreement with EQM to acquire a 5 percent equity interest in a lateral project to build an interstate natural gas pipeline (MVP Southgate project). The proposed pipeline will receive gas from the Mountain Valley mainline in Pittsylvania County, Virginia and extend approximately 73 miles south to new delivery points in Rockingham and Alamance counties, North Carolina. The total commitment by WGL Midstream is expected to be approximately US$20 million and the lateral pipeline is expected to be placed into service in mid-2021.

Retail Energy Marketing - Natural Gas
AltaGas' retail gas marketing business consists of the operations of WGL Energy Services, a retail energy marketing business which sells natural gas directly to residential, commercial, and industrial customers in Maryland, Virginia, Delaware, Pennsylvania, and the District of Columbia. As at December 31, 2019, WGL Energy Services served approximately 101,600 residential, commercial and industrial natural gas customers located in Maryland, Virginia, Delaware, Pennsylvania, and the District of Columbia. WGL Energy Services is subject to regulation by the public service regulatory commission of the jurisdictions in which it is authorized as a competitive service provider. WGL Energy Services contracts for storage and pipeline capacity to meet its customers’ needs primarily through transportation releases and storage services allocated from the utility companies in the various service territories through several interstate natural gas pipelines. To supplement WGL Energy Services’ natural gas supplies during periods of high customer demand, WGL Energy Services maintains gas storage inventory in storage facilities that are assigned by natural gas utilities such as Washington Gas. This storage inventory enables WGL Energy Services to meet daily and monthly fluctuations in demand and to minimize the effect of market price volatility. WGL Energy Services has a secured supply arrangement with Shell Energy North America (US), L.P. (Shell Energy). Under this arrangement, WGL Energy Services has the ability to purchase the majority of its power, natural gas, and related products from Shell Energy in a structure that reduces WGL Energy Services’ cash flow risk from collateral posting requirements. While Shell Energy is intended to be the majority provider of natural gas and electricity, WGL Energy Services retains the right to purchase supply from other providers. The supply arrangement with Shell Energy expires in 2022.

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

 
 
 
AltaGas Ltd. 2019 Annual Information Form 39

    



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

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

AltaGas’ fractionation assets are well positioned to operate in a competitive environment and take advantage of their strategic locations and contract terms in order to compete in the NGL industry providing producers with access to lower cost and higher netback alternatives for their NGL.

AltaGas' retail gas marketing and natural gas storage and transportation businesses compete with other midstream infrastructure and energy services companies, wholesale energy suppliers, producers, and other non-utility affiliates of regulated utilities for the acquisition of natural gas storage and transportation assets. Operations can be positively or negatively affected by significant volatility in the wholesale price of natural gas. Accordingly, risk management policies and procedures are designed to minimize the risk that purchase commitments and the related sale commitments do not closely match. In general, profit opportunities for trading activities are increased with increased volatility in natural gas prices. These opportunities are primarily in short-term transportation and storage spreads, seasonal storage spreads, and long-term supply or basis transactions.


 
 
 
AltaGas Ltd. 2019 Annual Information Form 40

    


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

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

AltaGas is currently focused on evaluating and implementing emissions reductions opportunities to reduce NOx emission associated with its engine, heater, and boiler fleet. Through a combination of engine modifications, implementation of technology, and/or changes in operating parameters, AltaGas expects to achieve a yearly fleet average compliance target of 8g/kWh by 2021.
Federal Carbon Pricing
On December 9, 2016, the Government of Canada formally announced the Pan-Canadian Framework on Clean Growth and Climate Change. As a result, on June 21, 2018, the federal government enacted the Greenhouse Gas Pollution Pricing Act to implement a carbon pollution pricing system that took effect beginning in 2019, to be applied in provinces and territories that do not have a carbon pricing system that aligns with the federal benchmark. The federal government has also proposed regulations setting out requirements to produce emissions information under the Greenhouse Gas Pollution Pricing Act.

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

A carbon levy applied to combusted fossil fuels, currently priced at $20 per tonne of carbon emitted but increasing annually up to $50 per tonne in 2022; and
An output-based pricing system for industrial facilities that emit 50,000 tonnes of carbon dioxide equivalent (CO2e) per year or more, with an opt-in capability for smaller facilities with emissions below the threshold.

The output-based pricing system applies to all industrial facilities that emit 50,000 tonnes or more of CO2e per year. The output-based pricing system will apply to emissions from fuel combustion as well as emissions of synthetically produced GHG’s from industrial processes and products. As of December 31, 2019, AltaGas has three processing facilities that would exceed the 50,000 tonnes of CO2e per year threshold. Two facilities in Alberta and one facility in British Columbia that exceed the threshold will continue to be regulated by the carbon pricing and reporting systems within those provinces. The carbon pricing schemes in both Alberta and British Columbia are expected to meet equivalency requirements to the federal benchmark.

The output-based pricing system came into effect on January 1, 2019. The carbon levy for provinces that do not meet equivalency requirements took effect in April 2019. Alberta challenged the constitutionality of the federal government's pricing regime and the Alberta Court of Appeal ruled that the federal legislation is unconstitutional. The Supreme Court of Canada is scheduled to hear arguments regarding the federal carbon levy in March 2020.

 
 
 
AltaGas Ltd. 2019 Annual Information Form 41

    



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

As of June 1, 2019, ten facilities within the Midstream segment reported to the GHGRP as a result of the lower reporting threshold.

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

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

Under the CCIR system, facilities can emit a certain amount of GHG, free of charge from the carbon levy. This approach protects industries from competitiveness impacts that could shift production to other jurisdictions. These "free" emissions are determined based on a product-specific emissions benchmark. Benchmarks are set relative to high-performing industry peers or competitors who produce the same or similar products. Both AltaGas’ Harmattan and Gordondale facilities are considered large final emitters under the CCIR and as at December 31, 2019, were compliant with the regulation.

TIER

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

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

 
 
 
AltaGas Ltd. 2019 Annual Information Form 42

    



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

Methane Reduction Regulation
The Government of Alberta has committed to reduce methane emissions from oil and gas operations by 45 percent relative to 2014 levels by 2025. Execution of the new oil and gas methane standards will be led by the Alberta Energy Regulator, in collaboration with Alberta Energy and the Alberta Climate Change Office. Details with respect to the Alberta Government’s methane reduction program were released on December 13, 2018, and are effective January 1, 2020. The AER Directive 060 sets out requirements for flaring, incinerating, and venting in Alberta at all upstream petroleum industry wells and facilities, with specific operational requirements to address fugitive emissions and venting, which are the primary sources of methane emissions from the oil and gas industry. These operational requirements could result in significant equipment retrofit, equipment replacement, advanced planning, and investment to ensure compliance. In addition, companies are also required to have in place a fugitive emissions management program that must be designed to reduce fugitive emissions over time to achieve the 45 percent reduction target relative to 2014 levels. Companies will also be required to conduct leak detection surveys at their facilities at a prescribed frequency (annually or tri-annually) based on equipment or facility type. The AER Directive 017 also sets out measurement requirements associated with the requirements under AER Directive 060.

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

The Blair Creek facility, Townsend complex, North Pine facility, and other assets in B.C. are subject to the reporting obligations and as at December 31, 2019, are in compliance with the Greenhouse Gas Emission Reporting Regulation.

Methane Reduction

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

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

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


 
 
 
AltaGas Ltd. 2019 Annual Information Form 43

    


Carbon Tax Act
B.C.’s carbon tax is currently set at $40 per tonne of CO2e emissions. In September 2017, the B.C. government announced in its budget update that starting on April 1, 2018, carbon tax rates will increase annually by $5 per tonne of CO2e emissions until rates equal to $50 per tonne in 2021. With these increases, B.C. will exceed the carbon pricing requirements expected in the Pan-Canadian Framework.
Effective Date
BC Carbon Tax Rate ($/tonne CO2e)

Prior to 2018

$30

April 1, 2018

$35

April 1, 2019

$40

April 1, 2020

$45

April 1, 2021

$50


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

CleanBC

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


 
 
 
AltaGas Ltd. 2019 Annual Information Form 44

    


POWER BUSINESS
AltaGas’ Power business contributed revenue of $1.4 billion for the year ended December 31, 2019 (2018 - $1.2 billion), representing approximately 25 percent (201827 percent) of AltaGas’ total revenue before Corporate segment and intersegment eliminations.


 
 
 
AltaGas Ltd. 2019 Annual Information Form 45

    


The Power business is engaged in the generation and sale of capacity, electricity, ancillary services, and related products in Alberta, California, and Colorado. After the sale of the WGL distributed generation business in September 2019, biomass assets in August 2019, non-core Canadian power assets in February 2019, and the remaining 55 percent interest in the Northwest Hydro facilities in January 2019, AltaGas has 710 MW of installed power capacity from a combination of gas-fired, energy storage, and remaining distributed generation assets, as more particularly set forth in the below table:
Facility
Interest
(%)
Capacity
(MW)
Type
Geographic Region
Contracted
Expiry Date
Blythe
100
507
Gas-fired
California, U.S.
2023
Brush II
100
70
Gas-fired
Colorado, U.S.
2019
Ripon
100
50
Gas-fired
California, U.S.
n/a
Pomona Energy Storage
100
20
Storage
California, U.S.
2027
Cogeneration I
100
15
Gas-fired
Alberta, Canada
n/a
Cogeneration II
100
15
Gas-fired
Alberta, Canada
n/a
Cogeneration III
100
15
Gas-fired
Alberta, Canada
n/a
Gordondale
100
3
Gas-fired
Alberta, Canada
n/a
Distributed Generation
100
15
Various
Various regions in the U.S.
Various
TOTAL
 
710
 
 
 

The following chart provides a summary of the volumes sold, renewable capacity factor, and contracted conventional equivalent availability factor for the last two years:
 
2019
2018

Renewable power sold (GWh)
616
1,551

Conventional power sold (GWh)
1,793
3,728

Renewable capacity factor (%)
17.7
29.7

Contracted conventional equivalent availability factor (%) (1)
75.4
97.2

WGL retail energy marketing – electricity sales volumes (GWh)
13,218
5,906

(1)
Calculated as the availability factor contracted under long-term tolling arrangements adjusted for occasions where partial or excess capacity payments have been added or deducted.

Gas-Fired Generation
In southern California, the 507 MW Blythe Energy Center utilizes gas-fired generation to produce power and serves the transmission grid operated by the California Independent System Operator (CAISO) to cover periods of high demand primarily driven by the Los Angeles area. Due to the structure of the long-term PPA with SCE, the majority of the revenue from the facility is derived from being available to produce and not from actual production, therefore providing stable cash flow. The facility is directly connected to a Southern California Gas Company natural gas pipeline for its supply and has reactivated an El Paso Gas Company connection as a second supply source, and interconnects to SCE and CAISO via a 67‑mile transmission line also owned by Blythe and is part of the Blythe Energy Center. In 2019, AltaGas announced the successful recontracting of the Blythe facility to SCE. Under the tolling agreement, SCE has exclusive rights to all capacity, energy, ancillary services, and resource adequacy benefits from August 1, 2020 to December 31, 2023. California Public Utilities Commission approval was received on January 16, 2020.

In northern California, AltaGas owns Ripon, which was contracted with PG&E until May 31, 2018. Following the expiry of the PPA at Ripon, AltaGas has negotiated resource adequacy contracts that include the majority of 2020. In Colorado, the Brush II facility was contracted until December 31, 2019.

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


 
 
 
AltaGas Ltd. 2019 Annual Information Form 46

    


Battery Storage
AltaGas constructed, owns, and operates the Pomona Energy Storage facility, a lithium-ion battery storage facility. The Pomona Energy Storage facility is a 20 MW (80 MWh) facility which entered service on December 31, 2016 and is under contract for its capacity with SCE under a 10-year ESA. Under the terms of the ESA, AltaGas provides SCE with 20 MW of resource adequacy capacity for a continuous four-hour period, which represents the equivalent of 80 MWh of energy discharging capacity. AltaGas receives fixed monthly resource adequacy payments under the ESA and retains the rights to earn additional revenue from the energy and ancillary services provided by the lithium-ion batteries, which will be sold on a merchant basis into the CAISO. In addition, AltaGas is in the initial stages of permitting a new 40MW stand-alone energy storage project in Goleta, California.

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

Competition
All of the power produced in Alberta and not used by the Harmattan facility is currently sold into the Pool, which operates an open market for the exchange of electricity and is run by the AESO. The AESO establishes the power price based on offers from Pool participants using a uniform pricing model whereby the marginal unit establishes the price for all generators. AESO system controllers sort the offers by price into a merit order beginning with the lowest priced offer, thereby defining a supply curve for each hour. By matching energy supply with demand, the Pool establishes a uniform hourly market price, which is published on the AESO’s website.

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

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

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


 
 
 
AltaGas Ltd. 2019 Annual Information Form 47

    


Environmental Considerations Impacting the Power Business
The Power business is subject to the following environmental regulations:

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

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

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

As of December 31, 2019, all of AltaGas’ operating natural gas-fired power generation facilities in California were in material compliance with their air permit requirements, which are issued in accordance with federal and state emissions standards.

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

As of December 31, 2019, all of AltaGas’ operating natural gas-fired power generation facilities in California were in material compliance with cap and trade requirements. Costs associated with meeting AB 32 and California’s cap-and-trade program have been passed through to the utilities pursuant to the applicable PPA.

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

 
 
 
AltaGas Ltd. 2019 Annual Information Form 48

    


CORPORATE SEGMENT
The Corporate segment consists of general corporate investments (including investments in other public companies) and other revenue and expense items, such as general corporate overhead and interest expense, which are not directly attributable to AltaGas’ operating business segments. For the year ended December 31, 2019, the revenue for the Corporate segment was less than $1 million excluding intersegment eliminations and risk management and trading activities (2018 – less than $1 million). In addition, as at December 31, 2019, AltaGas held approximately 4 percent of the common shares of Painted Pony through the Corporate segment.

 
 
 
AltaGas Ltd. 2019 Annual Information Form 49

    


CAPITAL STRUCTURE
Description of Capital Structure
The authorized share capital of AltaGas consists of an unlimited number of Common Shares and such number of Preferred Shares issuable in series at any time as have aggregate voting rights either directly or on conversion or exchange that in the aggregate represent less than 50 percent of the voting rights attaching to the then issued and outstanding Common Shares. At December 31, 2019, AltaGas had 279,074,685 outstanding Common Shares, 5,511,220 outstanding Series A Shares, 2,488,780 outstanding Series B Shares, 8,000,000 outstanding Series C Shares, 8,000,000 outstanding Series E Shares, 6,885,823 outstanding Series G Shares, 1,114,177 Series H Shares, 8,000,000 outstanding Series I Shares, and 12,000,000 outstanding Series K Shares.

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

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

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


 
 
 
AltaGas Ltd. 2019 Annual Information Form 50

    


Preferred Shares (1)
 
Current Yield

Annual dividend  
per share (2)

Redemption price
per share

Redemption and conversion  
option date (3) (4)
Right to  
convert into (4)
Series A Shares (5)
3.38
%

$0.845


$25

September 30, 2020
Series B
Series B Shares (6) (7)
Floating

Floating


$25

September 30, 2020
Series A
Series C Shares (8)
5.29
%

US$1.3225


US$25

September 30, 2022
Series D
Series E Shares (5)
5.393
%

$1.34825


$25

December 31, 2023
Series F
Series G Shares (5)
4.62
%

$1.1558


$25

September 30, 2024
Series H
Series H Shares (6) (7)
Floating

Floating


$25

September 30, 2024
Series G
Series I Shares (9)
5.25
%

$1.3125


$25

December 31, 2020
Series J
Series K Shares (10)
5.00
%

$1.25


$25

March 31, 2022
Series L
(1)
This table only includes those series of preferred shares that are currently issued and outstanding. The Corporation is authorized to issue up to 8,000,000 of each of Series D Shares, Series F Shares, and Series J Shares, and up to 12,000,000 of Series L Shares, subject to certain conditions, upon conversion by the holders of the applicable currently issued and outstanding series of preferred shares noted opposite such series in the table on the applicable conversion option date. If issued upon the conversion of the applicable series of preferred shares, Series F Shares, Series J Shares, and Series L Shares are also redeemable for $25.50, and Series D Shares are redeemable for US$25.50 on any date after the applicable conversion option date, plus all accrued but unpaid dividends to, but excluding, the date fixed for redemption.
(2)
The holders of Series A Shares, Series C Shares, Series E Shares, Series G Shares, Series I Shares, and Series K Shares are entitled to receive a cumulative quarterly fixed dividend as and when declared by the Board of Directors. The holders of Series B Shares and Series H Shares are entitled to receive a quarterly floating dividend as and when declared by the Board of Directors. If issued upon the conversion of the applicable series of Preferred Shares, the holders of Series D Shares, Series F Shares, Series J Shares, and Series L Shares will be entitled to receive a quarterly floating dividend as and when declared by the Board of Directors.
(3)
AltaGas may, at its option, redeem all or a portion of the outstanding shares for the redemption price per share, plus all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary thereafter.
(4)
The holder will have the right, subject to certain conditions, to convert their preferred shares of a specified series into Preferred Shares of that other specified series as noted in this column of the table on the applicable conversion option date and every fifth anniversary thereafter.
(5)
Holders of Series A Shares, Series E Shares, and Series G Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at a rate equal to the sum of the then five-year Government of Canada bond yield 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, 2019, the floating quarterly dividend rate is $0.26803 per share for Series B Shares and $0.29289 per share for Series H Shares for the period starting December 31, 2019 to, but excluding, March 31, 2020.
(7)
Series B Shares can be redeemed for $25.50 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 I Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the then five-year Government of Canada bond yield plus 0.0419, provided that, in any event, such rate shall not be less than 5.25 percent per annum.
(10)
Holders of Series K Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the then five-year Government of Canada bond yield plus 3.80 percent, provided that, in any event, such rate shall not be less than 5.00 percent per annum.

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

The Board of Directors may divide any unissued Preferred Shares into series and fix the number of shares in each series and the designation, rights, privileges, restrictions, and conditions thereof. The Preferred Shares of each series will rank on parity with Preferred Shares of every other series with respect to accumulated dividends and return of capital and the holders

 
 
 
AltaGas Ltd. 2019 Annual Information Form 51

    


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

The rights, privileges, restrictions and conditions attaching to the Preferred Shares as a class may be repealed, altered, modified, amended or amplified or otherwise varied only with the sanction of the holders of the Preferred Shares given in such manner as may then be required by law, subject to a minimum requirement that such approval be given by resolution in writing executed by all holders of Preferred Shares entitled to vote on that resolution or passed by the affirmative vote of at least 66⅔ percent of the votes cast at a meeting of holders of Preferred Shares duly called for such purpose.

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

Medium Term Notes
AltaGas has issued senior unsecured notes in the form of MTNs. Details with respect to the issued and outstanding MTNs can be found in Note 16 to AltaGas’ audited Consolidated Financial Statements as at and for the year ended December 31, 2019 filed on SEDAR at www.sedar.com. The MTNs are not listed or quoted on any exchange.

WGL and Washington Gas Notes
WGL and Washington Gas issue long-term notes with individual terms regarding interest rates, maturities and call or put options. These notes can have maturity dates of one or more years from the date of issuance. For a complete list of such notes currently outstanding please refer to Note 16 in AltaGas’ audited Consolidated Financial Statements as at and for the year ended December 31, 2019.
GENERAL
Employees
At December 31, 2019, there were 2,801 individuals employed by AltaGas.
 
December 31, 2019
Utilities
2,186
Midstream
295
Power
139
Corporate
181
Total
2,801

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

 
 
 
AltaGas Ltd. 2019 Annual Information Form 52

    


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

The term of office of any director continues until the annual meeting of Shareholders of AltaGas next following the director’s election or appointment, unless the term ends earlier in the event of death, resignation, or removal, disqualification or other reason in accordance with the constating documents of AltaGas. The Shareholders are annually entitled to elect the Board of Directors.

The following table sets forth the names of the directors of AltaGas on February 21, 2020, their municipalities of residence, and their principal occupations within the last five years.
Name of Director,
Municipality of
Residence, and Position
Principal Occupation During the Past Five Years
Director Since
Victoria A. Calvert (1)
Calgary, Alberta, Canada
Director
Ms. Calvert is a Corporate Director and Professor Emerita of Business at Mount Royal University in Calgary, where she taught from 1988 to 2018. She was also a Director of the Canadian Alliance of Community Service Learning from 2009 to 2017.
November 1, 2015
David W. Cornhill (1) (2)
Calgary, Alberta, Canada
Director
Mr. Cornhill is a founding shareholder of AltaGas and its predecessors. Mr. Cornhill was Chief Executive Officer from 1994 to 2016 and served as interim Co-CEO from July to December 2018. He was Chairman of the Board from 1994 to April 2019. Prior to forming AltaGas, Mr. Cornhill served in various capacities with Alberta and Southern Gas Co. Ltd., including Vice President, Finance and Administration, Treasurer and President and Chief Executive Officer.
Director of AltaGas
(and its predecessors)
since April 1, 1994
Randall L. Crawford (3)
Calgary, Alberta, Canada
Director
Mr. Crawford has been the Chief Executive Officer since December 2018. Refer to the disclosure under "Executive Officers" for further information.
December 10, 2018
Allan L. Edgeworth (1)
North Vancouver, B.C., Canada
Director
Mr. Edgeworth is a Professional Engineer and Corporate Director. He was the President of ALE Energy Inc., a private consulting company, from January 2005 through December 2015. Prior thereto, Mr. Edgeworth was with Alliance Pipeline Ltd, initially as Executive Vice President and Chief Operating Officer and later as the President and Chief Executive Officer.
Director of AltaGas
(and its predecessors)
since March 2, 2005
Daryl H. Gilbert (1) (4)
Calgary, Alberta, Canada
Director
Mr. Gilbert is a Professional Engineer. He joined JOG Capital Inc. in May 2008 as a Managing Director and Investment Committee Member. Prior to becoming an independent businessman in 2005, Mr. Gilbert was with Gilbert Laustsen Jung Associates Ltd. (now GLJ Petroleum Consultants Ltd.) from 1979 to 2005, serving as President and Chief Executive Officer from 1994 to 2005.
Director of AltaGas
(and its predecessors)
since May 4, 2000
Robert B. Hodgins (1) (5)
Calgary, Alberta, Canada
Director
Mr. Hodgins is a Chartered Professional Accountant and Chartered Accountant and has been an independent businessman since November 2004. Mr. Hodgins has been a Senior Advisor, Investment Banking for Canaccord Genuity Corp. since September 2018. Mr. Hodgins served as the Chief Financial Officer of Pengrowth Energy Trust from 2002 to 2004. Mr. Hodgins also held the positions of Vice President and Treasurer of Canadian Pacific Limited and Chief Financial Officer of TransCanada PipeLines Limited.
Director of AltaGas
(and its predecessors)
since March 2, 2005

 
 
 
AltaGas Ltd. 2019 Annual Information Form 53

    


Name of Director,
Municipality of
Residence, and Position
Principal Occupation During the Past Five Years
Director Since
Cynthia Johnston (1)
Victoria, B.C., Canada
Director
Ms. Johnston is a Corporate Director. She was Executive Vice President, Gas, Renewables and Operations Services at TransAlta Corporation from 2015 to 2017. From 2011 to 2015, she held a number of other executive positions with TransAlta, including Chief Operating Officer of TransAlta Renewables Inc., President, TAMA Transmission, and Executive Vice President, Enterprise Risk and Corporate Services.
July 25, 2018
Pentti O. Karkkainen (1)
West Vancouver, B.C., Canada
Chair of the Board
Mr. Karkkainen is a Corporate Director. He was a co-founder and General Partner of KERN Partners from 2000 to 2014, and was the firm’s Senior Strategy Advisor from 2014 until 2015. Prior thereto, Mr. Karkkainen was the Managing Director and Head of Oil and Gas Equity Research at RBC Capital Markets.
July 25, 2018
Phillip R. Knoll (1)
Kelowna, B.C., Canada
Director
Mr. Knoll is a Professional Engineer and has been the President of Knoll Energy Inc. since 2006. Mr. Knoll served as interim Co-CEO of AltaGas from July to December 2018. He was CEO of Corridor Resources Inc. from October 2010 to September 2014. Prior thereto, Mr. Knoll held senior roles with a number of companies, including Duke Energy Gas Transmission, Maritimes & Northeast Pipeline, Westcoast Energy Inc., TransCanada Pipelines Limited and Alberta Natural Gas Company Ltd.
November 1, 2015
Terry D. McCallister (3)
Santa Fe, New Mexico, USA
Director
Mr. McCallister is an independent businessman. He was the Chairman and Chief Executive Officer of WGL and of Washington Gas from October 2009 to July 2018. Prior to this, he served as President and Chief Operating Officer of WGL and Washington Gas, joining Washington Gas in 2000 as Vice President of Operations. He has also held various leadership positions with Southern Natural Gas and Atlantic Richfield Company.
July 25, 2018
Linda G. Sullivan (1)
Mullica Hill, New Jersey, USA
Director
Ms. Sullivan is a Corporate Director. She was Executive Vice President and Chief Financial Officer at American Water Works Company, Inc. from 2016 until 2019, and prior thereto was Senior Vice President and Chief Financial Officer from 2014. Prior to joining American Water Works, she held various roles with the Edison International companies, including Senior Vice President and Chief Financial Officer at Southern California Edison Company.
January 9, 2020
Nancy G. Tower (1)
Tampa, Florida, USA
Director

Ms. Tower is the President and Chief Executive Officer of Tampa Electric Company, a regulated electric utility and a subsidiary of Emera Inc. (Emera) in Tampa, Florida, a position she has held since December 2017. Prior thereto, she was the Chief Corporate Development Officer of Emera from 2014 to 2017. Ms. Tower joined Emera in 1997, and held several senior positions at Emera and with its subsidiaries, including Controller and Vice President, Customer Operations of Nova Scotia Power Inc., Chief Financial Officer of Emera, and Chief Executive Officer of Emera Newfoundland and Labrador.
January 9, 2020
(1)
Independent director. Mr. Cornhill and Mr. Knoll acted as interim Co-CEOs from July 24, 2018 to December 9, 2018 until the appointment of Mr. Crawford as CEO, however the interim role did not impact their independence.
(2)
Mr. Cornhill is no longer deemed to be in a material relationship with the Corporation as it has been three years since he retired from his executive position and he has been determined to be independent under National Instrument 52-110.
(3)
Mr. Crawford, as current CEO of the Corporation, is not considered independent. Mr. McCallister, as former CEO of a major subsidiary of the Corporation until July 6, 2018, is deemed to be a non-independent director until the third anniversary of that date.
(4)
Mr. Gilbert was a director of LGX Oil + Gas Inc. (LGX) from August 12, 2013 to June 7, 2016. On June 7, 2016, LGX was, on application by LGX's senior lender, the subject of a consent receivership order under the Bankruptcy and Insolvency Act (Canada) pursuant to which Ernst & Young Inc. was appointed the receiver of all of LGX’s current and future assets, undertakings and properties. LGX was the subject of a cease trade order issued by the ASC on September 6, 2016 for failure to file certain financial statements. On February 9, 2017, approval and vesting orders were granted by the Court of Queen’s Bench of Alberta with respect to the liquidation and sale of assets by the receiver. Mr. Gilbert was a director of Connacher Oil & Gas Limited (Connacher) from October 2014 until February 25, 2019. Mr. Gilbert initially joined the board of directors of Connacher to assist in guiding the corporation through what turned out to be several financial restructurings. On May 17, 2016, Connacher applied for and was granted protection from its creditors by the Court of Queen’s Bench of Alberta under the CCAA. On May 20, 2016, the TSX delisted the common shares of Connacher for failure to meet

 
 
 
AltaGas Ltd. 2019 Annual Information Form 54

    


continued listing requirements. On February 16, 2019 Connacher announced that it was proceeding to close on a credit bid transaction with its supporting lenders. Mr. Gilbert was a director of Trident Exploration Corp. (Trident) from 2010 to 2018. On April 30, 2019, Trident ceased operations and transferred all its assets to the Alberta Energy Regulator.
(5)
Mr. Hodgins was a director of Skope Energy Inc. (Skope) from December 15, 2010 to February 19, 2013. On November 27, 2012, Skope was granted protection from its creditors by the Court of Queen’s Bench of Alberta pursuant to the CCAA to implement a restructuring which was approved by the required majority of Skope’s creditors. The restructuring was sanctioned by the Court of Queen’s Bench of Alberta in February of 2013.

AltaGas has four standing committees of the Board of Directors: (1) Audit, (2) Governance, (3) Human Resources and Compensation (HRC), and (4) Environment, Health and Safety (EH&S). The members of each of these committees as of February 21, 2020 are identified below:
Director
Audit Committee
Governance Committee
HRC Committee
EH&S Committee
Victoria A. Calvert
 
n
n
 
David W. Cornhill
 
 
 
 
Allan L. Edgeworth
n
 
Chair
 
Daryl H. Gilbert
 
 
n
 
Cynthia Johnston
n
 
 
Chair
Pentti O. Karkkainen
 
 
 
 
Robert B. Hodgins
Chair
n
 
 
Phillip R. Knoll
 
Chair
 
n
Terry D. McCallister
 
 
 
n
Linda G. Sullivan
n
 
n
 
Nancy G. Tower
n
 
n
 


 
 
 
AltaGas Ltd. 2019 Annual Information Form 55

    


Executive Officers
The names, municipality of residence and position of each of the current executive officers of AltaGas are as follows:
Name of Officer, Municipality of Residence, and
Position with AltaGas Ltd.
Principal Occupation During the Past Five Years
Randall L. Crawford
Calgary, Alberta, Canada
President and Chief Executive Officer
Director
Chief Executive Officer of AltaGas since December 2018. Prior to joining AltaGas, Mr. Crawford was with EQT Midstream Partners, LP from 2012 to 2017, most recently as Executive Vice President and Chief Operating Officer, and with EQT Corporation as Senior Vice President and President Midstream, Commercial and Distribution from 2007 to 2017.
D. James Harbilas
Calgary, Alberta, Canada
Executive Vice President and Chief Financial Officer

Executive Vice President and Chief Financial Officer of AltaGas from June 2019. Prior to joining AltaGas, Mr. Harbilas was the Executive Vice President and Chief Financial Officer of Enerflex Ltd. from 2007.
Corine R.K. Bushfield
Airdrie, Alberta, Canada
Executive Vice President, Chief Administrative Officer
Executive Vice President, Chief Administrative Officer of AltaGas from December 2016. Senior Vice President and Chief Financial Officer of Long Run Exploration Ltd. from March 2013 to September 2016. Vice President and Assistant Controller of Encana Corporation from 2010 to March 2013.

Donald M. Jenkins
Washington, DC, U.S.A.
Executive Vice President and President Utilities, President of Washington Gas Light Company

Executive Vice President and President, Utilities of AltaGas from December 2019. President of WGL and Washington Gas from December 2019. Prior thereto, Mr. Jenkins was with EQT Corporation from 2012, most recently as Chief Commercial Officer.
Fredrick K. Dalena
Coraopolis, Pennsylvania
Executive Vice President, Commercial Strategy and Business Development
Executive Vice President, Commercial Strategy and Business Development of AltaGas since December 2018. Principal Midstream Business Development of EQT Corporation from 2015 to 2017. Executive Vice President Midstream Commercial Strategy from 2014 to 2015. Various executive commercial roles in EQT’s Distribution, Midstream and Energy Services companies since joining EQT in 2003.
Randy W. Toone
Calgary, Alberta, Canada
Executive Vice President and President, Midstream
Executive Vice President and President, Midstream from January 2019. Executive Vice President and Acting President from July to December 2018. Executive Vice President Gas from June 2017. Executive Vice President, Commercial and Business Development from December 2016 to June 2017. Chief Operating Officer of CSV Midstream Solutions from July 2014 to November 2016. Country Manager of TAG Oil Ltd. from May 2013 to June 2014. Other roles with AltaGas prior to 2014 include President Utilities, President Gas, and Co-President Gas.
Bradley B. Grant
Calgary, Alberta, Canada
Executive Vice President and Chief Legal Officer

 
Executive Vice President and Chief Legal Officer of AltaGas since July 2018. Prior thereto, Vice President and General Counsel of AltaGas from May 2015. Partner with the law firm of Stikeman Elliott LLP from January 2004 to May 2015.
Audit Committee
Composition of the Audit Committee
The Committee is currently comprised of five members, Allan Edgeworth, Robert Hodgins, Cynthia Johnston, Linda Sullivan and Nancy Tower. Mr. Hodgins is the chair of the Committee. All of the members of the Committee are independent and financially literate as defined under Canadian securities law.

Relevant Education and Experience
Mr. Edgeworth was the President of ALE Energy Inc. from January 2005 through December 2015. Mr. Edgeworth was the President and Chief Executive Officer of Alliance Pipeline from 2001 until December 2004. Mr. Edgeworth joined Alliance Pipeline in 1998 as Executive Vice President and Chief Operating Officer. Prior to that, Mr. Edgeworth spent almost 20 years

 
 
 
AltaGas Ltd. 2019 Annual Information Form 56

    


with Westcoast Energy Inc. where he held various positions including Vice President of Pipeline Operations, Senior Vice President of Regulatory Affairs and President Pipeline Division.

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

Ms. Johnston was Executive Vice President, Gas, Renewables and Operations Services at TransAlta Corporation from 2015 to 2017. From 2011 to 2015, she held a number of other executive positions with TransAlta, including Chief Operating Officer of TransAlta Renewables Inc., President, TAMA Transmission, and Executive Vice President, Enterprise Risk and Corporate Services. Prior thereto, Ms. Johnston held various executive leadership positions with TransAlta and FortisAlberta. She served on the Finance, Audit and Risk Committee of the Lethbridge College Board of Governors from 2011 to 2014 and as chair from 2013 to 2014.

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

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

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


 
 
 
AltaGas Ltd. 2019 Annual Information Form 57

    


External Auditor Service Fees by Category
The fees billed by Ernst & Young LLP (E&Y), AltaGas’ external auditor, during 2019 and 2018 were as follows:
Category of External Auditor Service Fee (1)
 
2019
 
2018
Audit fees
$
7,783,502
$
2,766,074
Audit-related fees (2)
 
833,268
 
1,242,606
Tax compliance fees (3)
 
259,313
 
66,389
All other fees (4)
 
357,002
 
86,970
Total 
$
9,233,085
$
4,162,039
(1)
Due to the timing of appointing E&Y as WGL's auditor, $3.7 million of fees relating to 2018 were paid in 2019.
(2)
Represent the aggregate fees billed by E&Y for assurance and related services that were reasonably related to the performance of the audit or review of AltaGas’ financial statements and were not reported under "Audit fees". During 2019 and 2018, the nature of the services provided included: review of prospectuses and security filings; research of accounting and audit-related issues (including those related to the acquisition of WGL); review of pro forma consolidated financial statements; review of new accounting standards implementation; internal controls assessment; cost allocation manual audits; environmental, social, and governance services; and registration costs for the Canadian Public Accountability Board, the Public Company Accounting Oversight Board, and the Financial Accounting Standards Board.
(3)
During 2019 and 2018, the nature of the services provided was for tax compliance and transfer pricing.
(4)
Represents the aggregate fees billed by E&Y for products and services, other than those reported with respect to the other categories of service fees. During 2019 and 2018, the nature of the services provided was for translation services and an assessment of AltaGas' IT risk management and cyber security.

RISK FACTORS
Set forth below is a summary of certain risk factors relating to AltaGas and the business of AltaGas. The risks described below are not an exhaustive list of all risks, nor should they be taken as a complete summary of all the risks associated with the applicable business being conducted. Security holders and prospective security holders of AltaGas should carefully review and consider the risk factors set out below as well as all other information contained and incorporated by reference in this AIF before making a decision on investment and should consult their own experts where necessary. Information regarding AltaGas’ risk management activities can be found in AltaGas’ management information circular dated May 2, 2019 and will also be included in AltaGas’ management information circular for its 2020 annual meeting of the Shareholders.

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

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

Safety has been and continues to be a core value of AltaGas and is integral to how AltaGas operates. AltaGas actively works with industry groups and communities within which it operates to improve safety. Also, AltaGas has policies, procedures, and emergency response plans in place, which AltaGas regularly monitors and evaluates to identify opportunities for improvement in its safety programs. In addition, in the Utilities business, with support from each of certain regulatory commissions, AltaGas is accelerating the replacement of aging pipeline infrastructure prioritized on a risk-based approach and has implemented

 
 
 
AltaGas Ltd. 2019 Annual Information Form 58

    


preventive and remedial measures to address increased leak rates in its distribution system caused by an increase in the volume of natural gas containing low concentration of halogenated hydrocarbons received from its suppliers.

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

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

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

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

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

Regulatory
AltaGas’ businesses are subject to extensive and complex laws and regulations in the jurisdictions in which they carry on business. Regulations and laws are subject to ongoing policy initiatives, and AltaGas cannot predict the future course of regulations and their respective ultimate effects on AltaGas’ businesses. Changes in the regulatory environment may be beyond AltaGas’ control and may significantly affect AltaGas' businesses, results of operations, and financial conditions.

 
 
 
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Pipelines and facilities can be subject to common carrier and common processor applications and to rate setting by the regulatory authorities in the event an agreement on fees or tariffs cannot be reached with producers. The export and import of energy is also subject to regulatory approvals. Power facilities are subject to regulatory approvals and regulatory changes in tariffs, market structure, and penalties. Washington Gas, SEMCO Gas, ENSTAR, and CINGSA operate in regulated marketplaces where regulatory approval is required to afford the utilities the opportunity to earn their regulated returns that provide for recovery of costs and a return on capital and may limit the ability to make and implement independent management decisions, including, without limitation, setting rates charged to customers, determining methods of cost recovery, and issuing debt. Earnings of AltaGas’ regulated utilities may be impacted by a number of factors, including, without limitation, (i) changes in the regulator-approved allowed return on equity and common equity component of capital structure; (ii) changes in rate base; (iii) changes in gas delivery volumes; (iv) changes in the number and composition of customers; (v) variances between actual expenses incurred and forecast expenses used to determine revenue requirements and set customer rates; and (vi) recovery of unplanned costs through rate cases. Changes to regulatory and environmental laws could increase AltaGas’ operating costs and require enhanced disclosures. Increased expenditures could include capital expenditures, operating expenditures, and decommissioning, abandonment, and reclamation costs, which may not be recoverable in the marketplace or through rate cases. These changes could adversely affect AltaGas, resulting in current operations and projects becoming less profitable or uneconomic and could require significant investment to develop new technologies.

Litigation

In the course of its business, AltaGas is subject to lawsuits and other claims. Defense and settlement costs associated with such lawsuits and claims can be substantial, even with respect to lawsuits and claims that have no merit. Due to the inherent uncertainty of the litigation process, the resolution of any particular legal proceeding could have a material adverse effect on the financial position or operating results of AltaGas.

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

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

As well, Washington Gas has recorded environmental liabilities for costs expected to be incurred to remediate sites where Washington Gas or a predecessor affiliate operated manufactured gas plants (MGPs). Estimates of liabilities for environmental response costs are difficult to determine with precision because of the various factors that can affect their ultimate level. See the section "Environmental Regulation", "Business of the Corporation – Utilities Business – Environmental Regulations Impacting the Utilities Business".


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

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

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

The operations of AltaGas’ retail energy-marketing business, are weather sensitive and seasonal, with a significant portion of revenues derived from the sale of natural gas to retail customers for space heating during the winter months, and from the sale of electricity to retail customers for cooling during the summer months. Weather conditions directly influence the volume of natural gas and electricity delivered to customers. Weather conditions can also affect the short-term pricing of energy supplies that the retail energy-marketing business may need to procure to meet the needs of its customers. Similarly, the business of AltaGas’ Midstream business is seasonal due to the tendency of storage and transportation spreads to increase during the winter. Deviations from normal weather conditions and the seasonal nature of these businesses can create large fluctuations in short-term cash requirements and earnings for these businesses.

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

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

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

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

Regulatory and environmental laws affecting AltaGas have changed, and will continue to change, over time. Concerns over climate change, including GHG emissions, fossil fuels, and land use, could lead to the introduction of additional or more stringent laws and regulation that would impact AltaGas, increasing AltaGas' exposure to legal risk.

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

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

 
 
 
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businesses. Washington Gas may be unable to recover from customers through the regulatory process all or some of these costs and may be unable to earn its authorized rate of return on these costs.

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

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

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

Washington Gas and the SPE made certain ring-fencing commitments, such that the assets of the Ring-Fenced Entities will not be available to satisfy the debt or contractual obligations of any Non-Ring-Fenced Entity.

General Economic Conditions
AltaGas’ operations are affected by the condition and overall strength of the global economy and, in particular, the economies of Canada and the U.S. During economic downturns, the demand for the products and services that AltaGas provides and the supply of or demand for power, natural gas, and NGLs may be adversely affected. The occurrence of periods of poor economic conditions or low or negative economic growth could have an adverse impact on AltaGas’ results and restrict AltaGas’ ability to make dividends to Shareholders.

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

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

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

Additionally, with respect to WGL, a reduction in credit rating could lead to higher borrowing costs. Merger-related commitments placed limitations on Washington Gas' ability to recover increased costs of financing from customers if caused by the merger or the ongoing affiliation of AltaGas and its affiliates. Therefore, a downgrade in AltaGas' or WGL's credit ratings could adversely affect earnings or cash flows by limiting Washington Gas’ ability to earn its allowed rate of return. Credit ratings are intended to provide investors with an independent measure of credit quality of any issuer of securities. The credit ratings assigned to AltaGas’ securities by the rating agencies are not recommendations to purchase, hold, or sell the securities in as much as such ratings do not comment as to market price or suitability for a particular investor. Any rating may not remain in

 
 
 
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effect for any given period of time or may be revised or withdrawn entirely by a rating agency in the future if in its judgment circumstances so warrant.

Foreign Exchange Risk
AltaGas' functional currency is the Canadian dollar. AltaGas is exposed to foreign exchange risk through its investments in the U.S. and is exposed to foreign exchange risk in the LNG and LPG export business. Changes in the Canadian dollar/U.S. dollar exchange rate could impact the earnings of AltaGas, the value of the U.S. investments, and the cash generated from the U.S. businesses. AltaGas operates internationally, with an increasing amount of the Corporation’s net income earned outside of Canada. As a result, AltaGas may experience a discrepancy between the currencies in which liabilities are incurred and the currency in which revenues are generated. This could adversely affect AltaGas’ results due to the imposition of additional taxes and cost of currency exchange.

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

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

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

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


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

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

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

Security breaches of AltaGas’ information technology infrastructure, including, without limitation, cyber-attacks and cyber-terrorism, or other failures of AltaGas’ information technology infrastructure could result in disruptions of natural gas distribution operations and other operational outages, ability to operate safely, delays, damage to assets, the environment or to AltaGas’ reputation, diminished customer confidence, lost profits, lost data including, without limitation, the unauthorized release of customer, employee or company data that is crucial to AltaGas’ operational security or could adversely affect the ability to deliver and collect on customer bills, increased regulation and other adverse outcomes, including, without limitation, material legal claims and liability or fines or penalties under applicable laws and adversely affect its business operations and financial results.

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

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

Dependence on Certain Partners

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

 
 
 
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develop interests or objectives which are different from or even in conflict with the objectives of AltaGas. AltaGas does not have the sole power to direct the business and operations of such facilities and AltaGas faces the risk of being impacted by partners’ decisions and by potential disagreements regarding operations and other business decisions. Any such differences could have a negative impact on the success of such facilities. AltaGas is sometimes required, through the permitting and approval process of such facilities, to notify and consult with various stakeholder groups, including, without limitation, landowners, Indigenous peoples, and municipalities. Any unforeseen delays in this process may negatively impact the ability of AltaGas to complete any given facility on time or at all.

Growth Strategy Risk
During 2019, AltaGas made significant changes to its business, including asset sales and a strategic shift in focus to primarily the Utilities and Midstream segments. It is possible that the changes in strategy AltaGas has implemented and plans to continue implementing in 2020 and onwards will not be as successful as projected.

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

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

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

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

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

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

Impact of Competition in AltaGas’ Midstream and Power Businesses

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

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

Counterparty Credit Risk

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

Composition Risk

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


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

Rep Agreements

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

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

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

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

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

Market Value of Common Shares and Other Securities
AltaGas cannot predict at what price the Common Shares, Preferred Shares, or other securities issued by AltaGas will trade in the future. Common Shares, Preferred Shares, and other securities of AltaGas will not necessarily trade at values determined solely by reference to the underlying value of the Corporation’s assets. One of the factors that may influence the market price of such securities is the annual yield on such securities. An increase in market interest rates may lead purchasers of securities of AltaGas to demand a higher annual yield and this could adversely affect the market price of such securities. In addition, the market price for securities of AltaGas may be affected by announcements of new developments, changes in AltaGas’

 
 
 
AltaGas Ltd. 2019 Annual Information Form 68

    


operating results, differences between results and analysts’ expectations, changes in credit ratings, changes in general market conditions, fluctuations in the market for securities, and numerous other factors beyond the control of AltaGas.

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

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

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

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

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


 
 
 
AltaGas Ltd. 2019 Annual Information Form 69

    


Risk Management Costs and Limitations
AltaGas uses derivative financial instruments to hedge risks associated with exchange rates, interest rates, and commodity price fluctuations. AltaGas does not enter into derivatives transactions for speculative purposes. AltaGas' derivative transactions cannot mitigate all risk associated with AltaGas’ business nor the risk of unauthorized activities notwithstanding appropriate oversight through AltaGas’ risk management function. Any such unauthorized activities could materially adversely affect AltaGas' business, operations, and financial condition.

In addition, rules implementing the derivatives transaction provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) in the U.S. could have an adverse impact on AltaGas’ ability to hedge risks associated with the business. The Dodd-Frank Act regulates derivatives transactions, which include certain instruments, such as interest rate swaps, and commodity options, financial, and other contracts used in AltaGas’ risk management activities. The Dodd-Frank Act requires that most swaps be cleared through a registered clearing facility and that they be traded on a designated exchange or swap execution facility, with certain exceptions for entities that use swaps to hedge or mitigate commercial risk. Requirements of the law and any new regulations could increase the operational and transactional cost of derivatives contracts and affect the number and/or creditworthiness of available counterparties. In addition, commencing in 2016, certain Canadian securities regulatory authorities adopted instruments in relation to the trading, clearing, and reporting of derivatives. While the nature of AltaGas’ derivatives activities may entitle AltaGas to exemptions from reporting obligations, there can be no assurance that AltaGas will be able to continue to rely on such exemptions for all transactions. In order to ensure its compliance with such obligations, AltaGas is required to incur the time and financial expense associated with maintaining the systems necessary to report its derivatives trades to a derivatives trade repository, which could increase the operational and transactional cost of derivatives contracts.

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

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

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


 
 
 
AltaGas Ltd. 2019 Annual Information Form 70

    


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

Electricity and Resource Adequacy Prices

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

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

Labor Relations
The operations and maintenance staff at the Blythe Energy Center and Younger, as well as some employees of Washington Gas and SEMCO Energy, are members of a labor union. Aspects of RIPET’s operations are also performed by employees that are members of a labor union. Labor disruptions could restrict the ability of the Blythe Energy Center to generate power, the ability of Younger to process natural gas and produce NGLs, operations at RIPET, or could affect Washington Gas and SEMCO Energy’s operations and therefore could affect AltaGas’ cash flow and net income (loss).

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

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


 
 
 
AltaGas Ltd. 2019 Annual Information Form 71

    


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

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

In addition, it is possible that the integration process could take longer than anticipated and could result in the disruption of AltaGas’ businesses, processes, and systems or inconsistencies in standards, controls, procedures, practices, and policies, any of which could adversely affect the combined company’s ability to achieve the anticipated benefits of the acquisition as and when expected. The overall combination of the businesses may also result in material unanticipated problems, expenses, liabilities, competitive responses, and loss of customer and other business relationships. Failure to achieve these anticipated benefits or the incurrence of unanticipated expenses and liabilities could materially adversely affect AltaGas’ business, financial condition, operating results, and prospects.
 
ENVIRONMENTAL, HEALTH, SAFETY, AND SOCIAL POLICIES
Values
AltaGas' core values form the foundation from which AltaGas does business with its customers, partners, and other stakeholders, and serve as a blueprint to fulfill the Company's vision and strategy. AltaGas' core values are:

Work Safely, Think Responsibly;
Act with Integrity;
Make Informed Decisions;
Achieve Results; and
Invest in our People and Foster Diversity.

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


 
 
 
AltaGas Ltd. 2019 Annual Information Form 72

    


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

Operating its business with the highest regard for safety for its employees, contractors, and stakeholders;
Protecting the environment and minimizing its impact;
Building long-term, mutually beneficial relationships with Indigenous peoples, partners, and communities;
Working closely with governments and regulatory agencies to develop long-term sustainable projects; and
Investing in communities through employment and training opportunities and donations to charitable organizations.

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

AltaGas' Environment, Health and Safety (EHS) policy guides its commitment to managing and minimizing its environmental impacts. Its EHS standards set expectations and parameters that apply consistently across the organization and provide a framework to reinforce our safety culture. This includes implementing programs that safeguard its people and the environment, proactively identifying and managing risks, and applying lessons learned and best practices to improve its performance. AltaGas’ EHS Management System provides a framework that establishes enterprise-wide requirements and expectations, and outlines actions and accountabilities for EHS-related performance within a Plan-Do-Check-Act cycle. Each business division is responsible for its internal policies and continuous improvement within this framework.
To ensure AltaGas is prepared and its teams are equipped to quickly and safely respond to emergency situations, it maintains comprehensive emergency response plans for each of its facilities, and for all lines of business. It conducts regular emergency response exercises, which are often coordinated with local first responders. These exercises offer a better understanding of each party's roles and responsibilities in the event of an emergency, resulting in a more effective response.
Policies
AltaGas has a number of policies in place with respect to environmental stewardship, health and safety, and social responsibility. Notably, AltaGas’ Code of Business Ethics (COBE) ensures it upholds its core values and conducts business in a safe, respectful, and ethical manner. The COBE is applicable to its people, contractors, suppliers, and partners, and is approved, along with its policies, by the Board. To ensure adherence to the COBE, all employees are required to review it and its related policies, and certify their understanding and compliance, on an annual basis. AltaGas' COBE related policies include:

Whistleblower;
Respectful Workplace;
Privacy;
Environment, Health and Safety;
Drugs and Alcohol in the Workplace;
Information Security;
Social Media and Acceptable Use;
Disclosure;
Conflicts of Interest;
Anti-Bribery and Anti-Corruption; and
Securities Trading and Reporting.

In December 2019, AltaGas released its inaugural Environmental, Social & Governance (ESG) Report, highlighting its 2018 performance in several key areas relevant to the long-term sustainability of its business, and demonstrating its ongoing commitment to transparency. The report can be found on AltaGas’ new ESG microsite, www.ESGatAltaGas.ca.
Environmental Regulation
AltaGas faces uncertainties related to future environmental laws and regulations affecting its business and operations. Existing environmental laws and regulations may be revised or interpreted more strictly, and new laws or regulations may be adopted or become applicable to AltaGas, which may result in increased compliance costs or additional operating restrictions, each of which could reduce AltaGas’ earnings and adversely affect AltaGas’ business.

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

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

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

U.S. Federal Air and GHG Regulations
Greenhouse Gas Reporting Program (U.S. GHGRP)
The U.S. GHGRP requires reporting of GHG data and other relevant information from large GHG emission sources, fuel, and industrial gas suppliers, and CO2 injection sites in the United States. A total of 41 categories of reporters are covered by the U.S. GHGRP. Facilities determine whether they are required to report based on the types of industrial operations

 
 
 
AltaGas Ltd. 2019 Annual Information Form 73

    


located at the facility, their emission levels, or other factors. Facilities are generally required to submit annual reports under Part 98 if:

GHG emissions from covered sources exceed 25,000 metric tons CO2e per year;
Supply of certain products would result in over 25,000 metric tons CO2e of GHG emissions if those products were released, combusted, or oxidized; or
The facility receives 25,000 metric tons or more of CO2 for underground injection.

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

For further discussion of the U.S. federal and state air emission regulations, please see "Business of the Corporation – Power Business – Environmental Considerations Impacting the Power Business".
Stakeholder Engagement and Indigenous Peoples Policy
AltaGas works to build long-term collaborative relationships that are based on trust, the willingness to listen and learn, and the desire to involve Indigenous peoples meaningfully in every phase of its developments. AltaGas’ approach is underscored by principles that help to enable strong relationships, including:

Open and honest communication throughout all aspects of a project;
A willingness to integrate Indigenous teachings and knowledge to help inform AltaGas’ environmental actions and community solutions as part of the project planning and development;
A desire to engage with as many community members as possible; and
A desire to educate, train, and build capacity so that Indigenous peoples may participate in the planning, construction, and operations of a project.

AltaGas is committed to building long-term, mutually beneficial working relationships with Indigenous peoples while recognizing and respecting individual values and traditions. AltaGas is committed to developing these relationships on a foundation of respect for the languages, customs, and political, social, and cultural institutions of Indigenous peoples.
AltaGas’ Indigenous Peoples Policy directs how the Corporation develops mutually beneficial relations with Indigenous communities affected by the Corporation’s operations. It provides direction and a means to clarify how the Corporation will interact with Indigenous communities. It also sets standards for employees and contractors to interact with Indigenous representatives and ensures a consistent approach for all projects. AltaGas' policy identifies guiding principles for Indigenous peoples in order to achieve these goals. These guiding principles include:

Respect for legal rights, cultural values, and traditional land use;
Recognition of the distinct needs of different Indigenous peoples with unique languages, cultures, priorities, and protocols and the need to research project-specific issues;
Acknowledgment that all communities are different. A distinct community-specific approach will need to be adopted for consultation and accommodation based on the impact of each project;
Open dialogue through communication and consultation;
AltaGas employee education and training on the Indigenous Peoples Policy; and
Community development and partnerships.

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

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

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

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


 
 
 
AltaGas Ltd. 2019 Annual Information Form 74

    


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

The table below shows the cash dividends paid by AltaGas on Common Shares and Preferred Shares for the three most recently completed financial years and the cash dividends paid by Washington Gas on Washington Gas Preferred Shares for the period from the close of the WGL Acquisition until redemption on December 20, 2019.
$ per share
2019

2018

2017

Common Shares
0.960000

2.190000

2.107500

Series A Shares
0.845000

0.845000

0.845000

Series B Shares
1.084641

0.968620

0.806380

Series C Shares (1)
1.322500

1.322500

1.155625

Series E Shares
1.348252

1.250000

1.250000

Series G Shares
1.155750

1.187500

1.187500

Series H Shares
0.296040



Series I Shares
1.312500

1.312500

1.312500

Series K Shares
1.250000

1.250000

1.063400

Washington Gas $4.25 Series (1)
2.125000

2.125000


Washington Gas $4.80 Series (1)
2.400000

2.400000


Washington Gas $5.00 Series (1)
2.500000

2.500000


(1)
Amounts disclosed are in U.S. dollars. Washington Gas preferred shares were redeemed on December 20, 2019.
Dividend Reinvestment And Optional Cash Purchase Plan
Effective May 17, 2016, AltaGas replaced, in its entirety, its dividend reinvestment plan with the Premium DividendTM, Dividend Reinvestment and Optional Cash Purchase Plan (the Plan). The Plan consists 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 (payable January 2020) being the last dividend payment eligible for reinvestment by participating shareholders under the DRIP. The Plan in its entirety will remain suspended until further notice.

The Plan provided eligible holders of Common Shares with the opportunity to, at their election, reinvest the cash dividends paid by AltaGas on their Common Shares towards the purchase of new Common Shares at a 3 percent discount to the average market price (as defined below) of the Common Shares on the applicable dividend payment date (the Dividend Reinvestment component of the Plan).

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

Each of the components of the Plan was subject to prorating and other limitations on availability of new Common Shares in certain events. The "average market price", in respect of a particular dividend payment date, refers to the arithmetic average (calculated to four decimal places) of the daily volume weighted average trading prices of Common Shares on the Toronto Stock Exchange for the trading days on which at least one board lot of Common Shares is traded during the 10 business days immediately preceding the applicable dividend payment date. Such trading prices will be appropriately adjusted for certain capital changes (including common share subdivisions, common share consolidations, certain rights offerings and certain dividends). Shareholders resident outside of Canada (other than the U.S.) may participate in the Dividend Reinvestment component or the Optional Cash Purchase component of the Plan only if their participation is permitted by the laws of the jurisdiction in which they reside and provided that AltaGas is satisfied, in its sole discretion, that such laws do not subject the Plan or AltaGas to additional legal or regulatory requirements.
MARKET FOR SECURITIES

The following chart provides the reported high and low trading prices and volume of Common Shares, traded on the TSX under the symbol ALA, traded by month from January to December 2019 as reported by the TSX:
Month
High
Low
Volume Traded
January
14.59
13.25
25,633,918
February
17.81
13.39
31,157,366
March
18.12
17.31
19,120,605
April
18.65
17.46
15,089,861
May
19.76
17.58
16,373,266
June
20.25
18.96
12,156,609
July
20.87
19.57
12,997,597
August
20.55
17.72
17,093,887
September
20.00
17.65
13,670,419
October
19.97
17.91
18,450,569
November
20.39
18.85
21,119,986
December
20.18
18.57
17,785,590

Series A Shares are traded on the TSX under the symbol ALA.PR.A. The following table sets forth the monthly price range and volume traded for Series A Shares from January to December 2019 as reported by the TSX:    
Month
High
Low
Volume Traded
January
15.15
13.80
715,599
February
15.40
14.10
166,437
March
15.75
13.52
247,072
April
14.30
13.97
139,921
May
14.75
14.01
229,061
June
14.22
13.14
205,426
July
14.86
13.75
176,656
August
14.71
12.44
145,224
September
14.35
13.00
135,240
October
15.01
13.52
154,165
November
15.16
14.28
315,794
December
15.35
14.58
117,013


 
 
 
AltaGas Ltd. 2019 Annual Information Form 75

    


Series B Shares are traded on the TSX under the symbol ALA.PR.B. The following table sets forth the monthly price range and volume traded for Series B Shares for the period from January to December 2019 as reported by the TSX:
Month
High
Low
Volume Traded
January
15.29
13.65
27,520
February
15.50
14.06
26,390
March
15.85
13.98
43,422
April
14.53
14.14
28,135
May
14.86
14.35
46,886
June
14.40
13.50
24,232
July
15.05
14.20
20,942
August
14.85
12.56
68,162
September
14.36
13.09
101,690
October
14.95
13.81
47,416
November
15.20
14.48
30,302
December
15.40
14.55
67,438

Series C Shares are traded on the TSX under the symbol ALA.PR.U. The following table sets forth the monthly price range (in US dollars) and volume traded for Series C Shares from January to December 2019 as reported by the TSX:
Month
High
Low
Volume Traded
January
19.17
17.40
229,434
February
20.00
18.35
168,850
March
20.63
19.00
89,108
April
19.76
18.99
97,981
May
19.94
19.00
133,957
June
19.15
18.05
90,259
July
19.49
18.75
113,428
August
19.45
16.73
137,794
September
18.30
17.30
124,607
October
19.96
17.75
302,841
November
19.44
18.75
141,441
December
20.50
18.84
134,238

Series E Shares are traded on the TSX under the symbol ALA.PR.E. The following table sets forth the monthly price range and volume traded for Series E Shares from January to December 2019 as reported by the TSX:
Month
High
Low
Volume Traded
January
18.50
17.19
229,111
February
18.63
17.80
210,116
March
19.51
18.25
202,876
April
19.00
18.31
188,980
May
19.26
18.50
237,253
June
18.80
17.71
139,189
July
19.41
18.63
173,265
August
19.59
17.80
114,372
September
19.80
18.21
467,524
October
19.54
18.90
105,837
November
19.46
18.90
100,481
December
19.50
18.55
140,980


 
 
 
AltaGas Ltd. 2019 Annual Information Form 76

    


Series G Shares are traded on the TSX under the symbol ALA.PR.G. The following table sets forth the monthly price range and volume traded for Series G Shares from January to December 2019 as reported by the TSX:
Month
High
Low
Volume Traded
January
17.57
16.05
134,170
February
17.09
15.69
81,236
March
17.91
15.53
61,467
April
16.36
15.83
52,334
May
16.89
15.88
68,464
June
16.00
14.93
333,873
July
17.18
16.05
532,773
August
17.04
14.71
92,817
September
16.00
15.35
130,070
October
16.91
15.71
121,128
November
17.20
16.48
113,827
December
17.59
16.11
93,043

Series H Shares were listed on the TSX under the symbol ALA.PR.H on September 30, 2019. The following table sets forth the monthly price range and volume traded for Series H Shares for the period of September 30, 2019 to December 2019 as reported by the TSX:
Month
High
Low
Volume Traded
September
16.00
16.00
October
16.00
16.00
700
November
16.50
15.55
5,000
December
16.43
16.04
6,350
Series I Shares are traded on the TSX under the symbol ALA.PR.I. The following table sets forth the monthly price range and volume traded for Series I Shares for the period of January to December 2019 as reported by the TSX:
Month
High
Low
Volume Traded
January
22.08
19.80
246,438
February
21.89
20.20
235,251
March
22.61
21.65
191,476
April
23.29
22.02
153,461
May
23.19
22.50
187,955
June
22.46
21.11
181,377
July
22.88
21.55
167,292
August
22.85
21.03
155,898
September
23.20
21.56
240,542
October
23.87
22.88
138,825
November
24.09
23.22
107,175
December
24.65
23.19
93,491

 
 
 
AltaGas Ltd. 2019 Annual Information Form 77

    



Series K Shares are traded on the TSX under the symbol ALA.PR.K. The following table sets forth the monthly price range and volume traded for Series K Shares for the period of January to December 2019 as reported by the TSX:
Month
High
Low
Volume Traded
January
19.40
17.56
422,071
February
20.08
18.35
307,105
March
20.79
19.49
388,920
April
20.40
19.41
159,775
May
20.76
20.05
149,506
June
20.30
19.34
157,558
July
21.44
20.17
192,505
August
21.51
19.75
239,174
September
22.02
20.26
102,814
October
22.78
21.57
219,618
November
22.80
21.66
108,073