Document:

Exhibit 4.1

 

ALTAGAS LTD.

 

Annual Information Form

 

For the year ended December 31, 2017

 

Dated: February 28, 2018

 

 

TABLE OF CONTENTS

 

	
GENERAL INFORMATION
    	
 
    	
2
    
	
FORWARD-LOOKING INFORMATION
    	
 
    	
2
    
	
GLOSSARY
    	
 
    	
4
    
	
METRIC CONVERSION
    	
 
    	
12
    
	
CORPORATE STRUCTURE
    	
 
    	
12
    
	
INCORPORATION
    	
 
    	
12
    
	
AMENDED ARTICLES
    	
 
    	
12
    
	
INTERCORPORATE   RELATIONSHIPS
    	
 
    	
13
    
	
OVERVIEW OF THE BUSINESS
    	
 
    	
15
    
	
ALTAGAS’ VISION   AND OBJECTIVE
    	
 
    	
15
    
	
ALTAGAS’   STRATEGY
    	
 
    	
15
    
	
ALTAGAS’ GEOGRAPHIC FOOTPRINT
    	
 
    	
18
    
	
GENERAL DEVELOPMENT OF ALTAGAS’ BUSINESS
    	
 
    	
20
    
	
DEVELOPMENTS   RELATING TO THE PENDING WGL ACQUISITION
    	
 
    	
20
    
	
DEVELOPMENT OF   THE GAS BUSINESS OF ALTAGAS
    	
 
    	
24
    
	
DEVELOPMENT OF   THE POWER BUSINESS OF ALTAGAS
    	
 
    	
25
    
	
DEVELOPMENT OF   THE UTILITIES BUSINESS OF ALTAGAS
    	
 
    	
26
    
	
BUSINESS OF THE CORPORATION
    	
 
    	
26
    
	
GAS BUSINESS
    	
 
    	
26
    
	
POWER BUSINESS
    	
 
    	
35
    
	
UTILITIES   BUSINESS
    	
 
    	
40
    
	
CORPORATE   SEGMENT
    	
 
    	
53
    
	
CAPITAL STRUCTURE
    	
 
    	
53
    
	
DESCRIPTION OF   CAPITAL STRUCTURE
    	
 
    	
53
    
	
GENERAL
    	
 
    	
56
    
	
EMPLOYEES
    	
 
    	
56
    
	
DIRECTORS AND OFFICERS
    	
 
    	
56
    
	
EXECUTIVE   OFFICERS
    	
 
    	
59
    
	
AUDIT COMMITTEE
    	
 
    	
60
    
	
RISK FACTORS
    	
 
    	
61
    
	
RISKS RELATED TO   THE BUSINESS OF ALTAGAS
    	
 
    	
61
    
	
RISKS RELATED TO   THE ACQUISITION OF WGL
    	
 
    	
69
    
	
RISKS RELATED TO   THE BUSINESS OF WGL
    	
 
    	
72
    
	
ENVIRONMENTAL AND SAFETY POLICIES AND SOCIAL RESPONSIBILITY
    	
 
    	
74
    
	
ENVIRONMENTAL REGULATION
    	
 
    	
75
    
	
CLIMATE CHANGE
    	
 
    	
76
    
	
DIVIDENDS
    	
 
    	
79
    
	
MARKET FOR SECURITIES
    	
 
    	
81
    
	
CREDIT RATINGS
    	
 
    	
84
    
	
MATERIAL CONTRACTS
    	
 
    	
85
    
	
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL   TRANSACTIONS
    	
 
    	
85
    
	
LEGAL PROCEEDINGS
    	
 
    	
85
    
	
REGULATORY ACTIONS
    	
 
    	
86
    
	
INTERESTS OF EXPERTS
    	
 
    	
86
    
	
ADDITIONAL INFORMATION
    	
 
    	
86
    
	
TRANSFER AGENTS AND REGISTRARS
    	
 
    	
86
    
	
SCHEDULE A: AUDIT COMMITTEE MANDATE
    	
 
    	
A-1
    

 

1

 

GENERAL INFORMATION

 

Unless otherwise noted, the information contained in this AIF is stated as at December 31, 2017 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 implementation and success of AltaGas’ strategy for the Corporation as a whole and each of its business segments; that abundant natural gas and demand for clean energy will provide opportunities for sustained growth across all three business segments; the aim to maintain a long-term balanced mix of energy infrastructure assets across AltaGas’ business segments; the expected benefits of AltaGas’ export-related infrastructure assets; AltaGas’ ability to take advantage of the demand for clean energy through its clean energy assets; expected development and expansion opportunities in California; AltaGas’ ability to exercise financial discipline and effective risk management; the realization of further battery storage opportunities; the success, timing and customer impact of the Marquette Connector Pipeline and the Alton Natural Gas Storage Project; expected growth of operating cash flows; expected success of financing plans and strategies, including maintenance of AltaGas’ credit rating; the expected safety and reliability of AltaGas’ operations; the expected good working relationships with stakeholders and governments; expected ability to close and the timing of the WGL Acquisition; the expectation that WGL’s debt will remain outstanding; the expected size and scale of AltaGas following completion of the WGL Acquisition; the expected long-term financing for the WGL Acquisition, including the timing of such potential financing activities and the asset monetizations and capital market activities that may be undertaken; the potential assets identified and potential options for monetization of such assets, including minority and/or controlling interests; AltaGas’ ability to pursue its asset sale process in a prudent and timely manner;  the expected timing, costs, completion and success of WGL’s midstream investments; expected operatorship and ownership interest change at Younger; expectations regarding filling capacity at the North Pine Facility; expected capacity at the second North Pine separation train; expected timing and shipping capacity of RIPET, and sources and terms of supply; the belief that AltaGas is a preferred business partner; the expected impacts on AltaGas’ business of applicable environmental regulations and requirements; expected growth in each of AltaGas’ business segments and the contributors to that growth; expected continuation of the increased capacity factor at Blythe; targeted power projects and profitability in California; targeted growth in AltaGas’ utilities; and the intention not to use preferred shares as a defensive tactic.

 

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; the outcomes of significant commercial contract negotiation; financing of the WGL Acquisition; and timing and completion of the WGL Acquisition.

 

AltaGas’ forward-looking statements are subject to certain risks and uncertainties which could cause results or events to differ from current expectations, including, without limitation: access to and use of capital markets; market value of AltaGas’ securities; AltaGas’ ability to pay dividends; AltaGas’ ability to service or refinance its debt and manage its credit rating and risk; prevailing economic conditions; potential litigation; AltaGas’ relationships with external stakeholders, including Aboriginal stakeholders; volume throughput and the impacts of commodity pricing, supply, composition and other market risks; available electricity prices; interest rate, exchange rate and counterparty risks; the Harmattan Rep agreements; legislative and regulatory environment; underinsured losses; weather, hydrology and climate changes; the

 

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potential for service interruptions; availability of supply from Cook Inlet; availability of biomass fuel; AltaGas’ ability to economically and safely develop, contract and operate assets; AltaGas’ ability to update infrastructure on a timely basis; AltaGas’ dependence on certain partners; impacts of climate change and carbon taxing; effects of decommissioning, abandonment and reclamation costs; impact of labour relations and reliance on key personnel; cybersecurity risks; risks associated with the acquisition of WGL, the financing of the WGL Acquisition and the underlying business of WGL; and the other factors discussed under the heading “Risk Factors” in this AIF.

 

Many factors could cause AltaGas’ or any particular business segment’s actual results, performance or achievements to vary from those described in this AIF, including, without limitation, those listed above and the assumptions upon which they are based proving incorrect. These factors should not be construed as exhaustive. Should one or more of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary materially from those described in this AIF as intended, planned, anticipated, believed, sought, proposed, estimated, forecasted, expected, projected or targeted and such forward-looking statements included in this AIF, should not be unduly relied upon. The impact of any one assumption, risk, uncertainty or other factor on a particular forward-looking statement cannot be determined with certainty because they are interdependent and AltaGas’ future decisions and actions will depend on management’s assessment of all information at the relevant time. Such statements speak only as of the date of this AIF. AltaGas does not intend, and does not assume any obligation, to update these forward-looking statements except as required by law. The forward-looking statements contained in this AIF are expressly qualified by these cautionary statements.

 

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

 

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GLOSSARY

 

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

 

“AESO” means Alberta Electric System Operator;

 

“AIF” means this Annual Information Form;

 

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

 

“AltaGas Services” means AltaGas Services Inc., a predecessor by amalgamation to AltaGas Ltd.;

 

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

 

“ASC” means the Alberta Securities Commission;

 

“Astomos” means Astomos Energy Corporation;

 

“Atlantic Bridge Expansion Project” means the construction of additional pipeline and related facilities infrastructure by Enbridge Inc. (formerly Spectra Energy) to provide additional capacity on its Algonquin Gas Transmission and Maritimes & Northeast Pipeline systems to move natural gas into New England and to specific end use markets in the Canadian Maritime provinces targeting an initial in-service date in the second half of 2018;

 

“AUC” means the Alberta Utilities Commission;

 

“AUI” means AltaGas Utilities Inc.;

 

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

 

“Bbls/d” means Bbls per day;

 

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

 

“Bcf/d” means Bcf per day;

 

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

 

“BCOGC” means British Columbia Oil and Gas Commission;

 

“BCSC” means the British Columbia Securities Commission;

 

“BCUC” means British Columbia Utilities Commission;

 

“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;

 

“BMWLP” means Bear Mountain Wind Limited Partnership, a wholly owned subsidiary of AltaGas Ltd.;

 

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

 

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“Bridge Facility” means the US$3.0 billion bridge facility to be provided by a syndicate of lenders, including JPMorgan Chase Bank, N.A., The Toronto-Dominion Bank and Royal Bank of Canada on substantially the terms set forth in the Debt Commitment Letter;

 

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

 

“Burdensome Condition” means any undertakings, terms, conditions, liabilities, obligations, commitments, sanctions or other measures (including any Remedial Action) that would have or would reasonably be expected to have, individually or in the aggregate, a material adverse effect on the financial condition, assets, liabilities, businesses or results of operations of (a) WGL and its subsidiaries, taken as a whole, or (b) AltaGas and its subsidiaries, taken as a whole and determined after giving effect to the transactions contemplated by the Merger Agreement; provided, however, that any such undertakings, terms, conditions, liabilities, obligations, commitments, sanctions or other measures shall not constitute or be taken into account in determining whether there has been or is such a material adverse effect to the extent such undertakings, terms, conditions, liabilities, obligations, commitments, sanctions or other measures are expressly set forth in the post-merger commitments of AltaGas set forth in the Merger Agreement;

 

“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;

 

“CES” means Commercial Energy Systems;

 

“CFIUS” means 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;

 

“Cogeneration III” means the expansion of the cogeneration fleet at Harmattan from 30 MW to 45 MW;

 

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

 

“Concurrent Private Placement” has the meaning given to it under the heading “Capital Structure — Description of Capital Structure — Subscription Receipts”;

 

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

 

“CPI” means the Consumer Price Index;

 

“Customer Retention Program” has the meaning given to it under the heading “Business of the Corporation — Utilities Business - Heritage Gas - Material Regulatory Developments and Applications”;

 

“DBRS” means DBRS Limited and its successors;

 

“Debt Commitment Letter” means the Debt Commitment Letter, dated as of January 25, 2017, by and among AltaGas, JPMorgan Chase Bank, N.A., The Toronto-Dominion Bank and Royal Bank of Canada, as amended, restated, supplemented, replaced or otherwise modified from time to time;

 

“Dekatherm” means 10 Therms;

 

5

 

“Degree Day” means the amount that the daily mean temperature deviates below 15 degrees Celsius at AUI, below 18 degrees Celsius at Heritage Gas and below 65 degrees Fahrenheit at SEMCO Gas and ENSTAR, such that a one degree difference equates to one Degree Day;

 

“Dividend Equivalent Payments” means payments per Subscription Receipt equal to the per Common Share cash dividends, if any, declared by AltaGas on the Common Shares in respect of all record dates for such dividends occurring from February 3, 2017 to, but excluding, the last day on which the Subscription Receipts remain outstanding, to be paid to holders of Subscription Receipts concurrently with the payment date of each such dividend on AltaGas’ outstanding Common Shares, paid first out of any interest credited or received on the Escrowed Funds and then as a refund of a portion of the offering price of $31.00 per Subscription Receipts;

 

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

 

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

 

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

 

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

 

“EPA” means electricity purchase agreement;

 

“ESA” means Energy Storage Resource Adequacy Purchase Agreement;

 

“Escrow Release Condition” means the parties to the Merger Agreement are able to complete the WGL Acquisition in all material respects in accordance with the terms of the Merger Agreement, without amendment or waiver materially adverse to AltaGas, unless the consent of co-lead underwriters of the Offering is given to such amendment or waiver (such consent not to be unreasonably withheld), but for the payment of the purchase price, and AltaGas has available to it all other funds required to complete the WGL Acquisition; provided that the Escrow Release Condition may, if the foregoing conditions are met, at the election of AltaGas, occur up to six business days prior to the scheduled closing date;

 

“Escrow Release Notice and Direction” means the notice to be provided to the subscription receipt agent, executed by AltaGas and the co-lead underwriters on behalf of the underwriters of the Offering, certifying that the Escrow Release Condition has been satisfied;

 

“Escrowed Funds” means, collectively, the Proceeds, earned interest thereon and any investments acquired or made from time to time with such funds, as such funds may be reduced upon payment of Dividend Equivalent Payments or other amounts payable under the Subscription Receipt Agreement from the Proceeds or earned interest;

 

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

 

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

 

“FID” means final investment decision;

 

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

 

“GHG” means greenhouse gas;

 

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

 

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

 

“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;

 

6

 

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

 

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

 

“Heritage Gas” means Heritage Gas Limited;

 

“HSR Act” means the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended;

 

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

 

“Ikhil Joint Venture” means the joint venture between AltaGas’ subsidiary, Utility Group Facilities Inc., Inuvialuit Petroleum Corporation and ATCO Midstream NWT Ltd., which owns and operates two gas wells, a processing facility and a pipeline that delivers natural gas to Inuvik Gas and the Northwest Territories Power Corporation;

 

“Inuvik Gas” means Inuvik Gas Ltd.;

 

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

 

“km” means kilometer;

 

“LLTD” means Low Load Turn Down;

 

“LNG” means liquefied natural gas;

 

“LPG” means liquefied petroleum gas;

 

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

 

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

 

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

 

“Mcf/d” means Mcf per day;

 

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

 

“MDth” means millions of Dekatherms;

 

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

 

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

 

“MGP” means manufactured gas plant;

 

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

 

“Mmcf/d” means Mmcf per day;

 

“MPSC” means the Michigan Public Service Commission;

 

“MRP” means Main Replacement Program;

 

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

 

7

 

and Computershare Trust Company of Canada, as amended, restated, supplemented or otherwise modified from time to time, as the case may be;

 

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

 

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

 

“NFA” means No Further Action;

 

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

 

“NGTL” means NOVA Gas Transmission Ltd.;

 

“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;

 

“Northeast System” means the PNG(NE) distribution utility in the northeast part of British Columbia;

 

“Northwest Hydro Facilities” means the three run-of-river hydroelectric facilities in northwest British Columbia, being Forrest Kerr, McLymont Creek and Volcano Creek, owned by AltaGas’ subsidiary Coast Mountain Hydro Limited Partnership;

 

“Nova Chemicals” means NOVA Chemicals Corporation;

 

“Northwest Transmission Line” means the 344 km, 287 kilovolt Northwest Transmission Line, owned by BC Hydro, from the Skeena substation near Terrace, British Columbia to a substation near Bob Quinn Lake, British Columbia;

 

“NSUARB” means the Nova Scotia Utility and Review Board;

 

“NWTPUB” means the Northwest Territories Public Utility Board;

 

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

 

“Offering” has the meaning given to it under the heading “Capital Structure — Description of Capital Structure — Subscription Receipts”;

 

“Outside Date” means the latest date by which the transaction contemplated by the Merger Agreement must be consummated, being 5:00 p.m. Washington, D.C. time on July 23, 2018.

 

“Over-allotment Option” has the meaning given to it under the heading “Capital Structure — Description of Capital Structure — Subscription Receipts”;

 

“Painted Pony” means Painted Pony Energy Ltd.;

 

“PBR” means performance based regulation;

 

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

 

“Pembina” means Pembina Infrastructure and Logistics LP;

 

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

 

“PJ” means Petajoule which is one million GJ;

 

8

 

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

 

“PNG” means Pacific Northern Gas Ltd.;

 

“PNG(NE)” means Pacific Northern Gas (N.E.) Ltd.;

 

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

 

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

 

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

 

“PPA” means power purchase agreement;

 

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

 

“Proceeds” means an amount equal to: (a) the offering price of $31.00 per Subscription Receipt multiplied by the total number of Subscription Receipts issued pursuant to the Offering, less the underwriters’ fee; and (b) the offering price of $31.00 per Subscription Receipt multiplied by the total number of Subscription Receipts issued pursuant to the Concurrent Private Placement (after deducting the capital commitment fee payable to the private placement subscriber);

 

“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;

 

“Rate Order” means the final order issued by the RCA on September 22, 2017 deciding matters in ENSTAR’s 2016 rate case;

 

“RCA” means the Regulatory Commission of Alaska;;

 

“RECs” means Renewable Energy Credits;

 

“Regulatory Approvals” means (i) any consents required by the PSC of DC, the PSC of MD and the SCC of VA; (ii) the approval of the CFIUS; and (iii) any consents required by FERC, in respect of the transactions contemplated by the Merger Agreement;

 

“Remedial Action” means committing to and effecting, by consent decree, hold separate orders, trust, or otherwise, (a) the sale, license, holding separate or other disposition of assets or businesses of AltaGas or WGL or any of their respective subsidiaries, (b) terminating, relinquishing, modifying or waiving existing relationships, ventures, contractual rights, obligations or other arrangements of AltaGas or WGL or any of their respective subsidiaries and (c) creating any relationships, ventures, contractual rights, obligations or other arrangements of AltaGas or WGL or any of their respective subsidiaries;

 

“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;

 

“RIPET” means the Ridley Island Propane Export Terminal, the propane export terminal being constructed by AltaGas’ subsidiary, Ridley Island LPG Export Limited Partnership, to ship up to 1.2 million tonnes of propane per annum and to be

 

TM Denotes trademark of Canaccord Genuity Corp

 

9

 

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;

 

“San Joaquin Facilities” means the 330 MW Tracy, the 97 MW Hanford and the 96 MW Henrietta gas-fired generation facilities located in northern California, owned by AltaGas’ indirect wholly-owned subsidiary AltaGas San Joaquin Energy Inc.;

 

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

 

“SCE” means Southern California Edison Company;

 

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

 

“SEMCO Energy” means SEMCO Energy, Inc.;

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

“Shareholders” mean the holders of Common Shares;

 

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“Subscription Receipts” means the subscription receipts of AltaGas Ltd., each of which entitles the holder thereof to receive, without payment of additional consideration or further action, one Common Share upon the closing of the WGL Acquisition;

 

“Subscription Receipt Agreement” means the subscription receipt agreement dated February 3, 2017 among AltaGas, the co-lead underwriters of the Offering and Computershare Trust Company of Canada, as subscription receipt agent, governing the terms of the Subscription Receipts;

 

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

 

“Termination Event” means any of: (a) if an Escrow Release Notice and Direction has not been delivered prior to 5:00 p.m. (Calgary time) on September 4, 2018 or if an Escrow Release Notice and Direction has been delivered but the Escrowed Funds are subsequently returned to the subscription receipt agent pursuant to the Subscription Receipt Agreement; (b) the termination of the Merger Agreement; (c) delivery by AltaGas to the co-lead underwriters, on behalf of the underwriters of the Offering, and the subscription receipt agent, of a notice executed by AltaGas indicating that AltaGas does not intend to proceed with the WGL Acquisition; or (d) the public announcement by AltaGas that it does not intend to proceed with the WGL Acquisition;

 

“Termination Time” means the time of occurrence of the earliest Termination Event;

 

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

 

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

 

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

 

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

 

“TSX” means the Toronto Stock Exchange;

 

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

 

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

 

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

 

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

 

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

 

“Washington Gas 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;

 

“Western System” means PNG’s regulated natural gas transmission and distribution utility in the west central portion of northern British Columbia;

 

“WGL” means WGL Holdings, Inc.;

 

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“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;

 

“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;

 

“WGL Shares” means the shares of common stock of WGL;

 

“WGL Shareholder Approval” means the affirmative vote (in person or by proxy) of the holders of more than two-thirds of the outstanding WGL Shares entitled to vote at a meeting of shareholders of WGL to consider the approval of the Merger Agreement, including any postponement, adjournment or recess thereof;

 

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

 

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

 

METRIC CONVERSION

 

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

 

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

 

CORPORATE STRUCTURE

 

INCORPORATION

 

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

 

AMENDED ARTICLES

 

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

 

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Shares, Series H Shares; (v) November 17, 2015 to create the ninth series of Preferred Shares, Series I Shares and the tenth series of Preferred Shares, Series J Shares; and (vi) February 15, 2017 to create the eleventh series of Preferred Shares, Series K Shares and the twelfth series of Preferred Shares, Series L Shares.

 

INTERCORPORATE RELATIONSHIPS

 

The following organization diagram presents the name and the jurisdiction of incorporation of certain of AltaGas’ subsidiaries as at December 31, 2017. 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, 2017.

 

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OVERVIEW OF THE BUSINESS

 

AltaGas, a Canadian corporation, is a North American diversified energy infrastructure company with a focus on owning and operating assets to provide clean and affordable energy to its customers. AltaGas has three business segments:

 

·                  Gas, which transacts more than 2 Bcf/d of natural gas and includes natural gas gathering and processing, NGL extraction and fractionation, transmission, storage, natural gas and NGL marketing, and the Corporation’s indirectly held one-third interest in Petrogas, through which AltaGas’ interest in the Ferndale Terminal is held;

·                  Power, which includes 1,708 MW of gross capacity from natural gas-fired, hydro, wind, and biomass generation facilities, and energy storage assets located across North America; and

·                  Utilities, serving over 580,000 customers through ownership of regulated natural gas distribution utilities across North America and a regulated natural gas storage utility in the United States, delivering clean and affordable natural gas to homes and businesses.

 

As at December 31, 2017, AltaGas’ enterprise value exceeded $10 billion. With physical and economic links along the energy value chain, together with its experienced and talented workforce of more than 1,600 people, and its efficient, reliable and profitable assets, market knowledge and financial discipline, AltaGas has provided strong, stable and predictable returns to its investors. AltaGas focuses on maximizing the profitability of its assets, adding services that are complementary to its existing business segments, and growing through the acquisition and development of energy infrastructure.

 

ALTAGAS’ VISION AND OBJECTIVE

 

AltaGas’ vision is to be a leading North American diversified energy infrastructure company. The Corporation’s overall objective is to generate superior economic returns by investing in low-risk, long-life energy assets. The Corporation focuses on assets underpinned by contracts with strong counterparties and regulated assets, both of which provide stable utility-like returns and long-life cash flows. Diversification increases the stability of earnings and cash flows and reduces AltaGas’ exposure to commodity market volatility. AltaGas’ earnings are underpinned by three business segments, and within each segment there is further diversification: by customer and service type in the Gas segment; by fuel source, customer, and geography within the Power segment; and by regulatory jurisdiction in the Utilities segment. The Corporation also focuses on expanding its business through acquisitions and organic growth to further support dividend and capital growth. AltaGas believes that in the long term, the abundant supply of natural gas in North America and the increasing global demand for clean energy will continue to provide opportunities for sustained growth across all of its business segments. Superior service, safety, and reliability are also integral to AltaGas’ customer value proposition.

 

ALTAGAS’ STRATEGY

 

Consistent with its mandate of overseeing and directing the Corporation’s strategic direction, AltaGas’ Board of Directors (Board of Directors) is actively engaged in regular review of the Corporation’s strategy. The Corporation continually assesses the macro and micro-economic trends impacting its business and seeks opportunities to generate value for shareholders, including through acquisitions, dispositions or other strategic transactions. Opportunities pursued by AltaGas must meet strategic, operating and financial criteria.

 

The Corporation’s long-term strategy is to grow in attractive areas and maintain a long-term, balanced mix of energy infrastructure assets across its Gas, Power and Utilities business segments. AltaGas’ business strategy is underpinned by the growing demand for clean energy with natural gas as a key fuel source.

 

Owning and Operating Energy Infrastructure

 

Natural gas supply and demand fundamentals and the demand for clean energy have consistently underpinned the Corporation’s strategy. In recent years, the supply and demand fundamentals have been changing. Abundant supply of natural gas in North America, driven by new technology that has improved the economics of unconventional gas plays, has been positive news for North American energy consumers and has led to renewed interest in natural gas as an economically priced, clean-burning fuel. As a result, the use of natural gas for power generation, household, and

 

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commercial and industrial uses has increased substantially, providing significant opportunities across AltaGas’ Gas, Power and Utilities segments to invest in and optimize its assets.

 

In the Gas segment, AltaGas’ strategy is to provide a fully-integrated midstream service offering to its customers across the energy value chain. As part of this strategy, the Corporation builds and acquires gas gathering and processing infrastructure on behalf of, or from, producers wishing to redeploy capital to exploration and production activities, rather than to non-core activities such as midstream services. Canada produces a surplus of gas, NGL and crude oil. The U.S. has traditionally been the sole export market for this surplus, but with the U.S. now having a surplus as well, its demand for import of these products has decreased. As a result, netbacks have been less attractive for Canadian producers. AltaGas believes that energy market diversification is critical for the Canadian energy sector. Investing in infrastructure for export outside of North America provides an opportunity for Canadian producers to align the vast supply of NGL and natural gas reserves with the growing demand from Asia. AltaGas is uniquely positioned to provide producers with a competitive service offering across the integrated value chain, from wellhead to end markets by way of export terminals. Access to Asian markets provides market diversity to producers, especially those in the Montney, Deep Basin, and Duvernay regions under development in northeastern British Columbia and western Alberta. AltaGas is uniquely positioned to deliver higher netbacks to producers for their NGL by establishing a western energy hub in northeast British Columbia, through RIPET, which is currently under construction, and through its ownership interest in Petrogas and the Ferndale Terminal. AltaGas also has access to Asian markets through its relationship with Idemitsu, which owns 51 percent of Astomos, the largest LPG importer in Japan (Mitsubishi Corporation owns the remaining 49 percent of Astomos). On January 25, 2017, the Corporation announced its pending acquisition of WGL. WGL has a growing midstream business with investments in gas gathering infrastructure and regulated gas pipelines in the Marcellus/Utica gas formation located in the northeast United States with capabilities for connections to marine-based energy export opportunities via the North American Atlantic coast through the Cove Point LNG terminal in Maryland being developed by a third party, which is currently in the final stages of commissioning. The combined enterprise will be uniquely positioned with key gas midstream assets in both the Marcellus/Utica and Montney gas formations, which are two of North America’s most prolific gas basins. Further information on the pending acquisition of WGL can be found under the heading “General Development of AltaGas’ Business - Developments Relating to the Pending WGL Acquisition” in this AIF.

 

There has been an increase in the demand in North America for clean sources of highly flexible power to complement the significant growth in renewable power, while also helping to fill the void as coal and nuclear power declines. The Power segment is focused on developing, building, owning, and operating a diversified portfolio of clean energy assets that reduce the Corporation’s carbon footprint and on meeting North America’s demand for clean energy. AltaGas is positioned to take advantage of this opportunity. In California, the CAISO has stated that up to 15,000 MW of fast ramping flexible capacity is required to meet the needs of the current 50 percent Renewable Portfolio Standard of California by 2030 given planned retirements of once-through cooling gas facilities, as well as the planned retirement of the Diablo Canyon nuclear plant. With the retirements of traditional generating assets and the increased variability of a growing renewable asset base, the demand for highly-responsive generation and energy storage assets is increasing. In northern California, the Corporation is focused on owning generation assets in locally constrained areas near load pockets as local resource adequacy needs result in more opportunities for expansion, re-contracting and energy storage. AltaGas is well positioned in northern California with the acquisition of the San Joaquin Facilities and Ripon in 2015. In southern California, there has been an increasing demand for non-gas resource adequacy as evidenced by the Aliso Canyon storage request for proposals, which has resulted in the successful bidding, construction and operation of the Pomona Energy Storage Facility, located in the east Los Angeles load pocket. This site is well suited for future development of additional battery storage. The Corporation expects further development and expansion opportunities to arise from existing sites, including Ripon, as well as third party sites similar to the recently completed Pomona Energy Storage Facility. The Corporation’s pending acquisition of WGL fits synergistically with this strategy. WGL owns a growing non-regulated contracted power business, with a focus on distributed generation and energy efficiency assets throughout the United States. WGL also owns a retail gas and power marketing business serving approximately 222,000 customers across five states in the U.S. Further information on the pending acquisition of WGL can be found under the heading “General Development of AltaGas’ Business - Developments Relating to the Pending WGL Acquisition” in this AIF.

 

In the Utilities segment, the Corporation is focused on finding innovative ways to continue to safely and reliably deliver clean and affordable natural gas to more customers. AltaGas focuses on growing rate base through adding customers,

 

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including serving power plants within service jurisdictions, and through consumers fuel switching as abundant natural gas supply provides a clean low-cost energy alternative. In addition, the Utilities segment continues to invest in existing distribution systems through pipeline replacement and system betterment programs to ensure safe, reliable service for AltaGas’ customers as well as to meet increased residential and commercial demand. The Marquette Connector Pipeline that will be constructed in Marquette, Michigan by SEMCO Gas will provide approximately 35,000 customers in its service territory with needed redundancy and additional supply options. The Alton Natural Gas Storage Project currently under construction in Nova Scotia will help increase reliability of supply and lower costs for AltaGas’ natural gas distribution customers in that area. The Corporation also seeks to execute strategic utility acquisitions and dispositions when opportunities arise as demonstrated by the Corporation’s pending acquisition of WGL, which is the sole common shareholder of Washington Gas, a regulated natural gas utility headquartered in Washington, D.C., serving more than 1.2 million customers in Maryland, Virginia, and the District of Columbia. Further information can be found under the heading “General Development of AltaGas’ Business - Developments Relating to the Pending WGL Acquisition” in this AIF.

 

Maintain Financial Strength and Flexibility

 

Integral to AltaGas’ strategy is maintaining financial strength and flexibility, an investment grade credit rating, and ready access to capital markets. Financial discipline and effective risk management are fundamental cornerstones of the Corporation’s strategy. AltaGas seeks to optimize risk and reward, ensuring that returns are commensurate with the level of risk assumed. AltaGas’ financing strategy is to ensure the Corporation has sufficient liquidity to meet its capital requirements and to do so at the lowest cost possible. As a growth-oriented energy infrastructure company, AltaGas creates value for its investors through minimizing its cost of capital and maximizing its return on invested capital, which ensures operating cash flows are maintained and growing. The Corporation develops and executes financing plans and strategies to ensure investment grade credit ratings, diversity in its funding sources, and ready access to capital markets.

 

A key element of the Corporation’s stable business model is mitigating its exposure to certain market price risks as well as volume risk. In addition to its diversification strategy, the Corporation has developed risk management processes that mitigate earnings volatility from commodity price risk and volume risk. AltaGas proactively hedges foreign exchange rates and commodity price exposures when it is prudent to do so. As well, the continued management of counterparty credit risk remains an ongoing priority. AltaGas partially mitigates the foreign exchange exposure on its U.S. investments by incorporating US dollar denominated capital, both debt and preferred shares, into its financing strategy.

 

Continue to Develop Organizational Capability to Support the Strategy

 

AltaGas recognizes that to be successful in operating and constructing energy infrastructure, specific core competencies are required. To that end, the Corporation continues to focus on hiring and training the required competencies to execute its strategy, and ensuring that the performance management processes support the long-term objective of creating shareholder value.

 

Sustainability

 

AltaGas adheres to a strong set of core values, which reinforce its commitment to integrating sustainability fundamentals into every aspect of the business. AltaGas recognizes the broad range of stakeholders that are reached through its operations, and is focused on owning and operating assets that provide clean and affordable energy to its customers. As the Corporation continues to evolve and expand its diversified energy assets, AltaGas will continue to operate in a safe, reliable manner, while working closely with governments, regulatory agencies and stakeholders to maintain positive relationships. By balancing economic priorities with AltaGas’ social and environmental values, AltaGas believes it can help meet the growing global demand for clean energy, while continuing to deliver sustainable benefits to its shareholders.

 

Focus on Project Delivery

 

AltaGas has the internal capabilities and resources to safely deliver capital projects on time and on budget, in close partnership with Aboriginal peoples and community stakeholders. AltaGas has significant in-house construction expertise, demonstrated by the successful completion of more than $2.2 billion in projects since 2012, which provides a significant competitive advantage. Cost efficiency and strong operating performance are the drivers for increasing value as the

 

17

 

Corporation continues to build out its portfolio of assets. Key initiatives continue to increase proficiency in managing costs and include upgrades to cost tracking systems and implementing best practice procurement strategies.

 

For more details on AltaGas’ strategy and strategy execution please refer to the Management’s Discussion and Analysis of AltaGas for the year ended December 31, 2017 under the heading “Strategy Execution” which is available through the SEDAR website www.sedar.com.

 

ALTAGAS’ GEOGRAPHIC FOOTPRINT

 

 

18

 

 

19

 

 

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, which have influenced the general development of such business segment of the Corporation over the last three completed financial years as well as a summary of certain recent developments in 2018.

 

DEVELOPMENTS RELATING TO THE PENDING WGL ACQUISITION

 

On January 25, 2017, AltaGas, Merger Sub and WGL entered into the Merger Agreement pursuant to which Merger Sub will be merged with and into WGL, with WGL continuing as the surviving corporation and as an indirect wholly-owned subsidiary of AltaGas, and the WGL Shares (other than any WGL Shares held immediately prior to the effective time by WGL or any of its subsidiaries or by AltaGas, Merger Sub or any of their respective subsidiaries) will be automatically converted into and represent only the right to receive US$88.25 in cash per WGL Share, without interest. The aggregate purchase price to be paid, including pursuant to any outstanding equity awards under WGL’s benefit plans, is approximately US$4.5 billion in cash; this does not include the outstanding debt of WGL and its subsidiaries and the preferred shares of Washington Gas, together totaling approximately US$2.7 billion at December 31, 2017, and which AltaGas expects will remain outstanding.

 

The WGL Acquisition is expected to close shortly after the later of: (a) the expiration or termination of the applicable waiting period (and any extensions thereof) in connection with the WGL Acquisition under the HSR Act; (b) receipt of WGL Shareholder Approval; and (c) receipt of the Regulatory Approvals, provided that all such conditions and certain other customary closing conditions are satisfied or waived on or prior to the Outside Date. On January 11, 2018, pursuant to the terms of the Merger Agreement, AltaGas and WGL agreed to extend the Outside Date to July 23, 2018. For further details on the Merger Agreement please see a copy of the Merger Agreement filed with Canadian securities regulatory authorities on SEDAR at www.sedar.com.

 

The closing of the WGL Acquisition is expected to occur in mid-2018. Following the closing of the WGL Acquisition AltaGas is expected to have approximately $22 billion of assets and approximately 1.8 million utility segment customers.

 

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Regulatory applications were filed with the PSC of DC, the PSC of MD, and the SCC of VA on April 24, 2017. On the same date, AltaGas and WGL also filed their voluntary Joint Notice to the CFIUS, and an application with FERC. On May 10, 2017, WGL common shareholders voted in favor of the Merger Agreement governing the proposed WGL Acquisition. On July 6, 2017, FERC approved the transaction, finding it to be consistent with the public interest. Also as of July 17, 2017, when the waiting period required by Section 7A(b)(1) of the HSR Act expired, the merger was deemed approved by the Federal Trade Commission and the Department of Justice, such approval being valid for one year. On July 28, 2017, CFIUS provided its approval for the WGL Acquisition. On October 20, 2017, the SCC of VA approved the WGL Acquisition. In Maryland, the hearing before the PSC of MD concluded on October 16, 2017, and on December 4, 2017 AltaGas and WGL announced that they had reached a settlement agreement with several of the intervenors in the Maryland proceeding. As a result, AltaGas and WGL filed a stipulation with the PSC of MD to extend the deadline for issuing its decision. The PSC of MD approved this request moving the date for a decision to on or before April 4, 2018. The hearing before the PSC of DC concluded on December 13, 2017, and a decision is expected to follow in the first half of 2018.

 

AltaGas believes that closing of the WGL Acquisition will occur in mid-2018. AltaGas plans to fund the WGL Acquisition with the proceeds from its aggregate $2.6 billion bought deal and private placement of subscription receipts, which closed in the first quarter of 2017. In addition, AltaGas has US$3 billion available under its fully committed Bridge Facility, which can be drawn at the time of closing. With all funding required for the closing of the WGL Acquisition in place, AltaGas can evaluate and pursue its asset sale process in a prudent and timely fashion in step with the regulatory process and consistent with AltaGas’ long term strategic vision. Management has presently identified a total of over $4.0 billion of assets from AltaGas’ Gas, Power and Utilities business segments in respect of which it is evaluating various options for monetization that could include the sale of either minority and/or controlling interests. Management expects to realize over $2 billion from its asset sale process in 2018. With the present optionality available to AltaGas and in light of a number of factors including recent developments in the California Resource Adequacy markets, AltaGas has discontinued the previously announced sale process of its California power assets. AltaGas will instead continue to pursue other structuring and commercial opportunities to unlock the value of the California assets. Additional financing steps could include offerings of senior debt, hybrid securities, and equity-linked securities (including preferred shares), subject to prevailing market conditions.

 

Business of WGL

 

Headquartered in Washington D.C., WGL is a New York Stock Exchange listed, diversified utility holding company with four reportable operating segments: regulated utility, retail energy marketing, commercial energy systems and midstream energy services. The regulated utility segment is WGL’s core business and consists of WGL’s principal subsidiary, Washington Gas, a regulated natural gas LDC serving customers in the District of Columbia, Maryland and Virginia and its subsidiary, Hampshire, which provides regulated interstate natural gas storage services to Washington Gas under a FERC approved interstate storage service tariff. WGL owns all of the shares of common stock of Washington Gas, Washington Gas Resources and Hampshire. Washington Gas Resources owns four unregulated subsidiaries that include WGL Energy Services, WGL Energy Systems, WGL Midstream and WGSW. Additionally, several subsidiaries of WGL own interests in other entities. Each of WGL’s operating segments is more particularly described below.

 

Regulated Utilities

 

Washington Gas Light Company (Washington Gas)

 

Washington Gas has been engaged in the natural gas distribution business since 1848, and provides regulated gas distribution services to end users in District of Columbia, Virginia, and Maryland. Washington Gas is a respected utility with constructive relationships with all three of its regulators. The utility has approximately 1.2 million customers across these three jurisdictions: District of Columbia (~162,000; 14 percent), Maryland (~478,000; 41 percent), and Virginia (~524,000; 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.

 

Washington Gas’ customers are eligible to purchase their natural gas from unregulated third-party marketers through natural gas unbundling; approximately 178,000 or approximately 15 percent of its customers have chosen to do so as at Washington Gas’ fiscal year-end 2017. This does not negatively impact Washington Gas’ net income as the company does not earn a margin on the sale of natural gas to firm customers, but only from the delivery and distribution of the gas.

 

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Washington Gas obtains natural gas supplies that originate from multiple regions throughout the U.S. As at its 2017 fiscal year-end, it had service agreements with four pipeline companies that provided firm transportation and storage services, with contract expiration dates ranging from 2018 to 2034. Washington Gas has also contracted with various interstate pipeline and storage companies to add to its storage and transportation capacity starting in fiscal year 2018.

 

Hampshire Gas Company (Hampshire)

 

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

 

Regulatory Environment

 

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. Hampshire is regulated by FERC.

 

The rates charged to utility customers are designed to recover Washington Gas’ operating expenses and natural gas commodity costs and to provide a return on its investment in the net assets used in its firm gas sales and delivery service.

 

WGL Midstream

 

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

 

As at WGL’s fiscal year end of September 30, 2017, WGL Midstream had infrastructure investments totalling US$384.6 million and as at December 31, 2017, the investments totalled US$489.4 million. Midstream investments have typically been in regulated gas pipelines that are expected to have a majority of the capacity covered under long-term contracts. In the fiscal year ended September 30, 2017, WGL Midstream invested US$140.8 million in pipelines.

 

Stonewall Gas Gathering System (30 percent net interest)

 

WGL Midstream has a 30 percent equity interest in an entity that owns and operates certain assets known as the Stonewall System. As at December 31, 2017 and September 30, 2017, WGL Midstream held a US$135.7 million and US$136.7 million equity method investment in the Stonewall System. The Stonewall System has the capacity to gather up to 1.4 Bcf/d of natural gas from the Marcellus production region in West Virginia, and connects with an interstate pipeline system that serves markets in the mid-Atlantic region.

 

Central Penn (21 percent net interest)

 

In February 2014, WGL Midstream and certain partners formed, and WGL Midstream acquired, a 55 percent interest in Meade Pipeline Co LLC (Meade). Meade was formed to develop and own, jointly with Transcontinental Gas Pipeline Company, LLC (Transco), an approximately 185-mile regulated pipeline originating in Susquehanna County, Pennsylvania and extending to Lancaster County, Pennsylvania (Central Penn) that will have the capacity to transport and deliver up to approximately 1.7 million Dekatherms of natural gas per day. Additionally, WGL Midstream entered into an agreement with Cabot Oil & Gas Corporation (Cabot) whereby WGL Midstream will purchase 500,000 Dekatherms of natural gas per day from Cabot over a 15 year term. As part of this agreement, Cabot has acquired 500,000 Dekatherms of firm gas transportation capacity per day on Transco’s Atlantic Sunrise project of which Central Penn is a part. This capacity will be released to WGL Midstream. On September 15, 2017, FERC issued the Notice to Proceed and construction on Central Penn has begun. Central Penn currently has a projected in-service date of mid-2018.

 

Central Penn is anticipated to be an integral part of Transco’s Atlantic Sunrise project and will be fully integrated into Transco’s system. WGL Midstream is anticipated to invest an estimated US$410 million for its interest in Meade, and Meade is anticipated to invest an estimated US$746 million in Central Penn for an approximate 39 percent interest in

 

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Central Penn. As at December 31, 2017 and September 30, 2017, WGL Midstream had invested US$238.6 million and US$146.7 million in Central Penn.

 

Mountain Valley (10 percent net interest)

 

WGL Midstream owns a 10 percent interest in Mountain Valley Pipeline, LLC (Mountain Valley). The proposed pipeline to be developed, constructed, owned and operated by Mountain Valley, will transport approximately 2.0 million Dekatherms of natural gas per day from two interconnects with EQT Corporation’s Equitrans system in West Virginia to Transco’s Station 165 in Pittsylvania County, Virginia. As at December 31, 2017 and September 30, 2017, WGL Midstream held a $76.8 million and US$63.0 million equity method investment in Mountain Valley, respectively. WGL Midstream expects to invest, in scheduled capital contributions through the in-service date of the pipeline, its pro rata share (based on its 10 percent equity interest) of project costs, an estimated aggregate amount of approximately US$350.0 million. On October 13, 2017, FERC issued an order granting a certificate of public convenience and necessity to construct and operate the Mountain Valley Pipeline Project. Mountain Valley currently has an expected in-service date by December 2018. In addition, WGL Midstream entered into a gas purchase commitment to buy 500,000 Dekatherms of natural gas per day, at index-based prices, for a 20 year term, and will also be a shipper on the proposed pipeline.

 

Constitution (10 percent net interest)

 

WGL Midstream owns a 10% interest in Constitution Pipeline Company, LLC (Constitution). The pipeline project is designed to transport at least 650,000 Dekatherms of natural gas per day from the Marcellus region in northern Pennsylvania to major northeastern markets. Fully contracted with long-term commitments from established natural gas producers currently operating in Pennsylvania, the pipeline is designed to originate from the Marcellus production areas in Susquehanna County, Pennsylvania, and interconnect with the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in Schoharie County, New York. As at December 31, 2017 and September 30, 2017, WGL Midstream had invested US$38.2 million and US$38.1 million in Constitution, respectively.

 

On December 2, 2014, FERC issued an order granting a certificate of public convenience and necessity. On April 22, 2016, the NYSDEC denied Constitution’s application for a Section 401 certification for the pipeline, which is necessary for the construction and operation of the pipeline. In May 2016, Constitution filed actions in both the U.S. Circuit Court of Appeals for the Second Circuit and the U.S. District Court for the Northern District of New York, appealing the decision and seeking declaratory judgment that the State of New York’s permitting authority is preempted by federal law. In May 2016, Constitution appealed the NYSDEC’s denial of the Section 401 certification to the United States Court of Appeals for the Second Circuit, and in August 2017 the court issued a decision denying in part and dismissing in part Constitution’s appeal. The court expressly declined to rule on Constitution’s argument that the NYSDEC’s decision on Constitution’s Section 401 application constitutes a waiver of the certification requirement. Constitution has filed a petition for rehearing with the Second Circuit Court’s decision, but in October the court denied the petition. In January 2018, Constitution petitioned the United States Supreme Court to review the Second Circuit Court’s decision.

 

In October 2017 Constitution filed a petition for declaratory order requesting the FERC to find that, by operation of law, the Section 401 certification requirement for the New York State portion of Constitution’s pipeline project was waived due to the failure by the NYSDEC to act on Constitution’s Section 401 application within a reasonable period of time as required by the express terms of such statute. The petition is consistent with a recent decision by the District of Columbia Circuit Court in another proceeding, in which the court clarified that an applicant facing similar circumstances should present evidence of waiver to the FERC. On January 11, 2018, the FERC denied the petition, finding that Section 401 provides that a state waives certification only when it does not act on an application within one year from the date of the application. The project’s sponsors remain committed to the project and on February 12, 2018, filed a Request for Rehearing of the FERC’s decision.

 

Commercial Energy Systems

 

WGL Energy Systems and WGSW

 

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

 

CES focuses on clean and energy efficient solutions for its customers, driving earnings through: (i) upgrading the mechanical, electrical, water and energy-related infrastructure of large governmental and commercial facilities by

 

23

 

implementing both traditional and alternative energy technologies; (ii) owning and operating distributed generation assets such as solar photovoltaic (solar PV) systems, combined heat and power plants, and natural gas fuel cells; and (iii) investments in residential and commercial retail solar PV companies. In addition, this segment provides customized energy solutions across a much wider footprint, with business activities across the United States.

 

As of WGL’s fiscal year end of September 30, 2017, this segment owned US$561.0 million of operating distributed generation assets, having invested US$85.5 million during the 2017 fiscal year, generating a total of 290,465 MWh in fiscal year 2017. Additionally, as of September 30, 2017, there was US$41.0 million of signed projects under construction. These distributed generation assets drive revenue through the sale of renewable power generation under long-term power purchase agreements and the sale of renewable energy credits.

 

Retail Energy Marketing

 

WGL Energy Services

 

WGL’s unregulated activities include WGL Energy Services, a retail energy marketing segment, which sells natural gas, electricity, wind/renewable energy credits and carbon offsets directly to residential, commercial and industrial customers in Maryland, Virginia, Delaware, Pennsylvania and the District of Columbia. As at December 31, 2017, WGL Energy Services served approximately 113,500 residential, commercial and industrial natural gas customer accounts and approximately 108,900 residential, commercial and industrial electricity customer accounts located in Maryland, Virginia, Delaware, Pennsylvania and the District of Columbia. WGL Energy Services is subject to regulation by the public service regulatory commission of the states in which the company is authorized as a competitive service provider. On February 20, 2013, WGL Energy Services entered into a five-year secured supply arrangement with Shell Energy North America (US), LP (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. On November 7, 2016, the supply arrangement was extended for two years, expiring in 2020. WGL Energy Services owns solar generating assets which are dedicated to five specific customers. The results of operations for these assets are reported within the CES segment. WGL Energy Services does not own or operate any other electric generation, transmission or distribution assets.

 

DEVELOPMENT OF THE GAS BUSINESS OF ALTAGAS

 

Effective January 1, 2016, AltaGas acquired the remaining 51 percent interest in EEEP.

 

On February 29, 2016, as part of AltaGas’ strategy to focus on larger scale opportunities in the Gas segment that support AltaGas’ northeast British Columbia strategy, AltaGas completed the sale of certain non-core natural gas gathering and processing assets located primarily in central and north central Alberta, totaling approximately 490 Mmcf/d of gross licensed natural gas processing capacity for total consideration of $30 million of cash and approximately 43.7 million of common shares of Tidewater Midstream and Infrastructure Ltd.

 

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

 

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

 

On December 19, 2016, AltaGas received approval from the BCOGC for Townsend Phase 2 and to retrofit the existing shallow-cut Townsend Facility to a deep-cut facility at a future date if AltaGas elects to do so. AltaGas will be constructing Townsend Phase 2 in two separate gas processing trains. On February 22, 2017, the Board of Directors approved a positive FID for the Townsend 2A phase of Townsend Phase 2 and the field compression equipment. Commissioning of Townsend 2A and the field compression equipment was completed on October 1, 2017. For further details, see below under the heading “Business of the Corporation - Gas Business — Field Gathering and Processing and Transmission - Townsend 2A”.

 

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In January 2017, AltaGas reached a positive FID on RIPET. RIPET is expected to be the first propane export facility off the west coast of Canada. The site is near Prince Rupert, British Columbia, and is subleased from RTI, which has a headlease with the PRPA. The site has a locational advantage given very short shipping distances to markets in Asia, notably a 10-day shipping time compared to 25 days from the U.S. Gulf Coast. The brownfield site also benefits from excellent railway access and ample deep water access to the Pacific Ocean. AltaGas’ arrangements with RTI gives AltaGas access to extensive land and water rights and a world class marine jetty which allows for the efficient loading of Very Large Gas Carriers that can access key global markets. Propane from British Columbia and Alberta will be transported to the facility using 50-60 rail cars a day through the existing CN rail network. 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 is expected to be in service in the first quarter of 2019. RIPET is expected to ship 1.2 million tonnes of propane per annum (which is equivalent to approximately 40,000 Bbls/d of export capacity. For further details on this project see below under the heading “Business of the Corporation — Gas Business — Energy Export”.

 

In March 2017, AltaGas sold the Ethylene Delivery System and the Joffre Feedstock Pipeline to Nova Chemicals for net proceeds of approximately $67.0 million.

 

On June 29, 2017, AltaGas modified its existing take-or-pay agreement with Birchcliff Energy Ltd. to incent increased utilization of the Gordondale Facility until late 2020. The modifications made apply solely to volumes above the existing take-or-pay volume commitments.

 

DEVELOPMENT OF THE POWER BUSINESS OF ALTAGAS

 

Effective January 8, 2015, AltaGas acquired three U.S. gas-fired power assets (Ripon, Pomona, and Brush II) with a total generation capacity of 164 MW for approximately US$28 million. Ripon is located in northern California, Pomona is located is southern California, and Brush II is located in Colorado.

 

In 2015, AltaGas completed Cogeneration III. The 15 MW cogeneration facility provides steam for gas processing while providing clean base-load power to the Alberta power market.

 

In 2015, AltaGas commissioned the 66 MW McLymont Creek facility, the third and final of the Northwest Hydro Facilities in British Columbia. The Northwest Hydro Facilities have a combined generating capacity of approximately 277 MW, including the 195 MW Forrest Kerr and 16 MW Volcano Creek facilities.

 

Effective November 30, 2015, AltaGas acquired the San Joaquin Facilities in Northern California with a total generating capacity of 523 MW, for approximately US$642 million, before working capital adjustments. All three facilities (Tracy, Hanford and Henrietta) are currently contracted under long-term PPAs with a creditworthy utility through 2022, providing low-risk and fully contracted cash flows.

 

Pursuant to the change in law provision of the Sundance B PPAs, ASTC Power Partnership, a joint venture partnership between TransCanada Energy Ltd. and AltaGas’ wholly-owned subsidiary, AltaGas Pipeline Partnership, exercised its right to terminate the Sundance B PPAs effective March 8, 2016. In December 2016, a definitive settlement agreement was reached with the Government of Alberta accepting termination of the Sundance B PPAs effective March 8, 2016. Under the settlement agreement, AltaGas agreed to contribute 391,879 self-generated carbon offsets and to make total cash payments in the aggregate amount of $6 million, payable in equal installments over three years starting in 2018 and the Government of Alberta granted AltaGas a full release from all obligations with respect to the Sundance B PPAs. Following the termination of the Sundance B PPAs, AltaGas has fully transitioned its power segment to be a 100 percent clean energy provider with approximately 74 percent and 26 percent of generation capacity from gas-fired and renewables sources, respectively.

 

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

 

On December 22, 2017, an agreement was signed to extend the PPA at the Craven biomass facility from December 31, 2017 to December 31, 2027.

 

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DEVELOPMENT OF THE UTILITIES BUSINESS OF ALTAGAS

 

In January 2015, SEMCO Gas filed a MRP case requesting to continue the existing MRP program for an additional five years and to increase SEMCO Gas’ MRP surcharge. The anticipated annual average capital spending over the five year period is approximately US$10 million with the average annual revenue, collected from customers in a monthly surcharge, anticipated to be approximately US$8 million. In June 2015, the MPSC approved this filing and the new rates became effective immediately following the approval.

 

In September 2016, the NSUARB approved Heritage Gas’ Customer Retention Program application to decrease distribution rates for certain commercial and residential customers, suspend depreciation and to increase the capitalization rate for operating, maintenance and administrative expenses effective March 22, 2016. For further details please refer to “Business of the Corporation — Heritage Gas - Material Regulatory Developments and Applications”.

 

On December 15, 2016, SEMCO Gas filed an application with the MPSC seeking approval to construct, own, and operate the Marquette Connector Pipeline. The Marquette Connector Pipeline is a proposed new pipeline that will connect the Great Lakes Gas Transmission pipeline to the Northern Natural Gas pipeline in Marquette, Michigan where it will provide system redundancy and increase deliverability, reliability and diversity of supply to SEMCO Gas’ approximately 35,000 customers in Michigan’s Western Upper Peninsula. The Marquette Connector Pipeline is estimated to cost between US$135 and US$140 million. In August 2017, the MPSC approved SEMCO’s application to construct, own and operate the Marquette Connector Pipeline. Engineering and property acquisitions are expected to begin in 2018 and construction is expected to be completed in 2019, with an anticipated in-service date by the end of the fourth quarter of 2019.

 

On September 22, 2017, the RCA issued a Rate Order deciding matters in ENSTAR’s 2016 rate case, including granting ENSTAR a return on equity of 11.875 percent and return on total capital of 8.59 percent. For further details please refer to “Business of the Corporation — Utilities Business — ENSTAR - Material Regulatory Developments and Applications”.

 

BUSINESS OF THE CORPORATION

 

AltaGas’ revenue for the year ended December 31, 2017 was approximately $2.6 billion compared to $2.2 billion for the year ended December 31, 2016.

 

	
Revenue   by Business for 2017 (1)
    	
 
    	
Revenue   by Business for 2016 (1)
    
	
 
    	
 
    	
 
    
	

    	
 
    	

    

 

Note:

(1)         Excluding Corporate segment and intersegment eliminations

 

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

 

GAS BUSINESS

 

AltaGas’ Gas business contributed revenue of $1.0 billion for the year ended December 31, 2017 (2016 - $804 million), representing approximately 36 percent (2016 — 33 percent) of AltaGas’ total revenue before Corporate segment and

 

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intersegment eliminations. The Gas business is primarily comprised of AltaGas’ extraction and fractionation, and field gathering and processing business described below. AltaGas also owns certain non-material transmission assets and transmission pipelines. To support its gas business, AltaGas conducts an energy service business mainly focused on natural gas and NGL marketing initiatives. AltaGas is also pursuing energy export initiatives and constructing the Alton Natural Gas Storage Project.

 

Gas Business — Extraction and Fractionation

 

Extraction and Fractionation — Plant Production

 

Extraction production is a function of natural gas volume processed, natural gas composition, recovery efficiency of the extraction plant and plant on-line time. The following tables are a summary as at December 31, 2017 of AltaGas’ operatorship, capacity and total production associated with extraction and fractionation plants in which AltaGas holds an interest:

 

	
Extraction or
   Fractionation
   Plant
    	
 
    	
Location
    	
 
    	
Interest (%)
    	
 
    	
AltaGas’
   Inlet
   Processing
   Capacity
   (Mmcf/d)
    	
 
    	
AltaGas’
   Inlet
   Processing
   Capacity
   (Bbls/d)
    	
 
    	
Operated or Non-
   Operated
    	
 
    
	
Harmattan
    	
 
    	
Central Alberta
    	
 
    	
100
    	
 
    	
490
    	
 
    	
N/A
    	
 
    	
Operated
    	
 
    
	
Younger(1)
    	
 
    	
Taylor, British Columbia
    	
 
    	
56.67
    	
 
    	
425
    	
 
    	
N/A
    	
 
    	
Operated
    	
 
    
	
JEEP
    	
 
    	
Joffre, Alberta
    	
 
    	
100
    	
 
    	
250
    	
 
    	
N/A
    	
 
    	
Operated
    	
 
    
	
EEEP
    	
 
    	
Edmonton, Alberta
    	
 
    	
100
    	
 
    	
390
    	
 
    	
N/A
    	
 
    	
Operated
    	
 
    
	
Empress Pembina
    	
 
    	
Empress, Alberta
    	
 
    	
11.25
    	
 
    	
135
    	
 
    	
N/A
    	
 
    	
Non-Operated
    	
 
    
	
North Pine
    	
 
    	
Fort St. John, British Columbia
    	
 
    	
100
    	
 
    	
N/A
    	
 
    	
10,000
    	
 
    	
Operated
    	
 
    
	
Total(2)
    	
 
    	
 
    	
 
    	
 
    	
 
    	
1,690
    	
 
    	
10,000
    	
 
    	
 
    	
 
    

 

Notes:

(1)         Pembina will assume operatorship of Younger effective April 1, 2018. AltaGas’ ownership interest will be reduced to 28.3 percent of the extraction assets and 50 percent of the fractionation assets, resulting in AltaGas’ inlet processing capacity being reduced to 212 Mmcf/d.

(2)         Excludes Bantry fractionator products and field NGLs.

 

Total Liquids Production (Bbls/d)(1)

 

	
 
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
NGLs (2)
    	
 
    	
28,316
    	
 
    	
27,517
    	
 
    
	
Ethane
    	
 
    	
26,125
    	
 
    	
32,233
    	
 
    

 

Notes:

(1)         Average volumes for the fourth quarter.

(2)         Excludes Bantry fractionator products and field NGLs.

 

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

 

Extraction and Fractionation - Plant Fee Structures

 

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. Extraction facility owners have the right to extract liquids from the natural gas stream, either directly as the owner of the natural gas, or through NGL extraction agreements. The typical commercial arrangement involves the ethane and NGL extraction plant owner contracting with the gas shipper on a natural gas transmission system for the right to extract NGLs from the transporter’s natural gas. By removing ethane and NGLs, the extraction plant is, in effect, extracting or shrinking a portion of the energy content of the shipper’s natural gas. The extraction plant owner pays the transporter for the extracted energy or alternatively purchases a sufficient volume of natural gas from the market to replace the extracted energy,

 

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thereby keeping the transporter whole. This purchased gas is referred to as shrinkage or make-up gas. This convention is not expected to change in the near future.

 

Extraction contract terms may be for firm or interruptible processing, and may vary from monthly to multi-year in length. Currently the majority of AltaGas’ extraction agreements are one-year term arrangements. AltaGas’ share of all ethane production is sold through long-term, cost-of-service or fee-for-service arrangements that bear no commodity price risk. The sales price received under these contracts provides for a return on and of capital and the recovery of certain operating costs, including shrinkage gas attributable to that production. AltaGas’ share of ethane production is sold at the outlet of the plants, with the product purchaser responsible for all downstream transportation and handling.

 

AltaGas’ NGL production is sold under a variety of arrangements. At December 31, 2017, approximately 65 percent of AltaGas’ NGL production was sold under long-term, fee-for-service contracts. Fee-for-service means that fees are charged to the customer for the service provided on a per unit volume basis. These volumes do not bear any commodity price risk. The revenue from this portion of NGL sales provides a stable, predictable cash flow base.

 

On the portion of the NGL production that is not sold under long-term fee-for-service contracts, performance is subject to frac spread which is the price spread between NGLs extracted and the natural gas purchased to make up the heating value of the NGLs extracted. At December 31, 2017, approximately 35 percent of AltaGas’ NGL production (17 percent of total extraction production) was sold under contracts subject to frac spread. If commodity prices or operating costs make NGL extraction uneconomical, the NGLs may be re-injected or the facilities may be turned down or shut-in. If this occurs, the operational flexibility of the commercial contracts translates into a minimal effect on margins.

 

In most cases the NGL recovered at natural gas processing and extraction plants in Western Canada are delivered into a system of pipelines that collects and moves NGL to Fort Saskatchewan, Alberta or Sarnia, Ontario. NGLs are used directly as an energy source and as feedstock for the petrochemical and crude oil refining industries. Ethane is the feedstock for ethylene production.

 

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

 

Extraction — Harmattan

 

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

 

Harmattan extracts NGLs from the raw natural gas delivered for processing, fractionates the recovered NGLs into specification ethane, propane, butane and condensate, and provides storage and terminalling services for each product. The terminalling options for each product are:

 

·                  Ethane — Harmattan is connected to the Alberta Ethane Gathering System by an interconnecting pipeline that is owned by AltaGas. All ethane produced at Harmattan is delivered to the Alberta Ethane Gathering System.

·                  Propane — Producers may have their propane loaded onto either rail or truck. The propane truck and rail loading facilities, which are located at Didsbury, Alberta, are connected by pipeline to the main complex.

·                  Butane and Condensate — Producers may have their butane and condensate delivered to the Rangeland pipeline or loaded onto trucks at Harmattan.

 

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

 

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.

 

28

 

Under the terms of many of the raw natural gas processing agreements, a component of the compensation received by AltaGas for providing services to the producers is derived by AltaGas having the right to purchase a portion of the producers’ ethane for a price equal to the value of the equivalent natural gas. The ethane acquired by AltaGas is sold under a long-term contract for a price that includes full recovery of the cost of acquiring the ethane from the producers plus a premium.

 

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

 

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

 

Extraction — Younger

 

AltaGas currently owns a 56.67 percent interest in Younger. The remaining interest is held by Pembina. Younger processes natural gas transported on the Spectra Energy transmission system and Canadian Natural Resources Limited’s Stoddart transmission system to recover NGLs. AltaGas also owns a 30 percent interest in a 250 Mmcf/d natural gas pipeline which brings liquids-rich gas from the Montney area of British Columbia to Younger.

 

Younger has a licence capacity to process up to 750 Mmcf/d of natural gas and AltaGas’ share of such capacity is 425 Mmcf/d. AltaGas owns 100 percent of the facilities related to fractionation, storage, loading, treating or terminalling of NGLs.

 

All of AltaGas’ NGL production from Younger is currently marketed by Pembina under an NGL purchase agreement which expires in 2018. Pembina sources gas supply to Younger as part of the NGL purchase agreement. Effective April 1, 2018, AltaGas’ ownership will be reduced to 28.3 percent of the extraction assets and 50 percent of the facilities related to fractionation, storage, loading, treating or terminalling of NGLs. Pembina will also assume operatorship. AltaGas will source its own gas supply and market its share of NGLs produced. AltaGas’ ethane production from Younger is sold to Dow Chemicals under a fee-for-service contract.

 

Extraction - Joffre Ethane Extraction Plant

 

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

 

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

 

Extraction — Edmonton Ethane Extraction Plant

 

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

 

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

 

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

 

29

 

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.

 

Fractionation — North Pine Facility

 

Commissioning of the first train of the North Pine Facility was completed on December 1, 2017. The first train of the North Pine Facility is capable of processing up to 10,000 Bbls/d of propane plus NGL mix and has 6,000 Bbls/d of condensate terminalling capacity. Permitting is in place for the second NGL separation train capable of processing up to an additional 10,000 Bbls/d of propane plus NGL mix.

 

The North Pine Facility is connected via the North Pine Pipelines to the truck terminal for the Townsend Facility and is contracted through long-term supply agreements with Painted Pony for a portion of the total capacity. The remaining capacity is expected to be filled with NGL from other producers in the area. The North Pine Facility also has access to the CN rail network, allowing for the transportation of propane, butane and condensate to North American markets and including propane to RIPET upon its completion, which is currently expected in the first quarter of 2019.

 

Extraction and Fractionation — Competition

 

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

 

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

 

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

 

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

 

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

 

Gas Business — Field Gathering and Processing and Transmission

 

The Field Gathering and Processing business consists of approximately 30 gathering and processing facilities located in 12 operating areas in Western Canada and approximately 5,000 km of gathering and sales lines upstream of processing facilities that deliver natural gas into downstream pipeline systems that feed North American natural gas markets. AltaGas has a total gross licenced processing capacity of approximately 1.1 Bcf/d, of which 24 percent was capable of processing sour gas. AltaGas operates all but two of its facilities.

 

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

 

The amount and complexity of processing required before the raw gas is of saleable quality is a function of the quantity of NGLs and impurities present in the raw gas stream.

 

NGLs generally have greater value if extracted in liquid form and additional NGL recovery beyond downstream pipeline specifications may be carried out in order to capture the value of the NGLs. This additional recovery process can be done at field gas plants or at large-scale extraction plants. See above under the heading “Gas Business — Extraction and Fractionation”. AltaGas has NGL extraction capability at 12 of its natural gas field processing facilities.

 

The main drivers of the field gathering and processing business are throughput, gathering and processing fees and operating costs, with several facilities having the benefit of take-or-pay contracts. Throughput is impacted by new well

 

30

 

tie-ins, reactivations, recompletions, well optimizations performed by producers and natural production declines in areas served by AltaGas’ processing facilities.

 

Field Gathering and Processing - Facilities

 

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

 

Field Gathering and Processing Facility Capacity and Throughput

 

	
 
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Licensed   capacity (gross Mmcf/d)(1)(2)
    	
 
    	
1,121
    	
 
    	
1,101
    	
 
    
	
Throughput   (gross fourth quarter Mmcf/d)(2)
    	
 
    	
441
    	
 
    	
365
    	
 
    
	
Capacity   utilization (%)
    	
 
    	
39
    	
 
    	
33
    	
 
    

 

Notes:

(1)         As at December 31, 2017 and 2016.

(2)         Gross numbers are not adjusted to reflect AltaGas’ working interest.

 

Average facility utilization increased to 39 percent in 2017 from 33 percent in 2016 primarily due to volumes processed at the Townsend Facility.

 

Field Gathering and Processing - Significant Operating Areas and Customers

 

Approximately 80 percent of AltaGas’ field gathering and processing volumes are processed through the Townsend Facility, Townsend 2A, Blair Creek Facility and Gordondale Facility located in the liquids rich Montney resource play.

 

Townsend Facility

 

In mid-2016, AltaGas completed construction of the 100 percent AltaGas owned Townsend Facility, which is a 198 Mmcf/d shallow cut gas processing facility located approximately 100 km north of Fort St. John and 20 km southeast of AltaGas’ Blair Creek Facility. Painted Pony has reserved all of the firm capacity at the Townsend Facility under a 20-year take-or-pay agreement.

 

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

 

Townsend 2A

 

AltaGas completed construction of its 100 percent owned Townsend 2A, a 99 Mmcf/d shallow cut processing facility, and related field compression equipment in September 2017. Townsend 2A entered service on October 1, 2017. Townsend 2A and the field compression equipment are fully contracted with Painted Pony under a 20-year take-or-pay agreement. NGL produced will be transported approximately 70 km to AltaGas’ North Pine Facility via existing NGL pipelines owned by AltaGas.

 

Blair Creek

 

AltaGas owns 100 percent of the Blair Creek Facility which has processing capacity of 83 Mmcf/d of natural gas. AltaGas operates the facility which is located approximately 140 km northwest of Fort St. John, British Columbia. The facility processes gas gathered from Painted Pony and Tourmaline Oil Corp. The plant is equipped with liquids extraction facilities to capture the NGLs value for the producer.

 

Gordondale

 

AltaGas owns 100 percent of the Gordondale Facility which has processing 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

 

31

 

northwest of Grande Prairie, Alberta. The Gordondale Facility processes gas gathered from Birchcliff Energy Ltd.’s Gordondale Montney development under a long-term take-or-pay contract. The plant is equipped with liquids extraction facilities to capture the NGLs value for the producer.

 

FG&P Other Operating Areas

 

AltaGas’ remaining facilities are often physically linked, creating facility complexes that offer delivery options and revenue continuity in the event that one of the plants in a complex shuts down. AltaGas currently conducts business with approximately 60 producers in its Field Gathering and Processing operating areas.

 

Field Gathering and Processing - Contracts

 

AltaGas gathers and processes natural gas under contracts with natural gas producers. Currently, there are approximately 160 active gathering and processing contracts. These contracts, in general:

 

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

 

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

 

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

 

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

 

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

 

The amount of capital that AltaGas commits to acquire or develop gathering and processing facilities is linked to AltaGas’ assessment of the production available to be processed at the facility, reserves in the area, the extent of the reserve dedication and the processing fees to be paid by producers for its services. When a facility is acquired or constructed, AltaGas conducts an independent review of the natural gas reserves and production in the area surrounding each facility using, among other sources, Alberta Energy Regulator production data and reserve estimates and producers’ reserve reports for the area. AltaGas also conducts a review of the physical plant and equipment and the operating and maintenance costs of facilities prior to construction or acquisition.

 

Fee Structure

 

AltaGas’ Field Gathering and Processing business generates revenue from fees for volumes of natural gas processed at a processing facility or gathered through a gathering system and, at several facilities, such fees are on a take-or-pay basis.

 

In determining appropriate contractual provisions, including a reasonable payback period on its invested capital, AltaGas seeks to align its interests with the financial and business objectives of its producer customers. The vast majority of AltaGas’ gathering and processing contracts are volumetric service fee structures, based on a rate per Mcf of throughput. Volumetric fee structures may include a provision for recovery of actual operating costs. The majority of contracts in place at December 31, 2017 were subject to annual price escalation related to changes in CPI. This toll-for-service structure (as opposed to the commodity spread-based price structures predominantly used by midstream companies in the U.S.) avoids exposure to commodity price risk because revenue is a function of volumes processed. AltaGas’ investment is generally protected by the life of reserves behind the facility, since producing wells typically remain connected to a gathering and processing system for their entire productive lives.

 

Length of Term

 

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

 

32

 

Type of Service

 

In general, producers have access to either firm service or interruptible service. Firm service offers producers priority to have their natural gas processed at the applicable AltaGas facility subject to industry standard maintenance and force majeure. Interruptible service is available only if the applicable AltaGas facility has capacity available after all firm service commitments with respect to such facility have been satisfied. Firm service is normally provided to a producer when the producer’s natural gas reserves have been dedicated to an AltaGas facility.

 

Field Gathering and Processing - Competition

 

AltaGas competes with other midstream entities operating in the WCSB. In 2017, AltaGas processed an average of 392 Mmcf/d, which was approximately 3 percent of volumes produced in the WCSB. The majority of processing capacity generally continues to be provided by the upstream natural gas exploration and production companies.

 

The field gathering and processing marketplace continues to evolve and the competitive environment also continues to change. AltaGas believes that its field gathering and processing strategies and competitive advantages, including plans to develop LPG export capacity and make such capacity available to producers, will allow it to continue to effectively compete in the midstream marketplace. AltaGas also believes that its operational skills and market penetration make it a preferred business partner for many exploration and production companies.

 

Transmission — Business Description

 

AltaGas wholly owns four natural gas transmission systems with transportation capacity of approximately 559 Mmcf/d.

 

Transmission — Competition

 

AltaGas competes with other midstream entities operating in the WCSB. AltaGas’ transmission assets are well positioned to operate in a competitive environment and take advantage of their strategic locations and contract terms in order to compete with others. AltaGas continually investigates new pipeline opportunities in developing areas and in the vicinity of other AltaGas assets.

 

Gas Business — Energy Services

 

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

 

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

 

Gas Business — Energy Export

 

RIPET

 

On October 16, 2015, AltaGas entered into a project agreement with RTI for RIPET. This was followed in December 2015, with a sublease and related agreements between RTI and AltaGas. RIPET is expected to ship up to 1.2 million tonnes of propane per annum. A positive FID was made on RIPET in January 2017. Construction began in April 2017. In May 2017, AltaGas entered into a joint venture agreement with Vopak pursuant to which Vopak acquired a 30 percent interest in RIPET. RIPET is expected to be in-service in the first quarter of 2019. AltaGas anticipates having physical volumes equal to approximately 50 percent of the 1.2 million tonnes per annum. The remaining 50 percent is expected to be supplied by producers and other suppliers. AltaGas has entered into negotiations with a number of producers and other suppliers and

 

33

 

expects to underpin approximately 40 percent of RIPET’s annual expected capacity under tolling arrangements with producers and other suppliers. AltaGas and Astomos have entered into a multi-year agreement for the purchase of at least 50 percent of the 1.2 million tonnes of propane expected to be available to be shipped from RIPET each year. Commercial discussions with Astomos and several other third party offtakers for further capacity commitments are proceeding.

 

Ferndale Terminal

 

AltaGas, through its indirect ownership interest in Petrogas, exports LPG through the Ferndale Terminal, which is owned and operated by Petrogas. The Ferndale Terminal is capable of handling LPG exports of up to 30,000 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 also has a logistics network consisting of over 1,800 rail cars and 24 rail and truck terminals in Canada and the United States. Petrogas’ major terminal and owned and leased storage facilities are located in key energy hubs, including, without limitation, Fort Saskatchewan, Alberta, Sarnia, Ontario, Griffith, Indiana, Conway, Kansas and Mt. Belvieu, Texas.

 

Environmental Considerations Impacting the Gas Business

 

The Gas business is subject to the following environmental regulations:

 

Alberta

 

Specified Gas Emitters Regulation (SGER)

 

The SGER under the Climate Change and Emissions Management Act (Alberta) took effect on July 1, 2007 and was amended in June of 2015. The regulation applied to large emitter facilities with direct emissions totalling 100,000 tonnes or more of carbon dioxide equivalent per annum, requiring a large emitter in its ninth or subsequent year of commercial operation to achieve a net emission intensity of 85 percent in 2016 and 80 percent in 2017 relative to the baseline emissions intensity that was established for the facility. Newer facilities were required to phase in annual emissions intensity reduction targets commencing in its 4th year of commercial operation.

 

Compliance options included: (i) making facility enhancements to reduce GHG emissions, (ii) purchasing Alberta-based offsets or emission performance credits, or (iii) contributing to the Alberta Government’s Climate Change and Emissions Management Fund that would invest in transformative technologies to reduce GHG emissions in the province. The amount of money that a facility owner must contribute to the Climate Change and Emissions Management Fund to obtain one fund credit equal to a one tonne reduction in emissions was set at $30.

 

Both Harmattan and the Gordondale Facility were considered large emitters under the SGER and as at December 31, 2017, were compliant with the regulation. Effective January 1, 2018 and concurrently with the coming into force of the Carbon Competitiveness Incentive Regulation, the SGER was repealed.

 

Carbon Competitiveness Incentive Regulation (CCIR)

 

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

 

Large emitters subject to the CCIR will have the same compliance options available to them, as they did under the SGER. However, the CCIR has introduced expiry dates for emissions performance credits and emissions offsets. Emissions performance credits and emissions offsets generated in 2017, on a go-forward basis, are subject to expiry periods of eight (8) years. Offsets or credits from 2014 and earlier will expire in 2020, and those from 2015 or 2016 will expire in 2021. The

 

34

 

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 output-based allocation system, facilities are allowed to emit a certain amount of GHG, free of charge from the carbon levy. This approach protects industries from competitiveness impacts that could shift production to other jurisdictions. These “free” emissions are determined based on a product-specific emissions benchmark. Benchmarks are set relative to high-performing industry peers or competitors who produce the same or similar products. Allocations of free emissions will decrease at one per cent annually beginning in 2020.

 

Both the Harmattan and Gordondale Facility are considered large final emitters under the CCIR. Details regarding this program are still being defined. AltaGas continues to monitoring developments to determine how its facilities’ compliance costs will be impacted.

 

Carbon Levy

 

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

 

Methane Reduction Regulation

 

The Government of Alberta has committed to reduce methane emissions from oil and gas operations by 45 percent 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 for oil and gas activities continue to evolve with regulations expected sometime in 2018.

 

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, Younger, Townsend Facility, Townsend 2A, North Pine Facility and other facilities in B.C. are subject to the reporting obligations and are in compliance with the Greenhouse Gas Emission Reporting Regulation.

 

POWER BUSINESS

 

AltaGas’ Power business contributed revenue of $632 million for the year ended December 31, 2017 (2016 - $575 million), representing approximately 23 percent (2016 — 23 percent) of AltaGas’ total revenue before Corporate segment and intersegment eliminations.

 

The Power business is engaged in the generation and sale of capacity, electricity, ancillary services and related products in Alberta, British Columbia, California, Colorado, Michigan and North Carolina. At December 31, 2017, AltaGas had 1,708 MW of installed power capacity from a combination of gas-fired, hydro, wind and biomass generation and energy storage assets, as more particularly set forth in the below table.

 

35

 

	
Facility
    	
 
    	
Interest
   (%)
    	
 
    	
Capacity
   (MW)
    	
 
    	
Type
    	
 
    	
Geographic
   Region
    	
 
    	
Contracted
   Expiry Date
    	
 
    
	
Blythe
    	
 
    	
100
    	
 
    	
507
    	
 
    	
Gas-fired
    	
 
    	
California, U.S.
    	
 
    	
2020
    	
 
    
	
Tracy
    	
 
    	
100
    	
 
    	
330
    	
 
    	
Gas-fired
    	
 
    	
California, U.S.
    	
 
    	
2022
    	
 
    
	
Forrest Kerr
    	
 
    	
100
    	
 
    	
195
    	
 
    	
Hydro
    	
 
    	
British Columbia,   Canada
    	
 
    	
2074
    	
 
    
	
Bear Mountain
    	
 
    	
100
    	
 
    	
102
    	
 
    	
Wind
    	
 
    	
British Columbia,   Canada
    	
 
    	
2034
    	
 
    
	
Hanford
    	
 
    	
100
    	
 
    	
97
    	
 
    	
Gas-fired
    	
 
    	
California, U.S.
    	
 
    	
2022
    	
 
    
	
Henrietta
    	
 
    	
100
    	
 
    	
96
    	
 
    	
Gas-fired
    	
 
    	
California, U.S.
    	
 
    	
2022
    	
 
    
	
Brush II
    	
 
    	
100
    	
 
    	
70
    	
 
    	
Gas-fired
    	
 
    	
Colorado, U.S.
    	
 
    	
2019
    	
 
    
	
McLymont
    	
 
    	
100
    	
 
    	
66
    	
 
    	
Hydro
    	
 
    	
British Columbia,   Canada
    	
 
    	
2075
    	
 
    
	
Ripon
    	
 
    	
100
    	
 
    	
49.5
    	
 
    	
Gas-fired
    	
 
    	
California, U.S.
    	
 
    	
2018
    	
 
    
	
Pomona(1)
    	
 
    	
100
    	
 
    	
44.5
    	
 
    	
Gas-fired
    	
 
    	
California, U.S.
    	
 
    	
Merchant
    	
 
    
	
Craven
    	
 
    	
50
    	
 
    	
24
    	
 
    	
Biomass
    	
 
    	
North Carolina, U.S.
    	
 
    	
2027
    	
 
    
	
Pomona Energy Storage
    	
 
    	
100
    	
 
    	
20
    	
 
    	
Storage
    	
 
    	
California, U.S.
    	
 
    	
2027
    	
 
    
	
Volcano
    	
 
    	
97
    	
 
    	
16
    	
 
    	
Hydro
    	
 
    	
British Columbia,   Canada
    	
 
    	
2074
    	
 
    
	
Cogeneration I
    	
 
    	
100
    	
 
    	
15
    	
 
    	
Gas-fired
    	
 
    	
Alberta, Canada
    	
 
    	
Merchant
    	
 
    
	
Cogeneration II
    	
 
    	
100
    	
 
    	
15
    	
 
    	
Gas-fired
    	
 
    	
Alberta, Canada
    	
 
    	
Merchant
    	
 
    
	
Cogeneration III
    	
 
    	
100
    	
 
    	
15
    	
 
    	
Gas-fired
    	
 
    	
Alberta, Canada
    	
 
    	
Merchant
    	
 
    
	
Busch Ranch
    	
 
    	
50
    	
 
    	
14.5
    	
 
    	
Wind
    	
 
    	
Colorado, U.S.
    	
 
    	
2037
    	
 
    
	
Grayling
    	
 
    	
30
    	
 
    	
11.1
    	
 
    	
Biomass
    	
 
    	
Michigan, U.S.
    	
 
    	
2027
    	
 
    
	
Parkland
    	
 
    	
100
    	
 
    	
10
    	
 
    	
Gas-fired
    	
 
    	
Alberta, Canada
    	
 
    	
Merchant
    	
 
    
	
Bantry
    	
 
    	
100
    	
 
    	
7
    	
 
    	
Gas-fired
    	
 
    	
Alberta, Canada
    	
 
    	
Merchant
    	
 
    
	
Gordondale
    	
 
    	
100
    	
 
    	
3.4
    	
 
    	
Gas-fired
    	
 
    	
Alberta, Canada
    	
 
    	
Merchant
    	
 
    
	
Total
    	
 
    	
 
    	
 
    	
1,708
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    

 

Note:

(1)             Currently under an extended outage as AltaGas evaluates repowering opportunities.

 

AltaGas continues to drive its strategy to grow its highly contracted, clean power generation portfolio. For the coming years, AltaGas has approximately 450 MW of generation projects targeted for California.

 

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

 

	
 
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Renewable power   sold (GWh)
    	
 
    	
1,629
    	
 
    	
1,551
    	
 
    
	
Conventional   power sold (GWh)
    	
 
    	
2,844
    	
 
    	
1,950
    	
 
    
	
Renewable   capacity factor (%)
    	
 
    	
39.6
    	
 
    	
39.1
    	
 
    
	
Contracted   conventional equivalent availability factor (%) (1)
    	
 
    	
98.1
    	
 
    	
97.3
    	
 
    

 

Note:

(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 northern California, the Corporation is focused on owning generating assets in locally constrained areas near load pockets as local resource adequacy needs result in more opportunities for expansion, re-contracting and energy storage. On November 30, 2015, AltaGas acquired three Northern California gas-fired power assets with total generating capacity of 523 MW, located in the San Joaquin Valley. All three assets are fully contracted through 2022 with PG&E under PPAs which are structured as tolling arrangements for 100 percent of facility energy, capacity and ancillary services. Earlier in 2015, AltaGas acquired Ripon, which is also contracted with PG&E until May 31, 2018. Following the expiry of the PPA at Ripon, AltaGas has been awarded a resource adequacy contract for June through September 2018. Concurrently, AltaGas is also continuing to pursue battery storage opportunities at this site.

 

36

 

In southern California, the 507 MW Blythe Energy Center utilizes gas-fired generation to produce power and heat. The heat is then captured in secondary steam generators, which produce additional power via a steam turbine, and increase the efficiency of the overall generation process. The power serves the transmission grid operated by the CAISO to cover periods of high-demand primarily driven by the Los Angeles area. The facility employs proven Siemens technology and has a low base load heat rate in the range of 7,000 to 7,500 Btu/kWh, low emissions, responsive start times and flexible ramp rates. Due to the structure of the long-term PPA with SCE, the majority of the revenue from the facility is derived from being available to produce and not from actual production, therefore providing stable cash flow. The current capacity of the Blythe Energy Center is contracted until July 31, 2020. The facility is directly connected to a Southern California Gas Company natural gas pipeline for its supply and has reactivated an El Paso Gas Company connection as a second supply source, and interconnects to SCE and CAISO via a 67-mile transmission line also owned by Blythe and is part of the Blythe Energy Center. The transmission line is capable of transmitting 1,100 MW and has excess capacity to meet future load growth. In 2014, Blythe entered into a long-term agreement with Siemens for the maintenance of the two existing combustion turbines. In 2014, AltaGas also acquired additional land to provide further opportunities to expand. Development activities are ongoing that could potentially result in a significant expansion in AltaGas’ renewable generation capacity in the vicinity of the Blythe Energy Center. The Blythe Energy Center also successfully implemented a LLTD package in 2017, which reduced the minimum operating level from 173 MW to 125 MW and increased the level of ancillary services certified by the CAISO by over 60 percent. The implementation of the LLTD coupled with the ability to draw gas from two systems has provided for increased reliability through a redundant gas source and led to a significant increase in capacity factor that is expected to continue into the future.

 

In addition, AltaGas acquired Pomona in early 2015. Pomona is strategically located in the East Los Angeles basin load pocket. In early 2016, AltaGas Pomona Energy Inc. submitted an application with the California Energy Commission to repower the Pomona facility to a flexible, fast ramping peaking facility under the small power plant exemption process. AltaGas exercised its one-time right to suspend the application in March 2017 for one year while AltaGas considers options for other power development opportunities at the site.

 

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

 

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 will provide 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 will receive fixed monthly resource adequacy payments under the ESA and will retain 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.

 

Run-of-River Hydroelectric Generation

 

In 2014, AltaGas commissioned the 195 MW Forrest Kerr and 16 MW Volcano Creek facilities and in 2015, AltaGas commissioned the 66 MW McLymont Creek facility. The Northwest Hydro Facilities have a combined generating capacity of approximately 277 MW and are contracted with 60-year EPAs with BC Hydro that are fully indexed to CPI. Impact Benefit Agreements are in place for all three Northwest Hydro Facilities, supporting a cooperative and mutually beneficial relationship between the Tahltan First Nation and AltaGas. In addition, AltaGas entered into an agreement with BC Hydro to contribute to the development of the Northwest Transmission Line. The Northwest Hydro Facilities are the anchor tenant for the Northwest Transmission Line.

 

Earnings from the Northwest Hydro Facilities are impacted by variations in river flow necessary for power generation. For example, increases in precipitation and snowpack melt in the spring and summer months create periods of higher water flow resulting in seasonally stronger earnings.

 

Wind Generation

 

AltaGas has 117 MW of wind generation with all electricity generated being sold under long-term contracts.

 

37

 

The 102 MW Bear Mountain Wind Park near Dawson Creek, British Columbia consists of 34 turbines, a substation and transmission and collector lines. It is 100 percent owned by BMWLP and connected to the BC Hydro transmission grid. The turbine manufacturer, Enercon GmbH of Germany, provides operating and maintenance services to BMWLP under a long-term service agreement. All of the power from the Bear Mountain Wind Park is sold to BC Hydro under a 25-year EPA. BMWLP has retained the green attributes and RECs and sells them, and intends to continue to sell them, to provide an additional revenue stream. There are royalty agreements in place with Peace Energy Cooperative (a community-based group) and Aeolis Wind Power Corporation for a total of 0.912 percent of the project revenues and for 28.5 percent of any revenues from the sale of RECs above a cumulative threshold amount.

 

AltaGas indirectly owns a 50 percent interest in a 29 MW wind farm in Colorado (Busch Ranch). Busch Ranch has a 25-year renewable energy purchase agreement with Black Hills/Colorado Electric Utility Company, LP.

 

Competition

 

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

 

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

 

Wind power generated from both Bear Mountain and Busch Ranch is not currently exposed to power price volatility as the power generated is sold at a fixed price for 25 years, with escalation factors of 50 percent of CPI and 2 percent, respectively. The Blythe Energy Center is contracted by SCE under a long-term PPA until July 31, 2020. Power sold from Forrest Kerr, McLymont Creek and Volcano Creek are sold at a predetermined price as contracted under the 60-year EPAs with BC Hydro. The EPAs for Forrest Kerr, McLymont Creek, and Volcano Creek are fully indexed to CPI. Power sold from Grayling and Craven is not exposed to market prices and is sold under PPAs that expire August 2027 (with automatic one year renewals unless terminated) and December 31, 2027, respectively. Ripon is contracted by PG&E under a PPA until May 31, 2018, following which AltaGas has been awarded a resource adequacy contract for June through September 2018. Brush II is contracted by Tri-State Generation and Transmission Association, Inc. until December 31, 2019. Tracy, Hanford and Henrietta are all fully contracted with PG&E under PPAs until October 31, 2022 for Tracy and December 31, 2022 for Hanford and Henrietta.

 

Environmental Considerations Impacting the Power Business

 

The Power business is subject to the following environmental regulations:

 

Alberta

 

Renewable Electricity Act

 

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

 

38

 

U.S. Federal Air and GHG Regulations

 

Clean Air Act

 

Under the Clean Air Act, the United States Environmental Protection Agency (EPA) has the authority to set federal ambient air quality standards for certain air pollutants which apply throughout the U.S. In 2015, the EPA lowered the primary national ambient air quality standard for ozone. Implementation will be phased in over several years. The new standard eventually could increase regulatory burdens for AltaGas’ natural gas-fired power plants, which emit volatile organic compounds and nitrogen oxides that may contribute to ozone formation, 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 EPA. In general, states may choose to impose stricter performance requirements than does the EPA.

 

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

 

All of AltaGas’ operating natural gas-fired power generation facilities located in the U.S. operate under and materially comply with requirements set forth in the permits issued to such facilities.

 

California GHG Regulations

 

California Renewable Portfolio Standard

 

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

 

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

 

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

 

Cap-and-Trade Program

 

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

 

As of December 31, 2017, 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. 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 with the relatively recent enactment of 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).

 

39

 

GSAs must develop plans that allow the maximum quantity of groundwater to be withdrawn without causing the lowering of groundwater levels, reduction of storage, seawater intrusion, degraded water quality, land subsidence or depletions of interconnected surface water. Although SGMA focuses on groundwater supplies, reduced availability of groundwater might increase surface water demands, whether originating from local or imported surface water supply sources. In these early stages of implementation, it is uncertain whether or how SGMA may impact water supplies for AltaGas’ power generation facilities in California.

 

UTILITIES BUSINESS

 

AltaGas’ Utilities business contributed revenue of $1.1 billion for the year ended December 31, 2017 (2016 - $1.1 billion), representing approximately 41 percent (2016 – 44 percent) of AltaGas’ total revenue before Corporate segment and intersegment eliminations.

 

The Utilities business owns utility assets that deliver natural gas to end-users in Canada (Alberta, British Columbia, Nova Scotia and the Northwest Territories) and the United States (Michigan and Alaska). The Utilities business in Canada is comprised of AUI in Alberta, PNG in British Columbia, Heritage Gas in Nova Scotia and a one third interest in Inuvik Gas in the Northwest Territories. The Utilities business in the United States is comprised of 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 the opportunity to earn regulated rates that provide for recovery of costs and a return on capital from the regulator, which is to reflect a fair rate of return on a regulatory deemed or targeted capital structure applied to an approved regulatory asset value (i.e. rate base). The ability of a regulated utility to recover prudently incurred costs of providing service and earn the regulator-approved rate of return on equity depends on the utility achieving the forecasts established in the rate-setting processes.

 

Canada

 

The distribution of natural gas in Alberta, British Columbia, Nova Scotia and the Northwest Territories is regulated by the AUC, the BCUC, the NSUARB and the NWTPUB, respectively. The AUC, BCUC and NSUARB’s jurisdiction includes the approval of distribution tariffs for regulated distribution utilities which includes the rates charged and the terms and conditions of service to be provided by those utilities. Inuvik Gas is regulated on a complaint basis and sets its rates to be market competitive.

 

For Heritage Gas and PNG, the regulators approve distribution rates based on a cost-of-service regulatory model. Under this model, the regulators seek to provide the distribution utility with an opportunity to recover all prudently incurred operating, depreciation, income tax and financing costs, and to earn a reasonable return on equity.

 

For AUI, the regulator approves distribution rates under a PBR model that commenced January 1, 2013 with an initial term of five years (2013 to 2017) and a second term of five years (2018 to 2022). Under this model, revenues are set by formula. Specifically, revenues in each year are based on the last approved rates and are increased each year by a formula reflecting customer growth and inflationary increases less expected productivity improvements. Amounts determined under the formula may also be supplemented in the event of extraordinary events creating gains or losses outside management’s control or for major capital projects not otherwise encompassed within the PBR formula.

 

Regardless of which model is used, the regulators attempt to ensure the resulting tariffs are just and reasonable, provide incentives for investments, and are not unduly preferential, arbitrary, or unjustly discriminatory.

 

United States

 

The gas utility business of SEMCO Energy is subject to regulation. 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. These regulatory agencies have jurisdiction over, among other things, rates, accounting procedures and standards of service.

 

40

 

In Alaska and Michigan, the regulators approve distribution rates based on a cost-of-service regulatory model. In Alaska, rates are set using the results from a historical test year plus known and measurable changes. In Michigan, rates are set using a projected test year. In both jurisdictions, the regulators seek to provide the distribution utility with an opportunity to recover all prudently incurred operating, depreciation, income tax, and financing costs, and to earn a reasonable return on equity. The regulators attempt to ensure that tariffs are just and reasonable, provide incentives for investments, and are not unduly preferential, arbitrary, or unjustly discriminatory.

 

Utilities Business Key Utility Metrics

 

The following table summarizes the average rate base for the Utilities business for the years ended December 31, 2017 and 2016:

 

	
 
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Rate base ($ millions) (1)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Utilities Canada
    	
 
    	
833
    	
 
    	
790
    	
 
    
	
Utilities U.S. (2) (3)
    	
 
    	
847
    	
 
    	
840
    	
 
    

 

Notes:

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

(2)    In US dollars.

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

 

The following table summarizes the capital expenditures for the years ended December 31, 2017 and 2016.

 

	
 
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
($ millions)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Utilities Canada
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
New business
    	
 
    	
14
    	
 
    	
19
    	
 
    
	
System   betterment and gas supply
    	
 
    	
40
    	
 
    	
39
    	
 
    
	
General plant
    	
 
    	
8
    	
 
    	
7
    	
 
    
	
Total
    	
 
    	
62
    	
 
    	
65
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Utilities U.S. (1)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
New business
    	
 
    	
9
    	
 
    	
14
    	
 
    
	
System   betterment and gas supply
    	
 
    	
37
    	
 
    	
35
    	
 
    
	
General plant
    	
 
    	
4
    	
 
    	
4
    	
 
    
	
Total
    	
 
    	
50
    	
 
    	
53
    	
 
    

 

Note:

(1)         In US dollars.

 

41

 

The following table summarizes the nature of regulation applicable to each utility (other than Inuvik Gas):

 

	
Regulated Utility
    	
 
    	
Regulated
   Authority
    	
 
    	
% of AltaGas’
   Consolidated
   Rate Base as
   at December
   31, 2017
    	
 
    	
Allowed
   Common
   Equity (%)
    	
 
    	
Allowed
   ROE
    (%)
    2016
    	
 
    	
Allowed
   ROE
    (%)
    2017
    	
 
    	
Significant Features/ Material Regulatory
   Development
    	
 
    
	
AUI
    	
 
    	
AUC
    	
 
    	
17
    	
 
    	
41
    	
(1)
    	
8.30
    	
(1)
    	
8.50
    	
(1)
    	
·   Distribution rates approved under PBR   model, current term 2013 – 2017. Effective January 1, 2018, next   generation PBR term 2018 – 2022 was approved.

·   Cost recovery and return on rate base   through revenue per customer formula.

·   Additional recovery and return on rate base   through capital tracker program.

·   Generic Cost of Capital proceeding underway   to establish allowed ROE and capital structure for 2018-2020, decision   expected in the second half of 2018.
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Heritage Gas
    	
 
    	
NSUARB
    	
 
    	
15
    	
 
    	
45
    	
 
    	
11.00
    	
 
    	
11.00
    	
 
    	
·   Distribution rates approved under cost of   service model.

·   No regulatory lag; earn immediately on   invested capital.

·   Revenue Deficiency Account of up to $50   million.

·   Customer Retention Program approved in   September 2016 resulting in a decrease in distribution rates for certain   commercial and residential customers and deferral of certain costs while the   program is in place.
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
PNG
    	
 
    	
BCUC
    	
 
    	
11
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
·   Distribution rates approved under cost of   service model.

·   Permanent rates approved for test year 2017   in the 2016/17 Revenue Requirement Application.

·   Primarily protected from weather related   volatility through revenue stabilization adjustment account.

·   Revenue requirements applications filed on   November 30, 2017 for test years 2018 and 2019, with new interim and   refundable rates in place January 1, 2018.
    	
 
    
	
PNG West
    	
 
    	
 
    	
 
    	
 
    	
 
    	
46.5
    	
 
    	
9.50
    	
 
    	
9.50
    	
 
    
	
PNG(NE) Fort St. John /Dawson Creek
    	
 
    	
 
    	
 
    	
 
    	
 
    	
41
    	
 
    	
9.25
    	
 
    	
9.25
    	
 
    
	
PNG(NE) Tumbler Ridge
    	
 
    	
 
    	
 
    	
 
    	
 
    	
46.5
    	
 
    	
9.50
    	
 
    	
9.50
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
SEMCO Gas
    	
 
    	
MPSC
    	
 
    	
33
    	
 
    	
49
    	
 
    	
10.35
    	
 
    	
10.35
    	
 
    	
·   Distribution rates approved under cost of   service model.

·   Use of projected test year for rate cases   with 10 month limit to issue a rate order.

·   Rate rider provides recovery relating to   the Main Replacement Program which allows the company to accelerate the   replacement of older portions of its system.

·   Last rate case settled in 2011. Next rate   case expected to be filed in 2019.
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
ENSTAR
    	
 
    	
RCA
    	
 
    	
19
    	
 
    	
51.81
    	
 
    	
12.55
    	
 
    	
11.875
    	
 
    	
·   Distribution rates approved under cost of service   model using historical test year and allows for known and measurable changes.

·   Rate Order approving rate increase issued   on September 22, 2017. Final rates effective November 1, 2017.

·   Required to file another rate case no later   than June 1, 2021 based upon 2020 test year.
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
CINGSA
    	
 
    	
RCA
    	
 
    	
5
    	
 
    	
50
    	
 
    	
12.55
    	
 
    	
12.55
    	
 
    	
·   Distribution rates approved under cost of   service model using historical test year and allows for known and measurable   changes.

·   Rate case will be filed in 2018 based on   2017 historical test year.
    	
 
    

 

Note:

(1)          2013-2016 ROE approved at 8.3%; 2017 ROE approved at 8.5% pursuant to Generic Cost of Capital decision.

 

42

 

AUI

 

AUI commenced operations as an Alberta, provincially regulated, natural gas distribution utility in 1954. Its head office is located in Leduc, Alberta. AUI delivers natural gas to residential, farm, and C&I consumers in more than 90 communities throughout Alberta. At the end of 2017, AUI served approximately 80,000 customers. AUI also owns transmission facilities, including, without limitation, high-pressure pipelines that deliver natural gas from gas sources to the distribution systems. AUI’s primary objective is to recover its costs and earn a return of, and return on, capital while maintaining high operating standards to ensure safe, reliable, cost-effective and secure natural gas supply and delivery for its customers.

 

AUI operates in a mature market and has achieved nearly 100 percent saturation within its franchise areas, with the exception of a few consumers choosing alternate fuel sources or living in remote areas where natural gas service is cost-prohibitive. The Alberta natural gas distribution market is dominated by a major distributor that serves approximately 85 percent of natural gas consumers. AUI serves approximately 6 percent of Alberta customers, with the remaining market served by member-owned natural gas cooperatives and municipally owned systems. AUI pursues opportunities to develop service areas not currently served with natural gas.

 

Operations

 

AUI’s distribution system consists of 20,986 km of pipeline. There are 704 small and mid-sized metering and pressure regulating stations throughout AUI’s distribution network. AUI operates its gas distribution systems through a network of 14 district offices. In 2017, the total throughput of natural gas delivered to 79,518 end consumer service sites and transported for two producers had a total energy value of approximately 20.5 PJ.

 

AUI’s market consists primarily of residential and small commercial consumers located in smaller population centres or rural areas of Alberta. AUI’s revenue by service type for each of the last two years is shown below:

 

AUI Revenue by Service Type(1)

 

	
(%)
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Residential
    	
 
    	
56.6
    	
 
    	
57.7
    	
 
    
	
Commercial
    	
 
    	
22.9
    	
 
    	
21.6
    	
 
    
	
Rural(2)
    	
 
    	
17.1
    	
 
    	
17.2
    	
 
    
	
Demand
    	
 
    	
3.4
    	
 
    	
3.5
    	
 
    
	
Total
    	
 
    	
100.0
    	
 
    	
100.0
    	
 
    

 

Notes:

(1)         Excludes revenue from producer transportation service.

(2)         Rural customers are located outside of incorporated areas and consist primarily of farms, irrigation pumps, grain dryers and greenhouses.

 

AUI provides service to designated areas in Alberta under the authority granted by franchise agreements or other agreements granted as permits or approvals issued pursuant to applicable statutes. As at December 31, 2017, AUI held a total of 74 such franchises and agreements, the majority of which are held with municipalities, with average remaining terms that vary from 3.5 years to perpetual and are renewed from time to time in the ordinary course of AUI’s business. The top three municipalities contributing to AUI’s total revenue in 2017 were the City of Leduc, Town of Beaumont and Town of Drumheller, which collectively accounted for approximately 24 percent of AUI’s total revenue and 21 percent of energy delivered in 2017.

 

Seasonality

 

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

 

Delivery rates for AUI are based on the 20-year rolling average Degree Days expected for the period. Temperature fluctuations impact the operating results of AUI.

 

43

 

Material Regulatory Developments and Applications

 

Effective January 1, 2018, the AUC approved a second PBR term from 2018 to 2022. Under the second generation PBR plan, rates continue to be set under a revenue cap per customer formula with annual adjustments for customer growth and inflation less expected productivity. In addition, the PBR mechanism continues to allow for recovery of costs determined to flow through directly to customers and related to material exogenous events. Incremental capital funding continues to be available, however, it is now largely established under a formula based on historical capital additions rather than for specific applied-for projects and programs.

 

HERITAGE GAS

 

Heritage Gas is a greenfield natural gas distribution utility in Nova Scotia with a head office located in Dartmouth, Nova Scotia. Heritage Gas’ franchise was granted in 2003 and gives it the exclusive right to distribute natural gas through its distribution system to all or part of seven counties in Nova Scotia, including the Halifax Regional Municipality until December 31, 2028.

 

As a greenfield operation, Heritage Gas has significant opportunity for growth in Nova Scotia. Natural gas currently provides less than 10 percent of total energy used in the province, with electricity and fuel oil being the dominant energy sources. To date, natural gas has been adopted by all of the major hospitals and universities in its most populous area, Halifax Regional Municipality, as well as many schools and businesses. At the end of 2017 there were approximately 21,400 residences and businesses with access to the Heritage Gas system (potential customer meters) of which approximately 7,200 were commercial energy consumers and 14,200 were residential energy consumers. Of the 21,400 potential customer meters, Heritage Gas had approximately 6,900 customer meters activated on December 31, 2017. While the Customer Retention Program is in place, Heritage Gas’ expects to focus on increasing penetration levels within the areas currently served by its existing network.

 

The following table illustrates the percentage of consumers who have access to the Heritage Gas system that have become customers of Heritage Gas.

 

	
Penetration rates (%)
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Activated   residential
    	
 
    	
27
    	
 
    	
25
    	
 
    
	
Activated   commercial
    	
 
    	
43
    	
 
    	
42
    	
 
    
	
All customers
    	
 
    	
32
    	
 
    	
31
    	
 
    

 

Beginning in the winter of 2014, declining propane prices available in Nova Scotia made the energy market, serving small commercial customers, extremely competitive with some customers choosing to adopt alternate fuels to natural gas, or implement dual fuel options. Heritage Gas expects natural gas pricing will return to a more competitive alternative as propane prices are projected to increase over the coming years and as lower priced natural gas becomes available to Heritage Gas through new pipelines and storage projects. In 2016, Heritage Gas gained approval for a Customer Retention Program from the NSUARB to enable the Company to retain commercial customers through this period of competitive commodity pricing. In the fall of 2017, Heritage Gas implemented an increase to the distribution rates as provided under the Customer Retention Program decision. To date the program has been successful in curtailing the migration of customers to propane. Since the implementation of the Customer Retention Program Heritage Gas has continued to add residential and commercial customers, although at a slower pace than prior years.

 

Operations

 

Heritage Gas’ distribution system consists of approximately 460 km of pipeline mains infrastructure of which approximately 345 km is located in the Halifax Regional Municipality, approximately 60 km is located in Amherst, 45 km in New Glasgow/Pictou area and approximately 10 km is located in Oxford.

 

Historically Heritage Gas has received much of its natural gas supply from the Sable Offshore Energy project and Encana Corporation’s Deep Panuke project off the coast of Nova Scotia. The natural gas supply from both of these projects continues to decline with an industry expectation for an end of reserves spanning the 2019 to 2020 timeframe.

 

44

 

Heritage Gas purchases gas under negotiated contracts with wholesale gas marketers. During 2017, Heritage Gas entered into gas supply and transportation contracts to ensure security of supply and to provide relative price stability. Gas supply was secured from western Canada as well as from local Maritime production. In 2017, Heritage Gas’ supply was delivered via TransCanada pipeline, Portland Natural Gas Transmission system and Maritimes & Northeast U.S. and Canadian pipeline systems from supply basins offshore Nova Scotia, Central and Western Canada and the United States. The cost of gas purchased is flowed through to the distribution customers and does not impact net income.

 

In 2014, Heritage Gas executed a 20-year gas storage agreement with Alton Natural Gas Storage L.P., a wholly-owned subsidiary of AltaGas, for storage capacity at the Alton Natural Gas Storage Project. Construction for this facility is underway and AltaGas currently expects the first phase of storage service to commence in 2021.

 

Also in 2014, Heritage Gas signed an agreement with Enbridge Inc. (formerly Spectra Energy) for the Atlantic Bridge Expansion Project, on the Algonquin Gas Transmission pipeline system. The contract is a 15-year commitment that provides Heritage Gas an opportunity to diversify suppliers and provide access to other supply basins. The Atlantic Bridge Expansion Project is expected to be in-service date in the second half of 2018.

 

Seasonality

 

The natural gas distribution business in Nova Scotia 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.

 

Delivery rates for Heritage Gas are set based on the 20-year rolling average Degree Days expected for the application period. Temperature fluctuations impact the operating results of Heritage Gas.

 

Material Regulatory Developments and Applications

 

In 2017, the Gas Distribution Act in Nova Scotia was changed to enable the NSUARB to regulate long-term gas distribution contracts for recovery by the gas distribution utility. In 2017, Heritage Gas entered into a precedent agreement with Portland Natural Gas Transmission System that will provide transportation capacity to Heritage Gas, giving it access to gas supply in Dawn, Ontario for a 22-year period beginning in the fall of 2018, enhancing security of supply and reducing gas price volatility. Heritage Gas filed an application with the NSUARB in January 2018 requesting approval for the contract.

 

As previously mentioned, Heritage Gas filed a customer retention program application with the NSUARB on March 2, 2016 requesting a decrease in distribution rates for commercial customers with consumption between 500 and 4,999 GJ per year and allowing for flexible rate increases from time to time for these customers up to previously approved distribution rates, a suspension of depreciation and a 50 percent capitalization rate for operating, maintenance and administrative expenses while the program is in place (the Customer Retention Program). In September 2016, the NSUARB approved Heritage Gas’ Customer Retention Program application. The approval included all of the items requested by Heritage Gas as well as a reduction to residential customer rates of $0.50 per GJ for the 2016 to 2017 and 2017 to 2018 winter seasons and a return on the deferred depreciation and operating expense balances arising from the Customer Retention Program of 4 percent.

 

The competitive position of natural gas pricing relative to propane improved in the Atlantic region throughout 2017 and into early 2018. Through enhanced gas procurement strategies and changes in market fundamentals, the average price of natural gas for Heritage Gas customers declined by over 20 percent in 2017 compared to 2016 and 2015, while the 2017 Sarnia benchmark price for propane increased by over 30 percent compared to 2016 and 40 percent compared to 2015. Accordingly, in November 2017, Heritage Gas exercised the flexibility provided for in the Customer Retention Program to increase the rates that were previously reduced as part of the Customer Retention Program, which has partially restored the rates to previously approved cost of service levels. Heritage Gas estimates that the Customer Retention Program will be in place through to 2021.

 

In June 2015 Heritage Gas received the NSUARB’s decision approving Heritage Gas’ application for the treatment, and the recovery, of natural gas storage service costs related to the Alton Natural Gas Storage Project. Heritage Gas expects this storage service to provide benefits to Heritage Gas and its customers in the form of security of gas supply, enhanced reliability and delivery of natural gas during the peak heating season, as well as reduced natural gas price volatility.

 

45

 

PNG

 

PNG’s head office is located in Vancouver, British Columbia and its principal operating office is located in Terrace, British Columbia. PNG’s wholly owned subsidiary, PNG(NE) has its main operating offices in Fort St. John and Dawson Creek, British Columbia.

 

PNG owns and operates the Western System, a regulated natural gas transmission and distribution utility within the west central portion of northern British Columbia. PNG(NE) owns and operates the Northeast System, a distribution utility in northeast British Columbia.

 

Substantially all of PNG’s and PNG(NE)’s pipeline facilities are located across Crown land or privately-owned property under rights-of-way granted by the Crown or the owners in perpetuity or for so long as they are used for pipeline purposes. Approximately three kilometers of main pipelines and approximately nine kilometers of lateral transmission pipelines cross reserves established under the Indian Act (Canada), for which PNG has appropriate land rights. Compressor and metering stations are principally located on land owned by PNG. PNG owns its local offices in Terrace, Prince Rupert, Kitimat, Burns Lake, Smithers, Summit Lake, Dawson Creek, Tumbler Ridge and Fort St. John and leases office space in Vanderhoof and Vancouver.

 

All of the property and assets of PNG and PNG(NE) are subject to the lien of a deed of trust and mortgage dated as of April 15, 1982 between PNG and Computershare Trust Company of Canada, as trustee, as amended and supplemented from time to time, under which PNG’s secured debentures have been issued.

 

All of PNG’s and PNG(NE)’s residential customers, most of their commercial customers and a number of their smaller industrial customers continue to rely on PNG and PNG(NE) for arrangement of their gas supply, and such customers pay tariffs which include PNG’s and PNG(NE)’s gas supply commodity and delivery costs. The large industrial customers, the majority of small industrial customers and a number of commercial customers purchase their own gas supply requirements from third party gas suppliers and contract for gas transportation service on the PNG and PNG(NE) pipeline systems. In addition, some of the smaller commercial customers purchase their gas supply requirements directly from gas marketers. Since PNG’s income is earned from the distribution of natural gas and not from the sale of the commodity, distribution margin is not adversely affected by this practice as the gas commodity costs are passed through to customers without a mark-up.

 

In the Western System service area, there are few remaining candidates for conversion to natural gas in the existing building stock and limited opportunity remains to extend gas distribution into un-serviced rural areas. In previous years, PNG had a Gas Transportation Service Agreement with a customer to contract for 80 Mmcf/d of its existing capacity for a LNG project. The project was subsequently halted and this agreement was terminated in March 2016. PNG continues to seek potential new customers to take over the released capacity in its Western System.

 

In the Northeast System service area, PNG(NE) continues to build out its distribution system to new communities and to capture new housing and commercial developments in its existing serviced communities.

 

Operations

 

PNG’s transmission pipeline system in the Western System service area connects with the British Columbia pipeline system operated by Enbridge Inc. (formerly Spectra Energy) near Summit Lake, British Columbia, and extends 587 km to the west coast of British Columbia at Prince Rupert. The pipeline between Summit Lake and Terrace has been partially paralleled, or looped, with a second line to increase throughput capacity. PNG also owns and operates over 300 km of lateral transmission pipelines extending into the various communities served by PNG, the most significant being dual lines extending approximately 57 km into Kitimat. The Western System distribution system is comprised of approximately 960 km of distribution pipelines. Five compressor units maintain pressure on PNG’s Western System transmission pipeline system (two of which are presently deactivated).

 

The Northeast System serves the Fort St. John and Dawson Creek area through connections with the Spectra Energy pipeline system at several locations. The Northeast System also connects with pipelines owned by Canadian Natural Resources Limited to obtain supply for the Fort St. John area, a producer’s pipeline to serve the Dawson Creek area, and a Canadian Natural Resources Limited gas supply pipeline to serve the Tumbler Ridge area. The entire Northeast System consists of approximately 243 km of transmission lines, 2,202 km of distribution lines and a gas processing plant near Tumbler Ridge with a capacity of 120 103m3 per day.

 

46

 

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

 

	
 
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Deliveries:   (PJ)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Residential
    	
 
    	
3.1
    	
 
    	
2.5
    	
 
    
	
Commercial
    	
 
    	
3.0
    	
 
    	
2.6
    	
 
    
	
Small industrial
    	
 
    	
2.4
    	
 
    	
2.4
    	
 
    
	
Large industrial
    	
 
    	
1.5
    	
 
    	
1.4
    	
 
    
	
Total deliveries
    	
 
    	
10.0
    	
 
    	
8.9
    	
 
    

 

	
 
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Customers   at Year End:
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Residential
    	
 
    	
36,218
    	
 
    	
36,169
    	
 
    
	
Commercial
    	
 
    	
5,414
    	
 
    	
5,409
    	
 
    
	
Small industrial
    	
 
    	
51
    	
 
    	
50
    	
 
    
	
Large industrial
    	
 
    	
2
    	
 
    	
2
    	
 
    
	
Total customers
    	
 
    	
41,685
    	
 
    	
41,630
    	
 
    

 

PNG currently has exclusive franchise agreements with the municipalities of Prince Rupert, Port Edward, Kitimat, Terrace, Smithers, Burns Lake, Houston, Fraser Lake and Vanderhoof, entitling it to supply and distribute natural gas within those municipalities. Each of the franchise agreements have a term of 21 years, expiring in 2032 (except in the cases of Port Edward, where the agreement expires on October 5, 2031, and Prince Rupert and Fraser Lake, where both agreements expire in 2036).

 

PNG also has operating agreements with the municipalities of Telkwa and Fort St. James that entitle it to install and operate gas distribution facilities in those municipalities. The initial term of each of these operating agreements has expired, and PNG is operating within ten year renewal terms which will expire in 2021 and 2019, respectively. Each operating agreement provides for an unlimited number of ten year renewal terms, which take effect automatically on the expiry of the preceding renewal term. If the parties cannot agree on alterations to an operating agreement for a renewal term, the BCUC may determine such alterations. During 2017, PNG and the District of Fort St. James agreed upon terms for a new franchise agreement to replace the current operating agreement. This has been submitted to the BCUC for acceptance.

 

PNG(NE) has exclusive franchise agreements with the city of Fort St. John, the District of Taylor and the City of Dawson Creek for 21-year terms, expiring in 2018, 2033, and 2036, respectively. PNG(NE) also had an operating agreement with the Village of Pouce Coupe which expired on December 31, 2016. An interim operating agreement has been in place while PNG(NE) and the Village of Pouce Coupe worked on finalizing a new franchise agreement, which has been submitted to the BCUC for acceptance. PNG(NE) operates its gas distribution facilities in the Tumbler Ridge area pursuant to a certificate of public convenience and necessity issued by the BCUC. The franchise agreements with the District of Taylor and City of Fort St. John give the municipalities the right to purchase the distribution system within the municipality on expiry of the franchise agreement, at the fair market value of the assets as a going concern.

 

Seasonality

 

Delivery rates for PNG are set based on the 10-year rolling average Degree Days expected for the application period. PNG is authorized by the BCUC to maintain a Revenue Stabilization Adjustment Mechanism regulatory account to mitigate the effect on its earnings of deliveries to certain customers caused principally by volatility in weather and the impact on deliveries. Balances in the account are recovered in customer rates over a two-year period based on forecast deliveries.

 

Material Regulatory Developments and Applications

 

On November 30, 2017, PNG also submitted Revenue Requirements Applications for 2018 and 2019 and received approvals for interim and refundable delivery rate increases effective January 1, 2018. Coupled with forecast changes in the Revenue Stabilization Adjustment Mechanism rate riders and decreases in the natural gas commodity costs, core customers will see net decreases in annualized bundled rates of 9 percent in the PNG West service area, a 1 percent

 

47

 

decrease in the Northeast Fort St. John and Dawson Creek service area and no rate changes in the Northeast Tumbler Ridge service area.

 

INUVIK GAS AND IKHIL JOINT VENTURE

 

Inuvik Gas is a corporation equally owned one third each by an AltaGas subsidiary, the Inuvialuit Petroleum Corporation, and ATCO Midstream NWT Ltd. The Ikhil Joint Venture is owned one third each by an AltaGas subsidiary, Inuvialuit Petroleum Corporation and ATCO Midstream NWT Ltd. The Ikhil Joint Venture owns and operates natural gas reserves, a processing facility and a 47 km pipeline that delivers natural gas to Inuvik Gas and the Northwest Territories Power Corporation. At the end of 2017 Inuvik Gas provided service to approximately 900 residential and commercial customers.

 

The Ikhil Joint Venture has historically supplied Inuvik Gas with natural gas to be delivered to the Town of Inuvik. The Ikhil Joint Venture natural gas reserves have depleted more rapidly than expected. As such, a propane air mixture system producing synthetic natural gas is currently the main source of energy supply for Inuvik Gas with Ikhil Joint Venture serving as a back-up. On December 7, 2016, Inuvik Gas notified the Town of Inuvik of its intention to terminate the gas distribution franchise agreement effective December 2018. Inuvik Gas is working with the Town of Inuvik over the course of the remaining term to transition ownership to the Town of Inuvik.

 

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 Energy Gas Company, and in Alaska, doing business as ENSTAR Natural Gas Company. SEMCO Energy’s gas utility business also includes a 65 percent ownership interest in CINGSA, a regulated natural gas storage utility in Alaska. The gas utility business accounts for approximately 99 percent of SEMCO Energy’s 2017 consolidated revenues. The gas utility business purchases, transports, distributes and sells natural gas and related gas distribution services to residential, C&I customers and is SEMCO Energy’s largest business segment.

 

SEMCO GAS

 

In Michigan, SEMCO Gas distributes natural gas to approximately 304,000 regulated customers located in both southern Michigan and Michigan’s Upper Peninsula, approximately 91 percent of which are residential. The remaining customers include power plants, food production facilities, furniture manufacturers and other industrial customers.

 

The average number of customers at SEMCO Gas has increased by an average of approximately 1.0 percent annually during the past three years (with an increase of 1.1 percent in 2017). 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, among other things, new homes and appliances are typically more energy efficient than older homes and appliances. In addition, incentives to install energy efficient appliances and equipment and employ other conservation and energy-saving measures and techniques appear to have prompted customers to reduce their gas consumption.

 

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

 

48

 

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

 

	
 
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Deliveries:   (MDth)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Residential
    	
 
    	
23,713
    	
 
    	
23,193
    	
 
    
	
Commercial
    	
 
    	
13,595
    	
 
    	
12,785
    	
 
    
	
Transport
    	
 
    	
21,225
    	
 
    	
20,347
    	
 
    
	
Gas Customer   Choice(1)
    	
 
    	
3,394
    	
 
    	
3,208
    	
 
    
	
Total deliveries
    	
 
    	
61,927
    	
 
    	
59,533
    	
 
    

 

	
 
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Customers   at Year End (2):
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Residential
    	
 
    	
256,670
    	
 
    	
255,906
    	
 
    
	
Commercial
    	
 
    	
23,487
    	
 
    	
23,399
    	
 
    
	
Transport
    	
 
    	
252
    	
 
    	
256
    	
 
    
	
Gas Customer   Choice(1)
    	
 
    	
23,171
    	
 
    	
20,469
    	
 
    
	
Total customers
    	
 
    	
303,580
    	
 
    	
300,030
    	
 
    

 

Notes:

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

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

 

Seasonality

 

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

 

Delivery rates 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

 

On December 15, 2016, SEMCO Gas filed an application with the MPSC seeking approval to construct, own, and operate the Marquette Connector Pipeline. In August 2017, the MPSC approved SEMCO’s application. For further details above under the heading “General Development of AltaGas’ Business - Development of the Utilities Business of AltaGas”.

 

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. A MPSC order is expected in mid-2018.

 

On December 27, 2017, the MPSC issued an order instructing all regulated utilities in Michigan to track the impact of the Tax Cuts and Jobs Act effective January 1, 2018 and sought comments from the utilities by January 19, 2018 on how any resulting benefit should flow back to customers. The Michigan utilities separately filed comments on January 19, 2018 and interested parties will have until February 2, 2018 to respond to the comments. The MPSC will then determine the appropriate process to establish how and when the savings will flow back to ratepayers. On February 22, 2018, the MPSC ordered the Michigan utilities to file an application no later than March 30, 2018 to determine the going forward tax credit to customers, with a goal for final commission determination no later than June 30, 2018 so that new rates can take effect on July 1, 2018. Within sixty days of the commission determination of the go-forward tax credit, the Michigan utilities are to submit a second application to determine the tax credit to customers for the prior period commencing January 1, 2018. Finally, no later than October 1, 2018, the utilities have to submit a third application to determine the deferred tax impact resulting from the tax law change and the method to flow the benefits to customers.

 

ENSTAR

 

In Alaska, ENSTAR distributes natural gas to approximately 144,000 customers in the metropolitan Anchorage area and surrounding Cook Inlet area, approximately 91 percent of which are residential. The remaining gas sales customers

 

49

 

include hospitals, universities and government buildings. ENSTAR also provides gas transportation service to power plants and a LNG plant. ENSTAR’s service area encompasses over 58 percent of the population of Alaska.

 

The average number of customers at ENSTAR has increased by an average of approximately 1.5 percent annually during the past three years (with an increase of 1.2 percent in 2017). While there may occasionally be variations in this pattern, average per customer annual gas consumption in Alaska over the longer-term has been decreasing because, among other things, new homes and appliances are typically more energy efficient than older homes and appliances. In addition, incentives to install energy efficient appliances and equipment and employ other conservation and energy-saving measures and techniques appear to have prompted customers to reduce their gas consumption.

 

Operations

 

ENSTAR’s natural gas delivery system (including SEMCO Energy’s Alaska Pipeline Company) includes approximately 456 miles of gas transmission pipelines and 3,083 miles of gas distribution mains. ENSTAR’s pipelines and mains are located in Anchorage and the Cook Inlet area of Alaska.

 

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

 

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

 

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

 

	
 
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Deliveries:   (Mmcf)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Residential
    	
 
    	
19,984
    	
 
    	
17,509
    	
 
    
	
Commercial
    	
 
    	
13,464
    	
 
    	
11,853
    	
 
    
	
Transport
    	
 
    	
27,344
    	
 
    	
27,963
    	
 
    
	
Total deliveries
    	
 
    	
60,792
    	
 
    	
57,325
    	
 
    

 

	
 
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Customers   at Year End:
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Residential
    	
 
    	
131,615
    	
 
    	
129,949
    	
 
    
	
Commercial
    	
 
    	
12,765
    	
 
    	
12,680
    	
 
    
	
Transport
    	
 
    	
22
    	
 
    	
22
    	
 
    
	
Total customers
    	
 
    	
144,402
    	
 
    	
142,651
    	
 
    

 

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 June 1, 2016, ENSTAR filed the 2016 rate case requesting an overall annual base rate increase of approximately US$12 million, or 3.9 percent on total revenues. On July 18, 2016, the RCA approved ENSTAR’s request for an additional

 

50

 

1.6 percent interim and refundable rate increase on total revenues, effective August 1, 2016. On September 22, 2017, the RCA issued a Rate Order deciding matters in ENSTAR’s 2016 rate case, including granting ENSTAR a return on equity of 11.875 percent and return on total capital of 8.59 percent. The Rate Order also requires ENSTAR to file another rate case based upon calendar year 2020 by June 1, 2021. ENSTAR was further directed to file revised revenue requirement schedules, cost of service study, and tariff sheets reflecting the RCA’s decisions in its Rate Order, which ENSTAR filed on October 3, 2017. The net result of the changes showed an overall rate deficiency which was approximately US$1 million higher than provided for by the interim rates or an additional increase of approximately 0.3 percent on total test year revenues. On October 25, 2017, the RCA issued an order accepting ENSTAR’s filing and approving the revised rates effective November 1, 2017.

 

CINGSA

 

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

 

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

 

CINGSA commenced “free-flow” injections into the CINGSA Storage Facility on April 1, 2012. In-service operations for the CINGSA Storage Facility began on November 9, 2012, when construction of the surface facilities was completed and withdrawal capability became available to storage customers. The CINGSA Storage Facility is actively being used by ENSTAR and its other customers as described above in the Cook Inlet area of Alaska.

 

Material Regulatory Developments and Approvals

 

In 2013, CINGSA detected higher than expected pressure during its biannual shut-in. CINGSA determined that it had encountered a pocket of gas that was at or near the initial reservoir pressure. Following extensive analysis, CINGSA has determined that the pocket of found gas it discovered totalled approximately 14.5 Bcf. In August 2015, CINGSA entered into a stipulation with most of its customers regarding the disposition of the found gas. Hearings before the RCA were held in September 2015. On December 4, 2015, the RCA issued an order that denied the stipulation, allowed CINGSA to sell up to 2 Bcf of the gas and required that approximately 87 percent of the net proceeds of any such sale be allocated to CINGSA’s firm customers. On January 4, 2016, CINGSA appealed the RCA decision to the Superior Court of Alaska. On August 17, 2017, the Alaska superior court issued a decision upholding each facet of the RCA’s decision. CINGSA did not exercise its right to appeal the superior court’s decision to the Alaska Supreme Court; the RCA’s decision and allocation of proceeds stands.

 

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 by June 30, 2017, which was subsequently extended by stipulation to August 31, 2017. In May 2017, the RCA granted the unopposed motion filed by CINGSA to extend the filing of CINGSA’s next rate case to April 30, 2018, based on a 2017 test year.

 

51

 

Environmental Considerations Impacting the Utilities Business

 

AUI

 

AUI is subject to the Climate Leadership Act (Alberta) as discussed under the heading “Business of the Corporation — Gas Business — Environmental Regulations Impacting the Gas Business”. However, compliance costs are recovered through customer billings.

 

PNG

 

PNG is subject to the Carbon Tax Act in British Columbia as described under the section “Environmental Regulation — Climate Change”. The carbon tax gets recovered through customer billings.

 

SEMCO Gas

 

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

 

As of December 31, 2017, SEMCO Gas has completed the investigation and remediation at the two MGP sites it was responsible for and has received NFA letters from the Michigan Department of Environmental Quality for both sites. SEMCO Gas will continue to monitor these sites in the future as required by the NFA letters. 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.

 

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.

 

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.

 

52

 

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, 2017, the revenue for the Corporate segment was $3 million excluding intersegment eliminations and unrealized losses on risk management contracts (2016 – $12 million) and as at December 31, 2017, AltaGas held approximately 3 percent of the common shares of Alterra Power Corp. (Alterra) and approximately 4 percent of the common shares of Painted Pony through the Corporate segment. On February 6, 2018, Innergex Renewable Energy Inc. (Innergex) acquired Alterra. As consideration per Alterra common share, AltaGas received approximately 37.8 percent in cash and approximately 62.2 percent in Innergex common share.

 

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, 2017, AltaGas had 175,279,216 outstanding Common Shares, 5,511,220 outstanding Series A Shares, 2,488,780 outstanding Series B Shares, 8,000,000 outstanding Series C Shares, 8,000,000 outstanding Series E Shares, 8,000,000 outstanding Series G Shares, 8,000,000 outstanding Series I Shares, and 12,000,000 outstanding Series K Shares. On February 3, 2017, AltaGas issued 80,710,000 Subscription Receipts pursuant to the Offering and Concurrent Private Placement. On March 3, 2017, the over-allotment option granted to the underwriters was partially exercised for an additional issuance of 3,800,000 Subscription Receipts. Such Subscription Receipts will be automatically exchanged for Common Shares upon the closing of the WGL Acquisition as more particularly described below under “Subscription Receipts”.

 

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.

 

53

 

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 Shares
    	
 
    
	
Series B   Shares (6)
    	
 
    	
Floating
    	
(6)
    	
Floating
    	
(6)
    	
$
    	
25
    	
 
    	
September 30, 2020
    	
(7)
    	
Series A Shares
    	
 
    
	
Series C   Shares (8)
    	
 
    	
5.29
    	
%
    	
US$
    	
1.3225
    	
 
    	
US$
    	
25
    	
 
    	
September 30, 2022
    	
 
    	
Series D Shares
    	
 
    
	
Series E   Shares (5)
    	
 
    	
5.00
    	
%
    	
$
    	
1.25
    	
 
    	
$
    	
25
    	
 
    	
December 31, 2018
    	
 
    	
Series F Shares
    	
 
    
	
Series G   Shares (5)
    	
 
    	
4.75
    	
%
    	
$
    	
1.1875
    	
 
    	
$
    	
25
    	
 
    	
September 30, 2019
    	
 
    	
Series H Shares
    	
 
    
	
Series I   Shares (9)
    	
 
    	
5.25
    	
%
    	
$
    	
1.3125
    	
 
    	
$
    	
25
    	
 
    	
December 31, 2020
    	
 
    	
Series J Shares
    	
 
    
	
Series K   Shares (10)
    	
 
    	
5.00
    	
%
    	
$
    	
1.25
    	
 
    	
$
    	
25
    	
 
    	
March 31, 2022
    	
 
    	
Series L Shares
    	
 
    
																

 

Notes:

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

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

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

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

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

(6)         Holders of Series B Shares will be entitled to receive cumulative quarterly floating dividends, which will reset each quarter thereafter at a rate equal to the sum of the then 90-day government of Canada Treasury Bill rate plus 2.66 percent. Each quarterly dividend is calculated as the annualized amount multiplied by the number of days in the quarter, divided by the number of days in the year. Commencing December 31, 2017, the floating quarterly dividend rate for Series B Shares is $0.21760 per share for the period starting December 31, 2017 to, but excluding, March 31, 2018.

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

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

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

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

 

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

 

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

 

54

 

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

 

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

 

Medium Term Notes

 

AltaGas has issued senior unsecured notes in the form of MTNs. On October 4, 2017, AltaGas issued an aggregate of $450 million of MTNs consisting of $200 million of MTNs with a coupon rate of 3.98 percent maturing on October 4, 2027, and $250 million of MTNs with a coupon rate of 4.99 percent maturing on October 4, 2047. Details with respect to the issued and outstanding MTNs can be found in Note 14 to AltaGas’ consolidated financial statements as at and for the year ended December 31, 2017 filed on SEDAR at www.sedar.com. The MTNs are not listed or quoted on any exchange.

 

Subscription Receipts

 

On February 3, 2017, AltaGas closed both: (a) a public offering of 67,800,000 Subscription Receipts, on a bought deal basis, at an issue price of $31.00 per Subscription Receipt, for total gross proceeds of approximately $2.1 billion (the Offering); and (b) a private placement of 12,910,000 Subscription Receipts at an issue price of $31.00 per Subscription Receipt, for total gross proceeds of $392 million (after deducting a capital commitment fee) (the Concurrent Private Placement). On March 3, 2017, AltaGas closed the partially exercised over-allotment option for an additional issuance of 3,800,000 Subscription Receipts, at an issue price of $31.00 per Subscription Receipt, for total gross proceeds of approximately $118 million (the Over-allotment Option). The Subscription Receipts entitle the holders thereof to receive, without payment of additional consideration or further action, one common share of AltaGas upon the closing of the WGL Acquisition. See “General Development of AltaGas’ Business — Recent Developments” for details on the WGL Acquisition.

 

The Proceeds are being held in escrow until the earlier of the delivery of the Escrow Release Notice and Direction and the Termination Time by Computershare Trust Company of Canada, as subscription receipt agent, together with accrued interest thereon, and deposited or invested, as the case may be, in accordance with the Subscription Receipt Agreement provided that Dividend Equivalent Payments may be made therefrom.

 

While the Subscription Receipts remain outstanding, holders thereof will be entitled to receive payments per Subscription Receipt equal to the per Common Share cash dividends, if any, declared by AltaGas on the Common Shares in respect of all record dates for such dividends occurring from February 3, 2017 to, but excluding, the last day on which the Subscription Receipts remain outstanding; to be paid to holders of Subscription Receipts concurrently with the payment date of each such dividend on the Corporation’s outstanding Common Shares; such dividends will be paid first out of any interest credited or received on the Escrowed Funds and then as a refund of a portion of the offering price, net of any applicable withholding taxes (any such payment, a Dividend Equivalent Payment). The record date for each Dividend Equivalent Payment will be the same as the record date for dividends declared on the Common Shares.

 

55

 

In the event that the Termination Time occurs after a dividend has been declared on the Common Shares but before the record date for such dividend, holders of Subscription Receipts will receive, as part of the Termination Payment, a pro rata Dividend Equivalent Payment in respect of such dividend declared on the Common Shares based on the ratio of the time between (i) the date of the prior Dividend Equivalent Payment (or, if none, February 3, 2017) and the Termination Time, to (ii) the date of the prior Dividend Equivalent Payment (or, if none, the prior payment date for dividends on the Common Shares) and the dividend payment date for the dividend so declared. If the Termination Time occurs on a record date or following a record date but on or prior to the payment date, holders will be entitled to receive the full Dividend Equivalent Payment.

 

GENERAL

 

EMPLOYEES

 

At December 31, 2017 there were 1,629 individuals employed by AltaGas.

 

	
Gas
    	
 
    	
294
    	
 
    
	
Power
    	
 
    	
114
    	
 
    
	
Utilities
    	
 
    	
1,001
    	
 
    
	
Corporate
    	
 
    	
220
    	
 
    
	
Total
    	
 
    	
1,629
    	
 
    

 

DIRECTORS AND OFFICERS

 

As at February 23, 2018: (i) the directors and executive officers of AltaGas Ltd., as a group, owned beneficially, directly or indirectly, or exercised control or direction over 1,764,275 of the outstanding Common Shares, or approximately 0.99 percent of the outstanding Common Shares; (ii) the directors and executive officers have been granted, and have not yet exercised, Share Options to acquire an aggregate of 1,962,750 Common Shares; and (iii) 176,918,328 Common Shares were issued and outstanding.

 

Directors

 

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

 

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

 

The following table sets forth the names of the Directors of AltaGas Ltd. on February 23, 2018, their municipalities of residence and their principal occupations within the last five years.

 

	
Name of Director,
   Municipality of
   Residence and Position
    	
 
    	
Principal Occupation During the Past Five
   Years
    	
 
    	
Director Since
    
	
Catherine M. Best (1)
    Calgary, Alberta, Canada
   Director
    	
 
    	
Ms. Best is an independent businesswoman.   Ms. Best was the Executive Vice-President, Risk Management and Chief   Financial Officer of the Calgary Health Region from 2000 to March 2009.   Before joining the Calgary Health Region she was with Ernst & Young   in Calgary for nineteen years, the last ten as Corporate Audit Partner.
    	
 
    	
November 30, 2011
    

 

56

 

	
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 the Community Service Learning   (CSL) Facilitator for Mount Royal University (MRU) in Calgary, and a   Professor of Entrepreneurship and International Business at the Bissett   School of Business at MRU, where she has taught since 1988. She has consulted   for more than 30 years, and published extensively regarding community   engagement. Research interests included developing strategies for   institutional and community partnerships, Global Service Learning, and   structuring CSL for optimal stakeholder impact.
    	
 
    	
November 1, 2015
    
	
David W. Cornhill (2)
    Calgary, Alberta, Canada
   Chairman of the Board
    	
 
    	
Mr. Cornhill is Chairman of the Board of   Directors of AltaGas, a position he has held since inception of AltaGas   Services (AltaGas’ predecessor) on April 1, 1994. Mr. Cornhill is a   founding shareholder and was Chief Executive Officer from April 1, 1994   to April 15, 2016. Prior to forming AltaGas Services, Mr. Cornhill   served in the capacities of Vice President, Finance and Administration, and   Treasurer at Alberta and Southern Gas Co. Ltd. from 1991 to 1993 and as   President and Chief Executive Officer until March 31, 1994.
    	
 
    	
Director of AltaGas (and its predecessors) since   April 1, 1994
    
	
Allan L. Edgeworth (1)
    Calgary, Alberta, Canada
   Director
    	
 
    	
Mr. Edgeworth is a professional engineer and an   independent businessman. He was the President of ALE Energy Inc., a private   consulting company, from January 2005 through December 2015.   Mr. Edgeworth was the President and Chief Executive Officer of Alliance   Pipeline Ltd. from 2001 until December 2004. Mr. Edgeworth joined   Alliance Pipeline Ltd. in 1998 as Executive Vice President and Chief   Operating Officer.
    	
 
    	
Director of AltaGas (and its predecessors) since   March 2, 2005
    
	
Daryl H. Gilbert (1)(3)
    Calgary, Alberta, Canada
   Director
    	
 
    	
Mr. Gilbert is a Professional Engineer and   joined JOG Capital Inc. in May 2008 as a Managing Director and   Investment Committee Member. Prior thereto, Mr. Gilbert was an   Independent businessman since January 2005. Prior to that,   Mr. Gilbert was President and Chief Executive Officer of Gilbert   Laustsen Jung Associates Ltd. (now GLJ Petroleum Consultants Ltd.), an   independent engineering consulting firm.
    	
 
    	
Director of AltaGas (and its predecessors) since   May 4, 2000
    
	
David M. Harris (6)
   Calgary, Alberta, Canada
   Director
    	
 
    	
Mr. Harris is a Professional Engineer and has   been the President and Chief Executive Officer of AltaGas since   April 16, 2016. Mr. Harris joined AltaGas in October 2010 and   has held several positions within AltaGas including Chief Operating Officer,   President Gas and Power, and Vice President Major Projects Power. Prior   thereto, Mr. Harris had 20 years of construction, engineering,   operations and management experience in the international energy sector.   Prior to working in the private sector, Mr. Harris held the rank of   Commander in the United States Navy.
    	
 
    	
April 26, 2017
    

 

57

 

	
Name of Director,
   Municipality of
   Residence and Position
    	
 
    	
Principal Occupation During the Past Five
   Years
    	
 
    	
Director Since
    
	
Robert B. Hodgins (1)(4)
    Calgary, Alberta, Canada
   Director
    	
 
    	
Mr. Hodgins is a Chartered Accountant and has   been an Independent businessman since November 2004. Prior to that,   Mr. Hodgins served as the Chief Financial Officer of Pengrowth Energy   Trust (now Pengrowth Corporation) from 2002 to 2004. Prior to that, Mr. Hodgins   held the position of Vice President and Treasurer of Canadian Pacific Limited   1998 to 2002 and was Chief Financial Officer of TransCanada PipeLines Limited   from 1993 to 1998.
    	
 
    	
Director of AltaGas (and its predecessors) since   March 2, 2005
    
	
Phillip R. Knoll (1)
    Halifax, Nova Scotia, Canada
   Director
    	
 
    	
Mr. Knoll is a Professional Engineer and the   President of Knoll Energy Inc. Mr. Knoll previously was CEO of Corridor   Resources Inc. from October 2010 to September 2014. Up to   July 2004 he held roles that included Group Vice President, Duke Energy   Gas Transmission, Chair, Management Committee and President for   Maritimes & Northeast Pipeline, and held senior roles at Westcoast   Energy Inc., TransCanada Pipelines Limited and Alberta Natural Gas Company   Ltd.
    	
 
    	
November 1, 2015
    
	
M. Neil McCrank (1)(5)
    Calgary, Alberta, Canada
   Director
    	
 
    	
Mr. McCrank is Senior Counsel to the Calgary   office of Borden Ladner Gervais LLP. Mr. McCrank was Chairman of the   Alberta Energy and Utilities Board from 1998 until 2007. Prior thereto,   Mr. McCrank was with the Alberta Department of Justice, serving in   various capacities, including Deputy Minister of Justice from 1989 to 1998.
    	
 
    	
Director of AltaGas (and its predecessors) since   December 10, 2007
    

 

Notes:

(1)         Independent director.

(2)         Mr. Cornhill as former CEO until April 15, 2016 is not considered to be an independent director.

(3)         Mr. Gilbert was a director of Globel Direct, Inc. (Globel), a public business outsource company, from December 1998 to June 2009. In June 2007, Globel was granted protection from its creditors by the Court of Queen’s Bench of Alberta pursuant to the CCAA. After a failed restructuring effort, Globel was placed in receivership in December of 2007 and the receiver was ultimately discharged in September 2008. Globel ceased operations, and as a result became the subject of cease trade orders issued by both ASC and the BCSC in September 2008 for failure to file certain disclosure documents. Globel was struck from the Alberta corporate registry on June 2, 2009. Mr. Gilbert was also 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 has been a director of Connacher Oil and Gas Limited (Connacher) since October 2014. On May 17, 2016, Connacher applied for and was granted protection from its creditors pursuant to a Stay of Proceedings Order from the Court of Queen’s Bench of Alberta under the CCAA, which Order has been further extended to June 29, 2018, allowing Connacher to continue to pursue and implement appropriate CCAA exit strategies. On May 20, 2016, the TSX delisted the common shares of Connacher for failure to meet continued listing requirements.

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

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

(6)         Mr. Harris as current President and CEO is not considered to be an independent director.

 

58

 

AltaGas has four standing committees of the Board of Directors: (1) Audit, (2) Governance, (3) Human Resources and Compensation (HRC) and (4) EOH&S. The members of each of these committees, as of December 31, 2017, are identified below:

 

	
Director
    	
 
    	
Audit Committee
    	
 
    	
Governance
   Committee
    	
 
    	
HRC Committee
    	
 
    	
EOH&S Committee
    
	
Catherine M. Best
    	
 
    	
ü
    	
 
    	
 
    	
 
    	
ü
    	
 
    	
 
    
	
Victoria A. Calvert(2)
    	
 
    	
 
    	
 
    	
ü
    	
 
    	
 
    	
 
    	
ü
    
	
David W. Cornhill
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Allan L. Edgeworth
    	
 
    	
ü
    	
 
    	
 
    	
 
    	
 
    	
 
    	
Chair
    
	
Daryl H. Gilbert
    	
 
    	
 
    	
 
    	
 
    	
 
    	
Chair
    	
 
    	
ü
    
	
Robert B. Hodgins
    	
 
    	
Chair
    	
 
    	
ü
    	
 
    	
 
    	
 
    	
 
    
	
Phillip R. Knoll(1)
    	
 
    	
ü
    	
 
    	
 
    	
 
    	
 
    	
 
    	
ü
    
	
M. Neil McCrank(2)
    	
 
    	
 
    	
 
    	
Chair
    	
 
    	
ü
    	
 
    	
 
    

 

Notes:

(1)                   Mr. Knoll was appointed to the Audit Committee effective January 1, 2017.

(2)                   With the passing of Mr. David Mackie on August 14, 2017, the Governance Committee considered and recommended changes to the composition of the committees. As a result, effective as of August 17, 2017, Mr. McCrank was appointed to the HRC Committee and removed from the EOH&S Committee and Ms. Calvert was appointed to the EOH&S Committee.

 

EXECUTIVE OFFICERS

 

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

 

	
Name of Officer, Municipality of Residence and
   Position with AltaGas Ltd.
    	
 
    	
Principal Occupation During the Past Five Years
    
	
David M. Harris
    Calgary, Alberta, Canada
   President and Chief Executive Officer
   Director
    	
 
    	
President and Chief Executive Officer of AltaGas   from April 16, 2016. President and Chief Operating Officer of AltaGas   from January 2015 to April 15, 2016. Chief Operating Officer of   AltaGas from August 2013 to December 2014. President Gas and Power   of AltaGas from December 2012 to August 2013. President Power of   AltaGas from May 2011 to December 2012. Vice President Major   Projects Power of AltaGas from October 2010 to May 2011. General   Manager Forrest Kerr of AltaGas from June 2010 to October 2010.   Prior thereto President and Chief Operating Officer of MW Power Corp. from   March 2009 to June 2010 and Senior Vice President of Engineering,   Procurement and Construction of NRG Energy Inc. from November 2006 to   March 2009.
    
	
Timothy W. Watson
    Calgary, Alberta, Canada
   Executive Vice President
   and Chief Financial Officer
    	
 
    	
Executive Vice President and Chief Financial Officer   of AltaGas from November 2015. Executive Vice President of AltaGas from   March 2015 to October 2015. Head and Managing Director, Canadian   Energy and Power Investment Banking at Merrill Lynch Canada Inc. from   September 2010 to January 2015. Managing Director in Energy   Investment Banking at CIBC World Markets in Calgary from February 2007   to July 2010. Managing Director in Energy Investment Banking with RBC   Capital Markets in Calgary, Houston and San Francisco from 2001 to   January 2007, and prior to that, various investment banking positions   with RBC Capital Markets in Toronto and Calgary from 1990 to 2000.
    
	
John E. Lowe
    Calgary, Alberta, Canada
   Executive Vice President
    	
 
    	
Executive Vice President of AltaGas from   January 2015. Executive Vice President Corporate Development of AltaGas   from December 2012 to December 2014. President AltaGas Utility   Group Inc. from October 2011 to December 2012. Partner with the law   firm of Burnet, Duckworth and Palmer LLP from September 2005 to   October 2011.
    

 

59

 

	
Name of Officer, Municipality of Residence and
   Position with AltaGas Ltd.
    	
 
    	
Principal Occupation During the Past Five Years
    
	
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.
    
	
Randy W. Toone
    Calgary, Alberta, Canada
   Executive Vice President Gas
    	
 
    	
Executive Vice President Gas from June 2017.   Executive Vice President, Commercial and Business Development of AltaGas 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. President   Utilities of AltaGas from December 2012 to April 2013. President   Gas of AltaGas February 2012 to December 2012. Co-President Gas of   AltaGas from December 2010 to January 2012.
    
	
Bradley B. Grant
    Calgary, Alberta, Canada
   Vice President and General Counsel
    	
 
    	
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. Associate with the law firm of Stikeman   Elliott LLP from July 1997 to December 2003. Student-at-Law with   the law firm of Stikeman Elliott LLP from June 1996 to July 1997.
    
	
John D. O’Brien Jr.
    Dallas, Texas, U.S.
   President AltaGas Services (U.S.) Inc. and President Utilities
    	
 
    	
President AltaGas Services (U.S.) Inc. (ASUS) and   President Utilities from June 12, 2017, President and Chief Operating   Officer of ASUS from April 16, 2016 to June 12, 2017. President of   ASUS from May 1, 2015 to April 15, 2016. Executive Vice President,   Public Policy and External Affairs of Energy Future Holdings from   October 2011 to April 2015. Senior Vice President, Government and   Regulatory Affairs of NRG Energy from March 2007 to September 2011.
    

 

AUDIT COMMITTEE

 

Composition of the Audit Committee

 

The Committee is currently comprised of four members, Catherine M. Best, Allan L. Edgeworth, Robert B. Hodgins and Phillip R. Knoll. Mr. Hodgins is the chair of the Committee. All of the members of the Committee are independent and financially literate as defined under Canadian securities law.

 

Relevant Education and Experience

 

Ms. Best was the Executive Vice-President, Risk Management and Chief Financial Officer of the Calgary Health Region from 2000 to March 2009. Before joining the Calgary Health Region she was with Ernst & Young LLP in Calgary for nineteen years, the last ten as Corporate Audit Partner.

 

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

 

Mr. Hodgins has been an independent businessman since November 2004. Prior to that, Mr. Hodgins was Chief Financial Officer at Pengrowth Energy Trust (now Pengrowth Corporation) from 2002 to 2004. Mr. Hodgins was Vice President and Treasurer at Canadian Pacific Limited from 1998 to 2002 and Chief Financial Officer of TransCanada PipeLines Limited from 1993 to 1998. Mr. Hodgins has an Honours Degree in Business from the Richard Ivey School of Business at the University of Western Ontario, is a Chartered Professional Accountant, and is a Chartered Accountant in Ontario and Alberta.

 

60

 

Mr. Knoll is a Professional Engineer and the President of Knoll Energy Inc. Mr. Knoll previously was CEO of Corridor Resources Inc. from October 2010 to September 2014. Up to July 2004 he held roles that included Group Vice President, Duke Energy Gas Transmission, Chair, Management Committee and President for Maritimes & Northeast Pipeline, and held senior roles at Westcoast Energy Inc., TransCanada Pipelines Limited and Alberta Natural Gas Company Ltd. Mr. Knoll was a director, and Audit Committee member, of AltaGas Utility Group Inc. from 2005 to 2009.

 

Pre-Approval Policies and Procedures

 

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

 

External Auditor Service Fees by Category

 

The fees billed by Ernst & Young LLP (E&Y), AltaGas’ external auditors, during 2017 and 2016 were as follows:

 

	
Category of External Auditor Service Fee
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Audit Fees
    	
 
    	
$
    	
2,452,645
    	
 
    	
$
    	
2,140,368
    	
 
    
	
Audit-Related   Fees(1)
    	
 
    	
381,383
    	
 
    	
293,701
    	
 
    
	
Tax Fees(2)
    	
 
    	
44,404
    	
 
    	
66,595
    	
 
    
	
All Other Fees(3)
    	
 
    	
206,387
    	
 
    	
118,190
    	
 
    
	
Total
    	
 
    	
$
    	
3,084,819
    	
 
    	
$
    	
2,618,854
    	
 
    

 

Notes:

(1)         Represent the aggregate fees billed by E&Y for assurance and related services that were reasonably related to the performance of the audit or review of AltaGas’ financial statements and were not reported under “Audit Fees”. During 2017 and 2016, the nature of the services provided included review of prospectuses and security filings, research of accounting and audit-related issues, internal controls assessment, and registration costs for the Canadian Public Accountability Board.

(2)         Represent the aggregate fees billed by E&Y for professional services for tax compliance, tax advice and tax planning. During 2017 and 2016, the nature of the services provided was for tax advice and transfer pricing.

(3)         Represent the aggregate fees billed by E&Y for products and services, other than those reported with respect to the other categories of service fees. During 2017 and 2016, the nature of the services provided was for translation services.

 

RISK FACTORS

 

Set forth below is a summary of certain risk factors relating to AltaGas and the business of AltaGas. Also included below is a summary of certain risks relating to the WGL Acquisition and the business of WGL following closing of the WGL Acquisition. 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.

 

RISKS RELATED TO THE BUSINESS OF ALTAGAS

 

Capital Markets

 

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.

 

61

 

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.

 

Market Value of Common Shares and Other Securities

 

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

 

Variability of Dividends

 

The declaration and payment of dividends on common shares by AltaGas are at the discretion of the Board of Directors. The cash available for dividends to Shareholders is a function of numerous factors, including, without limitation, AltaGas’ financial performance, the impact of interest rates, electricity prices, natural gas, NGL, LNG and LPG prices, debt covenants and obligations, working capital requirements 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.

 

Debt Service

 

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

 

Refinancing Risk

 

Each of AltaGas’ credit facilities has a maturity date, on which date, absent replacement, extension or renewal, the indebtedness under the respective credit facility becomes repayable in its entirety. To the extent any of the credit facilities are not replaced or extended on or before their respective maturity dates or are not replaced, extended or renewed for the same, similar or higher amounts or on the same, similar or better terms, AltaGas’ ability to fund ongoing operations and pay dividends could be impaired.

 

62

 

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, particularly a downgrade below investment grade ratings, or a negative change in AltaGas’ ratings outlook could adversely affect AltaGas’ cost of financing and its access to sources of liquidity and capital. Credit ratings are intended to provide investors with an independent measure of credit quality of any issuer of securities. The credit ratings assigned to AltaGas’ securities by the rating agencies are not recommendations to purchase, hold or sell the securities in as much as such ratings do not comment as to market price or suitability for a particular investor. Any rating may not remain in effect for any given period of time or may be revised or withdrawn entirely by a rating agency in the future if in its judgment circumstances so warrant.

 

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.

 

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. 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.

 

Volume Throughput

 

AltaGas’ businesses process, transport and store natural gas, ethane, NGLs and other commodities. Throughput within the business is dependent on a number of factors, including the level of exploration and development activity within the WCSB, the long-term supply and demand dynamics for the applicable commodities and the regulatory environment for market participants. These factors may result in AltaGas being unable to maintain throughput. 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 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 contract and, accordingly, could have a material adverse effect on AltaGas’ business, financial conditions and cash flow.

 

Litigation

 

In the course of its business, AltaGas is subject to lawsuits and other claims. Defence 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.

 

External Stakeholder Relations

 

AltaGas places great importance on establishing and maintaining positive relationships with its stakeholders, including, without limitation, within the communities in which AltaGas operates, local Aboriginal groups and regulators. There is an increasing level of public concern relating to the perceived effect of natural resources activities, including, without limitation, exploration, development, production, processing and transportation, on certain environmental and social

 

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aspects such as air and water quality, noise, dust, land and ecological disturbance and employment and economic development opportunities. Opposition to natural resources activities by communities or Aboriginal groups may ultimately impact AltaGas, including its ability to obtain or maintain permits, its operations, and its reputation. Publicity adverse to AltaGas’ operations, AltaGas’ partners, or others operating in the energy industry generally, could have an adverse effect on AltaGas and its operations. While AltaGas is committed to operating in a socially responsible manner, there can be no assurance that its efforts in this respect will mitigate this potential risk.

 

Composition Risk

 

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

 

Electricity and Resource Adequacy Prices

 

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

 

Counterparty and 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 long-term contracts including PPAs, EPAs and take-or-pay agreements and to numerous industrial and C&I counterparties. 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.

 

Cyber Security, Information, and Control Systems

 

AltaGas’ business processes are increasingly reliant upon information systems automation provided by infrastructure, technologies and data. A failure of these information systems could lead to the impairment of business processes, and there is a risk of cascading failure of information systems leading to the impairment of multiple business processes. The risk of cyber-attack targeting information systems is increasing, with strong evidence of the industry being specifically targeted.

 

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 operational outages, delays, damage to assets, the environment or to AltaGas’ reputation, diminished customer confidence, lost profits, lost data (including confidential information), 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.

 

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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.

 

Foreign Exchange Risk

 

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

 

Collateral

 

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

 

Changes in Laws

 

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

 

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 impacts of the recent changes to the U.S. tax laws are still being assessed by AltaGas but may have adverse impacts on the effective tax rates for part or all of AltaGas’ U.S. businesses.

 

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 or that of Petrogas. Changes in the regulatory environment may be beyond AltaGas’ control and may significantly affect AltaGas’ businesses, results of operations and financial conditions. Pipelines and facilities can be subject to common carrier and common processor applications and to rate setting by the regulatory authorities in the event an agreement on fees or tariffs cannot be reached with producers. The export and import of energy is also subject to regulatory approvals. Power facilities are subject to regulatory approvals and regulatory changes in tariffs, market structure and penalties. AUI, PNG, Heritage Gas, SEMCO Gas, ENSTAR and CINGSA operate in regulated marketplaces where regulatory approval is required for the regulated returns that provide for recovery of costs and a return on capital and may limit the ability to make and implement independent management decisions, including, without limitation, setting rates charged to customers, determining methods of cost recovery and issuing debt. Earnings of AltaGas’ regulated utilities may be impacted by a number of factors, including, without limitation, (i) changes in the regulator-approved allowed return on equity and common equity component of capital structure; (ii) changes in rate base; (iii) changes in gas delivery volumes; (iv) changes in the number and composition of customers; (v) variances between actual expenses incurred and forecast expenses used to determine revenue requirements and set customer rates; and (vi) recovery of unplanned costs through rate cases.

 

Climate Change and Carbon Tax

 

Some of AltaGas’ significant facilities may be subject to future provincial or federal climate change regulations or both to manage greenhouse gas emissions. See sections “Environmental Regulation”, “Business of the Corporation — Gas Business — Environmental Regulations Impacting the Gas Business”, “Business of the Corporation — Power — Business - Environmental Regulations Impacting the Power Business”, and “Business of the Corporation — Utilities Business —

 

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Environmental Regulations Impacting the Utilities 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 or limit the operations of, or increase the costs faced by producers. In addition, concerns about climate change have resulted in a number of environmental activists and members of the public opposing the continued exploitation, development and transportation of fossil fuels. Given the evolving nature of the debate related to climate change and the control of greenhouse gas emissions and resulting requirements, it is difficult to predict the impact on AltaGas and its operations and financial condition.

 

Aboriginal Land and Rights Claims

 

Aboriginal 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 projects and power development and generation in Alberta and 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 Aboriginal communities and other agreements are in development. These agreements support an approach of active engagement with Aboriginal 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 Aboriginal groups in its operations where feasible and reasonable. The agreements and the measures taken by AltaGas strengthen relationships between the parties while respecting the ever evolving regulatory and judicial relationship between Canada’s governments and Aboriginal people. However, AltaGas cannot predict whether future Aboriginal 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 Aboriginal group could have a material adverse effect on AltaGas’ business, financial condition and results of operations.

 

Crown Duty to Consult with Aboriginal Peoples

 

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

 

Underinsured and Uninsured Losses

 

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

 

Weather and Long Term Wind or Hydrology Data

 

AltaGas’ run-of-river hydroelectric power projects may be subject to significant variations in the river flow necessary for power generation. AltaGas relies on hydrological studies and data to confirm that sufficient water flow is available to generate sufficient electricity to determine the economic viability of its projects. There can be no assurance that the long-term historical water availability will remain unchanged or that no material hydrologic event will impact the hydrologic conditions that exist within the watersheds. Annual and seasonal deviations from the long-term average can be significant. AltaGas pays rent for its water rights. Significant increases in rental costs in the future or changes in the way water rights are granted could have a material adverse effect on AltaGas’ business, operating results, financial condition or prospects.

 

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AltaGas’ wind power projects may be subject to significant variations in wind which could affect the amount of power generated. AltaGas relies on wind studies and data to confirm that sufficient wind flows are available to generate sufficient electricity to determine the economic viability of its projects. Ice can accumulate on wind turbine blades in the winter months. Extreme cold temperatures and the accumulation of ice on wind turbine blades, caused by a number of factors, including temperature, ambient humidity and wind, can impact the ability of wind turbines to operate effectively and could result in the wind turbine experiencing more down-time potentially reducing the life expectancy of the wind turbine and generation revenue. There can be no assurance that the long-term historical wind patterns will remain unchanged. Annual and seasonal deviations from the long-term average can be significant.

 

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.

 

Service Interruptions

 

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

 

Rep Agreements

 

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

 

Cook Inlet Gas Supply

 

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

 

Biomass Supply Risk

 

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

 

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

 

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environment, land use, health, culture, conflicts of interest with other parties and other matters beyond the direct control of AltaGas.

 

Health and Safety

 

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

 

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

 

Safety has been and continues to be a core value of AltaGas and is integral to how AltaGas operates. AltaGas actively works with industry groups and communities within which it operates to improve safety and 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. However, no assurances can be given that the occurrence of any of these 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, sabotage, terrorism, failure of supply, weather, wind or water resource deviation, catastrophic events and natural disasters, fires, floods, explosions, earthquakes and other similar events. Unplanned outages or prolonged downtime for maintenance and repair 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. 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 older vintage 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 AltaGas’ utility business. Although the cost 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.

 

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. AltaGas has entered into various types of arrangements with joint venture partners for any or all of the construction, operation or ownership of certain facilities. Certain of these partners may have or develop interests or

 

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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, Aboriginal groups and municipalities. Any unforeseen delays in this process may negatively impact the ability of AltaGas to complete any given facility on time or at all.

 

Decommissioning, Abandonment and Reclamation Costs

 

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

 

Labour Relations

 

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

 

Key Personnel

 

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

 

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.

 

RISKS RELATED TO THE ACQUISITION OF WGL

 

Possible Failure to Realize Anticipated Benefits of the Acquisition of WGL

 

A variety of factors, including, without limitation, those risk factors set forth herein, may adversely affect the ability to achieve the anticipated benefits of the WGL Acquisition.

 

Increased Indebtedness

 

If the WGL Acquisition is completed on the terms contemplated in the Merger Agreement, AltaGas anticipates incurring additional debt, including as a result of borrowings under the Bridge Facility, in order to complete the Merger Agreement on the terms contemplated therein. Such borrowings are anticipated to represent a material increase in AltaGas’ consolidated indebtedness. Such additional indebtedness will increase AltaGas’ interest expense and debt service obligations and may have a negative effect on AltaGas’ results of operations or credit ratings. The increased indebtedness will also make AltaGas’ results more sensitive to increases in interest rates.

 

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Availability of Alternative Sources of Funding

 

It is currently contemplated that a portion of the Bridge Facility will be further reduced or repaid from the cash proceeds of asset sales and the net proceeds of future senior debt, hybrid security, and equity-linked security (including any Preferred Shares) financings completed for the purpose of funding the WGL Acquisition. There can be no assurance that AltaGas may be able to effect any of these actions on satisfactory terms, or at all. The inability to access such alternate sources of funding to reduce or repay the Bridge Facility may negatively impact the financial performance of AltaGas, including, without limitation, the extent to which the WGL Acquisition is accretive.

 

Borrowings under the Bridge Facility is Subject to Various Conditions

 

AltaGas’ ability to borrow under the Bridge Facility is subject to certain customary conditions that AltaGas must satisfy. If AltaGas is unable to satisfy one or more of those conditions and such conditions are not waived, AltaGas will not be able to borrow amounts under the Bridge Facility to fund the WGL Acquisition. If AltaGas cannot borrow under the Bridge Facility, a financing failure under the Merger Agreement will have occurred and, if AltaGas does not otherwise have the cash to close the WGL Acquisition, WGL will, in certain circumstances, have the right to terminate the Merger Agreement and receive a termination fee. Alternative sources of financing may not be available or if available, may be on terms that are less favourable than the terms of the Bridge Facility.

 

Exchange Rate Risk Related to the Acquisition of WGL

 

As AltaGas anticipates funding a portion of the purchase price of the WGL Acquisition from a combination of Canadian and US dollar denominated securities and credit facilities, and the purchase price of the WGL Acquisition is denominated in US dollars, a significant decline in the value of the Canadian dollar relative to the US dollar at the time of closing of the WGL Acquisition could increase the cost to AltaGas of funding the purchase price of the WGL Acquisition.

 

AltaGas’ consolidated results of operations may be negatively impacted by foreign currency fluctuations. As a result of the WGL Acquisition, a significantly larger portion of AltaGas’ revenues will be earned in US dollars. Accordingly, fluctuations in exchange rates between the Canadian and US dollar may have an increased adverse effect on AltaGas’ results and financial condition. Future events that may significantly increase or decrease the risk of future movement in the exchange rates for these currencies cannot be predicted.

 

Possible Failure to Complete the Acquisition of WGL

 

The WGL Acquisition is subject to normal commercial risk that the WGL Acquisition may not be completed on the terms negotiated or at all. If the WGL Acquisition is not completed prior to the Termination Time, then the Subscription Receipts will be cancelled and the holders of Subscription Receipts will be entitled to receive a refund of their subscription price and any unpaid Dividend Equivalent Payments owing to such holders of Subscription Receipts. The holder of Subscription Receipts would not be entitled to participate in any growth in the trading price of the Common Shares. Further, the holder of Subscription Receipts would be restricted from using the funds devoted to the acquisition of the Subscription Receipts for any other investment opportunities until the Escrowed Funds are returned to the holder of Subscription Receipts. In addition, if closing of the WGL Acquisition does not take place as contemplated, AltaGas could suffer adverse consequences, including, without limitation, the loss of investor confidence. The discovery or quantification of any material liabilities could have a material adverse effect on AltaGas’ business, financial condition or future prospects.

 

Satisfaction of Conditions Precedent to the Acquisition of WGL

 

The completion of the WGL Acquisition is subject to a number of conditions precedent, certain of which are outside the control of AltaGas or other parties to the Merger Agreement, including obtaining the Regulatory Approvals. There is no certainty, nor can AltaGas provide any assurance, that these conditions will be satisfied or, if satisfied, when they will be satisfied.

 

Pursuant to the Merger Agreement, AltaGas and Merger Sub must use their reasonable best efforts to, among other things, cause the transactions contemplated by the Merger Agreement to be consummated as promptly as reasonably practicable, including, without limitation, taking any and all steps necessary to avoid, eliminate or resolve each and every impediment and obtain all consents under antitrust laws or other applicable laws that may be required by any governmental authority, so as to enable the parties to close the transactions contemplated by the Merger Agreement, including, without limitation, any Remedial Action, provided that AltaGas shall not be required to, in connection with

 

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obtaining any consent of any governmental authority (including, without limitation, the Regulatory Approvals) in connection with the Merger Agreement or the transactions contemplated thereby, offer or accept, or agree, commit to agree or consent to, any undertaking, term, condition, liability, obligation, commitment, sanction or other measure (including any Remedial Action) that constitutes a Burdensome Condition. Further, without the prior written consent of AltaGas (which consent may be withheld, conditioned or delayed at AltaGas’ sole discretion), WGL shall not, and shall not permit any of its subsidiaries to, in connection with obtaining any consent of any governmental authority in connection with the Merger Agreement or the transactions contemplated thereby, offer or accept, or agree, commit to agree or consent to, any undertaking, term, condition, liability, obligation, commitment, sanction or other measure (including any Remedial Action) that constitutes a Burdensome Condition. There can be no assurance that in order to satisfy their obligations under the Merger Agreement that AltaGas and Merger Sub will not be required to undertake a Remedial Action that could have a material effect on the business, operations and assets of WGL or AltaGas without it being considered a Burdensome Condition.

 

Additionally, AltaGas expects that closing of the WGL Acquisition will occur in the mid-2018. However, the Merger Agreement allows the transaction to close as late as July 25, 2018 in certain circumstances and the Merger Agreement could be amended to further extend that date. While during the period prior to closing WGL is to carry on business in the ordinary course, given the potentially long period prior to closing the WGL Acquisition there can be no assurance that the business, operations and assets of WGL may not be adversely affected by intervening events. While it is a condition to closing the WGL Acquisition that WGL not be subject to a material adverse effect, it is possible that the business of WGL could be significantly affected prior to such a condition being breached. During the period prior to closing the WGL Acquisition, AltaGas and Merger Sub will have no right to control or direct the operations of WGL and WGL shall exercise complete unilateral control and supervision over its business operations, subject to the terms of the Merger Agreement and, therefore, AltaGas will indirectly be reliant on the business judgment and decisions of the board and management of WGL prior to closing the WGL Acquisition.

 

Regulatory Risk Related to the Acquisition of WGL

 

The WGL Acquisition is conditional upon, among other things, all waiting periods (and any extensions thereof) applicable to the WGL Acquisition under the HSR Act having expired or been terminated and the receipt of all Regulatory Approvals. A substantial delay in obtaining satisfactory approvals or the imposition of unfavourable terms or conditions in the approvals could have a material adverse effect on AltaGas’ ability to complete the WGL Acquisition and on AltaGas’ or WGL’s business, financial condition or results of operations. In addition, changes in laws or regulations, including, without limitation, tax laws, in the jurisdictions in which AltaGas, WGL and their subsidiaries operate could have a negative effect on their respective businesses, financial condition and results of operations, or on the ability of AltaGas to achieve its anticipated benefits from the WGL Acquisition.

 

Potential Undisclosed Liabilities Associated with the Acquisition of WGL

 

In connection with the WGL Acquisition, there may be liabilities that AltaGas failed to discover or was unable to quantify in its due diligence which it conducted prior to the execution of the Merger Agreement and which could have a material adverse effect on AltaGas’ business, financial condition or future prospects. In addition, AltaGas may be unable to retain existing WGL customers or employees following the WGL Acquisition. Following the closing of the WGL Acquisition, AltaGas will have no right to claim indemnification under the Merger Agreement for any such events.

 

Integration of WGL

 

The ability to realize the anticipated benefits of the WGL Acquisition will depend in part on AltaGas successfully consolidating functions and integrating operations, procedures and personnel in a timely and efficient manner, as well as on the ability of AltaGas to realize the anticipated growth from integrating WGL’s business into AltaGas’ current operations following the WGL Acquisition. To effectively integrate WGL into its current operations, AltaGas must establish appropriate operational, administrative, finance, management systems and controls and marketing functions relating to WGL. This will require substantial attention from AltaGas’ management team. This diversion of management attention, as well as any other difficulties which AltaGas may encounter in completing the transition and integration process, could have an adverse impact on AltaGas’ business, financial condition, results of operations and cash flows. The integration process may result in the loss of key employees and the disruption of ongoing business, customer and employee relationships that may adversely affect the ability of AltaGas to achieve all or some of the anticipated benefits of the WGL Acquisition. There can be no assurance that AltaGas will be successful in integrating WGL’s operations, or that the expected benefits will be realized.

 

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Dividends and Dividend Equivalent Payments

 

The declaration and payment of dividends on Common Shares and accordingly, the Dividend Equivalent Payment, by AltaGas are at the discretion of the Board of Directors. The cash available for dividends 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 and future capital requirements. Following closing of the WGL Acquisition, AltaGas’ ability to pay dividends could be adversely affected if the free cash flow resulting from the WGL Acquisition does not materialize as expected when coupled with the potentially dilutive effect of the additional Common Shares issued in exchange for the Subscription Receipts issued in the Offering and the Concurrent Private Placement. In addition, AltaGas’ ability to pay dividends depends upon the payment of dividends by certain of AltaGas’ subsidiaries or the repayment of funds to AltaGas by its subsidiaries. AltaGas’ subsidiaries, including, without limitation, WGL following the WGL Acquisition, in turn, may be restricted from paying dividends, making repayments or making other distributions to AltaGas for financial, regulatory, legal or other reasons. To the extent AltaGas’ subsidiaries are not able to pay dividends or repay funds to AltaGas, it may adversely affect AltaGas’ ability to pay dividends on Common Shares and accordingly, the Dividend Equivalent Payment.

 

RISKS RELATED TO THE BUSINESS OF WGL

 

The risk factors set forth in this AIF relating to the business and operations of AltaGas that are similar to WGL’s business, including AltaGas’ utility and natural gas distribution business apply equally in respect of similar components of WGL’s business. In addition, certain incremental risks to AltaGas following closing of the WGL Acquisition in relation to WGL’s business are set forth below.

 

Silver Spring, Maryland Incident

 

Washington Gas continues to support the investigation by the NTSB into the August 10, 2016 explosion and fire at an apartment complex on Arliss Street in Silver Spring, Maryland, the cause of which has not been determined. Additional information will be made available by the NTSB at the appropriate time. On November 2, 2016, two civil actions were filed in the District of Columbia Superior Court against WGL and Washington Gas (as well as a property management company that is not affiliated with WGL or Washington Gas), by residents of the apartment complex. In one lawsuit, twenty-nine plaintiffs sought unspecified damages for, among others, wrongful death and personal injury. The other action was a class action suit seeking total damages stated to be less than US$5 million for, among others, property damage and various counts relating to the loss of the use of the premises. Both actions alleged causes of action for negligence, product liability, and declaratory relief. These cases were dismissed on November 16, 2017. Those two actions were re-filed in Maryland on November 27, 2017. Thirty-five civil actions have been filed in the Circuit Court for Montgomery County, Maryland seeking unspecified damages for personal injury and property damage. Washington Gas maintains excess liability insurance coverage from highly-rated insurers, subject to a nominal self-insured retention. Washington Gas believes that this coverage will be sufficient to cover any significant liability to it that may result from this incident. Washington Gas is unable to determine a range of potential losses that are reasonably possible of occurring. Washington Gas was invited by the NTSB to be a party to the investigation and in that capacity continues to work closely with the NTSB to help determine the cause of this incident.

 

WGL’s ability to meet its customers’ requirements may be impaired if contracted supply is not available, if supplies are not delivered in a timely manner, if WGL loses key suppliers or if WGL is not able to obtain additional supplies during significant spikes in demand

 

Washington Gas must acquire adequate natural gas supply and pipeline and storage capacity to meet current and future customers’ annual and seasonal natural gas requirements. Similarly, WGL Energy Services requires adequate natural gas and electric supplies to serve the demands of its customers and WGL Midstream requires adequate natural gas supply and storage and pipeline capacity to meet its delivery obligations to its customers. WGL depends on the ability of natural gas producers, pipeline gatherers, natural gas processors, interstate pipelines, suppliers of electricity and regional electric transmission operators to meet these requirements. If WGL is unable to secure adequate supplies in a timely manner because of a failure of its suppliers to deliver the contracted commodity, capacity or storage, if WGL is unable to secure additional quantities during significant abnormal weather conditions, or if Washington Gas’ or WGL Energy Services’ interruptible customers fail to comply with requests to curtail their gas usage during periods of sustained cold weather, WGL may be unable to meet its customers’ requirements. Such inability could result in defaults under contracts with customers, penalties and financial damage payments, costs relating to procedures to recover from a disruption of service,

 

72

 

the loss of key licenses and operating authorities, and the loss of customers, which could have a material adverse effect on WGL’s financial results.

 

Rules implementing the derivatives transaction provisions of the Dodd-Frank Act could have an adverse impact on WGL’s ability to hedge risks associated with its 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 WGL’s risk management activities. The Dodd-Frank Act requires that most swaps be cleared through a registered clearing facility and that they be traded on a designated exchange or swap execution facility, with certain exceptions for entities that use swaps to hedge or mitigate commercial risk. The Dodd-Frank Act requirements relating to derivative transactions have not been fully implemented by the U.S. Securities and Exchange Commission and the Commodity Futures Trading Commission. When fully implemented, the law and any new regulations could increase the operational and transactional cost of derivatives contracts and affect the number and/or creditworthiness of available counterparties. In addition, WGL may transact with counterparties based in 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 WGL’s derivatives activities.

 

The availability of adequate interstate pipeline transportation capacity and natural gas supply may decrease

 

WGL purchases almost all of its natural gas supply from interstate sources that must then be transported to WGL’s service territory. In particular, while the Marcellus Shale region is rapidly developing as a premier gas formation, the interstate pipeline transportation capacity may limit the availability of gas from Marcellus in the near term. A significant disruption to or reduction in interstate pipeline capacity due to events such as operational failures or disruptions, hurricanes, tornadoes, floods, freeze off of natural gas wells, terrorist or cyber-attacks or other acts of war, or legislative or regulatory actions or requirements, including remediation related to integrity inspections, could reduce WGL’s normal interstate supply of gas, which may affect its ability to serve customer demand and may reduce its earnings.

 

The cost of providing retirement plan benefits to eligible current and former employees is subject to changes in the performance of investments, demographics, and other factors and assumptions. These changes may have a material adverse effect on WGL

 

The cost of providing retirement plan benefits to eligible current and former employees is subject to changes in the market value of WGL’s 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 WGL’s retirement plan liabilities, assets and benefit costs. Additionally, WGL 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.

 

The construction of WGL Midstream’s 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 WGL’s results of operations

 

WGL Midstream’s business plan involves making substantial investments in pipeline construction projects, which are subject to FERC and state agency regulation and approval. These construction projects are also subject to environmental, political and legal uncertainties that are beyond WGL’s control. In addition, the construction and operation of WGL Midstream’s pipeline assets are subject to risks relating to breakdowns or failures of equipment or processes due to pipeline integrity, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages, construction delays or cost overruns, and shortages of or delays in obtaining equipment, material and labor. Because these assets are interconnected with facilities of third parties, the operation of these facilities could also be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties. These events could further delay the in-service date of WGL Midstream’s projects or disrupt operations on these projects, which could have an adverse effect on its financial results.

 

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Returns on WGL’s non-utility subsidiaries’ investments in renewable energy projects are dependent upon regulatory and tax incentives, which may expire or be reduced or modified

 

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

 

Failure of WGL’s service providers, including in connection with the transition of certain outsourcing relationships to new vendors, could negatively impact WGL’s business, results of operations and financial condition

 

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

 

Competition may negatively affect WGL’s non-utility subsidiaries

 

WGL faces strong competition in its non-utility segments. WGL Energy Services 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. WGL Midstream 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. WGL Energy Systems faces many competitors in the commercial energy systems segment, including, for government customers, companies that contract with customers under Energy Savings Performance Contracting (ESPC) and other utilities providing services under Utility Energy Saving Contracts (UESC) and, in the renewable energy and distributed generation market, other developers, tax equity investors, distributed generation asset owner firms and lending institutions. These competitors may have diversified energy platforms with multiple marketing approaches, broader geographic coverage, greater access to credit and other financial resources, or lower cost structures, and may make strategic acquisitions or establish alliances among themselves. There can be no assurances that WGL can compete successfully, and its failure to do so could have an adverse impact on WGL’s results of operations and cash flow.

 

Delays in U.S. federal government budget appropriations may negatively impact WGL Energy Systems’ earnings

 

The Energy Efficiency and Energy Management operations of WGL Energy Systems are sensitive to U.S. federal government agencies’ receipt of funding in a timely manner. A significant portion of WGL Energy Systems 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 WGL Energy Systems’ ability to obtain new contracts, which may negatively impact earnings.

 

ENVIRONMENTAL AND SAFETY POLICIES AND SOCIAL RESPONSIBILITY

 

Values

 

AltaGas operates in a safe, reliable manner and maintains positive relationships with stakeholders in the communities in which it operates, which includes, without limitation, building mutually beneficial working relationships with Aboriginal

 

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peoples and working closely with governments and regulatory agencies to help meet long term project success. AltaGas’ three guiding principles for developing energy infrastructure are: respect the land, share the benefits, and nurture long-term relationships.

 

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

 

Board of Directors

 

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

 

Policies and Procedures

 

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

 

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

 

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

 

ENVIRONMENTAL REGULATION

 

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

 

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

 

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

 

CLIMATE CHANGE

 

Changes in laws and regulations relating to GHG emissions could require AltaGas, in addition to complying with monitoring and reporting requirements applicable to its operations, to do one or more of the following: (i) comply with stricter emissions standards for internal combustion engines; (ii) take additional steps to control transmission and distribution system leaks; (iii) retrofit existing AltaGas 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 — Gas Business — Environmental Regulations Impacting the Gas Business”, “Business of the Corporation — Power — Business - Environmental Regulations Impacting the Power Business”, and “Business of the Corporation — Utilities Business — Environmental Regulations Impacting the Utilities Business” of this AIF.

 

International Climate Change Agreements

 

As a signatory to the United Nations Framework Convention on Climate Change (the UNFCCC) and as a participant to the Copenhagen Agreement (a non-binding agreement created by the UNFCCC), the Government of Canada announced on January 29, 2010 that it will seek a 17 percent reduction in GHG emissions from 2005 levels by 2020. In May 2015, Canada submitted its Intended Nationally Determined Contribution (INDC) to the UNFCCC, ahead of the 2015 United Nations Climate Change Conference, held in Paris (COP 21). As a result, the Government of Canada will pursue an economy wide target to reduce GHG emissions with its INDC of 30 percent below 2005 levels by 2030. The UNFCCC adopted the Paris Agreement on December 12, 2015 and both Canada and the U.S. are signatories. On June 1, 2017, the United States announced its intentions to leave the Paris Agreement, and formally communicated its intent to withdraw to the UN on August 4, 2017. In response to this announced withdrawal at the national level, many U.S. states, regions, and cities are implementing climate change policies and action plans at the regional and local levels. Following the announcement of the United States’ intention to withdraw from the Paris Agreement, the governors of 14 states, including without limitation, California and one territory have joined a bipartisan coalition of state governors committed to reducing GHG emissions consistent with the goals of the Paris Agreement. Pursuant to the terms of the Paris Agreement, the United States cannot formally withdraw until November 4, 2020, and is obligated to maintain its commitments under the Paris Agreement until that time.

 

Canadian Federal Air and GHG Regulations

 

Multi-Sector Air Pollutants Regulations

 

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

 

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

 

AltaGas’ Canadian facilities are currently assessing the impact of the regulation on its operations as it relates to compliance obligations, maintenance requirements, retrofitting of existing engines, and reporting.

 

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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, the federal government plans to introduce new legislation and regulations to implement a carbon pollution pricing system, to be applied in provinces and territories that do not have a carbon pricing system that aligns with the federal benchmark.

 

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

 

·                                          A carbon levy applied to fossil fuels; and

 

·                                          An output based pricing system for industrial facilities that emit above a certain threshold, with an opt-in capability for smaller facilities with emissions below the threshold.

 

The output based pricing system is expected to apply to all industrial facilities that emit 50,000 tonnes or more of carbon dioxide equivalent emissions (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. AltaGas has two processing facilities that would exceed the 50,000 tonnes of CO2e per year threshold. These two facilities were previously regulated under the SGER in Alberta; and will continue to be regulated under the CCIR in Alberta. The carbon pricing scheme in Alberta is expected to align to the federal benchmark.

 

The output based standard is an emissions-intensity standard for a type of activity or product. The output-based standard will be set at a level that represents best-in class performance in order to drive reduced emissions intensity. Compliance reporting for the output-based pricing system will apply annually, based on the calendar year. A facility that emits less than its annual limit (top-quartile or best in class facility) will receive surplus credit from the Government of Canada for the difference between its limit and its reported emissions, where a surplus credit represents one tonne of CO2e. If a facility exceeds its annual emissions limit, it can meet its compliance obligations through payment to the government at the carbon price based on the federal benchmark, use eligible offset credits (Pan-Canadian offsets framework being developed by the Canadian Council of Ministers of the Environment), or use of surplus credits issued by the government to facilities that emitted less than their regulated limits.

 

The carbon levy and the output-based pricing system will not come into effect before January 1, 2019. Carbon pricing legislation is expected to be introduced by the federal government in 2018; giving the provinces until September 2018 to submit their own carbon pricing plans.

 

The provinces of Ontario, Quebec, Alberta and British Columbia, have already adopted carbon pricing plans, but the current price limit in each of those provinces is well below the minimum $50 per tonne level required in 2023 as proposed by the federal government.

 

The impact of a federal carbon pricing structure is expected to be varied across AltaGas’ business segments as the pricing structure catches up with provincial carbon pricing models already in place. The immediate carbon tax impact on AltaGas will mainly impact AltaGas’ Gas and Power segments, while AltaGas’ utilities are expected to pass-through carbon tax to their customers.

 

Federal Greenhouse Gas Reporting Programme (GHGRP)

 

Environment and Climate Change Canada will reduce the reporting threshold for the GHGRP starting with the 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.

 

Using best available data, the number of Gas segment facilities reporting to the GHGRP is expected to increase from three up to ten with this introduction of a lower reporting threshold, resulting in an increase in regulatory reporting obligations.

 

Canadian Provincial GHG Regulations

 

For a discussion of the Alberta GHG regulations and further discussion of federal and provincial environmental regulations, please see “Business of the Corporation — Gas Business — Environmental Considerations Impacting the Gas

 

77

 

Business”, “Business of the Corporation — Power Business — Environmental Considerations Impacting the Power Business” and “Business of the Corporation — Utilities Business — Environmental Considerations Impacting the Utilities Business”.

 

British Columbia (B.C.)

 

Carbon Tax Act

 

B.C.’s carbon tax is currently set at $30 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. and PNG operate under and comply with requirements set forth by the Carbon Tax Act of B.C.

 

British Columbia Climate Leadership Plan (B.C. Climate Leadership Plan)

 

The British Columbia government unveiled the Climate Leadership Plan in August 2016. B.C.’s Climate Leadership Plan identifies key areas where British Columbia can take action to reduce greenhouse gas emissions. Highlights from the plan include, without limitation:

 

1.              Launching a strategy to reduce methane emissions:

 

·                  Targeting extraction and processing emissions (referred to as upstream in the natural gas sector), targeting a 45 percent reduction by 2025 in fugitive and vented emissions in infrastructure built before January 1, 2015.

 

2.              Making B.C.’s electricity 100 percent renewable or clean:

 

·                  100 percent of the electricity acquired by BC Hydro on the integrated grid must now be from renewable or clean sources, except where concerns regarding reliability or costs must be addressed, with allowance for natural gas generation for reliability.

 

3.              Expanding incentives to promote adoption of efficient gas equipment:

 

·                  Expand incentives by at least 100 percent, to encourage further adoption of technologies that reduce the emissions from gas fired equipment and facilitating projects that will help fuel marine vessels and commercial vehicles with cleaner burning natural gas.

 

4.              Electrification support:

 

·                  The B.C. government has approved a regulatory amendment under the Clean Energy Act to support the development of additional transmission infrastructure in northeast B.C. to serve increasing demand for electricity from the upstream natural-gas sector.

 

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

 

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U.S. Federal Air and GHG Regulations

 

Greenhouse Gas Reporting Program (GHGRP)

 

The 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 GHGRP. Facilities determine whether they are required to report based on the types of industrial operations located at the facility, their emission levels, or other factors. Facilities are generally required to submit annual reports under Part 98 if:

 

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

 

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

 

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

 

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

 

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

 

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. Holders of Subscription Receipts are entitled to receive Dividend Equivalent Payments, see the “Capital Structure” section of this AIF for details. Dividends on the Series A Shares, Series B Shares, Series C Shares, Series E Shares, Series G Shares, Series I Shares, and Series K Shares are paid quarterly.

 

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.

 

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$ per share
    	
 
    	
2017
    	
 
    	
2016
    	
 
    	
2015
    	
 
    
	
Common Shares
    	
 
    	
2.107500
    	
 
    	
2.020000
    	
 
    	
1.867500
    	
 
    
	
Series A Shares
    	
 
    	
0.845000
    	
 
    	
0.845000
    	
 
    	
1.148750
    	
 
    
	
Series B Shares
    	
 
    	
0.806380
    	
 
    	
0.786920
    	
 
    	
0.191560
    	
 
    
	
Series C Shares(1)
    	
 
    	
1.155625
    	
 
    	
1.100000
    	
 
    	
1.100000
    	
 
    
	
Series E Shares
    	
 
    	
1.250000
    	
 
    	
1.250000
    	
 
    	
1.250000
    	
 
    
	
Series G Shares
    	
 
    	
1.187500
    	
 
    	
1.187500
    	
 
    	
1.187500
    	
 
    
	
Series I Shares
    	
 
    	
1.312500
    	
 
    	
1.448245
    	
 
    	
—
    	
 
    
	
Series K Shares
    	
 
    	
1.063400
    	
 
    	
—
    	
 
    	
—
    	
 
    

 

   

Note:

(1)         Amounts disclosed are in US dollars.

 

PREMIUM DIVIDENDTM, DIVIDEND REINVESTMENT AND OPTIONAL CASH PURCHASE PLAN

 

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

 

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

 

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

 

Each of the components of the Plan is subject to prorating and other limitations on availability of new Common Shares in certain events. The “average market price”, in respect of a particular dividend payment date, refers to the arithmetic average (calculated to four decimal places) of the daily volume weighted average trading prices of Common Shares on the TSX for the trading days on which at least one board lot of Common Shares is traded during the 10 business days immediately preceding the applicable dividend payment date. Such trading prices will be appropriately adjusted for certain capital changes (including, without limitation, common share subdivisions, common share consolidations, certain rights offerings and certain dividends). Shareholders resident outside of Canada are not entitled to participate in the Premium DividendTM component of the Plan. Shareholders resident outside of Canada (other than the U.S.) may participate in the Dividend Reinvestment component or the Optional Cash Payment Component of the Plan only if their participation is permitted by the laws of the jurisdiction in which they reside and provided that AltaGas is satisfied, in its sole discretion, that such laws do not subject the Plan or AltaGas to additional legal or regulatory requirements.

 

TM Denotes trademark of Canaccord Genuity Corp.

 

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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 2017 as reported by the TSX:

 

	
Month
    	
 
    	
High
    	
 
    	
Low
    	
 
    	
Volume Traded
    	
 
    
	
January
    	
 
    	
35.15
    	
 
    	
30.70
    	
 
    	
23,537,989
    	
 
    
	
February
    	
 
    	
31.70
    	
 
    	
29.96
    	
 
    	
17,647,685
    	
 
    
	
March
    	
 
    	
31.28
    	
 
    	
30.58
    	
 
    	
13,711,470
    	
 
    
	
April
    	
 
    	
31.24
    	
 
    	
30.43
    	
 
    	
8,831,892
    	
 
    
	
May
    	
 
    	
31.70
    	
 
    	
29.82
    	
 
    	
11,414,618
    	
 
    
	
June
    	
 
    	
30.60
    	
 
    	
29.42
    	
 
    	
11,936,696
    	
 
    
	
July
    	
 
    	
29.84
    	
 
    	
28.69
    	
 
    	
9,162,920
    	
 
    
	
August
    	
 
    	
29.30
    	
 
    	
26.87
    	
 
    	
9,692,075
    	
 
    
	
September
    	
 
    	
29.03
    	
 
    	
27.30
    	
 
    	
8,747,905
    	
 
    
	
October
    	
 
    	
29.65
    	
 
    	
28.02
    	
 
    	
11,760,831
    	
 
    
	
November
    	
 
    	
30.06
    	
 
    	
28.78
    	
 
    	
9,712,402
    	
 
    
	
December
    	
 
    	
29.58
    	
 
    	
28.32
    	
 
    	
10,336,582
    	
 
    

 

The Subscription Receipts commenced trading on the TSX under the symbol ALA.R, on February 3, 2017. The following table sets forth the monthly price range and volume traded for Subscription Receipts for the period of February to December 2017 as reported by the TSX:

 

	
Month
    	
 
    	
High
    	
 
    	
Low
    	
 
    	
Volume Traded
    	
 
    
	
February
    	
 
    	
30.53
    	
 
    	
28.86
    	
 
    	
8,403,365
    	
 
    
	
March
    	
 
    	
30.25
    	
 
    	
29.60
    	
 
    	
3,856,445
    	
 
    
	
April
    	
 
    	
30.43
    	
 
    	
29.67
    	
 
    	
2,209,824
    	
 
    
	
May
    	
 
    	
30.62
    	
 
    	
29.50
    	
 
    	
3,026,916
    	
 
    
	
June
    	
 
    	
30.25
    	
 
    	
29.15
    	
 
    	
2,543,205
    	
 
    
	
July
    	
 
    	
29.69
    	
 
    	
28.58
    	
 
    	
1,924,608
    	
 
    
	
August
    	
 
    	
29.11
    	
 
    	
27.32
    	
 
    	
2,257,637
    	
 
    
	
September
    	
 
    	
29.33
    	
 
    	
27.50
    	
 
    	
1,682,654
    	
 
    
	
October
    	
 
    	
29.79
    	
 
    	
28.30
    	
 
    	
1,901,947
    	
 
    
	
November
    	
 
    	
29.78
    	
 
    	
28.65
    	
 
    	
1,515,216
    	
 
    
	
December
    	
 
    	
29.36
    	
 
    	
27.94
    	
 
    	
2,195,966
    	
 
    

 

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 2017 as reported by the TSX:

 

	
Month
    	
 
    	
High
    	
 
    	
Low
    	
 
    	
Volume Traded
    	
 
    
	
January
    	
 
    	
19.65
    	
 
    	
17.77
    	
 
    	
122,727
    	
 
    
	
February
    	
 
    	
19.50
    	
 
    	
18.81
    	
 
    	
173,613
    	
 
    
	
March
    	
 
    	
20.43
    	
 
    	
19.40
    	
 
    	
212,711
    	
 
    
	
April
    	
 
    	
20.76
    	
 
    	
19.86
    	
 
    	
85,502
    	
 
    
	
May
    	
 
    	
20.24
    	
 
    	
19.38
    	
 
    	
76,971
    	
 
    
	
June
    	
 
    	
20.20
    	
 
    	
18.89
    	
 
    	
65,557
    	
 
    
	
July
    	
 
    	
21.06
    	
 
    	
20.22
    	
 
    	
244,819
    	
 
    
	
August
    	
 
    	
20.91
    	
 
    	
20.07
    	
 
    	
53,218
    	
 
    
	
September
    	
 
    	
20.96
    	
 
    	
20.31
    	
 
    	
213,739
    	
 
    
	
October
    	
 
    	
21.05
    	
 
    	
20.50
    	
 
    	
275,844
    	
 
    
	
November
    	
 
    	
21.50
    	
 
    	
20.52
    	
 
    	
114,504
    	
 
    
	
December
    	
 
    	
21.30
    	
 
    	
20.40
    	
 
    	
61,430
    	
 
    

 

81

 

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 2017 as reported by the TSX:

 

	
Month
    	
 
    	
High
    	
 
    	
Low
    	
 
    	
Volume Traded
    	
 
    
	
January
    	
 
    	
18.20
    	
 
    	
16.80
    	
 
    	
20,230
    	
 
    
	
February
    	
 
    	
18.42
    	
 
    	
18.09
    	
 
    	
13,290
    	
 
    
	
March
    	
 
    	
19.35
    	
 
    	
18.30
    	
 
    	
43,024
    	
 
    
	
April
    	
 
    	
19.75
    	
 
    	
19.14
    	
 
    	
26,862
    	
 
    
	
May
    	
 
    	
19.60
    	
 
    	
19.12
    	
 
    	
26,732
    	
 
    
	
June
    	
 
    	
20.20
    	
 
    	
18.94
    	
 
    	
36,893
    	
 
    
	
July
    	
 
    	
20.90
    	
 
    	
20.19
    	
 
    	
67,428
    	
 
    
	
August
    	
 
    	
20.92
    	
 
    	
20.13
    	
 
    	
13,151
    	
 
    
	
September
    	
 
    	
20.97
    	
 
    	
20.10
    	
 
    	
20,875
    	
 
    
	
October
    	
 
    	
20.92
    	
 
    	
20.31
    	
 
    	
95,420
    	
 
    
	
November
    	
 
    	
21.05
    	
 
    	
20.22
    	
 
    	
18,975
    	
 
    
	
December
    	
 
    	
21.30
    	
 
    	
20.49
    	
 
    	
36,805
    	
 
    

 

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 2017 as reported by the TSX:

 

	
Month
    	
 
    	
High
    	
 
    	
Low
    	
 
    	
Volume Traded
    	
 
    
	
January
    	
 
    	
24.42
    	
 
    	
23.21
    	
 
    	
106,243
    	
 
    
	
February
    	
 
    	
24.48
    	
 
    	
23.67
    	
 
    	
103,749
    	
 
    
	
March
    	
 
    	
24.90
    	
 
    	
23.97
    	
 
    	
156,169
    	
 
    
	
April
    	
 
    	
25.16
    	
 
    	
24.35
    	
 
    	
121,635
    	
 
    
	
May
    	
 
    	
24.89
    	
 
    	
24.36
    	
 
    	
113,522
    	
 
    
	
June
    	
 
    	
25.36
    	
 
    	
24.40
    	
 
    	
319,868
    	
 
    
	
July
    	
 
    	
25.25
    	
 
    	
24.95
    	
 
    	
250,714
    	
 
    
	
August
    	
 
    	
25.35
    	
 
    	
24.72
    	
 
    	
462,422
    	
 
    
	
September
    	
 
    	
25.20
    	
 
    	
24.81
    	
 
    	
171,131
    	
 
    
	
October
    	
 
    	
25.77
    	
 
    	
25.05
    	
 
    	
237,459
    	
 
    
	
November
    	
 
    	
26.10
    	
 
    	
25.64
    	
 
    	
107,915
    	
 
    
	
December
    	
 
    	
26.03
    	
 
    	
25.60
    	
 
    	
86,627
    	
 
    

 

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 2017 as reported by the TSX:

 

	
Month
    	
 
    	
High
    	
 
    	
Low
    	
 
    	
Volume Traded
    	
 
    
	
January
    	
 
    	
24.97
    	
 
    	
23.50
    	
 
    	
220,470
    	
 
    
	
February
    	
 
    	
24.79
    	
 
    	
23.91
    	
 
    	
455,452
    	
 
    
	
March
    	
 
    	
24.20
    	
 
    	
23.50
    	
 
    	
135,910
    	
 
    
	
April
    	
 
    	
24.51
    	
 
    	
23.50
    	
 
    	
212,696
    	
 
    
	
May
    	
 
    	
23.95
    	
 
    	
23.30
    	
 
    	
115,771
    	
 
    
	
June
    	
 
    	
24.14
    	
 
    	
22.63
    	
 
    	
205,620
    	
 
    
	
July
    	
 
    	
24.49
    	
 
    	
23.85
    	
 
    	
126,049
    	
 
    
	
August
    	
 
    	
24.40
    	
 
    	
23.51
    	
 
    	
76,909
    	
 
    
	
September
    	
 
    	
24.55
    	
 
    	
23.74
    	
 
    	
188,963
    	
 
    
	
October
    	
 
    	
24.83
    	
 
    	
24.42
    	
 
    	
99,022
    	
 
    
	
November
    	
 
    	
25.15
    	
 
    	
24.45
    	
 
    	
337,587
    	
 
    
	
December
    	
 
    	
25.20
    	
 
    	
24.41
    	
 
    	
132,966
    	
 
    

 

82

 

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 2017 as reported by the TSX:

 

	
Month
    	
 
    	
High
    	
 
    	
Low
    	
 
    	
Volume Traded
    	
 
    
	
January
    	
 
    	
23.66
    	
 
    	
22.12
    	
 
    	
266,472
    	
 
    
	
February
    	
 
    	
23.35
    	
 
    	
22.38
    	
 
    	
238,828
    	
 
    
	
March
    	
 
    	
23.05
    	
 
    	
21.96
    	
 
    	
240,021
    	
 
    
	
April
    	
 
    	
23.57
    	
 
    	
22.63
    	
 
    	
384,583
    	
 
    
	
May
    	
 
    	
23.08
    	
 
    	
22.49
    	
 
    	
76,970
    	
 
    
	
June
    	
 
    	
23.45
    	
 
    	
21.99
    	
 
    	
224,221
    	
 
    
	
July
    	
 
    	
23.75
    	
 
    	
23.13
    	
 
    	
72,767
    	
 
    
	
August
    	
 
    	
23.80
    	
 
    	
22.90
    	
 
    	
40,213
    	
 
    
	
September
    	
 
    	
23.75
    	
 
    	
23.13
    	
 
    	
222,388
    	
 
    
	
October
    	
 
    	
24.12
    	
 
    	
23.69
    	
 
    	
64,443
    	
 
    
	
November
    	
 
    	
24.52
    	
 
    	
23.52
    	
 
    	
435,150
    	
 
    
	
December
    	
 
    	
24.60
    	
 
    	
23.70
    	
 
    	
58,007
    	
 
    

 

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 2017 as reported by the TSX:

 

	
Month
    	
 
    	
High
    	
 
    	
Low
    	
 
    	
Volume Traded
    	
 
    
	
January
    	
 
    	
25.95
    	
 
    	
25.46
    	
 
    	
247,042
    	
 
    
	
February
    	
 
    	
26.18
    	
 
    	
25.45
    	
 
    	
240,995
    	
 
    
	
March
    	
 
    	
26.00
    	
 
    	
25.55
    	
 
    	
166,131
    	
 
    
	
April
    	
 
    	
26.25
    	
 
    	
25.70
    	
 
    	
173,091
    	
 
    
	
May
    	
 
    	
26.20
    	
 
    	
25.69
    	
 
    	
38,678
    	
 
    
	
June
    	
 
    	
26.60
    	
 
    	
25.86
    	
 
    	
66,279
    	
 
    
	
July
    	
 
    	
26.39
    	
 
    	
25.97
    	
 
    	
21,097
    	
 
    
	
August
    	
 
    	
26.06
    	
 
    	
25.30
    	
 
    	
59,759
    	
 
    
	
September
    	
 
    	
26.10
    	
 
    	
25.42
    	
 
    	
44,297
    	
 
    
	
October
    	
 
    	
26.05
    	
 
    	
25.56
    	
 
    	
546,457
    	
 
    
	
November
    	
 
    	
26.46
    	
 
    	
25.76
    	
 
    	
35,149
    	
 
    
	
December
    	
 
    	
26.19
    	
 
    	
25.75
    	
 
    	
78,167
    	
 
    

 

Series K Shares commenced trading on the TSX under the symbol ALA.PR.K on February 22, 2017. The following table sets forth the monthly price range and volume traded for Series K Shares for the period of February 22, 2017 to December 2017 as reported by the TSX:

 

	
Month
    	
 
    	
High
    	
 
    	
Low
    	
 
    	
Volume Traded
    	
 
    
	
February
    	
 
    	
25.12
    	
 
    	
25.00
    	
 
    	
632,689
    	
 
    
	
March
    	
 
    	
25.69
    	
 
    	
25.04
    	
 
    	
707,056
    	
 
    
	
April
    	
 
    	
26.35
    	
 
    	
25.60
    	
 
    	
521,855
    	
 
    
	
May
    	
 
    	
26.09
    	
 
    	
25.50
    	
 
    	
323,560
    	
 
    
	
June
    	
 
    	
26.25
    	
 
    	
25.50
    	
 
    	
289,424
    	
 
    
	
July
    	
 
    	
25.80
    	
 
    	
25.01
    	
 
    	
302,380
    	
 
    
	
August
    	
 
    	
25.80
    	
 
    	
25.00
    	
 
    	
258,466
    	
 
    
	
September
    	
 
    	
25.98
    	
 
    	
25.25
    	
 
    	
257,888
    	
 
    
	
October
    	
 
    	
25.80
    	
 
    	
25.30
    	
 
    	
295,503
    	
 
    
	
November
    	
 
    	
25.97
    	
 
    	
25.46
    	
 
    	
212,508
    	
 
    
	
December
    	
 
    	
25.82
    	
 
    	
25.35
    	
 
    	
210,870
    	
 
    

 

83

 

CREDIT RATINGS

 

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

 

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

 

On December 16, 2015, S&P revised AltaGas’ issuer rating and senior unsecured MTN rating to BBB with a Negative Outlook. On January 16, 2017, S&P reaffirmed the BBB with a Negative Outlook. On January 26, 2017, DBRS revised the rating to BBB Under Review with Developing Implications. On November 6, 2017, DBRS reaffirmed the rating of BBB Under Review with Developing Implications.

 

According to the DBRS rating system, debt securities rated BBB are of adequate credit quality. Protection of interest and principal is considered acceptable, but the entity is fairly susceptible to adverse changes in financial and economic conditions, or there may be other adverse conditions present which reduce the strength of the entity and its rated securities. “High” or “Low” grades are used to indicate the relative standing within a particular rating category.

 

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

 

On August 10, 2010, S&P and DBRS commenced rating of AltaGas’ Preferred Shares with an S&P rating of P-3 (High) and DBRS rating of Pfd-3. AltaGas’ Preferred Shares continue to have an S&P rating of P-3 (High) and DBRS rating of Pfd-3. On January 26, 2017, DBRS revised the outlook to Under Review with Developing Implications. On November 6, 2017, DBRS reaffirmed its status of Under Review with Developing Implications.

 

A Pfd-3 rating by DBRS is the third highest of six categories granted by DBRS. According to the DBRS rating system, preferred shares rated Pfd-3 are of adequate credit quality. While protection of dividends and principal is still considered acceptable, the issuing entity is more susceptible to adverse changes in financial and economic conditions, and there may be other adversities present which detract from debt protection. Pfd-3 ratings normally correspond with companies whose bonds are rated in the higher end of the BBB category. “High” or “Low” grades are used to indicate the relative standing within a rating category. The absence of either a “High” or “Low” designation indicates the rating is in the middle of the category.

 

The ratings action “Under Review” is applied, among other things, when a significant event occurs that directly impacts the credit quality of a particular entity or group of entities and there is uncertainty regarding the outcome of the event such that DBRS is unable to provide an objective, forward-looking opinion in a timely fashion. A rating that is “Under Review” remains outstanding; however, this status acts as a warning signal indicating that the outstanding rating may no longer be appropriate. When a rating is placed “Under Review”, DBRS will generally provide initial guidance as to the opinion of DBRS by noting whether the Under Review action has positive (Under Review — Positive), negative (Under Review — Negative) or developing implications (Under Review — Developing). These qualifications indicate the preliminary evaluation of DBRS of the impact on the credit quality of the security or issuer; however, as situations and potential rating implications may vary, its final rating conclusion may depart from the preliminary assessment. DBRS will further review the Corporation’s ratings as more information becomes available and aims to resolve the Under Review status of the ratings once financing details are known and the WGL Acquisition has closed.

 

A P-3 rating by S&P is the third highest of eight categories granted by S&P under its Canadian preferred share rating scale and a P-3 (High) rating directly corresponds with a BB+ rating under its global preferred rating scale. The Canadian

 

84

 

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

 

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

 

Except as set forth above, neither DBRS nor S&P has announced that it is reviewing or intends to revise or withdraw the ratings on AltaGas.

 

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

 

MATERIAL CONTRACTS

 

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

 

·                  The $1.4 billion Extendible Revolving Term Credit Facility Credit Agreement dated December 20, 2013, as amended by the first amending agreement dated December 17, 2014 the second amending agreement dated December 4, 2015 and the third amending agreement dated December 8, 2016. This is an unsecured extendible revolving credit facility with Royal Bank of Canada, The Toronto-Dominion Bank, Bank of Montreal, Canadian Imperial Bank of Commerce, The Bank of Nova Scotia, National Bank of Canada, HSBC Bank Canada, Alberta Treasury Branches, Bank of America, N.A., Canada Branch and JP Morgan Chase Bank, N.A., Export Development Canada and their respective affiliates maturing on December 15, 2020. Borrowings on the facility can be by way of prime loans, U.S. base rate loans, LIBOR loans, bankers’ acceptances or letters of credit. Borrowings on the facility bear fees and interest at rates relevant to the nature of the draw made;

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

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

·                  The Merger Agreement.

 

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

 

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

 

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

 

LEGAL PROCEEDINGS

 

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

 

85

 

REGULATORY ACTIONS

 

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

 

INTERESTS OF EXPERTS

 

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

 

ADDITIONAL INFORMATION

 

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

 

Additional financial information is contained in AltaGas’ audited consolidated financial statements as at and for the year ended December 31, 2017 and management’s discussion and analysis for the year ended December 31, 2017.

 

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

 

TRANSFER AGENTS AND REGISTRARS

 

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

 

The registrar and trustee for AltaGas’ MTNs is Computershare Trust Company of Canada, 710, 530 - 8th Avenue SW, Calgary, Alberta T2P 3S8, Tel: 1-800-564-6253.

 

86

 

SCHEDULE A: AUDIT COMMITTEE MANDATE

 

I.                                        Constitution

 

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

 

The Committee shall supervise the audit of AltaGas’ financial records and will ensure the adequacy and effectiveness of its policies and procedures regarding AltaGas’ financial reporting, internal accounting, financial controls, management information and risk management.

 

II.                                   Membership

 

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

 

·                  a Director of the Corporation,

 

·                  independent, and

 

·                  financially literate.

 

No Member shall be an officer or employee of the Corporation or any other subsidiary or affiliate of AltaGas. Any Member may be removed or replaced at any time by the Board and shall cease to be a Member upon ceasing to be a Director of the Corporation. Each Member shall hold office until the Member resigns or is replaced, whichever first occurs.

 

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

 

III.                              Meetings

 

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

 

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

 

In the absence of the Chair of the Committee, the Members may choose one (1) of the Members to be the chair of the meeting.

 

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

 

The Committee will hold in camera sessions with management, and the internal and external auditors, as may be deemed appropriate by the Members.

 

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

 

IV.                               Duties and Responsibilities of the Chair

 

The Chair is responsible for:

 

a)             convening Committee meetings and designating the times and places of those meetings;

 

b)             working with Management on the development of agendas and related materials for Committee meetings;

 

A-1

 

c)              ensuring Committee meetings are conducted in an efficient, effective and focused manner;

 

d)             providing leadership to the Committee and to assist the Committee in reviewing and monitoring its responsibilities; and

 

e)              reporting to the Board on the decisions and recommendations of the Committee.

 

V.                                    Duties and Responsibilities of the Committee

 

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

 

a)             oversight of external auditors, including:

 

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

 

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

 

·                  pre-approve non-audit work undertaken by the external audit firm;

 

·                  determine external auditor independence;

 

·                  review and approval of AltaGas’ hiring policies re: current and former partners and employees of the external auditor;

 

b)             oversight of audits and financial reporting, including:

 

·                  review of the audit plan;

 

·                  financial statements, including management’s discussion and analysis;

 

·                  annual and interim press releases regarding financial results;

 

·                  reports to shareholders and others;

 

·                  filings to securities regulators;

 

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

 

·                  review of litigation, claims and contingencies;

 

c)              oversight of financial reporting processes and internal controls, including:

 

·                  reviewing the adequacy and effectiveness of the accounting and internal control policies of the Corporation and procedures through inquiry and discussions with the external auditors, management and the internal auditor;

 

·                  review at least annually with the internal auditor the Corporation’s internal procedures, and the scope and plans for the work of the internal audit group;

 

d)             oversight of finance matters, including:

 

·                  review and, as required, approve or recommend for approval to the Board, prospectuses and documents, where practicable, which may be incorporated by reference into a prospectus;

 

A-2

 

·                  review the issuance of equity or debt securities by the Corporation;

 

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

 

·                  review and recommend to the Human Resources and Compensation Committee, for further recommendation or approval, the calculations of financial metrics used in the determination of employee incentive compensation plans;

 

·                  monitor finance integration and financial risk management programs associated with major acquisitions;

 

e)              oversight of risk management, including a review of the Corporation’s major risks, a review of the method of risk analysis by the Corporation, review of the strategies, policies and practices in place for risk management, a review of the Corporation’s cyber risk and data security, and a review of the Corporation’s insurance program;

 

f)               policies applicable to the Committee’s mandate, including:

 

·                  Accounting and Auditing Irregularity Reporting Policy; and

 

·                  commodity risk management and related policies;

 

g)              the following other duties:

 

·                  review at least annually the staffing and succession planning in the accounting and finance groups;

 

·                  report to the Board after each Committee meeting, as required during the year, with respect to the Committee’s activities and recommendations;

 

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

 

The Committee shall ensure satisfactory procedures for receipt, retention and resolution of complaints and for the confidential, anonymous submission by employees regarding any accounting, internal accounting controls or auditing matters.

 

The full Board will be kept informed of the Committee’s activities by a report at each regular meeting of the Board.

 

The Committee will review the relevance and adequacy of this Mandate on at least an annual basis and will provide recommendations to the Governance Committee of the Board.

 

VI.                               External Auditor

 

The Committee shall recommend the appointment of the external auditor annually. Once appointed by the Shareholders, the external auditor shall report directly to the Committee.

 

The Committee shall pre-approve all non-audit services provided by the external auditor, and shall have direct responsibility for overseeing the work of the external auditor engaged for the purpose of preparing or issuing an auditor’s report or performing other audit, review or attest services, including the resolution of disagreements between the external auditor and management.

 

VII.                          Relations with Management

 

The Committee will ensure that it coordinates its activities with the Chief Financial Officer on audit and financial matters and will:

 

·                                          meet regularly with Management to discuss areas of concern;

 

·                                          review and assess the quality of the executives involved in the financial reporting process; and

 

A-3

 

·                                          ensure Management provides adequate funding to the Committee so that it may independently engage and remunerate the Auditor and any advisors.

 

VIII.                     Committee Timetable

 

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

 

A-4

 

 

AltaGas Ltd.

1700, 355 - 4th Avenue SW

Calgary, AB  T2P 0J1

Tel: 403-691-7575

Fax: 403-691-7576

www.altagas.caExhibit 4.2

 

Management’s Responsibility for Consolidated Financial Statements

 

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

 

Management is responsible for establishing and maintaining adequate internal controls over financial reporting for the Corporation. Management has designed and maintains a system of internal controls over financial reporting, including a program of internal audits to carry out its responsibility. Management believes these controls provide reasonable assurance that financial records are reliable and form a proper basis for the preparation of financial statements. Management undertakes communication to employees of policies that govern ethical business conduct.

 

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

 

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

 

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

 

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

 

 

	
(signed) “David Harris”
    	
 
    	
(signed) “Tim Watson”
    
	
 
    	
 
    	
 
    
	
DAVID HARRIS
    	
 
    	
TIM WATSON
    
	
President and
    	
 
    	
Executive Vice President and
    
	
Chief Executive Officer of
    	
 
    	
Chief Financial Officer of
    
	
AltaGas Ltd.
    	
 
    	
AltaGas Ltd.
    

 

February 28, 2018

 

AltaGas Ltd. – 2017

 

1

 

Independent Auditors’ Report

 

To the Shareholders of AltaGas Ltd.

 

We have audited the accompanying Consolidated Financial Statements of AltaGas Ltd., which comprise the consolidated balance sheets as at December 31, 2017 and 2016, and the consolidated statements of income, comprehensive income (loss), equity and cash flows for the years then ended, and a summary of significant accounting policies and other explanatory information.

 

Management’s Responsibility for the Consolidated Financial Statements

 

Management is responsible for the preparation and fair presentation of these Consolidated Financial Statements in accordance with United States Generally Accepted Accounting Principles, and for such internal control as management determines is necessary to enable the preparation of Consolidated Financial Statements that are free from material misstatement, whether due to fraud or error.

 

Auditors’ Responsibility

 

Our responsibility is to express an opinion on these Consolidated Financial Statements based on our audits. We conducted our audits in accordance with Canadian Generally Accepted Auditing Standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the Consolidated Financial Statements are free from material misstatement.

 

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the Consolidated Financial Statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the Consolidated Financial Statements, whether due to fraud or error. In making those risk assessments, the auditors consider internal control relevant to the entity’s preparation and fair presentation of the Consolidated Financial Statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the Consolidated Financial Statements.

 

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

 

Opinion

 

In our opinion, the Consolidated Financial Statements present fairly, in all material respects, the financial position of AltaGas Ltd. as at December 31, 2017 and 2016 and the results of its operations and its cash flows for the years then ended in accordance with United States Generally Accepted Accounting Principles.

 

	
Calgary,   Canada
    	

    
	
February 28,   2018
    	
 
    

 

2

 

Consolidated Balance Sheets

 

	
As at ($ millions)
    	
 
    	
December 31,
   2017
    	
 
    	
December 31,
   2016
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
ASSETS
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Current   assets
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Cash and cash   equivalents
    	
 
    	
$
    	
27.3
    	
 
    	
$
    	
19.0
    	
 
    
	
Accounts   receivable, net of allowances (notes 4 and 20)
    	
 
    	
382.9
    	
 
    	
338.8
    	
 
    
	
Inventory (note 5)
    	
 
    	
201.1
    	
 
    	
221.0
    	
 
    
	
Restricted cash   holdings from customers
    	
 
    	
8.9
    	
 
    	
5.0
    	
 
    
	
Regulatory   assets (note 18)
    	
 
    	
1.1
    	
 
    	
0.9
    	
 
    
	
Risk management   assets (note 20)
    	
 
    	
38.6
    	
 
    	
40.4
    	
 
    
	
Prepaid expenses   and other current assets
    	
 
    	
36.0
    	
 
    	
42.8
    	
 
    
	
Assets held for   sale (note 4)
    	
 
    	
6.0
    	
 
    	
70.7
    	
 
    
	
 
    	
 
    	
701.9
    	
 
    	
738.6
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Property,   plant and equipment (notes 4 and 6)
    	
 
    	
6,689.8
    	
 
    	
6,734.9
    	
 
    
	
Intangible   assets (notes 4 and 7)
    	
 
    	
588.8
    	
 
    	
694.3
    	
 
    
	
Goodwill   (notes 4 and 8)
    	
 
    	
817.3
    	
 
    	
856.0
    	
 
    
	
Regulatory   assets (note 18)
    	
 
    	
328.6
    	
 
    	
329.1
    	
 
    
	
Risk   management assets (note 20)
    	
 
    	
15.9
    	
 
    	
24.1
    	
 
    
	
Deferred   income taxes (note 17)
    	
 
    	
2.8
    	
 
    	
2.8
    	
 
    
	
Restricted   cash holdings from customers
    	
 
    	
7.5
    	
 
    	
10.1
    	
 
    
	
Long-term   investments and other assets   (note 10)
    	
 
    	
312.6
    	
 
    	
189.3
    	
 
    
	
Investments   accounted for by the equity method (note 12)
    	
 
    	
567.0
    	
 
    	
621.4
    	
 
    
	
 
    	
 
    	
$
    	
10,032.2
    	
 
    	
$
    	
10,200.6
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
LIABILITIES   AND SHAREHOLDERS’ EQUITY
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Current   liabilities
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Accounts payable   and accrued liabilities (note 20)
    	
 
    	
$
    	
415.3
    	
 
    	
$
    	
345.8
    	
 
    
	
Dividends   payable (note 20)
    	
 
    	
32.0
    	
 
    	
29.2
    	
 
    
	
Short-term debt (notes 13 and 20)
    	
 
    	
46.8
    	
 
    	
128.7
    	
 
    
	
Current portion   of long-term debt (notes 14 and 20)
    	
 
    	
188.9
    	
 
    	
383.4
    	
 
    
	
Customer   deposits
    	
 
    	
30.8
    	
 
    	
35.5
    	
 
    
	
Regulatory   liabilities (note 18)
    	
 
    	
10.9
    	
 
    	
16.6
    	
 
    
	
Risk management   liabilities (note 20)
    	
 
    	
57.6
    	
 
    	
32.9
    	
 
    
	
Other current   liabilities (notes 16 and 20)
    	
 
    	
32.6
    	
 
    	
23.6
    	
 
    
	
Liabilities   associated with assets held for sale (note 4)
    	
 
    	
0.3
    	
 
    	
0.4
    	
 
    
	
 
    	
 
    	
815.2
    	
 
    	
996.1
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Long-term   debt (notes 14 and 20)
    	
 
    	
3,436.5
    	
 
    	
3,366.9
    	
 
    
	
Asset   retirement obligations (notes 4 and 15)
    	
 
    	
88.3
    	
 
    	
81.6
    	
 
    
	
Deferred   income taxes (note 17)
    	
 
    	
444.2
    	
 
    	
621.7
    	
 
    
	
Regulatory   liabilities (note 18)
    	
 
    	
268.6
    	
 
    	
170.5
    	
 
    
	
Risk   management liabilities (note 20)
    	
 
    	
13.8
    	
 
    	
12.6
    	
 
    
	
Other   long-term liabilities (notes 16 and 20)
    	
 
    	
201.9
    	
 
    	
206.3
    	
 
    
	
Future   employee obligations (note 25)
    	
 
    	
124.5
    	
 
    	
129.5
    	
 
    
	
 
    	
 
    	
$
    	
5,393.0
    	
 
    	
$
    	
5,585.2
    	
 
    

 

3

 

	
As at ($ millions)
    	
 
    	
December 31,
   2017
    	
 
    	
December 31,
   2016
    	
 
    
	
Shareholders’   equity
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Common shares,   no par values, unlimited shares authorized;      2017 - 175.3 million and   2016 - 166.9 million issued and outstanding (note 21)
    	
 
    	
$
    	
4,007.9
    	
 
    	
$
    	
3,773.4
    	
 
    
	
Preferred shares   (note 21)
    	
 
    	
1,277.7
    	
 
    	
985.1
    	
 
    
	
Contributed   surplus
    	
 
    	
22.3
    	
 
    	
17.4
    	
 
    
	
Accumulated   deficit
    	
 
    	
(933.6
    	
)
    	
(600.4
    	
)
    
	
Accumulated   other comprehensive income (AOCI) (note 19)
    	
 
    	
199.1
    	
 
    	
405.1
    	
 
    
	
Total   shareholders’ equity
    	
 
    	
4,573.4
    	
 
    	
4,580.6
    	
 
    
	
Non-controlling   interests
    	
 
    	
65.8
    	
 
    	
34.8
    	
 
    
	
Total   equity
    	
 
    	
4,639.2
    	
 
    	
4,615.4
    	
 
    
	
 
    	
 
    	
$
    	
10,032.2
    	
 
    	
$
    	
10,200.6
    	
 
    

 

Variable interest entity (note 11).

Commitments, contingencies and guarantees (note 26).

Subsequent events (note 30).

 

See accompanying notes to the Consolidated Financial Statements.

 

Approved by the Board of Directors of AltaGas Ltd.

 

 

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

 

4

 

Consolidated Statements of Income

 

	
For the year ended December 31 ($ millions except per share   amounts)
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
REVENUE
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Regulated   operations
    	
 
    	
$
    	
1,119.1
    	
 
    	
$
    	
1,049.9
    	
 
    
	
Services (note 24)
    	
 
    	
903.3
    	
 
    	
828.4
    	
 
    
	
Sales
    	
 
    	
595.9
    	
 
    	
315.6
    	
 
    
	
Other revenue
    	
 
    	
0.4
    	
 
    	
7.2
    	
 
    
	
Unrealized   losses on risk management contracts (note 20)
    	
 
    	
(62.5
    	
)
    	
(11.4
    	
)
    
	
 
    	
 
    	
2,556.2
    	
 
    	
2,189.7
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
EXPENSES
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Cost of sales,   exclusive of items shown separately
    	
 
    	
1,357.1
    	
 
    	
1,016.9
    	
 
    
	
Operating and   administrative
    	
 
    	
573.8
    	
 
    	
509.3
    	
 
    
	
Accretion   expenses (notes 15 and 16)
    	
 
    	
10.9
    	
 
    	
11.0
    	
 
    
	
Depreciation and   amortization (notes 6 and 7)
    	
 
    	
282.4
    	
 
    	
271.5
    	
 
    
	
Provisions on   assets (note 9)
    	
 
    	
139.6
    	
 
    	
—
    	
 
    
	
 
    	
 
    	
2,363.8
    	
 
    	
1,808.7
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Income   from equity investments (note 12)
    	
 
    	
31.4
    	
 
    	
3.4
    	
 
    
	
Other   income (note 23)
    	
 
    	
11.2
    	
 
    	
8.6
    	
 
    
	
Foreign   exchange gains
    	
 
    	
1.7
    	
 
    	
4.0
    	
 
    
	
Interest   expense
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Short-term debt
    	
 
    	
(3.7
    	
)
    	
(3.1
    	
)
    
	
Long-term debt
    	
 
    	
(166.6
    	
)
    	
(147.7
    	
)
    
	
Income   before income taxes
    	
 
    	
66.4
    	
 
    	
246.2
    	
 
    
	
Income   tax expense (recovery) (note 17)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Current
    	
 
    	
30.5
    	
 
    	
24.4
    	
 
    
	
Deferred
    	
 
    	
(64.0
    	
)
    	
8.4
    	
 
    
	
Net   income after taxes
    	
 
    	
99.9
    	
 
    	
213.4
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Net   income applicable to non-controlling interests
    	
 
    	
8.3
    	
 
    	
9.9
    	
 
    
	
Net   income applicable to controlling interests
    	
 
    	
91.6
    	
 
    	
203.5
    	
 
    
	
Preferred   share dividends
    	
 
    	
(61.3
    	
)
    	
(48.1
    	
)
    
	
Net   income applicable to common shares
    	
 
    	
$
    	
30.3
    	
 
    	
$
    	
155.4
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Net   income per common share (note 22)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Basic
    	
 
    	
$
    	
0.18
    	
 
    	
$
    	
0.99
    	
 
    
	
Diluted
    	
 
    	
$
    	
0.18
    	
 
    	
$
    	
0.99
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Weighted   average number of common shares outstanding (millions) (note 22)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Basic
    	
 
    	
171.0
    	
 
    	
157.2
    	
 
    
	
Diluted
    	
 
    	
171.3
    	
 
    	
157.6
    	
 
    

 

See accompanying notes to the Consolidated Financial Statements.

 

5

 

Consolidated Statements of Comprehensive Income (Loss)

 

	
For the year ended December 31 ($ millions)
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Net   income after taxes
    	
 
    	
$
    	
99.9
    	
 
    	
$
    	
213.4
    	
 
    
	
Other   comprehensive income (loss), net of taxes
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Loss on foreign   currency translation
    	
 
    	
(183.4
    	
)
    	
(84.2
    	
)
    
	
Unrealized gain   on net investment hedge (note 20)
    	
 
    	
6.6
    	
 
    	
34.0
    	
 
    
	
Actuarial losses   on pension plans and post-retirement benefit (PRB) plans (note 25)
    	
 
    	
(1.0
    	
)
    	
(2.4
    	
)
    
	
Reclassification   of actuarial losses and prior service costs on defined benefit and PRB plans   to net income (note 25)
    	
 
    	
0.7
    	
 
    	
0.7
    	
 
    
	
Settlement of   PRB plan (note 25)
    	
 
    	
0.2
    	
 
    	
—
    	
 
    
	
Unrealized gain   (loss) on available-for-sale assets
    	
 
    	
(26.9
    	
)
    	
22.2
    	
 
    
	
Other comprehensive   income (loss) from equity investees
    	
 
    	
(2.2
    	
)
    	
1.3
    	
 
    
	
Total   other comprehensive loss (OCI), net of taxes (note 19)
    	
 
    	
(206.0
    	
)
    	
(28.4
    	
)
    
	
Comprehensive   income (loss) attributable to controlling interests and non-controlling   interests, net of taxes
    	
 
    	
$
    	
(106.1
    	
)
    	
$
    	
185.0
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Comprehensive   income (loss) attributable to:
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Non-controlling   interests
    	
 
    	
$
    	
8.3
    	
 
    	
$
    	
9.9
    	
 
    
	
Controlling   interests
    	
 
    	
(114.4
    	
)
    	
175.1
    	
 
    
	
 
    	
 
    	
$
    	
(106.1
    	
)
    	
$
    	
185.0
    	
 
    

 

See accompanying notes to the Consolidated Financial Statements.

 

6

 

Consolidated Statements of Equity

 

	
For the year ended December 31 ($ millions)
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Common   shares (note 21)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Balance,   beginning of year
    	
 
    	
$
    	
3,773.4
    	
 
    	
$
    	
3,168.1
    	
 
    
	
Shares issued   for cash on exercise of options
    	
 
    	
6.5
    	
 
    	
9.3
    	
 
    
	
Shares issued   under DRIP (1)
    	
 
    	
236.3
    	
 
    	
173.6
    	
 
    
	
Deferred taxes   on share issuance costs
    	
 
    	
(8.3
    	
)
    	
0.2
    	
 
    
	
Shares issued on   public offering, net of issuance costs
    	
 
    	
—
    	
 
    	
422.2
    	
 
    
	
Balance, end of   year
    	
 
    	
$
    	
4,007.9
    	
 
    	
$
    	
3,773.4
    	
 
    
	
Preferred   shares (note 21)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Balance,   beginning of year
    	
 
    	
$
    	
985.1
    	
 
    	
$
    	
985.1
    	
 
    
	
Series K   Issued
    	
 
    	
293.4
    	
 
    	
—
    	
 
    
	
Deferred taxes   on share issuance costs
    	
 
    	
(0.8
    	
)
    	
—
    	
 
    
	
Balance, end of   year
    	
 
    	
$
    	
1,277.7
    	
 
    	
$
    	
985.1
    	
 
    
	
Contributed   surplus
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Balance, beginning   of year
    	
 
    	
$
    	
17.4
    	
 
    	
$
    	
16.7
    	
 
    
	
Share options   expense
    	
 
    	
1.4
    	
 
    	
1.6
    	
 
    
	
Exercise of   share options
    	
 
    	
(0.5
    	
)
    	
(0.7
    	
)
    
	
Forfeiture of   share options
    	
 
    	
(0.1
    	
)
    	
(0.2
    	
)
    
	
Adoption of ASU   No. 2016-09 (note 2)
    	
 
    	
1.1
    	
 
    	
—
    	
 
    
	
Sale of   non-controlling interest (note 11)
    	
 
    	
3.0
    	
 
    	
—
    	
 
    
	
Balance, end of   year
    	
 
    	
$
    	
22.3
    	
 
    	
$
    	
17.4
    	
 
    
	
Accumulated   deficit
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Balance,   beginning of year
    	
 
    	
$
    	
(600.4
    	
)
    	
$
    	
(435.4
    	
)
    
	
Net income   applicable to controlling interests
    	
 
    	
91.6
    	
 
    	
203.5
    	
 
    
	
Common share   dividends
    	
 
    	
(362.4
    	
)
    	
(320.4
    	
)
    
	
Preferred share   dividends
    	
 
    	
(61.3
    	
)
    	
(48.1
    	
)
    
	
Adoption of ASU   No. 2016-09 (note 2)
    	
 
    	
(1.1
    	
)
    	
—
    	
 
    
	
Balance, end of   year
    	
 
    	
$
    	
(933.6
    	
)
    	
$
    	
(600.4
    	
)
    
	
AOCI (note 19)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Balance,   beginning of year
    	
 
    	
$
    	
405.1
    	
 
    	
$
    	
433.5
    	
 
    
	
Other   comprehensive loss
    	
 
    	
(206.0
    	
)
    	
(28.4
    	
)
    
	
Balance, end of   year
    	
 
    	
$
    	
199.1
    	
 
    	
$
    	
405.1
    	
 
    
	
Total   shareholders’ equity
    	
 
    	
$
    	
4,573.4
    	
 
    	
$
    	
4,580.6
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Non-controlling   interests
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Balance,   beginning of year
    	
 
    	
$
    	
34.8
    	
 
    	
$
    	
34.9
    	
 
    
	
Net income   applicable to non-controlling interests
    	
 
    	
8.3
    	
 
    	
9.9
    	
 
    
	
Sale of   non-controlling interest (note 11)
    	
 
    	
20.0
    	
 
    	
—
    	
 
    
	
Contributions   from non-controlling interests to subsidiaries
    	
 
    	
11.0
    	
 
    	
—
    	
 
    
	
Distributions by   subsidiaries to non-controlling interests
    	
 
    	
(8.3
    	
)
    	
(10.0
    	
)
    
	
Balance, end of   year
    	
 
    	
65.8
    	
 
    	
34.8
    	
 
    
	
Total   equity
    	
 
    	
$
    	
4,639.2
    	
 
    	
$
    	
4,615.4
    	
 
    

 

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

 

See accompanying notes to the Consolidated Financial Statements.

 

7

 

Consolidated Statements of Cash Flows

 

	
For the year ended December 31 ($ millions)
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Cash   from operations
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Net income after   taxes
    	
 
    	
$
    	
99.9
    	
 
    	
$
    	
213.4
    	
 
    
	
Items not   involving cash:
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Depreciation and   amortization (notes 6 and 7)
    	
 
    	
282.4
    	
 
    	
271.5
    	
 
    
	
Provisions on   assets (note 9)
    	
 
    	
139.6
    	
 
    	
—
    	
 
    
	
Accretion   expenses (notes 15 and 16)
    	
 
    	
10.9
    	
 
    	
11.0
    	
 
    
	
Share-based   compensation (note 21)
    	
 
    	
1.3
    	
 
    	
1.4
    	
 
    
	
Deferred income   tax expense (recovery) (note 17)
    	
 
    	
(64.0
    	
)
    	
8.4
    	
 
    
	
Losses (gains)   on sale of assets (notes 3 and 23)
    	
 
    	
2.7
    	
 
    	
(4.2
    	
)
    
	
Income from   equity investments (note 12)
    	
 
    	
(31.4
    	
)
    	
(3.4
    	
)
    
	
Unrealized   losses on risk management contracts (note 20)
    	
 
    	
62.5
    	
 
    	
11.4
    	
 
    
	
Unrealized gains   on long-term investments (note 23)
    	
 
    	
(3.6
    	
)
    	
(0.5
    	
)
    
	
Amortization of   deferred financing costs
    	
 
    	
16.9
    	
 
    	
2.7
    	
 
    
	
Other
    	
 
    	
(4.1
    	
)
    	
(0.2
    	
)
    
	
Asset retirement   obligations settled (note 15)
    	
 
    	
(4.0
    	
)
    	
(3.8
    	
)
    
	
Distributions   from equity investments
    	
 
    	
30.2
    	
 
    	
26.0
    	
 
    
	
Changes in   operating assets and liabilities (note 28)
    	
 
    	
5.9
    	
 
    	
(77.5
    	
)
    
	
 
    	
 
    	
$
    	
545.2
    	
 
    	
$
    	
456.2
    	
 
    
	
Investing   activities
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Business   acquisitions, net of cash acquired (note 3)
    	
 
    	
—
    	
 
    	
(20.0
    	
)
    
	
Acquisition of   property, plant and equipment
    	
 
    	
(473.0
    	
)
    	
(507.2
    	
)
    
	
Acquisition of   intangible assets
    	
 
    	
(20.3
    	
)
    	
(24.4
    	
)
    
	
Acquisition of   investment in a publicly traded entity
    	
 
    	
(7.0
    	
)
    	
—
    	
 
    
	
Contributions to   equity investments
    	
 
    	
(16.8
    	
)
    	
(20.2
    	
)
    
	
Loan to   affiliate, net of repayment (note 27)
    	
 
    	
(12.5
    	
)
    	
(62.5
    	
)
    
	
Change in   restricted cash holdings from customers
    	
 
    	
(4.2
    	
)
    	
0.2
    	
 
    
	
Investment in   Petrogas preferred shares (note 12)
    	
 
    	
—
    	
 
    	
(150.0
    	
)
    
	
Payment for   derivative contracts
    	
 
    	
(36.0
    	
)
    	
—
    	
 
    
	
Proceeds from   disposition of assets, net of transaction costs (note 3)
    	
 
    	
70.5
    	
 
    	
31.9
    	
 
    
	
 
    	
 
    	
$
    	
(499.3
    	
)
    	
$
    	
(752.2
    	
)
    
	
Financing   activities
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Net issuance   (repayment) of short-term debt
    	
 
    	
(74.2
    	
)
    	
1.4
    	
 
    
	
Issuance of   long-term debt, net of debt issuance costs
    	
 
    	
758.1
    	
 
    	
674.5
    	
 
    
	
Repayment of   long-term debt
    	
 
    	
(861.6
    	
)
    	
(884.3
    	
)
    
	
Dividends -   common shares
    	
 
    	
(359.6
    	
)
    	
(315.3
    	
)
    
	
Dividends -   preferred shares
    	
 
    	
(61.3
    	
)
    	
(49.2
    	
)
    
	
Distributions to   non-controlling interest
    	
 
    	
(8.3
    	
)
    	
(10.0
    	
)
    
	
Contributions   from non-controlling interests
    	
 
    	
11.0
    	
 
    	
—
    	
 
    
	
Net proceeds   from shares issued on exercise of options
    	
 
    	
6.0
    	
 
    	
8.5
    	
 
    
	
Net proceeds   from issuance of common shares
    	
 
    	
236.3
    	
 
    	
595.8
    	
 
    
	
Net proceeds   from issuance of preferred shares
    	
 
    	
293.4
    	
 
    	
—
    	
 
    
	
Proceeds from sale   of non-controlling interest
    	
 
    	
24.1
    	
 
    	
—
    	
 
    
	
Other
    	
 
    	
(1.9
    	
)
    	
—
    	
 
    
	
 
    	
 
    	
$
    	
(38.0
    	
)
    	
$
    	
21.4
    	
 
    
	
Change   in cash and cash equivalents
    	
 
    	
7.9
    	
 
    	
(274.6
    	
)
    
	
Effect   of exchange rate changes on cash and cash equivalents
    	
 
    	
0.4
    	
 
    	
0.2
    	
 
    
	
Cash   and cash equivalents, beginning of year
    	
 
    	
19.0
    	
 
    	
293.4
    	
 
    
	
Cash   and cash equivalents, end of year
    	
 
    	
$
    	
27.3
    	
 
    	
$
    	
19.0
    	
 
    

 

See accompanying notes to the Consolidated Financial Statements.

 

8

 

Notes to the Consolidated Financial Statements

 

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

 

1.  ORGANIZATION AND OVERVIEW OF THE BUSINESS

 

The businesses of AltaGas Ltd. (AltaGas or Corporation) are operated by AltaGas and a number of its subsidiaries including, without limitation, AltaGas Services (U.S.) Inc.; in regards to the gas business, AltaGas Extraction and Transmission Limited Partnership, AltaGas Pipeline Partnership, AltaGas Processing Partnership, AltaGas Northwest Processing Limited Partnership and Harmattan Gas Processing Limited Partnership; in regards to the power business, Coast Mountain Hydro Limited Partnership, Blythe Energy Inc. (Blythe), and AltaGas San Joaquin Energy Inc.; and, in regards to the utility business, AltaGas Utilities Inc. (AUI), Heritage Gas Limited (Heritage Gas), Pacific Northern Gas Ltd. (PNG), and SEMCO Energy, Inc. (SEMCO). SEMCO conducts its Michigan natural gas distribution business under the name SEMCO Energy Gas Company (SEMCO Gas) and its Alaska natural gas distribution business under the name ENSTAR Natural Gas Company (ENSTAR).

 

AltaGas, a Canadian corporation, is a North American diversified energy infrastructure business with a focus on owning and operating assets to provide clean and affordable energy to its customers. AltaGas has three business segments: Gas, Power and Utilities.

 

AltaGas’ Gas segment serves producers in the Western Canada Sedimentary Basin (WCSB) and includes natural gas gathering and processing, natural gas liquids (NGL) extraction and fractionation, gas transmission, gas storage, natural gas and NGL marketing, and the one-third ownership investment, through AltaGas Idemitsu Joint Venture Limited Partnership (AIJVLP), in Petrogas Energy Corp. (Petrogas).

 

The Power segment includes 1,708 MW of gross capacity from natural gas-fired, hydro, wind, and biomass generation facilities, and energy storage assets in Canada and the United States (U.S.).

 

The Utilities segment is predominantly comprised of natural gas distribution rate regulated utilities in Canada and the United States. The utilities are generally allowed the opportunity to earn regulated returns that provide for recovery of costs and a return on, and of, capital from the regulator-approved capital investment base.

 

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

BASIS OF PRESENTATION

 

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

 

Pursuant to National Instrument 52-107, “Acceptable Accounting Principles and Auditing Standards” (NI 52-107), U.S. GAAP reporting is generally permitted by Canadian securities laws for companies subject to reporting obligations under U.S. securities laws. However, given that AltaGas is not subject to such reporting obligations and could not therefore rely on the provisions of NI 52-107 to that effect, AltaGas sought and obtained exemptive relief by the securities regulators in Alberta and Ontario to permit it to prepare its financial statements in accordance with U.S. GAAP. The Alberta Securities Commission exemption will terminate on or after the earlier of January 1, 2024, the date to which AltaGas ceases to have activities subject to rate regulation, or the effective date prescribed by the International Accounting Standards Board for the mandatory application of a standard within the International Financial Reporting Standard for entities with activities subject to rate-regulated accounting.

 

PRINCIPLES OF CONSOLIDATION

 

These Consolidated Financial Statements of AltaGas include the accounts of the Corporation, its subsidiaries, variable interest entities (VIEs) for which the Corporation is the primary beneficiary, and its interest in various partnerships and joint ventures

 

9

 

where AltaGas has an undivided interest in the assets and liabilities. Investments in unconsolidated companies that AltaGas has significant influence over, but not control, are accounted for using the equity method.

 

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

 

USE OF ESTIMATES AND MEASUREMENT UNCERTAINTY

 

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

 

SIGNIFICANT ACCOUNTING POLICIES

 

Rate-Regulated Operations

 

SEMCO Gas, ENSTAR, AUI, PNG, and Heritage Gas (collectively Utilities) engage in the delivery and sale of natural gas and are regulated by the Michigan Public Service Commission (MPSC), Regulatory Commission of Alaska (RCA), Alberta Utilities Commission (AUC), British Columbia Utilities Commission (BCUC), and the Nova Scotia Utility and Review Board (NSUARB), respectively.

 

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

 

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

 

Cash and Cash Equivalents

 

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

 

Restricted Cash Holdings from Customers

 

Cash deposited, which is restricted and is not available for general use by AltaGas, is separately presented as restricted cash holdings in the Consolidated Balance Sheets.

 

10

 

Accounts Receivable

 

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

 

Inventory

 

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

 

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

 

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

 

The U.S. utilities include in depreciation expense an amount allowed for regulatory purposes to be collected in current rates for future removal and site restoration costs. The Canadian utilities that collect future removal and site restoration costs in rates defer the revenue until the costs are incurred.

 

Interest costs are capitalized on major additions to property, plant, and equipment until the asset is ready for its intended use. The interest rate used for calculating the interest costs to be capitalized is based on AltaGas’ prior quarter actual borrowing long-term interest rate.

 

Utilities capitalize an imputed carrying cost on assets during construction as authorized by regulatory authorities and the amount so capitalized is an allowance for funds used during construction (AFUDC). AFUDC is the amount that a rate regulated enterprise is allowed to recover for its cost of financing assets under construction. Capitalized overhead, administrative expenses and AFUDC are included in the cost of the related assets and are recovered in rates charged to customers through depreciation expense, as allowed by the regulators.

 

The range of useful lives for AltaGas’ PP&E is as follows:

 

	
Gas assets
    	
 
    	
3 - 45 years
    
	
Power generation assets
    	
 
    	
2 - 120 years
    
	
Utilities assets
    	
 
    	
3 - 80 years
    
	
Corporate assets
    	
 
    	
1-7 years
    

 

As required by the respective regulatory authorities, net additions to utility assets at Heritage Gas and PNG are not depreciated until the year after they are brought into active service. Net additions to SEMCO’s utility assets are amortized for one half year in the year in which they are brought into active service. Net additions to AUI’s utility assets are amortized in the month they are brought into active service.

 

Generally, when a regulated asset is retired or disposed of, there is no gain or loss recorded in the Consolidated Statement of Income. Any difference between the cost and accumulated depreciation of the asset, net of salvage proceeds, is charged to accumulated depreciation or another regulatory asset or liability account. It is expected that any gain or loss that is charged to accumulated depreciation or another regulatory account will be reflected in future depreciation expense when it is refunded or collected in rates. When a non-regulated asset is retired or disposed of from PP&E, the original cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in the Consolidated Statement of Income.

 

11

 

Leases are classified as either capital or operating. Leases that transfer substantially all the benefits and risks of ownership of property to AltaGas are accounted for as capital leases.

 

Intangible Assets

 

Intangible assets are recorded at cost. Intangible assets which have a finite useful life are amortized on a straight-line basis over their term or estimated useful life. The range of useful lives for intangible assets with a finite life is as follows:

 

	
Energy services relationships
    	
 
    	
15 -19 years
    
	
Electricity service agreements
    	
 
    	
2 - 60 years
    
	
Software
    	
 
    	
3 - 10 years
    
	
Land rights
    	
 
    	
5 - 64 years
    
	
Franchises and consents
    	
 
    	
9 - 25 years
    
	
Extraction and Transmission (E&T) Contracts
    	
 
    	
15 - 25 years
    

 

Assets Held for Sale

 

The Corporation classifies assets as held for sale when the carrying amount will be recovered through a sale transaction rather than through continuing use. This condition is met when Management approves and commits to a formal plan to sell the assets, the assets are available for immediate sale in their present condition, and Management expects the sale to close within the next 12 months. Upon classifying an asset as held for sale, an asset is recorded at the lower of its carrying value or the estimated fair value less cost to sell. Assets held for sale are not depreciated or amortized.

 

Business Acquisitions

 

Business acquisitions are accounted for using the acquisition method. Under the acquisition method, assets and liabilities of the acquired entity are recorded at fair value at the date of acquisition. Acquisition-related costs are expensed as incurred. Goodwill represents the excess of purchase price over the fair value of the net assets acquired.

 

Provision on Assets

 

If facts and circumstances suggest that a long-lived asset or an intangible asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset is not recoverable, as determined by the projected undiscounted cash flows related to the asset over its remaining life, then the carrying value of the asset is reduced to its estimated fair value and an impairment loss is recognized.

 

Goodwill is not subject to amortization, but assessed at least annually for impairment, or more often when events or changes in circumstances indicate that goodwill may be impaired. The annual assessment of goodwill is performed at the reporting unit level, which is an operating segment or one level below. The Corporation has the option to first assess qualitative factors to determine whether events or changes in circumstances indicate that the goodwill may be impaired. If a quantitative impairment test is performed, the first step of the two-step impairment test is to compare the fair value of the reporting unit to its carrying value (including goodwill). If the carrying value of the reporting unit exceeds the fair value, goodwill is reduced to its implied fair value and an impairment loss would be recorded in the Consolidated Statement of Income.

 

Development Costs

 

AltaGas expenses development costs as incurred unless such development costs meet certain criteria related to technical, market, regulatory and financial feasibility for capitalization. Development costs are examined annually to ensure capitalization criteria continue to be met. When the criteria that previously justified the deferral of costs are no longer met, the unamortized balance is taken as a charge to income in the period when this determination is made. Development costs are amortized based on the expected period of benefit, beginning at the commencement of commercial operations.

 

Investments Accounted for by the Equity Method

 

The equity method of accounting is used for investments in which AltaGas has the ability to exercise significant influence, but does not have a controlling interest. Equity investments are initially measured at cost and are adjusted for the Corporation’s

 

12

 

proportionate share of earnings or losses. Equity investments are increased for contributions made and decreased for distributions received. To the extent an investee undertakes activities necessary to commence its planned principal operations, the Corporation will capitalize interest costs associated with its investment during such period.

 

An equity method investment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the investment may not be recoverable. When such condition is deemed other than temporary, the carrying value of the investment is written down to its fair value, and an impairment charge is recorded in the Consolidated Statement of Income.

 

Financial Instruments

 

All financial instruments are initially recorded at fair value unless they qualify for, and are designated under, a normal purchase and normal sale (NPNS) exemption. Subsequent measurement of the financial instruments is based on their classification. The financial assets are classified as “held-for-trading”, “held-to-maturity”, “loans and receivables”, or “available-for-sale”. Financial liabilities are classified as “held-for-trading” or other financial liabilities. Subsequent measurement is determined by classification.

 

A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to AltaGas’ business needs and AltaGas has the ability, and intent, to deliver or take delivery of the underlying item. AltaGas continually assesses the contracts designated under the NPNS exemption and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met.

 

Held-for-trading financial assets and liabilities may consist of swaps, options, forwards and equity securities. These financial instruments are initially recorded at their fair value, with subsequent changes in fair value recorded in net income under “unrealized gains and losses from risk management contracts” or “other income (loss)”. Held-to-maturity, loans and receivables, and other financial liabilities are recognized at amortized cost using the effective interest method.

 

The available-for-sale classification includes non-derivative financial assets that are designated as available-for-sale or are not included in the other three classifications. Available-for-sale instruments are initially recorded at fair value, and changes to fair value are recorded through “Other comprehensive income” (OCI). Declines in fair value below the amortized cost basis that are other than temporary are reclassified out of OCI to earnings for the period.

 

Investments in equity instruments not accounted for under the equity method that do not have a quoted market price in an active market are measured at cost. Income earned from these investments is included in the Consolidated Statement of Income under “Other income (loss)”.

 

Derivatives embedded in other financial instruments or contracts (the host instrument) are recorded separately and are measured at fair value if the economic characteristics of the embedded derivative are not closely related to the host instrument, the terms of the embedded derivative are the same as those of a standalone derivative and the entire contract is not held-for-trading or accounted for at fair value. Changes in fair value are included in earnings.

 

The fair values recorded on the Consolidated Balance Sheet reflect netting of the asset and liability positions where counterparty master netting arrangements contain provisions for net settlement.

 

Transaction costs related to the acquisition of held-for-trading financial assets and liabilities are expensed as incurred.

 

Transaction costs for obtaining debt financing other than line-of-credit arrangements are recognized as a direct deduction from the related debt liability on the Consolidated Balance Sheet. Transaction costs related to line-of-credit arrangements are capitalized and included under “Long-term investments and other assets” on the Consolidated Balance Sheet. Premiums and discounts are netted against long-term debt on the Consolidated Balance Sheets. The deferred charges are amortized over the life of the related debt on an effective interest basis and included in “Interest expense” on the Consolidated Statement of Income.

 

13

 

Asset Retirement Obligations

 

AltaGas recognizes asset retirement obligations in the period in which the legal obligation is incurred and a reasonable estimate of fair value can be determined. The associated asset retirement costs are capitalized as part of the carrying amount of the asset and are depreciated over the estimated useful life of the asset. The liability is increased due to the passage of time over the estimated period until the settlement of the obligation, with a corresponding charge to accretion expense for asset retirement obligations.

 

Certain utility assets will have future legal obligations on retirement, but an asset retirement obligation has not been recorded due to its indeterminate life and corresponding indeterminable timing and scope of these asset retirement obligations. The U.S. Utilities recognize asset retirement obligations for some interim retirements, as expected by their regulators, whereas Canadian Utilities do not.

 

Revenue Recognition

 

The Utilities reporting segment recognizes revenue, presented as “revenue from regulated operations” in the Consolidated Statement of Income, when the product or services are delivered on the basis of regular meter readings or estimates of usage and is consistent with the underlying rate setting mechanism mandated by the applicable regulatory authority. The Utilities reporting segment bills gas distribution customers monthly, on a cycle basis and accrues revenue for service rendered to its customers but not billed at month-end. Storage customers are billed monthly for services provided in the preceding month and revenue is accrued for services rendered but not billed at month end.

 

Revenue from services represents the proceeds from operating leases in the Gas and Power reporting segments where AltaGas is the lessor, and fees from the gathering, transportation, processing, and marketing of natural gas. Revenue from services are recognized at the time the service is rendered.

 

Revenue from sales represents the proceeds from the commodity sales in the Gas and Power reporting segments and are recognized at the time the product is delivered.

 

Foreign Currency Translation

 

Monetary assets and liabilities denominated in a foreign currency are converted to the functional currency using the exchange rate in effect at the balance sheet date. Adjustments resulting from the conversion are recorded in the Consolidated Statement of Income. Non-monetary assets and liabilities are converted at the historical exchange rate in effect at the transaction date. Revenues and expenses are converted at the exchange rate applicable at the transaction date.

 

For foreign entities with a functional currency other than Canadian dollars, AltaGas’ reporting currency, assets, and liabilities are translated into Canadian dollars at the rate in effect at the reporting date. Revenues and expenses are translated at average exchange rates during the reporting period. All adjustments resulting from the translation of the foreign operations are recorded in OCI.

 

AltaGas may designate some of its U.S. dollar denominated long-term debt as a foreign currency hedge of its investment in foreign operations. Accordingly, foreign exchange gains and losses, from the dates of designation, on the translation of the U.S. dollar denominated long-term debt are included in OCI.

 

Share Options and Other Compensation Plans

 

Share options granted are recorded using fair value. Compensation expense is measured at the date of the grant using the Black-Scholes-Merton model and is recognized over the vesting period of the options. Consideration received by AltaGas on exercise of the share options is credited to shareholders’ equity.

 

AltaGas has a medium-term incentive plan (MTIP) for employees and executive officers which includes two types of awards: restricted units (RUs) and performance units (PUs). Both RUs and PUs are valued based on the dividends declared during the vesting period and the weighted average share price of AltaGas’ common shares multiplied by the units outstanding at the end of the vesting period. Upon vesting, the RUs and PUs are paid in cash or, at the election of AltaGas, its equivalent in common

 

14

 

shares purchased from the market. The PUs are also subject to a performance multiplier ranging from 0 to 2 dependent on the Corporation’s performance relative to performance targets agreed between the Corporation and the employees. Compensation expense is recognized using the liability method and is recorded as operating and administrative expense over the vesting period. A change in value of the RUs or PUs is recognized in the period the change occurs.

 

In addition, AltaGas has a deferred share unit plan (DSUP) for directors, officer and employees as an additional form of long-term variable compensation incentive. Although the DSUP is available to directors, officers and employees, AltaGas currently only grants deferred share units (DSUs) under the DSUP as a form of director compensation. The DSUs granted are fully vested upon being credited to a participant’s account, and the participant is entitled to payment at his or her termination date, and payment is not subject to satisfaction of any requirements as to any minimum period of membership or employment or other conditions. DSUs are accounted for at fair value. Compensation expense is determined based on the fair value of the DSUs on the date of the grant and fluctuations in fair value are recognized in the period the change occurs.

 

Pension Plans and Post-Retirement Benefits

 

AltaGas maintains defined benefit pension plans, defined contribution plans, and other post-retirement benefit plans for eligible employees. Contributions made by the Corporation to the defined contribution plans are expensed in the period in which the contribution occurs.

 

The cost of defined benefit pension plans and post-retirement benefits is actuarially determined using the projected benefit method prorated based on service and Management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected health care costs. Pension plan assets are measured at fair value. The expected return on plan assets is based on historical and projected rates of return for each asset class in the plan portfolio. The projected benefit obligation is discounted using the market interest rate on high-quality debt instruments with cash flows matching the timing and amount of benefit payments. Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation and the fair value of plan assets along with any unamortized past service costs are amortized on a straight-line basis over the expected average remaining service life of active employees. The expected average remaining service period of the active members covered by the defined benefit pension plans and post-retirement benefit plans is 12.7 years and 13.5 years, respectively.

 

AltaGas recognizes the overfunded or underfunded status of its pension and post-retirement benefit plans as either assets or liabilities in the Consolidated Balance Sheet. Unrecognized actuarial gains and losses and past service costs and credits that arise during the period are recognized in OCI.

 

For certain regulated Utilities, the Corporation expects to recover pension expense in future rates and therefore records actuarial gains and losses as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the expected average remaining service life of active employees.

 

Income Taxes

 

Income taxes for the Corporation and its subsidiaries are calculated using the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are determined based on differences between the carrying value and the tax basis of assets and liabilities and are measured using the enacted tax rates and laws that are in effect in the periods in which the differences are expected to be settled or realized. Deferred income tax assets are routinely reviewed and a valuation allowance is recorded to reduce the deferred tax assets if it is more likely than not that deferred tax assets will not be realized. The financial statement effects of an uncertain tax position are recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxing authority. The current and deferred tax impact is equal to the largest amount, considering possible settlement outcomes, that is greater than 50 percent likely of being realized upon settlement with the taxing authorities.

 

Investment tax credits are deferred and amortized over the estimated service lives of the related properties.

 

15

 

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

 

Net Income per Share

 

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

 

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

 

Contingencies

 

Liabilities for loss contingencies arising from claims, assessments, litigation and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Any such accruals are adjusted thereafter as additional information becomes available or circumstances change.

 

ADOPTION OF NEW ACCOUNTING STANDARDS

 

Effective January 1, 2017, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU):

 

·                  ASU No. 2015-11 “Inventory: Simplifying the Measurement of Inventory”. The amendments in this ASU require an entity to measure inventory at the lower of cost and net realizable value. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

 

·                  ASU No. 2016-05 “Derivatives and Hedging: Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships”. The amendments in this ASU clarify that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument under Topic 815 does not, in and of itself, require de-designation of that hedging relationship provided that all other hedge accounting criteria continue to be met. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

 

·                  ASU No. 2016-06, “Derivatives and Hedging: Contingent Put and Call Options in Debt Instruments”. The amendments in this ASU clarify the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

 

·                  ASU No. 2016-07 “Investments - Equity Method and Joint Ventures Investments: Simplifying the Transition to the Equity Method of Accounting”. The amendments in this ASU eliminate the requirement to retrospectively apply the equity method as a result of an increase in the level of ownership interest or degree of influence. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and

 

·                  ASU No. 2016-09 “Stock Compensation: Improvements to Employee Share-Based Payment Accounting”. The amendments in this ASU focus on simplifying several areas of the accounting for share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory withholding requirements, as well as the classification on the statement of cash flow. Upon adoption of this ASU, AltaGas elected as an accounting policy to account for forfeitures when they occur instead of estimating the number of awards that are expected to vest. The ASU requires this change to be adopted using the modified retrospective approach and as a result, AltaGas recorded a decrease to accumulated retained earnings of approximately $1 million and an increase to contributed surplus of

 

16

 

approximately $1 million. The deferred tax impact was immaterial. The remaining amendments to this ASU did not have a material impact on AltaGas’ consolidated financial statements.

 

FUTURE CHANGES IN ACCOUNTING PRINCIPLES

 

In May 2014, FASB issued ASU No. 2014-09 “Revenue from Contracts with Customers”, which will replace numerous requirements in U.S. GAAP, including industry-specific requirements, and provide companies with a single revenue recognition model for recognizing revenue from contracts with customers. The core principle of the amendments in this ASU is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The amendments specify various disclosure requirements that would enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. In March 2016, FASB issued ASU No. 2016-08 “Principal versus Agent Consideration”. The amendments in this ASU clarify the implementation guidance on the principal versus agent considerations in the new revenue recognition standard. In April 2016, FASB issued ASU No. 2016-10 “Identifying Performance Obligation and Licensing”, which reduces the complexity when applying the guidance for identifying performance obligations and improves the operability and understandability of the license implementation guidance. In May 2016, FASB issued ASU No. 2016-12 “Narrow Scope Improvements and Practical Expedients”, clarifying several implementation issues, including collectability, presentation of sales taxes, non-cash consideration, contract modification, completed contracts, and transition. In December 2016, FASB issued ASU No. 2016-20 “Technical Corrections and Improvements”, which makes minor technical corrections and improvements to the new revenue standard. The new revenue standard will be effective for annual and interim periods beginning on or after December 15, 2017. The ASU permits the use of either the full retrospective or modified retrospective transition method and AltaGas has elected the modified retrospective transition method. In 2016, AltaGas established a cross-functional implementation team consisting of representatives from across all the operating segments. A scoping exercise was completed for each of AltaGas’ operating segments and AltaGas selected all material contracts or contract groups for review to identify potential impacts under the new standard. AltaGas has completed the contracts review and have not identified any material changes in how revenues are recognized under the new standard. AltaGas has started a process to compile the information needed to meet the new disclosure requirements and noted that there will be changes to the revenue disclosures based on additional requirements under the new standard regarding the disaggregation of revenue as well as details about performance obligations, and contracts assets and liabilities.

 

In January 2016, FASB issued ASU No. 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” which revises an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. It also amends certain disclosure requirements associated with the fair value of financial instruments. The amendments in this ASU are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Upon adoption, entities will be required to make a cumulative-effect adjustment to the statement of financial position as of the beginning of the first reporting period in which the guidance is effective. The guidance on equity securities without readily determinable fair value will be applied prospectively to all equity investments that exist as of the date of adoption of the standard. Upon adoption, AltaGas will no longer be able to classify equity securities with readily determinable fair values as available-for-sale and any changes in fair value will be reported through earnings instead of other comprehensive income. The remaining provisions of this ASU are not expected to have a material impact on AltaGas’ financial statements.

 

In February 2016, FASB issued ASU No. 2016-02 “Leases”, which requires lessees to recognize on the balance sheet a right-of-use asset and a lease liability for all leases with lease terms greater than 12 months. Lessor accounting remains substantially unchanged, however, the ASU modifies what qualifies as a sales-type and direct financing lease and eliminates the real estate-specific provisions included in ASC 840. The ASU also requires additional disclosures regarding leasing arrangements. In January 2018, FASB issued ASU No. 2018-01 “Land Easement Practical Expedient for Transition to Topic 842” providing entities with an optional election not to evaluate existing and expired land easements not previously accounted for as leases under ASC 840 using the provisions of ASC 842. The amendments to the new leases standard are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective

 

17

 

approach. AltaGas is currently performing a scoping exercise by gathering a complete inventory of lease contracts in order to evaluate the impact of adopting ASC 842 on its consolidated financial statements, but expects that the new standard will have an impact on the Corporation’s balance sheet as all operating leases will need to be reflected on the balance sheet upon adoption. In addition, AltaGas currently expects to utilize the transition practical expedients which allow entities to not have to reassess whether an arrangement contains a lease under the provisions of ASC 842.

 

In June 2016, FASB issued ASU No. 2016-13 “Financial Instruments — Credit Losses: Measurement of Credit Losses on Financial Instruments”. The amendments in this ASU replace the current “incurred loss” impairment methodology with an “expected loss” model for financial assets measured at amortized cost. The amendments in this ASU are effective for fiscal periods beginning after December 15, 2020, and interim periods within those fiscal periods. Early adoption is permitted. AltaGas is currently assessing the impact of this ASU on its consolidated financial statements.

 

In August 2016, FASB issued ASU No. 2016-15 “Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments”. The amendments in this ASU clarify the classification of certain cash flow transactions on the statement of cash flow. The amendments in this ASU are effective for fiscal periods beginning after December 15, 2017, and interim periods within those fiscal periods. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

 

In October 2016, FASB issued ASU No. 2016-16 “Income Taxes: Intra-Entity Transfers of Assets Other Than Inventory”. The amendments in this ASU revise the accounting for income tax consequences on intra-entity transfers of assets by requiring an entity to recognize current and deferred tax on intra-entity transfers of assets other than inventory when the transfer occurs. The amendment in this ASU is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. An entity should apply the amendments in this ASU on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

 

In November 2016, FASB issued ASU No. 2016-18 “Statement of Cash Flows: Restricted Cash”. The amendments in this ASU require those amounts deemed to be restricted cash and restricted cash equivalents to be included in the cash and cash equivalents balance on the statement of cash flows. The amendments in this ASU are effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. An entity should apply the amendments in this ASU retrospectively to each period presented. Early adoption is also permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated cash flow statements.

 

In January 2017, FASB issued ASU No. 2017-01 “Business Combinations: Clarifying the Definition of a Business”. The amendments in this ASU change the definition of a business to assist entities with evaluating when a set of transferred assets and activities is a business. The amendments in this ASU are effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. An entity should apply the amendments in this ASU on a prospective basis on or after the effective date. AltaGas will apply the amendments prospectively.

 

In January 2017, FASB issued ASU No. 2017-04 “Intangibles — Goodwill and Other: Simplifying the Test for Goodwill Impairment”. The ASU removes Step 2 of the goodwill impairment test, eliminating the requirement to determine the fair value of individual assets and liabilities of a reporting unit to measure the goodwill impairment. An entity should adopt the amendments in this ASU for annual periods beginning after December 15, 2020, and interim periods within those annual periods. An entity should apply the amendments in this ASU on a prospective basis. Early adoption is permitted. AltaGas currently expects to apply the amendments prospectively.

 

In February 2017, FASB issued ASU No. 2017-05 “Other Income — Gains and Losses from the De-recognition of Nonfinancial Assets: Clarifying the Scope of Asset De-recognition Guidance and Accounting for Partial Sales of Nonfinancial Assets”. The amendments in this ASU clarify the scope of ASC 610-20 as well as the accounting for partial sales of nonfinancial assets. The effective date and transition requirements for the amendments in this ASU are the same as the effective date and transition

 

18

 

requirements for ASU No. 2014-09, which is effective for fiscal years and interim periods beginning on or after December 15, 2017. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

 

In March 2017, FASB issued ASU No. 2017-07 “Compensation — Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”. The amendments in this ASU revise the presentation of net periodic pension cost and net periodic postretirement benefit cost on the income statement and limit the components that are eligible for capitalization in assets to only the service cost component. The amendments in this ASU are effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. The amendments in this ASU should be applied retrospectively for the presentation of the service cost component and the other components of net benefit cost in the income statement and prospectively, on and after the effective date, for the capitalization of the service cost component. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

 

In May 2017, FASB issued ASU No. 2017-09 “Compensation — Stock Compensation: Scope of Modifications Accounting”. The amendments in this ASU provide guidance on the types of changes to the terms or conditions of share-based payment arrangements to which an entity would be required to apply modification accounting. The amendments in this ASU are effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. An entity should apply the amendments in this ASU on a prospective basis on or after the effective date. Early adoption is permitted. AltaGas will apply the amendments prospectively.

 

In August 2017, FASB issued ASU No. 2017-12 “Derivatives and Hedging — Targeted Improvements to Accounting for Hedging Activities”. The amendments in this ASU improves the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and make certain targeted improvements to simplify the application of hedge accounting. The amendments in this ASU are effective for annual periods beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

 

3.  ACQUISITIONS AND DISPOSITIONS

 

Pending Acquisition of WGL Holdings, Inc. (WGL)

 

On January 25, 2017, the Corporation entered into the Merger Agreement to indirectly acquire WGL. Pursuant to the Merger Agreement, following the consummation of the WGL Acquisition, WGL common shareholders will receive US$88.25 per common share in cash, which represents a total enterprise value of approximately US$7.2 billion, including the assumption of approximately US$2.7 billion of debt as at December 31, 2017.

 

WGL is a diversified energy infrastructure company and the sole common shareholder of Washington Gas, a regulated natural gas utility headquartered in Washington, D.C., serving approximately 1.2 million customers in Maryland, Virginia, and the District of Columbia. WGL has a growing midstream business with investments in natural gas gathering infrastructure and regulated gas pipelines in the Marcellus/Utica gas formation located in the northeast United States, with capabilities for connections to marine-based energy export opportunities via the North American Atlantic coast through the Cove Point LNG Terminal in Maryland being developed by a third party, which is currently in the final stages of commissioning. WGL also owns contracted clean power assets, with a focus on distributed generation and energy efficiency assets throughout the United States. In addition, WGL has a retail gas and power marketing business with approximately 222,000 customers in Maryland, Virginia, Delaware, Pennsylvania and the District of Columbia. Upon completion of the WGL Acquisition, AltaGas expects that it will have over $22 billion of assets and approximately 1.8 million rate regulated gas customers.

 

Consummation of the WGL Acquisition is subject to certain closing conditions, including certain regulatory and government approvals, including approval by the Public Service Commission of the District of Columbia (PSC of DC), the Maryland Public Service Commission (PSC of MD), the Commonwealth of Virginia State Corporation Commission (SCC of VA), the United States Federal Energy Regulatory Commission (FERC), and the Committee on Foreign Investment in the United States (CFIUS), as well as expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (HSR Act).

 

19

 

Regulatory applications were filed with the PSC of DC, the PSC of MD, and the SCC of VA on April 24, 2017. On the same date, AltaGas and WGL also filed their voluntary Joint Notice to the CFIUS, and an application with FERC. On May 10, 2017, WGL common shareholders voted in favor of the Merger Agreement governing the proposed WGL Acquisition. On July 6, 2017, FERC approved the transaction, finding it to be consistent with the public interest. Also as of July 17, 2017, when the waiting period required by Section 7A(b)(1) of the HSR Act expired, the merger was deemed approved by the Federal Trade Commission and the Department of Justice, such approval being valid for one year. On July 28, 2017, CFIUS provided its approval for the WGL Acquisition. On October 20, 2017, the SCC of VA approved the WGL Acquisition. In Maryland, the hearing before the PSC of MD concluded on October 16, 2017, and on December 4, 2017 AltaGas and WGL announced that they had reached a settlement agreement with several of the intervenors in the Maryland proceeding. As a result, AltaGas and WGL filed a stipulation with the PSC of MD to extend the deadline for issuing its decision. The PSC of MD approved this request moving the date for a decision to on or before April 4, 2018. The hearing before the PSC of DC concluded on December 13, 2017, and a decision is expected to follow in the first half of 2018. On January 11, 2018, pursuant to the terms of the Merger Agreement, AltaGas elected to extend the Outside Date (as defined in the Merger Agreement) to July 23, 2018.

 

AltaGas believes that closing of the WGL Acquisition will occur in mid-2018. AltaGas plans to fund the WGL Acquisition with the proceeds from its aggregate $2.6 billion bought deal and private placement of subscription receipts, which closed in the first quarter of 2017 (see Subscription Receipts section below). In addition, AltaGas has US$3 billion available under its fully committed bridge facility, which can be drawn at the time of closing. With all funding required for the closing of the WGL Acquisition in place, AltaGas can evaluate and pursue its asset sale process in a prudent and timely fashion in step with the regulatory process and consistent with AltaGas’ long term strategic vision. Management has presently identified a total of over $4.0 billion of assets from AltaGas’ Gas, Power and Utilities business segments in respect of which it is evaluating various options for monetization that could include the sale of either minority and/or controlling interests. Management expects to realize over $2 billion from its asset sale process in 2018. With the present optionality available to AltaGas and in light of a number of factors including recent developments in the California Resource Adequacy markets, AltaGas has discontinued the previously announced sale process of its California power assets. AltaGas will instead continue to pursue other structuring and commercial opportunities to unlock the value of the California assets. Additional financing steps could include offerings of senior debt, hybrid securities, and equity-linked securities (including preferred shares), subject to prevailing market conditions.

 

Subscription Receipts

 

On February 3, 2017, the Corporation issued approximately 80.7 million subscription receipts pursuant to a private placement and public offering to partially fund the WGL Acquisition at a price of $31 each for total gross proceeds of approximately $2.5 billion. On March 3, 2017, the over-allotment option was partially exercised for an additional 3.8 million subscription receipts for gross proceeds of approximately $118 million. The sale of the additional subscription receipts pursuant to the over-allotment option brings the aggregate gross proceeds to approximately $2.6 billion. Each subscription receipt entitles the holder to automatically receive one common share upon closing of the WGL Acquisition. While the subscription receipts remain outstanding, holders will be entitled to receive cash payments (Dividend Equivalent Payments) per subscription receipt that are equal to dividends declared on each common share. Such Dividend Equivalent Payments will have the same record date as the related common share dividend and will be paid to holders of the subscription receipts concurrently with the payment date of each such common share dividend. The Dividend Equivalent Payments will be paid first out of any interest on the escrowed funds and then out of the escrowed funds. If the Merger Agreement is terminated after the common share dividend declaration date, but before the common share dividend record date, subscription receipt holders of record on the termination date shall receive a pro-rata payment of the dividend as the Dividend Equivalent Payment. If the Merger Agreement is terminated on a record date or following a record date but on or prior to the dividend payment date, holders will be entitled to receive the full Dividend Equivalent Payment.

 

The net proceeds from the sale of the subscription receipts are held by an escrow agent pending, among other things, receipt of all regulatory and government approvals required to finalize the WGL Acquisition and confirmation that the parties to the Merger Agreement are able to complete the WGL Acquisition in all material respects in accordance with the terms of the Merger Agreement, but for the payment of the purchase price, and AltaGas has available to it all other funds required to complete the

 

20

 

WGL Acquisition. If the escrow release notice and direction is not delivered on or prior to 5:00 pm (Calgary time) on September 4, 2018, the Corporation will be required to make a termination payment equal to the aggregate issue price of such holder’s subscription receipts plus any unpaid Dividend Equivalent Payments owing to such holders of subscription receipts.

 

Edmonton Ethane Extraction Plant (EEEP)

 

Effective January 1, 2016, AltaGas acquired the remaining 51 percent interest in EEEP for cash consideration of approximately $21.0 million, increasing its ownership interest to 100 percent. AltaGas accounted for the acquisition as a business combination achieved in stages and remeasured the previously held 49 percent interest in EEEP at fair value on the acquisition date using the discounted cash flow approach. The significant inputs included contracted cash flows for the facility, forecasted commodity prices, and projected operating costs based on historical pattern. No gain or loss was recorded as a result of the remeasurement. Upon the acquisition of control, AltaGas began consolidating the results of EEEP. Prior to the acquisition, AltaGas proportionately consolidated the 49 percent interest in EEEP.

 

Below is the final purchase price allocation:

 

	
Fair   value of net assets acquired
    	
 
    	
 
    	
 
    
	
Property, plant   and equipment
    	
 
    	
$
    	
67.1
    	
 
    
	
Asset retirement   obligations
    	
 
    	
(15.0
    	
)
    
	
Deferred income   taxes
    	
 
    	
(3.3
    	
)
    
	
 
    	
 
    	
$
    	
48.8
    	
 
    

 

The total estimated fair value of $48.8 million included $21.0 million of cash paid to acquire the remaining 51 percent interest and $27.8 million related to the previously held interest.

 

Dispositions

 

In March 2017, AltaGas completed the disposition of the Ethylene Delivery Systems (EDS) and the Joffre Feedstock Pipeline (JFP) transmission assets in the Gas segment to Nova Chemicals Corporation for gross proceeds of approximately $67.0 million. AltaGas recognized a pre-tax loss on disposition of approximately $3.4 million in the consolidated statement of income under the line item “Other income” for the year ended December 31, 2017 related to this disposition.

 

On February 29, 2016, AltaGas completed the disposition of certain non-core natural gas gathering and processing assets in the Gas segment to Tidewater Midstream and Infrastructure Ltd. (Tidewater) for total gross consideration of $30.0 million in cash and approximately 43.7 million of common shares of Tidewater valued at $1.48 per share (the Tidewater Gas Asset Disposition). The assets were located primarily in central and north central Alberta and totaled approximately 490 Mmcf/d of gross licensed natural gas processing capacity. AltaGas recognized a pre-tax gain on disposition of $4.5 million in the Consolidated Statement of Income under the line item “Other income” for the year ended December 31, 2016. In addition, AltaGas recorded a tax recovery of $10.3 million related to the asset sale for the year ended December 31, 2016.

 

21

 

4.  ASSETS HELD FOR SALE

 

	
As at
    	
 
    	
December 31,
   2017
    	
 
    	
December 31,
   2016
    	
 
    
	
Assets   held for sale
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Accounts   receivable
    	
 
    	
$
    	
0.3
    	
 
    	
$
    	
—
    	
 
    
	
Property, plant   and equipment
    	
 
    	
5.3
    	
 
    	
67.3
    	
 
    
	
Intangible   assets
    	
 
    	
0.1
    	
 
    	
—
    	
 
    
	
Goodwill
    	
 
    	
0.3
    	
 
    	
3.4
    	
 
    
	
 
    	
 
    	
$
    	
6.0
    	
 
    	
$
    	
70.7
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Liabilities   associated with assets held for sale
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Asset retirement   obligations
    	
 
    	
$
    	
0.3
    	
 
    	
$
    	
0.4
    	
 
    
	
 
    	
 
    	
$
    	
0.3
    	
 
    	
$
    	
0.4
    	
 
    

 

As at December 31, 2017, AltaGas committed to the sale of certain non-core facilities in the Gas segment in two separate transactions. Accordingly, the carrying value of the assets and liabilities were classified as held for sale. A pre-tax provision of $6.4 million on property, plant and equipment and a pre-tax provision of $0.2 million on allocated goodwill were recognized due to the reduction of the carrying value of the assets to fair value less costs to sell. Both transactions closed in early 2018.

 

In March 2017, AltaGas completed the sale of the EDS and JFP transmission assets in the Gas segment to Nova Chemicals Corporation that were presented as assets held for sale as at December 31, 2016. Please refer to Note 3 for further details.

 

5.  INVENTORY

 

	
As at
    	
 
    	
December 31,
   2017
    	
 
    	
December 31,
   2016
    	
 
    
	
Natural gas held   in storage
    	
 
    	
$
    	
133.9
    	
 
    	
$
    	
172.6
    	
 
    
	
Other inventory
    	
 
    	
67.2
    	
 
    	
48.4
    	
 
    
	
 
    	
 
    	
$
    	
201.1
    	
 
    	
$
    	
221.0
    	
 
    

 

6.  PROPERTY, PLANT AND EQUIPMENT

 

	
 
    	
 
    	
December 31, 2017
    	
 
    	
December 31, 2016
    	
 
    
	
As at
    	
 
    	
Cost
    	
 
    	
Accumulated
   amortization
    	
 
    	
Net book
   value
    	
 
    	
Cost
    	
 
    	
Accumulated
   amortization
    	
 
    	
Net book
   value
    	
 
    
	
Gas
    	
 
    	
$
    	
2,801.4
    	
 
    	
$
    	
(636.3
    	
)
    	
$
    	
2,165.1
    	
 
    	
$
    	
2,615.8
    	
 
    	
$
    	
(630.8
    	
)
    	
$
    	
1,985.0
    	
 
    
	
Power
    	
 
    	
2,874.8
    	
 
    	
(392.3
    	
)
    	
2,482.5
    	
 
    	
2,957.2
    	
 
    	
(232.1
    	
)
    	
2,725.1
    	
 
    
	
Utilities
    	
 
    	
2,245.4
    	
 
    	
(226.1
    	
)
    	
2,019.3
    	
 
    	
2,250.4
    	
 
    	
(193.5
    	
)
    	
2,056.9
    	
 
    
	
Corporate
    	
 
    	
65.9
    	
 
    	
(37.7
    	
)
    	
28.2
    	
 
    	
65.3
    	
 
    	
(30.1
    	
)
    	
35.2
    	
 
    
	
Reclassified to   assets held for sale (note 4)
    	
 
    	
(16.7
    	
)
    	
11.4
    	
 
    	
(5.3
    	
)
    	
(126.2
    	
)
    	
58.9
    	
 
    	
(67.3
    	
)
    
	
 
    	
 
    	
$
    	
7,970.8
    	
 
    	
$
    	
(1,281.0
    	
)
    	
$
    	
6,689.8
    	
 
    	
$
    	
7,762.5
    	
 
    	
$
    	
(1,027.6
    	
)
    	
$
    	
6,734.9
    	
 
    

 

Interest capitalized on long-term capital construction projects for the year ended December 31, 2017 was $10.8 million (2016 - $10.9 million).

 

As at December 31, 2017, the Corporation had approximately $269.5 million (December 31, 2016 - $183.4 million) of capital projects under construction that were not yet subject to amortization.

 

22

 

Depreciation expense related to property, plant and equipment (including assets under capital leases) for the year ended December 31, 2017 was $239.7 million (2016 - $229.3 million).

 

7.  INTANGIBLE ASSETS

 

	
 
    	
 
    	
December 31, 2017
    	
 
    	
December 31, 2016
    	
 
    
	
As at
    	
 
    	
Cost
    	
 
    	
Accumulated
   amortization
    	
 
    	
Net book
   value
    	
 
    	
Cost
    	
 
    	
Accumulated
   amortization
    	
 
    	
Net book
   value
    	
 
    
	
E&T   contracts
    	
 
    	
$
    	
26.6
    	
 
    	
$
    	
(13.4
    	
)
    	
$
    	
13.2
    	
 
    	
$
    	
53.7
    	
 
    	
$
    	
(39.2
    	
)
    	
$
    	
14.5
    	
 
    
	
Electricity   service agreements
    	
 
    	
603.1
    	
 
    	
(108.5
    	
)
    	
494.6
    	
 
    	
628.8
    	
 
    	
(37.2
    	
)
    	
591.6
    	
 
    
	
Energy services   relationships
    	
 
    	
10.2
    	
 
    	
(8.1
    	
)
    	
2.1
    	
 
    	
10.2
    	
 
    	
(7.4
    	
)
    	
2.8
    	
 
    
	
Software
    	
 
    	
126.8
    	
 
    	
(61.6
    	
)
    	
65.2
    	
 
    	
118.7
    	
 
    	
(45.6
    	
)
    	
73.1
    	
 
    
	
Land rights
    	
 
    	
11.0
    	
 
    	
(2.4
    	
)
    	
8.6
    	
 
    	
10.9
    	
 
    	
(2.2
    	
)
    	
8.7
    	
 
    
	
Franchises and   consents
    	
 
    	
7.4
    	
 
    	
(2.2
    	
)
    	
5.2
    	
 
    	
5.6
    	
 
    	
(2.0
    	
)
    	
3.6
    	
 
    
	
Reclassified to   assets held for sale (note 4)
    	
 
    	
(0.1
    	
)
    	
—
    	
 
    	
(0.1
    	
)
    	
(27.1
    	
)
    	
27.1
    	
 
    	
—
    	
 
    
	
 
    	
 
    	
$
    	
785.0
    	
 
    	
$
    	
(196.2
    	
)
    	
$
    	
588.8
    	
 
    	
$
    	
800.8
    	
 
    	
$
    	
(106.5
    	
)
    	
$
    	
694.3
    	
 
    

 

Amortization expense related to intangible assets for the year ended December 31, 2017 was $42.7 million (2016 - $42.2 million).

 

As at December 31, 2017, the Corporation excluded $11.2 million (December 31, 2016 - $8.0 million) of software assets under development as well as assets with indefinite life from the asset base subject to amortization.

 

The following table sets forth the estimated amortization expense of intangible assets, excluding any amortization of assets not yet subject to amortization as well as assets with indefinite life, for the years ended December 31:

 

	
2018
    	
 
    	
$
    	
40.0
    	
 
    
	
2019
    	
 
    	
$
    	
38.9
    	
 
    
	
2020
    	
 
    	
$
    	
34.8
    	
 
    
	
2021
    	
 
    	
$
    	
32.9
    	
 
    
	
2022
    	
 
    	
$
    	
30.2
    	
 
    
	
Thereafter
    	
 
    	
$
    	
400.8
    	
 
    

 

8.  GOODWILL

 

	
 
    	
 
    	
December 31,
    	
 
    	
December 31,
    	
 
    
	
As at
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Balance,   beginning of year
    	
 
    	
$
    	
856.0
    	
 
    	
$
    	
877.3
    	
 
    
	
Foreign exchange   translation
    	
 
    	
(38.4
    	
)
    	
(17.9
    	
)
    
	
Reclassified to   assets held for sale (note 4)
    	
 
    	
(0.3
    	
)
    	
(3.4
    	
)
    
	
Balance, end of   year
    	
 
    	
$
    	
817.3
    	
 
    	
$
    	
856.0
    	
 
    

 

9.  PROVISIONS ON ASSETS

 

	
Year ended December 31
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Power
    	
 
    	
$
    	
133.0
    	
 
    	
$
    	
—
    	
 
    
	
Gas
    	
 
    	
6.6
    	
 
    	
—
    	
 
    
	
 
    	
 
    	
$
    	
139.6
    	
 
    	
$
    	
—
    	
 
    

 

Power

 

In 2017, AltaGas recorded pre-tax provisions on assets related to the Hanford and Henrietta gas-fired peaking plants in California and certain non-core development stage gas-fired peaking projects in California and Alberta for $133.0 million. The

 

23

 

pre-tax provisions of $133.0 million were comprised of $48.5 million on intangible assets and $84.5 million on property, plant and equipment. No provisions on assets were recorded in 2016 for the Power segment.

 

Gas

 

In 2017, AltaGas recorded a pre-tax provision on assets of $6.6 million on a non-core gas processing facility that was classified as held for sale (See Note 4). No provisions on assets were recorded in 2016 for the Gas segment.

 

10.  LONG-TERM INVESTMENTS AND OTHER ASSETS

 

	
As at
    	
 
    	
December 31,
   2017
    	
 
    	
December 31,
   2016
    	
 
    
	
Investments in   publicly-traded entities
    	
 
    	
$
    	
95.0
    	
 
    	
$
    	
49.4
    	
 
    
	
Loan to   affiliate (see note 27)
    	
 
    	
75.0
    	
 
    	
62.5
    	
 
    
	
Deferred lease   receivable
    	
 
    	
29.0
    	
 
    	
16.3
    	
 
    
	
Debt issuance   costs associated with credit facilities
    	
 
    	
20.3
    	
 
    	
5.1
    	
 
    
	
Refundable   deposits
    	
 
    	
14.9
    	
 
    	
39.0
    	
 
    
	
Loan to employee   (see note 27)
    	
 
    	
—
    	
 
    	
0.8
    	
 
    
	
Prepayment on   long-term service agreements
    	
 
    	
68.1
    	
 
    	
8.7
    	
 
    
	
Post-retirement   benefit (see note 25)
    	
 
    	
—
    	
 
    	
2.8
    	
 
    
	
Subscription receipts   issuance costs
    	
 
    	
1.7
    	
 
    	
—
    	
 
    
	
Other
    	
 
    	
8.6
    	
 
    	
4.7
    	
 
    
	
 
    	
 
    	
$
    	
312.6
    	
 
    	
$
    	
189.3
    	
 
    

 

The following table summarizes the Corporation’s available-for-sale investments in equity securities:

 

	
As at
    	
 
    	
December 31,
   2017
    	
 
    	
December 31,
   2016
    	
 
    
	
Amortized cost
    	
 
    	
$
    	
28.7
    	
 
    	
$
    	
21.7
    	
 
    
	
Gross unrealized   gains
    	
 
    	
2.5
    	
 
    	
23.2
    	
 
    
	
Gross unrealized   losses
    	
 
    	
(9.6
    	
)
    	
—
    	
 
    
	
Fair value
    	
 
    	
$
    	
21.6
    	
 
    	
$
    	
44.9
    	
 
    

 

11. VARIABLE INTEREST ENTITY

 

On May 5, 2017, AltaGas LPG Limited Partnership (AltaGas LPG), a wholly-owned subsidiary of AltaGas, and Vopak Development Canada Inc. (Vopak), a wholly-owned subsidiary of Koninklijke Vopak N.V. (Royal Vopak), a public company incorporated under the laws of the Netherlands, formed the Ridley Island LPG Export Limited Partnership (RILE LP) to develop, own and operate the Ridley Island Propane Export Terminal (RIPET). AltaGas’ subsidiaries hold a 70 percent interest while Vopak holds a 30 percent interest in RILE LP. The construction cost of RIPET, which is estimated to be $450 to $500 million, will be funded by AltaGas LPG and Vopak in proportion to their respective interests in RILE LP. As part of the arrangements, AltaGas entered into a long-term agreement for the capacity of RIPET with RILE LP, and AltaGas and certain of its subsidiaries will provide construction and operating services to RILE LP.

 

AltaGas has determined that RILE LP is a VIE in which it holds variable interests and is the primary beneficiary. In the determination that AltaGas is the primary beneficiary of the VIE, AltaGas noted that it has the power to direct the activities that most significantly impact the VIE’s economic performance through the construction, operating and marketing services provided to RILE LP. In addition, AltaGas has the obligation to absorb the losses and the right to receive the benefits that could potentially be significant to RILE LP through the long-term agreement for the capacity of RIPET. As such, AltaGas has consolidated RILE LP and recorded $20.0 million of the $24.1 million proceeds received from Vopak on formation of RILE LP as a non-controlling interest with the remainder of the proceeds less deferred tax recognized as contributed surplus in the amount of $3.0 million.

 

24

 

The following table represents amounts included in the consolidated balance sheets attributable to this VIE:

 

	
 
    	
 
    	
December 31,
    	
 
    	
December 31,
    	
 
    
	
As at
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Accounts   receivable
    	
 
    	
$
    	
1.4
    	
 
    	
$
    	
—
    	
 
    
	
Property, plant   and equipment
    	
 
    	
84.3
    	
 
    	
—
    	
 
    
	
Long-term   investments and other assets
    	
 
    	
48.0
    	
 
    	
—
    	
 
    
	
Net assets
    	
 
    	
$
    	
133.7
    	
 
    	
$
    	
—
    	
 
    

 

The assets of RILE LP are the property of RILE LP and are not available to AltaGas for any other purpose. RILE LP’s asset balances can only be used to settle its own obligations. The liabilities of RILE LP do not represent additional claims against AltaGas’ general assets. AltaGas’ exposure to loss as a result of its interest as a limited partner is its net investment. AltaGas and Royal Vopak have provided limited guarantees for the obligations of their respective subsidiaries for the construction cost of RIPET. Upon commencement of commercial operations at RIPET, the terms of the long-term capacity agreement between AltaGas LPG and RILE LP provide for a return on and of capital and reimbursement of RIPET operating costs by AltaGas LPG in accordance with the terms set out in the agreement.

 

12. INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD

 

	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
Carrying value as at
   December 31
    	
 
    	
Equity income (loss)
   for the
   year ended
   December 31
    	
 
    
	
Description
    	
 
    	
Location
    	
 
    	
Ownership
   Percentage
    	
 
    	
2017
    	
 
    	
2016
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
AltaGas Idemitsu   Joint Venture LP (AIJVLP)
    	
 
    	
Canada
    	
 
    	
50
    	
 
    	
$
    	
323.3
    	
 
    	
$
    	
307.2
    	
 
    	
$
    	
6.6
    	
 
    	
$
    	
(0.4
    	
)
    
	
ASTC Power   Partnership (ASTC) (a)
    	
 
    	
Canada
    	
 
    	
n/a
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(11.1
    	
)
    
	
Craven County   Wood Energy LP
    	
 
    	
United States
    	
 
    	
50
    	
 
    	
20.9
    	
 
    	
22.9
    	
 
    	
3.3
    	
 
    	
0.2
    	
 
    
	
Eaton Rapids Gas   Storage System
    	
 
    	
United States
    	
 
    	
50
    	
 
    	
26.4
    	
 
    	
27.9
    	
 
    	
2.5
    	
 
    	
2.6
    	
 
    
	
Grayling   Generating Station LP
    	
 
    	
United States
    	
 
    	
50
    	
 
    	
27.6
    	
 
    	
30.1
    	
 
    	
3.5
    	
 
    	
4.1
    	
 
    
	
Inuvik Gas Ltd.
    	
 
    	
Canada
    	
 
    	
33.333
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    
	
Sarnia Airport   Storage Pool LP
    	
 
    	
Canada
    	
 
    	
50
    	
 
    	
18.8
    	
 
    	
19.2
    	
 
    	
1.0
    	
 
    	
0.9
    	
 
    
	
Petrogas   Preferred Shares
    	
 
    	
Canada
    	
 
    	
n/a
    	
 
    	
150.0
    	
 
    	
150.0
    	
 
    	
12.8
    	
 
    	
5.9
    	
 
    
	
Tidewater   Midstream and Infrastructure Ltd.
    	
 
    	
Canada
    	
 
    	
n/a
    	
 
    	
—
    	
 
    	
64.1
    	
 
    	
1.7
    	
 
    	
1.2
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
$
    	
567.0
    	
 
    	
$
    	
621.4
    	
 
    	
$
    	
31.4
    	
 
    	
$
    	
3.4
    	
 
    

 

(a)         ASTC was dissolved in 2016.

 

Summarized combined financial information, assuming a 100 percent ownership interest in the AltaGas’ equity investments listed above, is as follows:

 

	
Year ended December 31
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Revenues
    	
 
    	
$
    	
110.6
    	
 
    	
$
    	
178.6
    	
 
    
	
Expenses
    	
 
    	
(74.2
    	
)
    	
(147.9
    	
)
    
	
 
    	
 
    	
$
    	
36.4
    	
 
    	
$
    	
30.7
    	
 
    

 

	
As at December 31
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Current assets
    	
 
    	
$
    	
24.8
    	
 
    	
$
    	
67.2
    	
 
    
	
Property, plant   and equipment
    	
 
    	
$
    	
82.8
    	
 
    	
$
    	
528.6
    	
 
    
	
Intangible   assets
    	
 
    	
$
    	
5.6
    	
 
    	
$
    	
28.3
    	
 
    
	
Long-term   investments and other assets
    	
 
    	
$
    	
843.3
    	
 
    	
$
    	
834.1
    	
 
    
	
Current   liabilities
    	
 
    	
$
    	
(41.7
    	
)
    	
$
    	
(53.5
    	
)
    
	
Other long-term   liabilities
    	
 
    	
$
    	
(189.1
    	
)
    	
$
    	
(361.1
    	
)
    

 

25

 

Petrogas Preferred Shares

 

AltaGas, indirectly through its investment in AIJVLP holds a one-third equity interest in Petrogas. On June 29, 2016, AltaGas, directly invested $150.0 million to subscribe for 6,000,000 cumulative redeemable convertible preferred shares of Petrogas. These preferred shares form part of AltaGas’ overall investment in Petrogas and entitle AltaGas to a fixed, cumulative, preferential cash dividend at a rate of 8.5 percent per annum payable quarterly. These preferred shares are, in the normal course, redeemable at any time on or after January 1, 2018 and convertible into a specified number of common shares at the option of either holder at any time on or after April 19, 2018. For the year ended December 31, 2017, AltaGas received dividend income of $12.8 million (2016 - $5.9 million) from the Petrogas preferred shares, which has been included in the Consolidated Statement of Income under the line item “Income from equity investments”.

 

ASTC and the Sundance B PPAs

 

In the first quarter of 2016, ASTC exercised its right to terminate the Sundance B Power Purchase Arrangements for Sundance B Unit 3 and Unit 4 (collectively, the Sundance B PPAs) effective March 8, 2016 pursuant to the change in law provisions. As a result, AltaGas recognized a pre-tax provision of $4.0 million in the Consolidated Statement of Income under the line item “Income from equity investments” for the year ended December 31, 2016 on its investment in ASTC to settle the working deficiency.

 

In December 2016, AltaGas Pipeline Partnership and TransCanada Energy Ltd. dissolved ASTC. On December 16, 2016, AltaGas Pipeline Partnership and the Government of Alberta reached a definitive settlement agreement regarding the termination of the Sundance B PPAs. Under the settlement agreement, AltaGas has agreed to contribute 391,879 self-generated carbon offsets and make a total of $6.0 million in cash payments payable in equal installments over three years starting in 2018. AltaGas Pipeline Partnership and ASTC were granted a full release from all past, present and future obligations respecting the Sundance B PPAs by the Government of Alberta. As a result of the settlement, AltaGas recorded an overall pre-tax termination expense of approximately $8.4 million for the year ended December 31, 2016, which included the $6.0 million of future cash payments, the costs of the self-generated carbon offsets and associated revenue (See Note 16).

 

Tidewater

 

AltaGas received 43.7 million of common shares of Tidewater valued at $1.48 per share as part of the proceeds from the Tidewater Gas Asset Disposition on February 29, 2016 (see Note 3). AltaGas accounted for its investment in Tidewater common shares using the equity method up until the end of May 2017 when AltaGas concluded that it no longer exercised significant influence over Tidewater. Consequently, AltaGas ceased accounting for the investment under the equity method and reclassified the carrying value of the investment of approximately $65.4 million to “Long-term investments and other assets”. The Tidewater common shares are now recorded at fair value and subsequent changes in fair value are recognized in the Consolidated Statement of Income under “Other income”.

 

Provisions on investments accounted for by the equity method

 

No provisions were recorded for the year ended December 31, 2017. For the year ended December 31, 2016, pre-tax provision of $4.0 million was recorded on the investment in ASTC.

 

26

 

13.  SHORT-TERM DEBT

 

	
As at
    	
 
    	
December 31,
   2017
    	
 
    	
December 31,
   2016
    	
 
    
	
Bank   indebtedness (a)
    	
 
    	
$
    	
6.2
    	
 
    	
$
    	
6.0
    	
 
    
	
US$150 million   operating facility (b)
    	
 
    	
31.7
    	
 
    	
116.8
    	
 
    
	
$25 million   operating facility (c)
    	
 
    	
8.9
    	
 
    	
5.9
    	
 
    
	
 
    	
 
    	
$
    	
46.8
    	
 
    	
$
    	
128.7
    	
 
    

 

(a)         Bank indebtedness bears interest at the lender’s prime rate or at the interest rate applicable to bankers’ acceptances. The prime lending rate at December 31, 2017 was 3.2 percent (December 31, 2016 — 2.7 percent).

(b)         As at December 31, 2017, SEMCO held a US$150 million (December 31, 2016 - US$150.0 million) unsecured revolving operating credit facility with a Canadian chartered bank with a maturity date of December 15, 2022. Draws on the facility can be by way of U.S. base-rate loans, letters of credit and LIBOR loans. Letters of credit outstanding under this facility as at December 31, 2017 were $0.6 million (December 31, 2016 - $0.7 million).

(c)          As at December 31, 2017, AltaGas held a $25.0 million (December 31, 2016 - $25.0 million) bank operating facility which is available for working capital purposes and expires on May 22, 2018. Draws on the facility are by way of prime-rate advances, bankers’ acceptances or letters of credit at the bank’s prime rate or for a fee. Letters of credit outstanding under this facility as at December 31, 2017 were $3.7 million (December 31, 2016 - $3.9 million).

 

Other Credit Facilities

 

As at December 31, 2017, the Corporation held a $50.0 million (December 31, 2016 - $50.0 million) unsecured demand revolving operating credit facility with a Canadian chartered bank. Draws on the facility bear interest at the lender’s prime rate or at the bankers’ acceptance rate plus a stamping fee. Letters of credit outstanding under this facility as at December 31, 2017 were $nil (December 31, 2016 - $nil).

 

As at December 31, 2017, AltaGas Utility Group Inc. held a $20.0 million (December 31, 2016 - $20.0 million) unsecured, uncommitted demand operating credit facility with a Canadian chartered bank. Draws on the facility can be by way of prime rate loans, U.S. base-rate loans, letters of credit, bankers’ acceptances and LIBOR loans. Letters of credit outstanding under this facility as at December 31, 2017 were $3.5 million (December 31, 2016 - $3.7 million).

 

As at December 31, 2017, AltaGas held a $150.0 million (December 31, 2016 - $150.0 million) unsecured four-year extendible revolving letter of credit facility. Draws on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers’ acceptances or letters of credit. Letters of credit outstanding under this facility as at December 31, 2017 were $40.8 million (December 31, 2016 - $49.1 million).

 

As at December 31, 2017, AltaGas held a $150.0 million (December 31, 2016 - $150.0 million) unsecured bilateral letter of credit demand facility with a Canadian chartered bank. Borrowings on the facility incur fees and interest at rates relevant to the nature of the draws made. Letters of credit outstanding under this facility as at December 31, 2017 were $71.3 million (December 31, 2016 - $104.0 million).

 

27

 

14.  LONG-TERM DEBT

 

	
 
    	
 
    	
 
    	
 
    	
December 31,
    	
 
    	
December 31,
    	
 
    
	
As at
    	
 
    	
Maturity date
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Credit   facilities
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
$1,400 million   unsecured extendible revolving(a)
    	
 
    	
15-Dec-2020
    	
 
    	
$
    	
219.1
    	
 
    	
$
    	
377.9
    	
 
    
	
US$300 million   unsecured extendible revolving(b)
    	
 
    	
8-Dec-2019
    	
 
    	
—
    	
 
    	
—
    	
 
    
	
Medium-term   notes (MTNs)
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
$200 million Senior   unsecured - 5.49 percent
    	
 
    	
27-Mar-2017
    	
 
    	
—
    	
 
    	
200.0
    	
 
    
	
$175 million   Senior unsecured - 4.60 percent
    	
 
    	
15-Jan-2018
    	
 
    	
175.0
    	
 
    	
175.0
    	
 
    
	
$200 million   Senior unsecured - 4.55 percent
    	
 
    	
17-Jan-2019
    	
 
    	
200.0
    	
 
    	
200.0
    	
 
    
	
$200 million   Senior unsecured - 4.07 percent
    	
 
    	
1-Jun-2020
    	
 
    	
200.0
    	
 
    	
200.0
    	
 
    
	
$350 million   Senior unsecured - 3.72 percent
    	
 
    	
28-Sep-2021
    	
 
    	
350.0
    	
 
    	
350.0
    	
 
    
	
$300 million   Senior unsecured - 3.57 percent
    	
 
    	
12-Jun-2023
    	
 
    	
300.0
    	
 
    	
300.0
    	
 
    
	
$200 million   Senior unsecured - 4.40 percent
    	
 
    	
15-Mar-2024
    	
 
    	
200.0
    	
 
    	
200.0
    	
 
    
	
$300 million   Senior unsecured - 3.84 percent
    	
 
    	
15-Jan-2025
    	
 
    	
299.9
    	
 
    	
299.9
    	
 
    
	
$100 million   Senior unsecured - 5.16 percent
    	
 
    	
13-Jan-2044
    	
 
    	
100.0
    	
 
    	
100.0
    	
 
    
	
$300 million   Senior unsecured - 4.50 percent
    	
 
    	
15-Aug-2044
    	
 
    	
299.8
    	
 
    	
299.8
    	
 
    
	
$350 million   Senior unsecured - 4.12 percent
    	
 
    	
7-Apr-2026
    	
 
    	
349.8
    	
 
    	
349.8
    	
 
    
	
$200 million   Senior unsecured - 3.98 percent
    	
 
    	
4-Oct-2027
    	
 
    	
199.9
    	
 
    	
—
    	
 
    
	
$250 million   Senior unsecured - 4.99 percent
    	
 
    	
4-Oct-2047
    	
 
    	
250.0
    	
 
    	
—
    	
 
    
	
US$125 million   Senior unsecured - floating(c)
    	
 
    	
17-Apr-2017
    	
 
    	
—
    	
 
    	
167.8
    	
 
    
	
SEMCO long-term   debt
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
US$300 million   SEMCO Senior secured - 5.15 percent(d)
    	
 
    	
21-Apr-2020
    	
 
    	
376.4
    	
 
    	
402.8
    	
 
    
	
US$82 million   CINGSA Senior secured - 4.48 percent(e)
    	
 
    	
2-Mar-2032
    	
 
    	
85.2
    	
 
    	
97.5
    	
 
    
	
Debenture notes
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
PNG RoyNat   Debenture(f)
    	
 
    	
15-Sep-2017
    	
 
    	
—
    	
 
    	
7.4
    	
 
    
	
PNG 2018   Series Debenture - 8.75 percent(f)
    	
 
    	
15-Nov-2018
    	
 
    	
7.0
    	
 
    	
8.0
    	
 
    
	
PNG 2025   Series Debenture - 9.30 percent(f)
    	
 
    	
18-Jul-2025
    	
 
    	
13.0
    	
 
    	
13.5
    	
 
    
	
PNG 2027   Series Debenture - 6.90 percent(f)
    	
 
    	
2-Dec-2027
    	
 
    	
14.0
    	
 
    	
14.5
    	
 
    
	
CINGSA capital   lease - 3.50 percent
    	
 
    	
1-May-2040
    	
 
    	
0.5
    	
 
    	
0.6
    	
 
    
	
CINGSA capital   lease - 4.48 percent
    	
 
    	
4-Jun-2068
    	
 
    	
0.2
    	
 
    	
0.2
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
$
    	
3,639.8
    	
 
    	
$
    	
3,764.7
    	
 
    
	
Less debt   issuance costs
    	
 
    	
 
    	
 
    	
(14.4
    	
)
    	
(14.4
    	
)
    
	
 
    	
 
    	
 
    	
 
    	
3,625.4
    	
 
    	
3,750.3
    	
 
    
	
Less current   portion
    	
 
    	
 
    	
 
    	
(188.9
    	
)
    	
(383.4
    	
)
    
	
 
    	
 
    	
 
    	
 
    	
$
    	
3,436.5
    	
 
    	
$
    	
3,366.9
    	
 
    

 

(a)         Borrowings on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers’ acceptances or letters of credit. Borrowings on the facility have fees and interest at rates relevant to the nature of the draw made.

(b)         Borrowings on the facility can be by way of U.S. base rate loans, U.S. prime loans, LIBOR loans or letters of credit.

(c)          The notes carried a floating rate coupon of three months LIBOR plus 0.85 percent.

(d)         Collateral for the US$ MTNs is certain SEMCO assets.

(e)          Collateral for the CINGSA Senior secured loan is certain CINGSA assets. Alaska Storage Holding Company, LLC, a subsidiary in which AltaGas has a controlling interest, is the non-recourse guarantor of this loan.

(f)            Collateral for the Secured Debentures consists of a specific first mortgage on substantially all of PNG’s property, plant and equipment, and gas purchase and gas sales contracts, and a first floating charge on other property, assets and undertakings.

 

28

 

15.  ASSET RETIREMENT OBLIGATIONS

 

	
As at
    	
 
    	
December 31,
   2017
    	
 
    	
December 31,
   2016
    	
 
    
	
Balance,   beginning of year
    	
 
    	
$
    	
81.6
    	
 
    	
$
    	
67.9
    	
 
    
	
Obligations   acquired
    	
 
    	
—
    	
 
    	
11.3
    	
 
    
	
New obligations
    	
 
    	
1.5
    	
 
    	
0.7
    	
 
    
	
Obligations   settled
    	
 
    	
(4.0
    	
)
    	
(3.8
    	
)
    
	
Revision in   estimated cash flow
    	
 
    	
6.0
    	
 
    	
2.1
    	
 
    
	
Accretion   expense
    	
 
    	
4.4
    	
 
    	
4.2
    	
 
    
	
Foreign exchange   translation
    	
 
    	
(0.9
    	
)
    	
(0.4
    	
)
    
	
Reclassified to   liabilities associated with assets held for sale (note 4)
    	
 
    	
(0.3
    	
)
    	
(0.4
    	
)
    
	
Balance, end of   year
    	
 
    	
$
    	
88.3
    	
 
    	
$
    	
81.6
    	
 
    

 

The majority of the asset retirement obligations are associated with gas processing facilities in the Gas segment.

 

AltaGas estimates the undiscounted cash required to settle the asset retirement obligations, excluding growth for inflation, at December 31, 2017 was $232.9 million (December 31, 2016 - $225.9 million).

 

The asset retirement obligations have been recorded in the Consolidated Financial Statements at estimated values discounted at rates between 4.0 and 8.5 percent and are expected to be incurred between 2018 and 2164. No assets have been legally restricted for settlement of the estimated liability.

 

In May 2014, the National Energy Board (NEB) issued a decision establishing that, by January 1, 2015, all NEB-regulated companies must have a mechanism in place for the accumulation of funds to pay for future pipeline abandonment. AltaGas Holdings Inc., a wholly-owned subsidiary of AltaGas, opted to comply with the NEB decision with a surety bond supplied by a surety company regulated by the Office of the Superintendent of Financial Institutions in the amount of $30.3 million.

 

16.  OTHER LONG-TERM LIABILITIES

 

	
As at
    	
 
    	
December 31,
   2017
    	
 
    	
December 31,
   2016
    	
 
    
	
Deferred lease   payable
    	
 
    	
$
    	
2.4
    	
 
    	
$
    	
0.7
    	
 
    
	
Deferred revenue
    	
 
    	
3.8
    	
 
    	
4.0
    	
 
    
	
Customer   advances for construction
    	
 
    	
40.9
    	
 
    	
43.9
    	
 
    
	
NTL liability
    	
 
    	
142.0
    	
 
    	
146.8
    	
 
    
	
Sundance B PPA   termination expense (a)
    	
 
    	
4.0
    	
 
    	
6.0
    	
 
    
	
Lease Inducement
    	
 
    	
3.1
    	
 
    	
3.1
    	
 
    
	
Other long-term   liabilities
    	
 
    	
5.7
    	
 
    	
1.8
    	
 
    
	
 
    	
 
    	
$
    	
201.9
    	
 
    	
$
    	
206.3
    	
 
    

 

(a)         On December 16, 2016, AltaGas Pipeline Partnership and the Government of Alberta reached a definitive settlement agreement regarding the termination of the Sundance B PPAs. Under the settlement agreement, AltaGas has agreed to make a total of $6.0 million in cash payments in equal annual installments over three years starting in 2018, $2.0 million of which have been recorded under “Accounts payable and accrued liabilities”.

 

NTL Liability

 

In 2010, AltaGas entered into a 60-year CPI-indexed Electricity Purchase Agreement (EPA) and other related agreements with BC Hydro for the 195-MW Forrest Kerr run-of-river hydroelectric facility. As part of the related agreements, AltaGas agreed to pay BC Hydro annual payments of approximately $11.0 million per year, adjusted for inflation, in support of the construction and operation of the Northwest Transmission Line (NTL) until 2034.

 

The fair value of the firm commitment on initial recognition was measured using an estimated 2 percent inflation rate and 4.27 percent discount rate. As at December 31, 2017, the NTL liability has been recorded within other current liabilities for $11.5 million (December 31, 2016 - $11.3 million) and other long-term liabilities for $142.0 million (December 31, 2016 - $146.8

 

29

 

million). Accretion expense for the year ended December 31, 2017 was $6.5 million (2016 - $6.8 million). The initial consideration and the fair value of the future consideration of $258.5 million has been recognized within intangible assets and is being depreciated over 60 years, the term of the EPA with BC Hydro.

 

17.  INCOME TAXES

 

	
Year ended December 31
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Income before   income taxes - consolidated
    	
 
    	
$
    	
66.4
    	
 
    	
$
    	
246.2
    	
 
    
	
Statutory income   tax rate (%)
    	
 
    	
27.0
    	
 
    	
27.0
    	
 
    
	
Expected taxes   at statutory rates
    	
 
    	
$
    	
17.9
    	
 
    	
$
    	
66.5
    	
 
    
	
Add (deduct) the   tax effect of:
    	
 
    	
 
    	
 
    	
—
    	
 
    
	
Permanent   differences
    	
 
    	
9.5
    	
 
    	
(1.9
    	
)
    
	
Statutory and   other rate differences
    	
 
    	
(25.5
    	
)
    	
(0.3
    	
)
    
	
Rate adjustment   for change in tax rates
    	
 
    	
(34.1
    	
)
    	
—
    	
 
    
	
Deferred income   tax recovery on regulated assets
    	
 
    	
(7.4
    	
)
    	
(5.7
    	
)
    
	
Other
    	
 
    	
6.1
    	
 
    	
(25.8
    	
)
    
	
 
    	
 
    	
$
    	
(33.5
    	
)
    	
$
    	
32.8
    	
 
    
	
Income tax   provision
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Current
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Canada
    	
 
    	
18.0
    	
 
    	
10.0
    	
 
    
	
United States
    	
 
    	
12.5
    	
 
    	
14.4
    	
 
    
	
 
    	
 
    	
$
    	
30.5
    	
 
    	
$
    	
24.4
    	
 
    
	
Deferred
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Canada
    	
 
    	
(7.4
    	
)
    	
(28.7
    	
)
    
	
United States
    	
 
    	
(56.6
    	
)
    	
37.1
    	
 
    
	
 
    	
 
    	
$
    	
(64.0
    	
)
    	
$
    	
8.4
    	
 
    
	
Effective income   tax rate (%)
    	
 
    	
(50.5
    	
)
    	
13.3
    	
 
    

 

Net deferred income tax liabilities were composed of the following:

 

	
As at
    	
 
    	
December 31,
   2017
    	
 
    	
December 31,
   2016
    	
 
    
	
PP&E and   intangible assets
    	
 
    	
$
    	
726.5
    	
 
    	
$
    	
737.0
    	
 
    
	
Regulatory   assets
    	
 
    	
22.8
    	
 
    	
37.3
    	
 
    
	
Tax pools,   deferred financing and compensation
    	
 
    	
(302.3
    	
)
    	
(208.2
    	
)
    
	
Other
    	
 
    	
(59.3
    	
)
    	
8.9
    	
 
    
	
Valuation   allowance
    	
 
    	
53.7
    	
 
    	
43.9
    	
 
    
	
 
    	
 
    	
$
    	
441.4
    	
 
    	
$
    	
618.9
    	
 
    

 

The amount shown on the Consolidated Balance Sheets as deferred income tax liabilities represents the net differences between the tax basis and book carrying values on the Corporation’s balance sheets at enacted tax rates.

 

The Tax Cuts and Jobs Act (the U.S. tax reform) in the U.S. became law on December 22, 2017. The law includes significant changes to the U.S. corporate income tax system, including a federal corporate rate reduction from 35 percent to 21 percent beginning in 2018, changes to capital depreciation, limitations on the deductibility of interest expense and executive compensation, and the transition of U.S. international taxation from a worldwide tax system to a territorial tax system.

 

At December 31, 2017, as a result of the U.S. tax reform, the Corporation remeasured its U.S. deferred tax liability based upon the new statutory federal rate of 21 percent. This remeasurement resulted in a net reduction to the deferred tax liability in the amount of $135.9 million. As the Corporation’s U.S. utilities are subject to rate regulation, $101.8 million of the deferred tax remeasurement was recorded as a deferred regulatory liability on the Corporation’s Consolidated Balance Sheet. For the Corporation’s non-regulated U.S. businesses, the remeasurement was recorded as a $34.1 million reduction to income tax expense.

 

30

 

In addition to the U.S. federal rate change, the government of British Columbia increased the corporate tax rate to 12 percent from 11 percent beginning in 2018.

 

As at December 31, 2017, the Corporation had tax-effected non-capital losses of approximately $233.8 million for tax purposes, which will be available to offset future taxable income. If not used, these losses will expire between 2023 and 2037.

 

Uncertain Tax Positions

 

On an annual basis the Corporation and its subsidiaries file tax returns in Canada and various foreign jurisdictions. In Canada AltaGas’ federal and provincial tax returns for the years 2009 to 2016 remain subject to examination by taxation authorities. In the United States both the federal and state tax returns filed for the years 2011 to 2016 remain subject to examination by the taxation authorities.

 

Management determined that the following provision was required for uncertainty on income taxes during the year:

 

	
Year ended December 31
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Balance,   beginning of year
    	
 
    	
$
    	
2.2
    	
 
    	
$
    	
3.7
    	
 
    
	
Net changes   during the year
    	
 
    	
3.7
    	
 
    	
(1.5
    	
)
    
	
Balance, end of   year
    	
 
    	
$
    	
5.9
    	
 
    	
$
    	
2.2
    	
 
    

 

18.  REGULATORY ASSETS AND LIABILITIES

 

AltaGas accounts for certain transactions in accordance with ASC 980, Regulated Operations. AltaGas refers to this accounting guidance for regulated entities as “regulatory accounting”. Under regulatory accounting, utilities are permitted to defer expenses and income as regulatory assets and liabilities, respectively, in the Consolidated Balance Sheet when it is probable that those expenses and income will be allowed in the rate-setting process in a period different from the period in which they would have been reflected in the Consolidated Statement of Income by a non-rate-regulated entity. These deferred regulatory assets and liabilities are included in the Consolidated Statement of Income in future periods when the amounts are reflected in customer rates. Management’s assessment of the probability of recovery or pass-through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory agency orders, rules, and rate-making conventions. The relevant regulatory bodies are the AUC, BCUC, and NSUARB in Canada, and the MPSC and RCA in the United States.

 

If, for any reason, the Corporation ceases to meet the criteria for application of regulatory accounting for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be de-recognized from the Consolidated Balance Sheet and included in the Consolidated Statement of Income for the period in which the discontinuance of regulatory accounting occurs. Criteria that give rise to the discontinuance of regulatory accounting include: (i) increasing competition that restricts the ability of the Corporation to charge prices sufficient to recover specific costs, and (ii) a significant change in the manner in which rates are set by regulatory agencies from cost-based regulation to another form of regulation. The Corporation’s review of these criteria currently supports the continued application of regulatory accounting for all its utilities.

 

The following table summarizes the regulatory assets and liabilities recorded in the Consolidated Balance Sheets, as well as the remaining period, as of December 31, 2017 and 2016, over which the Corporation expects to realize or settle the assets or liabilities:

 

31

 

	
As at
    	
 
    	
December 31,
   2017
    	
 
    	
December 31,
   2016
    	
 
    	
Recovery
   Period
    	
 
    
	
Regulatory   assets - current
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Deferred cost of   gas
    	
 
    	
$
    	
0.5
    	
 
    	
$
    	
0.8
    	
 
    	
Less than one year
    	
 
    
	
Deferred   property taxes
    	
 
    	
0.3
    	
 
    	
0.1
    	
 
    	
Less than one year
    	
 
    
	
Energy   optimization costs
    	
 
    	
0.3
    	
 
    	
—
    	
 
    	
Less than one year
    	
 
    
	
 
    	
 
    	
$
    	
1.1
    	
 
    	
$
    	
0.9
    	
 
    	
 
    	
 
    
	
Regulatory   assets - non-current
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Deferred   regulatory costs and rate stabilization adjustment mechanism
    	
 
    	
$
    	
20.5
    	
 
    	
$
    	
18.0
    	
 
    	
1 - 28 years
    	
 
    
	
Pipeline   rehabilitation costs
    	
 
    	
0.3
    	
 
    	
6.7
    	
 
    	
1-3 years
    	
 
    
	
Future recovery   of pension and other retirement benefits (a)
    	
 
    	
113.9
    	
 
    	
114.7
    	
 
    	
Various
    	
 
    
	
Deferred   environmental costs
    	
 
    	
13.9
    	
 
    	
18.0
    	
 
    	
1-10 years
    	
 
    
	
Deferred loss on   reacquired debt
    	
 
    	
2.5
    	
 
    	
3.4
    	
 
    	
2-14 years
    	
 
    
	
Deferred   depreciation and amortization (b)
    	
 
    	
23.3
    	
 
    	
24.0
    	
 
    	
Various
    	
 
    
	
Deferred future   income taxes (c) 
    	
 
    	
104.7
    	
 
    	
104.7
    	
 
    	
Various
    	
 
    
	
Deferred   customer retention program amortization (d)
    	
 
    	
16.5
    	
 
    	
6.4
    	
 
    	
Various
    	
 
    
	
Revenue   deficiency account (e)
    	
 
    	
31.0
    	
 
    	
29.2
    	
 
    	
Various
    	
 
    
	
Other
    	
 
    	
2.0
    	
 
    	
4.0
    	
 
    	
Various
    	
 
    
	
 
    	
 
    	
$
    	
328.6
    	
 
    	
$
    	
329.1
    	
 
    	
 
    	
 
    
	
Regulatory   liabilities - current
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Deferred cost of   gas
    	
 
    	
$
    	
9.0
    	
 
    	
$
    	
13.7
    	
 
    	
Less than one year
    	
 
    
	
Energy   optimization costs
    	
 
    	
—
    	
 
    	
0.6
    	
 
    	
Less than one year
    	
 
    
	
Interruptible   storage service revenue
    	
 
    	
—
    	
 
    	
0.3
    	
 
    	
Less than one year
    	
 
    
	
Refundable tax   credit (f)
    	
 
    	
1.9
    	
 
    	
2.0
    	
 
    	
Less than one year
    	
 
    
	
 
    	
 
    	
$
    	
10.9
    	
 
    	
$
    	
16.6
    	
 
    	
 
    	
 
    
	
Regulatory   liabilities - non-current
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Option fees   deferral (g)
    	
 
    	
$
    	
4.3
    	
 
    	
$
    	
4.1
    	
 
    	
Various
    	
 
    
	
Refundable tax   credit (f)
    	
 
    	
7.5
    	
 
    	
10.1
    	
 
    	
4 years
    	
 
    
	
Future removal   and site restoration costs (h)
    	
 
    	
153.3
    	
 
    	
154.9
    	
 
    	
Various
    	
 
    
	
Federal income   tax rate change (i)
    	
 
    	
101.8
    	
 
    	
—
    	
 
    	
Various
    	
 
    
	
Insurance recovery   of environmental costs
    	
 
    	
0.3
    	
 
    	
0.5
    	
 
    	
1 year
    	
 
    
	
Other
    	
 
    	
1.4
    	
 
    	
0.9
    	
 
    	
Various
    	
 
    
	
 
    	
 
    	
$
    	
268.6
    	
 
    	
$
    	
170.5
    	
 
    	
 
    	
 
    

 

(a)         Certain utilities have recovered pension costs related to regulated operations in rates, and as such the Corporation has recorded a regulatory asset for the unamortized costs associated with the defined benefit and post-retirement benefit plans. Depending on the method utilized by the utility the recovery period can be either the expected service life of the employees or the benefit period for employees or a specific recovery period as approved by the respective regulator.

(b)         Pursuant to the NSUARB decisions in 2009 and 2011, Heritage Gas was ordered to suspend amortization of property, plant and equipment and intangible assets for regulatory purposes for the fiscal periods from 2009 to 2013. The NSUARB, in its decision dated November 24, 2011, directed amortization to be phased in over a four year period at the following rates: 2014 at 25 percent of the authorized rates; 2015 at 50 percent of the authorized rates; 2016 at 75 percent of the authorized rates; and 2017 at 100 percent of the authorized rates. As a result of this order, the Heritage Gas recognizes a regulatory asset equal to the amortization that would have otherwise been included in rates.

(c)          This regulatory asset reflects the amount of deferred income taxes expected to be refunded, or recovered from, customers in future rates.

(d)         In September 2016, the NSUARB approved Heritage Gas’ Customer Retention Program application to decrease distribution rates for certain commercial and residential customers, suspend depreciation and to increase the capitalization rate for operating, maintenance and administrative expenses effective March 22, 2016.

(e)          Heritage Gas has an approval from the NSUARB to use a revenue deficiency account (RDA) until it is fully recovered, subject to a cap of $50 million, imposed in 2010, which may be increased subject to approval by the NSUARB. The RDA is the cumulative difference between the revenue requirements and the actual amounts billed to customers.

(f)            On September 18, 2013, CINGSA received a US$15.0 million gas storage facility tax credit from the State of Alaska for the benefit of its firm storage service customers. CINGSA will derive no direct or indirect benefit from the tax credit. Following receipt of the tax credit, CINGSA deposited it in a separate interest-bearing account. CINGSA will act as a custodian of the tax credit and any interest earned for the benefit of CINGSA’s customers. On an annual basis, covering the years 2012 through 2021, CINGSA will disburse to the customers 1/10th of the amount of the tax credit not subject to refund to the State and interest earned. The RCA has approved the disbursement methodology.

(g)         Pursuant to BCUC approved negotiated settlement agreement.

(h)         This amount and timing of draw down is dependent upon the cost of removal of underlying utility property, plant and equipment and the life of property, plant and equipment.

(i)            The Tax Cuts and Jobs Act (the U.S. tax reform) was enacted on December 22, 2017, and required the Corporation to revalue its U.S. deferred tax assets and liabilities to the lower federal corporate tax rate of 21 percent resulting in excess accumulated deferred income taxes. The tax rate reduction created a reduction in deferred tax liability, which SEMCO Gas is required to refund to its ratepayers.

 

32

 

19.  ACCUMULATED OTHER COMPREHENSIVE INCOME

 

	
($ millions)
    	
 
    	
Available-
   for-sale
    	
 
    	
Defined
   benefit
   pension
   and PRB
   plans
    	
 
    	
Hedge net
   investments
    	
 
    	
Translation
   foreign
   operations
    	
 
    	
Equity
   investee
    	
 
    	
Total
    	
 
    
	
Opening balance, January 1, 2017
    	
 
    	
$
    	
19.8
    	
 
    	
$
    	
(11.3
    	
)
    	
$
    	
(135.6
    	
)
    	
$
    	
526.3
    	
 
    	
$
    	
5.9
    	
 
    	
$
    	
405.1
    	
 
    
	
OCI before reclassification
    	
 
    	
(30.3
    	
)
    	
(1.3
    	
)
    	
6.6
    	
 
    	
(183.4
    	
)
    	
(2.2
    	
)
    	
(210.6
    	
)
    
	
Amounts reclassified from OCI
    	
 
    	
—
    	
 
    	
1.3
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
1.3
    	
 
    
	
Current period OCI (pre-tax)
    	
 
    	
(30.3
    	
)
    	
—
    	
 
    	
6.6
    	
 
    	
(183.4
    	
)
    	
(2.2
    	
)
    	
(209.3
    	
)
    
	
Income tax on amounts retained in AOCI
    	
 
    	
3.4
    	
 
    	
0.3
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
3.7
    	
 
    
	
Income tax on amounts reclassified to earnings
    	
 
    	
—
    	
 
    	
(0.4
    	
)
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(0.4
    	
)
    
	
Net current period OCI
    	
 
    	
(26.9
    	
)
    	
(0.1
    	
)
    	
6.6
    	
 
    	
(183.4
    	
)
    	
(2.2
    	
)
    	
(206.0
    	
)
    
	
Ending balance, December 31, 2017
    	
 
    	
$
    	
(7.1
    	
)
    	
$
    	
(11.4
    	
)
    	
$
    	
(129.0
    	
)
    	
$
    	
342.9
    	
 
    	
$
    	
3.7
    	
 
    	
$
    	
199.1
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Opening balance, January 1, 2016
    	
 
    	
$
    	
(2.4
    	
)
    	
$
    	
(9.6
    	
)
    	
$
    	
(169.6
    	
)
    	
$
    	
610.5
    	
 
    	
$
    	
4.6
    	
 
    	
$
    	
433.5
    	
 
    
	
OCI before reclassification
    	
 
    	
25.6
    	
 
    	
(3.4
    	
)
    	
44.6
    	
 
    	
(84.2
    	
)
    	
1.3
    	
 
    	
(16.1
    	
)
    
	
Amounts reclassified from OCI
    	
 
    	
—
    	
 
    	
1.0
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
1.0
    	
 
    
	
Current period OCI (pre-tax)
    	
 
    	
25.6
    	
 
    	
(2.4
    	
)
    	
44.6
    	
 
    	
(84.2
    	
)
    	
1.3
    	
 
    	
(15.1
    	
)
    
	
Income tax on amounts retained in AOCI
    	
 
    	
(3.4
    	
)
    	
1.0
    	
 
    	
(10.6
    	
)
    	
—
    	
 
    	
—
    	
 
    	
(13.0
    	
)
    
	
Income tax on amounts reclassified to earnings
    	
 
    	
—
    	
 
    	
(0.3
    	
)
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(0.3
    	
)
    
	
Net current period OCI
    	
 
    	
22.2
    	
 
    	
(1.7
    	
)
    	
34.0
    	
 
    	
(84.2
    	
)
    	
1.3
    	
 
    	
(28.4
    	
)
    
	
Ending balance, December 31, 2016
    	
 
    	
$
    	
19.8
    	
 
    	
$
    	
(11.3
    	
)
    	
$
    	
(135.6
    	
)
    	
$
    	
526.3
    	
 
    	
$
    	
5.9
    	
 
    	
$
    	
405.1
    	
 
    

 

Reclassification From Accumulated Other Comprehensive Income

 

	
 
    	
 
    	
 
    	
 
    	
For the year ended
   December 31
    	
 
    
	
AOCI components reclassified
    	
 
    	
Income statement line item
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Defined benefit   pension and PRB plans
    	
 
    	
Operating and administrative expense
    	
 
    	
$
    	
1.3
    	
 
    	
$
    	
1.0
    	
 
    
	
Deferred income   taxes
    	
 
    	
Income tax expenses — deferred
    	
 
    	
(0.4
    	
)
    	
(0.3
    	
)
    
	
 
    	
 
    	
 
    	
 
    	
$
    	
0.9
    	
 
    	
$
    	
0.7
    	
 
    

 

20.  FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT

 

The Corporation’s financial instruments consist of cash and cash equivalents, accounts receivable, risk management contracts, certain long-term investments and other assets, accounts payable and accrued liabilities, dividends payable, short-term and long-term debt and certain other current and long-term liabilities.

 

Fair Value Hierarchy

 

AltaGas categorizes its financial assets and financial liabilities into one of three levels based on fair value measurements and inputs used to determine the fair value.

 

Level 1 - fair values are based on unadjusted quoted prices in active markets for identical assets or liabilities. Fair values are based on direct observations of transactions involving the same assets or liabilities and no assumptions are used. Included in this category are publicly traded shares valued at the closing price as at the balance sheet date.

 

33

 

Level 2 - fair values are determined based on valuation models and techniques where inputs other than quoted prices included within level 1 are observable for the asset or liability either directly or indirectly. AltaGas uses over-the-counter derivative instruments to manage fluctuations in commodity prices and foreign exchange rates. AltaGas estimates forward prices based on published sources adjusted for factors specific to the asset or liability, including basis and location differentials, discount rates, and currency exchange. The forward curves used to mark-to-market these derivative instruments are vetted against public sources.

 

Level 3 - fair values are based on inputs for the asset or liability that are not based on observable market data. AltaGas uses valuation techniques when observable market data is not available.

 

The following methods and assumptions were used to estimate the fair value of each significant class of financial instruments:

 

Cash and cash equivalents, Accounts receivable, Accounts payable, Other current liabilities, Short-term debt and Dividends payable - the carrying amounts approximate fair value because of the short maturity of these instruments.

 

Current portion of long-term debt, Long-term debt and Other long-term liabilities - the fair value of these liabilities has been estimated based on discounted future interest and principal payments using the current market interest rates of instruments with similar terms.

 

Risk management assets and liabilities - the fair values of power, natural gas and NGL derivative contracts were calculated using forward prices from published sources for the relevant period. The fair value of foreign exchange derivative contracts was calculated using quoted market rates. The fair value of foreign exchange option contracts was calculated using a variation of the Black-Scholes pricing model

 

	
 
    	
 
    	
December 31, 2017
    	
 
    
	
 
    	
 
    	
Carrying
   Amount
    	
 
    	
Level 1
    	
 
    	
Level 2
    	
 
    	
Level 3
    	
 
    	
Total
   Fair Value
    	
 
    
	
Financial assets
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Cash and cash   equivalents
    	
 
    	
$
    	
27.3
    	
 
    	
$
    	
27.3
    	
 
    	
$
    	
—
    	
 
    	
$
    	
—
    	
 
    	
$
    	
27.3
    	
 
    
	
Risk management   assets - current
    	
 
    	
38.6
    	
 
    	
—
    	
 
    	
38.6
    	
 
    	
—
    	
 
    	
38.6
    	
 
    
	
Risk management   assets - non-current
    	
 
    	
15.9
    	
 
    	
—
    	
 
    	
15.9
    	
 
    	
—
    	
 
    	
15.9
    	
 
    
	
Long-term   investments and other assets (a)
    	
 
    	
170.0
    	
 
    	
95.0
    	
 
    	
85.6
    	
 
    	
—
    	
 
    	
180.6
    	
 
    
	
 
    	
 
    	
$
    	
251.8
    	
 
    	
$
    	
122.3
    	
 
    	
$
    	
140.1
    	
 
    	
$
    	
—
    	
 
    	
$
    	
262.4
    	
 
    
	
Financial   liabilities
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Risk management   liabilities - current
    	
 
    	
$
    	
57.6
    	
 
    	
$
    	
—
    	
 
    	
$
    	
57.6
    	
 
    	
$
    	
—
    	
 
    	
$
    	
57.6
    	
 
    
	
Risk management   liabilities - non-current
    	
 
    	
13.8
    	
 
    	
—
    	
 
    	
13.8
    	
 
    	
—
    	
 
    	
13.8
    	
 
    
	
Current portion   of long-term debt
    	
 
    	
188.9
    	
 
    	
—
    	
 
    	
189.6
    	
 
    	
—
    	
 
    	
189.6
    	
 
    
	
Long-term debt
    	
 
    	
3,436.5
    	
 
    	
—
    	
 
    	
3,568.3
    	
 
    	
—
    	
 
    	
3,568.3
    	
 
    
	
Other current   liabilities   (b)
    	
 
    	
22.4
    	
 
    	
—
    	
 
    	
22.4
    	
 
    	
—
    	
 
    	
22.4
    	
 
    
	
Other long-term   liabilities (b) 
    	
 
    	
146.0
    	
 
    	
—
    	
 
    	
147.7
    	
 
    	
—
    	
 
    	
147.7
    	
 
    
	
 
    	
 
    	
$
    	
3,865.2
    	
 
    	
$
    	
—
    	
 
    	
$
    	
3,999.4
    	
 
    	
$
    	
—
    	
 
    	
$
    	
3,999.4
    	
 
    

 

(a)         Excludes non-financial assets.

(b)         Excludes non-financial liabilities.

 

34

 

	
 
    	
 
    	
December 31, 2016
    	
 
    
	
 
    	
 
    	
Carrying
   Amount
    	
 
    	
Level 1
    	
 
    	
Level 2
    	
 
    	
Level 3
    	
 
    	
Total
   Fair Value
    	
 
    
	
Financial assets
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Cash and cash   equivalents
    	
 
    	
$
    	
19.0
    	
 
    	
$
    	
19.0
    	
 
    	
$
    	
—
    	
 
    	
$
    	
—
    	
 
    	
$
    	
19.0
    	
 
    
	
Risk management   assets - current
    	
 
    	
40.4
    	
 
    	
—
    	
 
    	
40.4
    	
 
    	
—
    	
 
    	
40.4
    	
 
    
	
Risk management   assets - non-current
    	
 
    	
24.1
    	
 
    	
—
    	
 
    	
24.1
    	
 
    	
—
    	
 
    	
24.1
    	
 
    
	
Long-term   investments and other assets (a)
    	
 
    	
113.0
    	
 
    	
49.4
    	
 
    	
63.6
    	
 
    	
—
    	
 
    	
113.0
    	
 
    
	
 
    	
 
    	
$
    	
196.5
    	
 
    	
$
    	
68.4
    	
 
    	
$
    	
128.1
    	
 
    	
$
    	
—
    	
 
    	
$
    	
196.5
    	
 
    
	
Financial   liabilities
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Risk management   liabilities - current
    	
 
    	
$
    	
32.9
    	
 
    	
$
    	
—
    	
 
    	
$
    	
32.9
    	
 
    	
—
    	
 
    	
$
    	
32.9
    	
 
    
	
Risk management   liabilities - non-current
    	
 
    	
12.6
    	
 
    	
—
    	
 
    	
12.6
    	
 
    	
—
    	
 
    	
12.6
    	
 
    
	
Current portion   of long-term debt
    	
 
    	
383.4
    	
 
    	
—
    	
 
    	
385.3
    	
 
    	
—
    	
 
    	
385.3
    	
 
    
	
Long-term debt
    	
 
    	
3,366.9
    	
 
    	
—
    	
 
    	
3,500.9
    	
 
    	
—
    	
 
    	
3,500.9
    	
 
    
	
Other current   liabilities   (b)
    	
 
    	
22.3
    	
 
    	
—
    	
 
    	
22.0
    	
 
    	
—
    	
 
    	
22.0
    	
 
    
	
Other long-term   liabilities (b) 
    	
 
    	
152.8
    	
 
    	
—
    	
 
    	
152.4
    	
 
    	
—
    	
 
    	
152.4
    	
 
    
	
 
    	
 
    	
$
    	
3,970.9
    	
 
    	
$
    	
—
    	
 
    	
$
    	
4,106.1
    	
 
    	
$
    	
—
    	
 
    	
$
    	
4,106.1
    	
 
    

 

(a)         Excludes non-financial assets.

(b)         Excludes non-financial liabilities.

 

Summary of Unrealized Gains (Losses) on Risk Management Contracts Recognized in Net Income

 

	
For the year ended December 31
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Natural gas
    	
 
    	
$
    	
2.2
    	
 
    	
$
    	
0.2
    	
 
    
	
Storage   optimization
    	
 
    	
2.7
    	
 
    	
(5.3
    	
)
    
	
NGL frac spread
    	
 
    	
(11.7
    	
)
    	
(12.2
    	
)
    
	
Power
    	
 
    	
(20.8
    	
)
    	
4.7
    	
 
    
	
Heat rate
    	
 
    	
—
    	
 
    	
(0.1
    	
)
    
	
Foreign exchange
    	
 
    	
(34.9
    	
)
    	
1.0
    	
 
    
	
Embedded   derivative
    	
 
    	
—
    	
 
    	
0.3
    	
 
    
	
 
    	
 
    	
$
    	
(62.5
    	
)
    	
$
    	
(11.4
    	
)
    

 

Offsetting of Derivative Assets and Derivative Liabilities

 

Certain AltaGas risk management contracts are subject to master netting arrangements that create a legally enforceable right to offset by counterparty the related financial assets and financial liabilities.

 

	
 
    	
 
    	
December 31, 2017
    	
 
    
	
Risk management assets (a)
    	
 
    	
Gross amounts of
   recognized
   assets/liabilities
    	
 
    	
Gross amounts
   offset in
   balance sheet
    	
 
    	
Net amounts
   presented in
   balance sheet
    	
 
    
	
Natural gas
    	
 
    	
$
    	
41.0
    	
 
    	
$
    	
(6.2
    	
)
    	
$
    	
34.8
    	
 
    
	
NGL frac spread
    	
 
    	
1.3
    	
 
    	
(0.3
    	
)
    	
1.0
    	
 
    
	
Power
    	
 
    	
17.7
    	
 
    	
(0.7
    	
)
    	
17.0
    	
 
    
	
Foreign exchange
    	
 
    	
1.7
    	
 
    	
—
    	
 
    	
1.7
    	
 
    
	
 
    	
 
    	
$
    	
61.7
    	
 
    	
$
    	
(7.2
    	
)
    	
$
    	
54.5
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Risk management   liabilities (b)
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Natural gas
    	
 
    	
$
    	
35.1
    	
 
    	
$
    	
(6.2
    	
)
    	
$
    	
28.9
    	
 
    
	
NGL frac spread
    	
 
    	
25.3
    	
 
    	
(0.3
    	
)
    	
25.0
    	
 
    
	
Power
    	
 
    	
18.2
    	
 
    	
(0.7
    	
)
    	
17.5
    	
 
    
	
 
    	
 
    	
$
    	
78.6
    	
 
    	
$
    	
(7.2
    	
)
    	
$
    	
71.4
    	
 
    

 

(a)         Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $38.6 million and risk management assets (non-current) balance of $15.9 million.

(b)         Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $57.6 million and risk management liabilities (non-current) balance of $13.8 million.

 

35

 

	
 
    	
 
    	
December 31, 2016
    	
 
    
	
Risk management assets (a)
    	
 
    	
Gross amounts of
   recognized
   assets/liabilities
    	
 
    	
Gross amounts
   offset in
   balance sheet
    	
 
    	
Net amounts
   presented in
   balance sheet
    	
 
    
	
Natural gas
    	
 
    	
$
    	
20.1
    	
 
    	
$
    	
(2.9
    	
)
    	
$
    	
17.2
    	
 
    
	
Storage   optimization
    	
 
    	
0.7
    	
 
    	
(0.7
    	
)
    	
—
    	
 
    
	
NGL frac spread
    	
 
    	
3.4
    	
 
    	
—
    	
 
    	
3.4
    	
 
    
	
Power
    	
 
    	
43.5
    	
 
    	
—
    	
 
    	
43.5
    	
 
    
	
Foreign exchange
    	
 
    	
1.8
    	
 
    	
(1.4
    	
)
    	
0.4
    	
 
    
	
 
    	
 
    	
$
    	
69.5
    	
 
    	
$
    	
(5.0
    	
)
    	
$
    	
64.5
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Risk management   liabilities (b)
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Natural gas
    	
 
    	
$
    	
16.5
    	
 
    	
$
    	
(2.9
    	
)
    	
$
    	
13.6
    	
 
    
	
Storage   optimization
    	
 
    	
3.5
    	
 
    	
(0.7
    	
)
    	
2.8
    	
 
    
	
NGL frac spread
    	
 
    	
15.7
    	
 
    	
—
    	
 
    	
15.7
    	
 
    
	
Power
    	
 
    	
13.4
    	
 
    	
—
    	
 
    	
13.4
    	
 
    
	
Foreign exchange
    	
 
    	
1.4
    	
 
    	
(1.4
    	
)
    	
—
    	
 
    
	
 
    	
 
    	
$
    	
50.5
    	
 
    	
$
    	
(5.0
    	
)
    	
$
    	
45.5
    	
 
    

 

(a)         Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $40.4 million and risk management assets (non-current) balance of $24.1 million.

(b)         Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $32.9 million and risk management liabilities (non-current) balance of $12.6 million.

 

Risks associated with financial instruments

 

AltaGas is exposed to various financial risks in the normal course of operations such as market risks resulting from fluctuations in commodity prices, currency exchange rates and interest rates as well as credit risk and liquidity risk.

 

Commodity Price Risk

 

AltaGas enters into financial derivative contracts to manage exposure to fluctuations in commodity prices. The use of derivative instruments is governed under formal risk management policies and is subject to parameters set out by AltaGas’ Risk Management Committee and Board of Directors. AltaGas does not make use of derivative instruments for speculative purposes.

 

Natural Gas

 

In the normal course of business, AltaGas purchases and sells natural gas to support its infrastructure business. The fixed price and market price contracts for both the purchase and sale of natural gas extend to 2022. AltaGas had the following forward contracts and commodity swaps outstanding related to the activities in the energy services business as at December 31, 2017 and 2016:

 

	
December 31, 2017
    	
 
    	
Fixed price
   (per GJ)
    	
 
    	
Period
   (months)
    	
 
    	
Notional volume
   (GJ)
    	
 
    	
Fair Value
   ($ millions)
    	
 
    
	
Sales
    	
 
    	
0.42 to 6.89
    	
 
    	
1-60
    	
 
    	
94,804,039
    	
 
    	
14.8
    	
 
    
	
Purchases
    	
 
    	
0.52 to 6.40
    	
 
    	
1-48
    	
 
    	
61,980,315
    	
 
    	
(16.8
    	
)
    
	
Swaps
    	
 
    	
2.86 to 9.38
    	
 
    	
1-10
    	
 
    	
6,039,642
    	
 
    	
7.9
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
December 31, 2016
    	
 
    	
Fixed price
   (per GJ)
    	
 
    	
Period
   (months)
    	
 
    	
Notional volume
   (GJ)
    	
 
    	
Fair Value
   ($ millions)
    	
 
    
	
Sales
    	
 
    	
1.96 to 8.46
    	
 
    	
1-60
    	
 
    	
63,209,420
    	
 
    	
6.6
    	
 
    
	
Purchases
    	
 
    	
1.94 to 6.50
    	
 
    	
1-60
    	
 
    	
58,913,082
    	
 
    	
(4.4
    	
)
    
	
Swaps
    	
 
    	
8.78 to 9.91
    	
 
    	
1-3
    	
 
    	
474,037
    	
 
    	
1.4
    	
 
    

 

36

 

NGL Frac Spread

 

AltaGas entered into a series of swaps to lock in a portion of the volumes exposed to NGL frac spread. AltaGas had the following contracts outstanding as at December 31, 2017 and 2016:

 

	
December 31, 2017
    	
 
    	
Fixed price
    	
 
    	
Period
   (months)
    	
 
    	
Notional volume
    	
 
    	
Fair Value
   ($ millions)
    	
 
    
	
Propane swaps
    	
 
    	
$28.77 to $49.21 /Bbl
    	
 
    	
1-12
    	
 
    	
1,992,927 Bbl
    	
 
    	
(10.9
    	
)
    
	
Butane swaps
    	
 
    	
$47.83 to $54.67 /Bbl
    	
 
    	
1-12
    	
 
    	
130,088 Bbl
    	
 
    	
(0.3
    	
)
    
	
Crude oil swaps
    	
 
    	
$61.05 to $75.64 /Bbl
    	
 
    	
1-12
    	
 
    	
518,665 Bbl
    	
 
    	
(4.4
    	
)
    
	
Natural gas   swaps
    	
 
    	
$0.42 to $2.27 /GJ
    	
 
    	
1-12
    	
 
    	
11,428,515 GJ
    	
 
    	
(8.4
    	
)
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
December 31, 2016
    	
 
    	
Fixed price
    	
 
    	
Period
   (months)
    	
 
    	
Notional volume
    	
 
    	
Fair Value
   ($ millions)
    	
 
    
	
Propane swaps
    	
 
    	
$25.51 to $29.92 /Bbl
    	
 
    	
1-12
    	
 
    	
1,330,063 Bbl
    	
 
    	
(12.5
    	
)
    
	
Butane swaps
    	
 
    	
$29.88 /Bbl
    	
 
    	
1-3
    	
 
    	
49,500 Bbl
    	
 
    	
(1.0
    	
)
    
	
Crude oil swaps
    	
 
    	
$56.40 to $70.75 /Bbl
    	
 
    	
1-12
    	
 
    	
302,710 Bbl
    	
 
    	
(2.2
    	
)
    
	
Natural gas   swaps
    	
 
    	
$2.23 to $2.88 /GJ
    	
 
    	
1-12
    	
 
    	
7,639,175 GJ
    	
 
    	
3.4
    	
 
    

 

Power

 

AltaGas sells power to the Alberta Electric System Operator at market prices as well as to commercial and industrial users in Alberta at fixed prices. AltaGas’ strategy is to mitigate the cash flow risk to Alberta power prices to provide predictable earnings. Therefore, AltaGas uses third party swaps and purchase contracts to fix the prices over time on a portion of the volumes to mitigate financial exposure associated with the sale contracts. These power purchase and sale contracts extend to 2022. As at December 31, 2017, AltaGas had no intention to terminate any contracts prior to maturity. AltaGas had the following power commodity forward contracts and commodity swaps outstanding as at December 31, 2017 and 2016:

 

	
December 31, 2017
    	
 
    	
Fixed price
   (per MWh)
    	
 
    	
Period
   (months)
    	
 
    	
Notional volume
   (MWh)
    	
 
    	
Fair Value
   ($ millions)
    	
 
    
	
Power sales
    	
 
    	
38.20 to 95.03
    	
 
    	
1-60
    	
 
    	
2,169,321
    	
 
    	
(2.5
    	
)
    
	
Power purchases
    	
 
    	
58.50
    	
 
    	
1-12
    	
 
    	
17,520
    	
 
    	
(4.5
    	
)
    
	
Swap purchases
    	
 
    	
37.50 to 63.50
    	
 
    	
1-48
    	
 
    	
1,563,160
    	
 
    	
6.5
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
December 31, 2016
    	
 
    	
Fixed price
   (per MWh)
    	
 
    	
Period
   (months)
    	
 
    	
Notional volume
   (MWh)
    	
 
    	
Fair Value
   ($ millions)
    	
 
    
	
Power sales
    	
 
    	
34.00 to 99.25
    	
 
    	
1-60
    	
 
    	
2,671,748
    	
 
    	
36.2
    	
 
    
	
Power purchases
    	
 
    	
52.68 to 69.72
    	
 
    	
1-24
    	
 
    	
217,520
    	
 
    	
0.5
    	
 
    
	
Swap purchases
    	
 
    	
30.00 to 58.50
    	
 
    	
1-60
    	
 
    	
1,472,040
    	
 
    	
(6.6
    	
)
    

 

37

 

The table below provides the potential impact on pre-tax income due to changes in the fair value of risk management contracts in place as at December 31, 2017:

 

	
Factor
    	
 
    	
Increase or
   decrease to
   forward prices
    	
 
    	
Increase or decrease to
   income before tax
   ($ millions)
    	
 
    
	
Alberta power   price
    	
 
    	
$
    	
1/MWh
    	
 
    	
0.6
    	
 
    
	
AECO natural gas   price
    	
 
    	
$
    	
0.50/GJ
    	
 
    	
2.2
    	
 
    
	
NGL frac spread:
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Propane
    	
 
    	
$
    	
1/Bbl
    	
 
    	
2.0
    	
 
    
	
Butane
    	
 
    	
$
    	
1/Bbl
    	
 
    	
0.1
    	
 
    
	
Western Texas   Intermediate (WTI) crude oil
    	
 
    	
$
    	
1/Bbl
    	
 
    	
0.8
    	
 
    
	
Natural gas
    	
 
    	
$
    	
0.50/GJ
    	
 
    	
5.8
    	
 
    

 

Foreign Exchange Risk

 

AltaGas is exposed to foreign exchange risk as changes in foreign exchange rates may affect the fair value or future cash flows of the Corporation’s financial instruments. AltaGas has foreign operations whereby the functional currency is the U.S. dollar. As a result, the Corporation’s earnings, cash flows, and OCI are exposed to fluctuations resulting from changes in foreign exchange rates. This risk is partially mitigated to the extent that AltaGas has U.S. dollar-denominated debt and/or preferred shares outstanding. AltaGas may also enter into foreign exchange forward derivatives to manage the risk of fluctuating cash flows due to variations in foreign exchange rates. As at December 31, 2017, AltaGas did not have any outstanding foreign exchange forward contracts. As at December 31, 2016, AltaGas had outstanding foreign exchange forward contracts for US$5.1 million at an average rate of $1.26 Canadian per U.S. dollar which settled in 2017.

 

AltaGas may also designate its U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. As at December 31, 2017, AltaGas designated $nil of outstanding debt as a net investment hedge (December 31, 2016 - US$301.0 million). For the year ended December 31, 2017, AltaGas incurred an after-tax unrealized gain of $6.6 million arising from the translation of debt in OCI (2016 - after-tax unrealized gain of $34.0 million).

 

To mitigate the foreign exchange risks associated with the cash purchase price of WGL, AltaGas has entered into foreign currency option contracts with an aggregate notional value of approximately US$1.2 billion. These foreign currency option contracts do not qualify for hedge accounting. Therefore, all changes in fair value are recognized in net income. For the year ended December 31, 2017, an unrealized loss of $34.3 million was recognized under the line item “unrealized losses from risk management contracts” in the consolidated statement of income in relation to these contracts (2016 - $nil).

 

Interest Rate Risk

 

AltaGas is exposed to interest rate risk as changes in interest rates may impact future cash flows and the fair value of its financial instruments. The Corporation manages its interest rate risk by holding a mix of both fixed and floating interest rate debt. As at December 31, 2017, approximately 93 percent of AltaGas’ total outstanding short-term and long-term debt was at fixed rates. In addition, from time to time, AltaGas may enter into interest rate swap agreements to fix the interest rate on a portion of its banker’s acceptances issued under its credit facilities. There were no outstanding interest rate swaps as at December 31, 2017.

 

Credit Risk

 

Credit risk results from the possibility that a counterparty to a financial instrument fails to fulfill its obligations in accordance with the terms of the contract.

 

AltaGas’ credit policy details the parameters used to grant, measure, monitor and report on credit provided to counterparties. AltaGas minimizes counterparty risk by conducting credit reviews on counterparties in order to establish specific credit limits, both prior to providing products or services and on a recurring basis. In addition, most contracts include credit mitigation clauses that allow AltaGas to obtain financial or performance assurances from counterparties under certain circumstances. AltaGas maintains an allowance for doubtful accounts in the normal course of its business.

 

38

 

 

AltaGas’ maximum credit exposure consists primarily of the carrying value of the non-derivative financial assets and the fair value of derivative financial assets. As at December 31, 2017, AltaGas had no concentration of credit risk with a single counterparty.

 

Accounts Receivable Past Due or Impaired

 

AltaGas had the following past due or impaired accounts receivable (AR):

 

	
As at December 31, 2017
    	
 
    	
Total
    	
 
    	
AR
   accruals
    	
 
    	
Receivables
   impaired
    	
 
    	
Less than
   30 days
    	
 
    	
31 to
   60 days
    	
 
    	
61 to
   90 days
    	
 
    	
Over
   90 days
    	
 
    
	
Trade receivable
    	
 
    	
$
    	
383.0
    	
 
    	
$
    	
184.6
    	
 
    	
$
    	
2.4
    	
 
    	
$
    	
187.0
    	
 
    	
$
    	
7.9
    	
 
    	
$
    	
1.4
    	
 
    	
$
    	
(0.3
    	
)
    
	
Other
    	
 
    	
2.3
    	
 
    	
—
    	
 
    	
—
    	
 
    	
2.3
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    
	
Allowance for credit losses
    	
 
    	
(2.4
    	
)
    	
—
    	
 
    	
(2.4
    	
)
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    
	
 
    	
 
    	
$
    	
382.9
    	
 
    	
$
    	
184.6
    	
 
    	
$
    	
—
    	
 
    	
$
    	
189.3
    	
 
    	
$
    	
7.9
    	
 
    	
$
    	
1.4
    	
 
    	
$
    	
(0.3
    	
)
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
As at December 31, 2016
    	
 
    	
Total
    	
 
    	
AR
   accruals
    	
 
    	
Receivables
   impaired
    	
 
    	
Less than
   30 days
    	
 
    	
31 to
   60 days
    	
 
    	
61 to
   90 days
    	
 
    	
Over
   90 days
    	
 
    
	
Trade receivable
    	
 
    	
$
    	
339.1
    	
 
    	
$
    	
160.4
    	
 
    	
$
    	
2.5
    	
 
    	
$
    	
166.1
    	
 
    	
$
    	
6.4
    	
 
    	
$
    	
2.4
    	
 
    	
$
    	
1.3
    	
 
    
	
Other
    	
 
    	
2.2
    	
 
    	
—
    	
 
    	
—
    	
 
    	
2.2
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    
	
Allowance for credit losses
    	
 
    	
(2.5
    	
)
    	
—
    	
 
    	
(2.5
    	
)
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    
	
 
    	
 
    	
$
    	
338.8
    	
 
    	
$
    	
160.4
    	
 
    	
$
    	
—
    	
 
    	
$
    	
168.3
    	
 
    	
$
    	
6.4
    	
 
    	
$
    	
2.4
    	
 
    	
$
    	
1.3
    	
 
    

 

	
Allowance for credit losses
    	
 
    	
December 31,
   2017
    	
 
    	
December 31,
   2016
    	
 
    
	
Balance,   beginning of year
    	
 
    	
$
    	
2.5
    	
 
    	
$
    	
2.7
    	
 
    
	
Foreign exchange   translation
    	
 
    	
(0.1
    	
)
    	
—
    	
 
    
	
New allowance
    	
 
    	
0.4
    	
 
    	
0.4
    	
 
    
	
Allowance   applied to uncollectible customer accounts
    	
 
    	
(0.4
    	
)
    	
(0.6
    	
)
    
	
Balance, end of   year
    	
 
    	
$
    	
2.4
    	
 
    	
$
    	
2.5
    	
 
    

 

Liquidity Risk

 

Liquidity risk is the risk that AltaGas will not be able to meet its financial obligations as they come due. AltaGas manages this risk through its extensive budgeting and monitoring process to ensure it has sufficient cash and credit facilities to meet its obligations. AltaGas’ objective is to maintain its investment-grade ratings to ensure it has access to debt and equity funding as required.

 

AltaGas had the following contractual maturities with respect to financial liabilities:

 

	
 
    	
 
    	
Payments due by period
    	
 
    
	
As at December 31, 2017
    	
 
    	
Total
    	
 
    	
Less than
   1 year
    	
 
    	
1-3 years
    	
 
    	
4-5 years
    	
 
    	
After
   5 years
    	
 
    
	
Accounts payable   and accrued liabilities
    	
 
    	
$
    	
415.3
    	
 
    	
$
    	
415.3
    	
 
    	
$
    	
—
    	
 
    	
$
    	
—
    	
 
    	
$
    	
—
    	
 
    
	
Dividends   payable
    	
 
    	
32.0
    	
 
    	
32.0
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    
	
Short-term debt
    	
 
    	
46.8
    	
 
    	
46.8
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    
	
Other current   liabilities (a)
    	
 
    	
22.4
    	
 
    	
22.4
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    
	
Other long-term   liabilities (a)
    	
 
    	
146.0
    	
 
    	
—
    	
 
    	
25.7
    	
 
    	
20.8
    	
 
    	
99.5
    	
 
    
	
Risk management   contract liabilities
    	
 
    	
71.4
    	
 
    	
57.6
    	
 
    	
11.1
    	
 
    	
2.7
    	
 
    	
—
    	
 
    
	
Current portion   of long-term debt (b)
    	
 
    	
188.9
    	
 
    	
188.9
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    
	
Long-term debt (b)
    	
 
    	
3,450.9
    	
 
    	
—
    	
 
    	
1,009.1
    	
 
    	
363.8
    	
 
    	
2,078.0
    	
 
    
	
 
    	
 
    	
$
    	
4,373.7
    	
 
    	
$
    	
763.0
    	
 
    	
$
    	
1,045.9
    	
 
    	
$
    	
387.3
    	
 
    	
$
    	
2,177.5
    	
 
    

 

(a)         Excludes non-financial liabilities

(b)         Excludes deferred financing costs and discounts

 

39

 

	
 
    	
 
    	
Payments due by period
    	
 
    
	
As at December 31, 2016
    	
 
    	
Total
    	
 
    	
Less than
   1 year
    	
 
    	
1-3 years
    	
 
    	
4-5 years
    	
 
    	
After
   5 years
    	
 
    
	
Accounts payable   and accrued liabilities
    	
 
    	
$
    	
345.8
    	
 
    	
$
    	
345.8
    	
 
    	
$
    	
—
    	
 
    	
$
    	
—
    	
 
    	
$
    	
—
    	
 
    
	
Dividends   payable
    	
 
    	
29.2
    	
 
    	
29.2
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    
	
Short-term debt
    	
 
    	
128.7
    	
 
    	
128.7
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    
	
Other current   liabilities (a)
    	
 
    	
22.3
    	
 
    	
22.3
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    
	
Other long-term   liabilities (a)
    	
 
    	
152.8
    	
 
    	
—
    	
 
    	
25.2
    	
 
    	
22.4
    	
 
    	
105.2
    	
 
    
	
Risk management   contract liabilities
    	
 
    	
45.5
    	
 
    	
32.9
    	
 
    	
9.1
    	
 
    	
3.5
    	
 
    	
—
    	
 
    
	
Current portion   of long-term debt (b)
    	
 
    	
383.5
    	
 
    	
383.5
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    
	
Long-term debt (b)
    	
 
    	
3,381.2
    	
 
    	
—
    	
 
    	
396.6
    	
 
    	
1,345.2
    	
 
    	
1,639.4
    	
 
    
	
 
    	
 
    	
$
    	
4,489.0
    	
 
    	
$
    	
942.4
    	
 
    	
$
    	
430.9
    	
 
    	
$
    	
1,371.1
    	
 
    	
$
    	
1,744.6
    	
 
    

 

(a)         Excludes non-financial liabilities

(b)         Excludes deferred financing costs and discounts

 

21.  SHAREHOLDERS’ EQUITY

 

Authorization

 

AltaGas is authorized to issue an unlimited number of voting common shares. AltaGas is also authorized to issue preferred shares not to exceed 50 percent of the voting rights attached to the issued and outstanding common shares.

 

Common Shares

 

On June 6, 2016, AltaGas closed a public offering of 14,685,000 common shares, on a bought deal basis, at an issue price of $30 per common share, for total gross proceeds of approximately $440.6 million.

 

Premium DividendTM, Dividend Reinvestment and Optional Cash Purchase Plan (DRIP or the Plan)

 

The Plan consists of three components: a Premium DividendTM component, a Dividend Reinvestment component and an Optional Cash Purchase component.

 

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

 

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

 

Each of the components of the Plan are subject to prorating and other limitations on availability of new common shares in certain events. The “average market price”, in respect of a particular dividend payment date, refers to the arithmetic average (calculated to four decimal places) of the daily volume weighted average trading prices of common shares on the Toronto Stock Exchange for the trading days on which at least one board lot of common shares is traded during the 10 business days immediately preceding the applicable dividend payment date. Such trading prices will be appropriately adjusted for certain capital changes (including common share subdivisions, common share consolidations, certain rights offerings and certain dividends). Shareholders resident outside of Canada are not entitled to participate in the Premium DividendTM component of the Plan. Shareholders resident outside of Canada (other than the U.S.) may participate in the Dividend Reinvestment component or the Optional Cash Purchase component of the Plan only if their participation is permitted by the laws of the jurisdiction in which they

 

TM Denotes trademark of Canaccord Genuity Corp.

 

40

 

reside and provided that AltaGas is satisfied in its sole discretion, that such laws do not subject the Plan or AltaGas to additional legal or regulatory requirements.

 

	
Common Shares Issued and Outstanding
    	
 
    	
Number of
   shares
    	
 
    	
Amount
    	
 
    
	
January 1,   2016
    	
 
    	
146,281,247
    	
 
    	
$
    	
3,168.1
    	
 
    
	
Shares issued on   public offering, net of issuance costs
    	
 
    	
14,685,000
    	
 
    	
422.2
    	
 
    
	
Shares issued   for cash on exercise of options
    	
 
    	
337,750
    	
 
    	
9.3
    	
 
    
	
Deferred taxes   on share issuance cost
    	
 
    	
—
    	
 
    	
0.2
    	
 
    
	
Shares issued   under DRIP
    	
 
    	
5,602,836
    	
 
    	
173.6
    	
 
    
	
December 31,   2016
    	
 
    	
166,906,833
    	
 
    	
3,773.4
    	
 
    
	
Shares issued   for cash on exercise of options
    	
 
    	
240,125
    	
 
    	
6.5
    	
 
    
	
Deferred taxes   on share issuance costs
    	
 
    	
—
    	
 
    	
(8.3
    	
)
    
	
Shares issued   under DRIP
    	
 
    	
8,132,258
    	
 
    	
236.3
    	
 
    
	
Issued   and outstanding at December 31, 2017
    	
 
    	
175,279,216
    	
 
    	
$
    	
4,007.9
    	
 
    

 

Preferred Shares

 

	
As at
    	
 
    	
December 31, 2017
    	
 
    	
December 31, 2016
    	
 
    
	
Issued and Outstanding
    	
 
    	
Number of shares
    	
 
    	
Amount
    	
 
    	
Number of shares
    	
 
    	
Amount
    	
 
    
	
Series A
    	
 
    	
5,511,220
    	
 
    	
$
    	
137.8
    	
 
    	
5,511,220
    	
 
    	
$
    	
137.8
    	
 
    
	
Series B
    	
 
    	
2,488,780
    	
 
    	
62.2
    	
 
    	
2,488,780
    	
 
    	
62.2
    	
 
    
	
Series C
    	
 
    	
8,000,000
    	
 
    	
205.6
    	
 
    	
8,000,000
    	
 
    	
205.6
    	
 
    
	
Series E
    	
 
    	
8,000,000
    	
 
    	
200.0
    	
 
    	
8,000,000
    	
 
    	
200.0
    	
 
    
	
Series G
    	
 
    	
8,000,000
    	
 
    	
200.0
    	
 
    	
8,000,000
    	
 
    	
200.0
    	
 
    
	
Series I
    	
 
    	
8,000,000
    	
 
    	
200.0
    	
 
    	
8,000,000
    	
 
    	
200.0
    	
 
    
	
Series K
    	
 
    	
12,000,000
    	
 
    	
300.0
    	
 
    	
—
    	
 
    	
—
    	
 
    
	
Share issuance   costs, net of taxes
    	
 
    	
 
    	
 
    	
(27.9
    	
)
    	
 
    	
 
    	
(20.5
    	
)
    
	
 
    	
 
    	
52,000,000
    	
 
    	
$
    	
1,277.7
    	
 
    	
40,000,000
    	
 
    	
$
    	
985.1
    	
 
    

 

41

 

The following table outlines the characteristics of the cumulative redeemable preferred shares (a):

 

	
 
    	
 
    	
Current
   yield
    	
 
    	
Annual dividend
   per share(b)
    	
 
    	
Redemption price
   per share
    	
 
    	
Redemption and conversion
   option date(c)(d)
    	
 
    	
Right to convert
   into(d)
    	
 
    
	
Series A (e)
    	
 
    	
3.38
    	
%
    	
$
    	
0.845
    	
 
    	
$
    	
25
    	
 
    	
September 30,   2020
    	
 
    	
Series B
    	
 
    
	
Series B (f)
    	
 
    	
Floating
    	
(f)
    	
Floating
    	
(f)
    	
$
    	
25
    	
 
    	
September 30,   2020
    	
(g)
    	
Series A
    	
 
    
	
Series C (h)
    	
 
    	
5.29
    	
%
    	
US$
    	
1.3225
    	
 
    	
US$
    	
25
    	
 
    	
September 30,   2022
    	
 
    	
Series D
    	
 
    
	
Series E (e)
    	
 
    	
5.00
    	
%
    	
$
    	
1.25
    	
 
    	
$
    	
25
    	
 
    	
December 31,   2018
    	
 
    	
Series F
    	
 
    
	
Series G (e)
    	
 
    	
4.75
    	
%
    	
$
    	
1.1875
    	
 
    	
$
    	
25
    	
 
    	
September 30,   2019
    	
 
    	
Series H
    	
 
    
	
Series I (i)
    	
 
    	
5.25
    	
%
    	
$
    	
1.3125
    	
 
    	
$
    	
25
    	
 
    	
December 31,   2020
    	
 
    	
Series J
    	
 
    
	
Series K (j)
    	
 
    	
5.00
    	
%
    	
$
    	
1.25
    	
 
    	
$
    	
25
    	
 
    	
March 31,   2022
    	
 
    	
Series L
    	
 
    
																

 

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

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

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

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

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

(f)             Holders of Series B Shares will be entitled to receive cumulative quarterly floating dividends, which will reset each quarter thereafter at a rate equal to the sum of the then 90-day government of Canada Treasury Bill rate plus 2.66 percent. Each quarterly dividend is calculated as the annualized amount multiplied by the number of days in the quarter, divided by the number of days in the year. Commencing December 31, 2017, the floating quarterly dividend rate for Series B Shares is $0.21760 per share for the period starting December 31, 2017 to, but excluding, March 31, 2018.

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

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

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

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

 

Share Option Plan

 

AltaGas has an employee share option plan under which employees and directors are eligible to receive grants. As at December 31, 2017, 12,994,161 shares were reserved for issuance under the plan. As at December 31, 2017, options granted under the plan have a term between six and ten years until expiry and vest no longer than over a four-year period.

 

As at December 31, 2017, unexpensed fair value of share option compensation cost associated with future periods was $1.3 million (December 31, 2016 - $1.0 million).

 

42

 

The following table summarizes information about the Corporation’s share options:

 

	
As at
    	
 
    	
December 31, 2017
    	
 
    	
December 31, 2016
    	
 
    
	
 
    	
 
    	
Options outstanding
    	
 
    	
Options outstanding
    	
 
    
	
 
    	
 
    	
Number of
   options
    	
 
    	
Exercise
   price(a)
    	
 
    	
Number of
   options
    	
 
    	
Exercise
   price(a)
    	
 
    
	
Share options   outstanding, beginning of year
    	
 
    	
4,119,386
    	
 
    	
$
    	
32.39
    	
 
    	
4,559,261
    	
 
    	
$
    	
32.02
    	
 
    
	
Granted
    	
 
    	
848,000
    	
 
    	
30.80
    	
 
    	
89,500
    	
 
    	
31.45
    	
 
    
	
Exercised
    	
 
    	
(240,125
    	
)
    	
24.63
    	
 
    	
(337,750
    	
)
    	
25.28
    	
 
    
	
Forfeited
    	
 
    	
(193,500
    	
)
    	
36.36
    	
 
    	
(191,625
    	
)
    	
35.60
    	
 
    
	
Share   options outstanding, end of year
    	
 
    	
4,533,761
    	
 
    	
$
    	
32.35
    	
 
    	
4,119,386
    	
 
    	
$
    	
32.39
    	
 
    
	
Share   options exercisable, end of year
    	
 
    	
3,326,197
    	
 
    	
$
    	
31.93
    	
 
    	
3,279,133
    	
 
    	
$
    	
30.56
    	
 
    

 

(a)         Weighted average.

 

As at December 31, 2017, the aggregate intrinsic value of the total options exercisable was $6.0 million (December 31, 2016 - $16.5 million), the total intrinsic value of options outstanding was $6.0 million (December 31, 2016 - $16.8 million) and the total intrinsic value of options exercised was $1.4 million (December 31, 2016 - $2.6 million).

 

The following table summarizes the employee share option plan as at December 31, 2017:

 

	
 
    	
 
    	
Options outstanding
    	
 
    	
Options exercisable
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
Weighted
    	
 
    	
Weighted average
    	
 
    	
 
    	
 
    	
Weighted
    	
 
    	
Weighted average
    	
 
    
	
 
    	
 
    	
Number
    	
 
    	
average
    	
 
    	
remaining
    	
 
    	
Number
    	
 
    	
average
    	
 
    	
remaining
    	
 
    
	
 
    	
 
    	
outstanding
    	
 
    	
exercise price
    	
 
    	
contractual life
    	
 
    	
exercisable
    	
 
    	
exercise price
    	
 
    	
contractual life
    	
 
    
	
$14.24 to $18.00
    	
 
    	
157,750
    	
 
    	
$
    	
15.22
    	
 
    	
1.29
    	
 
    	
157,750
    	
 
    	
$
    	
15.22
    	
 
    	
1.29
    	
 
    
	
$18.01 to $25.08
    	
 
    	
480,975
    	
 
    	
20.88
    	
 
    	
2.69
    	
 
    	
480,975
    	
 
    	
20.88
    	
 
    	
2.69
    	
 
    
	
$25.09 to $50.89
    	
 
    	
3,895,036
    	
 
    	
34.45
    	
 
    	
4.04
    	
 
    	
2,687,472
    	
 
    	
34.89
    	
 
    	
3.75
    	
 
    
	
 
    	
 
    	
4,533,761
    	
 
    	
$
    	
32.35
    	
 
    	
3.80
    	
 
    	
3,326,197
    	
 
    	
$
    	
31.93
    	
 
    	
3.48
    	
 
    

 

The fair value of each option granted is estimated on the date of grant using the Black-Scholes-Merton option pricing model. The weighted average grant date fair value and assumptions are as follows:

 

	
Year ended December 31
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Fair value per   option ($)
    	
 
    	
1.91
    	
 
    	
2.09
    	
 
    
	
Risk-free   interest rate (%)
    	
 
    	
1.31
    	
 
    	
1.12
    	
 
    
	
Expected life   (years)
    	
 
    	
6
    	
 
    	
6
    	
 
    
	
Expected   volatility (%)
    	
 
    	
21.05
    	
 
    	
20.65
    	
 
    
	
Annual dividend   per share ($)
    	
 
    	
2.12
    	
 
    	
1.98
    	
 
    
	
Forfeiture rate   (%) (a)
    	
 
    	
—
    	
 
    	
16.00
    	
 
    

 

(a)         Effective January 1, 2017, AltaGas adopted ASU No. 2016-09 and elected to account for forfeitures when they occur instead of estimating the number of awards that are expected to vest. Refer to Note 2.

 

43

 

MTIP and DSUP

 

AltaGas has a MTIP for employees and executive officers, which includes RUs and PUs with vesting periods between 36 to 44 months from the grant date. In addition, AltaGas has a DSUP, which allows granting of DSUs to directors. DSUs granted under the DSUP vests immediately but settlement of the DSUs occur when the individual ceases to be a director.

 

	
PUs, RUs, and DSUs
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
(number of units)
    	
 
    	
December 31, 2017
    	
 
    	
December 31, 2016
    	
 
    
	
Balance,   beginning of year
    	
 
    	
364,839
    	
 
    	
409,037
    	
 
    
	
Granted
    	
 
    	
386,126
    	
 
    	
91,288
    	
 
    
	
Additional units   added by performance factor
    	
 
    	
24,301
    	
 
    	
—
    	
 
    
	
Vested and paid   out
    	
 
    	
(221,775
    	
)
    	
(136,359
    	
)
    
	
Forfeited
    	
 
    	
(27,279
    	
)
    	
(13,565
    	
)
    
	
Units in lieu of   dividends
    	
 
    	
38,337
    	
 
    	
14,438
    	
 
    
	
Outstanding, end   of year
    	
 
    	
564,549
    	
 
    	
364,839
    	
 
    

 

For the year ended December 31, 2017, the compensation expense recorded for the MTIP and DSUP was $9.1 million (2016 - $7.0 million). As at December 31, 2017, the unrecognized compensation expense relating to the remaining vesting period for the MTIP was $8.4 million (December 31, 2016 - $11.9 million) and is expected to be recognized over the vesting period.

 

22.  NET INCOME PER COMMON SHARE

 

The following table summarizes the computation of net income per common share:

 

	
For the year ended December 31
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Numerator:
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Net income   applicable to controlling interests
    	
 
    	
$
    	
91.6
    	
 
    	
$
    	
203.5
    	
 
    
	
Less: Preferred   share dividends
    	
 
    	
(61.3
    	
)
    	
(48.1
    	
)
    
	
Net income   applicable to common shares
    	
 
    	
$
    	
30.3
    	
 
    	
$
    	
155.4
    	
 
    
	
Denominator:
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
(millions)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Weighted average   number of common shares outstanding
    	
 
    	
171.0
    	
 
    	
157.2
    	
 
    
	
Dilutive equity   instruments(a)
    	
 
    	
0.3
    	
 
    	
0.4
    	
 
    
	
Weighted average   number of common shares outstanding - diluted
    	
 
    	
171.3
    	
 
    	
157.6
    	
 
    
	
Basic net income   per common share
    	
 
    	
$
    	
0.18
    	
 
    	
$
    	
0.99
    	
 
    
	
Diluted net   income per common share
    	
 
    	
$
    	
0.18
    	
 
    	
$
    	
0.99
    	
 
    

 

(a)         Includes all options that have a strike price lower than the share price of AltaGas’ common shares as at December 31, 2017 and 2016.

 

For the year ended December 31, 2017, 2.8 million of share options (2016 – 2.2 million) were excluded from the diluted net income per share calculation as their effects were anti-dilutive.

 

23.  OTHER INCOME

 

	
Year ended December 31
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Gains (losses)   from sale of assets
    	
 
    	
$
    	
(2.7
    	
)
    	
$
    	
4.2
    	
 
    
	
Interest income   and other revenue
    	
 
    	
10.3
    	
 
    	
3.9
    	
 
    
	
Unrealized gains   from held-for-trading assets
    	
 
    	
3.6
    	
 
    	
0.5
    	
 
    
	
 
    	
 
    	
$
    	
11.2
    	
 
    	
$
    	
8.6
    	
 
    

 

44

 

 

24.  OPERATING LEASES

 

Certain of AltaGas’ revenues are obtained through power purchase agreements or take-or-pay contracts whereby AltaGas is the lessor in these operating lease arrangements. Minimum lease payments received are amortized over the term of the lease. Contingent rentals are recorded when the condition that created the present obligation to make such payments occurs such as when actual electricity is generated and delivered. The carrying value of property, plant, and equipment associated with these leases was $3.0 billion as at December 31, 2017 (December 31, 2016 - $3.1 billion). For the year ended December 31, 2017, the total revenue earned from minimum lease payments was $290.8 million (2016 - $238.2 million) and from contingent rentals was $175.6 million (2016 - $116.3 million).

 

The following table sets forth the future fixed minimum revenue related to the operating leases for the years ended December 31:

 

	
2018
    	
 
    	
289.7
    
	
2019
    	
 
    	
287.4
    
	
2020
    	
 
    	
250.2
    
	
2021
    	
 
    	
208.8
    
	
2022
    	
 
    	
194.5
    

 

25.  PENSION PLANS AND RETIREE BENEFITS

 

The costs of the defined benefit and post-retirement benefit plans are based on management’s estimate of the future rate of return on the fair value of pension plan assets, salary escalations, mortality rates and other factors affecting the payment of future benefits.

 

Defined Contribution Plan

 

AltaGas has a defined contribution (DC) pension plan for substantially all employees who are not members of defined benefit plans. The pension cost recorded for the DC plan was $8.4 million for the year ended December 31, 2017 (2016 - $8.1 million).

 

Defined Benefit Plans

 

AltaGas has several defined benefit pension plans in Canada and the United States for unionized and non-unionized employees. These benefit plans are funded.

 

Supplemental Executive Retirement Plan (SERP)

 

AltaGas has non-registered, defined benefit plans that provide defined benefit pension benefits to eligible executives based on average earnings, years of service and age at retirement. The SERP benefits will be paid from the general revenue of the Corporation as payments come due. Security will be provided for the SERP benefits through a letter of credit within a retirement compensation arrangement trust account.

 

Post-Retirement Benefits

 

AltaGas has several post-retirement benefit plans for unionized and non-unionized employees in Canada and the United States. Benefits provided to retired employees are limited to the payment of life insurance and health insurance premiums. These benefit plans are not funded, except for one plan. Post-retirement benefit plans in the United States provide certain medical and prescription drug benefits to eligible retired employees, their spouses and covered dependents. Benefits are based on a combination of the retiree’s age and years of service at retirement. These benefit plans are funded.

 

AltaGas’ most recent actuarial valuation of the Canadian defined benefit plans for funding purposes was completed in 2016. AltaGas is required to file an actuarial valuation of its Canadian defined benefit plans with the pension regulators at least every three years. The next actuarial valuation for funding purposes is required to be completed as of a date no later than December 31, 2019 and is expected to be filed with the pension regulators in 2020. Actuarial valuations are required annually for AltaGas’ U.S. defined benefit plans.

 

45

 

The following table summarizes the details of the defined benefit plans, including the SERP and post-retirement plans in Canada and the United States:

 

	
 
    	
 
    	
Canada
    	
 
    	
United States
    	
 
    	
Total
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
Post-
    	
 
    	
 
    	
 
    	
Post-
    	
 
    	
 
    	
 
    	
Post-
    	
 
    
	
 
    	
 
    	
Defined
    	
 
    	
Retirement
    	
 
    	
Defined
    	
 
    	
Retirement
    	
 
    	
Defined
    	
 
    	
Retirement
    	
 
    
	
Year ended December 31, 2017
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    
	
Accrued   benefit obligation
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Balance,   beginning of year
    	
 
    	
$
    	
150.0
    	
 
    	
$
    	
16.4
    	
 
    	
$
    	
290.5
    	
 
    	
$
    	
72.7
    	
 
    	
$
    	
440.5
    	
 
    	
$
    	
89.1
    	
 
    
	
Actuarial loss   (gain)
    	
 
    	
8.3
    	
 
    	
(1.6
    	
)
    	
23.2
    	
 
    	
14.4
    	
 
    	
31.5
    	
 
    	
12.8
    	
 
    
	
Current service   cost
    	
 
    	
7.9
    	
 
    	
0.7
    	
 
    	
8.0
    	
 
    	
1.8
    	
 
    	
15.9
    	
 
    	
2.5
    	
 
    
	
Member   contributions
    	
 
    	
0.2
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
0.2
    	
 
    	
—
    	
 
    
	
Interest cost
    	
 
    	
5.8
    	
 
    	
0.6
    	
 
    	
11.7
    	
 
    	
2.9
    	
 
    	
17.5
    	
 
    	
3.5
    	
 
    
	
Benefits paid
    	
 
    	
(6.3
    	
)
    	
(0.3
    	
)
    	
(8.6
    	
)
    	
(3.2
    	
)
    	
(14.9
    	
)
    	
(3.5
    	
)
    
	
Expenses paid
    	
 
    	
(0.3
    	
)
    	
—
    	
 
    	
(0.8
    	
)
    	
(0.1
    	
)
    	
(1.1
    	
)
    	
(0.1
    	
)
    
	
Plan settlements
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(0.5
    	
)
    	
—
    	
 
    	
(0.5
    	
)
    
	
Foreign exchange   translation
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(20.2
    	
)
    	
(5.3
    	
)
    	
(20.2
    	
)
    	
(5.3
    	
)
    
	
Balance, end of   year
    	
 
    	
$
    	
165.6
    	
 
    	
$
    	
15.8
    	
 
    	
$
    	
303.8
    	
 
    	
$
    	
82.7
    	
 
    	
$
    	
469.4
    	
 
    	
$
    	
98.5
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Plan   assets
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Fair value,   beginning of year
    	
 
    	
$
    	
101.5
    	
 
    	
$
    	
6.8
    	
 
    	
$
    	
226.9
    	
 
    	
$
    	
67.2
    	
 
    	
$
    	
328.4
    	
 
    	
$
    	
74.0
    	
 
    
	
Actual return on   plan assets
    	
 
    	
8.5
    	
 
    	
0.4
    	
 
    	
37.9
    	
 
    	
11.0
    	
 
    	
46.4
    	
 
    	
11.4
    	
 
    
	
Employer contributions
    	
 
    	
11.6
    	
 
    	
1.2
    	
 
    	
9.5
    	
 
    	
0.6
    	
 
    	
21.1
    	
 
    	
1.8
    	
 
    
	
Member   contributions
    	
 
    	
0.2
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
0.2
    	
 
    	
—
    	
 
    
	
Benefits paid
    	
 
    	
(6.3
    	
)
    	
(0.3
    	
)
    	
(8.6
    	
)
    	
(3.2
    	
)
    	
(14.9
    	
)
    	
(3.5
    	
)
    
	
Expenses paid
    	
 
    	
(0.3
    	
)
    	
—
    	
 
    	
(0.8
    	
)
    	
(0.1
    	
)
    	
(1.1
    	
)
    	
(0.1
    	
)
    
	
Foreign exchange   translation
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(16.2
    	
)
    	
(4.7
    	
)
    	
(16.2
    	
)
    	
(4.7
    	
)
    
	
Fair value, end   of year
    	
 
    	
$
    	
115.2
    	
 
    	
$
    	
8.1
    	
 
    	
$
    	
248.7
    	
 
    	
$
    	
70.8
    	
 
    	
$
    	
363.9
    	
 
    	
$
    	
78.9
    	
 
    
	
Net amount   recognized
    	
 
    	
$
    	
(50.4
    	
)
    	
$
    	
(7.7
    	
)
    	
$
    	
(55.1
    	
)
    	
$
    	
(11.9
    	
)
    	
$
    	
(105.5
    	
)
    	
$
    	
(19.6
    	
)
    

 

46

 

	
 
    	
 
    	
Canada
    	
 
    	
United States
    	
 
    	
Total
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
Post-
    	
 
    	
 
    	
 
    	
Post-
    	
 
    	
 
    	
 
    	
Post-
    	
 
    
	
 
    	
 
    	
Defined
    	
 
    	
Retirement
    	
 
    	
Defined
    	
 
    	
Retirement
    	
 
    	
Defined
    	
 
    	
Retirement
    	
 
    
	
Year ended December 31, 2016
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    
	
Accrued   benefit obligation
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Balance,   beginning of year
    	
 
    	
$
    	
135.1
    	
 
    	
$
    	
14.7
    	
 
    	
$
    	
280.0
    	
 
    	
$
    	
88.0
    	
 
    	
$
    	
415.1
    	
 
    	
$
    	
102.7
    	
 
    
	
Actuarial loss   (gain)
    	
 
    	
7.9
    	
 
    	
0.8
    	
 
    	
8.8
    	
 
    	
(13.4
    	
)
    	
16.7
    	
 
    	
(12.6
    	
)
    
	
Current service   cost
    	
 
    	
7.0
    	
 
    	
0.6
    	
 
    	
7.1
    	
 
    	
1.9
    	
 
    	
14.1
    	
 
    	
2.5
    	
 
    
	
Member   contributions
    	
 
    	
0.2
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
0.2
    	
 
    	
—
    	
 
    
	
Interest cost
    	
 
    	
5.6
    	
 
    	
0.6
    	
 
    	
11.8
    	
 
    	
3.9
    	
 
    	
17.4
    	
 
    	
4.5
    	
 
    
	
Benefits paid
    	
 
    	
(5.7
    	
)
    	
(0.3
    	
)
    	
(8.2
    	
)
    	
(2.9
    	
)
    	
(13.9
    	
)
    	
(3.2
    	
)
    
	
Expenses paid
    	
 
    	
(0.3
    	
)
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(0.3
    	
)
    	
—
    	
 
    
	
Net transfer in   (out) (including the effect of acquisitions/divestitures)
    	
 
    	
0.2
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
0.2
    	
 
    	
—
    	
 
    
	
Plan amendments
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(2.0
    	
)
    	
—
    	
 
    	
(2.0
    	
)
    
	
Plan settlements
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(0.9
    	
)
    	
—
    	
 
    	
(0.9
    	
)
    	
—
    	
 
    
	
Foreign exchange   translation
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(8.1
    	
)
    	
(2.8
    	
)
    	
(8.1
    	
)
    	
(2.8
    	
)
    
	
Balance, end of   year
    	
 
    	
$
    	
150.0
    	
 
    	
$
    	
16.4
    	
 
    	
$
    	
290.5
    	
 
    	
$
    	
72.7
    	
 
    	
$
    	
440.5
    	
 
    	
$
    	
89.1
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Plan   assets
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Fair value,   beginning of year
    	
 
    	
$
    	
93.5
    	
 
    	
$
    	
5.7
    	
 
    	
$
    	
214.8
    	
 
    	
$
    	
66.2
    	
 
    	
$
    	
308.3
    	
 
    	
$
    	
71.9
    	
 
    
	
Actual return on   plan assets
    	
 
    	
6.1
    	
 
    	
0.2
    	
 
    	
15.9
    	
 
    	
4.9
    	
 
    	
22.0
    	
 
    	
5.1
    	
 
    
	
Employer contributions
    	
 
    	
7.5
    	
 
    	
1.2
    	
 
    	
11.5
    	
 
    	
0.9
    	
 
    	
19.0
    	
 
    	
2.1
    	
 
    
	
Member   contributions
    	
 
    	
0.2
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
0.2
    	
 
    	
—
    	
 
    
	
Benefits paid
    	
 
    	
(5.7
    	
)
    	
(0.3
    	
)
    	
(8.2
    	
)
    	
(2.9
    	
)
    	
(13.9
    	
)
    	
(3.2
    	
)
    
	
Expenses paid
    	
 
    	
(0.3
    	
)
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(0.3
    	
)
    	
—
    	
 
    
	
Acquisitions/   divestitures
    	
 
    	
0.2
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
0.2
    	
 
    	
—
    	
 
    
	
Plan settlements
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(0.9
    	
)
    	
—
    	
 
    	
(0.9
    	
)
    	
—
    	
 
    
	
Foreign exchange   translation
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(6.2
    	
)
    	
(1.9
    	
)
    	
(6.2
    	
)
    	
(1.9
    	
)
    
	
Fair value, end   of year
    	
 
    	
$
    	
101.5
    	
 
    	
$
    	
6.8
    	
 
    	
$
    	
226.9
    	
 
    	
$
    	
67.2
    	
 
    	
$
    	
328.4
    	
 
    	
$
    	
74.0
    	
 
    
	
Net amount   recognized
    	
 
    	
$
    	
(48.5
    	
)
    	
$
    	
(9.6
    	
)
    	
$
    	
(63.6
    	
)
    	
$
    	
(5.5
    	
)
    	
$
    	
(112.1
    	
)
    	
$
    	
(15.1
    	
)
    

 

The following amounts were included in the Consolidated Balance Sheets:

 

	
 
    	
 
    	
December 31, 2017
    	
 
    	
December 31, 2016
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
Post-
    	
 
    	
 
    	
 
    	
 
    	
 
    	
Post-
    	
 
    	
 
    	
 
    
	
 
    	
 
    	
Defined
    	
 
    	
Retirement
    	
 
    	
 
    	
 
    	
Defined
    	
 
    	
Retirement
    	
 
    	
 
    	
 
    
	
 
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    	
Total
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    	
Total
    	
 
    
	
Other assets (note 10)
    	
 
    	
$
    	
—
    	
 
    	
$
    	
—
    	
 
    	
$
    	
—
    	
 
    	
$
    	
—
    	
 
    	
$
    	
2.8
    	
 
    	
$
    	
2.8
    	
 
    
	
Accounts payable   and accrued liabilities
    	
 
    	
(0.6
    	
)
    	
—
    	
 
    	
(0.6
    	
)
    	
(0.5
    	
)
    	
—
    	
 
    	
(0.5
    	
)
    
	
Future employee   obligations
    	
 
    	
(104.9
    	
)
    	
(19.6
    	
)
    	
(124.5
    	
)
    	
(111.6
    	
)
    	
(17.9
    	
)
    	
(129.5
    	
)
    
	
 
    	
 
    	
$
    	
(105.5
    	
)
    	
$
    	
(19.6
    	
)
    	
$
    	
(125.1
    	
)
    	
$
    	
(112.1
    	
)
    	
$
    	
(15.1
    	
)
    	
$
    	
(127.2
    	
)
    

 

The funded status based on the accumulated benefit obligation for all defined benefit plans were:

 

	
 
    	
 
    	
December 31, 2017
    	
 
    	
December 31, 2016
    	
 
    
	
 
    	
 
    	
Canada
    	
 
    	
United States
    	
 
    	
Canada
    	
 
    	
United States
    	
 
    
	
Accumulated   benefit obligation (a)
    	
 
    	
$
    	
(143.9
    	
)
    	
$
    	
(274.2
    	
)
    	
$
    	
(128.9
    	
)
    	
$
    	
(262.1
    	
)
    
	
Fair value of   plan assets
    	
 
    	
115.2
    	
 
    	
248.7
    	
 
    	
101.5
    	
 
    	
226.9
    	
 
    
	
Funded status
    	
 
    	
$
    	
(28.7
    	
)
    	
$
    	
(25.5
    	
)
    	
$
    	
(27.4
    	
)
    	
$
    	
(35.2
    	
)
    

 

(a)         Accumulated benefit obligation differs from accrued benefit obligation in that it does not include an assumption with respect to future compensation levels.

 

47

 

The following amounts were not recognized in the net periodic benefit cost and recorded in the other comprehensive losses:

 

	
 
    	
 
    	
Canada
    	
 
    	
United States
    	
 
    	
Total
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
Post-
    	
 
    	
 
    	
 
    	
Post-
    	
 
    	
 
    	
 
    	
Post-
    	
 
    
	
 
    	
 
    	
Defined
    	
 
    	
Retirement
    	
 
    	
Defined
    	
 
    	
Retirement
    	
 
    	
Defined
    	
 
    	
Retirement
    	
 
    
	
Year ended December 31, 2017
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    
	
Past service   cost
    	
 
    	
$
    	
(0.4
    	
)
    	
$
    	
—
    	
 
    	
$
    	
—
    	
 
    	
$
    	
—
    	
 
    	
$
    	
(0.4
    	
)
    	
$
    	
—
    	
 
    
	
Net actuarial   loss
    	
 
    	
(13.9
    	
)
    	
(1.3
    	
)
    	
—
    	
 
    	
—
    	
 
    	
(13.9
    	
)
    	
(1.3
    	
)
    
	
Recognized in   AOCI pre-tax
    	
 
    	
$
    	
(14.3
    	
)
    	
$
    	
(1.3
    	
)
    	
$
    	
—
    	
 
    	
$
    	
—
    	
 
    	
$
    	
(14.3
    	
)
    	
$
    	
(1.3
    	
)
    
	
Increase   (decrease) by the amount    included in deferred tax   liabilities
    	
 
    	
4.0
    	
 
    	
0.3
    	
 
    	
(0.1
    	
)
    	
—
    	
 
    	
3.9
    	
 
    	
0.3
    	
 
    
	
Net amount in   AOCI after-tax
    	
 
    	
$
    	
(10.3
    	
)
    	
$
    	
(1.0
    	
)
    	
$
    	
(0.1
    	
)
    	
$
    	
—
    	
 
    	
$
    	
(10.4
    	
)
    	
$
    	
(1.0
    	
)
    

 

	
 
    	
 
    	
Canada
    	
 
    	
United States
    	
 
    	
Total
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
Post-
    	
 
    	
 
    	
 
    	
Post-
    	
 
    	
 
    	
 
    	
Post-
    	
 
    
	
 
    	
 
    	
Defined
    	
 
    	
Retirement
    	
 
    	
Defined
    	
 
    	
Retirement
    	
 
    	
Defined
    	
 
    	
Retirement
    	
 
    
	
Year ended December 31, 2016
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    
	
Past service   cost
    	
 
    	
$
    	
(0.5
    	
)
    	
$
    	
—
    	
 
    	
$
    	
—
    	
 
    	
$
    	
(0.3
    	
)
    	
$
    	
(0.5
    	
)
    	
$
    	
(0.3
    	
)
    
	
Net actuarial   loss
    	
 
    	
(13.7
    	
)
    	
(1.0
    	
)
    	
—
    	
 
    	
—
    	
 
    	
(13.7
    	
)
    	
(1.0
    	
)
    
	
Recognized in   AOCI pre-tax
    	
 
    	
$
    	
(14.2
    	
)
    	
$
    	
(1.0
    	
)
    	
$
    	
—
    	
 
    	
$
    	
(0.3
    	
)
    	
$
    	
(14.2
    	
)
    	
$
    	
(1.3
    	
)
    
	
Increase   (decrease) by the amount    included in deferred tax   liabilities
    	
 
    	
3.8
    	
 
    	
0.3
    	
 
    	
—
    	
 
    	
0.1
    	
 
    	
3.8
    	
 
    	
0.4
    	
 
    
	
Net amount in   AOCI after-tax
    	
 
    	
$
    	
(10.4
    	
)
    	
$
    	
(0.7
    	
)
    	
$
    	
—
    	
 
    	
$
    	
(0.2
    	
)
    	
$
    	
(10.4
    	
)
    	
$
    	
(0.9
    	
)
    

 

The costs of the defined benefit and post-retirement benefit plans are based on Management’s estimate of the future rate of return on the fair value of pension plan assets, salary escalations, mortality rates and other factors affecting the payment of future benefits.

 

	
 
    	
 
    	
 
    	
 
    	
Post-
    	
 
    
	
 
    	
 
    	
Defined
    	
 
    	
Retirement
    	
 
    
	
Amounts to be amortized in the next fiscal year from AOCI
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    
	
Past service   costs
    	
 
    	
$
    	
0.1
    	
 
    	
$
    	
—
    	
 
    
	
Actuarial losses
    	
 
    	
0.9
    	
 
    	
—
    	
 
    
	
Total
    	
 
    	
$
    	
1.0
    	
 
    	
$
    	
—
    	
 
    

 

The net pension expense by plan for the period was as follows:

 

	
 
    	
 
    	
Year ended December 31, 2017
    	
 
    
	
 
    	
 
    	
Canada
    	
 
    	
United States
    	
 
    	
Total
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
Post-
    	
 
    	
 
    	
 
    	
Post-
    	
 
    	
 
    	
 
    	
Post-
    	
 
    
	
 
    	
 
    	
Defined
    	
 
    	
retirement
    	
 
    	
Defined
    	
 
    	
retirement
    	
 
    	
Defined
    	
 
    	
retirement
    	
 
    
	
 
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    
	
Current service   cost
    	
 
    	
$
    	
7.9
    	
 
    	
$
    	
0.7
    	
 
    	
$
    	
8.0
    	
 
    	
$
    	
1.8
    	
 
    	
$
    	
15.9
    	
 
    	
$
    	
2.5
    	
 
    
	
Interest cost
    	
 
    	
5.8
    	
 
    	
0.6
    	
 
    	
11.7
    	
 
    	
2.9
    	
 
    	
17.5
    	
 
    	
3.5
    	
 
    
	
Expected return   on plan assets
    	
 
    	
(5.9
    	
)
    	
(0.2
    	
)
    	
(16.9
    	
)
    	
(4.7
    	
)
    	
(22.8
    	
)
    	
(4.9
    	
)
    
	
Settlement of   plan
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
0.2
    	
 
    	
—
    	
 
    	
0.2
    	
 
    
	
Amortization of   past service cost
    	
 
    	
0.2
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
0.2
    	
 
    	
—
    	
 
    
	
Amortization of net   actuarial loss
    	
 
    	
0.7
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
0.7
    	
 
    	
—
    	
 
    
	
Amortization of   regulatory asset/liability
    	
 
    	
1.3
    	
 
    	
0.1
    	
 
    	
6.5
    	
 
    	
(0.3
    	
)
    	
7.8
    	
 
    	
(0.2
    	
)
    
	
Net benefit cost   (income) recognized
    	
 
    	
$
    	
10.0
    	
 
    	
$
    	
1.2
    	
 
    	
$
    	
9.3
    	
 
    	
$
    	
(0.1
    	
)
    	
$
    	
19.3
    	
 
    	
$
    	
1.1
    	
 
    

 

48

 

	
 
    	
 
    	
Year ended December 31, 2016
    	
 
    
	
 
    	
 
    	
Canada
    	
 
    	
United States
    	
 
    	
Total
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
Post-
    	
 
    	
 
    	
 
    	
Post-
    	
 
    	
 
    	
 
    	
Post-
    	
 
    
	
 
    	
 
    	
Defined
    	
 
    	
retirement
    	
 
    	
Defined
    	
 
    	
retirement
    	
 
    	
Defined
    	
 
    	
retirement
    	
 
    
	
 
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    
	
Current service   cost
    	
 
    	
$
    	
7.0
    	
 
    	
$
    	
0.6
    	
 
    	
$
    	
7.1
    	
 
    	
$
    	
1.9
    	
 
    	
$
    	
14.1
    	
 
    	
$
    	
2.5
    	
 
    
	
Interest cost
    	
 
    	
5.6
    	
 
    	
0.6
    	
 
    	
11.8
    	
 
    	
3.9
    	
 
    	
17.4
    	
 
    	
4.5
    	
 
    
	
Expected return   on plan assets
    	
 
    	
(5.3
    	
)
    	
(0.2
    	
)
    	
(15.1
    	
)
    	
(4.5
    	
)
    	
(20.4
    	
)
    	
(4.7
    	
)
    
	
Settlement   (gain) loss
    	
 
    	
—
    	
 
    	
—
    	
 
    	
0.1
    	
 
    	
—
    	
 
    	
0.1
    	
 
    	
—
    	
 
    
	
Amortization of   past service cost
    	
 
    	
0.2
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
0.2
    	
 
    	
—
    	
 
    
	
Amortization of   net actuarial loss
    	
 
    	
0.8
    	
 
    	
0.1
    	
 
    	
—
    	
 
    	
—
    	
 
    	
0.8
    	
 
    	
0.1
    	
 
    
	
Amortization of   regulatory asset
    	
 
    	
1.2
    	
 
    	
—
    	
 
    	
6.3
    	
 
    	
0.8
    	
 
    	
7.5
    	
 
    	
0.8
    	
 
    
	
Net benefit cost   recognized
    	
 
    	
$
    	
9.5
    	
 
    	
$
    	
1.1
    	
 
    	
$
    	
10.2
    	
 
    	
$
    	
2.1
    	
 
    	
$
    	
19.7
    	
 
    	
3.2
    	
 
    
																				

 

The objective of the Corporation’s investment policy is to maximize long-term total return while protecting the capital value of the fund from major market fluctuations through diversification and selection of investments.

 

The objective for fund returns, over three to five-year periods, is the sum of two components - a passive component, which is the benchmark index market returns for the asset mix in effect, plus the added value expected from active management. It is the Corporation’s belief that the potential additional returns justify the additional risk associated with active management. The risk inherent in the investment strategy over a market cycle (a three-to five-year period) is two-fold. There is a risk that the market returns, as measured by the benchmark returns, will not be in line with expectations. The other risk is that the expected added value of active management over passive management will not be realized over the time period prescribed in each fund manager’s mandate. There is also the risk of annual volatility in returns, which means that in any one year the actual return may be very different from the expected return.

 

Cash and money market investments may be held from time to time as short-term investment decisions at the discretion of the fund manager(s) within the constraints prescribed by their mandate(s).

 

The Corporation has a target asset mix for the Canadian plans of 45 percent to 55 percent fixed income assets. The target asset mix for the U.S. plans is 33 percent fixed income assets. These objectives have taken into account the nature of the liabilities and the risk-reward tolerance of the Corporation.

 

49

 

The collective investment mixes for the plans are as follows as at December 31, 2017:

 

	
Canada
    	
 
    	
Fair value
    	
 
    	
Level 1
    	
 
    	
Level 2
    	
 
    	
Percentage of
   Plan Assets 
   (%)
    	
 
    
	
Cash and   short-term equivalents
    	
 
    	
$
    	
6.2
    	
 
    	
$
    	
6.2
    	
 
    	
$
    	
—
    	
 
    	
5.0
    	
 
    
	
Canadian   equities
    	
 
    	
40.8
    	
 
    	
40.8
    	
 
    	
—
    	
 
    	
33.1
    	
 
    
	
Foreign equities
    	
 
    	
22.7
    	
 
    	
22.7
    	
 
    	
—
    	
 
    	
18.4
    	
 
    
	
Fixed income
    	
 
    	
47.1
    	
 
    	
47.0
    	
 
    	
0.1
    	
 
    	
38.2
    	
 
    
	
Real estate
    	
 
    	
6.5
    	
 
    	
—
    	
 
    	
6.5
    	
 
    	
5.3
    	
 
    
	
 
    	
 
    	
$
    	
123.3
    	
 
    	
$
    	
116.7
    	
 
    	
$
    	
6.6
    	
 
    	
100.0
    	
 
    

 

	
United States
    	
 
    	
Fair value
    	
 
    	
Level 1
    	
 
    	
Level 2
    	
 
    	
Percentage of
   Plan Assets 
   (%)
    	
 
    
	
Cash and   short-term equivalents
    	
 
    	
$
    	
0.8
    	
 
    	
$
    	
0.8
    	
 
    	
$
    	
—
    	
 
    	
0.3
    	
 
    
	
Foreign equities
    	
 
    	
212.0
    	
 
    	
212.0
    	
 
    	
—
    	
 
    	
66.3
    	
 
    
	
Fixed income
    	
 
    	
106.7
    	
 
    	
106.7
    	
 
    	
—
    	
 
    	
33.4
    	
 
    
	
 
    	
 
    	
$
    	
319.5
    	
 
    	
$
    	
319.5
    	
 
    	
$
    	
—
    	
 
    	
100.0
    	
 
    

 

	
Total
    	
 
    	
Fair value
    	
 
    	
Level 1
    	
 
    	
Level 2
    	
 
    	
Percentage of
   Plan Assets 
   (%)
    	
 
    
	
Cash and   short-term equivalents
    	
 
    	
$
    	
7.0
    	
 
    	
$
    	
7.0
    	
 
    	
$
    	
—
    	
 
    	
1.6
    	
 
    
	
Canadian   equities
    	
 
    	
40.8
    	
 
    	
40.8
    	
 
    	
—
    	
 
    	
9.2
    	
 
    
	
Foreign equities
    	
 
    	
234.7
    	
 
    	
234.7
    	
 
    	
—
    	
 
    	
53.0
    	
 
    
	
Fixed income
    	
 
    	
153.8
    	
 
    	
153.7
    	
 
    	
0.1
    	
 
    	
34.7
    	
 
    
	
Real estate
    	
 
    	
6.5
    	
 
    	
—
    	
 
    	
6.5
    	
 
    	
1.5
    	
 
    
	
 
    	
 
    	
$
    	
442.8
    	
 
    	
$
    	
436.2
    	
 
    	
$
    	
6.6
    	
 
    	
100.0
    	
 
    

 

	
 
    	
 
    	
 
    	
 
    	
Post-
    	
 
    	
 
    	
 
    	
Post-
    	
 
    
	
 
    	
 
    	
Defined
    	
 
    	
Retirement
    	
 
    	
Defined
    	
 
    	
Retirement
    	
 
    
	
Significant actuarial assumptions used in measuring   net benefit plan costs
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    
	
For the year ended December 31
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Discount rate   (%)
    	
 
    	
2.65 - 4.20
    	
 
    	
4.00 - 4.20
    	
 
    	
2.70 - 4.50
    	
 
    	
4.20 - 4.60
    	
 
    
	
Expected   long-term rate of return on plan assets (%) (a)
    	
 
    	
6.18 - 7.30
    	
 
    	
3.10 - 7.30
    	
 
    	
6.00 - 7.30
    	
 
    	
3.10 - 7.30
    	
 
    
	
Rate of   compensation increase (%)
    	
 
    	
2.75 - 4.00
    	
 
    	
3.25
    	
 
    	
2.75 - 4.00
    	
 
    	
3.25
    	
 
    
	
Average   remaining service life of active employees (years)
    	
 
    	
12.7
    	
 
    	
13.5
    	
 
    	
12.5
    	
 
    	
13.6
    	
 
    

 

(a) Only applicable for funded plans

 

	
 
    	
 
    	
 
    	
 
    	
Post-
    	
 
    	
 
    	
 
    	
Post-
    	
 
    
	
 
    	
 
    	
Defined
    	
 
    	
Retirement
    	
 
    	
Defined
    	
 
    	
Retirement
    	
 
    
	
Significant actuarial assumptions used in measuring benefit obligations
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    
	
As at December 31
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Discount rate   (%)
    	
 
    	
2.80 - 3.70
    	
 
    	
3.60 - 3.70
    	
 
    	
2.65 - 4.20
    	
 
    	
4.00 - 4.20
    	
 
    
	
Rate of   compensation increase (%)
    	
 
    	
2.75 - 4.00
    	
 
    	
3.25
    	
 
    	
2.75 - 4.00
    	
 
    	
3.25
    	
 
    

 

The expected rate of return on assets is based on the current level of expected returns on risk free investments, the historical level of risk premium associated with other asset classes in which the portfolio is invested, and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based on the target asset allocation to develop the expected rate of return on assets assumption for the portfolio.

 

The discount rate is based on high-quality long-term corporate bonds, with maturities matching the estimated timing and amount of expected benefit payments.

 

50

 

The estimates for health care benefits take into consideration increased health care benefits due to aging and cost increases in the future. The assumed health care cost trend rates used to measure the expected cost of benefits for the next year were between 6.5 and 6.7 percent. The health care cost trend rates were assumed to decline to between 4.5 and 5 percent by 2029.

 

The assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one percentage point change in the assumed health care trend rates would have the following effects for 2017:

 

	
 
    	
 
    	
Increase
    	
 
    	
Decrease
    	
 
    
	
Service and   interest costs
    	
 
    	
$
    	
1.5
    	
 
    	
$
    	
(1.1
    	
)
    
	
Accrued benefit obligation
    	
 
    	
$
    	
19.3
    	
 
    	
$
    	
(15.0
    	
)
    

 

The following table shows the expected cash flows for defined benefit pension and other-post retirement plans:

 

	
 
    	
 
    	
 
    	
 
    	
Post-
    	
 
    
	
 
    	
 
    	
Defined
    	
 
    	
Retirement
    	
 
    
	
 
    	
 
    	
Benefit
    	
 
    	
Benefits
    	
 
    
	
Expected   employer contributions:
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
2018
    	
 
    	
$
    	
15.2
    	
 
    	
$
    	
3.0
    	
 
    
	
Expected   benefit payments:
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
2018
    	
 
    	
$
    	
16.4
    	
 
    	
$
    	
3.2
    	
 
    
	
2019
    	
 
    	
17.6
    	
 
    	
3.3
    	
 
    
	
2020
    	
 
    	
19.1
    	
 
    	
3.5
    	
 
    
	
2021
    	
 
    	
20.2
    	
 
    	
3.7
    	
 
    
	
2022
    	
 
    	
21.6
    	
 
    	
3.9
    	
 
    
	
2023 - 2027
    	
 
    	
$
    	
124.4
    	
 
    	
$
    	
21.7
    	
 
    

 

26.  COMMITMENTS, CONTINGENCIES AND GUARANTEES

 

Commitments

 

AltaGas has long-term natural gas purchase and transportation arrangements, service agreements, storage contract and operating leases for office space, office equipment, rail cars, and automobile equipment, all of which are transacted at market prices and in the normal course of business.

 

51

 

Future payments of these commitments at December 31, 2017 are estimated as follows:

 

	
 
    	
 
    	
2018
    	
 
    	
2019
    	
 
    	
2020
    	
 
    	
2021
    	
 
    	
2022
    	
 
    	
2023 and
   beyond
    	
 
    	
Total
    	
 
    
	
Gas purchase(a)
    	
 
    	
$
    	
362.4
    	
 
    	
$
    	
349.9
    	
 
    	
$
    	
342.2
    	
 
    	
$
    	
317.5
    	
 
    	
$
    	
285.3
    	
 
    	
$
    	
224.6
    	
 
    	
$
    	
1,881.9
    	
 
    
	
Service   agreement(b)(c)(d)
    	
 
    	
11.1
    	
 
    	
21.2
    	
 
    	
21.2
    	
 
    	
14.9
    	
 
    	
12.8
    	
 
    	
183.0
    	
 
    	
264.2
    	
 
    
	
Storage services(e)
    	
 
    	
3.5
    	
 
    	
3.5
    	
 
    	
3.5
    	
 
    	
3.6
    	
 
    	
3.6
    	
 
    	
25.8
    	
 
    	
43.5
    	
 
    
	
Capital projects(f)
    	
 
    	
105.0
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
105.0
    	
 
    
	
Operating leases(g)
    	
 
    	
9.0
    	
 
    	
18.3
    	
 
    	
6.1
    	
 
    	
5.5
    	
 
    	
4.6
    	
 
    	
12.1
    	
 
    	
55.6
    	
 
    
	
 
    	
 
    	
$
    	
491.0
    	
 
    	
$
    	
392.9
    	
 
    	
$
    	
373.0
    	
 
    	
$
    	
341.5
    	
 
    	
$
    	
306.3
    	
 
    	
$
    	
445.5
    	
 
    	
$
    	
2,350.2
    	
 
    

 

(a)         AltaGas enters into contracts to purchase natural gas and natural gas transportation and storage services from various suppliers for its utilities. These contracts, which have expiration dates that range from 2018 to 2033, are used to ensure that there is an adequate supply of natural gas to meet the needs of customers and to minimize exposure to market price fluctuations.

(b)         In 2014, AltaGas’ Blythe facility entered into a Long-Term Service Agreement with Siemens to complete various upgrade and maintenance services on the Combustion Turbines (CT) at the Blythe facility over 116,000 equivalent operating hour per CT, or 20 years, whichever comes first. The LTSA has fixed fees that will be incurred in the five years following December 31, 2014 and variable fees on a per equivalent operating hour basis. As at December 31, 2017, the total commitment was $196.5 million payable over the next 17 years, of which $55.1 million is expected to be paid over the next five years.

(c)          In 2007, AltaGas entered into a service and maintenance agreement with Enercon GmbH for the wind turbines for Bear Mountain. AltaGas has an obligation to pay a minimum of $7.6 million over the next four years.

(d)         In 2017, AltaGas entered into a 12-year service agreement for tug services to support the marine operations of RIPET.

(e)          In 2009, AltaGas entered into a 20-year storage contract at the Dawn Hub in southwest Ontario. AltaGas is obligated to pay approximately $3.5 million per annum over the term of the contract for storage services.

(f)            Commitments for capital projects. Estimated amounts are subject to variability depending on the actual construction costs.

(g)         Operating leases include lease arrangements for office spaces, vehicles, rail cars, office and other equipment.

 

Guarantees

 

On October 2014, Heritage Gas Limited, a wholly-owned subsidiary of AltaGas, entered into a throughput service contract with Enbridge Inc. (formerly Spectra Energy Corp.) for the use of the expansion of its Algonquin Gas Transmission and Maritimes & Northeast Pipeline systems (the Atlantic Bridge Project). The contract will commence upon completion of the construction of the pipelines and it will expire 15 years thereafter. AltaGas has two guarantees outstanding that total US$91.7 million to stand by all payment obligations under the transportation agreement.

 

Contingencies

 

AltaGas and its subsidiaries are subject to various legal claims and actions arising in the normal course of business. While the final outcome of such legal claims and actions cannot be predicted with certainty, the Corporation does not believe that the resolution of such claims and actions will have a material impact on the Corporation’s consolidated financial position or results of operations.

 

52

 

27.  RELATED PARTY TRANSACTIONS

 

In the normal course of business, AltaGas transacts with its subsidiaries, affiliates and joint ventures. Amounts due to or from related parties on the Consolidated Balance Sheets were measured at the exchange amount and were as follows:

 

	
As at
    	
 
    	
December 31,
   2017
    	
 
    	
December 31,
   2016
    	
 
    
	
Due   from related parties
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Accounts   receivable (a)
    	
 
    	
$
    	
0.8
    	
 
    	
$
    	
0.7
    	
 
    
	
Long-term   investments and other assets (b)(c) 
    	
 
    	
75.0
    	
 
    	
63.3
    	
 
    
	
 
    	
 
    	
$
    	
75.8
    	
 
    	
$
    	
64.0
    	
 
    
	
Due to   related parties
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Accounts payable   (d)
    	
 
    	
3.2
    	
 
    	
3.2
    	
 
    
	
 
    	
 
    	
$
    	
3.2
    	
 
    	
$
    	
3.2
    	
 
    

 

(a)         Receivable from joint ventures.

(b)         AltaGas and one of its executives agreed to a loan in the principal amount of $0.8 million to be paid in full with accrued interest at the rate prescribed by the Income Tax Act (Canada) on the earlier of the date of employment termination and February 8, 2021. The provisions of the loan were amended in 2015 to include provision for forgiveness of the loan. In 2017, the loan was forgiven.

(c)          AltaGas has provided a $100.0 million interest bearing secured loan facility to Petrogas of which $50.0 million is committed. The facility is available for Petrogas to draw upon from time to time for general corporate purposes. The facility is subject to annual renewal and has a maturity date of June 27, 2021. As at December 31, 2017, Petrogas had drawn $75.0 million (December 31, 2016 - $62.5 million) under the facility.

(d)         Payables to joint ventures.

 

The following transactions with related parties have been recorded on the Consolidated Statements of Income for the year ended December 31, 2017 and 2016:

 

	
Year ended December 31
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Revenue (a)(b)
    	
 
    	
$
    	
15.0
    	
 
    	
$
    	
16.1
    	
 
    
	
Cost of sales (c)
    	
 
    	
$
    	
(6.5
    	
)
    	
$
    	
(6.5
    	
)
    
	
Operating and   administrative expenses (d)
    	
 
    	
$
    	
—
    	
 
    	
$
    	
0.7
    	
 
    
	
Other income (e)
    	
 
    	
$
    	
4.4
    	
 
    	
$
    	
1.3
    	
 
    

 

(a)         In the ordinary course of business, AltaGas sold natural gas and natural gas liquids to a joint venture and an affiliate.

(b)         In 2016, PNG recognized revenue of $6.8 million related to the recovery of development costs from Triton LNG Limited Partnership for the PNG Pipeline Looping Project.

(c)          In the ordinary course of business, AltaGas obtained natural gas storage services from a joint venture as well as incurred costs related to the sale of natural gas liquids to an affiliate.

(d)         Administrative costs recovered from joint ventures. In 2017, amount was offset by the expense associated with the forgiveness of the loan to an executive.

(e)          Interest income from an affiliate.

 

53

 

28.  SUPPLEMENTAL CASH FLOW INFORMATION

 

The following table details the changes in operating assets and liabilities from operating activities:

 

	
For the year ended December 31
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Source (use) of   cash:
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Accounts   receivable
    	
 
    	
$
    	
(55.5
    	
)
    	
$
    	
(6.1
    	
)
    
	
Inventory
    	
 
    	
4.7
    	
 
    	
(14.4
    	
)
    
	
Other current   assets
    	
 
    	
7.0
    	
 
    	
(20.8
    	
)
    
	
Regulatory   assets (current)
    	
 
    	
(0.2
    	
)
    	
3.3
    	
 
    
	
Accounts payable   and accrued liabilities
    	
 
    	
85.5
    	
 
    	
(4.6
    	
)
    
	
Customer   deposits
    	
 
    	
(2.8
    	
)
    	
(4.6
    	
)
    
	
Regulatory   liabilities (current)
    	
 
    	
(4.8
    	
)
    	
(4.1
    	
)
    
	
Other current   liabilities
    	
 
    	
13.0
    	
 
    	
4.3
    	
 
    
	
Other operating   assets and liabilities
    	
 
    	
(41.0
    	
)
    	
(30.5
    	
)
    
	
Changes in   operating assets and liabilities
    	
 
    	
$
    	
5.9
    	
 
    	
$
    	
(77.5
    	
)
    

 

The following cash payments have been included in the determination of earnings:

 

	
For the year ended December 31
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Interest paid   (net of capitalized interest)
    	
 
    	
$
    	
151.1
    	
 
    	
$
    	
141.5
    	
 
    
	
Income taxes   paid
    	
 
    	
$
    	
36.3
    	
 
    	
$
    	
35.9
    	
 
    

 

54

 

29.  SEGMENTED INFORMATION

 

AltaGas owns and operates a portfolio of assets and services used to move energy from the source to the end-user. The following describes the Corporation’s four reporting segments:

 

	
Gas
    	
·
    	
NGL processing and extraction plants;
    
	
 
    	
·
    	
transmission pipelines to transport natural gas and   NGL;
    
	
 
    	
·
    	
natural gas gathering lines and field processing   facilities;
    
	
 
    	
·
    	
purchase and sale of natural gas, including to   commercial and industrial users;
    
	
 
    	
·
    	
natural gas storage facilities;
    
	
 
    	
·
    	
liquefied petroleum gas (LPG) terminal currently   under construction;
    
	
 
    	
·
    	
natural gas and NGL marketing; and
    
	
 
    	
·
    	
equity investment in Petrogas, a North American   entity engaged in the marketing, storage and distribution of NGL, drilling   fluids, crude oil and condensate diluents.
    
	
 
    	
 
    	
 
    
	
Power
    	
·
    	
natural gas-fired, wind, biomass and hydro power   generation assets, whereby outputs are generally sold under long term power purchase   agreements, both operational and under development;
    
	
 
    	
·
    	
energy storage; and
    
	
 
    	
·
    	
sale of power to commercial and industrial users in   Alberta.
    
	
 
    	
 
    	
 
    
	
Utilities
    	
·
    	
rate-regulated natural gas distribution assets in   Michigan, Alaska, Alberta, British Columbia and Nova Scotia; and
    
	
 
    	
·
    	
rate-regulated natural gas storage in Michigan and   Alaska.
    
	
 
    	
 
    	
 
    
	
Corporate
    	
·
    	
the cost of providing corporate services, financing   and general corporate overhead, investments in certain public and private   entities, corporate assets, financing other segments and the effects of   changes in the fair value of risk management contracts.
    

 

Geographic Information

 

	
Year ended December 31
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Revenue(a)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Canada
    	
 
    	
$
    	
1,508.8
    	
 
    	
$
    	
1,192.3
    	
 
    
	
United States
    	
 
    	
1,109.9
    	
 
    	
1,008.8
    	
 
    
	
Total
    	
 
    	
$
    	
2,618.7
    	
 
    	
$
    	
2,201.1
    	
 
    

 

(a)         Operating revenue from external customers, excluding unrealized gains (losses) on risk management contracts.

 

	
As at December 31
    	
 
    	
2017
    	
 
    	
2016
    	
 
    
	
Property, plant   and equipment
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Canada
    	
 
    	
$
    	
4,320.5
    	
 
    	
$
    	
4,080.3
    	
 
    
	
United States
    	
 
    	
2,369.3
    	
 
    	
2,654.6
    	
 
    
	
Total
    	
 
    	
$
    	
6,689.8
    	
 
    	
$
    	
6,734.9
    	
 
    

 

55

 

The following tables show the composition by segment:

 

	
 
    	
 
    	
Year ended December 31, 2017
    	
 
    
	
 
    	
 
    	
Gas
    	
 
    	
Power
    	
 
    	
Utilities
    	
 
    	
Corporate
    	
 
    	
Intersegment
   Elimination(a)
    	
 
    	
Total
    	
 
    
	
Revenue
    	
 
    	
$
    	
1,008.0
    	
 
    	
$
    	
631.7
    	
 
    	
$
    	
1,127.6
    	
 
    	
$
    	
3.2
    	
 
    	
$
    	
(151.8
    	
)
    	
$
    	
2,618.7
    	
 
    
	
Unrealized   losses on risk management contracts
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(0.9
    	
)
    	
(61.6
    	
)
    	
—
    	
 
    	
(62.5
    	
)
    
	
Cost of sales
    	
 
    	
(647.0
    	
)
    	
(242.8
    	
)
    	
(610.1
    	
)
    	
—
    	
 
    	
142.8
    	
 
    	
(1,357.1
    	
)
    
	
Operating and   administrative
    	
 
    	
(165.0
    	
)
    	
(93.1
    	
)
    	
(226.1
    	
)
    	
(99.1
    	
)
    	
9.5
    	
 
    	
(573.8
    	
)
    
	
Accretion   expenses
    	
 
    	
(3.9
    	
)
    	
(6.9
    	
)
    	
(0.1
    	
)
    	
—
    	
 
    	
—
    	
 
    	
(10.9
    	
)
    
	
Depreciation and   amortization
    	
 
    	
(68.6
    	
)
    	
(118.0
    	
)
    	
(81.8
    	
)
    	
(14.0
    	
)
    	
—
    	
 
    	
(282.4
    	
)
    
	
Provisions on   assets (note 9)
    	
 
    	
(6.6
    	
)
    	
(133.0
    	
)
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(139.6
    	
)
    
	
Income from   equity investments
    	
 
    	
22.0
    	
 
    	
6.8
    	
 
    	
2.6
    	
 
    	
—
    	
 
    	
—
    	
 
    	
31.4
    	
 
    
	
Other income (loss)
    	
 
    	
(0.9
    	
)
    	
0.8
    	
 
    	
3.9
    	
 
    	
7.9
    	
 
    	
(0.5
    	
)
    	
11.2
    	
 
    
	
Foreign exchange   gains
    	
 
    	
0.2
    	
 
    	
—
    	
 
    	
—
    	
 
    	
1.5
    	
 
    	
—
    	
 
    	
1.7
    	
 
    
	
Interest expense
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(170.3
    	
)
    	
—
    	
 
    	
(170.3
    	
)
    
	
Income (loss)   before income taxes
    	
 
    	
$
    	
138.2
    	
 
    	
$
    	
45.5
    	
 
    	
$
    	
215.1
    	
 
    	
$
    	
(332.4
    	
)
    	
$
    	
—
    	
 
    	
$
    	
66.4
    	
 
    
	
Net additions   (reductions) to:
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Property, plant   and equipment(b)
    	
 
    	
$
    	
245.3
    	
 
    	
$
    	
16.5
    	
 
    	
$
    	
124.3
    	
 
    	
$
    	
1.5
    	
 
    	
$
    	
—
    	
 
    	
$
    	
387.6
    	
 
    
	
Intangible   assets
    	
 
    	
$
    	
2.8
    	
 
    	
$
    	
13.2
    	
 
    	
$
    	
2.1
    	
 
    	
$
    	
2.2
    	
 
    	
$
    	
—
    	
 
    	
$
    	
20.3
    	
 
    

 

(a)         Intersegment transactions are recorded at market value.

(b)         Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statement of Cash flow due to classification of business acquisition and foreign exchange changes on U.S. assets.

 

	
 
    	
 
    	
Year ended December 31, 2016
    	
 
    
	
 
    	
 
    	
Gas
    	
 
    	
Power
    	
 
    	
Utilities
    	
 
    	
Corporate
    	
 
    	
Intersegment
   Elimination(a)
    	
 
    	
Total
    	
 
    
	
Revenue
    	
 
    	
$
    	
804.1
    	
 
    	
$
    	
574.7
    	
 
    	
$
    	
1,065.8
    	
 
    	
$
    	
11.7
    	
 
    	
$
    	
(255.2
    	
)
    	
$
    	
2,201.1
    	
 
    
	
Unrealized gains   (losses) on risk management contracts
    	
 
    	
—
    	
 
    	
—
    	
 
    	
0.5
    	
 
    	
(11.9
    	
)
    	
—
    	
 
    	
(11.4
    	
)
    
	
Cost of sales
    	
 
    	
(496.1
    	
)
    	
(200.5
    	
)
    	
(557.1
    	
)
    	
—
    	
 
    	
236.8
    	
 
    	
(1,016.9
    	
)
    
	
Operating and   administrative
    	
 
    	
(154.3
    	
)
    	
(100.1
    	
)
    	
(229.7
    	
)
    	
(44.1
    	
)
    	
18.9
    	
 
    	
(509.3
    	
)
    
	
Accretion   expenses
    	
 
    	
(3.9
    	
)
    	
(7.0
    	
)
    	
(0.1
    	
)
    	
—
    	
 
    	
—
    	
 
    	
(11.0
    	
)
    
	
Depreciation and   amortization
    	
 
    	
(65.8
    	
)
    	
(108.7
    	
)
    	
(82.3
    	
)
    	
(14.7
    	
)
    	
—
    	
 
    	
(271.5
    	
)
    
	
Income (loss)   from equity investments
    	
 
    	
7.6
    	
 
    	
(6.8
    	
)
    	
2.6
    	
 
    	
—
    	
 
    	
—
    	
 
    	
3.4
    	
 
    
	
Other income   (loss)
    	
 
    	
4.8
    	
 
    	
—
    	
 
    	
1.7
    	
 
    	
2.6
    	
 
    	
(0.5
    	
)
    	
8.6
    	
 
    
	
Foreign exchange   gains
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
4.0
    	
 
    	
—
    	
 
    	
4.0
    	
 
    
	
Interest expense
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(150.8
    	
)
    	
—
    	
 
    	
(150.8
    	
)
    
	
Income (loss)   before income taxes
    	
 
    	
$
    	
96.4
    	
 
    	
$
    	
151.6
    	
 
    	
$
    	
201.4
    	
 
    	
$
    	
(203.2
    	
)
    	
$
    	
—
    	
 
    	
$
    	
246.2
    	
 
    
	
Net additions   (reductions) to:
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Property, plant   and equipment(b)
    	
 
    	
$
    	
193.0
    	
 
    	
$
    	
95.0
    	
 
    	
$
    	
112.7
    	
 
    	
$
    	
4.3
    	
 
    	
$
    	
—
    	
 
    	
$
    	
405.0
    	
 
    
	
Intangible   assets
    	
 
    	
$
    	
2.6
    	
 
    	
$
    	
15.1
    	
 
    	
$
    	
2.4
    	
 
    	
$
    	
5.9
    	
 
    	
$
    	
—
    	
 
    	
$
    	
26.0
    	
 
    

 

(a)         Intersegment transactions are recorded at market value.

(b)         Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statement of Cash flow due to classification of business acquisition and foreign exchange changes on U.S. assets.

 

56

 

The following table shows goodwill and total assets by segment:

 

	
 
    	
 
    	
Gas
    	
 
    	
Power
    	
 
    	
Utilities
    	
 
    	
Corporate
    	
 
    	
Total
    	
 
    
	
As at December 31, 2017
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Goodwill
    	
 
    	
$
    	
152.6
    	
 
    	
$
    	
—
    	
 
    	
$
    	
664.7
    	
 
    	
$
    	
—
    	
 
    	
$
    	
817.3
    	
 
    
	
Segmented assets
    	
 
    	
$
    	
3,096.8
    	
 
    	
$
    	
3,192.5
    	
 
    	
$
    	
3,460.2
    	
 
    	
$
    	
282.7
    	
 
    	
$
    	
10,032.2
    	
 
    
	
As at   December 31, 2016
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Goodwill
    	
 
    	
$
    	
152.9
    	
 
    	
$
    	
—
    	
 
    	
$
    	
703.1
    	
 
    	
$
    	
—
    	
 
    	
$
    	
856.0
    	
 
    
	
Segmented assets
    	
 
    	
$
    	
2,826.3
    	
 
    	
$
    	
3,501.3
    	
 
    	
$
    	
3,586.4
    	
 
    	
$
    	
286.6
    	
 
    	
$
    	
10,200.6
    	
 
    

 

30.  SUBSEQUENT EVENTS

 

Subsequent events have been reviewed through February 28, 2018, the date these Consolidated Financial Statements were issued. There were no subsequent events requiring disclosure or adjustment to the Consolidated Financial Statements.

 

57

 

Supplementary Quarterly Operating Information

 

	
 
    	
 
    	
Q4-17
    	
 
    	
Q3-17
    	
 
    	
Q2-17
    	
 
    	
Q1-17
    	
 
    	
Q4-16
    	
 
    
	
OPERATING   HIGHLIGHTS
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
GAS
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Total inlet gas   processed (Mmcf/d)(1)
    	
 
    	
1,424
    	
 
    	
1,322
    	
 
    	
1,300
    	
 
    	
1,404
    	
 
    	
1,337
    	
 
    
	
Extraction   volumes (Bbls/d)(1)(2)
    	
 
    	
68,306
    	
 
    	
64,026
    	
 
    	
58,885
    	
 
    	
71,958
    	
 
    	
69,687
    	
 
    
	
Frac spread -   realized ($/Bbl)(1)(3)
    	
 
    	
18.02
    	
 
    	
14.96
    	
 
    	
9.06
    	
 
    	
10.56
    	
 
    	
6.11
    	
 
    
	
Frac spread -   average spot price ($/Bbl)(1)(4)
    	
 
    	
30.66
    	
 
    	
21.28
    	
 
    	
10.98
    	
 
    	
17.26
    	
 
    	
8.40
    	
 
    
	
POWER
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Renewable power   sold (GWh)
    	
 
    	
301
    	
 
    	
681
    	
 
    	
499
    	
 
    	
148
    	
 
    	
196
    	
 
    
	
Conventional   power sold (GWh)
    	
 
    	
1,059
    	
 
    	
992
    	
 
    	
409
    	
 
    	
385
    	
 
    	
374
    	
 
    
	
Renewable   capacity factor (%)
    	
 
    	
27.5
    	
 
    	
70.3
    	
 
    	
50.7
    	
 
    	
9.5
    	
 
    	
18.8
    	
 
    
	
Contracted   conventional availability factor (%)(5)
    	
 
    	
96.3
    	
 
    	
99.6
    	
 
    	
99.9
    	
 
    	
96.0
    	
 
    	
99.8
    	
 
    
	
UTILITIES
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Canadian   utilities
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Natural gas   deliveries - end-use (PJ)(6)
    	
 
    	
11.2
    	
 
    	
3.7
    	
 
    	
4.8
    	
 
    	
13.5
    	
 
    	
10.8
    	
 
    
	
Natural gas   deliveries - transportation (PJ)(6)
    	
 
    	
1.6
    	
 
    	
1.3
    	
 
    	
1.5
    	
 
    	
1.9
    	
 
    	
1.5
    	
 
    
	
U.S. utilities
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Natural gas   deliveries end use (Bcf) (6)
    	
 
    	
24.3
    	
 
    	
5.9
    	
 
    	
10.3
    	
 
    	
30.2
    	
 
    	
22.8
    	
 
    
	
Natural gas   deliveries transportation (Bcf)(6)
    	
 
    	
14.2
    	
 
    	
10.9
    	
 
    	
11.5
    	
 
    	
15.4
    	
 
    	
14.2
    	
 
    
	
Service sites(7)
    	
 
    	
581,518
    	
 
    	
575,602
    	
 
    	
575,084
    	
 
    	
576,829
    	
 
    	
574,875
    	
 
    
	
Degree day   variance from normal - AUI (%)(8)
    	
 
    	
4.0
    	
 
    	
(16.9
    	
)
    	
(7.4
    	
)
    	
(2.2
    	
)
    	
(0.6
    	
)
    
	
Degree day   variance from normal - Heritage Gas (%)(8)
    	
 
    	
(4.6
    	
)
    	
(20.4
    	
)
    	
(4.3
    	
)
    	
(1.9
    	
)
    	
(1.0
    	
)
    
	
Degree day   variance from normal - SEMCO Gas (%)(9)
    	
 
    	
4.8
    	
 
    	
5.7
    	
 
    	
(8.4
    	
)
    	
(11.8
    	
)
    	
(6.1
    	
)
    
	
Degree day   variance from normal - ENSTAR (%)(9) 
    	
 
    	
(8.3
    	
)
    	
(16.6
    	
)
    	
(5.4
    	
)
    	
9.6
    	
 
    	
(1.4
    	
)
    

 

(1)         Average for the period.

(2)         Includes Harmattan NGL processed on behalf of customers.

(3)         Realized frac spread or NGL margin, expressed in dollars per barrel of NGL, is derived from sales recorded by the segment during the period for frac exposed volumes plus the settlement value of frac hedges settled in the period less extraction premiums, divided by the total frac exposed volumes produced during the period.

(4)         Average spot frac spread or NGL margin, expressed in dollars per barrel of NGL, is indicative of the average sales price that AltaGas receives for propane, butane and condensate less extraction premiums, before accounting for hedges, divided by the respective frac exposed volumes for the period.

(5)         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.

(6)         Petajoule (PJ) is one million gigajoules (GJ). Bcf is one billion cubic feet.

(7)         Service sites reflect all of the service sites of AUI, PNG, Heritage Gas, and U.S. Utilities, including transportation and non-regulated business lines.

(8)         A degree day for AUI and Heritage Gas is the cumulative extent to which the daily mean temperature falls below 15 degrees Celsius at AUI and 18 degrees Celsius at Heritage Gas. Normal degree days are based on a 20-year rolling average. Positive variances from normal lead to increased delivery volumes from normal expectations. Degree day variances do not materially affect the results of PNG as the British Columbia Utilities Commission (BCUC) has approved a rate stabilization mechanism for its residential and small commercial customers.

(9)         A degree day for U.S. Utilities is a measure of coldness, determined daily as the number of degrees the average temperature during the day in question is below 65 degrees Fahrenheit. Degree days for a particular period are determined by adding the degree days incurred during each day of the period. Normal degree days for a particular period are the average of degree days during the prior 15 years for SEMCO Energy Gas Company and during the prior 10 years for ENSTAR.

 

58

 

Other Information

 

DEFINITIONS

 

	
Bbls/d
    	
barrels per day
    
	
Bcf
    	
billion cubic feet
    
	
GJ
    	
gigajoule
    
	
GWh
    	
gigawatt-hour
    
	
Mcf
    	
thousand cubic feet
    
	
Mmcf/d
    	
million cubic feet per day
    
	
MW
    	
megawatt
    
	
MWh
    	
megawatt-hour
    
	
MMBTU
    	
million British thermal unit
    
	
PJ
    	
petajoule
    
	
US$
    	
United States dollar
    

 

ABOUT ALTAGAS

 

AltaGas is an energy infrastructure business with a focus on natural gas, power and regulated utilities. The Corporation creates value by acquiring, growing and optimizing its energy infrastructure, including a focus on clean energy sources. For more information visit: www.altagas.ca.

 

For further information contact:

 

Investment Community

1-877-691-7199

investor.relations@altagas.ca

 

59

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