Exhibit 4.5

 

MANAGEMENT’S DISCUSSION AND ANALYSIS

 

This Management’s Discussion and Analysis (MD&A) dated April 25, 2018 is provided to enable readers to assess the results of operations, liquidity and capital resources of AltaGas Ltd. (AltaGas or the Corporation) as at and for the three months ended March 31, 2018. This MD&A should be read in conjunction with the accompanying unaudited condensed interim Consolidated Financial Statements and notes thereto of AltaGas as at and for the three months ended March 31, 2018 and the audited Consolidated Financial Statements and MD&A as at and for the year ended December 31, 2017.

 

The Consolidated Financial Statements and comparative information have been prepared in accordance with United States (U.S.) generally accepted accounting principles (U.S. GAAP) and in Canadian dollars, unless otherwise indicated. Throughout this MD&A, references to GAAP refer to U.S. GAAP.

 

Abbreviations, acronyms and capitalized terms used in this MD&A without express definition shall have the same meanings given to those terms in the MD&A as at and for the year ended December 31, 2017 or the Annual Information Form.

 

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

 

Specifically, such forward-looking statements included in this document include, but are not limited to, statements with respect to the following: 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 cash flow stability from Gordondale; expected increase in operating capacity at Gordondale and potential expansion; the expected closing of the WGL Acquisition and the expected timing of the WGL Acquisition; the expected growth in normalized EBITDA and normalized funds from operations of the combined entity; the expected benefits of the WGL Acquisition, including growth across all three of the business segments; the expected in-service dates for WGL’s midstream investments; the expected growth of the Corporation on a standalone basis; the estimated exposure to frac spreads; the expected asset and customer base, post-close; the expected timing of the PSC of DC decision; the expected sources of funds for the WGL Acquisition and potential asset monetizations and value, including the potential sale of minority interest(s) in the NW BC Hydro Facilities, the potential offerings of securities; expected capital expenditures, including by segment and project, and the expected capital program post-close; expected cost, timing, size, and capacity and tolling arrangements for RIPET; expectation that RIPET will be the first propane export facility on the West Coast; potential growth of AltaGas’ energy export business; expected cost, scale and timing of the MCP; and expected maintenance of the Corporation’s investment grade credit rating. 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 negotiations; 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

 

AltaGas Ltd. — Q1 2018

 

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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 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 the Corporation’s AIF for the year ended December 31, 2017 and set out in AltaGas’ other continuous disclosure documents.

 

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

 

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

 

Additional information relating to AltaGas, including its quarterly and annual MD&A and Consolidated Financial Statements, Annual Information Form, and press releases are available through AltaGas’ website at www.altagas.ca or through SEDAR at www.sedar.com.

 

ALTAGAS ORGANIZATION

 

The businesses of AltaGas are operated by AltaGas and a number of its subsidiaries including, without limitation, AltaGas Services (U.S.) Inc.; 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).

 

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. 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 Utility business segments. AltaGas’ business strategy is underpinned by the growing demand for clean energy with natural gas as a key fuel source. AltaGas has three business segments:

 

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·                  Gas, which transacts more than 2 Bcf/d of natural gas and includes natural gas gathering and processing, natural gas liquids (NGL) extraction and fractionation, transmission, storage, natural gas and NGL marketing, the Corporation’s 50 percent interest in AltaGas Idemitsu Joint Venture Limited Partnership (AIJVLP), and an indirectly held one-third ownership investment in Petrogas Energy Corp. (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.

 

FIRST QUARTER FINANCIAL HIGHLIGHTS

 

(Normalized EBITDA, normalized funds from operations, normalized net income, net debt, and net debt to total capitalization ratio are non-GAAP financial measures. Please see Non-GAAP Financial Measures section of this MD&A.)

 

·                  Net income applicable to common shares was $49 million ($0.28 per share) compared to $32 million ($0.19 per share) in the first quarter of 2017;

·                  Normalized net income was $70 million ($0.40 per share), an increase of 8 percent compared to $65 million ($0.39 per share) in the first quarter of 2017;

·                  Normalized EBITDA was $223 million compared to $228 million in the first quarter of 2017;

·                  Normalized funds from operations were $169 million ($0.96 per share) compared to $170 million ($1.01 per share) in the first quarter of 2017;

·                  Net debt was $3.6 billion as at both March 31, 2018 and December 31, 2017; and

·                  Net debt-to-total capitalization ratio was 43 percent as at March 31, 2018, compared to 44 percent as at December 31, 2017.

 

HIGHLIGHTS SUBSEQUENT TO QUARTER END

 

·                  On April 3, 2018, AltaGas entered into a long-term natural gas processing arrangement (the Processing Arrangement) with Birchcliff Energy Ltd. (Birchcliff) at AltaGas’ deep-cut sour gas processing facility located in Gordondale, Alberta (the Gordondale Facility). Under the Processing Arrangement, Birchcliff is provided with up to 120 MMcf/d of natural gas processing on a firm-service basis, and Birchcliff’s take-or-pay obligation is 100 MMcf/d. The Processing Arrangement provides stable long-term cash flow by filling the existing operational capacity of 120 Mmcf/d at the Gordondale Facility and significantly enhances the potential to flow third-party volumes through the facility and to grow those volumes to bring the operating capacity up to 150 Mmcf/d. Growing propane volumes will be dedicated to the Ridley Island Propane Export Terminal (RIPET) as part of the commercial arrangements. The new Processing Arrangement is effective as of January 1, 2018 and replaces the parties’ existing Gordondale processing arrangement;

·                  On April 4, 2018, AltaGas received regulatory approval from the Maryland Public Service Commission (PSC of MD) for the pending acquisition by AltaGas of WGL Holdings, Inc. (WGL); and

·                  Effective upon the expiry of the Power Purchase Arrangement (PPA) at the Ripon gas-fired electricity generation facility (Ripon), in April 2018, AltaGas signed a Resource Adequacy (RA) contract for June through September 2018, and has recently been awarded a contract for October through December 2018.

 

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CONSOLIDATED FINANCIAL REVIEW

 

	
 
    	
 
    	
Three Months Ended
   March 31
    	
 
    
	
($ millions)
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Revenue
    	
 
    	
878
    	
 
    	
771
    	
 
    
	
Normalized EBITDA(1) 
    	
 
    	
223
    	
 
    	
228
    	
 
    
	
Net income   applicable to common shares
    	
 
    	
49
    	
 
    	
32
    	
 
    
	
Normalized net   income(1)
    	
 
    	
70
    	
 
    	
65
    	
 
    
	
Total assets
    	
 
    	
10,106
    	
 
    	
10,044
    	
 
    
	
Total long-term   liabilities
    	
 
    	
4,631
    	
 
    	
4,358
    	
 
    
	
Net additions to   property, plant and equipment
    	
 
    	
66
    	
 
    	
2
    	
 
    
	
Dividends   declared(2)
    	
 
    	
97
    	
 
    	
88
    	
 
    
	
Normalized funds   from operations(1)
    	
 
    	
169
    	
 
    	
170
    	
 
    


 

	
 
    	
 
    	
Three Months Ended
   March 31
    	
 
    
	
($ per share, except shares outstanding)
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Net income per   common share - basic
    	
 
    	
0.28
    	
 
    	
0.19
    	
 
    
	
Net income per   common share - diluted
    	
 
    	
0.28
    	
 
    	
0.19
    	
 
    
	
Normalized net   income - basic(1)
    	
 
    	
0.40
    	
 
    	
0.39
    	
 
    
	
Dividends   declared(2)
    	
 
    	
0.55
    	
 
    	
0.53
    	
 
    
	
Normalized funds   from operations(1)
    	
 
    	
0.96
    	
 
    	
1.01
    	
 
    
	
Shares   outstanding - basic (millions)
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
During the   period(3)
    	
 
    	
177
    	
 
    	
168
    	
 
    
	
End of period
    	
 
    	
178
    	
 
    	
169
    	
 
    


 




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

(2)         Dividends declared per common share per month: $0.175 beginning on August 25, 2016, and $0.1825 beginning on November 27, 2017.

(3)         Weighted average.

 

Three Months Ended March 31

 

Normalized EBITDA for the first quarter of 2018 was $223 million, compared to $228 million for the same quarter in 2017. The decrease was mainly due to the impact from the weaker U.S. dollar on reported results from U.S. assets, lower natural gas storage margins, expenses related to a planned maintenance outage at Blythe, decreased revenue from SEMCO due to U.S. tax reform, and the impact from the sale of the Ethylene Delivery Systems (EDS) and the Joffre Feedstock Pipeline (JFP) transmission assets in the first quarter of 2017. These decreases were partially offset by higher realized frac spread and frac exposed volumes, contributions from the Townsend 2A facility which commenced commercial operations in the fourth quarter of 2017, and colder weather experienced at certain of the Utilities. For the three months ended March 31, 2018, the average Canadian/U.S. dollar exchange rate decreased to 1.26 from an average of 1.32 in the same quarter of 2017, resulting in a decrease in normalized EBITDA of approximately $6 million.

 

Normalized funds from operations for the first quarter of 2018 were $169 million ($0.96 per share), compared to $170 million ($1.01 per share) for the same quarter in 2017, reflecting the same drivers as normalized EBITDA, partially offset by lower current income tax expense. In the first quarter of 2018, AltaGas received $3 million of dividends from the Petrogas Preferred Shares (2017 - $3 million) and $1 million of common share dividends from Petrogas (2017 - $1 million).

 

Operating and administrative expenses for the first quarter of 2018 were $141 million, compared to $160 million for the same quarter in 2017. The decrease was mainly due to lower transaction costs on acquisitions (primarily related to the pending WGL Acquisition) of $11 million in the first quarter of 2018 compared to $36 million in the same quarter in 2017, partially offset by expenses related to the planned outage at Blythe. Depreciation and amortization expense for the first quarter of 2018 was $73 million, compared to $72 million for the same quarter in 2017. The increase was mainly due to new assets placed into service.

 

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Interest expense for the first quarter of 2018 was $43 million, compared to $46 million for the same quarter in 2017. The decrease was predominantly due to higher capitalized interest and the timing of debt issuances and repayments.

 

AltaGas recorded income tax expense of $18 million for the first quarter of 2018 compared to $21 million in the same quarter of 2017. The decrease was mainly due to the recently enacted change in the U.S. Federal tax rate from 35 percent to 21 percent.

 

Net income applicable to common shares for the first quarter of 2018 was $49 million ($0.28 per share), compared to $32 million ($0.19 per share) for the same quarter in 2017. The increase was mainly due to lower transaction costs incurred on the pending WGL Acquisition, and lower interest and income tax expense, partially offset by the same previously referenced factors resulting in the decrease in normalized EBITDA, higher losses on investments, higher preferred share dividends, and higher depreciation and amortization expense.

 

Normalized net income was $70 million ($0.40 per share) for the first quarter of 2018, compared to $65 million ($0.39 per share) reported for the same quarter in 2017. The increase was mainly due to lower interest and income tax expense, partially offset by the same previously referenced factors resulting in the decrease in normalized EBITDA, higher preferred share dividends, and higher depreciation and amortization expense. Normalizing items in the first quarter of 2018 included after-tax amounts related to losses on investments, transaction costs on acquisitions, financing costs associated with the bridge facility for the pending WGL Acquisition of $4 million, unrealized gains on risk management contracts, and gain on sale of certain non-core gas assets. In the first quarter of 2017, normalizing items included after-tax amounts related to transaction costs on acquisitions, unrealized gains on risk management contracts, loss on sale of assets, and amortization of financing costs associated with the bridge facility of $4 million.

 

2018 OUTLOOK

 

AltaGas expects the WGL Acquisition to close in mid-2018. As a combined entity, AltaGas expects normalized EBITDA to increase by approximately 25 to 30 percent and normalized funds from operations to increase by approximately 15 to 20 percent.

 

The WGL Acquisition is expected to drive growth in all three business segments. The combined Utilities segment is expected to have the largest contribution to EBITDA, followed by the Gas segment. Specifically for Utilities, the combined segment is expected to have an overall rate base of approximately $5 billion and is expected to grow through planned capital investments in 2018. The WGL Acquisition will also increase the number of utility customers by approximately 1.2 million. The Gas segment is expected to benefit from the addition of WGL’s pipeline investments in the prolific Marcellus/Utica gas resource regions as well as a gas supply agreement associated with the Cove Point LNG Terminal which recently began exporting LNG. WGL’s investment in the Stonewall Gas Gathering System is currently in-service and WGL expects the Central Penn and Mountain Valley pipelines to be operational by the end of 2018. The Gas segment will also benefit from a full year of contributions from AltaGas’ Townsend 2A and the first train of the North Pine Facility. Finally, the Power segment is expected to benefit from the addition of WGL’s distributed generation assets to its portfolio. For further information on the WGL Acquisition see Developments Relating to the Pending WGL Acquisition section of this MD&A.

 

The overall forecasted normalized EBITDA and funds from operations for the combined business include assumptions around the timing of closing of the WGL Acquisition, the U.S./Canadian dollar exchange rate, the impact of certain contemplated asset monetizations and other financing initiatives as part of the WGL financing plan, and the impact of U.S. tax reform. Any variance from AltaGas’ current assumptions could impact the forecasted increase to normalized EBITDA and funds from operations.

 

On a standalone basis, excluding the WGL Acquisition and potential asset monetizations, AltaGas expects a moderate increase to both normalized EBITDA and funds from operations in 2018 compared to 2017 related to its base business, mainly as a result of growth in the Gas segment. The moderate increase to normalized EBITDA and funds from operations for AltaGas’ standalone base business is primarily due to full year contributions from Townsend 2A and the first train of the North Pine Facility, higher realized frac spread mainly due to higher hedged prices, higher expected earnings from the Northwest Hydro Facilities due to contractual price increases and continued efficiency improvements, and colder weather and rate base and customer growth at

 

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certain of the Utilities. These increases may be partially offset by the impact of a weaker U.S. dollar on reported results of the U.S. assets, the impact of planned turnarounds at the Harmattan and JEEP facilities, and the expiry of the PPA at the Ripon facility in the second quarter of 2018. The U.S. tax reform is expected to be immaterially negative to normalized EBITDA and funds from operations for AltaGas’ U.S. businesses while, on a net income basis, the impact of the U.S. tax reform is expected to be immaterially positive. This 2018 outlook does not include any potential upside associated with new developments in either the Gas or Power segments.

 

AltaGas estimates an average of approximately 10,500 Bbls/d will be exposed to frac spreads prior to hedging activities. For 2018, AltaGas has frac hedges in place for approximately 7,500 Bbls/d at an average price of approximately $33/Bbl excluding basis differentials.

 

DEVELOPMENTS RELATING TO THE PENDING WGL ACQUISITION

 

On January 25, 2017, the Corporation entered into the Merger Agreement to indirectly acquire WGL Holdings, Inc. (the WGL Acquisition). 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 which was developed by a third party and recently began exporting LNG. 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 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).

 

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. On April 4, 2018, the PSC of MD approved the WGL Acquisition. 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.

 

Closing of the WGL Acquisition continues to be on track for 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 and could remain in place for up to 12 to 18 months

 

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thereafter. With all financing in place to close the WGL Acquisition, AltaGas continues to evaluate and advance an asset monetization strategy in a prudent and timely fashion in step with the regulatory process and consistent with AltaGas’ long term strategic vision. Management expects the repayment of the bridge facility to result from the monetization of over $2 billion from its asset sales process, including the potential sale of appropriate minority interest(s) in the Northwest B.C. Hydro Facilities, and from offerings of senior debt and hybrid securities, 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 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.

 

GROWTH CAPITAL

 

Based on projects currently under review, development or construction, AltaGas expects net capital expenditures in the range of $500 to $600 million (excluding WGL) for 2018. AltaGas’ Gas segment will account for approximately 50 to 55 percent of the total capital expenditures, while AltaGas’ Utilities segment will account for approximately 30 to 35 percent and the Power segment will account for the remainder. Gas and Power maintenance capital is expected to be approximately $25 to $35 million of the total capital expenditures in 2018. The majority of AltaGas’ capital expenditures is focused on the continued construction at RIPET, maintaining and growing rate base at its existing utilities, pre-construction design, engineering, and right-of-way procurement for the Marquette Connector Pipeline (MCP), and growth capital associated with the tie-in of incremental third party gas volumes. The Corporation continues to focus on enhancing productivity and streamlining businesses, including the disposition of smaller non-core assets.

 

AltaGas’ 2018 committed capital program is expected to be funded through internally-generated cash flow and the Premium DividendTM, Dividend Reinvestment and Optional Cash Purchase Plan (DRIP).

 

Following the close of the WGL Acquisition (expected close date in mid-2018), the consolidated 2018 capital program on a combined basis, including capital for WGL, is expected to be in the range of approximately $1.0 to $1.3 billion. Close to half of this total will be allocated to the Gas segment, with the majority of the remaining expected capital for the Utilities segment,

 




TM Denotes trademark of Canaccord Genuity Corp.

 

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followed by the Power segment. AltaGas expects that the largest portion of WGL’s 2018 capital program subsequent to close will be allocated to investments in the Central Penn and Mountain Valley gas pipeline developments in the Marcellus region. Capital allocated to WGL’s utilities business will represent most of the remaining 2018 capital subsequent to close, with spending consistent with recent levels.

 

Ridley Island Propane Export Terminal

 

RIPET is located near Prince Rupert, British Columbia, and is expected to be the first propane export facility off the west coast of Canada. The site has a locational advantage given very short shipping distances to markets in Asia, notably a 10-day shipping time compared to 25 days from the U.S. Gulf Coast. The construction cost of RIPET is estimated to be approximately $450 to $500 million and RIPET is expected to ship 1.2 million tonnes of propane per annum (which is equivalent to approximately 40,000 Bbls/d of export capacity).

 

Construction of RIPET commenced during the second quarter of 2017 and is proceeding pursuant to an agreement with Ridley Island LPG Export Limited Partnership (RILE LP). The LPG storage tank, rail infrastructure, and balance of plant construction remain on track to meet the expected commercial operation date of the first quarter of 2019. With the LPG storage tank inner steel roof installed and final roof concrete pours scheduled, the team is simultaneously progressing construction of the rail and marine infrastructure and receiving and setting of equipment modules for the balance of plant. The site construction management team and project support teams have successfully hit all critical milestones to date on the RIPET master schedule.

 

In 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 RILE LP to develop, own, and operate RIPET. AltaGas’ subsidiaries hold a 70 percent interest while Vopak holds a 30 percent interest in RILE LP. The construction cost of RIPET will be funded by AltaGas LPG and Vopak in proportion to their respective interests in RILE LP. RILE LP will be consolidated by AltaGas.

 

Based on production from its existing facilities and forecasts from new plants under construction and in active development, AltaGas anticipates having physical volumes equal to approximately 50 percent of the expected capacity of 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 expects to underpin approximately 40 percent of RIPET’s annual expected capacity under tolling arrangements with producers and other suppliers.

 

AltaGas LPG and Astomos have entered into a multi-year agreement for the purchase of at least 50 percent of the 1.2 million tonnes per annum of propane expected to be available to be shipped from RIPET each year. Commercial discussions with Astomos and several third party off-takers for further capacity commitments are proceeding.

 

Alton Natural Gas Storage Project

 

Solution mining for cavern development of the Alton Natural Gas Storage Project, located near Truro, Nova Scotia is considered feasible to begin in 2018. The Nova Scotia Minister of Environment is expected to make a decision on the Industrial Approval (IA) appeal by Sipekne’katik First Nation (SFN) in the first half of 2018. In the meantime, the IA remains in effect for the project. AltaGas continues to work constructively with governments, regulators, and SFN. The Alton Natural Gas Storage Project is expected to provide up to 10 Bcf of natural gas storage capacity. The first phase of storage service is expected to commence in 2021.

 

Marquette Connector Pipeline

 

On August 23, 2017, the Michigan Public Service Commission (MPSC) approved SEMCO Gas’ application to construct, own, and operate the MCP. The MCP is a proposed new pipeline that will connect the Great Lakes Gas Transmission Pipeline to the Northern Natural Gas Pipeline in Marquette, Michigan, which will provide system redundancy and increase deliverability, reliability and diversity of supply to SEMCO Gas’ approximately 35,000 customers in Michigan’s Western Upper Peninsula. The MCP is estimated to cost between US$135 to $140 million. Engineering work and property acquisitions have begun and will continue throughout 2018. The application for all environmental permits has been submitted and approval is expected to be

 

8











 

received by the end of the third quarter of 2018. Construction is expected to be completed in 2019, with an anticipated in-service date by the end of the fourth quarter of 2019.

 

NON-GAAP FINANCIAL MEASURES

 

This MD&A contains references to certain financial measures used by AltaGas that do not have a standardized meaning prescribed by GAAP and may not be comparable to similar measures presented by other entities. Readers are cautioned that these non-GAAP measures should not be construed as alternatives to other measures of financial performance calculated in accordance with GAAP. The non-GAAP measures and their reconciliation to GAAP financial measures are shown below. These non-GAAP measures provide additional information that management believes is meaningful in describing AltaGas’ operational performance, liquidity and capacity to fund dividends, capital expenditures, and other investing activities. The specific rationale for, and incremental information associated with, each non-GAAP measure is discussed below.

 

References to normalized EBITDA, normalized net income, normalized funds from operations, net debt, and net debt to total capitalization throughout this MD&A have the meanings as set out in this section.

 

Normalized EBITDA

 

	
 
    	
 
    	
Three Months Ended
   March 31
    	
 
    
	
($ millions)
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Normalized   EBITDA
    	
 
    	
$
    	
223
    	
 
    	
$
    	
228
    	
 
    
	
Add (deduct):
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Transaction   costs related to acquisitions
    	
 
    	
(11
    	
)
    	
(36
    	
)
    
	
Unrealized gains   on risk management contracts
    	
 
    	
1
    	
 
    	
1
    	
 
    
	
Losses on   investments
    	
 
    	
(9
    	
)
    	
—
    	
 
    
	
Gains (losses)   on sale of assets
    	
 
    	
1
    	
 
    	
(3
    	
)
    
	
Accretion   expenses
    	
 
    	
(3
    	
)
    	
(3
    	
)
    
	
EBITDA
    	
 
    	
$
    	
202
    	
 
    	
$
    	
187
    	
 
    
	
Add (deduct):
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Depreciation and   amortization
    	
 
    	
(73
    	
)
    	
(72
    	
)
    
	
Interest expense
    	
 
    	
(43
    	
)
    	
(46
    	
)
    
	
Income tax   expense
    	
 
    	
(18
    	
)
    	
(21
    	
)
    
	
Net income after   taxes (GAAP financial measure)
    	
 
    	
$
    	
68
    	
 
    	
$
    	
48
    	
 
    


 

EBITDA is a measure of AltaGas’ operating profitability prior to how business activities are financed, assets are amortized, or earnings are taxed. EBITDA is calculated from the Consolidated Statement of Income using net income adjusted for pre-tax depreciation and amortization, interest expense, and income tax expense.

 

Normalized EBITDA includes additional adjustments for unrealized gains (losses) on risk management contracts, gains (losses) on investments, transaction costs related to acquisitions, gains (losses) on the sale of assets, and accretion expenses related to asset retirement obligations and the Northwest Transmission Line liability. AltaGas presents normalized EBITDA as a supplemental measure. Normalized EBITDA is frequently used by analysts and investors in the evaluation of entities within the industry as it excludes items that can vary substantially between entities depending on the accounting policies chosen, the book value of assets and the capital structure.

 

9









 

Normalized Net Income

 

	
 
    	
 
    	
Three Months Ended
   March 31
    	
 
    
	
($ millions)
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Normalized net   income
    	
 
    	
$
    	
70
    	
 
    	
$
    	
65
    	
 
    
	
Add (deduct)   after-tax:
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Transaction   costs related to acquisitions
    	
 
    	
(9
    	
)
    	
(27
    	
)
    
	
Unrealized gains   on risk management contracts
    	
 
    	
—
    	
 
    	
1
    	
 
    
	
Losses on   investments
    	
 
    	
(9
    	
)
    	
—
    	
 
    
	
Gains (losses)   on sale of assets
    	
 
    	
1
    	
 
    	
(3
    	
)
    
	
Financing costs   associated with the bridge facility
    	
 
    	
(4
    	
)
    	
(4
    	
)
    
	
Net income   applicable to common shares (GAAP financial measure)
    	
 
    	
$
    	
49
    	
 
    	
$
    	
32
    	
 
    


 

Normalized net income represents net income applicable to common shares adjusted for the after-tax impact of unrealized gains (losses) on risk management contracts, gains (losses) on investments, transaction costs related to acquisitions, gains (losses) on the sale of assets, and financing costs associated with the bridge facility for the pending WGL Acquisition. This measure is presented in order to enhance the comparability of AltaGas’ earnings, as it reflects the underlying performance of AltaGas’ business activities.

 

Normalized Funds from Operations

 

	
 
    	
 
    	
Three Months Ended
   March 31
    	
 
    
	
($ millions)
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Normalized funds   from operations
    	
 
    	
$
    	
169
    	
 
    	
$
    	
170
    	
 
    
	
Add (deduct):
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Transaction and   financing costs related to acquisitions
    	
 
    	
(13
    	
)
    	
(35
    	
)
    
	
Funds from   operations
    	
 
    	
156
    	
 
    	
135
    	
 
    
	
Add (deduct):
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Net change in   operating assets and liabilities
    	
 
    	
34
    	
 
    	
66
    	
 
    
	
Asset retirement   obligations settled
    	
 
    	
(1
    	
)
    	
(1
    	
)
    
	
Cash from   operations (GAAP financial measure)
    	
 
    	
$
    	
189
    	
 
    	
$
    	
200
    	
 
    


 

Normalized funds from operations is used to assist management and investors in analyzing the liquidity of the Corporation without regard to changes in operating assets and liabilities in the period and non-operating related expenses (net of current taxes) such as transaction and financing costs related to acquisitions.

 

Funds from operations are calculated from the Consolidated Statement of Cash Flows and are defined as cash from operations before net changes in operating assets and liabilities and expenditures incurred to settle asset retirement obligations. Management uses this measure to understand the ability to generate funds for capital investments, debt repayment, dividend payments and other investing activities.

 

Funds from operations and normalized funds from operations as presented should not be viewed as an alternative to cash from operations or other cash flow measures calculated in accordance with GAAP.

 

Net Debt and Net Debt to Total Capitalization

 

Net debt and net debt to total capitalization are used by the Corporation to monitor its capital structure and financing requirements. It is also used as a measure of the Corporation’s overall financial strength. Net debt is defined as short-term debt, plus current and long-term portions of long-term debt, less cash and cash equivalents. Total capitalization is defined as net debt plus shareholders’ equity and non-controlling interests. Additional information regarding these non-GAAP measures can be found under the section Capital Resources of this MD&A.

 

10











 

RESULTS OF OPERATIONS BY REPORTING SEGMENT

 

	
Normalized EBITDA (1)
    	
 
    	
Three Months Ended
   March 31
    	
 
    
	
($ millions)
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Gas
    	
 
    	
$
    	
71
    	
 
    	
$
    	
67
    	
 
    
	
Power
    	
 
    	
41
    	
 
    	
50
    	
 
    
	
Utilities
    	
 
    	
112
    	
 
    	
115
    	
 
    
	
Sub-total:   Operating Segments
    	
 
    	
224
    	
 
    	
232
    	
 
    
	
Corporate
    	
 
    	
(1
    	
)
    	
(4
    	
)
    
	
 
    	
 
    	
$
    	
223
    	
 
    	
$
    	
228
    	
 
    


 




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

 

GAS

 

OPERATING STATISTICS

 

	
 
    	
 
    	
Three Months Ended
   March 31
    	
 
    
	
 
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Extraction inlet   gas processed (Mmcf/d)(1)
    	
 
    	
1,086
    	
 
    	
1,032
    	
 
    
	
FG&P inlet   gas processed (Mmcf/d)(1)
    	
 
    	
467
    	
 
    	
372
    	
 
    
	
Total inlet gas   processed (Mmcf/d)(1) 
    	
 
    	
1,553
    	
 
    	
1,404
    	
 
    
	
Extraction   ethane volumes (Bbls/d)(1)
    	
 
    	
31,222
    	
 
    	
33,683
    	
 
    
	
Extraction NGL   volumes (Bbls/d)(1) (2)
    	
 
    	
43,564
    	
 
    	
38,275
    	
 
    
	
Total extraction   volumes (Bbls/d)(1) (3)
    	
 
    	
74,786
    	
 
    	
71,958
    	
 
    
	
Frac spread -   realized ($/Bbl)(1) (4)
    	
 
    	
19.01
    	
 
    	
10.56
    	
 
    
	
Frac spread -   average spot price ($/Bbl)(1) (5)
    	
 
    	
22.25
    	
 
    	
17.26
    	
 
    


 




(1)         Average for the period.

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

(3)         Includes Harmattan NGL processed on behalf of customers.

(4)         Realized frac spread or NGL margin, expressed in dollars per barrel of NGL, is derived from sales recorded by the segment during the period for frac exposed volumes plus the settlement value of frac hedges settled in the period less extraction premiums, divided by the total frac exposed volumes produced during the period.

(5)         Average spot frac spread or NGL margin, expressed in dollars per barrel of NGL, is indicative of the average sales price that AltaGas receives for propane, butane and condensate less extraction premiums, divided by the respective frac exposed volumes for the period.

 

Inlet gas volumes processed at the extraction facilities for the three months ended March 31, 2018 increased by 54 Mmcf/d, compared to the same period in 2017. The increase was primarily due to higher processed volumes at the Edmonton Ethane Extraction Plant (EEEP) due to higher available gas flows, partially offset by lower Harmattan co-stream inlet volumes. Inlet gas volumes processed at the field gathering and processing (FG&P) facilities for the three months ended March 31, 2018 increased by 95 Mmcf/d primarily due to volumes at the newly constructed Townsend 2A and higher incentive volumes at the Gordondale facility.

 

Average ethane volumes for the three months ended March 31, 2018 decreased by 2,461 Bbls/d, while average NGL volumes increased by 5,289 Bbls/d, compared to the same period in 2017. Lower ethane volumes were as a result of rejecting production at the Pembina Empress Extraction Plant (PEEP) due to uneconomic pricing, partially offset by higher production at EEEP. Higher NGL volumes were primarily due to increased volumes produced at the Townsend, Gordondale, and EEEP facilities.

 

Three Months Ended March 31

 

The Gas segment reported normalized EBITDA of $71 million in the first quarter of 2018, compared to $67 million in the same quarter of 2017. The increase in normalized EBITDA was due to higher realized frac spread and frac exposed volumes, and contributions from the North Pine and Townsend 2A facilities which commenced commercial operations in the fourth quarter of 2017, partially offset by the sale of the EDS and JFP transmission assets in the first quarter of 2017, lower natural gas storage margins and lower equity earnings from Petrogas.

 

11











 

AltaGas recorded equity earnings of $10 million from Petrogas, compared to $11 million in the same period in 2017. The decrease in Petrogas earnings was due to a planned turnaround at the Ferndale Terminal in the first quarter of 2018.

 

During the first quarter of 2018, AltaGas hedged approximately 7,500 Bbls/d of NGL at an average frac spread of $33/Bbl excluding basis differentials. During the first quarter of 2017, AltaGas hedged 5,300 Bbls/d of NGL at an average price of $21/Bbl, excluding basis differentials. The average indicative spot NGL frac spread in the first quarter of 2018 was approximately $22/Bbl, compared to $17/Bbl in the first quarter of 2017 inclusive of basis differentials. The realized frac spread (based on average spot price and realized hedging losses inclusive of basis differentials) of approximately $19/Bbl in the first quarter of 2018 (2017 - $11/Bbl) was higher than the same quarter in 2017 due to improved commodity prices and higher hedged prices.

 

During the first quarter of 2018, AltaGas recognized a pre-tax gain of $1 million on the sale of a non-core gas processing facility while in the first quarter of 2017, AltaGas recognized a pre-tax loss of $3 million on the sale of the EDS and JFP transmission assets.

 

POWER

 

OPERATING STATISTICS

 

	
 
    	
 
    	
Three Months Ended
   March 31
    	
 
    
	
 
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Renewable power   sold (GWh)
    	
 
    	
126
    	
 
    	
148
    	
 
    
	
Conventional   power sold (GWh)
    	
 
    	
842
    	
 
    	
385
    	
 
    
	
Renewable capacity   factor (%)
    	
 
    	
8.1
    	
 
    	
9.5
    	
 
    
	
Contracted   conventional equivalent availability factor (%) (1)
    	
 
    	
94.5
    	
 
    	
96.0
    	
 
    


 




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

 

During the three months ended March 31, 2018, the volume of renewable power sold decreased by 22 GWh and the volume of conventional power sold increased by 457 GWh, compared to the same period in 2017. The decrease in renewable volumes is a result of weather conditions causing lower wind generation at the Bear Mountain wind facility (Bear Mountain) and lower hydro generation at the Northwest Hydro Facilities. Generation at the Craven biomass facility (Craven) decreased due to the timing of the planned spring outage which was completed in the first quarter of 2018 compared to the second quarter of 2017. The increase in conventional volumes was due to increased run time at the San Joaquin Facilities and Blythe as a result of increased dispatch under the respective power purchase agreements. Blythe was able to generate increased volumes despite a planned outage due to greater operational and fuel flexibility which caused it to be dispatched for a greater number of hours than in the first quarter of 2017.

 

The renewable capacity factor for the three months ended March 31, 2018 decreased due to weather conditions resulting in lower generation at the Northwest Hydro Facilities and Bear Mountain. Contracted conventional equivalent availability factor was lower in the first quarter of 2018 as a result of planned outages at Blythe.

 

Three Months Ended March 31

 

The Power segment reported normalized EBITDA of $41 million during the first quarter of 2018, compared to $50 million in the same period of 2017. Normalized EBITDA decreased due to expenses related to the planned outage at Blythe, timing of the Craven spring outage, lower wind generation at Bear Mountain, lower river flows and the timing of operating expenses at the Northwest Hydro Facilities, and the weaker U.S. dollar.

 

12











 

UTILITIES

 

OPERATING STATISTICS

 

	
 
    	
 
    	
Three Months Ended
   March 31
    	
 
    
	
 
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Canadian   utilities
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Natural gas   deliveries - end-use (PJ)(1)
    	
 
    	
14.1
    	
 
    	
13.5
    	
 
    
	
Natural gas   deliveries - transportation (PJ)(1)
    	
 
    	
1.8
    	
 
    	
1.9
    	
 
    
	
U.S. utilities
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Natural gas   deliveries - end-use (Bcf)(1)
    	
 
    	
31.0
    	
 
    	
30.2
    	
 
    
	
Natural gas   deliveries - transportation (Bcf)(1)
    	
 
    	
13.4
    	
 
    	
15.4
    	
 
    
	
Service sites (2)
    	
 
    	
582,871
    	
 
    	
576,829
    	
 
    
	
Degree day   variance from normal - AUI (%) (3)
    	
 
    	
10.2
    	
 
    	
(2.2
    	
)
    
	
Degree day   variance from normal - Heritage Gas (%) (3)
    	
 
    	
(8.1
    	
)
    	
(1.9
    	
)
    
	
Degree day   variance from normal - SEMCO Gas (%) (4)
    	
 
    	
3.0
    	
 
    	
(11.8
    	
)
    
	
Degree day   variance from normal - ENSTAR (%) (4)
    	
 
    	
(1.7
    	
)
    	
9.6
    	
 
    


 




(1)         Petajoule (PJ) is one million gigajoules. Bcf is one billion cubic feet.

(2)         Service sites reflect all of the service sites of AUI, PNG, Heritage Gas and U.S. utilities, including transportation and non-regulated business lines.

(3)         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 BCUC has approved a rate stabilization mechanism for its residential and small commercial customers.

(4)         A degree day for U.S. utilities is a measure of coldness determined daily as the number of degrees the average temperature during the day in question is below 65 degrees Fahrenheit. Degree days for a particular period are determined by adding the degree days incurred during each day of the period. Normal degree days for a particular period are the average of degree days during the prior 15 years for SEMCO Gas and during the prior 10 years for ENSTAR.

 

AltaGas’ Utilities segment experienced colder weather in the first quarter of 2018 compared to the same quarter of 2017. This was mainly driven by 3% colder than normal weather at SEMCO and 10% colder than normal weather at AUI, partially offset by 2% warmer than normal weather at ENSTAR. Overall colder weather resulted in increased natural gas deliveries to end-use customers in both Canada and the U.S.

 

Service sites increased by approximately 6,000 sites for the first quarter of 2018 compared to the same period in 2017 due to growth in customer base at all of the utilities.

 

Three Months Ended March 31

 

The Utilities segment reported normalized EBITDA of $112 million for the three months ended March 31, 2018, compared to $115 million in the same quarter of 2017. The decrease was mainly due to unfavorable foreign exchange rates, the revenue impact related to the U.S. tax reform at SEMCO, higher expenses at the U.S. utilities, and warmer weather in Alaska and Nova Scotia. These decreases were partially offset by colder weather in Michigan and Alberta, higher transport and gas sales revenue at SEMCO, and lower expenses at PNG.

 

CORPORATE

 

Three Months Ended March 31

 

In the Corporate segment, normalized EBITDA for the first quarter of 2018 was a loss of $1 million, compared to a $4 million loss in the same quarter of 2017. The decrease was a result of a number of factors including lower employee and information technology related costs.

 

13











 

INVESTED CAPITAL

 

	
 
    	
 
    	
Three Months Ended
   March 31, 2018
    	
 
    
	
($ millions)
    	
 
    	
Gas
    	
 
    	
Power
    	
 
    	
Utilities
    	
 
    	
Corporate
    	
 
    	
Total
    	
 
    
	
Invested   capital:
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Property, plant   and equipment
    	
 
    	
$
    	
54
    	
 
    	
$
    	
4
    	
 
    	
$
    	
17
    	
 
    	
$
    	
—
    	
 
    	
$
    	
75
    	
 
    
	
Intangible   assets
    	
 
    	
1
    	
 
    	
—
    	
 
    	
—
    	
 
    	
1
    	
 
    	
2
    	
 
    
	
Long-term   investments
    	
 
    	
19
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
19
    	
 
    
	
Contributions from   non-controlling interest
    	
 
    	
(14
    	
)
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
(14
    	
)
    
	
Invested capital
    	
 
    	
60
    	
 
    	
4
    	
 
    	
17
    	
 
    	
1
    	
 
    	
82
    	
 
    
	
Disposals:
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Property, plant   and equipment
    	
 
    	
(7
    	
)
    	
(2
    	
)
    	
—
    	
 
    	
—
    	
 
    	
(9
    	
)
    
	
Net invested   capital
    	
 
    	
$
    	
53
    	
 
    	
$
    	
2
    	
 
    	
$
    	
17
    	
 
    	
$
    	
1
    	
 
    	
$
    	
73
    	
 
    


 

	
 
    	
 
    	
Three Months Ended
   March 31, 2017
    	
 
    
	
($ millions)
    	
 
    	
Gas
    	
 
    	
Power
    	
 
    	
Utilities
    	
 
    	
Corporate
    	
 
    	
Total
    	
 
    
	
Invested   capital:
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Property, plant   and equipment
    	
 
    	
$
    	
45
    	
 
    	
$
    	
9
    	
 
    	
$
    	
17
    	
 
    	
$
    	
—
    	
 
    	
$
    	
71
    	
 
    
	
Intangible   assets
    	
 
    	
1
    	
 
    	
—
    	
 
    	
—
    	
 
    	
1
    	
 
    	
2
    	
 
    
	
Long-term   investments
    	
 
    	
14
    	
 
    	
—
    	
 
    	
—
    	
 
    	
—
    	
 
    	
14
    	
 
    
	
Invested capital
    	
 
    	
60
    	
 
    	
9
    	
 
    	
17
    	
 
    	
1
    	
 
    	
87
    	
 
    
	
Disposals:
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Property, plant   and equipment
    	
 
    	
(67
    	
)
    	
(2
    	
)
    	
—
    	
 
    	
—
    	
 
    	
(69
    	
)
    
	
Net invested   capital
    	
 
    	
$
    	
(7
    	
)
    	
$
    	
7
    	
 
    	
$
    	
17
    	
 
    	
$
    	
1
    	
 
    	
$
    	
18
    	
 
    


 

During the first quarter of 2018, AltaGas’ invested capital was $82 million, compared to $87 million in the same quarter of 2017. The decrease in invested capital was mainly due to contributions from non-controlling interest (representing Vopak’s share of construction costs related to RIPET) received in the first quarter of 2018, partially offset by higher additions to property, plant and equipment and a higher contribution to long-term investments (AIJVLP) for the three months ended March 31, 2018 compared with the same period of 2017.

 

The increase in additions to property, plant and equipment in the first quarter of 2018 was mainly due to costs related to the construction of RIPET, partially offset by costs incurred in the first quarter of 2017 relating to the construction of the Townsend 2A and the North Pine facilities. The disposals of property, plant and equipment in the first quarter of 2018 primarily related to the sale of non-core facilities in the Gas segment and a development stage wind asset in the Power segment, while in the first quarter of 2017 the disposals of property, plant and equipment related to the sale of the EDS and JFP transmission assets.

 

The invested capital in the first quarter of 2018 included maintenance capital of $3 million (2017 - $nil) in the Gas segment and $2 million (2017 - $3 million) in the Power segment.

 

14









 

RISK MANAGEMENT

 

AltaGas is exposed to various market risks in the normal course of operations that could impact earnings and cash flows. At times, AltaGas will enter into financial derivative contracts to manage exposure to fluctuations in commodity prices and foreign exchange rates. The Board of Directors of AltaGas has established a risk management policy for the Corporation establishing AltaGas’ risk management control framework. Financial derivative instruments are governed under, and subject to, this policy. As at March 31, 2018 and December 31, 2017, the fair values of the Corporation’s derivatives were as follows:

 

	
($ millions)
    	
 
    	
March 31,
   2018
    	
 
    	
December 31,
   2017
    	
 
    
	
Natural gas
    	
 
    	
$
    	
—
    	
 
    	
$
    	
6
    	
 
    
	
NGL frac spread
    	
 
    	
(13
    	
)
    	
(24
    	
)
    
	
Power
    	
 
    	
(7
    	
)
    	
(1
    	
)
    
	
Foreign exchange
    	
 
    	
1
    	
 
    	
2
    	
 
    
	
Net derivative   liability
    	
 
    	
$
    	
(19
    	
)
    	
$
    	
(17
    	
)
    


 

Commodity Price Contracts

 

From time to time, the Corporation executes gas, power, and other commodity contracts to manage its asset portfolio and lock in margins from back-to-back purchase and sale agreements. The fair value of power, natural gas, and NGL derivatives was calculated using estimated forward prices from published sources for the relevant period. AltaGas has not elected hedge accounting for any of its derivative contracts currently in place. Changes in the fair value of these derivative contracts are recorded in the Consolidated Statement of Income in the period in which the change occurs.

 

The Power segment has various fixed price power purchase and sale contracts in the Alberta market, which are expected to be settled over the next five years.

 

The Corporation also executes fixed-for-floating NGL frac spread swaps to manage its exposure to frac spreads as the financial results of several extraction plants are affected by fluctuations in NGL frac spreads. The average indicative spot NGL frac spread for the three months ended March 31, 2018 was approximately $22/Bbl (2017 — $17/Bbl), inclusive of basis differentials. The average NGL frac spread realized by AltaGas (based on average spot price and realized hedging losses inclusive of basis differentials) for the three months ended March 31, 2018 was approximately $19/Bbl (2017 - $11/Bbl). For the remainder of 2018, AltaGas currently has frac hedges in place to hedge approximately 7,500 Bbls/d at an average price of $33/Bbl, excluding basis differentials.

 

Foreign Exchange

 

AltaGas has foreign operations whereby the functional currency is the U.S. dollar. As a result, the Corporation’s earnings, cash flows, and other comprehensive income are exposed to fluctuations resulting from changes in foreign exchange rates. This risk is partially mitigated to the extent that AltaGas has U.S. dollar-denominated debt and 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 March 31, 2018 and December 31, 2017, management has not designated any outstanding U.S. dollar denominated long-term debt to hedge against the currency translation effect of its foreign investments. Designation of U.S. dollar denominated long-term debt has the effect of mitigating volatility on net income by offsetting foreign exchange gains and losses on U.S. dollar denominated long-term debt and foreign net investment. For the three months ended March 31, 2018, AltaGas incurred an after-tax unrealized gain of $nil arising from the translation of debt in other comprehensive income (2017 - after-tax unrealized gain of $1 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 three

 

15











 

months ended March 31, 2018, an unrealized loss of $1 million was recognized in revenue in relation to these contracts (2017 - unrealized loss of $6 million).

 

The Effects of Derivative Instruments on the Consolidated Statements of Income

 

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

 

	
 
    	
 
    	
Three Months Ended
   March 31
    	
 
    
	
($ millions)
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Natural gas
    	
 
    	
$
    	
(6
    	
)
    	
$
    	
(2
    	
)
    
	
Storage   optimization
    	
 
    	
—
    	
 
    	
2
    	
 
    
	
NGL frac spread
    	
 
    	
11
    	
 
    	
8
    	
 
    
	
Power
    	
 
    	
(3
    	
)
    	
—
    	
 
    
	
Foreign exchange
    	
 
    	
(1
    	
)
    	
(7
    	
)
    
	
 
    	
 
    	
$
    	
1
    	
 
    	
$
    	
1
    	
 
    


 

Please refer to Note 20 of the 2017 Annual Consolidated Financial Statements and Note 11 of the unaudited condensed interim Consolidated Financial Statements as at and for the three months ended March 31, 2018 for further details regarding AltaGas’ risk management activities.

 

LIQUIDITY

 

	
 
    	
 
    	
Three Months Ended
   March 31
    	
 
    
	
($ millions)
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
Cash from   operations
    	
 
    	
$
    	
189
    	
 
    	
$
    	
200
    	
 
    
	
Investing   activities
    	
 
    	
(89
    	
)
    	
(47
    	
)
    
	
Financing   activities
    	
 
    	
(34
    	
)
    	
(143
    	
)
    
	
Increase in   cash, cash equivalents, and restricted cash
    	
 
    	
$
    	
66
    	
 
    	
$
    	
10
    	
 
    


 

Cash from Operations

 

Cash from operations decreased by $11 million for the three months ended March 31, 2018 compared to the same period in 2017, primarily due to an unfavorable variance in the net change in operating assets and liabilities, partially offset by higher net income. The unfavorable variance in net change in operating assets and liabilities was primarily due to lower cash inflow in the first quarter of 2018 relating to changes in inventory and accounts payable at the Utilities due to weather. These decreases in cash flow were partially offset by changes in accounts receivable due to weather in the Utilities segment and favorable variances in the long-term regulatory liability due to the change in the U.S. Federal income tax rate.

 

Working Capital

 

	
($ millions except current ratio)
    	
 
    	
March 31,
   2018
    	
 
    	
December 31,
   2017
    	
 
    
	
Current assets
    	
 
    	
$
    	
665
    	
 
    	
$
    	
702
    	
 
    
	
Current   liabilities
    	
 
    	
728
    	
 
    	
815
    	
 
    
	
Working   deficiency
    	
 
    	
$
    	
(63
    	
)
    	
$
    	
(113
    	
)
    
	
Working capital   ratio
    	
 
    	
0.91
    	
 
    	
0.86
    	
 
    


 

The improvement in the working capital ratio was primarily due to an increase in cash and cash equivalents, and a decrease in short-term debt and accounts payable and accrued liabilities as compared to December 31, 2017, partially offset by a decrease in accounts receivable and inventory. AltaGas’ working capital will fluctuate in the normal course of business and the working capital deficiency will be funded using cash flow from operations, the DRIP and available credit facilities as required.

 

16











 

Investing Activities

 

Cash used in investing activities for the three months ended March 31, 2018 was $89 million, compared to $47 million in the same period in 2017. Investing activities for the three months ended March 31, 2018 primarily included expenditures of approximately $82 million for property, plant, and equipment and approximately $19 million of contributions to AltaGas’ equity investments, partially offset by cash proceeds of approximately $9 million primarily from the sale of non-core gas facilities and a wind asset, and cash proceeds of approximately $5 million for the disposition of an investment. Investing activities for the three months ended March 31, 2017 primarily included expenditures of approximately $86 million for property, plant, and equipment, approximately $21 million for derivative contracts, and approximately $14 million of contributions to AltaGas’ equity investments, partially offset by cash proceeds of approximately $69 million, net of transaction costs, primarily from the sale of the EDS and JFP transmission assets, and cash inflow of approximately $8 million from Petrogas to repay a portion of its outstanding loan.

 

Financing Activities

 

Cash used in financing activities for the three months ended March 31, 2018 was $34 million, compared to cash used in financing activities of $143 million in the same period in 2017. Financing activities for the three months ended March 31, 2018 were primarily comprised of net proceeds from the issuance of common shares of $67 million (mainly from common shares issued through the DRIP), and borrowings under the credit facilities of $248 million, partially offset by repayments of long-term debt and short-term debt of $205 million and $43 million, respectively. Financing activities for the three months ended March 31, 2017 were primarily comprised of net proceeds from the issuance of preferred shares of $294 million and common shares of $62 million (including common shares issued through the DRIP), and borrowings under the credit facilities of $14 million, partially offset by the repayments of long-term debt and short-term debt of $287 million and $123 million, respectively. Total dividends paid to common and preferred shareholders of AltaGas for the three months ended March 31, 2018 were $113 million (2017 - $100 million), of which $66 million was reinvested through the DRIP (2017 - $58 million). The increase in dividends paid was due to more common shares outstanding and dividend increases on common shares declared in the fourth quarter of 2017.

 

CAPITAL RESOURCES

 

AltaGas’ objective for managing capital is to maintain its investment grade credit ratings, ensure adequate liquidity, maximize the profitability of its existing assets and grow its energy infrastructure to create long-term value and enhance returns for its investors. AltaGas’ capital structure is comprised of shareholders’ equity (including non-controlling interests), short-term and long-term debt (including the current portion) less cash and cash equivalents.

 

The use of debt or equity funding is based on AltaGas’ capital structure, which is determined by considering the norms and risks associated with operations and cash flow stability and sustainability.

 

	
($ millions)
    	
 
    	
March 31,
   2018
    	
 
    	
December 31,
   2017
    	
 
    
	
Short-term debt
    	
 
    	
$
    	
5
    	
 
    	
$
    	
47
    	
 
    
	
Current portion   of long-term debt
    	
 
    	
214
    	
 
    	
189
    	
 
    
	
Long-term debt(1)
    	
 
    	
3,469
    	
 
    	
3,437
    	
 
    
	
Total debt
    	
 
    	
3,688
    	
 
    	
3,673
    	
 
    
	
Less: cash and   cash equivalents
    	
 
    	
(100
    	
)
    	
(27
    	
)
    
	
Net debt
    	
 
    	
$
    	
3,588
    	
 
    	
$
    	
3,646
    	
 
    
	
Shareholders’   equity
    	
 
    	
4,667
    	
 
    	
4,573
    	
 
    
	
Non-controlling   interests
    	
 
    	
81
    	
 
    	
66
    	
 
    
	
Total   capitalization
    	
 
    	
$
    	
8,336
    	
 
    	
$
    	
8,285
    	
 
    
	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Net   debt-to-total capitalization (%)
    	
 
    	
43
    	
 
    	
44
    	
 
    


 




(1)         Net of debt issuance costs of $14 million as at March 31, 2018 (December 31, 2017 - $14 million).

 

As at March 31, 2018, AltaGas’ total debt primarily consisted of outstanding MTNs of $2.7 billion (December 31, 2017 - $2.9 billion), PNG debenture notes of $34 million (December 31, 2017 - $34 million), SEMCO long-term debt of $471 million

 

17











 

(December 31, 2017 - $462 million) and $443 million drawn under the bank credit facilities (December 31, 2017 - $260 million). In addition, AltaGas had $130 million of letters of credit (December 31, 2017 - $120 million) outstanding.

 

As at March 31, 2018, AltaGas’ total market capitalization was approximately $4.2 billion based on approximately 178 million common shares outstanding and a closing trading price on March 31, 2018 of $23.84 per common share.

 

AltaGas’ earnings interest coverage for the rolling 12 months ended March 31, 2018 was 1.3 times (12 months ended March 31, 2017 – 2.3 times).

 

	
 
    	
 
    	
 
    	
 
    	
Drawn at
    	
 
    	
Drawn at
    	
 
    
	
Credit Facilities
   ($ millions)
    	
 
    	
Borrowing
   capacity
    	
 
    	
March 31,
   2018
    	
 
    	
December 31,
   2017
    	
 
    
	
Demand operating   facilities
    	
 
    	
$
    	
70
    	
 
    	
$
    	
3
    	
 
    	
$
    	
4
    	
 
    
	
Extendible   revolving letter of credit facility
    	
 
    	
150
    	
 
    	
38
    	
 
    	
41
    	
 
    
	
Letter of credit   demand facility
    	
 
    	
150
    	
 
    	
85
    	
 
    	
71
    	
 
    
	
PNG operating   facility
    	
 
    	
25
    	
 
    	
5
    	
 
    	
13
    	
 
    
	
AltaGas Ltd.   revolving credit facility (1)
    	
 
    	
1,400
    	
 
    	
441
    	
 
    	
219
    	
 
    
	
AltaGas Ltd.   revolving US$300 million credit facility (1) (2)
    	
 
    	
387
    	
 
    	
—
    	
 
    	
—
    	
 
    
	
SEMCO Energy   US$150 million unsecured credit facility (1) (2)
    	
 
    	
193
    	
 
    	
1
    	
 
    	
32
    	
 
    
	
 
    	
 
    	
$
    	
2,375
    	
 
    	
$
    	
573
    	
 
    	
$
    	
380
    	
 
    


 




(1)         Amount drawn at March 31, 2018 converted at the month-end rate of 1 U.S. dollar = 1.2894 Canadian dollar (December 31, 2017 - 1 U.S. dollar = 1.2545 Canadian dollar).

(2)         Borrowing capacity was converted at the March 31, 2018 U.S./Canadian dollar month-end exchange rate.

 

All of the borrowing facilities have covenants customary for these types of facilities, which must be met at each quarter end. AltaGas and its subsidiaries have been in compliance with all financial covenants each quarter since the establishment of the facilities.

 

The following table summarizes the Corporation’s primary financial covenants as defined by the credit facility agreements:

 

	
Ratios
    	
 
    	
Debt covenant
   requirements
    	
 
    	
As at
   March 31, 2018
    	
 
    
	
Bank   debt-to-capitalization(1)
    	
 
    	
not greater than 65 percent
    	
 
    	
42.6
    	
%
    
	
Bank   EBITDA-to-interest expense (1) (2) 
    	
 
    	
not less than 2.5x
    	
 
    	
4.1
    	
 
    
	
Bank   debt-to-capitalization (SEMCO)(3)
    	
 
    	
not greater than 60 percent
    	
 
    	
36.8
    	
%
    
	
Bank   EBITDA-to-interest expense (SEMCO)(3)
    	
 
    	
not less than 2.25x
    	
 
    	
7.7
    	
 
    


 




(1)         Calculated in accordance with the Corporation’s credit facility agreement, which is available on SEDAR at www.sedar.com.

(2)         Estimated, subject to final adjustments.

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

 

On September 7, 2017, a $5 billion base shelf prospectus was filed. The purpose of the base shelf prospectus is to facilitate timely offerings of certain types of future public debt and/or equity issuances during the 25-month period that the base shelf prospectus remains effective. As at March 31, 2018, approximately $4.6 billion was available under the base shelf prospectus.

 

RELATED PARTY TRANSACTIONS

 

In the normal course of business, AltaGas transacts with its subsidiaries, affiliates and joint ventures. There were no significant changes in the nature of the related party transactions described in Note 27 of the 2017 Annual Consolidated Financial Statements.

 

18









 

SHARE INFORMATION

 

	
 
    	
 
    	
As at April 20, 2018
    	
 
    
	
Issued   and outstanding
    	
 
    	
 
    	
 
    
	
Common shares
    	
 
    	
178,847,544
    	
 
    
	
Preferred Shares
    	
 
    	
 
    	
 
    
	
Series A
    	
 
    	
5,511,220
    	
 
    
	
Series B
    	
 
    	
2,488,780
    	
 
    
	
Series C
    	
 
    	
8,000,000
    	
 
    
	
Series E
    	
 
    	
8,000,000
    	
 
    
	
Series G
    	
 
    	
8,000,000
    	
 
    
	
Series I
    	
 
    	
8,000,000
    	
 
    
	
Series K
    	
 
    	
12,000,000
    	
 
    
	
Subscription   Receipts
    	
 
    	
84,510,000
    	
 
    
	
Issued
    	
 
    	
 
    	
 
    
	
Share options
    	
 
    	
4,496,486
    	
 
    
	
Share options   exercisable
    	
 
    	
3,504,047
    	
 
    


 

DIVIDENDS

 

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

 

The following table summarizes AltaGas’ dividend declaration history:

 

	
Dividends
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Year ended December 31
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
($ per common share)
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
First quarter
    	
 
    	
$
    	
0.547500
    	
 
    	
$
    	
0.525000
    	
 
    
	
Second quarter
    	
 
    	
—
    	
 
    	
0.525000
    	
 
    
	
Third quarter
    	
 
    	
—
    	
 
    	
0.525000
    	
 
    
	
Fourth quarter
    	
 
    	
—
    	
 
    	
0.540000
    	
 
    
	
Total
    	
 
    	
$
    	
0.547500
    	
 
    	
$
    	
2.115000
    	
 
    


 

	
Series A Preferred Share Dividends
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Year ended December 31
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
($ per preferred share)
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
First quarter
    	
 
    	
$
    	
0.211250
    	
 
    	
$
    	
0.211250
    	
 
    
	
Second quarter
    	
 
    	
—
    	
 
    	
0.211250
    	
 
    
	
Third quarter
    	
 
    	
—
    	
 
    	
0.211250
    	
 
    
	
Fourth quarter
    	
 
    	
—
    	
 
    	
0.211250
    	
 
    
	
Total
    	
 
    	
$
    	
0.211250
    	
 
    	
$
    	
0.845000
    	
 
    


 

	
Series B Preferred Share Dividends
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Year ended December 31
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
($ per preferred share)
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
First quarter
    	
 
    	
$
    	
0.217600
    	
 
    	
$
    	
0.195410
    	
 
    
	
Second quarter
    	
 
    	
—
    	
 
    	
0.195710
    	
 
    
	
Third quarter
    	
 
    	
—
    	
 
    	
0.201010
    	
 
    
	
Fourth quarter
    	
 
    	
—
    	
 
    	
0.214250
    	
 
    
	
Total
    	
 
    	
$
    	
0.217600
    	
 
    	
$
    	
0.806380
    	
 
    


 

19











 

	
Series C Preferred Share Dividends
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Year ended December 31
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
(US$ per preferred share)
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
First quarter
    	
 
    	
$
    	
0.330625
    	
 
    	
$
    	
0.275000
    	
 
    
	
Second quarter
    	
 
    	
—
    	
 
    	
0.275000
    	
 
    
	
Third quarter
    	
 
    	
—
    	
 
    	
0.275000
    	
 
    
	
Fourth quarter
    	
 
    	
—
    	
 
    	
0.330625
    	
 
    
	
Total
    	
 
    	
$
    	
0.330625
    	
 
    	
$
    	
1.155625
    	
 
    


 

	
Series E Preferred Share Dividends
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Year ended December 31
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
($ per preferred share)
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
First quarter
    	
 
    	
$
    	
0.312500
    	
 
    	
$
    	
0.312500
    	
 
    
	
Second quarter
    	
 
    	
—
    	
 
    	
0.312500
    	
 
    
	
Third quarter
    	
 
    	
—
    	
 
    	
0.312500
    	
 
    
	
Fourth quarter
    	
 
    	
—
    	
 
    	
0.312500
    	
 
    
	
Total
    	
 
    	
$
    	
0.312500
    	
 
    	
$
    	
1.250000
    	
 
    


 

	
Series G Preferred Share Dividends
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Year ended December 31
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
($ per preferred share)
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
First quarter
    	
 
    	
$
    	
0.296875
    	
 
    	
$
    	
0.296875
    	
 
    
	
Second quarter
    	
 
    	
—
    	
 
    	
0.296875
    	
 
    
	
Third quarter
    	
 
    	
—
    	
 
    	
0.296875
    	
 
    
	
Fourth quarter
    	
 
    	
—
    	
 
    	
0.296875
    	
 
    
	
Total
    	
 
    	
$
    	
0.296875
    	
 
    	
$
    	
1.187500
    	
 
    


 

	
Series I Preferred Share Dividends
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Year ended December 31
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
($ per preferred share)
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
First quarter
    	
 
    	
$
    	
0.328125
    	
 
    	
$
    	
0.328125
    	
 
    
	
Second quarter
    	
 
    	
—
    	
 
    	
0.328125
    	
 
    
	
Third quarter
    	
 
    	
—
    	
 
    	
0.328125
    	
 
    
	
Fourth quarter
    	
 
    	
—
    	
 
    	
0.328125
    	
 
    
	
Total
    	
 
    	
$
    	
0.328125
    	
 
    	
$
    	
1.312500
    	
 
    


 

	
Series K Preferred Share Dividends
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Year ended December 31
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
($ per preferred share)
    	
 
    	
2018
    	
 
    	
2017
    	
 
    
	
First quarter
    	
 
    	
$
    	
0.312500
    	
 
    	
$
    	
—
    	
 
    
	
Second quarter
    	
 
    	
—
    	
 
    	
0.438400
    	
 
    
	
Third quarter
    	
 
    	
—
    	
 
    	
0.312500
    	
 
    
	
Fourth quarter
    	
 
    	
—
    	
 
    	
0.312500
    	
 
    
	
Total
    	
 
    	
$
    	
0.312500
    	
 
    	
$
    	
1.063400
    	
 
    


 

CRITICAL ACCOUNTING ESTIMATES

 

Since a determination of the value of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of AltaGas’ Consolidated Financial Statements requires the use of estimates and assumptions that have been made using careful judgment. Other than as described below, AltaGas’ significant accounting policies have remained unchanged and are contained in the notes to the 2017 Annual Consolidated Financial Statements. Certain of these policies involve critical accounting estimates as a result of the requirement to make particularly subjective or complex judgments about matters that are

 

20











 

inherently uncertain, and because of the likelihood that materially different amounts could be reported under different conditions or using different assumptions.

 

AltaGas’ critical accounting estimates continue to be financial instruments, depreciation and amortization expense, asset retirement obligations and other environmental costs, asset impairment assessments, income taxes, pension plans and post-retirement benefits, and regulatory assets and liabilities. For a full discussion of these accounting estimates, refer to the 2017 Annual Consolidated Financial Statements and MD&A.

 

ADOPTION OF NEW ACCOUNTING STANDARDS

 

Effective January 1, 2018, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU):

 

·                  ASU No. 2014-09 “Revenue from Contracts with Customers” and all related amendments (collectively “ASC 606”).  AltaGas adopted ASC 606 using the modified retrospective method to contracts that have not been completed as at January 1, 2018. Under the modified retrospective method, the comparative information is not adjusted. The adoption of ASC 606 impacted the timing of revenue recognition in relation to contracts with take-or-pay or minimum volume commitments whereby the customers have make up rights for deficiency quantities. However, on adoption, no cumulative adjustments to opening retained earnings were required for this change in revenue recognition pattern as none of the customers had material deficiency quantities. Please also refer to Note 10 of the unaudited condensed interim Consolidated Financial Statements as at and for the three months ended March 31, 2018 for further details. AltaGas does not expect the application of ASC 606 to have a material impact on its consolidated financial statements in 2018;

 

·                  ASU No. 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” which revised an entity’s accounting related to (1) the classification and measurement of investments in equity securities and (2) the presentation of certain fair value changes for financial liabilities measured at fair value. It also amended certain disclosure requirements associated with the fair value of financial instruments. Upon adoption, AltaGas reclassified its equity securities with readily determinable fair values from available-for-sale to held for trading. Changes in fair value for equity securities with readily determinable fair values are now recognized through earnings instead of other comprehensive income. As a result, a cumulative-effect adjustment to retained earnings of approximately $7 million was recognized as at January 1, 2018. The remaining provisions of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

 

·                  ASU No. 2016-15 “Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments”. The amendments in this ASU clarified the classification of certain cash flow transactions on the statement of cash flow. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

 

·                  ASU No. 2016-16 “Income Taxes: Intra-Entity Transfers of Assets Other Than Inventory”. The amendments in this ASU revised the accounting for income tax consequences on intra-entity transfers of assets by requiring an entity to recognize current and deferred tax on intra-entity transfers of assets other than inventory when the transfer occurs. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

 

·                  ASU No. 2016-18 “Statement of Cash Flows: Restricted Cash”. The amendments in this ASU required those amounts deemed to be restricted cash and restricted cash equivalents to be included in the cash and cash equivalents balance on the statement of cash flows. The change in presentation of the restricted cash balance on the statement of cash flows was applied on a retrospective basis;

 

·                  ASU No. 2017-01 “Business Combinations: Clarifying the Definition of a Business”. The amendments in this ASU changed the definition of a business to assist entities with evaluating when a set of transferred assets and activities is a business. AltaGas will apply the amendments to this ASU prospectively;

 

21











 

·                  ASU No. 2017-04 “Intangibles — Goodwill and Other: Simplifying the Test for Goodwill Impairment”. The amendments in this ASU removed Step 2 of the goodwill impairment test, eliminating the requirement to determine the fair value of individual assets and liabilities of a reporting unit to measure the goodwill impairment. AltaGas early adopted this ASU and will apply the amendments to this ASU prospectively. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

 

·                  ASU No. 2017-05 “Other Income — Gains and Losses from the De-recognition of Nonfinancial Assets: Clarifying the Scope of Asset De-recognition Guidance and Accounting for Partial Sales of Nonfinancial Assets”. The amendments in this ASU clarified the scope of ASC 610-20 as well as the accounting for partial sales of nonfinancial assets. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

 

·                  ASU No. 2017-07 “Compensation — Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”. The amendments in this ASU revised the presentation of net periodic pension cost and net periodic postretirement benefit cost on the income statement and limited the components that are eligible for capitalization in assets to only the service cost component. AltaGas applied the change in presentation of the current service cost and other components of net benefit cost on the income statement retrospectively. As a result, $0.4 million of net benefit cost associated with other components were reclassified from the line item “Operating and administrative” to “Other loss” on the Consolidated Statement of Income for the three months ended March 31, 2017. AltaGas applied the change related to the capitalization of the service cost prospectively. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

 

·                  ASU No. 2017-09 “Compensation — Stock Compensation: Scope of Modifications Accounting”. The amendments in this ASU provided guidance on the types of changes to the terms or conditions of share-based payment arrangements to which an entity would be required to apply modification accounting. The guidance was applied prospectively and did not have a material impact on AltaGas’ consolidated financial statements;

 

·                  ASU No. 2017-12 “Derivatives and Hedging — Targeted Improvements to Accounting for Hedging Activities”. The amendments in this ASU improved the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and made certain targeted improvements to simplify the application of hedge accounting. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and

 

·                  ASU No. 2018-03 “Technical Corrections and Improvements to Financial Instruments — Overall”. The amendments in this ASU clarified certain aspects of the guidance issued in ASU No. 2016-01. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements.

 

FUTURE CHANGES IN ACCOUNTING PRINCIPLES

 

In February 2016, FASB issued ASU No. 2016-02 “Leases”, which requires lessees to recognize on the balance sheet a right-of-use asset and a lease liability 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 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

 

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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 years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted. AltaGas is currently assessing the impact of this ASU on its consolidated financial statements.

 

In February 2018, FASB issued ASU No. 2018-02 “Income Statement — Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”. The amendments in this ASU allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

 

OFF-BALANCE SHEET ARRANGEMENTS

 

With the exception of the subscription receipts and the net proceeds thereof held in escrow as described under the Developments Relating to the Pending WGL Acquisition section of this MD&A, AltaGas did not enter into any material off-balance sheet arrangements during the three months ended March 31, 2018. Reference should be made to the audited Consolidated Financial Statements and MD&A as at and for the year ended December 31, 2017 for information on off-balance sheet arrangements.

 

DISCLOSURE CONTROLS AND PROCEDURES (DCP) AND INTERNAL CONTROL OVER FINANCIAL REPORTING (ICFR)

 

AltaGas’ management, including its Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining DCP and ICFR, as those terms are defined in National Instrument 52-109 “Certification of Disclosure in Issuers’ Annual and Interim Filings”. The objective of this instrument is to improve the quality, reliability, and transparency of information that is filed or submitted under securities legislation.

 

AltaGas’ management, including the Chief Executive Officer and the Chief Financial Officer, have designed, or caused to be designed under their supervision, DCP and ICFR to provide reasonable assurance that information required to be disclosed by AltaGas in its annual filings, interim filings or other reports to be filed or submitted by it under securities legislation is made known to them, is reported on a timely basis, financial reporting is reliable, and financial statements prepared for external purposes are in accordance with U.S. GAAP.

 

The ICFR has been designed based on the framework established in the 2013 Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

 

During the first quarter of 2018, there were no changes made to AltaGas’ ICFR that materially affected, or are reasonably likely to materially affect, its ICFR.

 

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It should be noted that a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues, including instances of fraud, if any, have been detected. The design of any system of controls is also based in part on certain assumptions about the likelihood of future events, and there can be no assurances that any design will succeed in achieving its stated goals under all potential conditions.

 

SUMMARY OF CONSOLIDATED RESULTS FOR THE EIGHT MOST RECENT QUARTERS (1)

 

	
($ millions)
    	
 
    	
Q1-18
    	
 
    	
Q4-17
    	
 
    	
Q3-17
    	
 
    	
Q2-17
    	
 
    	
Q1-17
    	
 
    	
Q4-16
    	
 
    	
Q3-16
    	
 
    	
Q2-16
    	
 
    
	
Total revenue
    	
 
    	
878
    	
 
    	
745
    	
 
    	
502
    	
 
    	
539
    	
 
    	
771
    	
 
    	
661
    	
 
    	
492
    	
 
    	
426
    	
 
    
	
Normalized   EBITDA(2)
    	
 
    	
223
    	
 
    	
213
    	
 
    	
190
    	
 
    	
166
    	
 
    	
228
    	
 
    	
194
    	
 
    	
176
    	
 
    	
153
    	
 
    
	
Net income   (loss) applicable to common shares
    	
 
    	
49
    	
 
    	
(11
    	
)
    	
18
    	
 
    	
(8
    	
)
    	
32
    	
 
    	
38
    	
 
    	
46
    	
 
    	
16
    	
 
    


 

	
($ per share)
    	
 
    	
Q1-18
    	
 
    	
Q4-17
    	
 
    	
Q3-17
    	
 
    	
Q2-17
    	
 
    	
Q1-17
    	
 
    	
Q4-16
    	
 
    	
Q3-16
    	
 
    	
Q2-16
    	
 
    
	
Net income   (loss) per common share
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    	
 
    
	
Basic
    	
 
    	
0.28
    	
 
    	
(0.06
    	
)
    	
0.10
    	
 
    	
(0.05
    	
)
    	
0.19
    	
 
    	
0.23
    	
 
    	
0.28
    	
 
    	
0.10
    	
 
    
	
Diluted
    	
 
    	
0.28
    	
 
    	
(0.06
    	
)
    	
0.10
    	
 
    	
(0.05
    	
)
    	
0.19
    	
 
    	
0.23
    	
 
    	
0.28
    	
 
    	
0.10
    	
 
    
	
Dividends   declared
    	
 
    	
0.55
    	
 
    	
0.54
    	
 
    	
0.53
    	
 
    	
0.53
    	
 
    	
0.53
    	
 
    	
0.53
    	
 
    	
0.52
    	
 
    	
0.50
    	
 
    


 




(1)         Amounts may not add due to rounding.

(2)         Non-GAAP financial measure. See discussion in the “Non-GAAP Financial Measures” section of this MD&A.

 

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

 

Revenue for the Utilities is generally the highest in the first and fourth quarters of any given year as the majority of natural gas demand occurs during the winter heating season, which typically extends from November to March. The run-of-river hydroelectric facilities in British Columbia are also impacted by seasonal precipitation and snowpack melt, which create periods of high flow during the spring and summer months.

 

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

 

·                                          The weak NGL commodity prices throughout 2016;

·                                          The weak Alberta power pool prices throughout 2016;

·                                          The stronger U.S. dollar throughout 2016 and the weaker U.S. dollar in the second half of 2017 and the first quarter of 2018 on translated results of the U.S. assets;

·                                          The seasonally colder weather experienced at several of the Utilities in the fourth quarter of 2017 and the first quarter of 2018;

·                                          The commencement of commercial operations early in the third quarter of 2016 at the integrated midstream complex at Townsend in northeast British Columbia, including the Townsend Facility, gas gathering line, NGL egress pipelines and truck terminal;

·                                          The recovery of $7 million of development costs related to the PNG Pipeline Looping Project in the third quarter of 2016;

·                                          The commissioning of the Pomona Energy Storage Facility on December 31, 2016;

·                                          The closing of the sale of the EDS and the JFP transmission assets to Nova Chemicals in March of 2017;

·                                          The commencement of commercial operations on October 1, 2017 at Townsend 2A;

·                                          The commencement of commercial operations at the first train of the North Pine Facility on December 1, 2017; and

·                                          Unrealized losses on risk management contracts recorded in 2017 and the first quarter of 2018 related to the foreign currency option contracts entered into to mitigate the foreign exchange risks associated with the cash purchase price of WGL.

 

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Net income (loss) applicable to common shares is also affected by non-cash items such as deferred income tax, depreciation and amortization expense, accretion expense, provision on assets, gains or losses on investments, and gains or losses on the sale of assets. In addition, net income (loss) applicable to common shares is also impacted by preferred share dividends. For these reasons, the net income (loss) may not necessarily reflect the same trends as revenue. Net income (loss) applicable to common shares during the periods noted was impacted by:

 

·                                          Higher depreciation and amortization expense due to new assets placed into service;

·                                          Higher interest expense since the first quarter of 2017 mainly due to higher financing costs associated with the bridge facility;

·                                          After-tax restructuring charges of $5 million related to the non-utility workforce restructuring in the second quarter of 2016;

·                                          The unrealized loss of approximately $8 million recognized upon ceasing to account for the Tidewater investment using the equity method in the second quarter of 2017;

·                                          After-tax provisions totaling $84 million recognized in the fourth quarter of 2017 related to the Hanford and Henrietta gas-fired peaking facilities, a non-core gas processing facility in Alberta, and a non-core development stage peaking project in California;

·                                          Impact of the U.S. tax reform resulting in a decrease in tax expense of approximately $34 million in the fourth quarter of 2017; and

·                                          After-tax transaction costs incurred throughout 2017 (totaling $53 million) and in the first quarter of 2018 ($9 million) predominantly due to the pending WGL Acquisition.

 

25











 

Other Information

 

DEFINITIONS

 

	
Bbls/d
    	
 
    	
barrels per day
    
	
Bcf
    	
 
    	
billion cubic feet
    
	
GJ
    	
 
    	
gigajoule
    
	
GWh
    	
 
    	
gigawatt-hour
    
	
Mcf
    	
 
    	
thousand cubic feet
    
	
Mmcf/d
    	
 
    	
million cubic feet per day
    
	
MW
    	
 
    	
megawatt
    
	
MWh
    	
 
    	
megawatt-hour
    
	
MMBTU
    	
 
    	
million British thermal unit
    
	
PJ
    	
 
    	
petajoule
    
	
US$
    	
 
    	
United States dollar
    


 

ABOUT ALTAGAS

 

AltaGas is an energy infrastructure company with a focus on 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

 

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