Exhibit

EX-1.1 2 q32019mdaandfs.htm EXHIBIT 1.1 Exhibit

MANAGEMENT'S DISCUSSION AND ANALYSIS

This Management's Discussion and Analysis (MD&A) dated October 29, 2019 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 and nine months ended September 30, 2019. 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 and nine months ended September 30, 2019 and the audited Consolidated Financial Statements and MD&A as at and for the year ended December 31, 2018.

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

Abbreviations, acronyms and capitalized terms used in this MD&A without express definition shall have the same meanings given to those terms in the MD&A as at and for the year ended December 31, 2018 or the Annual Information Form for the year ended December 31, 2018.

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: anticipated closing dates, conditions to closing and EBITDA impact of pending asset dispositions; anticipated timing for a final decision in Washington Gas' Virginia rate case; increase in normalized EBITDA for the fourth quarter of 2019 resulting from the PSC of MD order; expected terms and approval date for Blythe tolling agreement; expected conditions to closing and closing date for ACI arrangement; expected normalized EBITDA of approximately $1.2 to $1.3 billion and expected normalized funds from operations of approximately $850 to $950 million for the full year 2019; growth levels and drivers expected in the three business segments; expectation that Utilities will have the largest contribution to EBITDA, followed by Midstream and Power; exposure to frac spreads prior to hedging activities; exposure to propane price differential; anticipated tolling arrangements; anticipated effect of commodity prices, exchange rates, and weather on 2019 normalized EBITDA; expected net invested capital expenditures; anticipated segment allocation of capital expenditures in 2019; expected funding sources for 2019 capital expenditure program; estimated costs of growth capital projects; expected program, construction, and in-service dates for growth projects; anticipated timing of applications, hearings and decisions of rate cases before Utilities regulators; expected funding sources for working capital deficiency; dividend payments; future changes in accounting policies and adoption of new accounting standards; and AltaGas’ long term strategy. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results, events and achievements to differ materially from those expressed or implied by such statements. Such statements reflect AltaGas’ current expectations, estimates, and projections based on certain material factors and assumptions at the time the statement was made. Material assumptions include: assumptions regarding asset sales anticipated to close in 2019, the U.S/Canadian dollar exchange rate, financing initiatives, the performance of the businesses underlying each sector; impacts of the hedging program; commodity prices; weather; frac spread; access to capital; timing and receipt of regulatory approvals; timing of regulatory approvals related to Utilities projects; seasonality; planned and unplanned plant outages; timing of in-service dates of new projects and acquisition and divestiture activities; taxes; operational expenses; returns on investments; dividend levels; and transaction costs.

AltaGas’ forward-looking statements are subject to certain risks and uncertainties which could cause results or events to differ from current expectations, including, without limitation: capital market and liquidity risks; general economic conditions; consumption risk; market risk; internal credit risk; foreign exchange risk; debt service risk; financing and refinancing risk; market value of common shares and other securities; variability of dividends; commitments associated with the regulatory approval of the WGL

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 1

Acquisition; integration of WGL; growth strategy risk; potential sale of additional shares; volume throughput; counterparty credit risk; dependence on certain partners; natural gas supply risk; operating risk; changes in laws; risk management costs and limitations; regulatory; climate change and carbon tax; construction and development; RIPET rail and marine transportation; litigation; infrastructure; cybersecurity, information and control systems risk; external stakeholder relations; composition risk; electricity and resource adequacy prices; interest rates; collateral; indigenous land and rights claims; duty to consult; underinsured and uninsured losses; weather data; service interruptions; rep agreements; Cook Inlet gas supply; health and safety; non-controlling interests in investments; decommissioning, abandonment and reclamation costs; cost of providing retirement plan benefits; labour relations; key personnel; failure of service providers; technical systems and processes incidents; securities class action suits and derivative suits; return on investments in renewable energy projects; competition; compliance with applicable law; and the other factors discussed under the heading "Risk Factors" in the Corporation’s Annual Information Form for the year ended December 31, 2018 (AIF) and set out in AltaGas’ other continuous disclosure documents.

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

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

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

AltaGas Organization

The businesses of AltaGas are operated by AltaGas and a number of its subsidiaries including, without limitation, AltaGas Services (U.S.) Inc., AltaGas Utility Holdings (U.S.) Inc., WGL Holdings, Inc. (WGL), Wrangler 1 LLC, Wrangler SPE LLC, Washington Gas Resources Corporation, WGL Energy Services, Inc. (WGL Energy Services), and SEMCO Holding Corporation; in regards to the Midstream business, AltaGas Extraction and Transmission Limited Partnership, AltaGas Pipeline Partnership, AltaGas Processing Partnership, AltaGas Northwest Processing Limited Partnership, Harmattan Gas Processing Limited Partnership, Ridley Island LPG Export Limited Partnership, and WGL Midstream Inc. (WGL Midstream); in regards to the Power business, AltaGas Power Holdings (U.S.) Inc., WGL Energy Systems, Inc. (WGL Energy Systems), and Blythe Energy Inc. (Blythe); and, in regards to the Utilities business, Washington Gas Light Company (Washington Gas), Hampshire Gas Company, and SEMCO Energy, Inc. (SEMCO). SEMCO conducts its Michigan natural gas distribution business under the name SEMCO Energy Gas Company (SEMCO Gas), its Alaska natural gas distribution business under the name ENSTAR Natural Gas Company (ENSTAR) and its 65 percent interest in an Alaska regulated gas storage utility under the name Cook Inlet Natural Gas Storage Alaska LLC (CINGSA).

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Third Quarter Highlights

(Normalized EBITDA, normalized funds from operations, normalized net income (loss), 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.)

▪

On September 26, 2019, AltaGas closed the sale of its portfolio of U.S. distributed generation assets held by its subsidiaries WGL Energy Systems, Inc. and WGSW, Inc., to TerraForm Power, Inc., an affiliate of Brookfield Asset Management. Total cash proceeds received were approximately US$735 million and a pre-tax gain on disposition of $100 million was recorded in the third quarter of 2019. There are certain projects for which legal title has not yet transferred as various consents and approvals remain outstanding. These projects remain held for sale at September 30, 2019;

▪

On September 30, 2019, AltaGas announced that it has entered into a definitive agreement for the sale of its indirect, non-operating interest in the Central Penn Pipeline (Central Penn) held by its subsidiary WGL Midstream, Inc. to Meade Pipeline Investment, LLC, a subsidiary of NextEra Energy Partners, LP. Total gross proceeds for WGL Midstream's interest is expected to be approximately US$657 million. The transaction is expected to close in the fourth quarter of 2019 and is subject to customary closing conditions and regulatory approvals. The estimated annual decrease in EBITDA resulting from the disposition of Central Penn is approximately $40 to $50 million. A pre-tax provision on equity investments of $44 million was recorded in the third quarter of 2019 relating to this pending sale;

▪

In September 2019, the Virginia Hearing Examiner assigned to Washington Gas' Virginia rate case issued a report with findings and recommendations to the State Corporation Commission of Virginia (SCC of VA), including the finding for no incremental revenues. In the third quarter of 2019, the impact of these recommendations was recorded, resulting in a one-time reduction in normalized EBITDA of approximately $30 million. The impact on net income after taxes in the third quarter of 2019 was a reduction of approximately $14 million due to certain offsetting amounts included in deferred income taxes. On October 21, 2019, Washington Gas filed comments on and exceptions to the Hearing Examiner's report, recommending the SCC of VA reject certain of the Hearing Examiner's findings. A final decision is expected late in the fourth quarter of 2019 or early in the first quarter of 2020;


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


▪	Normalized EBITDA was $178 million compared to $226 million in the third quarter of 2018;


▪	Cash used by operations was $30 million ($0.11 per share) compared to cash used by operations of $355 million ($1.36 per share) in the third quarter of 2018;


▪	Normalized funds from operations were $67 million ($0.24 per share) compared to $117 million ($0.45 per share) in the third quarter of 2018;


▪	Net income applicable to common shares was $22 million ($0.08 per share) compared to net loss applicable to common shares of $726 million ($2.78 per share) in the third quarter of 2018;


▪	Normalized net loss was $58 million ($0.21 per share) compared to normalized net loss of $17 million ($0.07 per share) in the third quarter of 2018;


▪	Net debt was $7.7 billion as at September 30, 2019, compared to $10.1 billion at December 31, 2018; and


▪	Net debt-to-total capitalization ratio was 50 percent as at September 30, 2019, compared to 57 percent as at December 31, 2018.

Highlights Subsequent to Quarter End


▪	On October 15, 2019, the Maryland Public Service Commission (PSC of MD) issued a final order approving Washington Gas' settlement agreement in their recent rate case, reflecting a US$27 million base rate increase effective October 15, 2019. The increase in AltaGas' normalized EBITDA resulting from this settlement agreement is expected to be approximately $11 million in the fourth quarter of 2019;


▪	In the Power segment, AltaGas announced the successful recontracting of the Blythe facility to Southern California Edison (SCE). Under the tolling agreement, SCE has exclusive rights to all capacity, energy, ancillary services, and

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 3

resource adequacy benefits from August 1, 2020 to December 31, 2023. California Public Utilities Commission approval is required and is expected to occur in the first half of 2020; and

▪

On October 21, 2019, AltaGas Canada Inc. (ACI) announced that the Public Sector Pension Investment Board and the Alberta Teachers' Retirement Fund Board (together, the "Consortium") and ACI have concluded a definitive arrangement agreement (the "Arrangement Agreement") whereby the Consortium will indirectly acquire all of the issued and outstanding common shares of ACI (the "Common Shares") in an all-cash transaction for $33.50 per Common Share (the "Arrangement"). The Arrangement will be subject to customary closing conditions including, approval by 66 2/3 percent of the Common Shares voted in person or by proxy at a special meeting of holders of Common Shares to be called to approve the Arrangement. In addition to shareholder approval, closing of the Arrangement is also subject to the approval by the Court of Queen's Bench of Alberta and to certain regulatory approvals, including approval under the Competition Act (Canada), approval from the Alberta Utilities Commission and approval from the British Columbia Utilities Commission. ACI and the Consortium expect to close the Arrangement in the first half of 2020. AltaGas owns 11,025,000 Common Shares or approximately 37 percent of the total number of Common Shares.

Consolidated Financial Review



	Three Months Ended September 30				Nine Months Ended September 30
($ millions)	2019		2018		2019		2018
Revenue	888		1,041		3,960		2,530
Normalized EBITDA ⁽¹⁾	178		226		847		615
Net income (loss) applicable to common shares	22		(726	)	872		(676	)
Normalized net income (loss) ⁽¹⁾	(58	)	(17	)	138		76
Total assets	20,687		22,958		20,687		22,958
Total long-term liabilities	9,358		11,319		9,358		11,319
Net additions (dispositions) of property, plant and equipment	(501	)	367		(1,330	)	556
Dividends declared ⁽²⁾	66		162		199		357
Cash from (used by) operations	(30	)	(355	)	600		(18	)
Normalized funds from operations ⁽¹⁾	67		117		564		407
Normalized adjusted funds from operations ⁽¹⁾	59		121		529		374
Normalized utility adjusted funds from (used by) operations ⁽¹⁾	(3	)	59		333		271



	Three Months Ended September 30				Nine Months Ended September 30
($ per share, except shares outstanding)	2019		2018		2019	2018
Net income (loss) per common share - basic	0.08		(2.78	)	3.16	(3.28	)
Net income (loss) per common share - diluted	0.08		(2.78	)	3.15	(3.28	)
Normalized net income (loss) - basic ⁽¹⁾	(0.21	)	(0.07	)	0.50	0.37
Normalized net income (loss) - diluted ⁽¹⁾	(0.21	)	(0.07	)	0.50	0.37
Dividends declared ⁽²⁾	0.24		0.55		0.72	1.64
Cash from (used by) operations	(0.11	)	(1.36	)	2.17	(0.09	)
Normalized funds from operations ⁽¹⁾	0.24		0.45		2.04	1.98
Normalized adjusted funds from operations ⁽¹⁾	0.21		0.46		1.92	1.82
Normalized utility adjusted funds from (used by) operations ⁽¹⁾	(0.01	)	0.23		1.21	1.32
Shares outstanding - basic (millions)
During the period ⁽³⁾	277		261		276	206
End of period	278		269		278	269


(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: $0.1825 beginning on November 27, 2017, and $0.08 beginning on December 27, 2018.


(3)	Weighted average.

Three Months Ended September 30

Normalized EBITDA for the third quarter of 2019 was $178 million, compared to $226 million for the same quarter in 2018. Factors negatively impacting normalized EBITDA included the impact of asset sales, including the sale of the Northwest Hydro Electric facilities (Northwest Hydro) in January 2019, the impact of the sale of the San Joaquin facilities in the fourth quarter of 2018, the

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impact of the initial public offering (IPO) of ACI in October 2018, the impact of the sale of WGL Midstream's interest in the Stonewall Gathering System (Stonewall) in May 2019, and the impact of the sale of non-core Midstream and Power assets in February 2019. In addition, normalized EBITDA decreased due to impacts related to a Hearing Examiner's report on Washington Gas' Virginia rate case (see Utilities section of this MD&A for additional details), and higher corporate employee costs primarily due to incentive plans. These were partially offset by contributions from RIPET, higher volumes and margins from WGL's retail power business, contributions from Central Penn which was placed into service in October 2018, higher equity earnings from Petrogas, higher Allowance for Funds Used During Construction (AFUDC) recognized for the Mountain Valley Pipeline, and higher Midstream NGL marketing revenues. For the three months ended September 30, 2019, the average Canadian/U.S. dollar exchange rate increased to 1.32 from an average of 1.31 in the same quarter of 2018, resulting in an increase in normalized EBITDA of approximately $1 million.

Normalized funds from operations for the third quarter of 2019 were $67 million ($0.24 per share), compared to $117 million ($0.45 per share) for the same quarter in 2018. The decrease was mainly due to the same factors impacting normalized EBITDA, partially offset by lower interest expense. In the third quarter of 2019, AltaGas received $3 million of dividend income from the Petrogas Preferred Shares (2018 - $3 million) and $1 million of common share dividends from Petrogas (2018 - $1 million).

Normalized adjusted funds from operations (AFFO) for the third quarter of 2019 were $59 million ($0.21 per share), compared to $121 million ($0.46 per share) for the same quarter in 2018. Factors impacting AFFO in the third quarter of 2019 included the same drivers as normalized funds from operations and lower cash received from non-controlling interests. In the third quarter of 2019, AltaGas paid $17 million of preferred share dividends (2018 - $17 million).

Normalized utility adjusted funds used by operations (UAFFO) for the third quarter of 2019 were $3 million ($0.01 per share), compared to normalized utility adjusted funds from operations of $59 million ($0.23 per share) for the same quarter in 2018. The decrease was due to the same drivers impacting normalized AFFO.

In the third quarter of 2019, AltaGas recorded a pre-tax provision on equity investments of approximately $44 million ($33 million after-tax) related to the pending disposition of Central Penn. In the third quarter of 2018, AltaGas recorded pre-tax provisions of approximately $698 million (after-tax $539 million) primarily related to assets that were classified as held for sale, including gas-fired peaking plants in California, non-core Midstream and Power assets in Canada, and certain assets included in the 2018 IPO of ACI.

Operating and administrative expenses for the third quarter of 2019 were $300 million, compared to $496 million for the same quarter in 2018. The decrease was mainly due to the absence of merger commitment costs recorded in the third quarter of 2018, lower transaction costs on acquisitions and dispositions, the impact of the IPO of ACI in October 2018, the impact of the sale of the San Joaquin facilities in the fourth quarter of 2018, and the impact of the sale of non-core Midstream and Power assets in February 2019, partially offset by the impact of RIPET coming online in May 2019. Depreciation and amortization expense for the third quarter of 2019 was $104 million, compared to $122 million for the same quarter in 2018. The decrease was mainly due to the impact of asset sales completed in late 2018 and the first nine months of 2019, partially offset by new assets placed into service. Interest expense for the third quarter of 2019 was $92 million, compared to $112 million for the same quarter in 2018. The decrease was predominantly due to lower average debt balances as a result of debt reduction from proceeds on asset sales.

AltaGas recorded an income tax recovery of $35 million for the third quarter of 2019 compared to a recovery of $221 million in the same quarter of 2018. The decrease in tax recovery was mainly due to tax recoveries booked on asset provisions and transaction costs in the third quarter of 2018, partially offset by a tax recovery on the sale of WGL's distributed generation assets in the third quarter of 2019. Current tax expense of $9 million was recorded in the third quarter of 2019, of which approximately $3 million related to tax on asset sales.

Net income applicable to common shares for the third quarter of 2019 was $22 million ($0.08 per share), compared to net loss of $726 million ($2.78 per share) for the same quarter in 2018. The decreased loss was mainly due to lower provisions on assets,

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the absence of merger commitment expenses recorded in the third quarter of 2018, gains on the sale of WGL's distributed generation assets, lower interest expense, and lower depreciation and amortization expense, partially offset by the same previously referenced factors impacting normalized EBITDA, lower income tax recovery, and higher unrealized losses on risk management contracts.

Normalized net loss was $58 million ($0.21 per share) for the third quarter of 2019, compared to normalized net loss of $17 million ($0.07 per share) reported for the same quarter in 2018. Factors negatively impacting normalized net loss included lower income tax recovery and the same previously referenced factors impacting normalized EBITDA, partially offset by lower interest expense and lower depreciation and amortization expense. Normalizing items in the third quarter of 2019 increased normalized net loss by $80 million and included after‑tax amounts related to gains on sale of assets, changes in fair value of natural gas optimization inventory, transaction costs related to acquisitions and dispositions, unrealized losses on risk management contracts, losses on investments, and provisions on investments accounted for by the equity method. Normalizing items in the third quarter of 2018 decreased normalized net loss by $709 million and included after‑tax amounts related to provisions on assets, merger commitment costs and transaction costs associated with the WGL Acquisition, gains on investments, unrealized losses on risk management contracts, realized gains on foreign exchange derivatives, change in fair value of natural gas optimization inventory, and financing costs associated with the bridge facility. Please refer to the Non-GAAP Financial Measures section of this MD&A for further details on normalization adjustments.

Nine Months Ended September 30

Normalized EBITDA for the first nine months of 2019 was $847 million, compared to $615 million for the same period in 2018. Factors positively impacting normalized EBITDA included contributions from WGL for the first half of the year, contributions from RIPET which was placed into service in May 2019, higher equity earnings from Petrogas, higher volumes and margins from WGL's retail power business, equity earnings from ACI, contributions from the Aitken Creek facilities, contributions from Central Penn which was placed into service in October 2018, higher AFUDC related to the Mountain Valley Pipeline, and the stronger U.S. dollar on reported results from U.S. assets. These were partially offset by the impact of asset sales, including the sale of the San Joaquin facilities in the fourth quarter of 2018, the impact of the IPO of ACI in October 2018, the impact of the sale of the Northwest Hydro facilities in January 2019, and the impact of the sale of non-core Midstream and Power assets in February 2019, as well as impacts relating to a Hearing Examiner's report on Washington Gas' Virginia rate case, higher corporate employee costs primarily due to incentive plans, and the extended planned outage at the Blythe facility. For the first nine months of 2019, the average Canadian/U.S. dollar exchange rate increased to 1.33 from an average of 1.29 in the same period of 2018, resulting in an increase in normalized EBITDA of approximately $8 million.

Normalized funds from operations for the first nine months of 2019 were $564 million ($2.04 per share), compared to $407 million ($1.98 per share) for the same period in 2018. The increase was mainly due to the same drivers as normalized EBITDA and lower current tax expense, partially offset by higher interest expense. In the first nine months of 2019, AltaGas received $10 million of dividend income from the Petrogas Preferred Shares (2018 - $9 million) and $4 million of common share dividends from Petrogas (2018 - $4 million).

Normalized adjusted funds from operations for the first nine months of 2019 were $529 million ($1.92 per share), compared to $374 million ($1.82 per share) for the same period in 2018. The increase was mainly due to the same drivers as normalized funds from operations and lower maintenance capital, partially offset by lower cash received from non-controlling interests. In the first nine months of 2019, AltaGas paid $51 million of preferred share dividends (2018 - $50 million).

Normalized utility adjusted funds from operations for the first nine months of 2019 were $333 million ($1.21 per share), compared to $271 million ($1.32 per share) for the same period in 2018. The increase was due to the same drivers as normalized adjusted funds from operations partially offset by higher utilities depreciation. The decrease in the per share amount is due to a higher number of shares outstanding during the first nine months of 2019 compared to the first nine months of 2018.

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In the first nine months of 2019, AltaGas recorded a pre-tax provision of approximately $1 million on a capital spare held in storage, a pre-tax provision on equity investments of approximately $44 million related to the pending disposition of Central Penn, and a pre-tax provision of $2 million on equity investments related to biomass investments which were sold in the third quarter of 2019. In the first nine months of 2018, AltaGas recorded pre-tax provisions of approximately $698 million (after-tax $539 million) primarily related to assets that were classified as held for sale, including gas-fired peaking plants in California, non-core Midstream and Power assets in Canada, and certain assets included in the IPO of ACI.

Operating and administrative expenses for the first nine months of 2019 were $958 million, compared to $783 million for the same period in 2018. The increase was mainly due to the addition of WGL’s operating and administrative expenses for the first six months of the year and the impact of RIPET coming into service in May 2019, partially offset by the absence of merger commitment costs recorded in the third quarter of 2018 and the impact of asset sales completed in late 2018 and the first nine months of 2019. Depreciation and amortization expense for the first nine months of 2019 was $329 million, compared to $268 million for the same period in 2018. The increase was mainly due to depreciation and amortization expense on WGL assets for the first six months of the year and new assets placed into service, partially offset by the impact of asset sales completed in late 2018 and the first nine months of 2019. Interest expense for the first nine months of 2019 was $269 million, compared to $198 million for the same period in 2018. The increase was predominantly due to interest on debt assumed in the WGL Acquisition for the first half of the year, partially offset by lower average debt balances in the third quarter of 2019 as a result of proceeds on asset sales.

AltaGas recorded income tax expense of $59 million for the first nine months of 2019 compared to income tax recovery of $200 million in the same period of 2018. The increase in tax expense was mainly due to tax expense incurred on the sale of the remaining interest in the Northwest Hydro facilities and tax on WGL’s earnings. These tax expenses were partially offset by a tax recovery on the sale of WGL's distributed generation assets and a tax recovery due to a one-time unitary tax rate adjustment related to the WGL Acquisition and a tax rate adjustment related to the Alberta Job Creation Tax Cut. Current tax expense of approximately $23 million was recorded in the first nine months of 2019, of which approximately $3 million related to tax on asset sales.

Net income applicable to common shares for the first nine months of 2019 was $872 million ($3.16 per share), compared to net loss of $676 million ($3.28 per share) for the same period in 2018. The increase was mainly due to gains on asset sales, lower provisions on assets in the third quarter of 2019 compared to the third quarter of 2018, the absence of merger commitment costs recorded in the third quarter of 2018, and the same previously referenced factors impacting normalized EBITDA, partly offset by higher income tax expense, higher interest expense, provisions on equity investments, higher depreciation and amortization expense, and higher unrealized losses on risk management contracts.

Normalized net income was $138 million ($0.50 per share) for the first nine months of 2019, compared to normalized net income of $76 million ($0.37 per share) reported for the same period in 2018. The increase was mainly due to the same previously referenced factors impacting normalized EBITDA, partially offset by higher income tax expense, higher interest expense, and higher depreciation and amortization expense. Normalizing items in the first nine months of 2019 reduced normalized net income by $734 million and included after‑tax amounts related to gains on sale of assets, changes in fair value of natural gas optimization inventory, merger commitment cost recovery due to a change in timing related to certain WGL merger commitments, transaction costs related to acquisitions and dispositions, unrealized losses on risk management contracts, losses on investments, provisions on assets, provisions on investments accounted for by the equity method, and the impact of a statutory tax rate change in Alberta. Normalizing items in the first nine months of 2018 increased normalized net income by $752 million and included after‑tax amounts related to provisions on assets, merger commitment costs and transaction costs associated with the WGL Acquisition, realized losses on foreign exchange derivatives, unrealized gains on risk management contracts, gains on investments, change in fair value of natural gas optimization inventory, gains on sale of assets, and financing costs associated with the bridge facility. Please refer to the Non-GAAP Financial Measures section of this MD&A for further details on normalization adjustments.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 7

2019 Outlook

With 2019 being the first full year of operations including WGL, AltaGas expects to achieve annual consolidated normalized EBITDA of approximately $1.2 to $1.3 billion, and normalized funds from operations of approximately $850 to $950 million. This range is net of asset sales which have closed or are anticipated to close in 2019, including the remaining 55 percent interest in the Northwest Hydro facilities which closed in January 2019, the interest in Stonewall which closed in May 2019, WGL's distributed generation portfolio which closed in September 2019, and the pending sale of WGL Midstream's indirect, non-operating interest in Central Penn. To date this year, AltaGas has announced or completed approximately $2.2 billion in asset sales, which exceeds the top end of the previously announced $1.5 to $2.0 billion asset sales program targeted for 2019.

Growth is expected in 2019 in the Utilities and Midstream segments, and in the Power segment excluding the impact of asset sales. The Utilities segment is expected to have the largest contribution to EBITDA, followed by the Midstream and Power segments. The overall forecasted normalized EBITDA and funds from operations include assumptions around remaining asset sales anticipated to close in 2019, the U.S./Canadian dollar exchange rate, and other financing initiatives. Within each segment, the performance of the underlying businesses has the potential to vary. Any variance from AltaGas’ current assumptions could impact the forecasted normalized EBITDA and funds from operations.

AltaGas estimates an average of approximately 10,000 Bbls/d of NGL will be exposed to frac spreads prior to hedging activities. For 2019, AltaGas has frac hedges in place for approximately 6,200 Bbls/d at an average price of approximately $40/Bbl excluding basis differentials.

At RIPET, AltaGas is exposed to the propane price differential between North American Indices and the Far East Index for contracts not under tolling arrangements. AltaGas estimates an average of approximately 30,000 Bbls/d will be exposed to these price differentials over the last quarter of 2019. AltaGas has hedges in place for approximately 80 percent of these exposed propane volumes at an average FEI to Mont Belvieu spread of US$10/Bbl. To date, AltaGas has entered into hedges of approximately 20,000 Bbls/d for 2020, at an average FEI to Mont Belvieu spread of US$10/Bbl. AltaGas plans to manage the facility such that a majority of annual capacity will be underpinned by tolling arrangements, and expects to reach this objective over the next several years.

Sensitivity Analysis

AltaGas’ financial performance is affected by factors such as changes in commodity prices, exchange rates, and weather. The following table illustrates the approximate effect of these key variables on AltaGas’ expected normalized EBITDA for 2019:




Factor	Increase or decrease	Approximate impact on normalized annual EBITDA ($ millions)
Natural gas liquids fractionation spread ⁽¹⁾	$1/Bbl	1
Degree day variance from normal - Utilities ⁽²⁾	5 percent	7
Change in CAD per US$ exchange rate	0.05	35
FG&P and extraction inlet volumes	10 percent	11
RIPET Propane Far East Index to Mont Belvieu spread ⁽³⁾	US$0.02/gal	3


(1)	Based on approximately 60 percent of frac spread exposed NGL volumes being hedged.

(2)

Degree days – Utilities relate to SEMCO Gas, ENSTAR, and Washington Gas service areas. Degree days are a measure of coldness determined daily as the numbers of degrees the average temperature during the day in question is below 65 degrees Fahrenheit. Degree days for a particular period are the average of degree days during the prior 15 years for SEMCO Gas, during the prior 10 years for ENSTAR, and during the prior 30 years for Washington Gas.


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

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 8

Growth Capital

Based on projects currently under review, development or construction, AltaGas expects net invested capital expenditures of approximately $1.3 billion to $1.36 billion in 2019, excluding disposals, utility asset removal costs, and certain contributions to equity investments. The increase in expected net invested capital compared to the estimated $1.3 billion previously disclosed is primarily due to the timing of close of certain asset sales. The focused and strategic approach to capital expenditures in 2019 will target projects that provide ongoing growth potential, favorable risk profiles, and the strongest risk-adjusted returns with immediate payback, as AltaGas continues to strengthen its balance sheet. The Utilities segment is expected to account for approximately 60 to 65 percent of total capital expenditures, while the Midstream segment is expected to account for approximately 35 to 40 percent and the Power segment is expected to account for any remainder. Midstream and Power maintenance capital is expected to be approximately $30 to $40 million of the total capital expenditures in 2019. AltaGas’ capital expenditures for the Utilities segment will focus on accelerated pipe replacement programs in Virginia, Maryland, the District of Columbia and Michigan, new customer additions, and the construction of the Marquette Connector Pipeline. In the Midstream segment, capital expenditures are anticipated to primarily relate to the completion of RIPET, the Townsend expansion, the Aitken Creek integrated development project, the second train of North Pine, and WGL’s investment in the Mountain Valley gas pipeline development. The Power segment continues to pursue a capital-light strategy. The Corporation continues to focus on enhancing productivity and streamlining businesses.

AltaGas' 2019 committed capital program is expected to be funded through internally-generated cash flow, asset sales, the Dividend Reinvestment and Optional Cash Purchase Plan (DRIP), and normal course borrowings on existing committed credit facilities.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 9

Growth Capital Project Updates

The following table summarizes the status of AltaGas’ significant growth projects. A full description of growth capital projects is provided in the MD&A for the year ended December 31, 2018.




Project	AltaGas' Ownership Interest			Estimated Cost ⁽¹⁾	Expenditures to Date ⁽²⁾		Status	Expected In-Service Date
Midstream Projects
Nig Creek Plant		50%	$100 million		$100 million	Construction of Nig Creek, the second plant in the Aitken Creek development, was completed ahead of schedule and placed into service in the third quarter of 2019.		Completed in Q3 2019
Northeast B.C. Pipeline Projects		33% to 100%	$75 million		$36 million	The Northeast B.C. Pipeline projects consist of four pipelines; the Inga gas gathering pipeline (33% ownership), the Townsend East natural gas liquids (NGL) pipeline (100% ownership), the Aitken Connector NGL pipeline (100% ownership), and the Gundy lateral pipeline (100% ownership). Regulatory approvals have been received and construction of all segments is underway. The Nig Creek facility (Aitken GP2A) was placed into service in the third quarter of 2019. The Aitken Connector and the Gundy lateral are expected to be in-service during the fourth quarter of 2019. The Inga gas gathering pipeline and the Townsend East NGL pipeline are expected to be in-service in the first quarter of 2020.		Q4 2019 and Q1 2020
Townsend 2B Expansion and Mercaptan Treating		100%	$165 million		$109 million	Field construction activities commenced in the second quarter of 2019 and are progressing according to plan. The expected completion date is the first quarter of 2020.		Q1 2020
North Pine Expansion		100%	$58 million		$24 million	Field construction activities commenced in the third quarter of 2019. The expected completion date is the first quarter of 2020.		Q1 2020
Mountain Valley Pipeline		10%	US$352 million		US$352 million	Construction is underway. As at September 30, 2019, approximately 90 percent of the project is complete, which includes construction of all original interconnects and compressor stations. In the third quarter of 2019 there was a voluntary suspension of construction activities in a section of the pipeline and the Federal Energy Regulatory Commission (FERC) issued an order to suspend all construction. As a result, the in-service date is now expected to be late 2020. Despite the delays, AltaGas' exposure is contractually capped to the original estimated contributions of approximately US$352 million.		Late 2020 due to ongoing legal and regulatory challenges
MVP Southgate Project		5%	US$20 million		US$2 million	Construction is expected to begin in the second quarter of 2020. Expenditures to date relate to land surveys, land acquisition, and obtaining permits and regulatory approvals.		Late 2020

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 10



Project	AltaGas' Ownership Interest			Estimated Cost ⁽¹⁾	Expenditures to Date ⁽²⁾			Status	Expected In-Service Date
Utilities Projects
Accelerated Utility Pipe Replacement Programs – District of Columbia		100%	Estimated US$305 million over the five year period from April 2020 to December 2024, plus additional expenditures in subsequent periods.			$nil ⁽³⁾⁽⁴⁾	Washington Gas has submitted an application for the second phase of PROJECTpipes to the Public Service Commission of the District of Columbia (PSC of DC). In the interim, Phase 1 has been extended to March 31, 2020 for an amount not to exceed US$12.5 million.		Individual assets are placed into service throughout the program.
Accelerated Utility Pipe Replacement Programs – Maryland		100%	Estimated US$350 million over the five year period from January 2019 to December 2023, plus additional expenditures in subsequent periods.			US$38 million ⁽³⁾	The second phase of the accelerated utility pipe replacement programs in Maryland (STRIDE 2.0) began in January 2019.		Individual assets are placed into service throughout the program.
Accelerated Utility Pipe Replacement Programs – Virginia		100%	Estimated US$500 million over the five year period from January 2018 to December 2022, plus additional expenditures in subsequent periods.			US$146 million ⁽³⁾	The second phase of the accelerated pipe replacement programs in Virginia (SAVE 2.0) began in January 2018.		Individual assets are placed into service throughout the program.
Accelerated Mains Replacement Programs – Michigan		100%	Estimated US$50 million over five year period from 2015 to 2020.			US$36 million ⁽³⁾	The third phase of the Accelerated Mains Replacement Program (MRP3) in Michigan expires in May 2020. SEMCO’s May 2019 rate case included the request for a new five year plan beyond 2020, similar to the current spend of approximately US$10 million annually. The MPSC is required to rule in the case no later than March 31, 2020.		Individual assets are placed into service throughout the program.
Marquette Connector Pipeline (MCP)		100%	US$154 million			US$145 million	Construction is nearing completion. The 10" portion of the MCP is completely pressure tested, cleaned, and ready for service. The mainline portion of the 20" pipeline is complete and pressure tested. The interconnecting facilities will be completed in October and commissioning will begin. Final grading, cleanup, and seeding of the 20" right-of-way continues. Community engagement, interaction, and media coverage continue to be positive. The pipeline in-service date is scheduled for November 2019.		Late Q4 2019


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


(2)	Expenditures to date reflect total cumulative expenditures incurred from inception of the projects to September 30, 2019. For WGL projects, this also includes any expenditures prior to the close of the WGL Acquisition on July 6, 2018.


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


(4)	Program is expected to commence in April 2020.

With the pending sale of WGL Midstream's interest in Central Penn, the Central Penn expansion (Leidy South) is no longer included in AltaGas' growth capital projects.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 11

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 (loss), normalized funds from operations, normalized adjusted funds from operations, normalized utility adjusted funds from (used by) 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 September 30						Nine Months Ended September 30
($ millions)	2019			2018			2019			2018
Normalized EBITDA	$	178		$	226		$	847		$	615
Add (deduct):
Transaction costs related to acquisitions and dispositions	(3		)	(35		)	(16		)	(52		)
Merger commitment recovery (costs)	—			(182		)	5			(182		)
Unrealized gains (losses) on risk management contracts	(29		)	(9		)	(14		)	13
Changes in fair value of natural gas optimization inventory	9			3			12			3
Non-controlling interest related to HLBV investments	(1		)	(17		)	(8		)	(17		)
Realized losses on foreign exchange derivatives	—			—			—			(36		)
Gains (losses) on investments	(2		)	15			(5		)	—
Gain on sale of assets	99			—			819			1
Provisions on assets	—			(698		)	(1		)	(698		)
Provisions on investments accounted for by the equity method	(44		)	—			(46		)	—
Investment tax credits related to distributed generation assets	(2		)	(2		)	(7		)	(2		)
Accretion expenses	(1		)	(3		)	(4		)	(8		)
Foreign exchange gains	1			3			—			4
EBITDA	$	205		$	(699	)	$	1,582		$	(359	)
Add (deduct):
Depreciation and amortization	(104		)	(122		)	(329		)	(268		)
Interest expense	(92		)	(112		)	(269		)	(198		)
Income tax recovery (expense)	35			221			(59		)	200
Net income (loss) after taxes (GAAP financial measure)	$	44		$	(712	)	$	925		$	(625	)

EBITDA is a measure of AltaGas' operating profitability prior to how business activities are financed, assets are amortized, or earnings are taxed. EBITDA is calculated from the Consolidated Statements of Income (Loss) using net income (loss) adjusted for pre‑tax depreciation and amortization, interest expense, and income tax recovery (expense).

Normalized EBITDA includes additional adjustments for unrealized gains (losses) on risk management contracts, gains (losses) on investments, transaction costs related to acquisitions and dispositions, merger commitment cost recovery due to a change in timing related to certain WGL merger commitments, gains on the sale of assets, accretion expenses related to asset retirement obligations, realized losses on foreign exchange derivatives, provisions on assets, provisions on investments accounted for by the equity method, foreign exchange gains, distributed generation asset related investment tax credits, non-controlling interest of certain investments to which HLBV accounting is applied, and changes in fair value of natural gas optimization inventory.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 12

AltaGas presents normalized EBITDA as a supplemental measure. Normalized EBITDA is frequently used by analysts and investors in the evaluation of entities within the industry as it excludes items that can vary substantially between entities depending on the accounting policies chosen, the book value of assets, and the capital structure.

Normalized Net Income (Loss)




	Three Months Ended September 30						Nine Months Ended September 30
($ millions)	2019			2018			2019			2018
Normalized net income (loss)	$	(58	)	$	(17	)	$	138		$	76
Add (deduct) after-tax:
Transaction costs related to acquisitions and dispositions	(2		)	(26		)	(13		)	(41		)
Merger commitment (costs) recovery	—			(135		)	5			(135		)
Unrealized gains (losses) on risk management contracts	(22		)	(23		)	(10		)	3
Changes in fair value of natural gas optimization inventory	6			3			10			3
Realized gain (loss) on foreign exchange derivatives	—			1			—			(35		)
Gains (losses) on investments	(1		)	22			(4		)	9
Gain on sale of assets	132			—			771			1
Provisions on assets	—			(539		)	(1		)	(539		)
Provisions on investments accounted for by the equity method	(33		)	—			(35		)	—
Statutory tax rate change	—			—			11			—
Financing costs associated with the bridge facility	—			(12		)	—			(18		)
Net income (loss) applicable to common shares (GAAP financial measure)	$	22		$	(726	)	$	872		$	(676	)

Normalized net income (loss) represents net income (loss) 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 and dispositions, merger commitment cost recovery due to a change in timing related to certain WGL merger commitments, gains on the sale of assets, financing costs associated with the bridge facility for the WGL Acquisition, realized gain (loss) on foreign exchange derivatives, provisions on investments accounted for by the equity method, provisions on assets, statutory tax rate change, and changes in fair value of natural gas optimization inventory. This measure is presented in order to enhance the comparability of AltaGas’ earnings, as it reflects the underlying performance of AltaGas’ business activities.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 13

Normalized Funds from Operations, AFFO and UAFFO




	Three Months Ended September 30						Nine Months Ended September 30
($ millions)	2019			2018			2019			2018
Normalized utility adjusted funds from (used by) operations	$	(3	)	$	59		$	333		$	271
Add (deduct):
Utilities depreciation and amortization	62			62			196			103
Normalized adjusted funds from operations	$	59		$	121		$	529		$	374
Add (deduct):
Net cash received from non-controlling interests	(6		)	(26		)	(39		)	(45		)
Midstream and Power maintenance capital	(3		)	5			23			28
Preferred dividends paid	17			17			51			50
Normalized funds from operations	$	67		$	117		$	564		$	407
Add (deduct):
Transaction and financing costs related to acquisitions and dispositions	(3		)	(36		)	(16		)	(56		)
Merger commitment recovery (costs)	—			(182		)	5			(182		)
Funds from (used by) operations	$	64		$	(101	)	$	553		$	169
Add (deduct):
Net change in operating assets and liabilities	(98		)	(253		)	49			(185		)
Asset retirement obligations settled	4			(1		)	(2		)	(2		)
Cash from (used by) operations (GAAP financial measure)	$	(30	)	$	(355	)	$	600		$	(18	)

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

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

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

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 Capital Resources section of this MD&A.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 14

Supplemental Reconciliation

Reconciliation of Normalized EBITDA to Normalized Net Income (Loss)

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



	Three Months Ended September 30						Nine Months Ended September 30
($ millions)	2019			2018			2019			2018
Normalized EBITDA	$	178		$	226		$	847		$	615
Add (deduct):
Depreciation and amortization	(104		)	(122		)	(329		)	(268		)
Interest expense	(92		)	(112		)	(269		)	(198		)
Normalizing items impacting interest expense	—			17			—			25
Income tax recovery (expense)	35			221			(59		)	200
Normalizing items impacting income tax recovery (expense)	(53		)	(216		)	13			(225		)
Accretion expenses	(1		)	(3		)	(4		)	(8		)
Foreign exchange gains	1			3			—			4
Non-controlling interest related to HLBV investments	(1		)	(17		)	(8		)	(17		)
Net loss (income) applicable to non-controlling interests	(4		)	3			(2		)	(2		)
Preferred share dividends	(17		)	(17		)	(51		)	(50		)
Normalized net income (loss)	$	(58	)	$	(17	)	$	138		$	76

Results of Operations by Reporting Segment




Normalized EBITDA⁽¹⁾	Three Months Ended September 30					Nine Months Ended September 30
($ millions)	2019			2018		2019			2018
Utilities	$	(8	)	$	32	$	413		$	194
Midstream	127			65		330			184
Power	70			128		132			245
Sub-total: Operating Segments	$	189		$	225	$	875		$	623
Corporate	(11		)	1		(28		)	(8		)
	$	178		$	226	$	847		$	615


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




Revenue	Three Months Ended September 30						Nine Months Ended September 30
($ millions)	2019			2018			2019			2018
Utilities	$	265		$	314		$	1,789		$	948
Midstream	292			313			1,157			946
Power	338			443			1,048			759
Sub-total: Operating Segments	$	895		$	1,070		$	3,994		$	2,653
Corporate	—			(15		)	—			(30		)
Intersegment eliminations	(7		)	(14		)	(34		)	(93		)
	$	888		$	1,041		$	3,960		$	2,530

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 15

Utilities

Operating Statistics




	Three Months Ended September 30				Nine Months Ended September 30
	2019		2018		2019		2018
Natural gas deliveries - end-use (Bcf) ⁽¹⁾	11.1		10.9		161.4		53.9
Natural gas deliveries - transportation (Bcf) ⁽¹⁾	23.3		25.7		130.8		50.7
Service sites (thousands) ⁽²⁾	1,647		1,759		1,647		1,759
Degree day variance from normal - SEMCO Gas (%)⁽³⁾	(47.2	)	(17.8	)	5.4		4.6
Degree day variance from normal - ENSTAR (%)⁽³⁾	(42.8	)	(31.2	)	(15.7	)	(6.9	)
Degree day variance from normal - Washington Gas (%) ^{(3) (4)}	—		(4.1	)	(8.3	)	(4.1	)


(1)	Bcf is one billion cubic feet.


(2)	Service sites reflect all of the service sites of the utilities, including transportation and non‑regulated business lines. Service sites at September 30, 2018 also include service sites of the Canadian utilities, which were included in the ACI IPO in October 2018.

(3)

A degree day is a measure of coldness determined daily as the number of degrees the average temperature during the day in question is below 65 degrees Fahrenheit. Degree days for a particular period are determined by adding the degree days incurred during each day of the period. Normal degree days for a particular period are the average of degree days during the prior 15 years for SEMCO Gas, during the prior 10 years for ENSTAR, and during the prior 30 years for Washington Gas.

(4)

In certain of Washington Gas’ jurisdictions (Virginia and Maryland) there are billing mechanisms in place which are designed to eliminate the effects of variance in customer usage caused by weather and other factors such as conservation. In the District of Columbia, there is no weather normalization billing mechanism nor does Washington Gas hedge to offset the effects of weather. As a result, colder or warmer weather will result in variances to financial results.

During the third quarter of 2019, AltaGas’ Utilities segment experienced warmer weather at SEMCO and warmer weather at ENSTAR compared to the same quarter of 2018. The 2019 decrease in customers and transportation volumes is due to inclusion of the Canadian utilities in the ACI IPO in the fourth quarter of 2018, partially offset by growth in customer base.

During the first nine months of 2019, AltaGas' Utilities segment experienced colder weather at SEMCO and warmer weather at ENSTAR compared to the same period of 2018. Washington Gas experienced warmer than normal weather. The 2019 increase in customers and transportation represents the addition of Washington Gas natural gas deliveries for the period since July 2018.

Service sites at September 30, 2019 decreased by approximately 112 thousand sites compared to September 30, 2018 due to service sites relating to the Canadian utilities which were included in the ACI IPO in the fourth quarter of 2018, partially offset by growth in customer base.

Three Months Ended September 30

On July 31, 2018, Washington Gas filed an application with the SCC of VA to increase its base rates for natural gas service. In September 2019, the Virginia Hearing Examiner assigned to Washington Gas' Virginia rate case issued a report with findings and recommendations to the SCC of VA, including the finding for no incremental revenues. In the third quarter of 2019, the impact of these recommendations was recorded, resulting in a one-time reduction in normalized EBITDA of approximately $30 million. The impact on net income after taxes in the third quarter of 2019 was a reduction of approximately $14 million due to certain offsetting amounts included in deferred income taxes. The reduction in normalized EBITDA includes amounts related to a lower return on equity (ROE), a revised amortization period for returning excess deferred income taxes as a result of the Tax Cuts and Jobs Act (TCJA) combined with a one-time refund liability related to the effect of the TCJA in 2018, lower revenue from the Virginia SAVE program, and a one-time write-off of regulatory assets related to the utility distribution integrity management program (DIMP). On October 21, 2019, Washington Gas filed comments on and exceptions to the Hearing Examiner's report, recommending the SCC of VA reject certain of the Hearing Examiner's findings. A final decision is expected late in the fourth quarter of 2019 or early in the first quarter of 2020.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 16

The Utilities segment normalized EBITDA was a loss of $8 million in the third quarter of 2019, compared to normalized EBITDA of $32 million in the same quarter in 2018. The decrease in normalized EBITDA was mainly due to a one-time decrease in normalized EBITDA resulting from recommendations from a Hearing Examiner on the Virginia rate case, the impact of the ACI IPO in late 2018, lower rates and lower returns on equity at CINGSA due to a rate case decision in August, and higher operating expenses, partially offset by higher revenue from a full quarter of WGL ownership and the impact of the stronger U.S. dollar.

Nine Months Ended September 30

The Utilities segment reported normalized EBITDA of $413 million in the first nine months of 2019, compared to $194 million in the same period of 2018. The increase in normalized EBITDA was mainly due to the addition of WGL for the first half of the year, the favorable impact of the stronger U.S. dollar, growth in customer base, and colder weather in Michigan. The increase was partially offset by lower rates at Washington Gas due to impacts from the Virginia Hearing Examiner's recommendations, the impact of the ACI IPO in late 2018, higher operating expenses, lower rates and lower returns on equity at CINGSA due to the rate case decision in August, the 2019 revenue impact related to the federal tax reduction at the U.S. utilities, and warmer weather in Alaska.

Rate Case Updates



Utility/Jurisdiction	Date Filed	Request	Status	Expected Timing of Decision
Washington Gas - Maryland	May 2018	US$56 million increase in base rates, including US$15 million in annual surcharges currently paid by customers for system upgrades.	In December 2018, the PSC of MD approved a lower net amount of US$29 million (vs. US$56 million requested). Washington Gas requested a rehearing on two of the issues. In June 2019, the PSC of MD issued an order partially allowing for approximately US$0.5 million of overtime in its revenue adjustment and denied the other item.	Complete
Washington Gas - Maryland	April 2019	US$36 million increase in base rates, of which US$5 million relates to costs being collected through the monthly STRIDE surcharges for system upgrades.	A settlement agreement was filed for a US$27 million rate increase (vs. US$36 million applied for). Approval was received from the PSC of MD in October 2019.	Complete
Washington Gas - Virginia	July 2018	US$38 million increase in base rates, of which approximately US$15 million relates to costs being collected through the monthly SAVE surcharges for accelerated pipeline replacement.	Washington Gas' rebuttal in May 2019 reduced the rate increase to approximately US$33 million including approximately US$14 million of SAVE rider to be transferred to base rates. The SCC of VA Hearing Examiner's report was issued in September 2019. Washington Gas comments were provided on October 21, 2019 with final decision pending.	Late 2019 or early 2020
CINGSA - Alaska	April 2018	US$4 million reduction in rates, due to lower rate base, lower returns on equity and lower federal income tax.	A decision was received in August 2019. The decision included an ROE of 10.25% (compared to 11.875% requested) and 100% of Interruptible Storage Service revenues payable to customers (versus 50% requested). CINGSA filed a petition for partial reconsideration on September 3, 2019. The Commission denied the petition and CINGSA is exploring the possibility of an appeal to the Superior Court.	Complete
SEMCO - Michigan	May 2019	US$38 million increase in base rates.	Awaiting decision. SEMCO and interveners filed rebuttal testimonies in October 2019 and SEMCO has adjusted the requested rate increase to US$36 million. The hearing is expected to take place in early November. The Michigan Public Service Commission (MPSC) has a 10-month statutory requirement from the time the application is filed to rule in this case and as a result, the case is expected to be completed no later than March 31, 2020.	March 2020

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 17

Midstream

Operating Statistics




	Three Months Ended September 30		Nine Months Ended September 30
	2019	2018	2019	2018
Extraction inlet gas processed (Mmcf/d) ⁽¹⁾	901	871	952	905
FG&P inlet gas processed (Mmcf/d) ⁽¹⁾	406	462	452	462
Total inlet gas processed (Mmcf/d) ⁽¹⁾	1,307	1,333	1,404	1,367
Extraction ethane volumes (Bbls/d) ⁽¹⁾	22,857	24,204	23,109	23,974
Extraction NGL volumes (Bbls/d) ^{(1) (2)}	42,974	36,741	38,621	37,810
Total extraction volumes (Bbls/d) ^{(1) (3)}	65,831	60,945	61,730	61,784
Frac spread - realized ($/Bbl) ^{(1) (4)}	17.12	15.60	17.83	16.42
Frac spread - average spot price ($/Bbl) ^{(1) (5)}	9.17	25.87	12.10	23.09
RIPET export volumes (Bbls/d) ⁽⁶⁾	36,225	—	34,787	—
Propane Far East Index (FEI) to Mont Belvieu spread (US$/Bbl) ⁽⁷⁾	12	—	13	—
Natural gas optimization inventory (Bcf)	35.7	36.7	35.7	36.7
WGL retail energy marketing - gas sales volumes (Mmcf)	6,476	8,155	43,246	8,155


(1)	Average for the period.


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


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


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


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


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


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

Inlet gas volumes processed at the extraction facilities for the third quarter of 2019 increased by 30 Mmcf/d compared to the same quarter of 2018. The increase was primarily due to additional available gas at the Edmonton Ethane Extraction Plant (EEEP), and additional volumes at Harmattan (including the Eagle Hill facility which was placed into service in May 2019), partially offset by lower inlet volumes at the Younger facility due to a partial plant outage at the upstream McMahon facility in early August to perform compressor repairs. Inlet gas volumes processed at the field gathering and processing (FG&P) facilities in the third quarter of 2019 decreased by 56 Mmcf/d primarily due to the disposition of certain non-core facilities in the first quarter of 2019, lower volumes at the Townsend complex as a result of lower drilling activities and low gas prices, partially offset by higher volumes from the Aitken Creek North facility which was placed in-service in the fourth quarter of 2018 and the newly constructed Nig Creek facility which was placed in-service in September 2019.

Inlet gas volumes processed at the extraction facilities for the first nine months of 2019 increased by 47 Mmcf/d compared to the same period of 2018. The increase was primarily due to the absence of the 2018 plant turnarounds at Harmattan, Joffre Ethane Extraction Plant (JEEP) and Pembina Empress Extraction Plant (PEEP), partially offset by lower volumes at the Younger facility due to various plant outages at the upstream McMahon facility in January, May, and August 2019, and reduced ownership of the Younger facility effective April 2018. Inlet gas volumes processed at the FG&P facilities for the first nine months of 2019 decreased by 10 Mmcf/d primarily due to the disposition of certain non-core facilities in the first quarter of 2019, partially offset by higher volumes at the Aitken Creek North facilities including the Nig Creek facility which was placed in-service September 2019.

Average ethane volumes for the third quarter of 2019 decreased by 1,347 Bbls/d, and average NGL volumes increased by 6,233 Bbls/d compared to the same period in 2018. Lower ethane volumes were a result of a contract termination at Harmattan at the end of 2018 which was renewed only in the fourth quarter of 2019, partially offset by higher contracted ethane volumes at EEEP. Higher NGL volumes were a result of additional volumes available from the Townsend complex and higher inlet at Harmattan and

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 18

EEEP, partially offset by operational issues upstream of Younger in August 2019, and the disposition of certain non-core facilities in the first quarter of 2019.

For the third quarter of 2019, U.S. retail sales volumes were 6,476 Mmcf, compared to 8,155 Mmcf in the same period of 2018. The decrease was primarily due to fewer customers in the third quarter of 2019 compared to the same period of 2018.

Average ethane volumes for the first nine months of 2019 decreased by 865 Bbls/d, and average NGL volumes increased by 811 Bbls/d compared to the same period in 2018. Lower ethane volumes were a result of reinjecting production at Younger due to uneconomic pricing, partially offset by higher contracted ethane volumes at PEEP and EEEP and higher inlet at JEEP. Higher NGL volumes were a result of additional volumes available from the Townsend complex, partially offset by lower inlet volumes at Younger due to various plant outages at the upstream McMahon facility in January, May, and August 2019, lower inlet at Harmattan, and the disposition of certain non-core facilities in the first quarter of 2019.

With RIPET commencing operations in the late May 2019, average propane volumes exported to Asia for the three and nine months ended September 30, 2019 were 36,225 Bbls/d and 34,787 Bbls/d, respectively.

For the first nine months of 2019, U.S. retail sales volumes were 43,246 Mmcf, compared to 8,155 Mmcf in the same period of 2018. The increase in retail sale volumes was primarily due to the addition of WGL volumes for the first half of 2019, partly offset by lower sales volumes due to fewer customers in the third quarter of 2019 compared to the same period in 2018.

Natural gas optimization inventory as at September 30, 2019 was 35.7 Bcf (December 31, 2018 - 35.9 Bcf).

Three Months Ended September 30

The Midstream segment reported normalized EBITDA of $127 million in the third quarter of 2019, compared to $65 million in the same quarter of 2018. The increase was mainly due to contributions from RIPET which was placed in-service in May 2019, contributions from Central Penn which was placed into service in October 2018, higher AFUDC recognized for the Mountain Valley Pipeline project, higher NGL marketing volumes and margins, the acquisition of 50 percent ownership in Black Swan’s Aitken Creek North gas processing facility in the fourth quarter of 2018, and contributions from the Nig Creek facility which was placed in-service September 2019. These were partly offset by lower contributions from WGL's retail energy marketing business due to fewer customers, the impact of the sale of Stonewall in the second quarter of 2019, lower than normal 2018 operating costs due to 2018 major turnarounds at several facilities, and the disposition of certain non-core facilities in the first quarter of 2019. During the third quarter of 2019, AltaGas recorded equity earnings of $13 million from Petrogas, compared to $2 million in the same quarter of 2018 mainly due to higher export volumes and expanded activity levels in Petrogas' other core business units.

During the third quarter of 2019, AltaGas recognized a pre-tax provision on equity investments of $44 million in the Midstream segment related to the pending sale of WGL Midstream's indirect equity interest in Central Penn. During the third quarter of 2018, AltaGas recognized pre-tax provisions of $152 million in the Midstream segment. Of this, $115 million was related to certain non-core Midstream assets classified as held for sale at September 30, 2018 and an additional $37 million was related to shut-in assets in the South, Cold Lake, and Northwest operating areas.

During the third quarter of 2019, AltaGas hedged approximately 6,228 Bbls/d of NGL volumes at an average price of $40/Bbl excluding basis differentials. During the third quarter of 2018, AltaGas hedged 7,500 Bbls/d of NGL at an average price of $33/Bbl, excluding basis differentials. The average indicative spot NGL frac spread for the third quarter of 2019 was approximately $9/Bbl, compared to $26/Bbl in the same quarter of 2018 inclusive of basis differentials. The realized frac spread of approximately $17/Bbl in the third quarter of 2019 (2018 - $16/Bbl) was higher than the same period in 2018 due to frac hedge gains. For RIPET, during the third quarter of 2019, AltaGas hedged approximately 22,447 Bbls/d of propane export volumes at an average FEI to Mont Belvieu spread of US$14/Bbl.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 19

In the third quarter of 2018, AltaGas recorded a realized loss of $2 million on the sale of its investment in Tidewater Midstream and Infrastructure Inc.

Nine Months Ended September 30

The Midstream segment reported normalized EBITDA of $330 million in the first nine months of 2019, compared to $184 million in the same period of 2018. The increase in normalized EBITDA was due to contributions from WGL Midstream assets in the first half of the year, contributions from Central Penn which was placed in-service in October 2018, higher AFUDC recognized from the Mountain Valley Pipeline project, contributions from RIPET which was placed in-service in May 2019, higher revenues at Harmattan due to increased NGL activities, the acquisition of 50 percent ownership in Black Swan’s Aitken Creek North gas processing facility in the fourth quarter of 2018, contributions from the Nig Creek facility which was placed in-service in September 2019, and higher realized frac spreads (inclusive of hedges). These were partially offset by impacts from the sale of Stonewall in the second quarter of 2019, the disposition of certain non-core facilities in the first quarter of 2019, lower contributions from WGL's retail energy marketing business in the third quarter of 2019, lower facility fees and lower operator income from change in operatorship at Younger, and lower uncontracted ethane volumes at Harmattan. During the first nine months of 2019, AltaGas recorded equity earnings of $46 million from Petrogas, compared to $13 million in the same period in 2018. The increase in Petrogas earnings was due to higher export volumes and margins at Ferndale and expanded activity levels in Petrogas' other core business segments.

During the first nine months of 2019, AltaGas hedged approximately 6,228 Bbls/d of NGL volumes at an average price of $40/Bbl, excluding basis differentials. During the first nine months of 2018, AltaGas hedged approximately 7,500 Bbls/d of NGL at an average price of $33/Bbl, excluding basis differentials. The average indicative spot NGL frac spread for first nine months of 2019 was approximately $12/Bbl compared to $23/Bbl in the same period of 2018. The realized frac spread of $18/Bbl in the first nine months of 2019 (2018 - $16/Bbl) was higher than the same period in 2018 due to frac hedge gains. For RIPET, during the first nine months of 2019, AltaGas hedged approximately 19,767 Bbls/d of propane export volumes at an average FEI to Mont Belvieu spread of US$13/Bbl.

During the first nine months of 2019, the Midstream segment recognized a pre-tax gain of $35 million on the disposition of WGL Midstream's equity investment in Stonewall, as well as a pre-tax gain of $5 million on the sale of remaining non-core Midstream processing facilities. As mentioned above, in the first nine months of 2018, AltaGas recorded a realized loss of $2 million on the sale of its investment in Tidewater Midstream and Infrastructure Inc.

During the first nine months of 2019 and 2018, the Midstream segment was also impacted by the previously mentioned provisions on assets and equity investments recorded in the third quarters of 2019 and 2018.

Power

Operating Statistics




	Three Months Ended September 30		Nine Months Ended September 30
	2019	2018	2019	2018
Renewable power sold (GWh)	136	690	426	1,318
Conventional power sold (GWh)	672	1,255	1,296	2,739
Renewable capacity factor (%)	21.7	44.6	17.8	36.6
Contracted conventional equivalent availability factor (%) ⁽¹⁾	98.9	98.5	69.6	97.2
WGL retail energy marketing - electricity sales volumes (GWh)	3,723	3,000	9,928	3,000


(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.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 20

During the third quarter of 2019, the volume of renewable power sold decreased by 554 GWh and the volume of conventional power sold decreased by 583 GWh, compared to the same quarter in 2018. The decrease in renewable volumes was primarily due to asset sales, including the Northwest Hydro facilities (January 2019), the Biomass facilities (August 2019), the Bear Mountain wind facility (October 2018) and the Busch Ranch wind facility (December 2018). The decrease in conventional volumes sold was primarily due to the November 2018 sale of the San Joaquin facilities.

The contracted conventional equivalent availability factor was slightly higher for the third quarter of 2019 as a result of lower maintenance activity. The renewable capacity factor was lower for the third quarter of 2019 primarily due to the sale of the Northwest Hydro facilities and the Bear Mountain wind facility.

U.S. retail sales volumes were 3,723 GWh in the third quarter of 2019, compared to 3,000 GWh in the same period of 2018. The increase was primarily due to an increase in customers served by the business.

During the first nine months of 2019, the volume of renewable power sold decreased by 892 GWh and the volume of conventional power sold decreased by 1,443 GWh. The change in volumes was due to the same reasons as noted above for the third quarter of 2019, partially offset by the addition of WGL volumes for the first six months of the year.

The variances related to the renewable capacity factor and contracted conventional availability factor for the first nine months of 2019 were due to the same factors as noted above for the third quarter of 2019 and the addition of WGL for the first six months of the year.

For the first nine months of 2019, U.S. retail sales volumes were 9,928 GWh, compared to 3,000 GWh in the same period of 2018. The increase was primarily due to the addition of WGL for the first half of the year and the previously mentioned factors impacting the third quarter of 2019.

Three Months Ended September 30

The Power segment reported normalized EBITDA of $70 million during the third quarter of 2019, compared to $128 million in the same period of 2018. Normalized EBITDA decreased primarily as a result of the impact of asset sales, including the Northwest Hydro facilities (January 2019), the San Joaquin facilities (November 2018), Canadian non-core Power assets (February 2019), the Biomass facilities (August 2019), the Bear Mountain facility (October 2018) and the Busch Ranch facility (December 2018). These decreases were partially offset by higher contributions to EBITDA from WGL's Power assets primarily due to favorable pricing on electricity purchases received by WGL retail energy marketing when compared to the same period of 2018.

In the third quarter of 2019, the sale of the U.S. portfolio of distributed generation assets was completed for total gross proceeds of US$735 million, resulting in a pre-tax gain of $100 million. Other asset sales completed in the third quarter of 2019 included the sale of AltaGas' equity ownership interest in two biomass plants in the United States for net cash proceeds of approximately US$18 million and the sale of a capital spare for proceeds of US$4 million. There were no gains or losses recorded on the dispositions of the biomass assets or the capital spare in the third quarter of 2019.

In the third quarter of 2018, pre-tax provisions of $352 million were recorded in the Power segment. These provisions were primarily related to assets classified as held for sale at September 30, 2018, including the Tracy, Hanford, and Henrietta gas-fired Power assets in California and certain gas-fired peaking plants in Alberta. There were no provisions recorded in the Power segment in the third quarter of 2019.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 21

Nine Months Ended September 30

The Power segment reported normalized EBITDA of $132 million in the first nine months of 2019, compared to $245 million in the same period of 2018. Normalized EBITDA decreased primarily for the same reasons noted above for the third quarter of 2019, and the extended planned outage at the Blythe facility impacting the first quarter and second quarter of 2019, partially offset by the addition of WGL's Power business for the first half of the year.

In addition to the previously mentioned asset sales completed in the third quarter of 2019, during the first nine months of 2019, AltaGas recognized a pre-tax gain of $688 million on the sale of the remaining interest in the Northwest Hydro facilities. In addition, during the first nine months of 2019, the sale of Canadian non-core Power assets was completed resulting in a pre-tax loss of $6 million, and the sale of a WGL Energy Systems financing receivable was completed resulting in a pre-tax loss of $1 million.

In the first nine months of 2019, a pre-tax provision of $1 million was recorded related to a capital spare turbine in storage which was classified as held for sale as at June 30, 2019 and a provision of $2 million was recorded on the Biomass facilities in the United States. In the first nine months of 2018, the Power segment was impacted by the previously mentioned provisions recorded in the third quarter of 2018.

Corporate

Three Months Ended September 30

In the Corporate segment, normalized EBITDA for the third quarter of 2019 was a loss of $11 million, compared to income of $1 million in the same quarter of 2018. The increased loss was mainly due to higher expenses related to employee incentive plans, lower interest income due to the absence of interest earned on funds that were held in escrow for the WGL Acquisition in the third quarter of 2018, and higher information technology related costs.

Nine Months ended September 30

In the Corporate segment, normalized EBITDA for the first nine months of 2019 was a loss of $28 million, compared to a loss of $8 million in the same period of 2018. The increased loss was a result of a number of factors including higher expenses related to employee incentive plans as a result of the increasing share price in the first nine months of 2019, lower interest income due to the absence of interest earned on funds that were held in escrow for the WGL Acquisition in the third quarter of 2018, and higher information technology related costs.

Invested Capital




	Three Months Ended September 30, 2019
($ millions)	Utilities		Midstream			Power			Corporate		Total
Invested capital:
Property, plant and equipment	$	313	$	164		$	—		$	—	$	477
Intangible assets	—		1			—			3		4
Long-term investments	—		41			—			—		41
Contributions from non-controlling interest	—		(7		)	—			—		(7		)
Invested capital	313		199			—			3		515
Disposals:
Property, plant and equipment	—		—			(978		)	—		(978		)
Equity method investments	—		—			(25		)	—		(25		)
Invested capital, net of disposals	$	313	$	199		$	(1,003	)	$	3	$	(488	)




	Three Months Ended September 30, 2018
($ millions)	Utilities		Midstream			Power		Corporate			Total
Invested capital:
Property, plant and equipment	$	259	$	60		$	47	$	1		$	367
Intangible assets	3		1			11		1			16
Long-term investments	—		59			—		—			59
Business acquisition	4,682		1,525			892		(1,168		)	5,931
Contributions from non-controlling interest	—		(12		)	—		—			(12		)
Invested capital	4,944		1,633			950		(1,166		)	6,361
Disposals:
Property, plant and equipment	—		—			—		—			—
Invested capital, net of disposals	$	4,944	$	1,633		$	950	$	(1,166	)	$	6,361

During the third quarter of 2019, AltaGas’ invested capital was $0.5 billion, compared to $6.4 billion in the same quarter of 2018. The decrease in invested capital was primarily due to the absence of the 2018 cash payment of $5.9 billion for the WGL Acquisition and lower contributions to WGL's investments in the Central Penn and Mountain Valley pipelines, partly offset by higher additions to property, plant and equipment.

The increase in additions to property, plant and equipment in the third quarter of 2019 was mainly due to capital expenditures related to system betterment and accelerated pipeline replacement programs at Washington Gas, the construction of the Marquette Connector pipeline, finalizing construction at RIPET, and construction of Nig Creek and the Townsend expansion. The disposal of property, plant and equipment primarily related to the disposition of WGL's distributed generation portfolio in September 2019. The disposal of equity method investments related to the disposition of the biomass investments in August 2019.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 22

The invested capital in the third quarter of 2019 included maintenance capital of $1 million (2018 ‑ $3 million) in the Midstream segment and a recovery of $4 million (2018 ‑ expenditures of $2 million) in the Power segment. The decrease in maintenance capital for the Midstream segment was primarily due to reduced turnaround expenditures. The decrease in maintenance capital for the Power segment was primarily due to lower than expected planned turnaround maintenance capital at the Blythe facility.



	Nine Months Ended September 30, 2019
($ millions)	Utilities		Midstream			Power			Corporate		Total
Invested capital:
Property, plant and equipment	$	696	$	344		$	36		$	1	$	1,077
Intangible assets	1		4			—			7		12
Long-term investments	—		176			—			—		176
Contributions from non-controlling interest	—		(34		)	—			—		(34		)
Invested capital	697		490			36			8		1,231
Disposals:
Property, plant and equipment	—		(87		)	(2,319		)	—		(2,406		)
Equity method investments	—		(379		)	(25		)	—		(404		)
Invested capital, net of disposals	$	697	$	24		$	(2,308	)	$	8	$	(1,579	)



	Nine Months Ended September 30, 2018
($ millions)	Utilities		Midstream			Power			Corporate			Total
Invested capital:
Property, plant and equipment	$	330	$	175		$	59		$	2		$	566
Intangible assets	4		4			12			3			23
Long-term investments	—		78			—			—			78
Business acquisition	4,682		1,525			892			(1,168		)	5,931
Contributions from non-controlling interest	—		(35		)	—			—			(35		)
Invested capital	5,016		1,747			963			(1,163		)	6,563
Disposals:
Property, plant and equipment	—		(8		)	(2		)	—			(10		)
Invested capital, net of disposals	$	5,016	$	1,739		$	961		$	(1,163	)	$	6,553

During the first nine months of 2019, AltaGas’ invested capital was $1.2 billion, compared to $6.6 billion in the same period of 2018. The decrease in invested capital in the first nine months of 2019 was mainly due to the absence of the 2018 cash payment of $5.9 billion for the WGL Acquisition, partly offset by higher additions to property, plant and equipment and contributions to WGL's investments in the Central Penn and Mountain Valley pipelines.

The increase in additions to property, plant and equipment in the first nine months of 2019 was mainly due to capital expenditures related to system betterment and accelerated pipeline replacement programs at Washington Gas, construction of the Marquette Connector pipeline, construction costs at RIPET, construction of Nig Creek and the Townsend expansion, and capital expenditures related to WGL's distributed generation projects. The disposals of property, plant and equipment in the first nine months of 2019 primarily related to the Northwest Hydro facilities, non-core Canadian Midstream and Power assets, and WGL's distributed generation portfolio, while in the first nine months of 2018 the disposals of property, plant and equipment related to non-core facilities in the Midstream segment and a development stage wind asset in the Power segment. The disposal of equity method investments in the first nine months of 2019 related to the disposition of Stonewall in May 2019 and the disposition of biomass investments in August 2019.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 23

The invested capital in the first nine months of 2019 included maintenance capital of $3 million (2018 ‑ $16 million) in the Midstream segment and $20 million (2018 ‑ $12 million) in the Power segment. The variances in maintenance capital for the first nine months of 2019 was primarily due to the same factors impacting maintenance capital in the third quarter of 2019.

Risk Management

AltaGas is exposed to various market risks in the normal course of operations that could impact earnings and cash flows. AltaGas enters into physical and financial derivative contracts to manage exposure to fluctuations in commodity prices and foreign exchange rates, as well as to optimize certain owned and managed natural gas assets. The Board of Directors of AltaGas has established a risk management policy for the Corporation establishing AltaGas’ risk management control framework. Derivative instruments are governed under, and subject to, this policy. As at September 30, 2019 and December 31, 2018, the fair values of the Corporation’s derivatives were as follows:




($ millions)	September 30, 2019			December 31, 2018
Natural gas	$	(122	)	$	(137	)
Energy exports	(10		)	—
NGL frac spread	9			16
Power	(8		)	(9		)
Foreign exchange	—			(1		)
Net derivative liability	$	(131	)	$	(131	)

Summary of Risk Management Contracts

Commodity Price Contracts

▪

The average indicative spot NGL frac spread for the nine months ended September 30, 2019 was approximately $12/Bbl (2018 – $23/Bbl), inclusive of basis differentials. The average NGL frac spread realized by AltaGas (based on average spot price and realized hedge price inclusive of basis differentials) for the nine months ended September 30, 2019 was approximately $18/Bbl inclusive of basis differentials (2018 - $16/Bbl).


▪	For 2019, AltaGas currently has frac hedges in place to hedge approximately 6,200 Bbls/d out of a total of approximately 10,000 Bbls/d at an average price of $40/Bbl, excluding basis differentials.

▪

Foreign Exchange Contracts


▪	As at September 30, 2019, management has designated US$0.7 billion of outstanding U.S. dollar denominated long-term debt to hedge against the currency translation effect of its foreign investments (December 31, 2018 - US$1.5 billion).


▪	For the three and nine months ended September 30, 2019, AltaGas recognized after-tax unrealized losses of $17 million and unrealized gains of $52 million, respectively, arising from the translation of debt in other comprehensive income (three and nine months ended September 30, 2018 - unrealized gains of $37 million).

Weather Instruments


▪	For the three and nine months ended September 30, 2019, pre-tax losses of $1 million and $nil, respectively (three and nine months ended September 30, 2018 - pre-tax losses of $1 million) were recorded related to heating degree day (HDD) and cooling degree day (CDD) instruments.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 24

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

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




	Three Months Ended September 30						Nine Months Ended September 30
($ millions)	2019			2018			2019			2018
Natural gas	$	1		$	(4	)	$	9		$	(15	)
Energy exports	(14		)	—			(21		)	—
NGL frac spread	(3		)	(7		)	(7		)	(5		)
Power	1			2			(3		)	(3		)
Foreign exchange	—			(2		)	1			35
	$	(15	)	$	(11	)	$	(21	)	$	12

Please refer to Note 22 of the 2018 Annual Consolidated Financial Statements and Note 14 of the unaudited condensed interim Consolidated Financial Statements as at and for the three and nine months ended September 30, 2019 for further details regarding AltaGas’ risk management activities.

Liquidity

As a result of certain commitments made to the PSC of DC, the PSC of MD, and the SCC of VA in respect of the WGL Acquisition, Washington Gas is subject to certain restrictions when paying dividends to AltaGas. However, AltaGas does not expect that this will have an impact on AltaGas’ ability to meet its obligations.

In addition, Wrangler SPE LLC and Washington Gas made certain ring fencing commitments to the PSC of DC, the PSC of MD, and the SCC of VA with the intention of removing Washington Gas from the bankruptcy estate of AltaGas and its affiliates, other than Washington Gas and Wrangler SPE LLC (together, the “Ring Fenced Entities”). Because of these ring fencing measures, none of the assets of the Ring Fenced Entities would be available to satisfy the debt or contractual obligations of AltaGas or any non-Ring Fenced Entity Affiliate, including any indebtedness or other contractual obligations of AltaGas, and the Ring Fenced Entities do not bear any liability for indebtedness or other contractual obligations of any non-Ring Fenced Entity, and vice versa.




	Three Months Ended September 30						Nine Months Ended September 30
($ millions)	2019			2018			2019			2018
Cash from (used by) operations	$	(30	)	$	(355	)	$	600		$	(18	)
Investing activities	528			(6,269		)	1,715			(6,465		)
Financing activities	(510		)	5,994			(2,408		)	6,602
Increase (decrease) in cash and cash equivalents	$	(12	)	$	(630	)	$	(93	)	$	119

Cash from (Used by) Operations

Cash from (used by) operations increased by $618 million for the nine months ended September 30, 2019 compared to the same period in 2018, primarily due to higher net income after taxes and a favorable variance in the net change in operating assets and liabilities. The majority of the variance in net change in operating assets and liabilities was due to the addition of WGL's operating assets and liabilities in the third quarter of 2018, increased cash flows from changes in accounts receivable due to seasonality at the Utilities, the lower price of gas, and asset sales completed in the first quarter of 2019, partially offset by decreased cash flows from accounts payable and accrued liabilities due to lower rates and volumes at the Utilities.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 25

Working Capital




($ millions except current ratio)	September 30, 2019			December 31, 2018
Current assets	$	1,823		$	4,033
Current liabilities	3,644			4,102
Working deficiency	$	(1,821	)	$	(69	)
Working capital ratio ⁽¹⁾	0.50			0.98


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

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

Investing Activities

Cash from investing activities for the nine months ended September 30, 2019 was $1.7 billion, compared to cash used in investing activities of $6.5 billion in the same period in 2018. Investing activities for the nine months ended September 30, 2019 primarily included proceeds of $2.8 billion from asset sales completed in the first nine months of 2019 (including the Northwest Hydro facilities, Stonewall, non-core Canadian Midstream and Power assets, and WGL's distributed generation portfolio) and proceeds of $73 million from the sale of a WGL Energy Systems financing receivable, partially offset by expenditures of approximately $1.0 billion for property, plant and equipment and intangible assets, and approximately $178 million of contributions to equity investments. Investing activities for the nine months ended September 30, 2018 primarily included the cash payment of $5.9 billion for the WGL acquisition, expenditures of approximately $522 million for property, plant and equipment and approximately $78 million of contributions to AltaGas' equity investments, partially offset by proceeds of $77 million on the disposition of investments, and cash proceeds of approximately $10 million, net of transaction costs, primarily from the sale of non-core Midstream facilities and a wind asset.

Financing Activities

Cash used in financing activities for the nine months ended September 30, 2019 was $2.4 billion, compared to cash from financing activities of $6.6 billion in the same period in 2018. Financing activities for the nine months ended September 30, 2019 were primarily comprised of net repayments under credit facilities of $1.6 billion, net repayments of short-term debt of $725 million, repayment of long-term debt of $275 million, and dividends of $250 million, partially offset by long-term debt issuances of $390 million, contributions from non-controlling interests of $44 million, and net proceeds from the issuance of common shares of $48 million (mainly from common shares issued through the DRIP). Financing activities for the nine months ended September 30, 2018 were primarily comprised of long-term debt issuances of $3.0 billion, net short-term debt issuances of $154 million, net proceeds from the issuance of common shares of $2.5 billion, the proceeds from the sale of the non-controlling interest in the Northwest Hydro facilities of $912 million (net of transaction costs), net borrowings under credit facilities of $574 million, and contributions from non-controlling interests of $53 million, partially offset by repayments of long-term debt of $272 million. Total dividends paid to common and preferred shareholders of AltaGas for the nine months ended September 30, 2019 were $250 million (2018 - $390 million), of which $48 million was reinvested through the DRIP (2018 - $224 million). The decrease in dividends paid was due to the reduction in dividends on common shares declared in the fourth quarter of 2018, partially offset by more common shares outstanding.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 26

Capital Resources

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

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




($ millions)	September 30, 2019			December 31, 2018
Short-term debt	$	449		$	1,210
Current portion of long-term debt	1,531			890
Long-term debt ⁽¹⁾	5,759			8,067
Total debt	7,739			10,167
Less: cash and cash equivalents	(36		)	(102		)
Net debt	$	7,703		$	10,065
Shareholders' equity	7,537			7,020
Non-controlling interests	148			621
Total capitalization	$	15,388		$	17,706

Net debt-to-total capitalization (%)	50			57


(1)	Net of debt issuance costs of $37 million as at September 30, 2019 (December 31, 2018 - $35 million).

As at September 30, 2019, AltaGas’ total debt primarily consisted of outstanding MTNs of $2.5 billion (December 31, 2018 - $2.7 billion), WGL and Washington Gas long-term debt of $3.0 billion, reflecting fair value adjustments on acquisition (December 31, 2018 - $2.7 billion), SEMCO long‑term debt of $0.5 billion (December 31, 2018 - $0.5 billion), $1.3 billion drawn under the bank credit facilities (December 31, 2018 - $3.0 billion) and short-term debt of $0.4 billion (December 31, 2018 - $1.2 billion). In addition, AltaGas had $306 million of letters of credit outstanding (December 31, 2018 - $271 million).

As at September 30, 2019, AltaGas’ total market capitalization was approximately $5.4 billion based on approximately 278 million common shares outstanding and a closing trading price on September 30, 2019 of $19.45 per common share.

AltaGas' earnings interest coverage for the rolling 12 months ended September 30, 2019 was 3.8 times (12 months ended September 30, 2018 – (2.6) times).

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 27




Credit Facilities			Drawn at		Drawn at
($ millions)	Borrowing capacity		September 30, 2019		December 31, 2018
AltaGas unsecured demand credit facilities ^{(1) (2)}	$	335	$	143	$	153
AltaGas unsecured extendible revolving letter of credit facilities^{(1) (2)}	547		154		117
AltaGas unsecured revolving credit facilities ^{(1) (2)}	3,387		904		2,890
AltaGas bridge facility ^{(1) (3)}	—		—		113
AltaGas unsecured term credit facility ^{(1) (2)}	397		397		—
SEMCO Energy US$200 million unsecured credit facilities ^{(1) (2)}	265		19		1
WGL US$250 million unsecured revolving credit facility^{(2) (4)}	331		—		—
Washington Gas US$450 million unsecured revolving credit facility^{(2) (4)}	596		—		—
	$	5,858	$	1,617	$	3,274


(1)	Amount drawn at September 30, 2019 converted at the month‑end rate of 1 U.S. dollar = 1.3243 Canadian dollar (December 31, 2018 - 1 U.S. dollar = 1.3642 Canadian dollar).


(2)	All US$ borrowing capacity was converted at the September 30, 2019 U.S./Canadian dollar month-end exchange rate.


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


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

WGL and Washington Gas use short-term debt in the form of commercial paper or unsecured short-term bank loans to fund seasonal cash requirements. Revolving committed credit facilities are maintained in an amount equal to or greater than the expected maximum commercial paper position. At September 30, 2019, commercial paper outstanding totaled US$277 million for WGL and Washington Gas (December 31, 2018 – US$840 million).

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

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

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




Ratios	Debt covenant requirements	As at September 30, 2019
Bank debt-to-capitalization ⁽¹⁾	not greater than 65 percent	49.9%
Bank EBITDA-to-interest expense ^{(1) (2)}	not less than 2.5x	3.1
Bank debt-to-capitalization (SEMCO) ⁽³⁾	not greater than 60 percent	35.5%
Bank EBITDA-to-interest expense (SEMCO) ⁽³⁾	not less than 2.25x	7.4
Bank debt-to-capitalization (WGL) ⁽⁴⁾	not greater than 65 percent	54.5%
Bank debt-to-capitalization (Washington Gas) ⁽⁴⁾	not greater than 65 percent	48.9%


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


(2)	Estimated, subject to final adjustments.


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


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

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

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 28

that the base shelf prospectus remains effective. As at September 30, 2019, approximately $2.0 billion was available under the base shelf prospectus.

On June 4, 2018, a US$2.0 billion preliminary short form prospectus for the issuance of both debt securities and preferred shares was filed in Alberta. AltaGas filed a final short form base shelf prospectus on June 13, 2018 both in Alberta and the U.S. This will enable AltaGas to access the U.S. capital markets during the 25-month period that the base shelf prospectus remains effective. As at September 30, 2019, US$2.0 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 30 of the 2018 Annual Consolidated Financial Statements.

Share Information




	As at October 25, 2019
Issued and outstanding
Common shares	278,303,196
Preferred Shares
Series A	5,511,220
Series B	2,488,780
Series C	8,000,000
Series E	8,000,000
Series G	6,885,823
Series H	1,114,177
Series I	8,000,000
Series K	12,000,000
Washington Gas US$4.25 series	150,000
Washington Gas US$4.80 series	70,600
Washington Gas US$5.00 series	60,000
Issued
Share options	7,572,397
Share options exercisable	2,715,938

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.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 29

The Series G Preferred Shares will continue to pay on a quarterly basis, for the five-year period beginning on September 30, 2019, as and when declared by the Board of Directors of AltaGas, a fixed dividend based on an annual fixed dividend rate of 4.242 percent.

The Series H Preferred Shares will pay a floating quarterly dividend for the five-year period beginning on September 30, 2019, as and when declared by the Board of Directors of AltaGas. The floating quarterly dividend rate for the Series H Preferred Shares for the first quarterly floating rate period (being the period from September 30, 2019 to, but excluding, December 31, 2019) is 4.698 percent and will be reset every quarter.

The following table summarizes AltaGas’ dividend declaration history:




Dividends
Year ended December 31
($ per common share)	2019		2018
First quarter	$	0.240000	$	0.547500
Second quarter	0.240000		0.547500
Third quarter	0.240000		0.547500
Fourth quarter	—		0.445000
Total	$	0.720000	$	2.087500




Series A Preferred Share Dividends
Year ended December 31
($ per preferred share)	2019		2018
First quarter	$	0.211250	$	0.211250
Second quarter	0.211250		0.211250
Third quarter	0.211250		0.211250
Fourth quarter	—		0.211250
Total	$	0.633750	$	0.845000




Series B Preferred Share Dividends
Year ended December 31
($ per preferred share)	2019		2018
First quarter	$	0.269380	$	0.217600
Second quarter	0.270510		0.238720
Third quarter	0.273921		0.249530
Fourth quarter	—		0.262770
Total	$	0.813811	$	0.968620




Series C Preferred Share Dividends
Year ended December 31
(US$ per preferred share)	2019		2018
First quarter	$	0.330625	$	0.330625
Second quarter	0.330625		0.330625
Third quarter	0.330625		0.330625
Fourth quarter	—		0.330625
Total	$	0.991875	$	1.322500

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 30




Series E Preferred Share Dividends
Year ended December 31
($ per preferred share)	2019		2018
First quarter	$	0.337063	$	0.312500
Second quarter	0.337063		0.312500
Third quarter	0.337063		0.312500
Fourth quarter	—		0.312500
Total	$	1.011189	$	1.250000




Series G Preferred Share Dividends
Year ended December 31
($ per preferred share)	2019		2018
First quarter	$	0.296875	$	0.296875
Second quarter	0.296875		0.296875
Third quarter	0.296875		0.296875
Fourth quarter	—		0.296875
Total	$	0.890625	$	1.187500




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




Series I Preferred Share Dividends
Year ended December 31
($ per preferred share)	2019		2018
First quarter	$	0.328125	$	0.328125
Second quarter	0.328125		0.328125
Third quarter	0.328125		0.328125
Fourth quarter	—		0.328125
Total	$	0.984375	$	1.312500




Series K Preferred Share Dividends
Year ended December 31
($ per preferred share)	2019		2018
First quarter	$	0.312500	$	0.312500
Second quarter	0.312500		0.312500
Third quarter	0.312500		0.312500
Fourth quarter	—		0.312500
Total	$	0.937500	$	1.250000

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 31




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




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




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

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 2018 Annual Consolidated Financial Statements. Certain of these policies involve critical accounting estimates as a result of the requirement to make particularly subjective or complex judgments about matters that are inherently uncertain, and because of the likelihood that materially different amounts could be reported under different conditions or using different assumptions.

AltaGas’ critical accounting estimates relate to revenue recognition, financial instruments, depreciation and amortization expense, accounting for leases, asset retirement obligations and other environmental costs, asset impairment assessments, income taxes, pension plans and post-retirement benefits, regulatory assets and liabilities, and contingencies. For a full discussion of these accounting estimates, refer to the 2018 Annual Consolidated Financial Statements and MD&A and Note 2 of the unaudited condensed interim Consolidated Financial Statements as at and for the three and nine months ended September 30, 2019.

Adoption of New Accounting Standards

Effective January 1, 2019, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU):

ASU No. 2016-02 “Leases” and all related amendments (collectively “ASC 842”). AltaGas has applied ASC 842 using the modified retrospective approach as of the effective date of the new standard. Comparative information has not been restated and continues to be reported under the previous lease guidance ASC 840. AltaGas has applied the package of transition practical expedients which permitted the Corporation to not reassess (a) whether any expired or existing contracts contain leases, (b) lease classifications for any expired or existing leases, and (c) initial direct costs for any existing leases. In addition, AltaGas applied the transition practical expedient that permitted the Corporation to grandfather its accounting policy for land easements that existed as of, or expired, before January 1, 2019. The transition practical expedient to not separate lease and non-lease components for its building, office equipment, transportation equipment,

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 32

and vehicle leases has been elected for lessee arrangements. The transition practical expedient to not separate lease and non-lease components for its lessor arrangements related to Power assets and Midstream processing facilities has also been elected. AltaGas has applied the short-term lease recognition exemption under which lease arrangements with a term of twelve months or less, including extension options that are reasonably certain of being exercised, are exempt from the recognition of a right-of-use asset and lease liability and recorded as an expense over the term of the lease. This exemption applies to all classes of assets.

On adoption of ASC 842, all operating leases were recognized on the balance sheet. The adoption resulted in an increase to long-term assets of approximately $181.0 million and an increase to long-term liabilities of approximately $170.5 million (net of the current portion that is recorded in current liabilities of approximately $23.3 million). The lease related liabilities were measured using the present value of the remaining minimum lease payments for existing leases discounted using the Corporation’s incremental borrowing rate as of January 1, 2019. For operating leases, the associated right-of-use assets were measured at the amount equal to the lease liabilities on January 1, 2019, adjusted for any prepaid or accrued lease payments and the remaining balance of any lease incentives received. The adoption of ASC 842 did not impact lessor accounting, the consolidated statement of income, or the consolidated statement of cash flow.

Please also refer to Note 15 of the unaudited condensed interim Consolidated Financial Statements as at and for the nine months ended September 30, 2019 for further details;

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

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

ASU No. 2018-07 “Compensation – Stock Compensation: Improvements to Nonemployee Share-Based Payment Accounting”. The amendments in this ASU expand the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees, with the objective of making the measurement consistent with employee share based payment awards. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;


§	ASU No. 2018-08 “Not-for-Profit-Entities – Clarifying the Scope and the Accounting Guidance for Contributions Received and Contributions Made”. The amendments in this ASU clarify whether a transfer of assets is a contribution or an exchange transaction. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

ASU No. 2018-15 “Intangibles – Goodwill and Other – Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement (CCA) that is a Service Contract”. The amendments in this ASU align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 33

arrangements that include an internal use software license). The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and

ASU No. 2018-16 “Derivatives and Hedging: Inclusion of the Second Overnight Financing Rate (SOFR) Overnight Index Swap (OIS) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes”. The amendments in this ASU permit the use of Overhead Index Swap (OIS) rate based on SOFR as a U.S. benchmark interest rate for hedge accounting purposes. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements.

Future Changes in Accounting Principles

In June 2016, FASB issued ASU No. 2016-13 “Financial Instruments – Credit Losses: Measurement of Credit Losses on Financial Instruments”. The amendments in this ASU replace the current “incurred loss” impairment methodology with an “expected loss” model for financial assets measured at amortized cost. The amendments in this ASU are effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted. AltaGas will adopt this standard on January 1, 2020 using a modified-retrospective approach through a cumulative-effect adjustment to retained earnings. AltaGas has completed scoping activities for this new accounting standard and is continuing to assess the impact of this ASU on its consolidated financial statements.

In August 2018, FASB issued ASU No. 2018-13 “Fair Value Measurement – Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurement”. The amendments in this ASU modify the disclosure requirements on fair value measurements. The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In August 2018, FASB issued ASU No. 2018-14 “Compensation-Retirement Benefits-Defined Benefit Plans – General: Disclosure Framework – Changes to the Disclosure Requirements for the Defined Benefit Plans”. The amendments in this ASU modify the disclosure requirements on defined benefit pension and other post-retirement plans. The amendments in this update are effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In October 2018, FASB issued ASU No. 2018-17 “Consolidation: Targeted Improvements to Related Party Guidance for Variable Interest Entities”. The amendments in this ASU provide a private-company scope exception to the VIE guidance for certain entities and clarify that indirect interest held through related parties under common control will be considered on a proportional basis when determining whether fees paid to decision makers and service providers are variable interests. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. An entity should apply the amendments retrospectively with a cumulative-effect adjustment to retained earnings at the beginning of the earliest period presented. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

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

In April 2019, FASB issued ASU No. 2019-04 “Financial Instruments - Credit Losses, Derivatives and Hedging, and Codification Improvements”. The amendments in this ASU provide clarification and improve the codification in recently issued accounting

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 34

standards on credit losses (ASU 2016-13), hedging (ASU 2017-12), and recognizing and measuring financial instruments (ASU 2016-01). The amendments related to credit losses have the same effective date and transition requirements as ASU 2016-13, the amendments related to hedge accounting are effective as of the beginning of the first annual period beginning after issuance of this ASU and may be applied retrospectively to the date ASU 2017-12 was adopted or prospectively with some exceptions, and the amendments related to financial instruments are effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

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

Off-Balance Sheet Arrangements

AltaGas did not enter into any material off-balance sheet arrangements during the nine months ended September 30, 2019. Reference should be made to the audited Consolidated Financial Statements and MD&A as at and for the year ended December 31, 2018 for further information on off-balance sheet arrangements.

Disclosure Controls and Procedures (DCP) and Internal Control Over Financial Reporting (ICFR)

Management, including the 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.

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 third quarter of 2019, there were no changes made to AltaGas’ ICFR that materially affected, or are reasonably likely to materially affect, its ICFR.

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

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 35

Overview of the Business

AltaGas, a Canadian corporation, is a leading North American clean energy infrastructure company with strong growth opportunities and 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 across its Utilities and Midstream business segments seeking optimal capital deployment. In the Midstream business, the Corporation is focused on optimizing the full value chain of energy exports by providing producers with solutions, including global market access off both coasts of North America via the Corporation’s footprint in two of the most prolific gas plays – the Montney and Marcellus. To optimize capital deployment, the Corporation seeks to invest in U.S. utilities located in strong growth markets with increasing capital deployment to support customer additions, system improvement, and accelerated replacement programs. AltaGas has three business segments:

Utilities, which serves approximately 1.6 million customers with a rate base of approximately US$3.7 billion through ownership of regulated natural gas distribution utilities across five jurisdictions in the United States and two regulated natural gas storage utilities in the United States, delivering clean and affordable natural gas to homes and businesses. The Utilities business also includes storage facilities and contracts for interstate natural gas transportation and storage services;

Midstream, which includes a 70 percent interest in the recently completed Ridley Island Propane Export Terminal, allowing AltaGas to leverage its assets along the energy value chain in Western Canada including natural gas gathering and processing, natural gas liquids (NGL) extraction and fractionation, and natural gas and NGL marketing. The Midstream segment also includes transmission, storage, an interest in three regulated pipelines in the Marcellus/Utica gas formation in the northeastern United States, one of which is pending sale, WGL’s retail gas marketing business, 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; and

Power, which includes 730 MW of operational gross capacity from natural gas-fired, solar, other distributed generation and energy storage assets, certain of which are pending sale, located in Alberta, Canada, and the United States in California and various other states as well as the District of Columbia. The Power business also includes energy efficiency contracting and WGL’s retail power marketing business.

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




($ millions)	Q3-19	Q2-19	Q1-19	Q4-18	Q3-18		Q2-18	Q1-18	Q4-17
Total revenue	888	1,174	1,898	1,727	1,041		610	878	745
Normalized EBITDA ⁽²⁾	178	203	466	394	226		166	223	213
Net income (loss) applicable to common shares	22	41	809	174	(726	)	1	49	(11	)
($ per share)	Q3-19	Q2-19	Q1-19	Q4-18	Q3-18		Q2-18	Q1-18	Q4-17
Net income (loss) per common share
Basic	0.08	0.15	2.93	0.64	(2.78	)	0.01	0.28	(0.06	)
Diluted	0.08	0.15	2.93	0.64	(2.78	)	0.01	0.28	(0.06	)
Dividends declared	0.24	0.24	0.24	0.45	0.55		0.55	0.55	0.54


(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.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 36

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


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


§	The weak Alberta power pool prices throughout 2017;


§	The weaker U.S. dollar in the second half of 2017 and the first half 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, throughout 2018, and the first quarter of 2019;


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


§	Losses on risk management contracts recorded in 2017 and the first half of 2018 related to the foreign currency option contracts entered into to mitigate the foreign exchange risks associated with the cash purchase price of WGL;


§	The negative impact on revenue of the TCJA at the U.S. utilities throughout 2018 and the first half of 2019;


§	The impact of the sale of non-core U.S. Power assets in the fourth quarter of 2018;


§	The impact of the sale of the Canadian utilities to ACI in the fourth quarter of 2018;


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


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

Net income (loss) applicable to common shares is also affected by non-cash items such as deferred income tax, depreciation and amortization expense, accretion expense, provisions on assets, gains or losses on long-term investments, and gains or losses on the sale of assets. In addition, net income (loss) applicable to common shares is also impacted by preferred share dividends. 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:


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


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


§	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 Midstream processing facility in Alberta, and a non-core development stage peaking project in California;


§	Impact of the TCJA resulting in a decrease in tax expense of approximately $34 million in the fourth quarter of 2017;


§	After-tax transaction costs incurred throughout 2017 (totaling $53 million) and 2018 ($50 million) predominantly due to the WGL Acquisition;


§	After-tax merger commitment costs of $135 million associated with the WGL Acquisition recorded in the second half of 2018;


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


§	An income tax recovery of approximately $104 million related to the Northwest Hydro facilities held for sale classification at December 31, 2018;


§	The impact of the sale of non-core U.S. Power assets in the fourth quarter of 2018;


§	The impact of the sale of the Canadian utilities to ACI in the fourth quarter of 2018;


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


§	The impact of the sale of WGL's distributed generation business in the third quarter of 2019.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 37

CONSOLIDATED BALANCE SHEETS

(condensed and unaudited)

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 38





As at ($ millions)	September 30, 2019		December 31, 2018

ASSETS
Current assets
Cash and cash equivalents (note 21)	$	36.4	$	101.6
Accounts receivable, net of allowances	842.8		1,547.5
Inventory (note 7)	517.2		515.9
Restricted cash holdings from customers (note 21)	3.9		4.1
Regulatory assets	14.7		21.0
Risk management assets (note 14)	69.1		114.1
Prepaid expenses and other current assets (note 21)	233.5		199.9
Assets held for sale (note 5)	105.0		1,528.9
	1,822.6		4,033.0

Property, plant and equipment	10,632.0		10,929.6
Intangible assets	610.6		711.9
Operating right of use assets (note 15)	147.7		—
Goodwill (note 8)	4,016.6		4,068.2
Regulatory assets	532.1		663.0
Risk management assets (note 14)	46.9		57.7
Restricted cash holdings from customers (note 21)	4.0		6.1
Prepaid post-retirement benefits	339.9		342.7
Long-term investments and other assets (notes 9, 14, and 21)	275.1		283.1
Investments accounted for by the equity method	2,259.0		2,392.4
	$	20,686.5	$	23,487.7

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities	$	1,332.8	$	1,488.2
Dividends payable	22.2		22.0
Short-term debt	449.4		1,209.9
Current portion of long-term debt (notes 11 and 14)	1,531.3		890.2
Customer deposits	81.0		98.0
Regulatory liabilities	103.1		114.9
Risk management liabilities (note 14)	68.4		89.3
Operating lease liabilities (note 15)	23.3		—
Other current liabilities (note 14)	11.8		18.1
Liabilities associated with assets held for sale (note 5)	20.6		171.4
	3,643.9		4,102.0

Long-term debt (notes 11 and 14)	5,758.7		8,066.9
Asset retirement obligations	493.8		500.6
Unamortized investment tax credits	2.9		190.1
Deferred income taxes	1,065.0		957.9
Regulatory liabilities	1,272.3		1,392.8
Risk management liabilities (note 14)	178.3		213.0
Operating lease liabilities (note 15)	140.1		—
Other long-term liabilities (note 14)	144.9		122.0
Future employee obligations	301.5		302.2
	$	13,001.4	$	15,847.5




As at ($ millions)	September 30, 2019			December 31, 2018

Shareholders' equity
Common shares, no par values, unlimited shares authorized; 2019 - 277.9 million and 2018 - 275.2 million issued and outstanding (note 16)	$	6,701.6		$	6,653.9
Preferred shares (note 16)	1,318.8			1,318.8
Contributed surplus	375.6			373.2
Accumulated deficit	(1,232.2		)	(1,905.3		)
Accumulated other comprehensive income (AOCI) (note 12)	372.8			579.0
Total shareholders' equity	7,536.6			7,019.6
Non-controlling interests	148.5			620.6
Total equity	$	7,685.1		$	7,640.2
	$	20,686.5		$	23,487.7

Variable interest entities (note 10)

Commitments, guarantees and contingencies (note 18)

Seasonality (note 22)

Segmented information (note 23)

Subsequent events (note 24)

See accompanying notes to the Consolidated Financial Statements.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 39

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(condensed and unaudited)





	Three months ended September 30						Nine months ended September 30
($ millions except per share amounts)	2019			2018			2019			2018

REVENUE (note 13)	$	888.4		$	1,041.4		$	3,960.4		$	2,529.6

EXPENSES
Cost of sales, exclusive of items shown separately	481.5			571.1			2,338.3			1,433.7
Operating and administrative	299.6			495.9			958.2			783.0
Accretion expenses	1.1			2.6			3.8			8.1
Depreciation and amortization	103.6			122.5			329.4			268.0
Provisions on assets (note 6)	—			697.4			0.8			697.4
	885.8			1,889.5			3,630.5			3,190.2

Income (loss) from equity investments (note 6)	(5.1		)	12.6			84.7			25.4
Other income (note 4)	103.5			11.7			838.8			5.2
Foreign exchange gains	0.7			3.0			—			3.6
Interest expense
Short-term debt	(18.2		)	(3.0		)	(44.7		)	(4.3		)
Long-term debt	(74.3		)	(109.1		)	(224.4		)	(194.0		)
Income (loss) before income taxes	9.2			(932.9		)	984.3			(824.7		)
Income tax expense (recovery) (note 20)
Current	9.4			11.4			23.0			34.0
Deferred	(43.7		)	(232.3		)	36.2			(234.2		)
Net income (loss) after taxes	43.5			(712.0		)	925.1			(624.5		)

Net income (loss) applicable to non-controlling interests	4.3			(2.7		)	1.7			1.8
Net income (loss) applicable to controlling interests	39.2			(709.3		)	923.4			(626.3		)
Preferred share dividends	(16.8		)	(16.9		)	(51.3		)	(49.7		)
Net income (loss) applicable to common shares	$	22.4		$	(726.2	)	$	872.1		$	(676.0	)

Net income (loss) per common share (note 17)
Basic	$	0.08		$	(2.78	)	$	3.16		$	(3.28	)
Diluted	$	0.08		$	(2.78	)	$	3.15		$	(3.28	)

Weighted average number of common shares outstanding (millions) (note 17)
Basic	277.4			261.3			276.4			206.0
Diluted	278.0			261.3			276.8			206.0

See accompanying notes to the Consolidated Financial Statements.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 40

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(condensed and unaudited)





	Three months ended September 30						Nine months ended September 30
($ millions)	2019			2018			2019			2018

Net income (loss) after taxes	$	43.5		$	(712.0	)	$	925.1		$	(624.5	)
Other comprehensive income (loss), net of taxes
Gain (loss) on foreign currency translation	100.5			(127.5		)	(260.5		)	4.0
Unrealized gain (loss) on net investment hedge (note 14)	(16.6		)	37.4			52.4			37.4
Reclassification of actuarial gains and prior service costs on defined benefit (DB) and post-retirement benefit plans (PRB) to net income (note 19)	1.1			0.1			3.7			0.4
Curtailment of DB and PRB plan (note 19)	—			—			—			2.7
Adoption of ASU 2016-01	—			—			—			7.1
Other comprehensive income (loss) from equity investees	(0.9		)	(0.9		)	(1.8		)	0.8
Total other comprehensive income (loss) (OCI), net of taxes (note 12)	84.1			(90.9		)	(206.2		)	52.4
Comprehensive income (loss) attributable to controlling interests and non-controlling interests, net of taxes	$	127.6		$	(802.9	)	$	718.9		$	(572.1	)

Comprehensive income (loss) attributable to:
Non-controlling interests	$	4.3		$	(2.7	)	$	1.7		$	1.8
Controlling interests	123.3			(800.2		)	717.2			(573.9		)
	$	127.6		$	(802.9	)	$	718.9		$	(572.1	)

See accompanying notes to the Consolidated Financial Statements.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 41

CONSOLIDATED STATEMENTS OF EQUITY

(condensed and unaudited)





Nine months ended September 30 ($ millions)	2019			2018

Common shares (note 16)
Balance, beginning of period	$	6,653.9		$	4,007.9
Shares issued for cash on exercise of options	—			1.1
Shares issued under DRIP ⁽¹⁾	47.7			223.5
Deferred taxes on share issuance costs	—			13.3
Shares issued on conversion of subscription receipts, net of issuance costs	—			2,321.1
Balance, end of period	$	6,701.6		$	6,566.9
Preferred shares (note 16)
Balance, beginning of period	$	1,318.8		$	1,277.7
Preferred shares acquired through WGL Acquisition	—			41.1
Balance, end of period	$	1,318.8		$	1,318.8
Contributed surplus
Balance, beginning of period	$	373.2		$	22.3
Share options expense	2.6			0.7
Exercise of share options	—			(0.1		)
Forfeiture of share options	(0.2		)	—
Sale of non-controlling interest	—			334.6
Balance, end of period	$	375.6		$	357.5
Accumulated deficit
Balance, beginning of period	$	(1,905.3	)	$	(933.6	)
Net income (loss) applicable to controlling interests	923.4			(626.3		)
Common share dividends	(199.0		)	(357.1		)
Preferred share dividends	(51.3		)	(49.7		)
Adoption of ASU No. 2016-01	—			(7.1		)
Balance, end of period	$	(1,232.2	)	$	(1,973.8	)
AOCI (note 12)
Balance, beginning of period	$	579.0		$	199.1
Other comprehensive income (loss)	(206.2		)	52.4
Balance, end of period	$	372.8		$	251.5
Total shareholders' equity	$	7,536.6		$	6,520.9

Non-controlling interests
Balance, beginning of period	$	620.6		$	65.8
Net income applicable to non-controlling interests	1.7			1.8
Sale of non-controlling interest	—			420.4
Adjustment on disposition of assets	(508.0		)	—
Contributions from non-controlling interests to subsidiaries	43.5			52.9
Distributions by subsidiaries to non-controlling interests	(9.3		)	(7.8		)
Acquisition of non-controlling interest through WGL Acquisition	—			9.0
Balance, end of period	$	148.5		$	542.1
Total equity	$	7,685.1		$	7,063.0


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

See accompanying notes to the Consolidated Financial Statements.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 42

CONSOLIDATED STATEMENTS OF CASH FLOWS

(condensed and unaudited)




	Three months ended September 30						Nine months ended September 30
	2019			2018			2019			2018
Cash from (used by) operations
Net income (loss) after taxes	$	43.5		$	(712.0	)	$	925.1		$	(624.5	)
Items not involving cash:
Depreciation and amortization	103.6			122.5			329.4			268.0
Provisions on assets (note 6)	—			697.4			0.8			697.4
Accretion expenses	1.1			2.6			3.8			8.1
Share-based compensation (note 16)	1.2			0.3			2.5			0.7
Deferred income tax expense (recovery) (note 20)	(43.7		)	(232.3		)	36.2			(234.2		)
Gains on sale of assets (note 4)	(99.1		)	—			(818.8		)	(1.3		)
Loss (income) from equity investments	5.1			(12.6		)	(84.7		)	(25.4		)
Unrealized losses (gains) on risk management contracts (note 14)	14.9			10.5			21.1			(12.0		)
Realized loss on expiry of foreign exchange options	—			—			—			36.0
Losses (gains) on investments	1.6			(14.8		)	4.6			—
Amortization of deferred financing costs	2.7			18.1			9.0			24.4
Provision for doubtful accounts	2.3			7.7			17.3			7.7
Change in pension and other post retirement benefits	4.8			2.2			9.3			2.2
Other	0.7			(2.9		)	7.0			(2.8		)
Asset retirement obligations settled	4.1			(0.9		)	(1.9		)	(2.5		)
Distributions from equity investments	25.1			12.7			89.5			25.3
Changes in operating assets and liabilities (note 21)	(98.3		)	(253.2		)	49.8			(185.4		)
	$	(30.4	)	$	(354.7	)	$	600.0		$	(18.3	)
Investing activities
Business acquisitions, net of cash acquired (note 3)	—			(5,931.0		)	—			(5,931.0		)
Capital expenditures - property, plant and equipment	(417.8		)	(327.1		)	(960.1		)	(522.3		)
Capital expenditures - intangible assets	(12.5		)	(15.8		)	(31.2		)	(20.5		)
Contributions to equity investments	(43.8		)	(58.8		)	(177.6		)	(78.2		)
Proceeds from disposition of investments	—			63.4			—			76.5
Proceeds from disposition of assets, net of transaction costs (note 4)	1,002.4			0.3			2,810.9			10.2
Proceeds from disposition of financing receivable (note 4)	—			—			73.5			—
	$	528.3		$	(6,269.0	)	$	1,715.5		$	(6,465.3	)
Financing activities
Net issuance (repayment) of short-term debt	(302.8		)	202.5			(725.2		)	154.1
Issuance of long-term debt, net of debt issuance costs	391.9			3,023.6			389.9			3,030.9
Repayment of long-term debt	(4.7		)	(66.4		)	(274.8		)	(272.2		)
Net borrowing (repayment) under credit facilities	(537.0		)	565.7			(1,634.2		)	574.0
Dividends - common shares	(66.4		)	(145.8		)	(198.8		)	(340.0		)
Dividends - preferred shares	(16.8		)	(16.9		)	(51.3		)	(49.7		)
Distributions to non-controlling interest	(1.2		)	(3.3		)	(4.8		)	(7.8		)
Contributions from non-controlling interests	7.6			29.6			43.5			52.9
Net proceeds from shares issued on exercise of options	—			—			—			1.0
Net proceeds from issuance of common shares	19.3			2,413.0			47.7			2,546.9
Net proceeds from sale of non-controlling interest	—			(8.7		)	—			912.3
Other	—			0.5			—			—
	$	(510.1	)	$	5,993.8		$	(2,408.0	)	$	6,602.4
Change in cash, cash equivalents and restricted cash	(12.2		)	(629.9		)	(92.5		)	118.8
Effect of exchange rate changes on cash, cash equivalents and restricted cash	2.3			(2.0		)	(5.4		)	(0.7		)
Net change in cash classified within assets held for sale	—			(134.9		)	4.9			(134.9		)
Restricted cash acquired (note 21)	—			81.0			—			81.0
Cash, cash equivalents, and restricted cash beginning of period	118.0			793.7			201.1			43.7
Cash, cash equivalents, and restricted cash end of period (note 21)	$	108.1		$	107.9		$	108.1		$	107.9

See accompanying notes to the Consolidated Financial Statements.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 43

NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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

1. Organization and Overview of the Business

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 44

2. Summary of Significant Accounting Policies

BASIS OF PRESENTATION

These unaudited condensed interim Consolidated Financial Statements have been prepared by management in accordance with United States Generally Accepted Accounting Principles (U.S. GAAP). As a result, these unaudited condensed interim Consolidated Financial Statements do not include all of the information and disclosures required in the annual Consolidated Financial Statements and should be read in conjunction with the Corporation's 2018 annual audited Consolidated Financial Statements prepared in accordance with U.S. GAAP. In management's opinion, these unaudited condensed interim Consolidated Financial Statements include all adjustments that are of a recurring nature and necessary to present fairly the financial position of the Corporation.

Pursuant to National Instrument 52‑107, "Acceptable Accounting Principles and Auditing Standards" (NI 52‑107), financial statements of an “SEC issuer” may be prepared in accordance with U.S. GAAP. On July 13, 2018, AltaGas filed a final short form base shelf prospectus in Alberta and a corresponding registration statement on Form F-10 in the United States, by virtue of which AltaGas is now required to file reports under section 15(d) of the Securities Exchange Act of 1934 with the United States Securities and Exchange Commission. As a result, AltaGas became an SEC issuer at such time and is now entitled to prepare its financial statements in accordance with U.S. GAAP.

PRINCIPLES OF CONSOLIDATION

These unaudited condensed interim Consolidated Financial Statements of AltaGas include the accounts of the Corporation, its subsidiaries, variable interest entities (VIEs) for which the Corporation is the primary beneficiary, and its interest in various partnerships and joint ventures where AltaGas has an undivided interest in the assets and liabilities. Investments in unconsolidated companies that AltaGas has significant influence over, but not control, are accounted for using the equity method.

Hypothetical Liquidation at Book Value (HLBV) methodology is used for certain equity method investments as well as consolidating equity investments with non-controlling interests when the governing structuring agreement over the equity investment results in different liquidation rights and priorities than what is reflected by the underlying ownership interest percentage.

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

USE OF ESTIMATES AND MEASUREMENT UNCERTAINTY

The preparation of Consolidated Financial Statements in accordance with U.S. GAAP requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenue and expenses during the period. Key areas where Management has made complex or subjective judgments, when matters are inherently uncertain, include but are not limited to: determining the nature and timing of satisfaction of performance obligations and determining the transaction price and amounts allocated to performance obligations for revenue recognition; depreciation and amortization rates; determination as to whether a contract is or contains a lease; determination of the classification, term, and discount rate for leases; fair value of asset retirement obligations; fair value of property, plant and equipment and goodwill for impairment assessments; fair value of financial instruments; provisions for income taxes; assumptions used to measure employee future benefits; provisions for contingencies; and carrying value of regulatory assets and liabilities. Certain estimates are necessary for the regulatory environment in which AltaGas' subsidiaries or affiliates operate, which often require amounts to be recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. By their

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 45

nature, these estimates are subject to measurement uncertainty and may impact the Consolidated Financial Statements of future periods.

SIGNIFICANT ACCOUNTING POLICIES

Except as noted below, these unaudited condensed interim Consolidated Financial Statements have been prepared following the same accounting policies and methods as those used in preparing the Corporation's 2018 annual audited Consolidated Financial Statements.

The following are the Corporation’s significant accounting policies upon the adoption of ASC 842:

Leases – Lessee

AltaGas determines if an arrangement is a lease at inception. Operating leases are included in right-of-use (“ROU”) assets, current operating lease liabilities, and long-term operating lease liabilities in the consolidated balance sheets. Finance leases are included in property, plant and equipment and current and long-term debt in the consolidated balance sheets.

ROU assets represent the right to use an underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Operating lease ROU assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. AltaGas uses the rate implicit in the lease when readily determinable. When the implicit lease rate is not readily determinable, AltaGas uses its incremental borrowing rate to determine the present value of lease payments. AltaGas includes lessee options to renew or terminate the lease term in the determination of the ROU asset and lease liability when exercise is reasonably certain. The operating lease ROU asset is adjusted for lease payments made in advance of the commencement date, initial direct costs, and any lease incentives.

Operating lease expense is recognized on a straight-line basis over the lease term in operating and administrative expense. Depreciation and interest expense are recorded on finance leases.

Leases – Lessor

AltaGas determines if an arrangement is a lease at inception. Lease payments under an operating lease are recognized on a straight-line basis over the term of the lease. Variable lease payments are recognized as revenue as the facts and circumstances on which the variable lease payment is based occur.

AltaGas does not include taxes assessed by governmental authorities, such as sales and related taxes, in the lease payments or variable lease payments.

ADOPTION OF NEW ACCOUNTING STANDARDS

Effective January 1, 2019, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU):

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 46

expedient to not separate lease and non-lease components for its building, office equipment, transportation equipment, and vehicle leases has been elected for lessee arrangements. The transition practical expedient to not separate lease and non-lease components for its lessor arrangements related to Power assets and Midstream processing facilities has also been elected. AltaGas has applied the short-term lease recognition exemption under which lease arrangements with a term of twelve months or less, including extension options that are reasonably certain of being exercised, are exempt from the recognition of a right-of-use asset and lease liability and recorded as an expense over the term of the lease. This exemption applies to all classes of assets.

Please also refer to Note 15 of the unaudited condensed interim Consolidated Financial Statements as at and for the nine months ended September 30, 2019 for further details;


§	ASU No. 2018-08 “Not-for-Profit-Entities – Clarifying the Scope and the Accounting Guidance for Contributions Received and Contributions Made”. The amendments in this ASU clarify whether a transfer of assets is a contribution or an exchange transaction. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 47

arrangements that include an internal use software license). The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and

FUTURE CHANGES IN ACCOUNTING PRINCIPLES

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 48

3. Acquisition of WGL Holdings, Inc.

Following the receipt of all required federal, state, and local regulatory approvals, on July 6, 2018 the Corporation acquired WGL (the WGL Acquisition). The WGL Acquisition was accounted for as a business combination using the acquisition method of accounting whereby the acquired assets and assumed liabilities are recorded at their estimated fair values at the date of acquisition. The excess of purchase price over estimated fair values of assets acquired and liabilities assumed was recognized as goodwill at the acquisition date.

The following table summarizes the final purchase price allocation representing the consideration paid and the fair value of the net assets acquired as at July 6, 2018 using an exchange rate of 1.31 to convert U.S. dollars to Canadian dollars. The purchase price allocation was finalized on June 30, 2019 and reflects Management’s best estimate of the fair value of WGL’s assets and liabilities. In the first half of 2019, based on new information obtained in the period and further refinement of assumptions, adjustments to the purchase price allocation included amounts relating to intangible assets, deferred income taxes, pension liabilities, current liabilities, other long-term liabilities, valuation of equity investments in Midstream pipelines, and deferred rent, resulting in a net increase to goodwill of approximately $92.2 million (Note 8).

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 49




Purchase consideration	$	5,973

Fair value assigned to net assets
Current assets	$	1,220
Property, plant and equipment	5,884
Intangible assets	577
Regulatory assets	408
Long-term investments	1,475
Other long-term assets	462
Current liabilities	(1,916		)
Long-term debt	(2,548		)
Preferred shares	(41		)
Regulatory liabilities	(1,126		)
Deferred income taxes	(741		)
Other long-term liabilities	(959		)
Non-controlling interest	(9		)
Accumulated other comprehensive income	(2		)
Fair value of net assets acquired	$	2,684
Goodwill	$	3,289

4. Dispositions

Northwest Hydro Electric Facilities

On January 31, 2019, AltaGas completed the disposition of its remaining 55 percent indirect interest in the Northwest Hydro Electric facilities in British Columbia (Northwest Hydro) for net cash proceeds of approximately $1.3 billion. The disposition was completed through the sale of 55 percent of Northwest Hydro Limited Partnership, a subsidiary of AltaGas which indirectly held the Northwest Hydro facilities. As a result, AltaGas recognized a pre-tax gain on disposition of approximately $687.9 million in the Consolidated Statements of Income (Loss) under the line item “other income” for the nine months ended September 30, 2019.

Non-Core Midstream and Power Assets in Canada

On February 1, 2019, AltaGas completed the disposition of certain non-core Midstream and Power assets for cash proceeds of approximately $87.8 million. As a result, AltaGas recognized a pre-tax loss on disposition of approximately $1.2 million in the Consolidated Statements of Income (Loss) under the line item “other income” for the nine months ended September 30, 2019.

Architect of the Capitol (AOC) Project

In February 2019, AltaGas completed the disposition of a financing receivable related to the construction of an energy management services project for cash proceeds of approximately $73.5 million. As a result, AltaGas recognized a pre-tax loss on disposition of approximately $1.3 million in the Consolidated Statements of Income (Loss) under the line item “other income” for the nine months ended September 30, 2019.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 50

Stonewall Gas Gathering System

On May 31, 2019, AltaGas completed the disposition of WGL Midstream's entire interest in the Stonewall Gas Gathering System (Stonewall) to a wholly-owned subsidiary of DTE Energy Company for total gross proceeds of approximately $379.2 million (US$280 million). As a result, AltaGas recognized a pre-tax gain on disposition of $35.3 million in the Consolidated Statements of Income (Loss) under the line item “other income” for the nine months ended September 30, 2019.

Biomass Assets

On August 13, 2019, AltaGas completed the disposition of its equity ownership interests in Craven County Wood Energy LP and Grayling Generation Station LP for net proceeds of approximately $24.5 million (US$18.5 million). There was no gain or loss resulting from this disposition.

Distributed Generation Assets

On September 26, 2019, AltaGas closed the disposition of its portfolio of U.S. distributed generation assets for total cash proceeds of approximately $975 million (US$735 million). As a result, AltaGas recognized a pre-tax gain on disposition of approximately $99.5 million in the Consolidated Statement of Income (Loss) under the line item "other income" for the nine months ended September 30, 2019. There are certain projects for which ownership will not legally transfer to the purchaser until various consents and approvals are obtained. As such, the carrying value of the assets and liabilities relating to these projects remain classified as held for sale on the Consolidated Balance Sheets at September 30, 2019 (Note 5). The portion of the purchase price relating to these projects is approximately $151 million (US$114 million) and is recorded within "Accounts payable and accrued liabilities" on the Consolidated Balance Sheets until these projects are legally transferred to the purchaser. The pre-tax gain related to these projects has also been deferred and will be recognized as these projects are legally transferred. The purchaser is entitled to after-tax earnings from the distributed generation projects, including those awaiting consent, beginning September 1, 2019.

Capital Spare

In the third quarter of 2019, AltaGas completed the sale of a capital spare turbine in the Power segment which was held for sale at June 30, 2019 for total cash proceeds of $4.6 million (US$3.5 million). There was no gain or loss resulting from this disposition in the third quarter of 2019.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 51

5. Assets Held For Sale



As at	September 30, 2019		December 31, 2018
Assets held for sale
Cash	$	—	$	4.9
Accounts receivable	—		85.2
Inventory	—		0.5
Property, plant and equipment	96.2		1,189.6
Intangible assets	—		248.7
Operating right of use assets	4.1		—
Goodwill	4.7		—
	$	105.0	$	1,528.9

Liabilities associated with assets held for sale
Accounts payable and accrued liabilities	$	—	$	23.8
Operating lease liabilities - current	0.4		—
Asset retirement obligations	0.6		10.8
Unamortized investment tax credits	15.9		—
Operating lease liabilities - long-term	3.7		—
Other long-term liabilities	—		136.8
	$	20.6	$	171.4

Distributed Generation Assets

On July 22, 2019, AltaGas announced that it entered into a definitive agreement for the sale of its portfolio of U.S. distributed generation assets (Note 4). The transaction closed on September 26, 2019; however, there are certain projects for which ownership will not legally transfer to the purchaser until various consents and approvals are obtained. As such, the carrying value of the assets and liabilities related to these projects remain classified as held for sale at September 30, 2019. These assets are recorded in the Power segment.

6. Provisions on Assets



Nine months ended September 30	2019		2018
Utilities	$	—	$	193.7
Midstream	—		151.5
Power	0.8		352.2
	$	0.8	$	697.4

Utilities

There were no provisions recorded in the Utilities segment in the first nine months of 2019. In the third quarter of 2018, AltaGas recorded pre-tax provisions of $193.7 million related to certain rate-regulated natural gas distributed utility assets that were classified as held for sale.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 52

Midstream

There were no provisions recorded in the Midstream segment in the first nine months of 2019. In the third quarter of 2018, AltaGas recorded pre-tax provisions of $151.5 million related to certain non-core Midstream assets that were classified as held for sale and shut-in assets in the South, Cold Lake and Northwest operating areas.

Power

In the second quarter of 2019, AltaGas recorded pre-tax provisions totaling $0.8 million in the Power segment related to a capital spare which was classified as held for sale. In the third quarter of 2018, AltaGas recorded pre-tax provisions of $352.2 million related to gas-fired peaking plants in California and certain non-core Power assets in Canada that were classified as held for sale, and the Pomona natural gas-fired co-generation facility in the United States.

Provisions on investments accounted for by the equity method

In the third quarter of 2019, AltaGas entered into a definitive agreement for the sale of its indirect, non-operating interest in the Central Penn Pipeline (Central Penn) held by its subsidiary WGL Midstream, Inc. Total gross proceeds for WGL Midstream's interest are expected to be approximately US$657 million. As a result of this pending sale, during the third quarter of 2019, a pre-tax provision of $44.2 million was recorded against AltaGas' investment in Meade Pipeline Co. LLC, which holds WGL Midstream's investment in Central Penn. This equity investment is in the Midstream segment and the provision was recorded in the Consolidated Statements of Income (Loss) under the line item "Income (loss) from equity investments".

In the second quarter of 2019, AltaGas recorded a pre-tax provision of $2.2 million against AltaGas' investment in Craven County Wood Energy LP as a result of a pending sale. The disposition of the investment in this entity was completed in the third quarter of 2019 (Note 4). This equity investment was in the Power segment and the provision was recorded in the Consolidated Statements of Income (Loss) under the line item "Income (loss) from equity investments".

There were no provisions on equity investments recorded during the nine months ended September 30, 2018.

7. Inventory



As at	September 30, 2019		December 31, 2018
Natural gas held in storage	$	386.5	$	418.0
Materials and supplies	57.0		53.3
Renewable energy credits and emission compliance instruments	53.8		38.2
Natural gas liquids	19.9		6.4
	$	517.2	$	515.9

8. Goodwill





As at	September 30, 2019			December 31, 2018
Balance, beginning of period	$	4,068.2		$	817.3
Provisions on assets	—			(124.2		)
Business acquisition (note 3)	—			3,196.4
Adjustment to goodwill on business acquisition (note 3)	92.2			—
Goodwill included in dispositions (note 4)	(25.4		)	—
Reclassified to assets held for sale (note 5)	(4.7		)	—
Foreign exchange translation	(113.7		)	178.7
Balance, end of period	$	4,016.6		$	4,068.2

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 53

9. Long-Term Investments and Other Assets



As at	September 30, 2019		December 31, 2018
Investments in publicly-traded entities	$	3.9	$	8.4
Loan to affiliate	45.0		45.0
Deferred lease receivable	15.6		24.4
Debt issuance costs associated with credit facilities	6.6		7.9
Refundable deposits	12.3		16.2
Prepayment on long-term service agreements	82.5		82.5
Contract asset (note 13)	25.5		11.5
Rabbi trust (notes 19 and 21)	58.2		61.7
Other	25.5		25.5
	$	275.1	$	283.1

10. Variable Interest Entities

Consolidated VIEs

AltaGas consolidates VIEs where the Corporation is deemed the primary beneficiary. The primary beneficiary of a VIE has the power to direct the activities of the entity that most significantly impact its economic performance such as being the provider of construction, operating and marketing services to the entity. In addition, the primary beneficiary of a VIE also has the obligation to absorb losses of the entity or the right to receive benefits that could potentially be significant to the VIE. AltaGas determined that it is the primary beneficiary of the following VIEs:

Ridley Island LPG Export Limited Partnership

On May 5, 2017, AltaGas LPG Limited Partnership (AltaGas LPG), a wholly-owned subsidiary of AltaGas, and Vopak Development Canada Inc. (Vopak), a wholly-owned subsidiary of Koninklijke Vopak N.V. (Royal Vopak), a public company incorporated under the laws of the Netherlands, formed the Ridley Island LPG Export Limited Partnership (RILE LP) to develop, own and operate the Ridley Island Propane Export Terminal (RIPET). AltaGas’ subsidiaries hold a 70 percent interest while Vopak holds a 30 percent interest in RILE LP. The construction cost of RIPET was funded by AltaGas LPG and Vopak in proportion to their respective interests in RILE LP. As part of the arrangements, AltaGas entered into a long-term agreement for the capacity of RIPET with RILE LP, and AltaGas and certain of its subsidiaries will provide construction and operating services to RILE LP.

AltaGas has determined that RILE LP is a VIE in which it holds variable interests and is the primary beneficiary. In the determination that AltaGas is the primary beneficiary of the VIE, AltaGas noted that it has the power to direct the activities that most significantly impact the VIE’s economic performance through the construction, operating and marketing services provided to RILE LP. In addition, AltaGas has the obligation to absorb the losses and the right to receive the benefits that could potentially be significant to RILE LP through the long-term agreement for the capacity of RIPET. As such, AltaGas has consolidated RILE LP.

The assets of RILE LP are the property of RILE LP and are not available to AltaGas for any other purpose. RILE LP’s asset balances can only be used to settle its own obligations. The liabilities of RILE LP do not represent additional claims against AltaGas’ general assets. AltaGas’ exposure to loss as a result of its interest as a limited partner is its net investment. AltaGas and Royal Vopak have provided limited guarantees for the obligations of their respective subsidiaries for the construction cost of RIPET. With the commencement of commercial operations at RIPET, the terms of the long-term capacity agreement between AltaGas LPG and RILE LP provide for a return on and of capital and reimbursement of RIPET operating costs by AltaGas LPG in accordance with the terms set out in the agreement.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 54

Disposal of Consolidated VIE Investments

Prior to the close of the U.S. distributed generation assets in the third quarter of 2019, WGSW Inc. (WGSW) was the primary beneficiary of SFGF LLC (SFGF), SFRC, LLC (SFRC), SFGF II, LLC (SFGF II), SFEE LLC (SFEE), and ASD Solar LP (ASD), because of its ability to direct the activities most significant to the economic performance of those entities plus the right to receive potentially significant benefits or the obligation to absorb potentially significant losses. These VIEs were consolidated until the close of the distributed generation asset sale (Note 4). As at September 30, 2019, these entities are no longer VIEs of AltaGas.

The following table represents amounts included in the Consolidated Balance Sheets attributable to AltaGas’ consolidated VIEs:




As at	September 30, 2019			December 31, 2018
As at	September 30, 2019			December 31, 2018
Current assets	$	23.5		$	1,383.5
Property, plant and equipment	357.9			619.2
Long-term investments and other assets	56.8			48.0
Operating right of use assets	0.1			—
Current liabilities	(4.1		)	(161.8		)
Asset retirement obligations	(0.9		)	(0.9		)
Other long term liabilities	(0.1		)	(3.0		)
Net assets	$	433.2		$	1,885.0

The decrease in current assets and current liabilities associated with AltaGas’ consolidated VIEs at September 30, 2019 compared to December 31, 2018 is primarily due to the sale of Northwest Hydro Limited Partnership in January 2019 (Note 4) and the sale of VIEs included in the sale of WGL's distributed generation portfolio (Note 4).

Unconsolidated VIE Investments

Meade Pipeline Co. LLC (Meade)

In 2014, WGL Midstream and certain partners entered into a limited liability company agreement and formed Meade, a Delaware limited liability company, to develop and own, jointly with Transcontinental Gas Pipe Line Company, LLC, a regulated pipeline, Central Penn Pipeline (Central Penn), which is a segment of the larger Atlantic Sunrise project. Central Penn is an approximately 185-mile pipeline originating in Susquehanna County, Pennsylvania and extending to Lancaster County, Pennsylvania with the capacity to transport and deliver up to approximately 1.7 Bcf per day of natural gas.

As at September 30, 2019, AltaGas held an equity investment in Meade with a carrying value of $825.7 million, inclusive of fair value adjustments on acquisition date (Note 3). WGL Midstream owns a 55 percent interest in Meade (21 percent indirect interest in Central Penn). Although WGL Midstream holds greater than a 50 percent interest in Meade, Meade is not consolidated by WGL Midstream and instead is accounted for under the equity method of accounting. WGL Midstream is not the primary beneficiary of Meade as it does not have the power to direct the activities most significant to the economic performance of Meade. WGL Midstream applies the HLBV equity method of accounting and any profits and losses are included in “income (loss) from equity investments” in the accompanying Consolidated Statements of Income (Loss) and are added to or subtracted from the carrying amount of AltaGas’ investment balance. On September 30, 2019, AltaGas announced that it has entered into a definitive agreement for the sale of its interest in Central Penn for gross proceeds of approximately US$657 million. A pre-tax provision of $44.2 million was recorded against the investment in Meade in the third quarter of 2019 (Note 6).

The maximum financial exposure to loss as a result of the involvement with this VIE is equal to WGL Midstream's capital contributions.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 55

11. Long-Term Debt





As at	Maturity date	September 30, 2019			December 31, 2018
Credit facilities
$1,400 million unsecured extendible revolving facility ^(a)	15-May-2023	$	387.0		$	964.7
US$300 million unsecured extendible revolving facility ^(b)	15-May-2022	—			287.8
Acquisition credit facility ^(c)	6-Jan-2020	—			113.2
US$1,200 million revolving credit facility ^(d)	28-Dec-2021	516.5			1,637.0
US$300 million unsecured term facility ^(e)	27-Feb-2021	397.3			—
Medium-term notes (MTNs)
$200 million Senior unsecured - 4.55 percent	17-Jan-2019	—			200.0
$200 million Senior unsecured - 4.07 percent	1-Jun-2020	200.0			200.0
$350 million Senior unsecured - 3.72 percent	28-Sep-2021	350.0			350.0
$300 million Senior unsecured - 3.57 percent	12-Jun-2023	300.0			300.0
$200 million Senior unsecured - 4.40 percent	15-Mar-2024	200.0			200.0
$300 million Senior unsecured - 3.84 percent	15-Jan-2025	299.9			299.9
$100 million Senior unsecured - 5.16 percent	13-Jan-2044	100.0			100.0
$300 million Senior unsecured - 4.50 percent	15-Aug-2044	299.8			299.8
$350 million Senior unsecured - 4.12 percent	7-Apr-2026	349.9			349.8
$200 million Senior unsecured - 3.98 percent	4-Oct-2027	199.9			199.9
$250 million Senior unsecured - 4.99 percent	4-Oct-2047	250.0			250.0
WGL and Washington Gas medium-term notes
US$450 million Senior unsecured - 2.25 to 4.76 percent ^(f)	Nov 2019	595.9			682.1
US$250 million Senior unsecured - 2.68 percent ^(g)	12-Mar-2020	331.1			341.1
US$20 million Senior unsecured - 6.65 percent	20-Mar-2023	26.5			27.3
US$40.5 million Senior unsecured - 5.44 percent	11-Aug-2025	53.6			55.3
US$53 million Senior unsecured - 6.62 to 6.82 percent	Oct - 2026	70.2			72.3
US$72 million Senior unsecured - 6.40 to 6.57 percent	Feb - Sep 2027	95.3			98.2
US$52 million Senior unsecured - 6.57 to 6.85 percent	Jan - Mar 2028	68.9			70.9
US$8.5 million Senior unsecured - 7.50 percent	1-Apr-2030	11.3			11.6
US$50 million Senior unsecured - 5.70 to 5.78 percent	Jan - Mar 2036	66.2			68.2
US$75 million Senior unsecured - 5.21 percent	3-Dec-2040	99.3			102.3
US$75 million Senior unsecured - 5.00 percent	15-Dec-2043	99.3			102.3
US$300 million Senior unsecured - 4.22 to 4.60 percent	Sep - Dec 2044	397.3			409.3
US$450 million Senior unsecured - 3.80 percent	15-Sep-2046	595.9			613.9
US$300 million Senior unsecured - 3.65 percent	16-Sep-2049	397.3			—
SEMCO long-term debt
US$300 million SEMCO Senior Secured - 5.15 percent ^(h)	21-Apr-2020	397.3			409.3
US$82 million SEMCO Senior Secured - 4.48 percent ⁽ⁱ⁾	2-Mar-2032	77.6			86.3
Fair value adjustment on WGL Acquisition (note 3)		86.3			89.0
Finance lease liabilities (note 15)		7.1			0.8
		$	7,326.7		$	8,992.3
Less debt issuance costs		(36.7		)	(35.2		)
		$	7,290.0		$	8,957.1
Less current portion		(1,531.3		)	(890.2		)
		$	5,758.7		$	8,066.9


(a)	Borrowings on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers' acceptances, or letters of credit. Borrowings on the facility have fees and interest at rates relevant to the nature of the draw made.


(b)	Borrowings on the facility can be by way of U.S. base-rate loans, U.S. prime loans, LIBOR loans, or letters of credit.


(c)	The acquisition facility was repaid in full and canceled on February 1, 2019.


(d)	Borrowings on the facility can be by way of U.S. base-rate loans, U.S. prime loans, or LIBOR loans.


(e)	Borrowings on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, or bankers’ acceptances.


(f)	Certain MTNs have a floating rate per annum reset quarterly based on terms set forth in the prospectus supplement filed by WGL pursuant to Securities Act Rule 424 on November 27, 2017.


(g)	Floating rate per annum reset quarterly based on terms set forth in the prospectus filed by WGL pursuant to Securities Act Rule 424 on March 13, 2018.


(h)	Collateral for the US$ MTNs is certain SEMCO assets.


(i)	Collateral for the CINGSA Senior secured loan is certain CINGSA assets. Alaska Storage Holding Company, LLC, a subsidiary in which AltaGas has a controlling interest, is the non-recourse guarantor of this loan.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 56

12. Accumulated Other Comprehensive Income





	Available-for-sale			Defined benefit pension and PRB plans			Hedge net investments			Translation foreign operations			Equity investee			Total
Opening balance, January 1, 2019	$	—		$	(19.0	)	$	(209.2	)	$	801.4		$	5.8		$	579.0
OCI before reclassification	—			—			59.5			(260.5		)	(1.8		)	(202.8		)
Amounts reclassified from OCI	—			2.4			—			—			—			2.4
Current period OCI (pre-tax)	—			2.4			59.5			(260.5		)	(1.8		)	(200.4		)
Income tax on amounts retained in AOCI	—			—			(7.1		)	—			—			(7.1		)
Income tax on amounts reclassified to earnings	—			1.3			—			—			—			1.3
Net current period OCI	—			3.7			52.4			(260.5		)	(1.8		)	(206.2		)
Ending balance, September 30, 2019	$	—		$	(15.3	)	$	(156.8	)	$	540.9		$	4.0		$	372.8

Opening balance, January 1, 2018	$	(7.1	)	$	(11.4	)	$	(129.0	)	$	342.9		$	3.7		$	199.1
OCI before reclassification	—			—			37.4			4.0			0.8			42.2
Amounts reclassified from AOCI	—			0.6			—			—			—			0.6
Adoption of ASU No. 2016-01	7.1			—			—			—			—			7.1
Curtailment of DB and PRB plan	—			4.2			—			—			—			4.2
Current period OCI (pre-tax)	7.1			4.8			37.4			4.0			0.8			54.1
Income tax on amounts reclassified to earnings	—			(0.2		)	—			—			—			(0.2		)
Income tax on amounts related to curtailment of DB and PRB plan	—			(1.5		)	—			—			—			(1.5		)
Net current period OCI	7.1			3.1			37.4			4.0			0.8			52.4
Ending balance, September 30, 2018	$	—		$	(8.3	)	$	(91.6	)	$	346.9		$	4.5		$	251.5

Reclassification From Accumulated Other Comprehensive Income




AOCI components reclassified	Income statement line item	Three months ended September 30, 2019		Three months ended September 30, 2018
Defined benefit pension and PRB plans	Other income	$	0.2	$	0.2
Deferred income taxes	Income tax expense (recovery) – deferred	0.9		(0.1		)
		$	1.1	$	0.1



AOCI components reclassified	Income statement line item	Nine months ended September 30, 2019		Nine months ended September 30, 2018
Defined benefit pension and PRB plans	Other income	$	2.4	$	0.6
Deferred income taxes	Income tax expense (recovery) – deferred	1.3		(0.2		)
		$	3.7	$	0.4

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 57

13. Revenue

The following tables disaggregate revenue by major sources for the period:




	Three months ended September 30, 2019
	Utilities		Midstream			Power			Corporate		Total
Revenue from contracts with customers
Commodity sales contracts	$	—	$	239.2		$	312.2		$	—	$	551.4
Midstream service contracts	—		36.0			—			—		36.0
Gas sales and transportation services	244.9		—			—			—		244.9
Storage services	5.0		—			—			—		5.0
Other	2.2		1.6			6.7			—		10.5
Total revenue from contracts with customers	$	252.1	$	276.8		$	318.9		$	—	$	847.8

Other sources of revenue
Revenue from alternative revenue programs ^(a)	$	8.1	$	—		$	—		$	—	$	8.1
Leasing revenue ^(b)	0.1		34.8			33.4			—		68.3
Risk management and trading activities ^{(c) (d)}	—		(19.9		)	(22.2		)	—		(42.1		)
Other	1.1		(0.1		)	5.3			—		6.3
Total revenue from other sources	$	9.3	$	14.8		$	16.5		$	—	$	40.6
Total revenue	$	261.4	$	291.6		$	335.4		$	—	$	888.4


(a)	A large portion of revenue generated from the Utilities segment is subject to rate regulation and accordingly there are circumstances where the revenue recognized is mandated by the applicable regulators in accordance with ASC 980.


(b)	Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Power segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases.


(c)	Risk management activities involve the use of derivative instruments such as physical and financial swaps, forward contracts, and options. These derivatives are accounted for under ASC 815 and ASC 825. The majority of revenue generated by the Midstream and Power segments is from the physical sale and delivery of natural gas and power to end users, except for WGL Midstream (see footnote d).

(d)

WGL Midstream trading margins are reported in risk management and trading activities from the Midstream segment. WGL Midstream enters into derivative contracts for the purpose of optimizing its storage and transportation capacity as well as managing the transportation and storage assets on behalf of third parties. The trading margins of WGL Midstream, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues for the three months ended September 30, 2019 of $103.6 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract, which are in scope of ASC 606, are reported within risk management and trading activities. While the GAIL contract is individually not accounted for as a derivative, it is inseparable from the overall trading portfolio of WGL Midstream. Revenue is recognized at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount. The GAIL contract has a term of 20 years and began on March 31, 2018.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 58




	Nine months ended September 30, 2019
	Utilities			Midstream		Power		Corporate		Total
Revenue from contracts with customers
Commodity sales contracts	$	—		$	718.8	$	863.7	$	—	$	1,582.5
Midstream service contracts	—			108.1		—		—		108.1
Gas sales and transportation services	1,718.4			—		—		—		1,718.4
Storage services	21.7			—		—		—		21.7
Other	6.8			2.7		24.5		—		34.0
Total revenue from contracts with customers	$	1,746.9		$	829.6	$	888.2	$	—	$	3,464.7

Other sources of revenue
Revenue from alternative revenue programs ^(a)	$	23.3		$	—	$	—	$	—	$	23.3
Leasing revenue ^(b)	0.6			104.1		81.5		—		186.2
Risk management and trading activities ^{(c) (d)}	—			217.2		51.7		0.2		269.1
Other	(1.2		)	0.3		18.0		—		17.1
Total revenue from other sources	$	22.7		$	321.6	$	151.2	$	0.2	$	495.7
Total revenue	$	1,769.6		$	1,151.2	$	1,039.4	$	0.2	$	3,960.4


(a)	A large portion of revenue generated from the Utilities segment is subject to rate regulation and accordingly there are circumstances where the revenue recognized is mandated by the applicable regulators in accordance with ASC 980.


(b)	Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Power segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases.


(c)	Risk management activities involve the use of derivative instruments such as physical and financial swaps, forward contracts, and options. These derivatives are accounted for under ASC 815 and ASC 825. The majority of revenue generated by the Midstream and Power segments is from the physical sale and delivery of natural gas and power to end users, except for WGL Midstream (see footnote d).

(d)

WGL Midstream trading margins are reported in risk management and trading activities from the Midstream segment. WGL Midstream enters into derivative contracts for the purpose of optimizing its storage and transportation capacity as well as managing the transportation and storage assets on behalf of third parties. The trading margins of WGL Midstream, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues for the nine months ended September 30, 2019 of $393.4 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract, which are in scope of ASC 606, are reported within risk management and trading activities. While the GAIL contract is individually not accounted for as a derivative, it is inseparable from the overall trading portfolio of WGL Midstream. Revenue is recognized at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount. The GAIL contract has a term of 20 years and began on March 31, 2018.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 59




	Three months ended September 30, 2018
	Utilities			Midstream		Power		Corporate			Total
Revenue from contracts with customers
Commodity sales contracts	$	—		$	170.5	$	250.7	$	—		$	421.2
Midstream service contracts	—			50.3		—		—			50.3
Gas sales and transportation services	286.7			—		—		—			286.7
Storage services	8.3			—		—		—			8.3
Other	2.9			—		8.4		—			11.3
Total revenue from contracts with customers	$	297.9		$	220.8	$	259.1	$	—		$	777.8

Other sources of revenue
Revenue from alternative revenue programs ^(a)	$	13.3		$	—	$	—	$	—		$	13.3
Leasing revenue ^(b)	0.2			23.8		122.5		—			146.5
Risk management and trading activities ^{(c) (d)}	(0.3		)	61.0		55.0		(14.7		)	101.0
Other	(1.6		)	—		4.4		—			2.8
Total revenue from other sources	$	11.6		$	84.8	$	181.9	$	(14.7	)	$	263.6
Total revenue	$	309.5		$	305.6	$	441.0	$	(14.7	)	$	1,041.4


(a)	A large portion of revenue generated from the Utilities segment is subject to rate regulation and accordingly there are circumstances where the revenue recognized is mandated by the applicable regulators in accordance with ASC 980.


(b)	Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Power segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases.


(c)	Risk management activities involve the use of derivative instruments such as physical and financial swaps, forward contracts, and options. These derivatives are accounted for under ASC 815 and ASC 825. Revenue generated by the Midstream and Power segments is from the physical sale and delivery of natural gas and power to end users, except for WGL Midstream (see footnote d).

(d)

WGL Midstream trading margins are reported in risk management and trading activities from the Midstream segment. WGL Midstream enters into derivative contracts for the purpose of optimizing its storage and transportation capacity as well as managing the transportation and storage assets on behalf of third parties. The trading margins of WGL Midstream, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues for the three months ended September 30, 2018 of $114.1 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract, which are in scope of ASC 606, are reported within risk management and trading activities. While the GAIL contract is individually not accounted for as a derivative, it is inseparable from the overall trading portfolio of WGL Midstream. Revenue is recognized at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount. The GAIL contract has a term of 20 years and began on March 31, 2018.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 60




	Nine months ended September 30, 2018
	Utilities		Midstream			Power		Corporate			Total
Revenue from contracts with customers
Commodity sales contracts	$	—	$	391.8		$	250.7	$	—		$	642.5
Midstream service contracts	—		152.1			—		—			152.1
Gas sales and transportation services	894.3		—			—		—			894.3
Storage services	26.5		—			—		—			26.5
Other	8.2		0.6			8.4		—			17.2
Total revenue from contracts with customers	$	929.0	$	544.5		$	259.1	$	—		$	1,732.6

Other sources of revenue
Revenue from alternative revenue programs ^(a)	$	8.8	$	—		$	—	$	—		$	8.8
Leasing revenue ^(b)	0.3		71.5			287.0		—			358.8
Risk management and trading activities ^{(c) (d)}	0.8		249.0			194.2		(29.4		)	414.6
Other	3.2		(0.2		)	11.8		—			14.8
Total revenue from other sources	$	13.1	$	320.3		$	493.0	$	(29.4	)	$	797.0
Total revenue	$	942.1	$	864.8		$	752.1	$	(29.4	)	$	2,529.6


(a)	A large portion of revenue generated from the Utilities segment is subject to rate regulation and accordingly there are circumstances where the revenue recognized is mandated by the applicable regulators in accordance with ASC 980.


(b)	Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Power segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases.


(c)	Risk management activities involve the use of derivative instruments such as physical and financial swaps, forward contracts, and options. These derivatives are accounted for under ASC 815 and ASC 825. Revenue generated by the Midstream and Power segments is from the physical sale and delivery of natural gas and power to end users, except for WGL Midstream (see footnote d).

(d)

WGL Midstream trading margins are reported in risk management and trading activities from the Midstream segment. WGL Midstream enters into derivative contracts for the purpose of optimizing its storage and transportation capacity as well as managing the transportation and storage assets on behalf of third parties. The trading margins of WGL Midstream, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues for the nine months ended September 30, 2018 of $114.1 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract, which are in scope of ASC 606, are reported within risk management and trading activities. While the GAIL contract is individually not accounted for as a derivative, it is inseparable from the overall trading portfolio of WGL Midstream. Revenue is recognized at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount. The GAIL contract has a term of 20 years and began on March 31, 2018.

Revenue Recognition

The following is a description of the Corporation’s revenue recognition policy by segment and by major source of revenue from contracts with customers.

Utilities Segment

Gas Sales and Transportation Services

Customers are billed monthly based on regular meter readings. Customer billings are based on two main components: (i) a fixed service fee and (ii) a variable fee based on usage. Revenue is recognized over time when the gas has been delivered or as the service has been performed. As meter readings are performed on a cycle basis, AltaGas recognizes accrued revenue for any services rendered to its customers but not billed at month-end. The vast majority of these contracts are “at-will” as customers may cancel their service at any time, however, there are certain contracts that have terms of one year or longer. For these long-term contracts, there is generally a contract demand specified in the contract whereby the customer has to pay regardless of whether or not gas has been delivered. These contracts generally do not contain any make up rights and revenue is recognized on a monthly basis as service has been performed.

Gas Storage Services

Gas storage customers are billed monthly for services provided. Customer billings are based on four components: (i) reservation charges; (ii) capacity charges; (iii) injection/withdrawal charges; and (iv) excess charges. Reservation charges are based on the

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 61

customer’s contract withdrawal quantity, capacity charges are based on the customer’s total contract quantity, and injection/withdrawal charges are based on the volume of gas delivered to or from the customer. Excess charges are applied to each day that the storage quantity exceeds 100 percent of the customer’s maximum storage quantity. Revenue is recognized as the service has been performed over time on a monthly basis, which corresponds to the invoice amount. The majority of these contracts have terms extending beyond one year.

Midstream Segment

Commodity Sales

A portion of the NGL production from AltaGas’ extraction facilities is subject to frac spread between NGLs extracted and the natural gas purchased to make up the heating value of the NGLs extracted. For commodity sales contracts that do not meet the definition of a derivative or for contracts whereby AltaGas has elected to apply the normal purchase normal sales scope exception, the sales contract is accounted for under ASC 606. These commodity sales contracts have varying terms but the majority of the contracts have a one-year term which coincides with the NGL year. AltaGas recognizes revenue for commodity sales contracts at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount.

Commodity sales contracts at RIPET generate revenue from the sale and delivery of liquid propane purchased from upstream producers. Revenue from these sales contracts is recognized when propane is loaded onto transport vessels; the delivery point. AltaGas has the right to consideration in an amount that directly corresponds to the volumes of propane loaded on a vessel.

Commodity sales also include gas sales to residential, commercial and industrial customers in certain states where WGL Energy Services is authorized as a competitive service provider. These commodity sales contracts have varying terms that generally range from one to five years. Customers are billed monthly based on the amount of gas delivered to the customer. Revenue is recognized based on the amount the Corporation is entitled to invoice the customer.

Midstream Service Contracts

AltaGas earns revenue from its field gathering and processing facilities, extraction facilities, and transmission systems through a variety of contractual arrangements. For arrangements that do not contain a lease, the revenue is accounted for under ASC 606 as follows:

Fee-for-service – The customer is charged a fee for the service provided on a per unit volume basis. Contract terms generally range from one month to up to the life of the reserves. Revenue under this type of arrangement is recognized over time as the service is provided, which corresponds to the customer’s monthly invoice amount.

Take-or-pay – The customer has agreed to a minimum volume commitment whereby the customer must have AltaGas process or deliver a specified volume at a rate per unit that is specified in the contract. Quantities that the customer is unable to deliver are considered deficiency quantities. Certain of AltaGas’ take-or-pay contracts contain provisions whereby the customer can make up deficiency quantities in subsequent periods. Under this type of arrangement, any consideration received relating to the deficiency quantities that will be made up in a future period will be deferred until either: (i) the customer makes up the volumes or (ii) the likelihood that the customer will make up the volumes before the make up period expires becomes remote. If AltaGas does not expect the customer to make up the deficiency quantities (also referred to as breakage amount), AltaGas may recognize the expected breakage amount as revenue before the make up period expires. Significant judgment is required in estimating the breakage amount. For contracts where the customer has no make up rights, revenue is recognized on a monthly basis based on the higher of (i) the actual quantity delivered times the per unit rate or (ii) the contracted minimum amount.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 62

Power Segment

For the Power segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases. In instances where power generation is not sold under a power purchase agreement, the commodity is sold via a merchant market, or via commodity sales agreements which are accounted for as financial instruments. For commodity sales contracts that do not meet the definition of a lease, derivative or for contracts whereby AltaGas has elected to apply the normal purchase normal sales scope exception, the sales contract is accounted for under ASC 606.

Commodity Sales

Energy generated from commercial solar and combined heating and power assets is sold under long term power purchase agreements with a general duration of approximately 20 years. These long term purchase agreements provide stable cash flow by way of contracted prices for the underlying commodities. In the third quarter of 2019, AltaGas closed the sale of it's U.S. portfolio of distributed generation assets, which included wholly owned solar and fuel cell projects and tax equity partnership interests (Note 4). Subsequent to the sale, AltaGas will continue to generate energy from its from combined heating and power assets.

Commodity sales also include electricity sales to residential, commercial and industrial customers in certain states where WGL Energy Services is authorized as a competitive service provider. These commodity sales contracts have varying terms that generally range from one to five years. Customers are billed monthly based on meter readings or the amount of energy delivered to the customer. Revenue is recognized based on the amount the Corporation is entitled to invoice the customer.

Contract Balances

As at September 30, 2019, a contract asset of $25.5 million has been recorded within long-term investments and other assets on the Consolidated Balance Sheets (December 31, 2018 – $11.5 million). This contract asset represents the difference in revenue recognized under a new rate in a blend-and-extend contract modification with a customer. Revenue from this contract modification will be recognized at the pre-modification rate for the remainder of the original term with the excess revenue recorded as a contract asset. The contract asset will be drawn down over the remaining term of the modified contract.

In addition, at September 30, 2019 there is a contract asset of $57.0 million (December 31, 2018 - $47.3 million) recorded within prepaid expenses and other current assets on the Consolidated Balance Sheets for WGL Energy Systems’ unbilled revenue relating to design-build construction contracts. The contract asset represents unbilled amounts typically resulting from sales under contracts when the cost-to-cost method of revenue recognition is utilized, and revenue recognized exceeds the amount billed to the customer. Right to payment is achieved when the projects are formally “accepted” by the federal government. At September 30, 2019, contract liabilities of $0.9 million (December 31, 2018 - $2.2 million) have been recorded within other current liabilities on the Consolidated Balance Sheets. The contract liabilities consist of advance payments and billings in excess of revenue recognized and deferred revenue. Contract assets and liabilities are reported in a net position on a contract-by-contract basis at the end of each reporting period.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 63

Contract Assets




	September 30, 2019			December 31, 2018
As at	September 30, 2019			December 31, 2018
Balance, beginning of period	$	58.8		$	—
Additions	25.2			130.1
Transfers to held for sale ^(a)	—			(72.2		)
Transfers to accounts receivable ^(b)	—			(3.7		)
Foreign exchange translation	(1.5		)	4.6
Balance, end of period	$	82.5		$	58.8


(a)	In the fourth quarter of 2018, WGL Energy Systems reached an agreement for the sale of a financing receivable included in the contract asset balance. Accordingly, the receivable was classified as held for sale at December 31, 2018. In February 2019, WGL Energy Systems completed the sale of the financing receivable (Note 4).


(b)	Amounts included in contract assets are transferred to accounts receivable when AltaGas’ right to consideration becomes unconditional.

Contract Liabilities




As at	September 30, 2019			December 31, 2018
As at	September 30, 2019			December 31, 2018
Balance, beginning of period	$	2.2		$	—
Additions	1.1			2.6
Revenue recognized from contract liabilities ^(a)	(2.3		)	(0.5		)
Foreign exchange translation	(0.1		)	0.1
Balance, end of period	$	0.9		$	2.2


(a)	Recognition of revenue related to performance obligations satisfied in the current period for amounts that were previously included in contract liabilities.

Transaction price allocated to the remaining obligations

The following table includes estimated revenue expected to be recognized in the future related to performance obligations that are unsatisfied as of September 30, 2019:



	Remainder of 2019		2020		2021		2022		2023		> 2023		Total
Midstream service contracts	$	12.7	$	52.9	$	29.9	$	29.4	$	26.5	$	219.1	$	370.5
Storage services	6.6		24.6		24.6		23.8		23.6		194.6		297.8
Other	16.3		14.9		2.2		1.6		1.6		7.7		44.3
	$	35.6	$	92.4	$	56.7	$	54.8	$	51.7	$	421.4	$	712.6

AltaGas applies the practical expedient available under ASC 606 and does not disclose information about the remaining performance obligations for (i) contracts with an original expected length of one year or less, (ii) contracts for which revenue is recognized at the amount to which AltaGas has the right to invoice for performance completed, and (iii) contracts with variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation. In addition, the table above does not include any estimated amounts of variable consideration that are constrained. The majority of midstream service contracts, gas sales and transportation service contracts, and storage service contracts contain variable consideration whereby uncertainty related to the associated variable consideration will be resolved (usually on a daily basis) as volumes are processed, gas is delivered or as service is provided.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 64

14. Financial Instruments and Financial Risk Management

The Corporation’s financial instruments consist of cash and cash equivalents, accounts receivable, risk management contracts, certain long-term investments and other assets, accounts payable and accrued liabilities, dividends payable, short-term and long-term debt, and certain other current and long-term liabilities.

Fair Value Hierarchy

AltaGas categorizes its financial assets and financial liabilities into one of three levels based on fair value measurements and inputs used to determine the fair value.

Level 1 - fair values are based on unadjusted quoted prices in active markets for identical assets or liabilities. Fair values are based on direct observations of transactions involving the same assets or liabilities and no assumptions are used. Included in this category are publicly traded shares valued at the closing price as at the balance sheet date.

Level 2 - fair values are determined based on valuation models and techniques where inputs other than quoted prices included within Level 1 are observable for the asset or liability either directly or indirectly. AltaGas enters into derivative instruments in the futures, over-the-counter, and retail markets to manage fluctuations in commodity prices and foreign exchange rates. The fair values of power, natural gas, and NGL derivative contracts were calculated using forward prices based on published sources for the relevant period, adjusted for factors specific to the asset or liability, including basis and location differentials, discount rates, and currency exchange. The fair value of foreign exchange derivative contracts was calculated using quoted market rates. The fair value of foreign exchange option contracts was calculated using a variation of the Black-Scholes pricing model.

Level 3 - fair values are based on inputs for the asset or liability that are not based on observable market data. AltaGas uses valuation techniques when observable market data is not available. A variety of valuation methodologies are used to determine the fair value of Level 3 derivative contracts, including developed valuation inputs and pricing models. The prices used in the valuations are corroborated using multiple pricing sources, and the Corporation periodically conducts assessments to determine whether each valuation model is appropriate for its intended purpose. Level 3 derivatives include physical contracts at illiquid market locations with no observable market data, long-dated positions where observable pricing is not available over the life of the contract, contracts valued using historical spot price volatility assumptions, and valuations using indicative broker quotes for inactive market locations.

The following methods and assumptions were used to estimate the fair value of each significant class of financial instruments:

Other current liabilities - the carrying amounts approximate fair value because of the short maturity of these instruments.

Current portion of long-term debt, Long-term debt and Other long-term liabilities - the fair value of these liabilities was estimated based on discounted future interest and principal payments using the current market interest rates of instruments with similar terms. The fair value of Level 3 long-term debt was determined by taking the present value of the debt securities’ future cash flows discounted at interest rates that reflect market conditions as of the measurement date. The discount rate is based on the quoted market prices of the U.S. Treasury issues having a similar term to maturity, adjusted for the credit quality of the debt issuer.

Risk management assets and liabilities - the fair values of power, natural gas, and NGL derivative contracts were calculated using forward prices from published sources for the relevant period. The fair value of foreign exchange derivative contracts was calculated using quoted market rates. The fair value of Level 3 derivative contracts was calculated using internally developed valuation inputs and pricing models.

Equity securities – the fair value of equity securities was calculated using quoted market prices.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 65

Loans and receivables – the fair value of these assets was estimated based on discounted future interest and principal payments using the current market interest rates of instruments with similar terms.




As at	September 30, 2019
	Carrying Amount		Level 1		Level 2		Level 3		Total Fair Value
Financial assets
Fair value through net income ^(a)
Risk management assets - current	$	66.2	$	—	$	40.4	$	25.8	$	66.2
Risk management assets - non-current	40.0		—		11.7		28.3		40.0
Equity securities ^(b)	3.9		3.9		—		—		3.9
Fair value through regulatory assets/liabilities ^(a)
Risk management assets - current	2.9		—		0.5		2.4		2.9
Risk management assets - non-current	6.9		—		—		6.9		6.9
Amortized cost
Loans and receivables ^(b)	45.0		—		46.2		—		46.2
	$	164.9	$	3.9	$	98.8	$	63.4	$	166.1
Financial liabilities
Fair value through net income ^(a)
Risk management liabilities - current	$	57.0	$	—	$	40.2	$	16.8	$	57.0
Risk management liabilities - non-current	80.0		—		18.7		61.3		80.0
Fair value through regulatory assets/liabilities ^(a)
Risk management liabilities - current	11.4		—		0.1		11.3		11.4
Risk management liabilities - non-current	98.3		—		—		98.3		98.3
Amortized cost
Current portion of long-term debt	1,531.3		—		1,531.3		—		1,531.3
Long-term debt^(c)	5,758.7		—		3,920.1		2,209.1		6,129.2
Other current liabilities^(d)	8.4		—		8.4		—		8.4
Other long-term liabilities ^(d)	2.0		—		2.0		—		2.0
	$	7,547.1	$	—	$	5,520.8	$	2,396.8	$	7,917.6

(a)

To manage price risk associated with acquiring natural gas supply for Maryland, Virginia, and District of Columbia utility customers, Washington Gas, a subsidiary of the Corporation, enters into physical and financial derivative transactions. Any gains and losses associated with these derivatives are recorded as regulatory liabilities or assets, respectively, to reflect the rate treatment for these economic hedging activities. Additionally, as part of its asset optimization program, Washington Gas enters into derivatives with the primary objective of securing operating margins that Washington Gas will ultimately realize. Regulatory sharing mechanisms provide for the annual realized profit from these transactions to be shared between Washington Gas' shareholder and customers; therefore, changes in fair value are recorded through earnings, or as regulatory assets or liabilities to the extent that it is probable that realized gains and losses associated with these derivative transactions will be included in the rates charged to customers when they are realized.


(b)	Included under the line item "long-term investments and other assets" on the Consolidated Balance Sheets.


(c)	Long term debt classified as Level 3 is comprised of the long term portion of WGL and Washington Gas medium-term notes (MTN). These MTNs are classified as Level 3 as they are not traded frequently or publicly traded at all, which makes observable market prices non-existent or stale.


(d)	Excludes non-financial liabilities.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 66





As at	December 31, 2018
	Carrying Amount		Level 1		Level 2		Level 3		Total Fair Value
Financial assets
Fair value through net income ^(a)
Risk management assets - current	$	99.0	$	—	$	68.3	$	30.7	$	99.0
Risk management assets - non-current	49.0		—		18.0		31.0		49.0
Equity securities ^(b)	8.4		8.4		—		—		8.4
Fair value through regulatory assets/liabilities ^(a)
Risk management assets - current	15.1		—		2.7		12.4		15.1
Risk management assets - non-current	8.7		—		—		8.7		8.7
Amortized cost
Loans and receivables ^(b)	45.0		—		45.2		—		45.2
	$	225.2	$	8.4	$	134.2	$	82.8	$	225.4
Financial liabilities
Fair value through net income ^(a)
Risk management liabilities - current	72.0		—		41.3		30.7		72.0
Risk management liabilities - non-current	103.4		—		15.3		88.1		103.4
Fair value through regulatory assets/liabilities ^(a)
Risk management liabilities - current	17.3		—		2.9		14.4		17.3
Risk management liabilities - non-current	109.6		—		0.1		109.5		109.6
Amortized cost
Current portion of long-term debt	890.2		—		884.4		—		884.4
Long-term debt ^(c)	8,066.9		—		6,027.6		2,012.7		8,040.3
Other current liabilities^(d)	11.2		—		11.2		—		11.2
Other long-term liabilities ^(d)	2.0		—		2.0		—		2.0
	$	9,272.6	$	—	$	6,984.8	$	2,255.4	$	9,240.2

(a)


(b)	Included under the line item "long-term investments and other assets" on the Consolidated Balance Sheets.


(c)	Long term debt classified as Level 3 is comprised of the long term portion of WGL and Washington Gas medium-term notes (MTN). These MTNs are classified as Level 3 as they are not traded frequently or publicly traded at all, which makes observable market prices non-existent or stale.


(d)	Excludes non‑financial liabilities.

The following table includes quantitative information about the significant unobservable inputs used in the fair value measurement of Level 3 financial instruments at September 30, 2019:




	Net Fair Value			Valuation Technique	Unobservable Inputs	Range
Natural gas	$	(121.4	)	Discounted Cash Flow	Natural Gas Basis Price (per Dth)	$	(1.46	)	-	$	4.60
Natural gas	$	(2.8	)	Option Model	Natural Gas Basis Price (per Dth)	$	(1.13	)	-	$	3.91
					Annualized Volatility of Spot Market Natural Gas	38		%	-	1,200		%
Electricity	$	(0.1	)	Discounted Cash Flow	Electricity Congestion Price (per MWh)	$	(6.79	)	-	$	76.08

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 67

The following tables provide a reconciliation of changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy:



For the three months ended	September 30, 2019									September 30, 2018
	Natural Gas			Electricity			Total			Natural Gas			Electricity			Total
Balance, beginning of period	$	(92.2	)	$	13.3		$	(78.9	)	$	—		$	—		$	—
Acquired (note 3)	—			—			—			(136.1		)	(10.6		)	(146.7		)
Realized and unrealized gains:
Recorded in income	(12.0		)	(22.5		)	(34.5		)	8.4			(11.8		)	(3.4		)
Recorded in regulatory assets	(13.3		)	—			(13.3		)	1.7			—			1.7
Transfers into Level 3	(3.7		)	—			(3.7		)	—			—			—
Transfers out of Level 3	4.6			—			4.6			0.8			—			0.8
Purchases	—			—			—			—			3.8			3.8
Settlements	(6.5		)	8.8			2.3			1.7			(0.8		)	0.9
Foreign exchange translation	(1.1		)	0.3			(0.8		)	1.7			0.1			1.8
Balance, end of period	$	(124.2	)	$	(0.1	)	$	(124.3	)	$	(121.8	)	$	(19.3	)	$	(141.1	)



For the nine months ended	September 30, 2019									September 30, 2018
	Natural Gas			Electricity			Total			Natural Gas			Electricity			Total
Balance, beginning of period	$	(148.5	)	$	(14.7	)	$	(163.2	)	$	—		$	—		$	—
Acquired (note 3)	—			—			—			(136.1		)	(10.6		)	(146.7		)
Realized and unrealized gains:
Recorded in income	25.2			2.9			28.1			8.4			(11.8		)	(3.4		)
Recorded in regulatory assets	5.7			—			5.7			1.7			—			1.7
Transfers into Level 3	(8.9		)	—			(8.9		)	—			—			—
Transfers out of Level 3	11.8			—			11.8			0.8			—			0.8
Purchases	—			(6.0		)	(6.0		)	—			3.8			3.8
Settlements	(13.7		)	17.3			3.6			1.7			(0.8		)	0.9
Foreign exchange translation	4.2			0.4			4.6			1.7			0.1			1.8
Balance, end of period	$	(124.2	)	$	(0.1	)	$	(124.3	)	$	(121.8	)	$	(19.3	)	$	(141.1	)

Transfers between different levels of the fair value hierarchy may occur based on fluctuations in the valuation and on the level of observable inputs used to value the instruments from period to period. Transfers into and out of the different levels of the fair value hierarchy are presented at the fair value as of the beginning of the period. Transfers out of Level 3 during the period ended September 30, 2019 were due to an increase in valuations using observable market inputs. Transfers into Level 3 during the period ended September 30, 2019 were due to an increase in unobservable market inputs used in valuations.

Summary of Unrealized Gains (Losses) on Risk Management Contracts Recognized in Net Income (Loss)



	Three months ended September 30						Nine months ended September 30
	2019			2018			2019			2018
Natural gas	$	0.6		$	(3.8	)	$	8.9		$	(15.0	)
Energy exports	(14.0		)	—			(22.0		)	—
NGL frac spread	(2.2		)	(7.4		)	(6.8		)	(4.6		)
Power	0.7			2.2			(2.4		)	(2.9		)
Foreign exchange	—			(1.5		)	1.2			34.5
	$	(14.9	)	$	(10.5	)	$	(21.1	)	$	12.0

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 68

Offsetting of Derivative Assets and Derivative Liabilities

Certain of AltaGas’ risk management contracts are subject to master netting arrangements that create a legally enforceable right for a counterparty to offset the related financial assets and financial liabilities. As part of these master netting agreements, cash, letters of credit, and parental guarantees may be required to be posted or obtained from counterparties in order to mitigate credit risk related to both derivative and non-derivative positions. Collateral balances are also offset against the related counterparties’ derivative positions to the extent the application would not result in the over-collateralization of those derivative positions on the balance sheet.



As at	September 30, 2019
Risk management assets ^(a)	Gross amounts of recognized assets/liabilities		Gross amounts offset in balance sheet			Netting of collateral			Net amounts presented in balance sheet
Natural gas	$	137.8	$	(85.7	)	$	—		$	52.1
Energy exports	10.4		(4.9		)	11.6			17.1
NGL frac spread	9.4		(0.1		)	—			9.3
Power	49.5		(12.0		)	—			37.5
	$	207.1	$	(102.7	)	$	11.6		$	116.0

Risk management liabilities ^(b)
Natural gas	$	265.0	$	(85.7	)	$	(5.0	)	$	174.3
Energy exports	31.6		(4.9		)	—			26.7
NGL frac spread	0.1		(0.1		)	—			—
Power	57.3		(12.0		)	0.4			45.7
	$	354.0	$	(102.7	)	$	(4.6	)	$	246.7


(a)	Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $69.1 million and risk management assets (non‑current) balance of $46.9 million.


(b)	Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $68.4 million and risk management liabilities (non‑current) balance of $178.3 million.



As at	December 31, 2018
Risk management assets ^(a)	Gross amounts of recognized assets/liabilities		Gross amounts offset in balance sheet			Netting of collateral			Net amounts presented in balance sheet
Natural gas	$	200.8	$	(82.0	)	$	—		$	118.8
NGL frac spread	18.7		(0.7		)	—			18.0
Power	42.8		(7.8		)	—			35.0
	$	262.3	$	(90.5	)	$	—		$	171.8

Risk management liabilities ^(b)
Natural gas	$	340.4	$	(82.0	)	$	(3.3	)	$	255.1
NGL frac spread	2.7		(0.7		)	—			2.0
Power	50.6		(7.8		)	1.2			44.0
Foreign exchange	1.2		—			—			1.2
	$	394.9	$	(90.5	)	$	(2.1	)	$	302.3


(a)	Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $114.1 million and risk management assets (non‑current) balance of $57.7 million.


(b)	Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $89.3 million and risk management liabilities (non‑current) balance of $213.0 million.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 69

Cash Collateral

The following table presents collateral not offset against risk management assets and liabilities:



As at	September 30, 2019		December 31, 2018
Collateral posted with counterparties	$	22.4	$	27.6
Cash collateral held representing an obligation	$	0.3	$	0.8

Any collateral posted that is not offset against risk management assets and liabilities is included in line item “prepaid expenses and other current assets” in the Consolidated Balance Sheets. Collateral received and not offset against risk management assets and liabilities is included in line item “customer deposits” in the Consolidated Balance Sheets.

Certain derivative instruments contain contract provisions that require collateral to be posted if the credit rating of AltaGas or certain of its subsidiaries falls below certain levels. At September 30, 2019, AltaGas has posted $3.4 million (December 31, 2018 - nil), of collateral related to its derivative liabilities that contained credit-related contingent features. The following table shows the aggregate fair value of all derivative instruments with credit-related contingent features that are in a liability position, as well as the maximum amount of collateral that would be required if specific credit-risk-related contingent features underlying these agreements were triggered:




As at	September 30, 2019		December 31, 2018
Risk management liabilities with credit-risk-contingent features	$	25.4	$	14.7
Maximum potential collateral requirements	$	12.7	$	7.5

Notional Summary

The following table presents the notional quantity outstanding related to the Corporation’s commodity contracts:




As at	September 30, 2019		December 31, 2018
Natural Gas
Sales	739,204,237	GJ	858,640,810 GJ
Purchases	1,447,715,027	GJ	1,638,207,391 GJ
Swaps	529,052,622	GJ	621,578,572 GJ
Energy Exports
Swaps	10,603,134	Bbl	—
NGL Frac Spread
Propane swaps	408,292	Bbl	1,725,114 Bbl
Butane swaps	18,740	Bbl	74,371 Bbl
Crude oil swaps	82,958	Bbl	329,230 Bbl
Natural gas swaps	2,392,092	GJ	9,490,365 GJ
Power
Sales	8,105,509	MWh	11,881,575 MWh
Purchases	8,506,590	MWh	8,507,874 MWh
Swaps	26,551,954	MWh	20,957,180 MWh

Foreign Exchange Risk

AltaGas is exposed to foreign exchange risk as changes in foreign exchange rates may affect the fair value or future cash flows of the Corporation’s financial instruments. AltaGas has foreign operations whereby the functional currency is the U.S. dollar. As a result, the Corporation’s earnings, cash flows, and OCI are exposed to fluctuations resulting from changes in foreign exchange rates. This risk is partially mitigated to the extent that AltaGas has U.S. dollar-denominated debt and/or preferred shares

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 70

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 September 30, 2019 and December 31, 2018, AltaGas did not have any outstanding foreign exchange forward contracts.

AltaGas may designate its U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. As at September 30, 2019, AltaGas has designated US$690.0 million of outstanding debt as a net investment hedge (December 31, 2018 - US$1,494.0 million). For the three and nine months ended September 30, 2019, AltaGas recognized after-tax unrealized losses of $16.6 million and after-tax unrealized gains of $52.4 million, respectively, arising from the translation of debt in other comprehensive income (three and nine months ended September 30, 2018 ‑ after-tax unrealized gains of $37.4 million).

Weather Related Instruments

WGL Energy Services utilizes heating degree day (HDD) instruments from time to time to manage weather and price risks related to its natural gas and electricity sales during the winter heating season. WGL Energy Services also utilizes cooling degree day (CDD) instruments and other instruments to manage weather and price risks related to its electricity sales during the summer cooling season. These instruments cover a portion of estimated revenue or energy-related cost exposure to variations in HDDs or CDDs. For the three and nine months ended September 30, 2019, pre-tax losses of $0.7 million and $0.1 million, respectively, were recorded related to these instruments (three and nine months ended September 30, 2018 - pre-tax losses of $1 million).

15. Leases

Lessee

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

The components of lease expense were as follows:




	Three months ended September 30, 2019		Nine months ended September 30, 2019
Operating lease cost (includes variable lease payments)	$	7.5	$	22.0
Finance lease cost
Amortization of right-of-use assets	$	0.7	$	2.3
Interest on lease liabilities	—		0.2
Total finance lease cost	$	0.7	$	2.5
Total lease cost	$	8.2	$	24.5

Supplemental cash flow information related to leases was as follows:




	Three months ended September 30, 2019			Nine months ended September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows used by finance leases	$	(0.1	)	$	(0.2	)
Operating cash flows used by operating leases	$	(5.6	)	$	(14.1	)
Financing cash flows used by finance leases ^(a)	$	(0.8	)	$	(2.5	)
Right-of-use assets obtained in exchange for new lease liabilities
Operating leases	$	12.9		$	26.8
Finance leases	$	0.5		$	1.5


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

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 71

Supplemental balance sheet information related to leases was as follows:




As at	September 30, 2019
Operating Leases
Operating lease right-of-use assets
Long-term	$	147.7
Included in assets held for sale (note 5)	4.1
Total operating lease right-of-use assets	151.8

Operating lease liabilities
Current	$	(23.3	)
Long-term	(140.1		)
Included in liabilities associated with assets held for sale (note 5)	(4.1		)
Total operating lease liabilities	$	(167.5	)

Finance Leases
Property and equipment, gross	$	9.4
Accumulated depreciation	(2.3		)
Property and equipment, net	$	7.1

Current portion of long-term debt	$	(2.7	)
Long-term debt	(4.4		)
Total finance lease liabilities	$	(7.1	)




As at	September 30, 2019
Weighted average remaining lease term (years)
Operating leases	11.7
Finance leases	5.6
Weighted average discount rate (%)
Operating leases	3.66	%
Finance leases	4.10	%

Maturity analysis of lease liabilities was as follows:




	Operating Leases			Finance Leases
Remainder of 2019	$	24.2		$	2.8
2020	23.9			2.1
2021	23.2			1.4
2022	21.5			0.6
2023	18.0			0.1
Thereafter	103.5			2.0
Total lease payments	214.3			9.0
Less: imputed interest	(46.8		)	(1.9		)
Total	$	167.5		$	7.1

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 72

As of September 30, 2019, AltaGas has additional operating leases, primarily for rail cars, that have not yet commenced of $21.9 million. These operating leases will commence later in 2019 with lease terms of up to 6 years.

Lessor

Certain of AltaGas’ revenues are obtained through power purchase agreements or take-or-pay contracts whereby AltaGas is the lessor in these operating lease arrangements. Minimum lease payments received are amortized over the term of the lease. Contingent rentals are recorded when the condition that created the present obligation to make such payments occurs such as when actual electricity is generated and delivered.

Maturity analysis of lease receivables was as follows:




	Operating Leases
Remainder of 2019	$	47.5
2020	152.2
2021	109.6
2022	110.7
2023	111.8
Thereafter	1,187.8
Total	$	1,719.6

The carrying value of property, plant and equipment associated with these leases was approximately $1.3 billion as at September 30, 2019.

AltaGas manages its risk associated with the residual value of its leased assets through strategically constructing leased facilities in key commercial regions, and retaining the ability to sell commodities and ancillary services via the merchant market or through commodity sales agreements.

16. Shareholders’ Equity

Authorization

AltaGas is authorized to issue an unlimited number of voting common shares. AltaGas is also authorized to issue such number of Preferred Shares in series at any time as have aggregate voting rights either directly or on conversion or exchange that in the aggregate represent less than 50 percent of the voting rights attaching to the then issued and outstanding Common Shares.

Dividend Reinvestment and Optional Cash Purchase Plan (DRIP or the Plan)

The Plan consists of two components: a Dividend Reinvestment component and an Optional Cash Purchase component. The Premium Dividend™ component of the plan was suspended effective December 18, 2018.

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

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

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 73

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





Common Shares Issued and Outstanding	Number of shares	Amount
January 1, 2018	175,279,216	$	4,007.9
Shares issued on conversion of subscription receipts, net of issuance costs	84,510,000	2,305.6
Shares issued for cash on exercise of options	57,275	1.3
Deferred taxes on share issuance cost	—	13.3
Shares issued under DRIP	15,377,575	325.8
December 31, 2018	275,224,066	$	6,653.9
Shares issued under DRIP	2,709,339	47.7
Issued and outstanding at September 30, 2019	277,933,405	$	6,701.6

Preferred Shares




As at	September 30, 2019				December 31, 2018
Issued and Outstanding	Number of shares	Amount			Number of shares	Amount
Series A	5,511,220	$	137.8		5,511,220	$	137.8
Series B	2,488,780	62.2			2,488,780	62.2
Series C	8,000,000	205.6			8,000,000	205.6
Series E	8,000,000	200.0			8,000,000	200.0
Series G	6,885,823	172.1			8,000,000	200.0
Series H	1,114,177	27.9			—	—
Series I	8,000,000	200.0			8,000,000	200.0
Series K	12,000,000	300.0			12,000,000	300.0
Washington Gas
$4.80 series	150,000	19.7			150,000	19.7
$4.25 series	70,600	9.4			70,600	9.4
$5.00 series	60,000	7.9			60,000	7.9
Share issuance costs, net of taxes		(27.9		)		(27.9		)
Fair value adjustment on WGL Acquisition (note 3)		4.1				4.1
	52,280,600	$	1,318.8		52,280,600	$	1,318.8

On September 30, 2019, 1,114,177 of the outstanding 8,000,000 Cumulative Redeemable Five-Year Fixed Rate Reset Preferred Shares, Series G (Series G Preferred Shares) were converted into Cumulative Floating Rate Preferred Shares, Series H (Series H Preferred Shares). As a result of the conversion, AltaGas has 6,885,823 Series G Preferred Shares and 1,114,177 Series H Preferred Shares issued and outstanding. The Series G Preferred Shares will continue to pay on a quarterly basis, for the five-year period beginning on September 30, 2019, as and when declared by the Board of Directors of AltaGas, a fixed dividend based on an annual fixed dividend rate of 4.242 percent. The Series H Preferred Shares will pay a floating quarterly dividend for the five-year period beginning on September 30, 2019, as and when declared by the Board of Directors of AltaGas. The floating

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 74

quarterly dividend rate for the Series H Preferred Shares for the first quarterly floating rate period (being the period from September 30, 2019 to, but excluding, December 31, 2019) is 4.698 percent and will be reset every quarter.

Share Option Plan

AltaGas has an employee share option plan under which officers, employees, and service providers (as defined by the TSX) are eligible to receive grants. As at September 30, 2019, 20,238,944 shares were reserved for issuance under the plan. As at September 30, 2019, share options granted under the plan have a term between six and ten years until expiry and vest no longer than over a four‑year period.

As at September 30, 2019, the unexpensed fair value of share option compensation cost associated with future periods was $5.5 million (December 31, 2018 ‑ $3.7 million).

The following table summarizes information about the Corporation’s share options:





As at	September 30, 2019				December 31, 2018
	Options outstanding				Options outstanding
	Number of options		Exercise price^(a)		Number of options		Exercise price^(a)
Share options outstanding, beginning of period	6,309,183		$	25.18	4,533,761		$	32.35
Granted	2,125,824		19.14		2,811,460		16.69
Exercised	—		—		(57,275	)	20.68
Forfeited	(880,610	)	28.45		(878,013	)	36.47
Expired	—		—		(100,750	)	14.60
Share options outstanding, end of period	7,554,397		$	23.10	6,309,183		$	25.18
Share options exercisable, end of period	2,700,938		$	31.84	2,897,723		$	32.01


(a)	Weighted average.

As at September 30, 2019, the aggregate intrinsic value of the total share options exercisable was $0.1 million (December 31, 2018 - $nil), the total intrinsic value of share options outstanding was $11.7 million (December 31, 2018 - $nil) and the total intrinsic value of share options exercised was $nil (December 31, 2018 - $0.3 million).

The following table summarizes the employee share option plan as at September 30, 2019:




	Options outstanding				Options exercisable
		Weighted		Weighted average		Weighted		Weighted average
	Number	average		remaining	Number	average		remaining
	outstanding	exercise price		contractual life	exercisable	exercise price		contractual life
$14.52 to $18.00	2,709,605	$	15.15	5.23	25,000	$	17.10	0.67
$18.01 to $25.08	1,916,744	19.83		4.84	348,250	20.74		1.09
$25.09 to $46.70	2,928,048	32.60		2.70	2,327,688	33.66		2.33
	7,554,397	$	23.10	4.15	2,700,938	$	31.84	2.15

Medium Term Incentive Plan (MTIP) and Deferred Share Unit Plan (DSUP)

AltaGas has a MTIP for employees and executive officers, which includes restricted units (RUs) and performance units (PUs) with vesting periods between 36 to 44 months from the grant date. In addition, AltaGas has a DSUP, which allows granting of deferred share units (DSUs) to directors. DSUs granted under the DSUP vest immediately but settlement of the DSUs occur when the individual ceases to be a director.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 75




PUs, RUs, and DSUs	September 30, 2019		December 31, 2018
(number of units)
Balance, beginning of period	15,199,775		564,549
Acquired ^(a)	—		5,291,621
Granted	582,397		9,502,347
Vested and paid out	(31,150	)	(148,154	)
Forfeited	(2,854,050	)	(66,522	)
Units in lieu of dividends	51,447		55,934
Outstanding, end of period	12,948,419		15,199,775


(a)	Upon close of the WGL Acquisition in 2018, AltaGas acquired WGL’s PUs. These were converted to a fixed cash amount at a value of US$1.00 per unit.

For the three and nine months ended September 30, 2019, the compensation expense recorded for the MTIP and DSUP was an expense of $4.2 million and $13.1 million, respectively (three and nine months ended September 30, 2018 – recovery of $0.2 million and expense of $2.7 million, respectively). As at September 30, 2019, the unrecognized compensation expense relating to the remaining vesting period for the MTIP was $26.0 million (December 31, 2018 ‑ $26.9 million) and is expected to be recognized over the vesting period.

17. Net Income (Loss) Per Common Share

The following table summarizes the computation of net income (loss) per common share:




	Three months ended September 30, 2019						Nine months ended September 30, 2019
	2019			2018			2019			2018
Numerator:
Net income (loss) applicable to controlling interests	$	39.2		$	(709.3	)	$	923.4		$	(626.3	)
Less: Preferred share dividends	(16.8		)	(16.9		)	(51.3		)	(49.7		)
Net income (loss) applicable to common shares	$	22.4		$	(726.2	)	$	872.1		$	(676.0	)
Denominator:
(millions)
Weighted average number of common shares outstanding	277.4			261.3			276.4			206.0
Dilutive equity instruments ^(a)	0.6			—			0.4			—
Weighted average number of common shares outstanding - diluted	278.0			261.3			276.8			206.0
Basic net income (loss) per common share	$	0.08		$	(2.78	)	$	3.16		$	(3.28	)
Diluted net income (loss) per common share	$	0.08		$	(2.78	)	$	3.15		$	(3.28	)


(a)	Includes all options that have a strike price lower than the average share price of AltaGas' common shares during the periods noted.

For the three and nine months ended September 30, 2019, 4.9 million and 4.2 million share options, respectively (2018 – 4.3 million and 4.1 million, respectively), were excluded from the diluted net income (loss) per share calculation as their effects were anti‑dilutive.

18. Commitments, Guarantees, and Contingencies

Commitments

AltaGas has long-term natural gas purchase and transportation arrangements, electricity purchase arrangements, service agreements, storage contracts, environmental commitments, and operating leases for office space, office equipment, rail cars, and automobile equipment, all of which are transacted at market prices and in the normal course of business.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 76

AltaGas’ utilities have contracts to purchase natural gas, natural gas transportation and storage services from various suppliers to ensure that there is an adequate supply of natural gas to meet the needs of customers and to minimize exposure to market price fluctuations. These contracts have expiration dates that range from 2019 to 2044. In addition, WGL Energy Services also enters into contracts to purchase natural gas and electricity designed to match the duration of its sales commitments, and to secure a margin on estimated sales over the terms of existing sales contracts. WGL Midstream enters into contracts to acquire, invest in, manage, and optimize natural gas storage and transportation assets.

In connection with the WGL Acquisition, AltaGas and WGL have made commitments related to the terms of the Public Service Commission of the District of Columbia (PSC of DC) settlement agreement and the conditions of approval from the Maryland Public Service Commission (PSC of MD) and the Commonwealth of Virginia State Corporation Commission (SCC of VA). Among other things, these commitments include rate credits distributable to both residential and non-residential customers, gas expansion and other programs, various public interest commitments, and safety programs. As at September 30, 2019, the total amount of merger commitments which have been expensed but are not yet paid is approximately US$18 million. In addition, there are certain additional regulatory commitments which will be expensed when the costs are incurred in the future, including the hiring of damage prevention trainers, investment of US$70 million over a 10 year period to further extend natural gas service, US$7.5 million for leak mitigation, and development of 15MW of either electric grid energy storage or Tier 1 renewable resources within 5 years.

In 2017, AltaGas entered into a 12-year service agreement for tug services to support the marine operations of RIPET. AltaGas is obligated to pay fixed fees of approximately $27 million over the term of the contract.

In 2019, AltaGas entered into propane supply contracts with various counterparties to secure physical volumes required for RIPET’s export capacity commitments. The contract terms range from 1 - 15 years, for an aggregate commitment amount of approximately $667 million.

In 2014, AltaGas’ Blythe facility entered into a Long-Term Service Agreement with Siemens to complete various upgrade and maintenance services on the Combustion Turbines (CT) at Blythe. The term of the agreement is over 124,000 equivalent operating hours per CT, or 25 years, whichever comes first. As at September 30, 2019, approximately $176.3 million is expected to be paid over the next 16 years, of which $49.1 million is expected to be paid over the next five years.

In 2009, AltaGas entered into a 20-year storage agreement at the Dawn Hub in southwestern Ontario. AltaGas is obligated to pay approximately $3.5 million per annum over the term of the contract for storage services.

Guarantees

AltaGas has guaranteed payments primarily for certain commitments on behalf of some of its subsidiaries. AltaGas has also guaranteed payments for certain of its external partners. As at September 30, 2019, AltaGas has no guarantees to external parties.

Contingencies

AltaGas and its subsidiaries are subject to various legal claims and actions arising in the normal course of business. While the final outcome of such legal claims and actions cannot be predicted with certainty, the Corporation does not believe that the resolution of such claims and actions will have a material impact on the Corporation’s consolidated financial position or results of operations.

Antero Contract

In June 2019, a jury trial was held in the County Court for Denver, Colorado to consider a contractual dispute relating to gas pricing between Washington Gas and WGL Midstream (together, the Companies) and Antero Resources Corporation (Antero). Following the trial, the jury returned a verdict in favor of Antero for approximately US$96 million, of which approximately US$11

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 77

million was against Washington Gas with the remainder against WGL Midstream. Following the official entry of the judgment, the Companies filed an appeal on August 16, 2019.

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

Silver Spring, Maryland Incident

On April 23, 2019, the National Transportation and Safety Board (NTSB) held a hearing during which it found, among other things, that the probable cause of the August 10, 2016, explosion and fire at an apartment complex on Arliss Street in Silver Spring, Maryland “was the failure of an indoor mercury service regulator with an unconnected vent line that allowed natural gas into the meter room where it accumulated and ignited from an unknown ignition source. Contributing to the accident was the location of the mercury service regulators where leak detection by odor was not readily available.” Washington Gas disagrees with the NTSB’s probable cause findings. Following this hearing, on June 10, 2019, the NTSB issued an accident report.

In connection with the incident, a total of 37 civil actions related to the incident have been filed and are pending against WGL and Washington Gas in the Circuit Court for Montgomery County, Maryland. All cases have been consolidated for discovery purposes. All of these suits seek unspecified damages for personal injury and/or property damage. A trial date for eight bellwether civil actions has been scheduled for December 2, 2019. In addition, two suits were recently filed related to the incident, one each in the Superior Court for the District of Columbia and one in the Circuit Court of Montgomery County, Maryland. At this stage of the litigation, the outcome is not yet determinable and management is unable to make an estimate of any potential loss or range of potential losses that are reasonably possible of occurring. As a result, management has only recorded a reserve for a few of the actions for which a settlement offer was made. Washington Gas maintains excess liability insurance coverage from highly-rated insurers, subject to a nominal self-insured retention. Washington Gas believes that this coverage will be sufficient to cover any significant liability that may result from this incident.

In connection with the incident, on September 5, 2019, the PSC of MD ordered Washington Gas, within 30 days, to (i) provide a detailed response to the NTSB’s probable cause findings and (ii) provide evidence regarding the status of a 2003 mercury regulator replacement program and, if the program was not completed, to show cause why the PSC of MD should not impose a civil penalty on Washington Gas. On September 16, 2019, the PSC of MD granted Washington Gas a 14-day extension to file its response to the Show-Cause Order. On October 18, 2019, Washington Gas filed its response to the Show-Cause Order, providing a detailed response to the NTSB’s probable cause findings and (ii) providing evidence regarding the status of a 2003 mercury regulator replacement program and why the PSC of MD should not impose a civil penalty on Washington Gas. The PSC of MD has not adopted a procedural schedule with respect to this matter but has indicated that it will schedule one public hearing near the apartment complex at Arliss Street. Given the early stage of the Show-Cause proceeding, the outcome is not yet determinable and management is unable to predict the likelihood of a civil penalty, or make an estimate of any potential civil penalty or range of potential civil penalty.

19. Pension Plans and Retiree Benefits

The costs of the defined benefit and post-retirement benefit plans are based on management's estimate of the future rate of return on the fair value of pension plan assets, salary escalations, mortality rates, and other factors affecting the payment of future benefits.

Rabbi trusts of $63.8 million as at September 30, 2019 have been funded to satisfy the employee benefit obligations associated with WGL’s various pension plans (December 31, 2018 - $89.3 million). These balances are included in "prepaid expenses and other current assets" and "long-term investments and other assets" in the Consolidated Balance Sheets.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 78

The net pension expense by plan for the period was as follows:



	Three months ended September 30, 2019
	Canada					United States						Total
				Post-					Post-						Post-
	Defined			retirement		Defined			retirement			Defined			retirement
	Benefit			Benefits		Benefit			Benefits			Benefit			Benefits
Current service cost ^(a)	$	0.6		$	—	$	6.0		$	2.1		$	6.6		$	2.1
Interest cost ^(b)	0.3			—		16.8			4.8			17.1			4.8
Expected return on plan assets ^(b)	(0.1		)	—		(18.6		)	(9.2		)	(18.7		)	(9.2		)
Amortization of past service cost^(b)	—			—		—			(5.1		)	—			(5.1		)
Amortization of net actuarial loss ^(b)	0.2			—		2.4			—			2.6			—
Net benefit cost (income) recognized	$	1.0		$	—	$	6.6		$	(7.4	)	$	7.6		$	(7.4	)


(a)	Recorded under the line item “operating and administrative” expenses on the Consolidated Statements of Income (Loss).


(b)	Recorded under the line item “other income” on the Consolidated Statements of Income (Loss).



	Three months ended September 30, 2018
	Canada						United States						Total
				Post-						Post-						Post-
	Defined			retirement			Defined			retirement			Defined			retirement
	Benefit			Benefits			Benefit			Benefits			Benefit			Benefits
Current service cost ^(a)	$	2.4		$	0.2		$	6.5		$	2.2		$	8.9		$	2.4
Interest cost ^(b)	1.3			0.1			16.5			4.8			17.8			4.9
Expected return on plan assets ^(b)	(1.5		)	(0.1		)	(21.0		)	(9.6		)	(22.5		)	(9.7		)
Amortization of net actuarial loss ^(b)	0.2			—			—			—			0.2			—
Amortization of regulatory asset ^(b)	0.4			—			1.9			—			2.3			—
Net benefit cost (income) recognized	$	2.8		$	0.2		$	3.9		$	(2.6	)	$	6.7		$	(2.4	)


(a)	Recorded under the line item “operating and administrative” expenses on the Consolidated Statements of Income (Loss).


(b)	Recorded under the line item “other income” on the Consolidated Statements of Income (Loss).



	Nine months ended September 30, 2019
	Canada					United States						Total
				Post-					Post-						Post-
	Defined			retirement		Defined			retirement			Defined			retirement
	Benefit			Benefits		Benefit			Benefits			Benefit			Benefits
Current service cost ^(a)	$	1.8		$	—	$	18.0		$	6.4		$	19.8		$	6.4
Interest cost ^(b)	0.9			—		50.8			14.4			51.7			14.4
Expected return on plan assets ^(b)	(0.3		)	—		(56.1		)	(27.8		)	(56.4		)	(27.8		)
Amortization of past service cost ^(b)	—			—		0.1			(15.4		)	0.1			(15.4		)
Amortization of net actuarial loss ^(b)	0.6			—		6.9			—			7.5			—
Plan settlements ^(b)	—			—		5.8			—			5.8			—
Net benefit cost (income) recognized	$	3.0		$	—	$	25.5		$	(22.4	)	$	28.5		$	(22.4	)


(a)	Recorded under the line item “operating and administrative” expenses on the Consolidated Statements of Income (Loss).


(b)	Recorded under the line item “other income” on the Consolidated Statements of Income (Loss).

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 79



	Nine months ended September 30, 2018
	Canada						United States						Total
				Post-						Post-						Post-
	Defined			retirement			Defined			retirement			Defined			retirement
	Benefit			Benefits			Benefit			Benefits			Benefit			Benefits
Current service cost ^(a)	$	7.4		$	0.6		$	11.4		$	3.6		$	18.8		$	4.2
Interest cost ^(b)	4.1			0.4			23.6			6.7			27.7			7.1
Expected return on plan assets ^(b)	(4.8		)	(0.2		)	(32.9		)	(13.0		)	(37.7		)	(13.2		)
Curtailment of plan ^(b)	(1.0		)	(0.2		)	—			—			(1.0		)	(0.2		)
Amortization of past service cost ^(b)	0.1			—			—			—			0.1			—
Amortization of net actuarial loss ^(b)	0.5			—			—			—			0.5			—
Amortization of regulatory asset ^(b)	1.1			—			5.6			0.1			6.7			0.1
Net benefit cost (income) recognized	$	7.4		$	0.6		$	7.7		$	(2.6	)	$	15.1		$	(2.0	)


(a)	Recorded under the line item “operating and administrative” expenses on the Consolidated Statements of Income (Loss).


(b)	Recorded under the line item “other income” on the Consolidated Statements of Income (Loss).

20. Income Taxes

The effective income tax rates for the three and nine months ended September 30, 2019 were approximately (374) percent and 6 percent, respectively (three and nine months ended September 30, 2018 – 24 percent). The decrease in the effective tax rate for the three months ended September 30, 2019 was mainly due to a tax recovery on the sale of WGL's distributed generation assets relative to pre-tax income. The decrease in the effective tax rate for the nine months ended September 30, 2019 was mainly due to the capital gain on the sale of the remaining interest in the Northwest Hydro facilities in the first quarter of 2019, which was taxed at the capital rate, a tax recovery on the sale of WGL's distributed generation assets, and a tax rate adjustment related to the Alberta Job Creation Tax Cut.

21. Supplemental Cash Flow Information

The following table details the changes in operating assets and liabilities from operating activities:




	Three months ended September 30						Nine months ended September 30
	2019			2018			2019			2018
Source (use) of cash:
Accounts receivable	$	85.8		$	9.2		$	620.9		$	139.4
Inventory	(91.3		)	(134.5		)	(3.2		)	(95.9		)
Other current assets	(8.6		)	(45.3		)	(37.6		)	(34.6		)
Regulatory assets - current	2.0			(8.1		)	5.7			(8.6		)
Accounts payable and accrued liabilities	(92.1		)	(88.0		)	(505.5		)	(153.9		)
Customer deposits	12.9			33.5			(14.1		)	22.5
Regulatory liabilities - current	21.1			2.1			(10.4		)	13.5
Risk management liabilities - current	(1.4		)	—			2.4			—
Other current liabilities	2.8			(4.1		)	(4.5		)	(9.2		)
Other operating assets and liabilities	(29.5		)	(18.0		)	(3.9		)	(58.6		)
Changes in operating assets and liabilities	$	(98.3	)	$	(253.2	)	$	49.8		$	(185.4	)

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 80

The following cash payments have been included in the determination of earnings:




	Three months ended September 30				Nine months ended September 30
	2019		2018		2019		2018
Interest paid (net of capitalized interest)	$	92.1	$	106.7	$	264.5	$	189.2
Income taxes paid	$	21.4	$	6.8	$	37.6	$	27.9

The following table is a reconciliation of cash and restricted cash balances:



As at September 30	2019		2018
Cash and cash equivalents	$	36.4	$	14.1
Restricted cash holdings from customers - current	3.9		3.8
Restricted cash holdings from customers - non-current	4.0		5.8
Restricted cash included in prepaid expenses and other current assets ^(a)	5.6		26.2
Restricted cash included in long-term investments and other assets ^(a)	58.2		58.0
Cash, cash equivalents and restricted cash per consolidated statement of cash flow	$	108.1	$	107.9


(a)	The restricted cash balances included in prepaid expenses and other current assets and long-term investments and other assets relates to Rabbi trusts associated with WGL’s pension plans (Note 19).

22. Seasonality

The Utilities business is highly seasonal with the majority of natural gas deliveries occurring during the winter heating season. Gas sales increase during the winter resulting in stronger first and fourth quarter results and weaker second and third quarter results.

In addition, gas and power sales under the WGL Energy Services retail business are seasonal, with larger amounts of electricity being sold in the summer and peak winter months and larger amounts of natural gas being sold in the winter months.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 81

23. Segmented Information

AltaGas owns and operates a portfolio of assets and services used to move energy from the source to the end‑user. The following describes the Corporation’s four reporting segments:




Utilities	n rate-regulated natural gas distribution assets in Michigan, Alaska, the District of Columbia, Maryland, and Virginia; n rate-regulated natural gas storage in the United States; and n equity investment in AltaGas Canada Inc.
Midstream	n NGL processing and extraction plants; n transmission pipelines to transport natural gas and NGL; n natural gas gathering lines and field processing facilities; n purchase and sale of natural gas; n natural gas storage facilities; n liquefied petroleum gas (LPG) terminal; n natural gas and NGL marketing; n equity investment in Petrogas, a North American entity engaged in the marketing, storage and distribution of NGL, drilling fluids, crude oil and condensate diluents; n interests in three regulated gas pipelines in the Marcellus/Utica basins, one of which is pending sale; and n sale of natural gas to residential, commercial and industrial customers in Washington D.C., Maryland, Virginia, Delaware, and Pennsylvania.
Power	n natural gas-fired and solar power generation assets, certain of which are pending sale, whereby outputs are generally sold under power purchase agreements, both operational and under development; n energy storage; and n sale of power to residential, commercial and industrial users in Washington D.C., Maryland, Virginia, Delaware, Pennsylvania, and Ohio.
Corporate	n the cost of providing corporate services, financing and general corporate overhead, investments in certain public and private entities, corporate assets, financing other segments and the effects of changes in the fair value of certain risk management contracts.

The following table provides a reconciliation of segment revenue to the disaggregated revenue table as disclosed under Note 13:




	Three months ended September 30, 2019
	Utilities		Midstream		Power		Corporate		Total
External revenue (note 13)	$	261.4	$	291.6	$	335.4	$	—	$	888.4
Intersegment revenue	3.9		0.5		2.3		—		6.7
Segment revenue	$	265.3	$	292.1	$	337.7	$	—	$	895.1



	Three months ended September 30, 2018
	Utilities		Midstream		Power		Corporate			Total
External revenue (note 13)	$	309.5	$	305.6	$	441.0	$	(14.7	)	$	1,041.4
Intersegment revenue	4.2		7.5		2.6		(0.1		)	14.2
Segment revenue	$	313.7	$	313.1	$	443.6	$	(14.8	)	$	1,055.6

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 82



	Nine months ended September 30, 2019
	Utilities		Midstream		Power		Corporate		Total
External revenue (note 13)	$	1,769.6	$	1,151.2	$	1,039.4	$	0.2	$	3,960.4
Intersegment revenue	19.8		5.6		8.4		—		33.8
Segment revenue	$	1,789.4	$	1,156.8	$	1,047.8	$	0.2	$	3,994.2



	Nine months ended September 30, 2018
	Utilities		Midstream		Power		Corporate			Total
External revenue (note 13)	$	942.1	$	864.8	$	752.1	$	(29.4	)	$	2,529.6
Intersegment revenue	5.5		81.0		6.4		(0.1		)	92.8
Segment revenue	$	947.6	$	945.8	$	758.5	$	(29.5	)	$	2,622.4

The following tables show the composition by segment:



	Three months ended September 30, 2019
	Utilities			Midstream			Power			Corporate			Intersegment Elimination^(a)			Total
Segment revenue	$	265.3		$	292.1		$	337.7		$	—		$	(6.7	)	$	888.4
Cost of sales	(92.6		)	(154.7		)	(238.4		)	—			4.2			(481.5		)
Operating and administrative	(197.5		)	(58.9		)	(32.9		)	(12.8		)	2.5			(299.6		)
Accretion expenses	—			(1.0		)	(0.1		)	—			—			(1.1		)
Depreciation and amortization	(61.7		)	(23.5		)	(15.2		)	(3.2		)	—			(103.6		)
Income (loss) from equity investments	2.4			(8.2		)	0.7			—			—			(5.1		)
Other income (loss)	3.3			(0.4		)	101.1			(0.5		)	—			103.5
Foreign exchange gains (losses)	—			0.8			—			(0.1		)	—			0.7
Interest expense	—			—			—			(92.5		)	—			(92.5		)
Income (loss) before income taxes	$	(80.8	)	$	46.2		$	152.9		$	(109.1	)	$	—		$	9.2
Net additions (reductions) to:
Property, plant and equipment ^(b)	$	312.9		$	163.8		$	(977.7	)	$	0.4		$	—		$	(500.6	)
Intangible assets	$	0.4		$	0.8		$	—		$	2.7		$	—		$	3.9


(a)	Intersegment transactions are recorded at market value.


(b)	Net additions to property, plant and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statements of Cash Flows due to classification of business acquisition and foreign exchange changes on U.S. assets.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 83



	Three months ended September 30, 2018
	Utilities			Midstream			Power			Corporate			Intersegment Elimination^(a)			Total
Segment revenue	$	313.7		$	313.1		$	443.6		$	(14.8	)	$	(14.2	)	$	1,041.4
Cost of sales	(90.5		)	(202.7		)	(289.4		)	—			11.5			(571.1		)
Operating and administrative	(386.5		)	(51.8		)	(50.1		)	(10.3		)	2.8			(495.9		)
Accretion expenses	—			(1.0		)	(1.6		)	—			—			(2.6		)
Depreciation and amortization	(61.8		)	(19.3		)	(38.3		)	(3.1		)	—			(122.5		)
Provision on assets	(193.7		)	(151.5		)	(352.2		)	—			—			(697.4		)
Income from equity investments	0.6			10.2			1.8			—			—			12.6
Other income (loss)	(9.6		)	10.3			0.9			10.2			(0.1		)	11.7
Foreign exchange gains (losses)	—			(0.1		)	—			3.1			—			3.0
Interest expense	(70.3		)	(1.2		)	(4.0		)	(36.6		)	—			(112.1		)
Loss before income taxes	$	(498.1	)	$	(94.0	)	$	(289.3	)	$	(51.5	)	$	—		$	(932.9	)
Net additions to:
Property, plant and equipment ^(b)	$	258.7		$	60.5		$	46.6		$	1.0		$	—		$	366.8
Intangible assets	$	2.4		$	1.4		$	11.4		$	1.3		$	—		$	16.5


(a)	Intersegment transactions are recorded at market value.


(b)	Net additions to property, plant and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statements of Cash Flows due to classification of business acquisition and foreign exchange changes on U.S. assets.



	Nine months ended September 30, 2019
	Utilities			Midstream			Power			Corporate			Intersegment Elimination^(a)			Total
Segment revenue	$	1,789.4		$	1,156.8		$	1,047.8		$	0.2		$	(33.8	)	$	3,960.4
Cost of sales	(780.1		)	(761.7		)	(821.4		)	—			24.9			(2,338.3		)
Operating and administrative	(634.0		)	(180.6		)	(120.1		)	(32.4		)	8.9			(958.2		)
Accretion expenses	(0.1		)	(2.9		)	(0.8		)	—			—			(3.8		)
Depreciation and amortization	(195.8		)	(67.3		)	(57.4		)	(8.9		)	—			(329.4		)
Provisions on assets (note 6)	—			—			(0.8		)	—			—			(0.8		)
Income from equity investments	12.0			72.3			0.4			—			—			84.7
Other income (loss)	17.6			39.0			784.6			(2.4		)	—			838.8
Interest expense	—			—			—			(269.1		)	—			(269.1		)
Income (loss) before income taxes	$	209.0		$	255.6		$	832.3		$	(312.6	)	$	—		$	984.3
Net additions (reductions) to:
Property, plant and equipment ^(b)	$	695.8		$	257.0		$	(2,283.5	)	$	0.9		$	—		$	(1,329.8	)
Intangible assets	$	1.5		$	4.0		$	—		$	7.1		$	—		$	12.6


(a)	Intersegment transactions are recorded at market value.


(b)	Net additions to property, plant and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statements of Cash Flows due to classification of business acquisition and foreign exchange changes on U.S. assets.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 84



	Nine months ended September 30, 2018
	Utilities			Midstream			Power			Corporate			Intersegment Elimination^(a)			Total
Segment revenue	$	947.6		$	945.8		$	758.5		$	(29.5	)	$	(92.8	)	$	2,529.6
Cost of sales	(448.9		)	(634.4		)	(436.5		)	—			86.1			(1,433.7		)
Operating and administrative	(503.7		)	(144.4		)	(105.2		)	(36.8		)	7.1			(783.0		)
Accretion expenses	(0.1		)	(3.1		)	(4.9		)	—			—			(8.1		)
Depreciation and amortization	(103.0		)	(57.2		)	(97.4		)	(10.4		)	—			(268.0		)
Provision on assets	(193.7		)	(151.5		)	(352.2		)	—			—			(697.4		)
Income from equity investments	1.3			19.8			4.3			—			—			25.4
Other income (loss)	(5.7		)	0.3			0.9			10.1			(0.4		)	5.2
Foreign exchange gains (losses)	—			(0.1		)	—			3.7			—			3.6
Interest expense	(70.3		)	(1.2		)	(4.0		)	(122.8		)	—			(198.3		)
Loss before income taxes	$	(376.5	)	$	(26.0	)	$	(236.5	)	$	(185.7	)	$	—		$	(824.7	)
Net additions to:
Property, plant and equipment ^(b)	$	329.8		$	166.9		$	57.2		$	2.3		$	—		$	556.2
Intangible assets	$	3.8		$	3.8		$	12.1		$	2.9		$	—		$	22.6


(a)	Intersegment transactions are recorded at market value.


(b)	Net additions to property, plant and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statements of Cash Flows due to classification of business acquisition and foreign exchange changes on U.S. assets.

The following table shows goodwill and total assets by segment:



	Utilities		Midstream		Power		Corporate			Total
As at September 30, 2019
Goodwill	$	3,643.2	$	248.4	$	125.0	$	—		$	4,016.6
Segmented assets	$	12,974.2	$	6,398.7	$	1,366.6	$	(53.0	)	$	20,686.5
As at December 31, 2018
Goodwill	$	3,450.8	$	426.4	$	191.0	$	—		$	4,068.2
Segmented assets	$	12,991.3	$	6,398.8	$	3,814.7	$	282.9		$	23,487.7

24. Subsequent Events

Subsequent events have been reviewed through October 29, 2019, the date on which these unaudited condensed interim Consolidated Financial Statements were issued.

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 85

SUPPLEMENTAL QUARTERLY OPERATING INFORMATION




	Q3-19		Q2-19		Q1-19		Q4-18		Q3-18
OPERATING HIGHLIGHTS
UTILITIES
Natural gas deliveries - end use (Bcf) ⁽¹⁾	11.1		20.7		75.4		58.5		10.9
Natural gas deliveries - transportation (Bcf) ⁽¹⁾	23.3		25.2		47.6		52.0		25.7
Service sites (thousands) ⁽²⁾	1,647		1,648		1,647		1,643		1,759
Degree day variance from normal - SEMCO Gas (%) ⁽³⁾	(47.2	)	14.5		5.7		7.5		(17.8	)
Degree day variance from normal - ENSTAR (%) ⁽³⁾	(42.8	)	(16.1	)	(9.4	)	(19.6	)	(31.2	)
Degree day variance from normal - Washington Gas (%) ^{(3) (4)}	—		(44.5	)	(1.1	)	0.4		(4.1	)
MIDSTREAM
Total inlet gas processed (Mmcf/d) ⁽⁵⁾	1,307		1,417		1,481		1,413		1,333
Extraction volumes (Bbls/d) ^{(5) (6)}	65,831		56,990		62,332		64,522		60,945
Frac spread - realized ($/Bbl) ^{(5) (7)}	17.12		19.50		16.84		15.84		15.60
Frac spread - average spot price ($/Bbl) ^{(5) (8)}	9.17		15.27		11.79		21.00		25.87
RIPET export volumes (Bbls/d) ⁽⁹⁾	36,225		31,711		—		—		—
Propane Far East Index to Mont Belvieu spread (US$/Bbl) ⁽¹⁰⁾	12		14		—		—		—
Natural gas optimization inventory (Bcf)	35.7		31.9		13.2		35.9		36.7
WGL retail energy marketing - gas sales volumes (Mmcf)	6,476		9,360		27,411		20,750		8,155
POWER
Renewable power sold (GWh)	136		150		141		233		690
Conventional power sold (GWh)	672		361		263		985		1,255
Renewable capacity factor (%)	21.7		22.3		12.2		14.6		44.6
Contracted conventional availability factor (%) ⁽¹¹⁾	98.9		66.7		43.2		97.4		98.5
WGL retail energy marketing - electricity sales volumes (GWh)	3,723		3,125		3,080		2,911		3,000


(1)	Bcf is one billion cubic feet.


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

(3)

(4)


(5)	Average for the period.


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


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


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


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


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


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

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 86

OTHER INFORMATION

DEFINITIONS

Bbls/d barrels per day

Bcf billion cubic feet

Dth dekatherm

GJ gigajoule

GWh gigawatt‑hour

Mcf thousand cubic feet

Mmcf/d million cubic feet per day

MW megawatt

MWh megawatt‑hour

MMBTU million British thermal unit

US$ United States dollar

ABOUT ALTAGAS

AltaGas is an energy infrastructure company with a focus on regulated utilities, midstream and power. 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

AltaGas Ltd. – Q3 2019 MD&A and Financial Statements – 87