AltaGas 6K Announces Third Quarter Results and Framework for Balanced Funding Plan to Build Long-term Shareholder Value | ATGFF 30 Oct 18

Exhibit 1.1

Consolidated Balance Sheets

(condensed and unaudited)

As at ($ millions)	September 30, 2018		December 31, 2017

ASSETS
Current assets
Cash and cash equivalents (note 21)	$	14.1	$	27.3
Accounts receivable, net of allowances	937.1		382.9
Inventory (note 7)	502.1		201.1
Restricted cash holdings from customers (note 21)	3.8		8.9
Regulatory assets	13.4		1.1
Risk management assets (note 15)	64.1		38.6
Prepaid expenses and other current assets (note 21)	209.8		36.0
Assets held for sale (note 4)	1,771.3		6.0
	3,515.7		701.9

Property, plant and equipment	11,306.7		6,689.8
Intangible assets	931.4		588.8
Goodwill (note 8)	3,903.3		817.3
Regulatory assets	547.4		328.6
Risk management assets (note 15)	39.3		15.9
Deferred income taxes	—		2.8
Restricted cash holdings from customers (note 21)	5.8		7.5
Prepaid post-retirement benefits	349.5		—
Long-term investments and other assets (notes 9 and 21)	315.9		312.6
Investments accounted for by the equity method (note 11)	2,042.8		567.0
	$	22,957.8	$	10,032.2

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable and accrued liabilities	$	1,104.9	$	415.3
Dividends payable	49.1		32.0
Short-term debt	866.3		46.8
Current portion of long-term debt (notes 12 and 15)	1,998.6		188.9
Customer deposits	128.9		30.8
Regulatory liabilities	58.4		10.9
Risk management liabilities (note 15)	87.0		57.6
Other current liabilities	25.0		32.6
Liabilities associated with assets held for sale (note 4)	257.3		0.3
	4,575.5		815.2

Long-term debt (notes 12 and 15)	7,570.9		3,436.5
Asset retirement obligations	472.0		88.3
Unamortized investment tax credits	182.8		—
Deferred income taxes	1,038.0		444.2
Regulatory liabilities	1,374.5		268.6
Risk management liabilities (note 15)	172.5		13.8
Other long-term liabilities	254.1		201.9
Future employee obligations	254.5		124.5
	$	15,894.8	$	5,393.0

As at ($ millions)	September 30, 2018			December 31, 2017
Shareholders’ equity
Common shares, no par values, unlimited shares authorized; 2018 - 268.9 million and 2017 - 175.3 million issued and outstanding (note 16)	$	6,566.9		$	4,007.9
Preferred shares (note 16)	1,318.8			1,277.7
Contributed surplus	357.5			22.3
Accumulated deficit	(1,973.8		)	(933.6		)
Accumulated other comprehensive income (AOCI) (note 13)	251.5			199.1
Total shareholders’ equity	6,520.9			4,573.4
Non-controlling interests	542.1			65.8
Total equity	7,063.0			4,639.2
	$	22,957.8		$	10,032.2

Variable interest entities (note 10).

Commitments, contingencies and guarantees (note 18).

Subsequent events (note 24).

See accompanying notes to the Consolidated Financial Statements.

Consolidated Statements of Income (Loss)

(condensed and unaudited)

	Three months ended September 30						Nine months ended September 30
($ millions except per share amounts)	2018			2017			2018			2017

REVENUE (note 14)	$	1,041.4		$	501.5		$	2,529.6		$	1,811.4

EXPENSES
Cost of sales, exclusive of items shown separately	571.1			230.0			1,433.7			935.5
Operating and administrative	495.9			125.2			783.0			420.9
Accretion expenses	2.6			2.7			8.1			8.2
Depreciation and amortization	122.5			69.0			268.0			211.1
Provisions on assets (note 6)	697.4			—			697.4			1.3
	1,889.5			426.9			3,190.2			1,577.0

Income from equity investments	12.6			7.3			25.4			24.4
Other income	11.7			6.3			5.2			1.1
Foreign exchange gains	3.0			0.4			3.6			1.8
Interest expense
Short-term debt	(3.0		)	(0.6		)	(4.3		)	(2.3		)
Long-term debt	(109.1		)	(38.9		)	(194.0		)	(124.2		)
Income (loss) before income taxes	(932.9		)	49.1			(824.7		)	135.2
Income tax expense (recovery) (note 20)
Current	11.4			11.3			34.0			32.9
Deferred	(232.3		)	2.5			(234.2		)	9.7
Net income (loss) after taxes	(712.0		)	35.3			(624.5		)	92.6

Net income (loss) applicable to non-controlling interests	(2.7		)	2.2			1.8			6.4
Net income (loss) applicable to controlling interests	(709.3		)	33.1			(626.3		)	86.2
Preferred share dividends	(16.9		)	(15.6		)	(49.7		)	(45.1		)
Net income (loss) applicable to common shares	$	(726.2	)	$	17.5		$	(676.0	)	$	41.1

Net income (loss) per common share (note 17)
Basic	$	(2.78	)	$	0.10		$	(3.28	)	$	0.24
Diluted	$	(2.78	)	$	0.10		$	(3.28	)	$	0.24

Weighted average number of common shares outstanding (millions) (note 17)

Basic	261.3			171.9			206.0			169.9
Diluted	261.4			172.1			206.1			170.2

See accompanying notes to the Consolidated Financial Statements.

Consolidated Statements of Comprehensive Income (Loss)

(condensed and unaudited)

	Three months ended September 30						Nine months ended September 30
($ millions)	2018			2017			2018			2017
Net income (loss) after taxes	$	(712.0	)	$	35.3		$	(624.5	)	$	92.6
Other comprehensive income (loss), net of taxes
Gain (loss) on foreign currency translation	(127.5		)	(103.9		)	4.0			(198.2		)
Unrealized gain on net investment hedge (note 15)	37.4			—			37.4			6.8
Reclassification of actuarial gains and prior service costs on defined benefit (DB) and post-retirement benefit plans (PRB) to net income (note 19)	0.1			0.2			0.4			0.5
Settlement of PRB plan	—			—			—			0.2
Curtailment of DB and PRB plan	—			—			2.7			—
Unrealized loss on available-for-sale assets	—			(8.0		)	—			(25.5		)
Adoption of ASU 2016-01 (note 2)	—			—			7.1			—
Other comprehensive income (loss) from equity investees	(0.9		)	(2.2		)	0.8			(3.3		)
Total other comprehensive income (loss) (OCI), net of taxes (note 13)	(90.9		)	(113.9		)	52.4			(219.5		)
Comprehensive loss attributable to controlling interests and non-controlling interests, net of taxes	$	(802.9	)	$	(78.6	)	$	(572.1	)	$	(126.9	)

Comprehensive income (loss) attributable to:
Non-controlling interests	$	(2.7	)	$	2.2		$	1.8		$	6.4
Controlling interests	(800.2		)	(80.8		)	(573.9		)	(133.3		)
	$	(802.9	)	$	(78.6	)	$	(572.1	)	$	(126.9	)

See accompanying notes to the Consolidated Financial Statements.

Consolidated Statements of Equity

(condensed and unaudited)

Nine months ended September 30 ($ millions)	2018			2017

Common shares (note 16)
Balance, beginning of period	$	4,007.9		$	3,773.4
Shares issued for cash on exercise of options	1.1			4.1
Shares issued under DRIP (1)	223.5			175.4
Deferred taxes on share issuance costs	13.3			0.1
Shares issued on conversion of subscription receipts, net of issuance costs	2,321.1			—
Balance, end of period	$	6,566.9		$	3,953.0
Preferred shares (note 16)
Balance, beginning of period	$	1,277.7		$	985.1
Series K issued	—			293.4
Preferred shares acquired through WGL Acquisition (note 16)	41.1			—
Deferred taxes on share issuance costs	—			1.9
Balance, end of period	$	1,318.8		$	1,280.4
Contributed surplus
Balance, beginning of period	$	22.3		$	17.4
Share options expense	0.7			1.1
Exercise of share options	(0.1		)	(0.3		)
Forfeiture of share options	—			(0.1		)
Adoption of ASU No. 2016-09	—			1.1
Sale of non-controlling interest (notes 5 and 10)	334.6			3.0
Balance, end of period	$	357.5		$	22.2
Accumulated deficit
Balance, beginning of period	$	(933.6	)	$	(600.4	)
Net income applicable to controlling interests	(626.3		)	86.2
Common share dividends	(357.1		)	(268.1		)
Preferred share dividends	(49.7		)	(45.1		)
Adoption of ASU No. 2016-09	—			(1.1		)
Adoption of ASU No. 2016-01 (note 2)	(7.1		)	—
Balance, end of period	$	(1,973.8	)	$	(828.5	)
AOCI (note 13)
Balance, beginning of period	$	199.1		$	405.1
Other comprehensive income (loss)	52.4			(219.5		)
Balance, end of period	$	251.5		$	185.6
Total shareholders’ equity	$	6,520.9		$	4,612.7

Non-controlling interests
Balance, beginning of period	$	65.8		$	34.8
Net income applicable to non-controlling interests	1.8			6.4
Sale of non-controlling interest (notes 5 and 10)	420.4			20.0
Contributions from non-controlling interests to subsidiaries	52.9			5.9
Distributions by subsidiaries to non-controlling interests	(7.8		)	(5.5		)
Acquisition of non-controlling interest through WGL Acquisition (note 3)	9.0			—
Balance, end of period	542.1			61.6
Total equity	$	7,063.0		$	4,674.3

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

See accompanying notes to the Consolidated Financial Statements.

Consolidated Statements of Cash Flows

(condensed and unaudited)

	Three months ended September 30						Nine months ended September 30
($ millions)	2018			2017			2018			2017
Cash from operations
Net income (loss) after taxes	$	(712.0	)	$	35.3		$	(624.5	)	$	92.6
Items not involving cash:
Depreciation and amortization	122.5			69.0			268.0			211.1
Provisions on assets (note 6)	697.4			—			697.4			1.3
Accretion expenses	2.6			2.7			8.1			8.2
Share-based compensation (note 16)	0.3			0.3			0.7			1.0
Deferred income tax (recovery) expense (note 20)	(232.3		)	2.5			(234.2		)	9.7
Losses (gains) on sale of assets (note 5)	—			—			(1.3		)	2.6
Income from equity investments	(12.6		)	(7.3		)	(25.4		)	(24.4		)
Unrealized losses (gains) on risk management contracts (note 15)	10.5			25.3			(12.0		)	46.5
Realized loss on expiry of foreign exchange options (note 15)	—			—			36.0			—
Losses (gains) on investments	(14.8		)	(4.6		)	—			3.1
Amortization of deferred financing costs	18.1			3.1			24.4			13.8
Provision for doubtful accounts	7.7			—			7.7			—
Net change in pension and other post retirement benefits	2.2			—			2.2			—
Other	(2.9		)	(1.3		)	(2.8		)	(3.5		)
Asset retirement obligations settled	(0.9		)	(0.3		)	(2.5		)	(3.0		)
Distributions from equity investments	12.7			6.1			25.3			19.7
Changes in operating assets and liabilities (note 21)	(253.2		)	(42.6		)	(185.4		)	11.9
	$	(354.7	)	$	88.2		$	(18.3	)	$	390.6
Investing activities
Business acquisitions, net of cash acquired (note 3)	(5,931.0		)	—			(5,931.0		)	—
Acquisition of property, plant and equipment	(327.1		)	(179.5		)	(522.3		)	(358.9		)
Acquisition of intangible assets	(15.8		)	(12.0		)	(20.5		)	(16.7		)
Acquisition of investment in a publicly traded entity	—			—			—			(7.0		)
Contributions to equity investments	(58.8		)	(2.5		)	(78.2		)	(16.8		)
Loan to affiliate, net of repayment	—			(7.5		)	—			(12.5		)
Proceeds from disposition of investment (note 9)	63.4			—			76.5			—
Payment for derivative contracts	—			—			—			(36.0		)
Proceeds from disposition of assets, net of transaction costs (note 5)	0.3			0.2			10.2			70.4
	$	(6,269.0	)	$	(201.3	)	$	(6,465.3	)	$	(377.5	)
Financing activities
Net issuance (repayment) of short-term debt	202.5			22.1			154.1			(102.4		)
Issuance of long-term debt, net of debt issuance costs	3,266.6			209.7			3,273.9			749.0
Repayment of long-term debt	(66.4		)	(204.6		)	(272.2		)	(838.4		)
Net issuance of bankers’ acceptances	322.7			—			331.0			—
Dividends - common shares	(145.8		)	(90.1		)	(340.0		)	(267.0		)
Dividends - preferred shares	(16.9		)	(15.6		)	(49.7		)	(45.1		)
Distributions to non-controlling interest	(3.3		)	(1.0		)	(7.8		)	(5.5		)
Contributions from non-controlling interests	29.6			5.9			52.9			5.9
Net proceeds from shares issued on exercise of options	—			0.3			1.0			3.8
Net proceeds from issuance of common shares	2,413.0			58.1			2,546.9			175.4
Net proceeds from issuance of preferred shares	—			—			—			293.4
Net proceeds from sale of non-controlling interest (notes 5 and 10)	(8.7		)	—			912.3			24.1
Other	0.5			(0.1		)	—			(1.6		)
	$	5,993.8		$	(15.3	)	$	6,602.4		$	(8.4	)
Change in cash, cash equivalents and restricted cash	(629.9		)	(128.4		)	118.8			4.7
Effect of exchange rate changes on cash, cash equivalents and restricted cash	(2.0		)	0.9			(0.7		)	1.5
Net change in cash classified within assets held for sale (note 4)	(134.9		)	—			(134.9		)	—
Restricted cash acquired (note 21)	81.0			—			81.0			—
Cash, cash equivalents, and restricted cash beginning of period	793.7			167.8			43.7			34.1
Cash, cash equivalents, and restricted cash end of period (note 21)	$	107.9		$	40.3		$	107.9		$	40.3

See accompanying notes to the Consolidated Financial Statements.

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

The businesses of AltaGas Ltd. (AltaGas or the Corporation) are operated by AltaGas and a number of its subsidiaries including, without limitation, AltaGas Services (U.S.) Inc., AltaGas Utility Holdings (U.S.) Inc., and SEMCO Holding Corporation; in regards to the Gas business, AltaGas Extraction and Transmission Limited Partnership, AltaGas Pipeline Partnership, AltaGas Processing Partnership, AltaGas Northwest Processing Limited Partnership and Harmattan Gas Processing Limited Partnership; in regards to the Power business, Coast Mountain Hydro Limited Partnership, Northwest Hydro Limited Partnership, Blythe Energy Inc. (Blythe), and AltaGas San Joaquin Energy Inc.; and, in regards to the Utility business, AltaGas Utilities Inc. (AUI), Heritage Gas Limited (Heritage Gas), Pacific Northern Gas Ltd. (PNG), and SEMCO Energy, Inc. (SEMCO). SEMCO conducts its Michigan natural gas distribution business under the name SEMCO Energy Gas Company (SEMCO Gas) and its Alaska natural gas distribution business under the name ENSTAR Natural Gas Company (ENSTAR). Upon close of the initial public offering of AltaGas Canada Inc. (Note 4), AUI, Heritage Gas and PNG are no longer subsidiaries of AltaGas.

With the close of the acquisition of WGL Holdings, Inc. (the WGL Acquisition) on July 6, 2018, AltaGas’ subsidiaries also include: in regards to the Gas business, WGL Midstream, Inc. (WGL Midstream) and the retail gas marketing business of WGL Energy Services, Inc.; in regards to the Power business, WGSW Inc., WGL Energy Systems, Inc., and the retail power marketing business of WGL Energy Services, Inc.; and, in regards to the Utility business, Washington Gas Light Company and Hampshire Gas Company.

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 Gas, Power, and Utility business segments seeking optimal capital deployment. In the Gas 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 differentially invest in U.S utilities located in strong growth markets with increasing construction to support customer additions, system improvement and accelerated replacement programs. In the Power business, AltaGas seeks to create innovative solutions with light capital investment utilizing the Corporation’s clean energy expertise. AltaGas has three business segments:

· Gas, which transacts more than 3 Bcf/d of natural gas and includes natural gas gathering and processing, natural gas liquids (NGL) extraction and fractionation, transmission, storage, natural gas and NGL marketing, the Corporation’s 50 percent interest in AltaGas Idemitsu Joint Venture Limited Partnership (AIJVLP), an indirectly held one-third ownership investment in Petrogas Energy Corp. (Petrogas), through which AltaGas’ interest in the Ferndale Terminal is held, an interest in four regulated pipelines in the Marcellus/Utica gas formation in northeast United States and WGL’s retail gas marketing business;

· Power, which, subsequent to the WGL Acquisition and the close of the initial public offering of AltaGas Canada Inc. (see Note 4) includes 1,931 MW of gross capacity from natural gas-fired, hydro, wind, biomass, solar, other distributed generation and energy storage assets located in 2 provinces in Canada and 20 states and the District of Columbia in the United States. The Power business also includes energy efficiency contracting and WGL’s retail power marketing business; and

· Utilities, which, subsequent to the WGL Acquisition and the close of the initial public offering of AltaGas Canada Inc. (see Note 4) serves approximately 1.6 million customers with a rate base of approximately $4.4 billion through ownership of regulated natural gas distribution utilities across 5 jurisdictions in North America, and a regulated natural gas storage utility 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, delivering clean and affordable natural gas to homes and businesses.

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 2017 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.

As a result of the WGL Acquisition, 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 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, fair value of asset retirement obligations, fair value of property, plant and equipment and goodwill for impairment assessments, fair value of financial instruments, provisions for income taxes, assumptions used to measure employee future benefits, provisions for contingencies, and carrying value of regulatory assets and liabilities. Certain estimates are necessary for the regulatory environment in which AltaGas’ subsidiaries or affiliates operate, which often require amounts to be recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. By their nature, these estimates are subject to measurement uncertainty and may impact the Consolidated Financial Statements of future periods.

SIGNIFICANT ACCOUNTING POLICIES

Except as noted below and the addition of HLBV accounting as discussed above, 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 2017 annual audited Consolidated Financial Statements.

ADOPTION OF NEW ACCOUNTING STANDARDS

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

· ASU No. 2014-09 “Revenue from Contracts with Customers” and all related amendments (collectively “ASC 606”). AltaGas adopted ASC 606 using the modified retrospective method to contracts that have not been completed as at January 1, 2018. Under the modified retrospective method, the comparative information is not adjusted. The adoption of ASC 606 impacted the timing of revenue recognition in relation to contracts with take-or-pay or minimum volume commitments whereby the customers have make up rights for deficiency quantities. However, on adoption, no cumulative adjustments to opening retained earnings were required for this change in revenue recognition pattern as none of the customers had material deficiency quantities. Please also refer to Note 14 for further details. AltaGas does not expect the application of ASC 606 to have a material impact on its consolidated financial statements in 2018;

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

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

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

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

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

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

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

· ASU No. 2017-07 “Compensation — Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”. The amendments in this ASU revised the presentation of net periodic pension cost and net periodic postretirement benefit cost on the income statement and limited the components that are eligible for capitalization in assets to only the service cost component. AltaGas applied the change in presentation of the current service cost and other components of net benefit cost on the income statement retrospectively. As a result, $0.4 million and $1.2 million of net benefit cost associated with other components were reclassified from the line item “operating and administrative” to “other income” on the Consolidated Statements of Income for the three and nine months ended September 30, 2017. AltaGas applied the change related to the capitalization of the service cost prospectively. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

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

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

· ASU No. 2018-02 “Income Statement — Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”. The amendments in this ASU allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. AltaGas early adopted this ASU. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and

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

FUTURE CHANGES IN ACCOUNTING PRINCIPLES

In February 2016, FASB issued ASU No. 2016-02 “Leases”, which requires lessees to recognize on the balance sheet a right-of-use asset and a lease liability for all leases with lease terms greater than 12 months. Lessor accounting remains substantially unchanged, however, the ASU modifies what qualifies as a sales-type and direct financing lease and eliminates the real estate-specific provisions included in ASC 840. The ASU also requires additional disclosures regarding leasing arrangements. In January 2018, FASB issued ASU No. 2018-01 “Land Easement Practical Expedient for Transition to Topic 842” providing entities with an optional election not to evaluate existing and expired land easements not previously accounted for as leases under ASC 840 using the provisions of ASC 842. The amendments to the new leases standard are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. AltaGas is currently performing a scoping exercise by gathering a complete inventory of lease contracts in order to evaluate the impact of adopting ASC 842 on its consolidated financial statements, but expects that the new standard will have an impact on the Corporation’s balance sheet as all operating leases will need to be reflected on the balance sheet upon adoption. In addition, AltaGas currently expects to utilize the transition practical expedients which allow entities to not have to reassess whether an arrangement contains a lease under the provisions of ASC 842.

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

In February 2018, FASB issued ASU No. 2018-02 “Income Statement — Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”. The amendments in this ASU allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted and AltaGas plans to adopt this ASU effective July 1, 2018. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

In June 2018, FASB issued 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 amendments in this update are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ consolidated financial statements.

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 postretirement 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 August 2018, FASB issued 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 arrangements that include an internal use software license). 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.

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 for an aggregate purchase price of approximately $9.3 billion (US$7.1 billion), including the assumption of approximately $3.3 billion (US$2.5 billion) of debt and $41 million (US$31 million) of preferred shares.

Under the terms of the transaction, WGL shareholders received US$88.25 per common share. The net cash consideration was approximately $6.0 billion (US$4.6 billion). The WGL Acquisition was financed through net proceeds of approximately $2.3 billion from the sale of subscription receipts, draws on the fully committed acquisition credit facility of $3.0 billion (US$2.3 billion) and existing cash on hand. The draws on the acquisition credit facility included additional amounts for the payment of fees and regulatory commitments related to the WGL Acquisition. The sale of the subscription receipts was completed in the first quarter of 2017 and upon closing of the WGL Acquisition, the subscription receipts were exchanged into approximately 84.5 million common shares of AltaGas.

The WGL Acquisition is 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 is recognized as goodwill at the acquisition date.

The following table summarizes the preliminary 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 preliminary purchase price allocation reflects Management’s current best estimate of the fair value of WGL’s assets and liabilities based on the analysis of information obtained to date. As additional information becomes available, the purchase price allocation may differ materially from the preliminary purchase price allocation below. Any adjustments to the purchase price allocation will be made as soon as practicable but no later than one year from the date of acquisition.

The following table summarizes the estimated fair values that were assigned to the net assets of WGL at the date of acquisition:

Purchase consideration	$	5,973

Fair value assigned to net assets
Current assets	$	1,185
Property, plant and equipment	5,953
Intangible assets	627
Regulatory assets	402
Long-term investments	1,411
Other long-term assets	449
Current liabilities	(1,801		)
Long-term debt	(2,548		)
Preferred shares	(41		)
Regulatory liabilities	(1,131		)
Other long-term liabilities	(1,756		)
Non-controlling interest	(9		)
Fair value of net assets acquired	$	2,741
Goodwill	$	3,232

The fair value of property, plant and equipment was estimated using the valuation methodologies described in ASC 820, Fair Value Measurements and Disclosures, to value the property, plant and equipment purchased. The fair value of WGL’s rate regulated property, plant and equipment is determined using a market participant perspective, which is equal to the carrying amount. The preliminary fair values of the remaining non-regulated property, plant and equipment is determined using both the income and cost approaches and resulted in an estimated fair value decrease of approximately $88 million related to solar distributed generation assets.

Long-term investments include WGL’s 55 percent equity investment in Meade Pipeline Co. LLC. (Meade), a 10 percent equity interest in Mountain Valley Pipeline LLC, and a 30 percent equity interest in Stonewall Gas Gathering Systems LLC. Meade owns 39 percent of Central Penn, and WGL owns a 21 percent net interest in Central Penn. The preliminary fair value of these investments has been determined using an income approach, resulting in an estimated fair value increase of approximately $464 million.

Intangible assets consist of customer relationships, contracts relating to gas transportation capacity, and natural gas purchase and sale agreements for tax energy exports. The preliminary fair value of these assets is determined using an income approach, resulting in an estimated fair value of approximately $627 million.

The fair value of current assets and current liabilities approximate their carrying values due to their short-term nature.

The fair value of long-term debt was estimated 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, WGL or Washington Gas Light Company. This resulted in a fair value increase of approximately $87 million, with a corresponding regulatory offset.

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

The preliminary purchase price allocation includes goodwill of approximately $3.2 billion. The goodwill is primarily related to the investment in low risk, long-life rate regulated assets, opportunities to grow the gas midstream business, expanded access to capital and greater financial flexibility as a result of increased scale, and earnings diversification. The goodwill recognized as part of this transaction is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to this goodwill.

Pre-tax acquisition expenses and merger commitment costs for the three and nine months ended September 30, 2018 of approximately $217.1 million and $233.3 million, respectively, were incurred and included in the Consolidated Statements of Income (2017 — $9.5 million and $50.3 million, respectively). AltaGas expects to recognize additional acquisition-related expenses in the fourth quarter of 2018 predominantly related to the fulfilment of various regulatory commitments.

Upon completion of the WGL Acquisition, AltaGas began consolidating WGL. Since the closing date through September 30, 2018, WGL has generated approximately $464 million in revenues and $246 million in net loss after tax. The loss was primarily due to the payment of various regulatory commitments as well as seasonality in certain of WGL’s operating businesses.

The following supplemental unaudited, pro forma consolidated financial information for the three and nine months ended September 30, 2018 and 2017 gives effect to the WGL Acquisition as if it had closed on January 1, 2017. This pro forma information is presented for information purposes only and does not purport to be indicative of the results that would have occurred had the WGL Acquisition taken place at the beginning of 2017, nor is it indicative of the results that may be expected in future periods.

	Three months ended September 30					Nine months ended September 30
	2018			2017		2018			2017
Pro forma revenue	$	1,072		$	1,049	$	4,235		$	4,125
Pro forma net income (loss) after taxes	$	(618	)	$	38	$	(465	)	$	281

Pro forma revenue excludes the gains and losses on foreign exchange contracts used to mitigate the foreign exchange risks associated with the cash purchase price of WGL on the basis that the gains and losses are directly incremental to the WGL Acquisition and are non-recurring in nature. These adjustments increased pro forma revenue by $2 million, for the three and nine months ended September 30, 2018, and increased pro forma revenue by $10 million and $32 million, respectively, for the three and nine months ended September 30, 2017.

Pro forma net income (loss) after taxes excludes all non-recurring acquisition-related expenses and merger commitment costs incurred by AltaGas and WGL and AltaGas’ realized and unrealized gains and losses on foreign exchange contracts entered into to mitigate the foreign exchange risk associated with the WGL Acquisition. Pro forma net income after taxes was also adjusted for financing costs associated with the bridge facility for the WGL Acquisition, and amortization of fair value adjustments relating to property, plant and equipment, intangible assets, and other long-term investments as well as tax impacts of all the previously noted adjustments. For the three and nine month periods ended September 30, 2018, the total after-tax pro forma adjustments increased net income (loss) after taxes by $175 million and $142 million, respectively. For the three and nine months ended September 30, 2017, the total after-tax pro forma adjustments increased net income (loss) after taxes by $3 million and $28 million, respectively.

4. ASSETS HELD FOR SALE

As at	September 30, 2018		December 31, 2017
Assets held for sale
Cash	$	134.9	$	—
Accounts receivable	38.7		0.3
Inventory	11.3		—
Regulatory assets - current	1.5		—
Risk management assets - current	0.5		—
Prepaid expenses	4.8		—
Property, plant and equipment	1,222.6		5.3
Intangible assets	140.7		0.1
Goodwill	—		0.3
Regulatory assets - non-current	209.1		—
Deferred income taxes - non-current	2.8		—
Long-term investments and other assets	4.4		—
	$	1,771.3	$	6.0

Liabilities associated with assets held for sale
Accounts payable and accrued liabilities	$	48.9	$	—
Short-term debt	6.0		—
Current portion of long-term debt	8.0		—
Customer deposits	11.4		—
Regulatory liabilities - current	9.3		—
Other current liabilities	0.1		—
Long term debt	25.3		—
Asset retirement obligations	12.7		0.3
Deferred income taxes - non-current	85.2		—
Regulatory liabilities - non-current	21.5		—
Future employee obligations	28.9		—
	$	257.3	$	0.3

Initial Public Offering of AltaGas Canada Inc.

In September 2018, AltaGas filed a preliminary prospectus for the initial public offering (IPO) of AltaGas Canada Inc. (ACI), a wholly owned subsidiary of AltaGas. The final prospectus was filed on October 18, 2018. ACI will hold Canadian rate-regulated natural gas distribution utility assets and a contracted wind power asset in Canada, as well as an approximate 10 percent indirect equity interest in the Northwest Hydro facilities in British Columbia. With the exception of the interest in the Northwest Hydro facilities, which AltaGas will continue to consolidate subsequent to the close of the IPO, the assets and liabilities associated with the IPO were classified as held for sale as of September 30, 2018, which resulted in the reclassification of $1,278.1 million of assets to assets held for sale and $225.0 million of liabilities to liabilities associated with assets held for sale on the Consolidated Balance Sheets. In addition, a pre-tax provision of $74.6 million on property, plant and equipment and a pre-tax provision of $119.1 million on goodwill was recorded due to the reduction of the carrying value of these assets to the fair value less cost to sell. The assets held for sale are recorded in the Utility segment, with the exception of the wind asset which is recorded in the Power segment.

The IPO closed on October 25, 2018 (Note 24). Upon close, AltaGas holds approximately 45 percent of ACI common shares, which could be reduced to approximately 37 percent if the over-allotment option is exercised in full. The pre-tax income (loss) associated with these assets classified as held for sale for the three and nine months ended September 30, 2018 was a loss of $2.5 million and income of $23.8 million, respectively (2017 — loss of $1.9 million and income of $23.2 million, respectively).

Non-Core Midstream and Power Assets in Canada

In the third quarter of 2018, AltaGas entered into definitive agreements for the sale of selected non-core smaller scale gas midstream and power assets in Canada, as well as AltaGas’ commercial and industrial customer portfolio in Canada, for an aggregate purchase price of approximately $165.0 million. The transaction is subject to customary closing conditions and approvals, and is expected to be completed in the fourth quarter of 2018. Accordingly, the carrying value of the assets and liabilities was classified as held for sale, which resulted in the reclassification of $100.6 million of assets to assets held for sale and $10.8 million of liabilities to liabilities associated with assets held for sale on the Consolidated Balance Sheets. A pre-tax provision of $119.2 million on property, plant and equipment, $0.5 million on intangible assets, and a pre-tax provision of $5.1 million on goodwill were recognized in the third quarter of 2018 due to the reduction of the carrying value of the assets to fair value less costs to sell. These assets are recorded in the Gas and Power segments.

The transaction also includes the 43.7 million shares of Tidewater Midstream and Infrastructure Inc. previously held by AltaGas. This portion of the transaction was completed in September 2018 (Note 9).

Non-Core San Joaquin Power Assets in California

In the third quarter of 2018, AltaGas entered into an agreement for the sale of gas-fired power assets for a purchase price of approximately US$300.0 million. The assets comprise the Tracy, Hanford and Henrietta plants totaling 523 MW of capacity. The sale is subject to customary closing conditions and approvals, and is expected to be completed in the fourth quarter of 2018. Accordingly, the carrying value of the assets and liabilities were classified as held for sale, which resulted in the reclassification of $373.7 million of assets to assets held for sale and $20.8 million of liabilities to liabilities associated with assets held for sale on the Consolidated Balance Sheets. A pre-tax provision of $221.3 million on property, plant and equipment and a pre-tax provision of $119.3 million on intangible assets were recognized in the third quarter of 2018 due to the reduction of the carrying value of the assets to fair value less costs to sell. These assets are recorded in the Power segment.

Other U.S. Power Assets

In the third quarter of 2018, AltaGas entered into an agreement for the sale of Busch Ranch, a wind asset in the United States for a purchase price of approximately US$16.3 million. Accordingly, the carrying value of the assets and liabilities was classified as held for sale, which resulted in the reclassification of $18.9 million of assets to assets held for sale and $0.7 million of liabilities to liabilities associated with assets held for sale on the Consolidated Balance Sheets.

5. SALE OF MINORITY INTEREST AND OTHER DISPOSITIONS

Northwest Hydro Facilities

On June 22, 2018, AltaGas completed the disposition of a 35 percent indirect equity interest in the Northwest Hydro facilities for gross cash proceeds of approximately $921.6 million. The disposition was completed through the sale of 35 percent of Northwest Hydro Limited Partnership (NW Hydro LP), a subsidiary of AltaGas which indirectly holds the Northwest Hydro facilities. AltaGas will continue to consolidate NW Hydro LP (Note 10). As a result of the sale, in the second quarter of 2018, AltaGas recognized a non-controlling interest of $420.4 million, a deferred income tax liability of $153.3 million and contributed surplus of $334.6 million on the Consolidated Balance Sheets, net of transaction costs. There was no impact to the Consolidated Statements of Income upon closing of this transaction.

Other Dispositions

In March 2018, AltaGas completed the disposition of certain non-core facilities in the Gas segment for gross proceeds of approximately $7.0 million. As a result, AltaGas recognized a pre-tax gain on disposition of approximately $1.3 million in the Consolidated Statements of Income under the line item “other income” for the nine months ended September 30, 2018.

6. PROVISIONS ON ASSETS

Nine months ended September 30	2018		2017
Power	$	352.2	$	1.3
Gas	151.5		—
Utilities	193.7		—
	$	697.4	$	1.3

Power

In the third quarter of 2018, AltaGas recorded pre-tax provisions totaling $352.2 million in the Power segment. Of this, $340.6 million related to the Tracy, Hanford, and Henrietta gas-fired peaking plants in California that were classified as held for sale (see Note 4). The pre-tax provision on the California power assets was comprised of $221.3 million on property, plant, and equipment and $119.3 million on intangible assets. In addition, a pre-tax provision of $9.8 million was recorded on certain non-core power assets in Canada that were classified as held for sale (see Note 4) and $1.8 million was recorded on the Pomona natural gas-fired co-generation facility in the United States. During the nine months ended September 30, 2017, AltaGas recognized a pre-tax provision of $1.3 million on certain gas-fired peaking assets in Alberta.

Gas

In the third quarter of 2018, AltaGas recorded pre-tax provisions totaling $151.5 million in the Gas segment. The pre-tax provisions included $115.0 million related to certain non-core midstream assets that were classified as held for sale (see Note 4) and $36.5 million related to shut-in assets in the South, Cold Lake and Northwest operating areas. The total pre-tax provisions of $151.5 million were comprised of $145.9 million on property, plant, and equipment, $0.5 million on intangible assets, and $5.1 million on goodwill. No provisions on assets were recorded during the nine months ended September 30, 2017 for the Gas segment.

Utilities

In the third quarter of 2018, AltaGas recorded pre-tax provisions of $193.7 million related to certain rate-regulated natural gas distribution utility assets that were classified as held for sale (see Note 4). The pre-tax provision was comprised of $119.1 million on goodwill and $74.6 million on property, plant and equipment. No provisions on assets were recorded during the nine months ended September 30, 2017 for the Utilities segment.

7. INVENTORY

	September 30,		December 31,
As at	2018		2017
Natural gas held in storage	$	379.3	$	133.9
Materials and supplies	54.3		32.3
Renewable energy credits and emission compliance instruments	60.6		28.4
Other inventory	7.9		6.5
	$	502.1	$	201.1

8. GOODWILL

	September 30,			December 31,
As at	2018			2017
Balance, beginning of period	$	817.3		$	856.0
Provision on assets (notes 4 and 6)	(124.2		)	—
Business acquisition (note 3)	3,232.0			—
Foreign exchange translation	(21.8		)	(38.4		)
Reclassified to assets held for sale	—			(0.3		)
Balance, end of period	$	3,903.3		$	817.3

9. LONG-TERM INVESTMENTS AND OTHER ASSETS

As at	September 30, 2018		December 31, 2017
Investments in publicly-traded entities	$	18.6	$	95.0
Loan to affiliate	75.0		75.0
Deferred lease receivable	23.3		29.0
Debt issuance costs associated with credit facilities	9.2		20.3
Refundable deposits	15.4		14.9
Prepayment on long-term service agreements	77.1		68.1
Subscription receipts issuance costs	—		1.7
Contract asset	7.8		—
Rabbi trust (note 19)	58.0		—
Other	31.5		8.6
	$	315.9	$	312.6

In September 2018, as part of the agreement for the sale of non-core midstream and power assets in Canada, AltaGas sold 43.7 million shares of Tidewater Midstream and Infrastructure Inc. for gross proceeds of $63.4 million. For the three and nine months ended September 30, 2018, a realized loss of $2.0 million was recognized in the Consolidated Statements of Income under the line item “other income” in relation to the sale of these shares.

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:

Northwest Hydro Limited Partnership

On May 4, 2018, NW Hydro LP was formed to indirectly hold the assets of the Northwest Hydro facilities. On June 22, 2018, AltaGas closed the sale of a 35 percent indirect equity interest in its Northwest Hydro facilities through the sale of 35 percent of NW Hydro LP, and its general partner, Northwest Hydro GP Inc. (NW Hydro GP).

AltaGas has determined that NW Hydro 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 continued provision of all operational, maintenance and management functions for the Northwest Hydro facilities. In addition, AltaGas has the obligation to absorb the losses and the right to receive the benefits that could potentially be significant to the Northwest Hydro facilities. As such, AltaGas has consolidated NW Hydro LP and has recorded $420.4 million of the $921.6 million proceeds received as a non-controlling interest with the remainder of the proceeds, less deferred tax and transaction costs, recognized as contributed surplus in the amount of $334.6 million.

The assets of NW Hydro LP are the property of NW Hydro LP and are not available to AltaGas for any other purpose. NW Hydro LP’s asset balances can only be used to settle its own obligations. The liabilities of NW Hydro 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.

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, which is estimated to be $450 to $500 million, will be funded by AltaGas LPG and Vopak in proportion to their respective interests in RILE LP. As part of the arrangements, AltaGas entered into a long-term agreement for the capacity of RIPET with RILE LP, and AltaGas and certain of its subsidiaries will provide construction and operating services to RILE LP.

AltaGas has determined that RILE LP is a VIE in which it holds variable interests and is the primary beneficiary. In the determination that AltaGas is the primary beneficiary of the VIE, AltaGas noted that it has the power to direct the activities that most significantly impact the VIE’s economic performance through the construction, operating and marketing services provided to RILE LP. In addition, AltaGas has the obligation to absorb the losses and the right to receive the benefits that could potentially be significant to RILE LP through the long-term agreement for the capacity of RIPET. As such, AltaGas has consolidated RILE LP and recorded $20.0 million of the $24.1 million proceeds received from Vopak on formation of RILE LP as a non-controlling interest with the remainder of the proceeds less deferred tax recognized as contributed surplus in the amount of $3.0 million.

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

Variable Interest Entities Acquired in WGL Acquisition

In connection with the acquisition of WGL (Note 3), AltaGas has acquired both consolidated and unconsolidated VIEs:

Consolidated VIE Investments

At September 30, 2018, 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. Accordingly, these VIEs have been consolidated:

SFGF, SFRC, and SFGF II

WGSW, along with its various tax equity partners, formed the tax equity partnerships SFGF, SFRC, and SFGF II to acquire, own, and operate distributed generation solar projects nationwide. WGSW is the managing member of these investments and will provide cash equal to the purchase price of the solar projects less any contributions from the tax-equity partner for projects sold into the partnerships. WGL Energy Systems is the developer of the projects and sells them to the partnerships, and is the operations and maintenance provider.

Profits and losses are allocated between the partners under the Hypothetical Liquidation at Book Value (HLBV) method of accounting and the portion allocated to the tax equity partner is included in “net income (loss) attributable to non-controlling interest” on the accompanying Condensed Consolidated Statements of Income and is recorded to non-controlling interest on the accompanying Condensed Consolidated Balance Sheets.

When applying HLBV accounting, the Corporation determines the amount that it would receive if an equity investment entity were to liquidate all of its assets at book value (as valued in accordance with U.S. GAAP) and distribute that cash to the investors based on the contractually defined liquidation priorities. The change in the Corporation’s claim on the equity investment entity’s book value at the beginning and end of the reporting period (adjusted for contributions and distributions) is the Corporation’s share of the earnings or losses from the equity investment for the period.

SFEE

In 2016, WGSW and a tax equity partner formed SFEE to acquire distributed generation solar projects that were to be developed and sold by a third-party developer or WGL Energy Systems. New projects were to be designed and constructed under long-term power purchase agreements. SFEE is considered a VIE and is consolidated by WGSW.

ASD

WGSW is a limited partner in ASD, a limited partnership formed to own and operate a portfolio of residential solar projects, primarily rooftop photovoltaic power generation systems. SF ASD, a wholly-owned subsidiary of WGL Energy Systems, has management rights and control of ASD.

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

As at	September 30, 2018			December 31, 2017
Current assets	$	62.5		$	1.4
Property, plant and equipment	1,621.6			84.3
Intangible assets	246.9			—
Long-term investments and other assets	48.0			48.0
Current liabilities	(23.4		)	—
Other long term liabilities	(135.2		)	—
Deferred tax credits	(2.2		)	—
Net assets	$	1,818.2		$	133.7

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), 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, 2018, AltaGas held a $610.4 million equity method investment in Meade, inclusive of fair value adjustments on acquisition date (see Note 3). WGL Midstream plans to invest an estimated US$450 million for a 55 percent interest in Meade, the majority of which has already been spent. Meade owns 39 percent of Central Penn, and the Corporation’s total net ownership in Central Penn is 21 percent. 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 from equity investments” in the accompanying Consolidated Statements of Income and are added to or subtracted from the carrying amount of AltaGas’ investment balance.

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

11. INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD

In addition to AltaGas’ existing equity investments as described in Note 12 of the Annual Consolidated Financial Statements, in connection with the acquisition of WGL, AltaGas acquired the following investments accounted for by the equity method that are not considered VIEs:

Mountain Valley Pipeline, LLC (Mountain Valley)

WGL Midstream owns a 10 percent equity interest in Mountain Valley Pipeline, LLC. The proposed pipeline, which will be operated by EQT Midstream Partners, LP (EQT) and developed, constructed, and owned by Mountain Valley (a venture of EQT and other entities), will transport approximately 2.0 Bcf of natural gas per day and will extend EQT Corporation’s Equitrans system in Wetzel County, West Virginia to Transcontinental Gas Pipe Line Company LLC’s Station 165 in Pittsylvania County, Virginia. The pipeline is expected to span approximately 300 miles.

At September 30, 2018, AltaGas held a $410.9 million equity method investment in Mountain Valley, inclusive of fair value adjustments on acquisition date (see Note 3). WGL Midstream expects to invest approximately US$350 million in scheduled capital contributions through the in-service date of the pipeline based on its contracted share of project costs. The equity method is considered appropriate because Mountain Valley is a Limited Liability Company (LLC) with specific ownership accounts and ownership between five and fifty percent resulting in WGL Midstream maintaining a more than minor influence over the partnership operating and financing policies. Profits and losses are allocated under the HLBV method of accounting and are included in income from equity investments in the accompanying Consolidated Statements of Income and are added to or subtracted from the carrying amount of AltaGas’ investment balance.

In April 2018, WGL Midstream entered into a separate agreement with EQT to acquire a 5 percent equity interest in a project to build a lateral interstate natural gas pipeline connecting to the mainline.

Stonewall Gas Gathering System (Stonewall)

WGL Midstream has a 30 percent equity interest in an entity that owns and operates certain assets known as the Stonewall Gas Gathering System. Stonewall has the capacity to gather up to 1.4 Bcf of natural gas per day from the Marcellus production region

in West Virginia, and connects with an interstate pipeline system that serves markets in the mid-Atlantic region. As at September 30, 2018, the investment in Stonewall was $431.9 million, inclusive of fair value adjustments on acquisition date (see Note 3). Profits and losses are allocated under the HLBV method of accounting and are included in income from equity investments in the accompanying Consolidated Statements of Income.

Constitution Pipeline Company, LLC (Constitution)

WGL Midstream has an investment in Constitution, owning a 10 percent equity interest in the proposed pipeline venture. At September 30, 2018, the investment in Constitution was $nil, reflecting AltaGas’ fair value on acquisition date (see Note 3). This natural gas pipeline venture is proposed to transport natural gas from the Marcellus region in northern Pennsylvania to major northeastern markets.

In addition to the above non-VIE equity investments acquired in the WGL Acquisition, the Company’s investment in Meade (Note 10) is also accounted for using the equity method.

12. LONG-TERM DEBT

		September 30,			December 31,
As at	Maturity date	2018			2017
Credit facilities
$1,400 million unsecured extendible revolving(a)	15-May-2023	$	639.2		$	219.1
US$300 million unsecured extendible revolving(b)	15-May-2022	161.8			—
$25 million secured extendible revolving(c)	4-May-2023	—			—
Acquisition credit facility (d)	Jul 2019 - Jan 2020	2,914.3			—
Medium-term notes (MTNs)
$175 million Senior unsecured - 4.60 percent	15-Jan-2018	—			175.0
$200 million Senior unsecured - 4.55 percent	17-Jan-2019	200.0			200.0
$200 million Senior unsecured - 4.07 percent	1-Jun-2020	200.0			200.0
$350 million Senior unsecured - 3.72 percent	28-Sep-2021	350.0			350.0
$300 million Senior unsecured - 3.57 percent	12-Jun-2023	300.0			300.0
$200 million Senior unsecured - 4.40 percent	15-Mar-2024	200.0			200.0
$300 million Senior unsecured - 3.84 percent	15-Jan-2025	299.9			299.9
$100 million Senior unsecured - 5.16 percent	13-Jan-2044	100.0			100.0
$300 million Senior unsecured - 4.50 percent	15-Aug-2044	299.8			299.8
$350 million Senior unsecured - 4.12 percent	7-Apr-2026	349.8			349.8
$200 million Senior unsecured - 3.98 percent	4-Oct-2027	199.9			199.9
$250 million Senior unsecured - 4.99 percent	4-Oct-2047	250.0			250.0
WGL and Washington Gas medium-term notes
US$50 million Senior unsecured - 7.46 percent	5-Dec-2018	64.7			—
US$500 million Senior unsecured - 2.25 to 4.76 percent	Jan - Nov 2019	647.3			—
US$250 million Senior unsecured - 2.88 percent	12-Mar-2020	323.6			—
US$20 million Senior unsecured - 6.65 percent	20-Mar-2023	25.9			—
US$40.5 million Senior unsecured - 5.44 percent	11-Aug-2025	52.4			—
US$53 million Senior unsecured - 6.62 to 6.82 percent	Oct - 2026	68.6			—
US$72 million Senior unsecured - 6.40 to 6.57 percent	Feb - Sep 2027	93.2			—
US$52 million Senior unsecured - 6.57 to 6.85 percent	Jan - Mar 2028	67.3			—
US$8.5 million Senior unsecured - 7.50 percent	1-Apr-2030	11.0			—
US$50 million Senior unsecured - 5.70 to 5.78 percent	Jan - Mar 2036	64.7			—
US$75 million Senior unsecured - 5.21 percent	3-Dec-2040	97.1			—
US$75 million Senior unsecured - 5.00 percent	15-Dec-2043	97.1			—
US$300 million Senior unsecured - 4.22 to 4.60 percent	Sep - Dec 2044	388.4			—
US$450 million Senior unsecured - 3.80 percent	15-Sep-2046	582.5			—
SEMCO long-term debt
US$300 million SEMCO Senior secured - 5.15 percent(e)	21-Apr-2020	388.4			376.4
US$82 million CINGSA Senior secured - 4.48 percent(f)	2-Mar-2032	81.9			85.2
Debenture notes
PNG 2018 Series Debenture - 8.75 percent(c)(g)	15-Nov-2018	—			7.0
PNG 2025 Series Debenture - 9.30 percent(c)(g)	18-Jul-2025	—			13.0
PNG 2027 Series Debenture - 6.90 percent(c)(g)	2-Dec-2027	—			14.0
CINGSA capital lease - 3.50 percent	1-May-2040	0.5			0.5
CINGSA capital lease - 4.48 percent	4-Jun-2068	0.2			0.2
Fair value adjustment on WGL Acquisition (note 3)		84.8			—
		$	9,604.3		$	3,639.8
Less debt issuance costs		(34.8		)	(14.4		)
		9,569.5			3,625.4
Less current portion		(1,998.6		)	(188.9		)
		$	7,570.9		$	3,436.5

(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) Collateral for the Secured Debentures and secured extendible revolving credit facility consisted of a specific first mortgage on substantially all of PNG’s property, plant and equipment, and gas purchase and gas sales contracts, and a first floating charge on other property, assets and undertakings.

(d) US$2.0 billion of the Acquisition credit facility is due on January 6, 2020, with the remainder due on July 5, 2019. AltaGas expects to fully repay the facility in the fourth quarter of 2018, subject to the close of pending asset sales and the timing of offering of term debt and hybrid securities.

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

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

(g) PNG debentures totaling $33.3 million have been classified as liabilities associated with assets held for sale (note 4) at September 30, 2018.

13. ACCUMULATED OTHER COMPREHENSIVE INCOME

($ millions)	Available- for-sale			Defined benefit pension and PRB plans			Hedge net investments			Translation foreign operations			Equity investee			Total
Opening balance, January 1, 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 OCI	—			0.6			—			—			—			0.6
Adoption of ASU No. 2016-01 (note 2)	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

Opening balance, January 1, 2017	$	19.8		$	(11.3	)	$	(135.6	)	$	526.3		$	5.9		$	405.1
OCI before reclassification	(28.6		)	—			6.8			(198.2		)	(3.3		)	(223.3		)
Amounts reclassified from AOCI	—			0.7			—			—			—			0.7
Settlement of PRB plan	—			0.3			—			—			—			0.3
Current period OCI (pre-tax)	(28.6		)	1.0			6.8			(198.2		)	(3.3		)	(222.3		)
Income tax on amounts retained in AOCI	3.1			—			—			—			—			3.1
Income tax on amounts reclassified to earnings	—			(0.2		)	—			—			—			(0.2		)
Income tax on amounts related to settlement of PRB plan	—			(0.1		)	—			—			—			(0.1		)
Net current period OCI	(25.5		)	0.7			6.8			(198.2		)	(3.3		)	(219.5		)
Ending balance, September 30, 2017	$	(5.7	)	$	(10.6	)	$	(128.8	)	$	328.1		$	2.6		$	185.6

Reclassification From Accumulated Other Comprehensive Income

AOCI components reclassified	Income statement line item	Three months ended September 30, 2018			Nine months ended September 30, 2018
Defined benefit pension and PRB plans	Operating and administrative expense	$	0.2		$	0.6
Deferred income taxes	Income tax expenses — deferred	(0.1		)	(0.2		)
		$	0.1		$	0.4

AOCI components reclassified	Income statement line item	Three months ended September 30, 2017			Nine months ended September 30, 2017
Defined benefit pension and PRB plans	Operating and administrative expense	$	0.2		$	0.7
Deferred income taxes	Income tax expenses — deferred	(0.1		)	(0.2		)
		$	0.1		$	0.5

14. REVENUE

The following table disaggregates revenue by major sources for the period ended September 30, 2018:

	Three months ended September 30, 2018
	Gas		Power		Utilities			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	—		8.4		2.9			—			11.3
Total revenue from contracts with customers	$	220.8	$	259.1	$	297.9		$	—		$	777.8

Other sources of revenue
Revenue from alternative revenue programs (a)	$	—	$	—	$	13.3		$	—		$	13.3
Leasing revenue (b)	23.8		122.5		0.2			—			146.5
Risk management and trading activities (c)(d)	61.0		55.0		(0.3		)	(14.7		)	101.0
Other	—		4.4		(1.6		)	—			2.8
Total revenue from other sources	$	84.8	$	181.9	$	11.6		$	(14.7	)	$	263.6
Total revenue	$	305.6	$	441.0	$	309.5		$	(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. The majority of revenue generated by the Gas 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 Gas 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 of $114.1 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract, which is in scope of ASC 606, is reported in the 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 contract has a term of 20 years starting March 31, 2018.

	Nine months ended September 30, 2018
	Gas			Power		Utilities		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	0.6			8.4		8.2		—			17.2
Total revenue from contracts with customers	$	544.5		$	259.1	$	929.0	$	—		$	1,732.6

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

Revenue Recognition

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

Gas 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 also include gas sales to residential, commercial and industrial customers in certain states where WGL Energy 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 Company 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.

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 20 years. Commodity sales also include electricity sales to residential, commercial and industrial customers in certain states where WGL Energy Systems 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 Company is entitled to invoice the customer.

Utilities segment

Gas sales and transportation services

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

Gas storage services

Gas storage customers are billed monthly for services provided. Customer billings are based on four components: (i) reservation charges; (ii) capacity charges; (iii) injection/withdrawal charges; and (iv) excess charges. Reservation charges are based on the customer’s contract withdrawal quantity, capacity charges are based on the customer’s total contract quantity, and injection/withdrawal charges are based on the volume of gas delivered to or from the customer. Excess charges are applied to each day that the storage quantity exceeds 100 percent of the customer’s maximum storage quantity. Revenue is recognized as the service has been performed over time on a monthly basis, which corresponds to the invoice amount. The majority of these contracts have terms extending beyond one-year.

Contract Balances

As at September 30, 2018, a contract asset of $7.8 million has been recorded within long-term investments and other assets on the Consolidated Balance Sheets (December 31, 2017 — $nil). 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, 2018 there is a contract asset of $105.0 million (December 31, 2017 - $nil) recorded within accounts receivable 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 not just subject to the passage of time or until the projects are formally “accepted” by the federal government. Contract liabilities of $1.8 million (2017 - $nil) 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.

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, 2018:

	Remainder of 2018		2019		2020		2021		2022		> 2022		Total
Midstream service contracts	$	13.2	$	51.4	$	55.0	$	32.5	$	32.0	$	222.0	$	406.1
Gas sales and transportation services	4.0		6.1		12.9		16.9		16.8		19.6		76.3
Storage services	8.9		34.8		34.5		34.5		34.5		318.9		466.1
Other	21.8		12.5		3.0		1.5		1.4		3.8		44.0
	$	47.9	$	104.8	$	105.4	$	85.4	$	84.7	$	564.3	$	992.5

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.

15. 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.

September 30, 2018

Carrying
Amount

Level 1

Level 2

Level 3

Total
Fair Value

Financial assets

Fair value through net income(a)

Risk management assets - current

51.3

—

27.4

23.9

51.3

Risk management assets - non-current

33.0

—

15.0

18.0

33.0

Equity securities(b)

18.6

—

18.6

Fair value through regulatory assets/liabilities (a)

Risk management assets - current

12.8

—

0.9

11.9

12.8

Risk management assets - non-current

6.3

—

6.3

Amortized cost

Loans and receivables (b)

75.0

—

75.8

—

75.8

197.0

18.6

119.1

60.1

197.8

Financial liabilities

Fair value through net income(a)

Risk management liabilities - current

75.2

—

56.9

18.3

75.2

Risk management liabilities - non-current

77.4

—

16.3

61.1

77.4

Fair value through regulatory assets/liabilities (a)

Risk management liabilities - current

11.8

—

11.8

Risk management liabilities - non-current

95.1

—

0.1

95.0

95.1

Amortized cost

Current portion of long-term debt

1,998.6

—

1,868.6

—

1,868.6

Long-term debt

7,570.9

—

5,128.5

2,476.1

7,604.6

Other current liabilities (c)

19.3

—

19.3

—

19.3

Other long-term liabilities (c)

139.2

—

136.5

—

136.5

9,987.5

—

7,226.2

2,662.3

9,888.5

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

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

(c) Excludes non-financial liabilities.

	December 31, 2017
	Carrying Amount		Level 1		Level 2		Level 3		Total Fair Value
Financial assets
Fair value through net income
Risk management assets - current	$	38.6	$	—	$	38.6	$	—	$	38.6
Risk management assets - non-current	15.9		—		15.9		—		15.9
Equity securities(a)	95.0		95.0		—		—		95.0
Amortized cost
Loans and receivables (a)	75.0		—		85.6		—		85.6
	$	224.5	$	95.0	$	140.1	$	—	$	235.1
Financial liabilities
Fair value through net income
Risk management liabilities - current	$	57.6	$	—	$	57.6	$	—	$	57.6
Risk management liabilities - non-current	13.8		—		13.8		—		13.8
Amortized cost
Current portion of long-term debt	188.9		—		189.6		—		189.6
Long-term debt	3,436.5		—		3,568.3		—		3,568.3
Other current liabilities (b)	22.4		—		22.4		—		22.4
Other long-term liabilities (b)	146.0		—		147.7		—		147.7
	$	3,865.2	$	—	$	3,999.4	$	—	$	3,999.4

(a) Included under the line item “long-term investments and other assets” on the Consolidated Balance Sheets.

(b) 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, 2018:

	Net Fair Value			Valuation Technique	Unobservable Inputs	Range
Natural gas	$	(117.2	)	Discounted Cash Flow	Natural Gas Basis Price (per dekatherm)		($1.30) - $5.03
Natural gas	$	(4.6	)	Option Model	Natural Gas Basis Price (per dekatherm)		($1.28) - $4.80
					Annualized Volatility of Spot Market Natural Gas	37.46% - 900.98%
Electricity	$	(19.3	)	Discounted Cash Flow	Electricity Congestion Price (per megawatt hour)		($8.10) - $83.69

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

Three months ended

September 30, 2018

September 30, 2017

Natural
Gas

Electricity

Total

Natural
Gas

Electricity

Total

Balance, beginning of period

—

Acquired (note 3)

(134.4

)

(10.5

)

(144.9

)

—

Realized and unrealized gains (losses):

—

Recorded in income

8.4

(11.8

)

(3.4

)

Recorded in regulatory assets

1.7

—

1.7

—

Transfers out of Level 3

0.8

—

0.8

—

Purchases

—

3.8

—

Settlements

1.7

(0.8

)

0.9

—

Balance, end of period

(121.8

)

(19.3

)

(141.1

)

—

Nine months ended

September 30, 2018

September 30, 2017

Natural
Gas

Electricity

Total

Natural
Gas

Electricity

Total

Balance, beginning of period

—

Acquired (note 3)

(134.4

)

(10.5

)

(144.9

)

—

Realized and unrealized gains (losses):

—

Recorded in income

8.4

(11.8

)

(3.4

)

Recorded in regulatory assets

1.7

—

1.7

—

Transfers out of Level 3

0.8

—

0.8

—

Purchases

—

3.8

—

Settlements

1.7

(0.8

)

0.9

—

Balance, end of period

(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, 2018 were due to an increase in valuations using observable market inputs. Transfers into Level 3 during the period ended September 30, 2018 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
	2018			2017			2018			2017
Natural gas	$	(3.8	)	$	(1.9	)	$	(15.0	)	$	(1.1	)
NGL frac spread	(7.4		)	(10.2		)	(4.6		)	(0.6		)
Power	2.2			(3.0		)	(2.9		)	(12.1		)
Foreign exchange	(1.5		)	(10.2		)	34.5			(32.7		)
	$	(10.5	)	$	(25.3	)	$	12.0		$	(46.5	)

Offsetting of Derivative Assets and Derivative Liabilities

Certain 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 derivatives 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.

September 30, 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

123.1

(42.0

)

—

81.1

NGL frac spread

1.3

(0.4

)

—

0.9

Power

30.7

(9.0

)

—

21.7

Foreign exchange

(0.3

)

—

(0.3

)

154.8

(51.4

)

—

103.4

Risk management liabilities (b)

Natural gas

263.9

(42.0

)

(12.8

)

209.1

NGL frac spread

29.8

(0.4

)

—

29.4

Power

43.5

(9.0

)

(12.4

)

22.1

337.2

(51.4

)

(25.2

)

260.6

(a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $64.1 million and risk management assets (non-current) balance of $39.3 million.

(b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $87.0 million, risk management liabilities (non-current) balance of $172.5 million, and an embedded derivative balance in accounts payable of $1.1 million.

	December 31, 2017
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	$	41.0	$	(6.2	)	$	—	$	34.8
NGL frac spread	1.3		(0.3		)	—		1.0
Power	17.7		(0.7		)	—		17.0
Foreign exchange	1.7		—			—		1.7
	$	61.7	$	(7.2	)	$	—	$	54.5

Risk management liabilities (b)
Natural gas	$	35.1	$	(6.2	)	$	—	$	28.9
NGL frac spread	25.3		(0.3		)	—		25.0
Power	14.0		(0.7		)	4.2		17.5
	$	74.4	$	(7.2	)	$	4.2	$	71.4

(a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $38.6 million and risk management assets (non-current) balance of $15.9 million.

(b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $57.6 million and risk management liabilities (non-current) balance of $13.8 million.

Cash Collateral

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

	September 30, 2018		December 31, 2017
Collaterals posted with counterparties	$	77.8	$	—
Cash collateral held representing an obligation	$	4.0	$	—

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. 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 the most intrusive credit-risk-related contingent features underlying these agreements were triggered:

	September 30, 2018		December 31, 2017
Risk management liabilities with credit-risk-contingent features	$	7.9	$	—
Maximum potential collateral requirements	$	1.4	$	—

Notional Summary

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

	September 30, 2018	December 31, 2017
Natural Gas
Sales	859,214,213 GJ	94,804,039 GJ
Purchases	1,674,993,508 GJ	61,980,315 GJ
Swaps	621,061,437 GJ	6,039,642 GJ
NGL Frac Spread
Propane swaps	2,220,618 Bbl	1,992,927 Bbl
Butane swaps	181,582 Bbl	130,088 Bbl
Crude oil swaps	409,546 Bbl	518,665 Bbl
Natural gas swaps	12,370,977 GJ	11,428,515 GJ
Power
Sales	4,449,998 MWh	2,169,321 MWh
Purchases	2,936,481 MWh	17,520 MWh
Swaps	6,922,518 MWh	1,563,160 MWh

Foreign Exchange

AltaGas may designate its U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. As at September 30, 2018, AltaGas has designated US$2,438.3 million of outstanding debt as a net investment hedge (December 31, 2017 - $nil). For the three and nine months ended September 30, 2018, AltaGas incurred after-tax unrealized gains of $37.4 million arising from the translation of debt in OCI (2017 - after-tax unrealized gains of $nil and $6.8 million, respectively).

In addition, to mitigate the foreign exchange risks associated with the cash purchase price of WGL, AltaGas entered into foreign currency option contracts with an aggregate notional value of US$1.2 billion which expired in May 2018. These foreign currency option contracts did not qualify for hedge accounting. Therefore, all changes in fair value were recognized in net income. For the three and nine months ended September 30, 2018, unrealized gains of $nil and $34.3 million, respectively, and realized losses of $nil and $36.0 million, respectively were recognized in revenue in relation to these contracts (2017 — unrealized losses of $10.3 million and $32.2 million, respectively). During the second quarter of 2018, AltaGas entered into foreign exchange forward contracts with an aggregate notional value of $3.2 billion which settled in July 2018. These foreign currency derivatives do not qualify for hedge accounting. For the three and nine months ended September 30, 2018, unrealized losses of $1.7 million and $nil, respectively, and a realized gain $1.3 million was recognized in income in relation to these forwards (2017 - $nil).

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 period from close of the WGL Acquisition to September 30, 2018, pre-tax losses of $1 million were recorded related to these instruments (2017 - $nil).

16. SHAREHOLDERS’ EQUITY

Authorization

AltaGas is authorized to issue an unlimited number of voting common shares. AltaGas is also authorized to issue preferred shares not to exceed 50 percent of the voting rights attached to the issued and outstanding common shares.

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

The Plan consists of three components: a Premium Dividend™ component, a Dividend Reinvestment component and an Optional Cash Purchase component.

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

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

Each of the components of the Plan are subject to prorating and other limitations on availability of new common shares in certain events. The “average market price”, in respect of a particular dividend payment date, refers to the arithmetic average (calculated to four decimal places) of the daily volume weighted average trading prices of common shares on the Toronto Stock Exchange for the trading days on which at least one board lot of common shares is traded during the 10 business days immediately preceding the applicable dividend payment date. Such trading prices will be appropriately adjusted for certain capital changes (including common share subdivisions, common share consolidations, certain rights offerings and certain dividends). Shareholders resident outside of Canada are not entitled to participate in the Premium DividendTM component of the Plan. Shareholders resident outside of Canada (other than the U.S.) may participate in the Dividend Reinvestment component or the Optional Cash Purchase component of the Plan only if their participation is permitted by the laws of the jurisdiction in which they 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. Effective December 18, 2018, the Premium Dividend™ portion of the plan has been suspended.

TM Denotes trademark of Canaccord Genuity Corp.

Common Shares Issued and Outstanding	Number of shares	Amount
January 1, 2017	166,906,833	$	3,773.4
Shares issued for cash on exercise of options	240,125	6.5
Deferred taxes on share issuance cost	—	(8.3		)
Shares issued under DRIP	8,132,258	236.3
December 31, 2017	175,279,216	4,007.9
Shares issued on conversion of subscription receipts, net of issuance costs	84,510,000	2,321.1
Shares issued for cash on exercise of options	46,775	1.1
Deferred taxes on share issuance costs	—	13.3
Shares issued under DRIP	9,036,649	223.5
Issued and outstanding at September 30, 2018	268,872,640	$	6,566.9

Preferred Shares

As at	September 30, 2018				December 31, 2017
Issued and Outstanding	Number of shares	Amount			Number of shares	Amount
Series A	5,511,220	$	137.8		5,511,220	$	137.8
Series B	2,488,780	62.2			2,488,780	62.2
Series C	8,000,000	205.6			8,000,000	205.6
Series E	8,000,000	200.0			8,000,000	200.0
Series G	8,000,000	200.0			8,000,000	200.0
Series I	8,000,000	200.0			8,000,000	200.0
Series K	12,000,000	300.0			12,000,000	300.0
Washington Gas
$4.80 series	150,000	19.7			—	—
$4.25 series	70,600	9.4			—	—
$5.00 series	60,000	7.9			—	—
Share issuance costs, net of taxes		(27.9		)		(27.9		)
Fair value adjustment on WGL Acquisition (note 3)		4.1				—
	52,280,600	$	1,318.8		52,000,000	$	1,277.7

In connection with the WGL Acquisition, AltaGas assumed Washington Gas’ preferred stock. Washington Gas has three series of cumulative preferred stock outstanding, and each series is subject to redemption by Washington Gas:

	Current yield		Annual dividend per share		Redemption price per share
Washington Gas
$4.80 series	4.41	%	US$	4.80	US$	101
$4.25 series	4.41	%	US$	4.25	US$	105
$5.00 series	4.41	%	US$	5.00	US$	102

Share Option Plan

AltaGas has an employee share option plan under which employees and directors are eligible to receive grants. As at September 30, 2018, 21,974,766 shares were reserved for issuance under the plan. As at September 30, 2018, 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, 2018, unexpensed fair value of share option compensation cost associated with future periods was $1.2 million (December 31, 2017 - $1.3 million).

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

	September 30, 2018				December 31, 2017
	Options outstanding				Options outstanding
As at	Number of options		Exercise price(a)		Number of options		Exercise price(a)
Share options outstanding, beginning of period	4,533,761		$	32.35	4,119,386		$	32.39
Granted	516,825		26.32		848,000		30.80
Exercised	(46,775	)	22.13		(240,125	)	24.63
Forfeited	(111,813	)	31.77		(193,500	)	36.36
Expired	(3,000	)	26.23		—		—
Share options outstanding, end of period	4,888,998		$	31.82	4,533,761		$	32.35
Share options exercisable, end of period	3,497,109		$	32.25	3,326,197		$	31.93

(a) Weighted average.

As at September 30, 2018, the aggregate intrinsic value of the total share options exercisable was $1.0 million (December 31, 2017 - $6.0 million), the total intrinsic value of share options outstanding was $1.0 million (December 31, 2017 - $6.0 million) and the total intrinsic value of share options exercised was $0.2 million (December 31, 2017 - $1.4 million).

The following table summarizes the employee share option plan as at September 30, 2018:

	Options outstanding				Options exercisable
		Weighted		Weighted average		Weighted		Weighted average
	Number	average		remaining	Number	average		remaining
	outstanding	exercise price		contractual life	exercisable	exercise price		contractual life
$14.24 to $18.00	150,250	$	15.12	0.53	150,250	$	15.12	0.53
$18.01 to $25.08	444,700	20.75		2.08	444,700	20.75		2.08
$25.09 to $50.89	4,294,048	33.55		3.58	2,902,159	34.89		3.07
	4,888,998	$	31.82	3.35	3,497,109	$	32.25	2.84

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.

PUs, RUs, and DSUs	September 30, 2018		December 31, 2017
(number of units)
Balance, beginning of period	564,549		364,839
Granted	142,665		386,126
Additional units added by performance factor	—		24,301
Vested and paid out	(65,762	)	(221,775	)
Forfeited	(39,213	)	(27,279	)
Units in lieu of dividends	36,518		38,337
Outstanding, end of period	638,757		564,549

For the three and nine months ended September 30, 2018, the compensation expense recorded for the MTIP and DSUP was a recovery of $0.2 million and an expense of $2.7 million, respectively (2017 — expense of $1.8 million and $5.0 million, respectively). As at September 30, 2018, the unrecognized compensation expense relating to the remaining vesting period for the MTIP was $7.2 million (December 31, 2017 - $8.4 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						Nine months ended September 30
	2018			2017			2018			2017
Numerator:
Net income (loss) applicable to controlling interests	$	(709.3	)	$	33.1		$	(626.3	)	$	86.2
Less: Preferred share dividends	(16.9		)	(15.6		)	(49.7		)	(45.1		)
Net income (loss) applicable to common shares	$	(726.2	)	$	17.5		$	(676.0	)	$	41.1
Denominator:
(millions)
Weighted average number of common shares outstanding	261.3			171.9			206.0			169.9
Dilutive equity instruments(a)	0.1			0.2			0.1			0.3
Weighted average number of common shares outstanding - diluted	261.4			172.1			206.1			170.2
Basic net income (loss) per common share	$	(2.78	)	$	0.10		$	(3.28	)	$	0.24
Diluted net income (loss) per common share	$	(2.78	)	$	0.10		$	(3.28	)	$	0.24

(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, 2018, 4.3 million and 4.1 million share options, respectively (2017 — 3.8 million and 2.9 million, respectively) were excluded from the diluted net income (loss) per share calculation as their effects were anti-dilutive.

18. COMMITMENTS, CONTINGENCIES AND GUARANTEES

Commitments

AltaGas has long-term natural gas purchase and transportation arrangements, service agreements, storage contracts 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.

As a result of the acquisition of WGL, AltaGas’ operating lease commitments increased by approximately $169.3 million.

AltaGas’ utilities (including Washington Gas) 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 2018 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. As a result of the WGL Acquisition, AltaGas’ gas purchase, transportation, and storage services commitments increased by approximately $45 billion, the majority of which relate to 2023 and beyond. In addition, AltaGas’ electricity purchase agreements increased by approximately $873.4 million as a result of the WGL Acquisition.

In connection with the WGL Acquisition, AltaGas and WGL have made commitments totaling approximately US$150.0 million related to the terms of the Public Service Commission of the District of Columbia settlement agreement and the conditions of approval from the Maryland Public Service Commission and the Commonwealth of Virginia State Corporation Commission. These commitments include US$56.4 million in rate credits distributable to both residential and non-residential customers, gas expansion and other programs in Maryland counties of approximately US$57.1 million, various public interest commitments totaling approximately US$33.3 million, safety programs of approximately US$2.8 million, and a renewable natural gas study of approximately US$0.4 million. In the third quarter of 2018, AltaGas paid approximately US$80.0 million of the regulatory commitments.

AltaGas also committed to make payments of approximately US$13 million for retention payments to senior executives and severance costs related to the retirement of senior executives, with the potential for additional payments in the future. In the third quarter of 2018, AltaGas paid approximately US$7.0 million of the retention and severance payments.

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 and variable fees of approximately $60.1 million over the term of the contract.

On October 4, 2017, Heritage Gas signed a Precedent Agreement (PA) with the intention of entering into a long-term (22 year) contract with Portland Natural Gas Transmission System (PNGTS) for natural gas transportation capacity from the Dawn Hub in Ontario to Nova Scotia on the Maritimes and Northeast Pipeline (M&NP) system. The PA with PNGTS was subject to Heritage Gas satisfying a condition precedent of obtaining regulatory approval by July 31, 2018 for the contract to proceed. On June 1, 2018, Heritage Gas received approval from the Nova Scotia Utility and Review Board (NSUARB) to enter into this contract and recover associated costs of the contract from its customers through regulated rates. The contract will commence on November 1, 2018.

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, 2018, approximately $191.7 million is expected to be paid over the next 18 years, of which $59.8 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.

In 2007, AltaGas entered into a service and maintenance agreement with Enercon GmbH for the wind turbines for Bear Mountain. AltaGas has an obligation to pay a minimum of $6.3 million over the next four years.

Guarantees

In October 2014, Heritage Gas Limited, a wholly-owned subsidiary of AltaGas, entered into a throughput service contract with Enbridge Inc. (formerly Spectra Energy Corp.) for the use of the expansion of its Algonquin Gas Transmission and Maritimes & Northeast Pipeline systems (the Atlantic Bridge Project). The contract will commence upon completion of the construction of the pipelines and it will expire 15 years thereafter. AltaGas has two guarantees outstanding that total US$91.7 million to stand by all payment obligations under the transportation agreement.

WGL has guaranteed payments primarily for certain commitments on behalf of some of its subsidiaries. WGL has also guaranteed payments for certain of its external partners. As at September 30, 2018, WGL 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.

As a result of the WGL Acquisition, AltaGas has the following additional contingencies:

Antero Contract

Washington Gas and WGL Midstream contracted in June 2014 with Antero Resources Corporation (Antero) to buy gas from Antero at invoiced prices based on an index, and at a delivery point, specified in the contracts. Since deliveries began, however, the index price paid has been more than the fair market value at the same physical delivery point, resulting in losses within WGL entities of approximately US$29.6 million. Accordingly, Washington Gas and WGL Midstream notified Antero that it sought to apply a provision of the contracts that would permit a new index to be established. Antero objected, claiming that the contract provisions permitting re-pricing did not apply, unless Antero itself chose to sell gas at cheaper prices at the delivery point (which

Antero claimed it had not). The dispute was arbitrated in January 2017, and the arbitral tribunal ruled in favor of Antero on the applicability of the re-pricing mechanism. However, the tribunal ruled that it lacked authority to determine whether Antero was in breach of its obligation to deliver gas to Washington Gas and WGL Midstream at a point where they could obtain the higher pricing. Accordingly, Washington Gas and WGL Midstream filed suit in state court in Colorado for a determination of this issue. The state court granted Antero’s motion to dismiss the case, however the court of appeals reversed the district court’s decision to dismiss WGL’s complaint in October 2018 and remanded the case back to the district court.

Separately, Antero has initiated suit against Washington Gas and WGL Midstream, claiming that they have failed to purchase specified daily quantities of gas and seeking alleged cover damages exceeding US$100 million as of April 4, 2018 according to Antero’s complaint. Washington Gas and WGL Midstream oppose both the validity and amount of Antero’s claim. WGL believes the probability that Antero could succeed in collecting these penalties is remote therefore no accrual was made as of September 30, 2018. In December 2017, WGL Midstream amended its purchase contract with Antero and, effective February 1, 2018, is no longer obligated to purchase gas at the delivery point that is the subject of these disputes.

Silver Spring, Maryland Incident

Washington Gas has continually worked with the National Transportation and Safety Board (NTSB) to support its investigation of the August 2016 explosion and fire at an apartment complex on Arliss Street in Silver Spring, Maryland, the cause of which has not been determined. Additional information will be made available by the NTSB at the appropriate time. A total of 40 civil actions related to the incident have been filed against WGL and Washington Gas in the Circuit Court for Montgomery County, Maryland. All of these suits seek unspecified damages for personal injury and/or property damage. An initial class action suit filed against WGL and Washington Gas was amended to assert property damage and loss of use claims. WGL maintains excess liability insurance coverage from highly-rated insurers, subject to a nominal self-insured retention and expects this coverage will be sufficient to cover any significant liability to it that may result from this incident. Management is unable to determine a range of potential losses that is reasonably possible of occurring and therefore has not recorded a reserve associated with this incident. Washington Gas was invited by the NTSB to be a party to the investigation and in that capacity, continues to work closely with the NTSB to help determine the cause of this incident.

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.

The following defined benefit and post-retirement benefit plans were acquired in connection with the acquisition of WGL:

Defined Benefit Plans:

· Qualified Pension Plan - Washington Gas maintains a qualified, trusteed, non-contributory defined benefit pension plan covering most active and vested former employees of Washington Gas and certain employees of WGL subsidiaries. The non-contributory defined benefit pension plan is closed to all employees hired on or after January 1, 2010.

· Supplemental Executive Retirement Plan (DB SERP) - several executive officers of Washington Gas participate in the non-funded DB SERP, a nonqualified pension plan. The DB SERP was closed to new entrants beginning January 1, 2010.

· Defined Benefit Restoration Plan (DB Restoration) - a non-funded defined benefit restoration plan for the purpose of providing supplemental pension and pension-related benefits to a select group of management employees of Washington Gas.

Post-retirement Benefit Plans:

· Life Plan - Washington Gas provides life insurance benefits for retired employees of Washington Gas and certain employees of WGL subsidiaries

· Retiree Medical Plan — under this plan Washington Gas provides medical, prescription drug and dental benefits through Preferred Provider Organization (PPO) or Health Maintenance Organization (HMO) plans for eligible retirees and dependents not yet receiving Medicare benefits.

· Health Reimbursement Account (HRA) Plan — under this plan retirees age 65 and older and dependents receive an annual subsidy to help purchase supplemental medical, prescription drug and dental coverage in the marketplace.

Rabbi trusts have been funded to satisfy the employee benefit obligations associated with WGL’s various pension plans for a total of $84.2 million. These balances are included in prepaid expenses and other current assets and long-term investments and other assets in the Consolidated Balance Sheets.

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

Three months ended September 30, 2018

Canada

United States

Total

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.

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

Nine months ended September 30, 2018

Canada

United States

Total

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.

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

	Three months ended September 30, 2017
	Canada						United States						Total
				Post-						Post-						Post-
	Defined			retirement			Defined			retirement			Defined			retirement
	Benefit			Benefits			Benefit			Benefits			Benefit			Benefits
Current service cost (a)	$	2.0		$	0.2		$	1.7		$	0.4		$	3.7		$	0.6
Interest cost (b)	1.4			0.2			2.8			0.7			4.2			0.9
Expected return on plan assets (b)	(1.5		)	(0.1		)	(3.9		)	(1.1		)	(5.4		)	(1.2		)
Amortization of net actuarial loss (b)	0.2			—			—			—			0.2			—
Amortization of regulatory asset/liability (b)	0.3			—			1.6			(0.1		)	1.9			(0.1		)
Net benefit cost (income) recognized	$	2.4		$	0.3		$	2.2		$	(0.1	)	$	4.6		$	0.2

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

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

	Nine months ended September 30, 2017
	Canada						United States						Total
				Post-						Post-						Post-
	Defined			retirement			Defined			retirement			Defined			retirement
	Benefit			Benefits			Benefit			Benefits			Benefit			Benefits
Current service cost (a)	$	5.8		$	0.5		$	5.3		$	1.2		$	11.1		$	1.7
Interest cost (b)	4.3			0.5			8.7			2.2			13.0			2.7
Expected return on plan assets (b)	(4.4		)	(0.2		)	(12.1		)	(3.5		)	(16.5		)	(3.7		)
Settlement of plan (b)	—			—			—			(0.1		)	—			(0.1		)
Amortization of past service cost (b)	0.1			—			—			—			0.1			—
Amortization of net actuarial loss (b)	0.6			—			—			—			0.6			—
Amortization of regulatory asset/liability (b)	0.9			0.1			4.9			(0.2		)	5.8			(0.1		)
Net benefit cost (income) recognized	$	7.3		$	0.9		$	6.8		$	(0.4	)	$	14.1		$	0.5

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

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

20. INCOME TAXES

The effective income tax rates for the three and nine months ended September 30, 2018 were approximately 23.7 percent and 24.3 percent, respectively (2017 — 28.2 percent and 31.6 percent, respectively). The decrease in the effective tax rate for the three and nine months ended September 30, 2018 was mainly due to the decrease in the U.S. Federal tax rate from 35 percent to 21 percent. In addition, a lower amount of the transaction costs incurred on the WGL Acquisition was non-deductible in the first nine months of 2018 than in the first nine months of 2017. This was partially offset by an increase to the uncertain tax provision in the first quarter of 2018.

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
	2018			2017			2018			2017
Source (use) of cash:
Accounts receivable	$	9.2		$	(20.3	)	$	139.4		$	77.0
Inventory	(134.5		)	(51.8		)	(95.9		)	1.3
Other current assets	(45.3		)	(1.0		)	(34.6		)	12.0
Regulatory assets (current)	(8.1		)	(0.4		)	(8.6		)	(0.5		)
Accounts payable and accrued liabilities	(88.0		)	6.5			(153.9		)	(22.8		)
Customer deposits	33.5			11.4			22.5			(1.6		)
Regulatory liabilities (current)	2.1			(1.5		)	13.5			(9.8		)
Other current liabilities	(4.1		)	1.4			(9.2		)	4.3
Other operating assets and liabilities	(18.0		)	13.1			(58.6		)	(48.0		)
Changes in operating assets and liabilities	$	(253.2	)	$	(42.6	)	$	(185.4	)	$	11.9

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

	Three months ended September 30				Nine months ended September 30
	2018		2017		2018		2017
Interest paid (net of capitalized interest)	$	106.7	$	33.2	$	189.2	$	121.4
Income taxes paid	$	6.8	$	6.0	$	27.9	$	29.5

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

As at September 30	2018		2017
Cash and cash equivalents	$	14.1	$	25.1
Restricted cash holdings from customers - current	3.8		7.7
Restricted cash holdings from customers - non-current	5.8		7.5
Restricted cash included in prepaid expenses and other current assets(a)	26.2		—
Restricted cash included in long-term investments and other assets(a)	58.0		—
Cash, cash equivalents and restricted cash per consolidated statement of cash flow	$	107.9	$	40.3

(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 (see Note 19). On the date of the WGL Acquisition, the restricted cash balance related to Rabbi trusts was $81.0 million.

22. SEASONALITY

The Utility 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.

The power generation at the run-of-river hydro-facilities Forrest Kerr, Volcano Creek, and McLymont Creek occurs substantially from mid second quarter through early fourth quarter, resulting in weaker results in the first and fourth quarters.

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.

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:

Gas		· NGL processing and extraction plants;
		· transmission pipelines to transport natural gas and NGL;
		· natural gas gathering lines and field processing facilities;
		· purchase and sale of natural gas, including to commercial and industrial users;
		· natural gas storage facilities;
		· liquefied petroleum gas (LPG) terminal currently under construction;
		· natural gas and NGL marketing;
		· equity investment in Petrogas, a North American entity engaged in the marketing, storage and distribution of NGL, drilling fluids, crude oil and condensate diluents;
		· interests in four regulated gas pipelines in the Marcellus/Utica basins; and
		· WGL’s retail gas marketing business.

Power		· natural gas-fired, wind, biomass and hydro power generation assets, whereby outputs are generally sold under long-term power purchase agreements, both operational and under development;
		· energy storage;
		· distributed generation assets; and
		· sale of power to commercial and industrial users in Alberta, Washington D.C., Maryland, Virginia, Delaware, and Pennsylvania.

Utilities		· rate-regulated natural gas distribution assets in Michigan, Alaska, District of Columbia, Maryland, Virginia, Alberta, British Columbia and Nova Scotia; and
		· rate-regulated natural gas storage in Michigan, Alaska, and Virginia.

Corporate		· the cost of providing corporate services, financing and general corporate overhead, investments in certain public and private entities, corporate assets, financing other segments and the effects of changes in the fair value of certain risk management contracts. Once the risk management contracts are settled, the realized gains and losses are recorded in the reporting segment to which the derivative instruments relate.

The following table provides a reconciliation of segment revenue to the disaggregated revenue table as disclosed under Note 14 of these unaudited condensed interim Consolidated Financial Statements:

Three months ended September 30, 2018

Gas

Power

Utilities

Corporate

Total

External revenue (note 11)

305.6

441.0

309.5

(14.7

)

1,041.4

Intersegment revenue

7.5

2.6

4.2

(0.1

)

14.2

Segment revenue

313.1

443.6

313.7

(14.8

)

1,055.6

Nine months ended September 30, 2018

Gas

Power

Utilities

Corporate

Total

External revenue (note 11)

864.8

752.1

942.1

(29.4

)

2,529.6

Intersegment revenue

81.0

6.4

5.5

(0.1

)

92.8

Segment revenue

945.8

758.5

947.6

(29.5

)

2,622.4

The following tables show the composition by segment:

Three months ended September 30, 2018

Gas

Power

Utilities

Corporate

Intersegment
Elimination(a)

Total

Segment revenue

313.1

443.6

313.7

(14.8

)

(14.2

)

1,041.4

Cost of sales

(202.7

)

(289.4

)

(90.5

)

—

11.5

(571.1

)

Operating and administrative

(51.8

)

(50.1

)

(386.5

)

(10.3

)

2.8

(495.9

)

Accretion expenses

(1.0

)

(1.6

)

—

(2.6

)

Depreciation and amortization

(19.3

)

(38.3

)

(61.8

)

(3.1

)

—

(122.5

)

Provisions on assets (note 9)

(151.5

)

(352.2

)

(193.7

)

—

(697.4

)

Income from equity investments

10.2

1.8

0.6

—

12.6

Other income (loss)

10.3

0.9

(9.6

)

10.2

(0.1

)

11.7

Foreign exchange gains

(0.1

)

—

3.1

—

3.0

Interest expense

(1.2

)

(4.0

)

(70.3

)

(36.6

)

—

(112.1

)

Loss before income taxes

(94.0

)

(289.3

)

(498.1

)

(51.5

)

—

(932.9

)

Net additions (reductions) to:

Property, plant and equipment(b)

60.5

46.6

258.7

1.0

—

366.8

Intangible assets

1.4

11.4

2.4

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 Statement of Cash flow due to classification of business acquisition and foreign exchange changes on U.S. assets.

Nine months ended September 30, 2018

Gas

Power

Utilities

Corporate

Intersegment
Elimination(a)

Total

Segment revenue

945.8

758.5

947.6

(29.5

)

(92.8

)

2,529.6

Cost of sales

(634.4

)

(436.5

)

(448.9

)

—

86.1

(1,433.7

)

Operating and administrative

(144.4

)

(105.2

)

(503.7

)

(36.8

)

7.1

(783.0

)

Accretion expenses

(3.1

)

(4.9

)

(0.1

)

—

(8.1

)

Depreciation and amortization

(57.2

)

(97.4

)

(103.0

)

(10.4

)

—

(268.0

)

Provisions on assets (note 9)

(151.5

)

(352.2

)

(193.7

)

—

(697.4

)

Income from equity investments

19.8

4.3

1.3

—

25.4

Other income (loss)

0.3

0.9

(5.7

)

10.1

(0.4

)

5.2

Foreign exchange gains

(0.1

)

—

3.7

—

3.6

Interest expense

(1.2

)

(4.0

)

(70.3

)

(122.8

)

—

(198.3

)

Loss before income taxes

(26.0

)

(236.5

)

(376.5

)

(185.7

)

—

(824.7

)

Net additions (reductions) to:

Property, plant and equipment(b)

166.9

57.2

329.8

2.3

—

556.2

Intangible assets

3.8

12.1

3.8

2.9

—

22.6

(a) Intersegment transactions are recorded at market value.

	Three months ended September 30, 2017
	Gas			Power			Utilities			Corporate			Intersegment Elimination(a)			Total
Segment revenue	$	205.4		$	184.2		$	152.0		$	(24.5	)	$	(15.6	)	$	501.5
Cost of sales	(121.1		)	(60.1		)	(62.4		)	—			13.6			(230.0		)
Operating and administrative	(38.6		)	(20.5		)	(53.1		)	(15.1		)	2.1			(125.2		)
Accretion expenses	(1.0		)	(1.7		)	—			—			—			(2.7		)
Depreciation and amortization	(17.1		)	(28.9		)	(20.1		)	(2.9		)	—			(69.0		)
Income from equity investments	4.4			2.2			0.7			—			—			7.3
Other income (loss)	5.2			—			0.4			0.8			(0.1		)	6.3
Foreign exchange gains	0.2			—			—			0.2			—			0.4
Interest expense	—			—			—			(39.5		)	—			(39.5		)
Income (loss) before income taxes	$	37.4		$	75.2		$	17.5		$	(81.0	)	$	—		$	49.1
Net additions (reductions) to:
Property, plant and equipment(b)	$	113.2		1.2			31.9			0.4			—			$	146.7
Intangible assets	$	0.2		11.1			0.2			—			—			$	11.5

(a) Intersegment transactions are recorded at market value.

	Nine months ended September 30, 2017
	Gas			Power			Utilities			Corporate			Intersegment Elimination(a)			Total
Segment revenue	$	741.4		$	467.7		$	772.6		$	(43.5	)	$	(126.8	)	$	1,811.4
Cost of sales	(476.2		)	(173.9		)	(405.9		)	—			120.5			(935.5		)
Operating and administrative	(125.2		)	(67.4		)	(165.3		)	(69.7		)	6.7			(420.9		)
Accretion expenses	(3.0		)	(5.2		)	—			—			—			(8.2		)
Depreciation and amortization	(50.3		)	(90.5		)	(61.8		)	(8.5		)	—			(211.1		)
Provision on assets	—			(1.3		)	—			—			—			(1.3		)
Income from equity investments	17.1			5.4			1.9			—			—			24.4
Other income (loss)	(5.7		)	0.8			3.6			2.8			(0.4		)	1.1
Foreign exchange gains	0.2			—			—			1.6			—			1.8
Interest expense	—			—			—			(126.5		)	—			(126.5		)
Income (loss) before income taxes	$	98.3		$	135.6		$	145.1		$	(243.8	)	$	—		$	135.2
Net additions (reductions) to:
Property, plant and equipment(b)	$	180.1		$	13.7		$	78.8		$	1.1		$	—		$	273.7
Intangible assets	$	1.2		$	12.7		$	1.3		$	1.6		$	—		$	16.8

(a) Intersegment transactions are recorded at market value.

The following table shows goodwill and total assets by segment:

	Gas		Power		Utilities		Corporate		Total
As at September 30, 2018
Goodwill	$	418.9	$	199.2	$	3,285.2	$	—	$	3,903.3
Segmented assets	$	5,559.7	$	4,360.0	$	12,815.8	$	222.3	$	22,957.8
As at December 31, 2017
Goodwill	$	152.6	$	—	$	664.7	$	—	$	817.3
Segmented assets	$	3,096.8	$	3,192.5	$	3,460.2	$	282.7	$	10,032.2

24. SUBSEQUENT EVENTS

On October 18, 2018, the final prospectus for the ACI IPO was filed reflecting a final price of $14.50 per common share of ACI. On October 25, 2018, the ACI IPO was successfully completed. Upon close, AltaGas holds approximately 45 percent of ACI common shares, which could be reduced to approximately 37 percent if the over-allotment option is exercised in full. Total expected proceeds to AltaGas (including $239 million from the sale of common shares and $635 million of debt) are approximately $874 million (before the deduction of underwriting fees and expenses) which could increase to approximately $910 million (before the deduction of underwriting fees and expenses) if the over-allotment option is exercised in full. Upon close of the ACI IPO, the assets associated with the IPO which were classified as held for sale at September 30, 2018 were deconsolidated from AltaGas and an equity investment for AltaGas’ interest in ACI was recorded.

Subsequent events have been reviewed through October 29, 2018, the date on which these unaudited condensed interim Consolidated Financial Statements were issued.

Supplementary Quarterly Operating Information

(unaudited)

	Q3-18		Q2-18		Q1-18		Q4-17		Q3-17
OPERATING HIGHLIGHTS
GAS
Total inlet gas processed (Mmcf/d)(1)	1,333		1,227		1,553		1,424		1,322
Extraction volumes (Bbls/d)(1)(2)	60,945		49,728		74,786		68,306		64,026
Frac spread - realized ($/Bbl)(1)(3)	15.60		14.98		19.01		18.02		14.96
Frac spread - average spot price ($/Bbl)(1)(4)	25.87		22.19		22.25		30.66		21.28
Natural gas optimization inventory (Bcf)	36.7		1.3		—		2.5		2.6
WGL retail energy marketing - gas sales volumes (Mmcf)	8,155		n/a		n/a		n/a		n/a
POWER
Renewable power sold (GWh)	690		504		126		301		681
Conventional power sold (GWh)	1,255		642		842		1,059		992
Renewable capacity factor (%)	44.6		51.7		8.1		27.5		70.3
Contracted conventional availability factor (%)(5)	98.5		97.7		94.5		96.3		99.6
WGL retail energy marketing - electricity sales volumes (GWh)	3,000		n/a		n/a		n/a		n/a
UTILITIES
Canadian utilities
Natural gas deliveries - end-use (PJ)(6)	3.5		5.6		14.1		11.2		3.7
Natural gas deliveries - transportation (PJ)(6)	1.1		1.4		1.8		1.6		1.3
U.S. utilities
Natural gas deliveries end use (Bcf) (6)	10.9		12.0		31.0		24.3		5.9
Natural gas deliveries transportation (Bcf)(6)	25.7		10.9		13.4		14.2		10.9
Service sites(7)	1,759,154		580,526		582,871		581,518		575,602
Degree day variance from normal - AUI (%)(8)	80.0		3.9		10.2		4.0		(16.9	)
Degree day variance from normal - Heritage Gas (%)(8)	(16.5	)	6.7		(8.1	)	(4.6	)	(20.4	)
Degree day variance from normal - SEMCO Gas (%)(9)	(17.8	)	14.8		3.0		4.8		5.7
Degree day variance from normal - ENSTAR (%)(9)	(31.2	)	(6.1	)	(1.7	)	(8.3	)	(16.6	)
Degree day variance from normal - Washington Gas (%)(9)(10)	(4.1	)	n/a		n/a		n/a		n/a

(1) Average for the period.

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

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

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

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

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

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

(8) A degree day for AUI and Heritage Gas is the cumulative extent to which the daily mean temperature falls below 15 degrees Celsius at AUI and 18 degrees Celsius at Heritage Gas. Normal degree days are based on a 20-year rolling average. Positive variances from normal lead to increased delivery volumes from normal expectations. Degree day variances do not materially affect the results of PNG as the British Columbia Utilities Commission (BCUC) has approved a rate stabilization mechanism for its residential and small commercial customers.

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

(10) 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 it hedge to offset the effects of weather. As a result, colder or warmer weather will result in variances to financial results.

Other Information

DEFINITIONS

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

ABOUT ALTAGAS

AltaGas is an energy infrastructure company with a focus on natural gas, power and regulated utilities. The Corporation creates value by acquiring, growing and optimizing its energy infrastructure, including a focus on clean energy sources. For more information visit: www.altagas.ca.

For further information contact:

Investment Community

1-877-691-7199

investor.relations@altagas.ca

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