AltaGas (ATGFF) F-10 Registration of securities (Canada)

Exhibit 4.4

Consolidated Balance Sheets

(condensed and unaudited)

As at ($ millions)	March 31, 2018		December 31, 2017
ASSETS
Current assets
Cash and cash equivalents (note 17)	$	100.1	$	27.3
Accounts receivable, net of allowances	354.7		382.9
Inventory (note 5)	138.7		201.1
Restricted cash holdings from customers (note 17)	5.2		8.9
Regulatory assets	1.7		1.1
Risk management assets (note 11)	27.7		38.6
Prepaid expenses and other current assets	37.1		36.0
Assets held for sale (note 4)	—		6.0
	665.2		701.9
Property, plant and equipment	6,767.4		6,689.8
Intangible assets	587.3		588.8
Goodwill (note 6)	832.5		817.3
Regulatory assets	326.5		328.6
Risk management assets (note 11)	15.3		15.9
Deferred income taxes	2.8		2.8
Restricted cash holdings from customers (note 17)	5.8		7.5
Long-term investments and other assets (note 7)	310.4		312.6
Investments accounted for by the equity method	593.1		567.0
	$	10,106.3	$	10,032.2
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable and accrued liabilities	$	377.1	$	415.3
Dividends payable	32.5		32.0
Short-term debt	4.9		46.8
Current portion of long-term debt (notes 8 and 11)	213.9		188.9
Customer deposits	20.7		30.8
Regulatory liabilities	8.3		10.9
Risk management liabilities (note 11)	48.7		57.6
Other current liabilities	21.6		32.6
Liabilities associated with assets held for sale (note 4)	—		0.3
	727.7		815.2
Long-term debt (notes 8 and 11)	3,468.6		3,436.5
Asset retirement obligations	89.0		88.3
Deferred income taxes	448.2		444.2
Regulatory liabilities	278.5		268.6
Risk management liabilities (note 11)	13.6		13.8
Other long-term liabilities	206.4		201.9
Future employee obligations	126.4		124.5
	$	5,358.4	$	5,393.0

AltaGas Ltd. – Q1 2018

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As at ($ millions)	March 31, 2018			December 31, 2017
Shareholders’ equity
Common shares, no par values, unlimited shares authorized; 2018 - 177.9 million and 2017 - 175.3 million issued and outstanding (note 12)	$	4,074.4		$	4,007.9
Preferred shares (note 12)	1,277.7			1,277.7
Contributed surplus	22.5			22.3
Accumulated deficit	(988.7		)	(933.6		)
Accumulated other comprehensive income (AOCI) (note 9)	280.9			199.1
Total shareholders’ equity	4,666.8			4,573.4
Non-controlling interests	81.1			65.8
Total equity	4,747.9			4,639.2
	$	10,106.3		$	10,032.2

Commitments, contingencies and guarantees (note 14).

Subsequent events (note 20).

See accompanying notes to the Consolidated Financial Statements.

2

Consolidated Statements of Income

(condensed and unaudited)

Three months ended March 31 ($ millions except per share amounts)	2018			2017
REVENUE (note 10)	$	878.4		$	771.2
EXPENSES
Cost of sales, exclusive of items shown separately	538.0			434.1
Operating and administrative	140.8			159.7
Accretion expenses	2.7			2.8
Depreciation and amortization	72.6			71.5
	754.1			668.1
Income from equity investments	10.1			14.1
Other loss	(5.3		)	(2.5		)
Foreign exchange gains	—			0.3
Interest expense
Short-term debt	(0.8		)	(0.8		)
Long-term debt	(42.3		)	(45.2		)
Income before income taxes	86.0			69.0
Income tax expense (note 16)
Current	12.8			11.4
Deferred	5.7			9.9
Net income after taxes	67.5			47.7
Net income applicable to non-controlling interests	2.3			2.3
Net income applicable to controlling interests	65.2			45.4
Preferred share dividends	(16.4		)	(13.6		)
Net income applicable to common shares	$	48.8		$	31.8
Net income per common share (note 13)
Basic	$	0.28		$	0.19
Diluted	$	0.28		$	0.19
Weighted average number of common shares outstanding (millions) (note 13)
Basic	176.5			167.9
Diluted	176.6			168.3

See accompanying notes to the Consolidated Financial Statements.

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Consolidated Statements of Comprehensive Income (Loss)

(condensed and unaudited)

Three months ended March 31 ($ millions)	2018		2017
Net income after taxes	$	67.5	$	47.7
Other comprehensive income (loss), net of taxes
Gain (loss) on foreign currency translation	73.2		(24.2		)
Unrealized gain on net investment hedge (note 11)	—		1.4
Reclassification of actuarial gains and prior service costs on defined benefit and post-retirement benefit plans (PRB) to net income (note 15)	0.2		0.1
Unrealized loss on available-for-sale assets	—		(17.4		)
Adoption of ASU 2016-01 (note 2)	7.1		—
Other comprehensive income (loss) from equity investees	1.3		(1.2		)
Total other comprehensive income (loss) (OCI), net of taxes (note 9)	81.8		(41.3		)
Comprehensive income attributable to controlling interests and non-controlling interests, net of taxes	$	149.3	$	6.4
Comprehensive income attributable to:
Non-controlling interests	$	2.3	$	2.3
Controlling interests	147.0		4.1
	$	149.3	$	6.4

See accompanying notes to the Consolidated Financial Statements.

4

Consolidated Statements of Equity

(condensed and unaudited)

Three months ended March 31 ($ millions)	2018			2017
Balance, beginning of period	$	4,007.9		$	3,773.4
Shares issued for cash on exercise of options	0.6			3.6
Shares issued under DRIP (1)	65.9			58.3
Balance, end of period	$	4,074.4		$	3,835.3
Preferred shares (note 12)
Balance, beginning of period	$	1,277.7		$	985.1
Series K Issued	—			293.6
Deferred taxes on share issuance costs	—			1.8
Balance, end of period	$	1,277.7		$	1,280.5
Contributed surplus
Balance, beginning of period	$	22.3		$	17.4
Share options expense	0.2			0.3
Exercise of share options	—			(0.3		)
Adoption of ASU No. 2016-09	—			1.1
Balance, end of period	$	22.5		$	18.5
Accumulated deficit
Balance, beginning of period	$	(933.6	)	$	(600.4	)
Net income applicable to controlling interests	65.2			45.4
Common share dividends	(96.8		)	(88.3		)
Preferred share dividends	(16.4		)	(13.6		)
Adoption of ASU No. 2016-09	—			(1.1		)
Adoption of ASU No. 2016-01 (note 2)	(7.1		)	—
Balance, end of period	$	(988.7	)	$	(658.0	)
AOCI (note 9)
Balance, beginning of period	$	199.1		$	405.1
Other comprehensive income (loss)	81.8			(41.3		)
Balance, end of period	$	280.9		$	363.8
Total shareholders’ equity	$	4,666.8		$	4,840.1
Non-controlling interests
Balance, beginning of period	$	65.8		$	34.8
Net income applicable to non-controlling interests	2.3			2.3
Contributions from non-controlling interests to subsidiaries	13.0			—
Distributions by subsidiaries to non-controlling interests	—			(1.4		)
Balance, end of period	81.1			35.7
Total equity	$	4,747.9		$	4,875.8

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

See accompanying notes to the Consolidated Financial Statements.

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Consolidated Statements of Cash Flows

(condensed and unaudited)

Three months ended March 31 ($ millions)	2018			2017
Cash from operations
Net income after taxes	$	67.5		$	47.7
Items not involving cash:
Depreciation and amortization	72.6			71.5
Accretion expenses	2.7			2.8
Share-based compensation	0.2			0.3
Deferred income tax expense (note 16)	5.7			9.9
Losses (gains) on sale of assets (note 4)	(1.3		)	3.4
Income from equity investments	(10.1		)	(14.1		)
Unrealized gains on risk management contracts (note 11)	(0.6		)	(0.9		)
Losses on investments	9.5			0.4
Amortization of deferred financing costs	3.1			6.8
Other	0.3			0.7
Asset retirement obligations settled	(0.7		)	(1.2		)
Distributions from equity investments	6.3			6.6
Changes in operating assets and liabilities (note 17)	33.8			66.4
	$	189.0		$	200.3
Investing activities
Acquisition of property, plant and equipment	(82.3		)	(86.3		)
Acquisition of intangible assets	(1.7		)	(2.2		)
Contributions to equity investments	(19.0		)	(14.3		)
Loan to affiliate, net of repayment	—			7.5
Proceeds from disposition of investment	5.2			—
Payment for derivative contracts	—			(21.0		)
Proceeds from disposition of assets, net of transaction costs (note 4)	9.1			69.0
	$	(88.7	)	$	(47.3	)
Financing activities
Net repayment of short-term debt	(42.9		)	(122.6		)
Issuance of long-term debt, net of debt issuance costs	247.8			13.5
Repayment of long-term debt	(205.1		)	(287.1		)
Dividends - common shares	(96.3		)	(88.0		)
Dividends - preferred shares	(16.4		)	(12.1		)
Distributions to non-controlling interest	—			(1.4		)
Contributions from non-controlling interests	13.0			—
Net proceeds from shares issued on exercise of options	0.6			3.3
Net proceeds from issuance of common shares	65.9			58.3
Net proceeds from issuance of preferred shares	—			293.6
Other	(0.2		)	(0.4		)
	$	(33.6	)	$	(142.9	)
Change in cash, cash equivalents and restricted cash	66.7			10.1
Effect of exchange rate changes on cash, cash equivalents and restricted cash	0.7			0.2
Cash, cash equivalents, and restricted cash beginning of period	43.7			34.1
Cash, cash equivalents, and restricted cash end of period (note 17)	$	111.1		$	44.4

See accompanying notes to the Consolidated Financial Statements.

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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.; in regards to the gas business, AltaGas Extraction and Transmission Limited Partnership, AltaGas Pipeline Partnership, AltaGas Processing Partnership, AltaGas Northwest Processing Limited Partnership and Harmattan Gas Processing Limited Partnership; in regards to the power business, Coast Mountain Hydro Limited Partnership, Blythe Energy Inc. (Blythe), and AltaGas San Joaquin Energy Inc.; and, in regards to the utility business, AltaGas Utilities Inc. (AUI), Heritage Gas Limited (Heritage Gas), Pacific Northern Gas Ltd. (PNG), and SEMCO Energy, Inc. (SEMCO). SEMCO conducts its Michigan natural gas distribution business under the name SEMCO Energy Gas Company (SEMCO Gas) and its Alaska natural gas distribution business under the name ENSTAR Natural Gas Company (ENSTAR).

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

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

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

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

2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

BASIS OF PRESENTATION

These 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), U.S. GAAP reporting is generally permitted by Canadian securities laws for companies subject to reporting obligations under U.S. securities laws. However, given that AltaGas is not subject to such reporting obligations and could not therefore rely on the provisions of NI 52-107 to that effect, AltaGas sought and obtained exemptive relief by the securities regulators in Alberta and Ontario to permit it to prepare its financial statements in accordance with U.S. GAAP. The Alberta Securities Commission exemption will terminate on or after the earlier of January 1, 2024, the date to which AltaGas ceases to have activities subject to rate regulation, or the

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effective date prescribed by the International Accounting Standards Board for the mandatory application of a standard within the International Financial Reporting Standard for entities with activities subject to rate-regulated accounting.

PRINCIPLES OF CONSOLIDATION

These 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.

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, 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 10 for further details. AltaGas does not expect the application of ASC 606 to have a material impact on its consolidated financial statements in 2018;

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·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 of net benefit cost associated with other components was reclassified from the line item “Operating and administrative” to “Other loss” on the Consolidated Statement of Income for the three months ended March 31, 2017. AltaGas applied the change related to the capitalization of the service cost prospectively. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements;

·ASU No. 2017-09 “Compensation — Stock Compensation: Scope of Modifications Accounting”. The amendments in this ASU provided guidance on the types of changes to the terms or conditions of share-based payment arrangements to

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which an entity would be required to apply modification accounting. The guidance was applied prospectively and did not have a material impact on AltaGas’ consolidated financial statements;

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

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

FUTURE CHANGES IN ACCOUNTING PRINCIPLES

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

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

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

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3.   DEVELOPMENTS RELATING TO THE PENDING WGL ACQUISITION

Pending Acquisition of WGL Holdings, Inc. (WGL)

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

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

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

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

Closing of the WGL Acquisition continues to be on track for mid-2018. AltaGas plans to fund the WGL Acquisition with the proceeds from its aggregate $2.6 billion bought deal and private placement of subscription receipts, which closed in the first quarter of 2017 (see Subscription Receipts section below). In addition, AltaGas has US$3 billion available under its fully committed bridge facility, which can be drawn at the time of closing and could remain in place for up to 12 to 18 months thereafter. With all financing in place to close the WGL Acquisition, AltaGas continues to evaluate and advance an asset monetization strategy in a prudent and timely fashion in step with the regulatory process and consistent with AltaGas’ long term strategic vision. Management expects the repayment of the bridge facility to result from the monetization of over $2 billion from its asset sales process, including the potential sale of appropriate minority interest(s) in the Northwest B.C. Hydro Facilities, and from offerings of senior debt and hybrid securities, subject to prevailing market conditions.

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Subscription Receipts

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

The net proceeds from the sale of the subscription receipts are held by an escrow agent pending, among other things, receipt of all regulatory and government approvals required to finalize the WGL Acquisition and confirmation that the parties to the Merger Agreement are able to complete the WGL Acquisition in all material respects in accordance with the terms of the Merger Agreement, but for the payment of the purchase price, and AltaGas has available to it all other funds required to complete the WGL Acquisition. If the escrow release notice and direction is not delivered on or prior to 5:00 pm (Calgary time) on September 4, 2018, the Corporation will be required to make a termination payment equal to the aggregate issue price of such holder’s subscription receipts plus any unpaid Dividend Equivalent Payments owing to such holders of subscription receipts.

4.   ASSETS HELD FOR SALE

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 Statement of Income under the line item “Other loss” for the three months ended March 31, 2018.

5.   INVENTORY

	March 31,		December 31,
As at	2018		2017
Natural gas held in storage	$	68.8	$	133.9
Other inventory	69.9		67.2
	$	138.7	$	201.1

6.   GOODWILL

	March 31,		December 31,
As at	2018		2017
Balance, beginning of period	$	817.3	$	856.0
Foreign exchange translation	15.2		(38.4		)
Reclassified to assets held for sale (note 4)	—		(0.3		)
Balance, end of period	$	832.5	$	817.3

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7.   LONG-TERM INVESTMENTS AND OTHER ASSETS

As at	March 31, 2018		December 31, 2017
Investments in publicly-traded entities	$	72.8	$	95.0
Loan to affiliate	75.0		75.0
Deferred lease receivable	46.6		29.0
Debt issuance costs associated with credit facilities	17.8		20.3
Refundable deposits	15.3		14.9
Prepayment on long-term service agreements	71.5		68.1
Subscription receipts issuance costs	1.8		1.7
Other	9.6		8.6
	$	310.4	$	312.6

8.   LONG-TERM DEBT

		March 31,			December 31,
As at	Maturity date	2018			2017
Credit facilities
$1,400 million unsecured extendible revolving(a)	15-Dec-2020	$	441.4		$	219.1
US$300 million unsecured extendible revolving(b)	8-Dec-2019	—			—
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
SEMCO long-term debt
US$300 million SEMCO Senior secured - 5.15 percent(c)	21-Apr-2020	386.8			376.4
US$82 million CINGSA Senior secured - 4.48 percent(d)	2-Mar-2032	84.6			85.2
Debenture notes
PNG 2018 Series Debenture - 8.75 percent(e)	15-Nov-2018	7.0			7.0
PNG 2025 Series Debenture - 9.30 percent(e)	18-Jul-2025	13.0			13.0
PNG 2027 Series Debenture - 6.90 percent(e)	2-Dec-2027	14.0			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
		$	3,696.9		$	3,639.8
Less debt issuance costs		(14.4		)	(14.4		)
		3,682.5			3,625.4
Less current portion		(213.9		)	(188.9		)
		$	3,468.6		$	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 US$ MTNs is certain SEMCO assets.

(d)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.

(e)Collateral for the Secured Debentures 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.

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9.   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	—			—			—			73.2			1.3			74.5
Amounts reclassified from OCI	—			0.3			—			—			—			0.3
Adoption of ASU No. 2016-01 (note 2)	7.1			—			—			—			—			7.1
Current period OCI (pre-tax)	7.1			0.3			—			73.2			1.3			81.9
Income tax on amounts reclassified to earnings	—			(0.1		)	—			—			—			(0.1		)
Net current period OCI	7.1			0.2			—			73.2			1.3			81.8
Ending balance, March 31, 2018	$	—		$	(11.2	)	$	(129.0	)	$	416.1		$	5.0		$	280.9
Opening balance, January 1, 2017	$	19.8		$	(11.3	)	$	(135.6	)	$	526.3		$	5.9		$	405.1
OCI before reclassification	(17.4		)	—			3.0			(24.2		)	(1.2		)	(39.8		)
Amounts reclassified from OCI	—			0.2			—			—			—			0.2
Current period OCI (pre-tax)	(17.4		)	0.2			3.0			(24.2		)	(1.2		)	(39.6		)
Income tax on amounts retained in AOCI	—			—			(1.6		)	—			—			(1.6		)
Income tax on amounts reclassified to earnings	—			(0.1		)	—			—			—			(0.1		)
Net current period OCI	(17.4		)	0.1			1.4			(24.2		)	(1.2		)	(41.3		)
Ending balance, March 31, 2017	$	2.4		$	(11.2	)	$	(134.2	)	$	502.1		$	4.7		$	363.8

Reclassification From Accumulated Other Comprehensive Income

		Three months ended March 31
AOCI components reclassified	Income statement line item	2018			2017
Defined benefit pension and PRB plans	Operating and administrative expense	$	0.3		$	0.2
Deferred income taxes	Income tax expenses — deferred	(0.1		)	(0.1		)
		$	0.2		$	0.1

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10.   REVENUE

The following table disaggregates revenue by major sources for the period ended March 31, 2018:

	Three months ended March 31, 2018
	Gas			Power		Utilities			Corporate			Total
Revenue from contracts with customers
Commodity sales contracts	$	107.3		$	—	$	—		$	—		$	107.3
Midstream service contracts	49.5			—		—			—			49.5
Gas sales and transportation services	—			—		410.3			—			410.3
Storage services	—			—		9.1			—			9.1
Other	0.6			—		2.9			—			3.5
Total revenue from contracts with customers	$	157.4		$	—	$	422.3		$	—		$	579.7
Other sources of revenue
Revenue from alternative revenue programs (a)	$	—		$	—	$	(5.1	)	$	—		$	(5.1	)
Leasing revenue (b)	24.0			67.2		—			—			91.2
Risk management contracts gains (losses)	130.5			75.8		1.2			(0.6		)	206.9
Other	(0.1		)	2.8		3.0			—			5.7
Total revenue from other sources	$	154.4		$	145.8	$	(0.9	)	$	(0.6	)	$	298.7
Total revenue	$	311.8		$	145.8	$	421.4		$	(0.6	)	$	878.4

(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 are accounted for as operating leases. For the Power segment, the majority of revenue earned is through power purchase agreements which are accounted for as operating leases.

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.

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

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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 become 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. As at March 31, 2018, AltaGas did not recognize any contract liabilities or assets related to its take-or-pay contracts.

Power segment

For the Power segment, the majority 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.

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 have a term of one-month, 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.

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 March 31, 2018:

	Remainder of 2018		2019		2020		2021		2022		> 2022		Total
Midstream service contracts	$	36.0	$	46.1	$	43.1	$	3.4	$	3.0	$	—	$	131.6
Gas sales and transportation services	14.5		18.9		17.1		16.2		15.7		29.8		112.2
Storage services	20.7		26.9		26.6		26.6		26.6		246.4		373.8
Other	0.8		1.1		1.1		1.1		1.1		3.0		8.2
	$	72.0	$	93.0	$	87.9	$	47.3	$	46.4	$	279.2	$	625.8

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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.

11.   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 uses over-the-counter derivative instruments 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 from 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.

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	March 31, 2018
	Carrying Amount		Level 1		Level 2		Level 3		Total Fair Value
Financial assets
Fair value through net income
Risk management assets - current	$	27.7	$	—	$	27.7	$	—	$	27.7
Risk management assets - non-current	15.3		—		15.3		—		15.3
Equity securities(a)	80.4		80.4		—		—		80.4
Amortized cost
Loans and receivables (a)	75.0		—		76.8		—		76.8
	$	198.4	$	80.4	$	119.8	$	—	$	200.2
Financial liabilities
Fair value through net income
Risk management liabilities - current	$	48.7	$	—	$	48.7	$	—	$	48.7
Risk management liabilities - non-current	13.6		—		13.6		—		13.6
Amortized cost
Current portion of long-term debt	213.9		—		217.8		—		217.8
Long-term debt	3,468.6		—		3,534.1		—		3,534.1
Other current liabilities (b)	13.8		—		14.0		—		14.0
Other long-term liabilities (b)	147.8		—		146.7		—		146.7
	$	3,906.4	$	—	$	3,974.9	$	—	$	3,974.9

(a)Included under the line items “Prepaid expenses and other current assets” and “Long-term investments and other assets” on the Consolidated Balance Sheet.

(b)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 Sheet.

(b)Excludes non-financial liabilities.

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

Three months ended March 31	2018			2017
Natural gas	$	(5.8	)	$	(1.8	)
Storage optimization	—			2.4
NGL frac spread	11.0			7.5
Power	(3.4		)	(0.4		)
Foreign exchange	(1.2		)	(6.8		)
	$	0.6		$	0.9

Offsetting of Derivative Assets and Derivative Liabilities

Certain AltaGas risk management contracts are subject to master netting arrangements that create a legally enforceable right to offset by counterparty. The following is a summary of AltaGas’ financial assets and financial liabilities that were subject to offsetting:

	March 31, 2018
Risk management assets (a)	Gross amounts of recognized assets/liabilities		Gross amounts offset in balance sheet			Net amounts presented in balance sheet
Natural gas	$	23.4	$	(2.1	)	$	21.3
NGL frac spread	2.9		(0.6		)	2.3
Power	19.3		(0.4		)	18.9
Foreign exchange	0.5		—			0.5
	$	46.1	$	(3.1	)	$	43.0
Risk management liabilities (b)
Natural gas	$	23.5	$	(2.2	)	$	21.3
NGL frac spread	15.9		(0.5		)	15.4
Power	26.0		(0.4		)	25.6
	$	65.4	$	(3.1	)	$	62.3

(a)Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $27.7 million and risk management assets (non-current) balance of $15.3 million.

(b)Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $48.7 million and risk management liabilities (non-current) balance of $13.6 million.

	December 31, 2017
Risk management assets (a)	Gross amounts of recognized assets/liabilities		Gross amounts offset in balance sheet			Net amounts presented in balance sheet
Natural gas	$	41.0	$	(6.2	)	$	34.8
NGL frac spread	1.3		(0.3		)	1.0
Power	17.7		(0.7		)	17.0
Foreign exchange	1.7		—			1.7
	$	61.7	$	(7.2	)	$	54.5
Risk management liabilities (b)
Natural gas	$	35.1	$	(6.2	)	$	28.9
NGL frac spread	25.3		(0.3		)	25.0
Power	18.2		(0.7		)	17.5
	$	78.6	$	(7.2	)	$	71.4

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

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

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Notional Summary

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

	March 31, 2018	December 31, 2017
Natural Gas
Sales	110,807,671 GJ	94,804,039 GJ
Purchases	44,077,028 GJ	61,980,315 GJ
Swaps	1,181,710 GJ	6,039,642 GJ
NGL Frac Spread
Propane swaps	1,748,430 Bbl	1,992,927 Bbl
Butane swaps	56,101 Bbl	130,088 Bbl
Crude oil swaps	390,775 Bbl	518,665 Bbl
Natural gas swaps	8,610,525 GJ	11,428,515 GJ
Power
Sales	2,193,944 MWh	2,169,321 MWh
Purchases	320,452 MWh	17,520 MWh
Swaps	1,334,221 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 March 31, 2018, AltaGas has not designated any outstanding debt as a net investment hedge. For the three months ended March 31, 2018, AltaGas incurred an after-tax unrealized gain of $nil arising from the translation of debt in OCI (2017 - after-tax unrealized gain of $1.4 million).

In addition, to mitigate the foreign exchange risks associated with the cash purchase price of WGL, AltaGas has entered into foreign currency option contracts with an aggregate notional value of US$1.2 billion. These foreign currency option contracts do not qualify for hedge accounting. Therefore, all changes in fair value are recognized in net income. For the three months ended March 31, 2018, an unrealized loss of $1.2 million was recognized in revenue in relation to these contracts (2017 — unrealized loss of $6.4 million).

12.   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).

TM Denotes trademark of Canaccord Genuity Corp.

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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.

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 for cash on exercise of options	24,875	0.6
Shares issued under DRIP	2,577,178	65.9
Issued and outstanding at March 31, 2018	177,881,269	$	4,074.4

Preferred Shares

As at	March 31, 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
Share issuance costs, net of taxes		(27.9		)		(27.9		)
	52,000,000	$	1,277.7		52,000,000	$	1,277.7

Share Option Plan

AltaGas has an employee share option plan under which employees and directors are eligible to receive grants. As at March 31, 2018, 13,285,741 shares were reserved for issuance under the plan. As at March 31, 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 March 31, 2018, unexpensed fair value of share option compensation cost associated with future periods was $1.0 million (December 31, 2017 - $1.3 million).

TM Denotes trademark of Canaccord Genuity Corp.

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

	March 31, 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	—		—		848,000		30.80
Exercised	(24,875	)	23.26		(240,125	)	24.63
Forfeited	(6,500	)	30.14		(193,500	)	36.36
Share options outstanding, end of period	4,502,386		$	32.40	4,533,761		$	32.35
Share options exercisable, end of period	3,509,947		$	32.05	3,326,197		$	31.93

(a)Weighted average.

As at March 31, 2018, the aggregate intrinsic value of the total share options exercisable was $2.7 million (December 31, 2017 - $6.0 million), the total intrinsic value of share options outstanding was $2.7 million (December 31, 2017 - $6.0 million) and the total intrinsic value of share options exercised was $0.1 million (December 31, 2017 - $1.4 million).

The following table summarizes the employee share option plan as at March 31, 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	157,750	$	15.22	1.05	157,750	$	15.22	1.05
$18.01 to $25.08	454,600	20.75		2.58	454,600	20.75		2.58
$25.09 to $50.89	3,890,036	34.46		3.79	2,897,597	34.74		3.58
	4,502,386	$	32.40	3.57	3,509,947	$	32.05	3.34

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	March 31, 2018		December 31, 2017
(number of units)
Balance, beginning of period	564,549		364,839
Granted	9,922		386,126
Additional units added by performance factor	—		24,301
Vested and paid out	(26,018	)	(221,775	)
Forfeited	(1,149	)	(27,279	)
Units in lieu of dividends	11,552		38,337
Outstanding, end of period	558,856		564,549

For the three months ended March 31, 2018, the compensation expense recorded for the MTIP and DSUP was $0.2 million (2017 — $1.4 million). As at March 31, 2018, the unrecognized compensation expense relating to the remaining vesting period for the MTIP was $7.7 million (December 31, 2017 - $8.4 million) and is expected to be recognized over the vesting period.

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13.   NET INCOME PER COMMON SHARE

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

Three months ended March 31	2018			2017
Numerator:
Net income applicable to controlling interests	$	65.2		$	45.4
Less: Preferred share dividends	(16.4		)	(13.6		)
Net income applicable to common shares	$	48.8		$	31.8
Denominator:
(millions)
Weighted average number of common shares outstanding	176.5			167.9
Dilutive equity instruments(a)	0.1			0.4
Weighted average number of common shares outstanding - diluted	176.6			168.3
Basic net income per common share	$	0.28		$	0.19
Diluted net income per common share	$	0.28		$	0.19

(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 months ended March 31, 2018, 1.3 million of share options (2017 — 2.1 million) were excluded from the diluted net income per share calculation as their effects were anti-dilutive.

14.   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.

AltaGas enters into contracts to purchase natural gas and natural gas transportation and storage services from various suppliers for its utilities. These contracts, which have expiration dates that range from 2018 to 2033, are used to ensure that there is an adequate supply of natural gas to meet the needs of customers and to minimize exposure to market price fluctuations.

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.

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 March 31, 2018, approximately $202.0 million is expected to be paid over the next 19 years, of which $56.7 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 $8.1 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

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pipelines and it will expire 15 years thereafter. AltaGas has two guarantees outstanding that total US$91.7 million to stand by all payment obligations under the transportation agreement.

Contingencies

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

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

	Three months ended March 31, 2018
	Canada						United States						Total
				Post-						Post-						Post-
	Defined			retirement			Defined			retirement			Defined			retirement
	Benefit			Benefits			Benefit			Benefits			Benefit			Benefits
Current service cost (a)	$	2.6		$	0.2		$	2.5		$	0.7		$	5.1		$	0.9
Interest cost (b)	1.4			0.1			3.5			1.0			4.9			1.1
Expected return on plan assets (b)	(1.7		)	(0.1		)	(5.9		)	(1.7		)	(7.6		)	(1.8		)
Amortization of net actuarial loss (b)	0.3			—			—			—			0.3			—
Amortization of regulatory asset (b)	0.4			—			1.8			—			2.2			—
Net benefit cost recognized	$	3.0		$	0.2		$	1.9		$	—		$	4.9		$	0.2

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

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

	Three months ended March 31, 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		$	1.8		$	0.4		$	3.8		$	0.6
Interest cost (b)	1.4			0.2			3.0			0.7			4.4			0.9
Expected return on plan assets (b)	(1.5		)	(0.1		)	(4.1		)	(1.2		)	(5.6		)	(1.3		)
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		$	2.3		$	(0.2	)	$	4.7		$	0.1

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

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

16.   INCOME TAXES

The effective income tax rate for the three months ended March 31, 2018 was approximately 21.5 percent (2017 — 30.9 percent). The decrease in the effective tax rate for the three months ended March 31, 2018 was primarily due to the decrease in the U.S. Federal tax rate from 35 percent to 21 percent. In addition, a lesser amount of the transaction costs incurred on the pending WGL Acquisition in the first quarter of 2018 were non-deductible than in the first quarter of 2017. This was partially offset by an increase to the uncertain tax provision in the first quarter of 2018.

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17.   SUPPLEMENTAL CASH FLOW INFORMATION

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

Three months ended March 31	2018			2017
Source (use) of cash:
Accounts receivable	$	34.1		$	17.1
Inventory	69.0			90.3
Other current assets	7.2			6.7
Regulatory assets (current)	(0.6		)	(1.0		)
Accounts payable and accrued liabilities	(43.7		)	(4.9		)
Customer deposits	(10.7		)	(12.8		)
Regulatory liabilities (current)	(2.8		)	(7.2		)
Other current liabilities	(7.8		)	(3.6		)
Other operating assets and liabilities	(10.9		)	(18.2		)
Changes in operating assets and liabilities	$	33.8		$	66.4

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

Three months ended March 31	2018		2017
Interest paid (net of capitalized interest)	$	40.7	$	52.4
Income taxes paid	$	11.7	$	11.3

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

As at March 31	2018		2017
Cash and cash equivalents	$	100.1	$	32.4
Restricted cash holdings from customers - current	5.2		4.0
Restricted cash holdings from customers - non-current	5.8		8.0
Cash, cash equivalents and restricted cash per consolidated statement of cash flow	$	111.1	$	44.4

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18.   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.

19.   SEGMENTED INFORMATION

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

Gas	·	NGL processing and extraction plants;
	·	transmission pipelines to transport natural gas and NGL;
	·	natural gas gathering lines and field processing facilities;
	·	purchase and sale of natural gas, including to commercial and industrial users;
	·	natural gas storage facilities;
	·	liquefied petroleum gas (LPG) terminal currently under construction;
	·	natural gas and NGL marketing; and
	·	equity investment in Petrogas, a North American entity engaged in the marketing, storage and distribution of NGL, drilling fluids, crude oil and condensate diluents.
Power	·	natural gas-fired, wind, biomass and hydro power generation assets, whereby outputs are generally sold under long-term power purchase agreements, both operational and under development;
	·	energy storage; and
	·	sale of power to commercial and industrial users in Alberta.
Utilities	·	rate-regulated natural gas distribution assets in Michigan, Alaska, Alberta, British Columbia and Nova Scotia; and
	·	rate-regulated natural gas storage in Michigan and Alaska.
Corporate	·	the cost of providing corporate services, financing and general corporate overhead, investments in certain public and private entities, corporate assets, financing other segments and the effects of changes in the fair value of risk management contracts.

The following table provides a reconciliation of segment revenue to the disaggregated revenue table as disclosed under Note 10 of these unaudited condensed interim Consolidated Financial Statements:

	Three months ended March 31, 2018
	Gas		Power		Utilities		Corporate			Total
External revenue (note 10)	$	311.8	$	145.8	$	421.4	$	(0.6	)	$	878.4
Intersegment revenue	59.3		1.9		0.9		0.1			62.2
Segment revenue	$	371.1	$	147.7	$	422.3	$	(0.5	)	$	940.6

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The following tables show the composition by segment:

	Three months ended March 31, 2018
	Gas			Power			Utilities			Corporate			Intersegment Elimination(a)			Total
Segment revenue	$	371.1		$	147.7		$	422.3		$	(0.5	)	$	(62.2	)	$	878.4
Cost of sales	(266.5		)	(78.5		)	(253.1		)	—			60.1			(538.0		)
Operating and administrative	(43.2		)	(29.4		)	(57.8		)	(12.6		)	2.2			(140.8		)
Accretion expenses	(1.0		)	(1.7		)	—			—			—			(2.7		)
Depreciation and amortization	(18.8		)	(29.6		)	(20.5		)	(3.7		)	—			(72.6		)
Income from equity investments	9.2			0.6			0.3			—			—			10.1
Other income (loss)	(4.0		)	—			1.4			(2.6		)	(0.1		)	(5.3		)
Foreign exchange gains (losses)	(0.1		)	—			—			0.1			—			—
Interest expense	—			—			—			(43.1		)	—			(43.1		)
Income (loss) before income taxes	$	46.7		$	9.1		$	92.6		$	(62.4	)	$	—		$	86.0
Net additions (reductions) to:
Property, plant and equipment(b)	$	46.6		$	1.7		$	17.4		$	0.4		$	—		$	66.1
Intangible assets	$	0.9		$	—		$	0.4		$	0.9		$	—		$	2.2

(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.

	Three months ended March 31, 2017
	Gas			Power			Utilities			Corporate			Intersegment Elimination(a)			Total
Segment revenue	$	301.5		$	132.2		$	414.5		$	2.1		$	(79.1	)	$	771.2
Cost of sales	(204.1		)	(61.8		)	(244.9		)	—			76.7			(434.1		)
Operating and administrative	(41.8		)	(23.2		)	(56.2		)	(41.0		)	2.5			(159.7		)
Accretion expenses	(1.0		)	(1.8		)	—			—			—			(2.8		)
Depreciation and amortization	(16.5		)	(30.8		)	(20.8		)	(3.4		)	—			(71.5		)
Income from equity investments	11.2			2.3			0.6			—			—			14.1
Other income (loss)	(3.4		)	—			0.6			0.4			(0.1		)	(2.5		)
Foreign exchange gains	—			—			—			0.3			—			0.3
Interest expense	—			—			—			(46.0		)	—			(46.0		)
Income (loss) before income taxes	$	45.9		$	16.9		$	93.8		$	(87.6	)	$	—		$	69.0
Net additions (reductions) to:
Property, plant and equipment(b)	$	(21.6	)	$	7.0		$	16.4		$	0.2		$	—		$	2.0
Intangible assets	$	0.5		$	0.2		$	0.4		$	0.9		$	—		$	2.0

(a)Intersegment transactions are recorded at market value.

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

The following table shows goodwill and total assets by segment:

	Gas		Power		Utilities		Corporate		Total
As at March 31, 2018
Goodwill	$	152.6	$	—	$	679.9	$	—	$	832.5
Segmented assets	$	3,127.4	$	3,211.7	$	3,438.6	$	328.6	$	10,106.3
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

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20.   SUBSEQUENT EVENTS

Subsequent events have been reviewed through April 25, 2018, the date on which these unaudited condensed interim Consolidated Financial Statements were issued.

Subsequent to quarter-end, AltaGas entered into a long-term natural gas processing arrangement (the Processing Arrangement) with Birchcliff Energy Ltd. (Birchcliff) at AltaGas’ deep-cut sour gas processing facility located in Gordondale, Alberta (the Gordondale Facility). Under the Processing Arrangement, Birchcliff is provided with up to 120 MMcf/d of natural gas processing on a firm-service basis, and Birchcliff’s take-or-pay obligation is 100 MMcf/d. The new Processing Arrangement is effective as of January 1, 2018 and replaces the parties’ existing Gordondale processing arrangement.

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Supplementary Quarterly Operating Information

(unaudited)

	Q1-18		Q4-17		Q3-17		Q2-17		Q1-17
OPERATING HIGHLIGHTS
GAS
Total inlet gas processed (Mmcf/d)(1)	1,553		1,424		1,322		1,300		1,404
Extraction volumes (Bbls/d)(1)(2)	74,786		68,306		64,026		58,885		71,958
Frac spread - realized ($/Bbl)(1)(3)	19.01		18.02		14.96		9.06		10.56
Frac spread - average spot price ($/Bbl)(1)(4)	22.25		30.66		21.28		10.98		17.26
POWER
Renewable power sold (GWh)	126		301		681		499		148
Conventional power sold (GWh)	842		1,059		992		409		385
Renewable capacity factor (%)	8.1		27.5		70.3		50.7		9.5
Contracted conventional availability factor (%)(5)	94.5		96.3		99.6		99.9		96.0
UTILITIES
Canadian utilities
Natural gas deliveries - end-use (PJ)(6)	14.1		11.2		3.7		4.8		13.5
Natural gas deliveries - transportation (PJ)(6)	1.8		1.6		1.3		1.5		1.9
U.S. utilities
Natural gas deliveries end use (Bcf) (6)	31.0		24.3		5.9		10.3		30.2
Natural gas deliveries transportation (Bcf)(6)	13.4		14.2		10.9		11.5		15.4
Service sites(7)	582,871		581,518		575,602		575,084		576,829
Degree day variance from normal - AUI (%)(8)	10.2		4.0		(16.9	)	(7.4	)	(2.2	)
Degree day variance from normal - Heritage Gas (%)(8)	(8.1	)	(4.6	)	(20.4	)	(4.3	)	(1.9	)
Degree day variance from normal - SEMCO Gas (%)(9)	3.0		4.8		5.7		(8.4	)	(11.8	)
Degree day variance from normal - ENSTAR (%)(9)	(1.7	)	(8.3	)	(16.6	)	(5.4	)	9.6

(1)Average for the period.

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

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

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

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

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

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

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

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

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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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