Consolidated Financial Statements of

Algonquin Power & Utilities Corp.

For the years ended December 31, 2019 and 2018

MANAGEMENT’S REPORT

Financial Reporting

The preparation and presentation of the accompanying consolidated financial statements, MD&A and all financial information in the consolidated financial statements are the responsibility of management and have been approved by the Board of Directors. The consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles. Financial statements by nature include amounts based upon estimates and judgments. When alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances. Management has prepared the financial information presented elsewhere in this document and has ensured that it is consistent with that in the consolidated financial statements.

The Board of Directors and its committees are responsible for all aspects related to governance of the Company. The Audit Committee of the Board of Directors, composed of directors who are unrelated and independent, has a specific responsibility to oversee management’s efforts to fulfill its responsibilities for financial reporting and internal controls related thereto. The Committee meets with management and independent auditors to review the consolidated financial statements and the internal controls as they relate to financial reporting. The Audit Committee reports its findings to the Board of Directors for its consideration in approving the consolidated financial statements for issuance to the shareholders.

Internal Control over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles.

During the year ended December 31, 2019, the Company acquired Enbridge Gas New Brunswick Limited Partnership ("New Brunswick Gas") and St. Lawrence Gas Company, Inc. ("St. Lawrence Gas"). Management is in the process of evaluating the existing controls and procedures of New Brunswick Gas and St. Lawrence Gas and integrating financial reporting and controls for New Brunswick Gas and St. Lawrence gas into the Company's internal control over financial reporting. The financial information for these acquisitions is included in this MD&A and in note 3 to the consolidated financial statements. As permitted by National Instrument 52-109 and the U.S. Securities and Exchange Commission, due to the complexity associated with assessing internal controls during integration efforts, the Company excluded these acquisitions from its evaluation of the effectiveness of the Company's internal controls over financial reporting as of December 31, 2019 (representing approximately 4% of its total assets as of December 31, 2019 and approximately 2% of its revenues for the year ended December 31, 2019).

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2019, based on the framework established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2019.

February 27, 2020

/s/ Ian Robertson	/s/ David Bronicheski
Chief Executive Officer	Chief Financial Officer

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Directors of Algonquin Power & Utilities Corp.

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Algonquin Power & Utilities Corp. (the “Company”), as of December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive income, equity and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

Report on Internal Control over Financial Reporting

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2019, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 27, 2020 expressed an unqualified opinion thereon.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the US federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

	Accounting for Long-term Investments and Related Financing Arrangements
Description of the Matter	As more fully described in Notes 8 and 17 to the consolidated financial statements, the Company has various long-term investments and related financing arrangements with Atlantica Yield PLC, Abengoa-Algonquin Global Energy Solutions B.V. and other entities. In the current year, the Company also entered into various new long-term investments including Atlantica Yield Energy Solutions Canada Inc., a subsidiary of Atlantica Yield PLC, and AAGES Sugar Creek, amongst others. The accounting for these investments involves the application of the variable interest model, which includes evaluating whether various entities within these investment structures are variable interest entities (“VIE”) and whether the Company is the primary beneficiary of the VIE. If the Company is the primary beneficiary of the VIE, then the VIE is consolidated. These assessments are complex and required significant judgment. Such judgments include a consideration of the adequacy of equity at risk within the entities, consideration of whether other parties to the arrangements are agents or defacto agents and determining the party that has the power to direct the activities of the entities that most significantly affect their economic performance and evaluating the debt and equity characteristics of certain financing instruments. In addition, certain financing arrangements entered into as part of the funding of these investment structures required consideration of whether the financing arrangements are debt or non-controlling interests. The Company also monitors for reconsideration events relating to these investment structures, which necessitates on-going critical judgments over whether any such events have arisen that require a re-evaluation of prior accounting judgments.
How We Addressed the Matter in Our Audit	We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s application of the variable interest model, including the process of evaluating whether an entity is a VIE, whether the Company is the primary beneficiary of the VIE, the classification of related financing instruments and the assessment of reconsideration events. To evaluate the Company’s conclusions about the determination of variable interest entities and consolidation, our audit procedures included, amongst others, obtaining and reviewing all agreements associated with the set-up or acquisition of the respective investments, investee financial information and other legal documents. We reviewed management’s analysis of the significant activities and evaluated which party has the power to direct such activities, considering the purpose and design of the entity, composition of the board of directors and other legal rights of the parties, including whether there were indicators that other parties to the arrangement were acting in the role of agents or defacto agents. We also compared the rights of each party to underlying legal documents, articles of incorporation and board of directors’ minutes. In addition, we performed an evaluation of the various entities’ equity and whether such equity at risk was sufficient to conduct its related activities. We analyzed the at-risk equity holder’s obligation to absorb the investments’ expected losses and right to receive expected residual returns. We further evaluated the accounting and presentation of related financing instruments by reviewing the agreements and terms related to such instruments and assessing their equity and debt characteristics. Finally, we inspected new financing arrangements and any changes to related agreements within the respective structures to determine if a reconsideration event arose that necessitated a re-evaluation of previous accounting judgments.

/s/ Ernst & Young LLP        

Chartered Professional Accountants

Licensed Public Accountants

We have served as the Company's auditor since 2013.

Toronto, Canada

February 27, 2020

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Directors of Algonquin Power & Utilities Corp.

Opinion on Internal Control over Financial Reporting

We have audited Algonquin Power & Utilities Corp.’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the “COSO criteria”). In our opinion, Algonquin Power & Utilities Corp. (the "Company") maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on the COSO criteria.

As indicated in the accompanying Internal Controls over Financial Reporting section in Management’s Report, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Enbridge Gas New Brunswick Limited Partnership ("New Brunswick Gas") and St. Lawrence Gas Company, Inc. ("St. Lawrence Gas"), which are included in the 2019 consolidated financial statements of the Company and constituted 4% of total assets as of December 31, 2019 and 2% of revenues for the year then ended. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of New Brunswick Gas and St. Lawrence Gas.

We also have audited, in accordance with the standards of the Public Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets as of December 31, 2019 and 2018, and the consolidated statements of operations, comprehensive income, equity and cash flows for the years then ended, and the related notes, and our report dated February 27, 2020 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP        

Chartered Professional Accountants

Licensed Public Accountants

Toronto, Canada

February 27, 2020

Algonquin Power & Utilities Corp.

Consolidated Statements of Operations

(thousands of U.S. dollars, except per share amounts)	Year ended December 31
	2019			2018
Revenue
Regulated electricity distribution	$	784,396		$	831,196
Regulated gas distribution	439,153			431,453
Regulated water reclamation and distribution	130,488			128,437
Non-regulated energy sales	246,601			235,359
Other revenue	24,283			22,018
	1,624,921			1,648,463
Expenses
Operating expenses	471,989			472,466
Regulated electricity purchased	247,417			265,166
Regulated gas purchased	170,487			183,012
Regulated water purchased	8,142			8,796
Non-regulated energy purchased	17,258			27,164
Administrative expenses	56,802			52,710
Depreciation and amortization	284,304			260,772
Loss (gain) on foreign exchange	3,146			(58		)
	1,259,545			1,270,028
Operating income	365,376			378,435
Interest expense on long-term debt and others	(181,488		)	(152,118		)
Income (loss) from long-term investments (note 8)	399,092			(84,818		)
Other net losses (note 19)	(44,026		)	(8,402		)
Gain (loss) on derivative financial instruments (note 24(b)(iv))	16,113			(636		)
	189,691			(245,974		)
Earnings before income taxes	555,067			132,461
Income tax expense (note 18)
Current	(16,431		)	(11,347		)
Deferred	(53,686		)	(42,025		)
	(70,117		)	(53,372		)
Net earnings	484,950			79,089
Net effect of non-controlling interests (note 17)
Net effect of non-controlling interests	62,416			108,521
Net effect of non-controlling interests held by related party	(16,482		)	(2,622		)
	$	45,934		$	105,899
Net earnings attributable to shareholders of Algonquin Power & Utilities Corp.	$	530,884		$	184,988
Series A and D Preferred shares dividend (note 15)	8,486			8,027
Net earnings attributable to common shareholders of Algonquin Power & Utilities Corp.	$	522,398		$	176,961
Basic net earnings per share (note 20)	$	1.05		$	0.38
Diluted net earnings per share (note 20)	$	1.04		$	0.38

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Consolidated Statements of Comprehensive Income

(thousands of U.S. dollars)	Year ended December 31
	2019			2018
Net earnings	$	484,950		$	79,089
Other comprehensive income (loss):
Foreign currency translation adjustment, net of tax recovery of $289 and $4,532, respectively (notes 1(u), 24(b)(iii) and 24(b)(iv))	7,795			(27,969		)
Change in fair value of cash flow hedges, net of tax expense and tax recovery of $3,862 and $952, respectively (note 24(b)(ii))	10,580			(2,690		)
Change in pension and other post-employment benefits, net of tax recovery and tax expense of $2,735 and $696, respectively (note 10)	(6,509		)	1,960
Other comprehensive income (loss), net of tax	11,866			(28,699		)
Comprehensive income	496,816			50,390
Comprehensive loss attributable to the non-controlling interests	(43,506		)	(107,380		)
Comprehensive income attributable to shareholders of Algonquin Power & Utilities Corp.	$	540,322		$	157,770

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Consolidated Balance Sheets

(thousands of U.S. dollars)
	December 31, 2019		December 31, 2018
ASSETS
Current assets:
Cash and cash equivalents	$	62,485	$	46,819
Accounts receivable, net (note 4)	259,144		245,728
Fuel and natural gas in storage	30,804		43,063
Supplies and consumables inventory	60,295		52,537
Regulatory assets (note 7)	50,213		59,037
Prepaid expenses	29,003		27,283
Derivative instruments (note 24)	13,483		9,616
Other assets and long-term investments (notes 8 and 11)	7,764		7,522
	513,191		491,605
Property, plant and equipment, net (note 5)	7,231,664		6,393,558
Intangible assets, net (note 6)	47,616		54,994
Goodwill (note 6)	1,031,696		954,282
Regulatory assets (note 7)	509,674		401,058
Long-term investments (note 8)
Investments carried at fair value	1,294,147		814,530
Other long-term investments	121,968		134,371
Derivative instruments (note 24)	72,221		53,192
Deferred income taxes (note 18)	30,585		72,415
Other assets (note 11)	58,708		28,584
	$	10,911,470	$	9,398,589

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Consolidated Balance Sheets

(thousands of U.S. dollars)
	December 31, 2019			December 31, 2018
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	150,336		$	89,740
Accrued liabilities	307,952			235,586
Dividends payable (note 15)	73,945			62,613
Regulatory liabilities (note 7)	41,683			39,005
Long-term debt (note 9)	225,013			13,048
Other long-term liabilities (note 12)	57,939			42,337
Derivative instruments (note 24)	5,898			14,339
Other liabilities	9,300			2,313
	872,066			498,981
Long-term debt (note 9)	3,706,855			3,323,747
Regulatory liabilities (note 7)	556,379			549,208
Deferred income taxes (note 18)	491,538			444,145
Derivative instruments (note 24)	78,766			88,503
Pension and other post-employment benefits obligation (note 10)	224,094			199,829
Other long-term liabilities (note 12)	243,401			255,668
	5,301,033			4,861,100
Redeemable non-controlling interests (note 17)
Redeemable non-controlling interest, held by related party (note 16(b))	305,863			307,622
Redeemable non-controlling interests	25,913			33,364
Equity:
Preferred shares (note 13(b))	184,299			184,299
Common shares (note 13(a))	4,017,044			3,562,418
Additional paid-in capital	50,579			45,553
Deficit	(367,107		)	(595,259		)
Accumulated other comprehensive loss (note 14)	(9,761		)	(19,385		)
Total equity attributable to shareholders of Algonquin Power & Utilities Corp.	3,875,054			3,177,626
Non-controlling interests (note 17)
Non-controlling interests	457,834			519,896
Non-controlling interest, held by related party (note 16(c))	73,707			—
	531,541			519,896
Total equity	4,406,595			3,697,522
Commitments and contingencies (note 22)
Subsequent events (notes 1(u), 8(a), 9(a), 9(d), 13(a)(iii)) and 24(b)(ii))
	$	10,911,470		$	9,398,589

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Consolidated Statement of Equity

(thousands of U.S. dollars) For the year ended December 31, 2019
	Algonquin Power & Utilities Corp. Shareholders
	Common shares		Preferred shares		Additional paid-in capital			Accumulated deficit			Accumulated OCI			Non- controlling interests			Total
Balance, December 31, 2018	$	3,562,418	$	184,299	$	45,553		$	(595,259	)	$	(19,385	)	$	519,896		$	3,697,522
Adoption of ASU 2017-12 on hedging (note 2(a))	—		—		—			(186		)	186			—			—
Net earnings (loss)	—		—		—			530,884			—			(45,934		)	484,950
Redeemable non-controlling interests not included in equity (note 17)	—		—		—			—			—			(7,476		)	(7,476		)
Other comprehensive income	—		—		—			—			9,438			2,428			11,866
Dividends declared and distributions to non-controlling interests	—		—		—			(217,464		)	—			(37,691		)	(255,155		)
Dividends and issuance of shares under dividend reinvestment plan (note 13(a)(iii))	68,856		—		—			(68,856		)	—			—			—
Contributions received from non-controlling interests	—		—		—			—			—			100,318			100,318
Common shares issued upon conversion of convertible debentures	148		—		—			—			—			—			148
Common shares issued upon public offering, net of cost	364,211		—		—			—			—			—			364,211
Issuance of common shares under employee share purchase plan	2,853		—		—			—			—			—			2,853
Share-based compensation	—		—		12,974			—			—			—			12,974
Common shares issued pursuant to share-based awards	18,558		—		(7,948		)	(16,226		)	—			—			(5,616		)
Balance, December 31, 2019	$	4,017,044	$	184,299	$	50,579		$	(367,107	)	$	(9,761	)	$	531,541		$	4,406,595

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Consolidated Statement of Equity

(thousands of U.S. dollars) For the year ended December 31, 2018
	Algonquin Power & Utilities Corp. Shareholders
	Common shares		Preferred shares		Additional paid-in capital			Accumulated deficit			Accumulated OCI			Non- controlling interests			Total
Balance, December 31, 2017	$	3,021,699	$	184,299	$	38,569		$	(524,311	)	$	(2,792	)	$	602,636		$	3,320,100
Adoption of Topic 606 on revenue (note 1(t))	—		—		—			1,860			—			—			1,860
Adoption of ASU 2018-02 on tax effects in AOCI	—		—		—			(10,625		)	10,625			—			—
Net earnings (loss)	—		—		—			184,988			—			(105,899		)	79,089
Redeemable non-controlling interests not included in equity (note 17)	—		—		—			—			—			4,923			4,923
Other comprehensive loss	—		—		—			—			(27,218		)	(1,481		)	(28,699		)
Dividends declared and distributions to non-controlling interests	—		—		—			(187,890		)	—			(9,393		)	(197,283		)
Dividends and issuance of shares under dividend reinvestment plan (note 13(a)(iii))	55,442		—		—			(55,442		)	—			—			—
Common shares issued pursuant to public offering, net of costs (note 13(a)(i))	472,180		—		—			—			—			—			472,180
Common shares issued upon conversion of convertible debentures (note 12(h))	447		—		—			—			—			—			447
Common shares issued pursuant to share-based awards (note 13(c))	12,650		—		(4,027		)	(3,839		)	—			—			4,784
Share-based compensation (note 13(c))	—		—		11,011			—			—			—			11,011
Contributions received from non-controlling interests (note 3(g)), net of costs	—		—		—			—			—			29,110			29,110
Balance, December 31, 2018	$	3,562,418	$	184,299	$	45,553		$	(595,259	)	$	(19,385	)	$	519,896		$	3,697,522

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Consolidated Statements of Cash Flows

(thousands of U.S. dollars)	Year ended December 31
	2019			2018
Cash provided by (used in):
Operating Activities
Net earnings	$	484,950		$	79,089
Adjustments and items not affecting cash:
Depreciation and amortization	284,304			260,772
Deferred taxes	53,686			42,025
Unrealized gain on derivative financial instruments	(15,237		)	(1,781		)
Share-based compensation expense	11,042			7,495
Cost of equity funds used for construction purposes	(4,896		)	(2,728		)
Change in value of investments carried at fair value	(276,458		)	137,957
Pension and post-employment contributions in excess of expense	(8,952		)	(6,354		)
Distributions received from equity investments, net of income	7,487			5,698
Others	15,031			16,305
Changes in non-cash operating items (note 23)	60,303			(8,126		)
	611,260			530,352
Financing Activities
Increase in long-term debt	3,614,758			2,015,533
Decrease in long-term debt	(3,048,008		)	(1,699,592		)
Issuance of common shares, net of costs	362,364			473,911
Cash dividends on common shares	(196,391		)	(166,384		)
Dividends on preferred shares	(8,486		)	(8,027		)
Contributions from non-controlling interests, related party (note 17)	96,752			305,000
Contributions from non-controlling interests and redeemable non-controlling interests (note 17)	3,403			15,250
Production-based cash contributions from non-controlling interest	3,565			13,860
Distributions to non-controlling interests, related party (note 16(b) and (c))	(38,718		)	—
Distributions to non-controlling interests	(12,251		)	(9,289		)
Settlement of derivatives	(8,732		)	—
Proceeds from exercise of share options	—			4,504
Shares surrendered to fund withholding taxes on exercised share options	(5,282		)	(2,088		)
Increase in other long-term liabilities	10,175			9,403
Decrease in other long-term liabilities	(39,783		)	(20,144		)
	733,366			931,937
Investing Activities
Additions to property, plant and equipment and intangible assets	(581,332		)	(466,369		)
Increase in long-term investments	(669,832		)	(1,005,072		)
Acquisitions of operating entities	(308,423		)	—
Increase in other assets	(16,690		)	(5,912		)
Receipt of principal on development loans receivable	251,118			17,950
Decrease in long-term investments	1,000			1,158
Proceeds from sale of long-lived assets	—			2,912
	(1,324,159		)	(1,455,333		)
Effect of exchange rate differences on cash and restricted cash	1,032			(606		)
Increase in cash, cash equivalents and restricted cash	21,499			6,350
Cash, cash equivalents and restricted cash, beginning of year	65,773			59,423
Cash, cash equivalents and restricted cash, end of year	$	87,272		$	65,773
Supplemental disclosure of cash flow information:	2019			2018
Cash paid during the year for interest expense	$	171,548		$	155,309
Cash paid during the year for income taxes	$	14,543		$	9,652
Non-cash financing and investing activities:
Property, plant and equipment acquisitions in accruals	$	98,231		$	45,154
Issuance of common shares under dividend reinvestment plan and share-based compensation plans	$	87,414		$	65,767
Issuance of common shares upon conversion of convertible debentures	$	155		$	468
Sale of property, plant and equipment, intangible assets and accrued liabilities in exchange of note receivable	$	57,753		$	13,092

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

Algonquin Power & Utilities Corp. (“APUC” or the “Company”) is an incorporated entity under the Canada Business Corporations Act. APUC's operations are organized across two primary business units consisting of the Regulated Services Group and the Renewable Energy Group. The Regulated Services Group owns and operates a portfolio of regulated electric, natural gas, water distribution and wastewater collection utility systems and transmission operations in the United States and Canada; the Renewable Energy Group owns and operates a diversified portfolio of non-regulated renewable and thermal electric generation assets.

1. Significant accounting policies

(a) Basis of preparation

The accompanying consolidated financial statements and notes have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and follow disclosure required under Regulation S-X provided by the U.S. Securities and Exchange Commission.

(b) Basis of consolidation

The accompanying consolidated financial statements of APUC include the accounts of APUC, its wholly owned subsidiaries and variable interest entities (“VIEs”) where the Company is the primary beneficiary (note 1(m)). Intercompany transactions and balances have been eliminated. Interests in subsidiaries owned by third parties are included in non-controlling interests (note 1(s)).

(c) Business combinations, intangible assets and goodwill

The Company accounts for acquisitions of entities or assets that meet the definition of a business as business combinations. Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed are measured at their fair value at the acquisition date, except for deferred income taxes which are accounted for as described in note 1(v). Acquisition costs are expensed in the period incurred. When the set of activities does not represent a business, the transaction is accounted for as an asset acquisition and includes acquisition costs.

Intangible assets acquired are recognized separately at fair value if they arise from contractual or other legal rights or are separable. Power sales contracts are amortized on a straight-line basis over the remaining term of the contract ranging from 6 to 25 years from the date of acquisition. Interconnection agreements are amortized on a straight-line basis over their estimated life of 40 years. Customer relationships are amortized on a straight-line basis over their estimated life of 40 years.

Goodwill represents the excess of the purchase price of an acquired business over the fair value of the net assets acquired. Goodwill is generally not included in the rate base on which regulated utilities are allowed to earn a return and is not amortized.

As at September 30 of each year, the Company assesses qualitative and quantitative factors to determine whether it is more likely than not that the fair value of a reporting unit to which goodwill is attributed is less than its carrying amount. If it is more likely than not that a reporting unit’s fair value is less than its carrying amount or if a quantitative assessment is elected, the Company calculates the fair value of the reporting unit. The carrying amount of the reporting unit’s goodwill is considered not recoverable if the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value. An impairment charge is recorded for any excess of the carrying value of the goodwill over the implied fair value. Goodwill is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount.

(d) Accounting for rate regulated operations

The operating companies within the Regulated Services Group are subject to rate regulation generally overseen by the public utility commission of the states and provinces in which they operate (the “Regulator”). The Regulator provides the final determination of the rates charged to customers. APUC’s regulated operating companies are accounted for under the principles of U.S. Financial Accounting Standards Board (“FASB”) ASC Topic 980, Regulated Operations (“ASC 980”).

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

1. Significant accounting policies (continued)

(d) Accounting for rate regulated operations (continued)

Under ASC 980, regulatory assets and liabilities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process. Included in note 7 “Regulatory matters” are details of regulatory assets and liabilities, and their current regulatory treatment.

In the event the Company determines that its net regulatory assets are not probable of recovery, it would no longer apply the principles of the current accounting guidance for rate regulated enterprises and would be required to record an after-tax, non-cash charge or credit against earnings for any remaining regulatory assets or liabilities. The impact could be material to the Company’s reported financial condition and results of operations.

The U.S. electric, gas and water utilities’ accounts are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (“FERC”), the Regulator and National Association of Regulatory Utility Commissioners in the United States. The New Brunswick Gas accounts are maintained in accordance with the New Brunswick Gas Distribution Act Uniform Accounting Regulation.

(e) Cash and cash equivalents

Cash and cash equivalents include all highly liquid instruments with an original maturity of three months or less.

(f) Restricted cash

Restricted cash represents reserves and amounts set aside pursuant to requirements of various debt agreements, deposits to be returned back to customers, and certain requirements related to generation and transmission operations. Cash reserves segregated from APUC’s cash balances are maintained in accounts administered by a separate agent and disclosed separately as restricted cash in these consolidated financial statements. APUC cannot access restricted cash without the prior authorization of parties not related to APUC.

(g) Accounts receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses adjusted to take into account current market conditions and customers’ financial condition, the amount of receivables in dispute, and the receivables aging and current payment patterns. Account balances are charged against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. The Company does not have any off-balance sheet credit exposure related to its customers.

(h) Fuel and natural gas in storage

Fuel and natural gas in storage is reflected at weighted average cost or first-in-first-out as required by regulators and represents fuel, natural gas and liquefied natural gas that will be utilized in the ordinary course of business of the gas utilities and some generating facilities. Existing rate orders (note 7(e)) and other contracts allow the Company to pass through the cost of gas purchased directly to the customers along with any applicable authorized delivery surcharge adjustments. Accordingly, the net realizable value of fuel and gas in storage does not fall below the cost to the Company.

(i) Supplies and consumables inventory

Supplies and consumables inventory (other than capital spares and rotatable spares, which are included in property, plant and equipment) are charged to inventory when purchased and then capitalized to plant or expensed, as appropriate, when installed, used or become obsolete. These items are stated at the lower of cost and net realizable value. Through rate orders and the regulatory environment, capitalized construction jobs are recovered through rate base and repair and maintenance expenses are recovered through a cost of service calculation. Accordingly, the cost usually reflects the net realizable value.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

1. Significant accounting policies (continued)

(j)    Property, plant and equipment

Property, plant and equipment are recorded at cost. Capitalization of development projects begins when management with the relevant authority has authorized and committed to the funding of a project and it is probable that costs will be realized through the use of the asset or ultimate construction and operation of a facility. Project development costs for rate regulated entities, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are capitalized either as property, plant and equipment or regulatory assets when it is determined that recovery of such costs through regulated revenue of the completed project is probable.

The costs of acquiring or constructing property, plant and equipment include the following: materials, labour, contractor and professional services, construction overhead directly attributable to the capital project (where applicable), interest for non-regulated property and allowance for funds used during construction (“AFUDC”) for regulated property. Where possible, individual components are recorded and depreciated separately in the books and records of the Company. Plant and equipment under finance leases are initially recorded at cost determined as the present value of lease payments to be made over the lease term.

AFUDC represents the cost of borrowed funds and a return on other funds. Under ASC 980, an allowance for funds used during construction projects that are included in rate base is capitalized. This allowance is designed to enable a utility to capitalize financing costs during periods of construction of property subject to rate regulation. For operations that do not apply regulatory accounting, interest related only to debt is capitalized as a cost of construction in accordance with ASC 835, Interest. The interest capitalized that relates to debt reduces interest expense on the consolidated statements of operations. The AFUDC capitalized that relates to equity funds is recorded as interest and other income under income from long-term investments on the consolidated statements of operations. 

Improvements that increase or prolong the service life or capacity of an asset are capitalized. Costs incurred for major expenditures or overhauls that occur at regular intervals over the life of an asset are capitalized and depreciated over the related interval. Maintenance and repair costs are expensed as incurred.

Grants related to capital expenditures are recorded as a reduction to the cost of assets and are amortized at the rate of the related asset as a reduction to depreciation expense. Grants related to operating expenses such as maintenance and repairs costs are recorded as a reduction of the related expense. Contributions in aid of construction represent amounts contributed by customers, governments and developers to assist with the funding of some or all of the cost of utility capital assets. It also includes amounts initially recorded as advances in aid of construction (note 12(a)) but where the advance repayment period has expired. These contributions are recorded as a reduction in the cost of utility assets and are amortized at the rate of the related asset as a reduction to depreciation expense.

The Company’s depreciation is based on the estimated useful lives of the depreciable assets in each category and is determined using the straight-line method with the exception of certain wind assets, as described below. The ranges of estimated useful lives and the weighted average useful lives are summarized below:

	Range of useful lives		Weighted average useful lives
	2019	2018	2019	2018
Generation	3 - 60	3 - 60	33	33
Distribution	5 - 100	5 - 100	42	40
Equipment	5 - 44	5 - 43	10	10

The Company uses the unit-of-production method for certain components of its wind generating facilities where the useful life of the component is directly related to the amount of production. The benefits of components subject to wear and tear from the power generation process are best reflected through the unit-of-production method. The Company generally uses wind studies prepared by third parties to estimate the total expected production of each component.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

1. Significant accounting policies (continued)

(j)    Property, plant and equipment (continued)

In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of the Regulated Services Group are replaced or retired, the original cost plus any removal costs incurred (net of salvage) are charged to accumulated depreciation with no gain or loss reflected in results of operations. Gains and losses will be charged to results of operations in the future through adjustments to depreciation expense. In the absence of regulator-approved accounting policies, gains and losses on the disposition of property, plant and equipment are charged to earnings as incurred. 

(k)Commonly owned facilities

The Regulated Services Group owns undivided interests in three electric generating facilities with ownership interest ranging from 7.52% to 60% with a corresponding share of capacity and generation from the facility used to serve certain of its utility customers. The Company's investment in the undivided interest is recorded as plant in service and recovered through rate base. The Company's share of operating costs is recognized in operating, maintenance and fuel expenditures excluding depreciation expense.

(l) Impairment of long-lived assets

APUC reviews property, plant and equipment and intangible assets for impairment whenever events or changes in circumstances indicate the carrying amount may not be recoverable.

Recoverability of assets expected to be held and used is measured by comparing the carrying amount of an asset to undiscounted expected future cash flows. If the carrying amount exceeds the recoverable amount, the asset is written down to its fair value.

(m) Variable interest entities

The Company performs analyses to assess whether its operations and investments represent VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements and jointly owned facilities. VIEs for which the Company is deemed the primary beneficiary are consolidated. In circumstances where APUC is not deemed the primary beneficiary, the VIE is not consolidated (note 8).

The Company has equity and notes receivable interests in two power generating facilities. APUC has determined that both entities are considered VIEs mainly based on total equity at risk not being sufficient to permit the legal entity to finance its activities without additional subordinated financial support. The key decisions that affect the generating facilities’ economic performance relate to siting, permitting, technology, construction, operations and maintenance and financing. As APUC has both the power to direct the activities of the entities that most significantly impact its economic performance and the right to receive benefits or the obligation to absorb losses of the entities that could potentially be significant to the entity, the Company is considered the primary beneficiary.

Total net book value of generating assets and long-term debt of these facilities amounts to $60,230 (2018 - $59,288) and $21,754 (2018 - $22,263), respectively. The financial performance of these facilities reflected on the consolidated statements of operations includes non-regulated energy sales of $17,108 (2018 - $17,232), operating expenses and amortization of $4,930 (2018 - $4,634) and interest expense of $2,340 (2018 - $2,557).

(n) Long-term investments and notes receivable

Investments in which APUC has significant influence but not control are either accounted for using the equity method or at fair value. Equity-method investments are initially measured at cost including transaction costs and interest when applicable. APUC records its share in the income or loss of its equity-method investees in income from long-term investments in the consolidated statements of operations. APUC records in the consolidated statements of operations the fluctuations in the fair value of its investees held at fair value and dividend income when it is declared by the investee.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

1. Significant accounting policies (continued)

(n) Long-term investments and notes receivable (continued)

Notes receivable are financial assets with fixed or determined payments that are not quoted in an active market. Notes receivable are initially recorded at cost, which is generally face value. Subsequent to acquisition, the notes receivable are recorded at amortized cost using the effective interest method. The Company holds these notes receivable as long-term investments and does not intend to sell these instruments prior to maturity. Interest from long-term investments is recorded as earned and when collectability of both the interest and principal are reasonably assured.

If a loss in value of a long-term investment is considered other than temporary, an allowance for impairment on the investment is recorded for the amount of that loss. An allowance for impairment loss on notes receivable is recorded if it is expected that the Company will not collect all principal and interest contractually due. The impairment is measured based on the present value of expected future cash flows discounted at the note’s effective interest rate.

(o) Pension and other post-employment plans

The Company has established defined contribution pension plans, defined benefit pension plans, other post-employment benefit (“OPEB”) plans, and supplemental retirement program (“SERP”) plans for its various employee groups in Canada and the United States. Employer contributions to the defined contribution pension plans are expensed as employees render service. The Company recognizes the funded status of its defined benefit pension plans, OPEB and SERP plans on the consolidated balance sheets. The Company’s expense and liabilities are determined by actuarial valuations, using assumptions that are evaluated annually as of December 31, including discount rates, mortality, assumed rates of return, compensation increases, turnover rates and healthcare cost trend rates. The impact of modifications to those assumptions and modifications to prior services are recorded as actuarial gains and losses in accumulated other comprehensive income (“AOCI”) and amortized to net periodic cost over future periods using the corridor method. When settlements of the Company's pension plans occur, the Company recognizes associated gains or losses immediately in earnings if the cost of all settlements during the year is greater than the sum of the service cost and interest cost components of the pension plan for the year. The amount recognized is a pro rata portion of the gains and losses in AOCI equal to the percentage reduction in the projected benefit obligation as a result of the settlement.

The costs of the Company’s pension for employees are expensed over the periods during which employees render service and the service costs are recognized as part of administrative expenses in the consolidated statements of operations.The components of net periodic benefit cost other than the service cost component are included in other net losses in the consolidated statements of operations.

(p) Asset retirement obligations

The Company recognizes a liability for asset retirement obligations based on the fair value of the liability when incurred, which is generally upon acquisition, during construction or through the normal operation of the asset. Concurrently, the Company also capitalizes an asset retirement cost, equal to the estimated fair value of the asset retirement obligation, by increasing the carrying value of the related long-lived asset. The asset retirement costs are depreciated over the asset’s estimated useful life and are included in depreciation and amortization expense on the consolidated statements of operations. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the consolidated statements of operations. Actual expenditures incurred are charged against the obligation.

(q) Leases

The Company adopted ASU 2016-02, Leases (Topic 842) ("ASC 842") during 2019 using a modified retrospective approach.

The Company leases buildings, vehicles, rail cars, and office equipment for use in its day-to-day operations. The Company has options to extend the lease term of many of its lease agreements, with renewal periods ranging from one to five years. As at the consolidated balance sheet date, the Company is not reasonably certain that these renewal options will be exercised.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

1. Significant accounting policies (continued)

(q) Leases (continued)

The Renewable Energy Group enters into land easement agreements for the operation of its generation facilities. In assessing whether these contracts contain leases, the Company considers whether it has exclusive use of the land. In the majority of situations, the landowner or grantor of the easement still has full access to the land and can use the land in any capacity, as long as it does not interfere with the Company’s operations. Therefore, these land easement agreements do not contain leases. For land easement agreements that provide exclusive access to and use of the land, these agreements meet the definition of a lease and are within the scope of ASC 842.

The Regulated Services Group enters into easement agreements for the operation of its utilities. For all easements that existed or were expired as of January 1, 2019, the practical expedient was taken to not change the legacy accounting for these easement contracts. For new easement contracts entered into subsequent to January 1, 2019, the Company considers whether they contain a lease.

The implementation of ASC 842 did not have an impact on the Company's existing finance leases. The weighted-average discount rate as of December 31, 2019 for the Company's finance lease assets and liabilities is 6.45% and the weighted-average remaining lease term of the Company's finance leases is 5.55 years.

New right-of-use assets and lease liabilities of $8,295 were recognized for the Company's operating leases as at January 1, 2019. As a result of the acquisition of Enbridge Gas New Brunswick Limited Partnership ("New Brunswick Gas") on October 1, 2019 (note 3(a)), the Company acquired new right-of-use assets and assumed lease liabilities of $1,316. The weighted-average discount rate as of December 31, 2019 for the Company's operating lease assets and liabilities is 3.95% and the weighted-average remaining lease term is 13.49 years.

The right-of-use assets are included in property, plant and equipment while lease liabilities are included in other liabilities on the consolidated balance sheets.

The Company's operating leases payments for the next five years and thereafter are as follows:

Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
$	2,115	$	1,138	$	688	$	659	$	642	$	5,195	$	10,437

The lease payments for the Company's finance leases are expected to be approximately $539 annually for the next five years, and $318 thereafter.

(r) Share-based compensation

The Company has several share-based compensation plans: a share option plan; an employee share purchase plan (“ESPP”); a deferred share unit (“DSU”) plan; a restricted share unit (“RSU”) plan and a performance share unit (“PSU”) plan. Equity-classified awards are measured at the grant date fair value of the award. The Company estimates grant date fair value of options using the Black-Scholes option pricing model. The fair value is recognized over the vesting period of the award granted, adjusted for estimated forfeitures. The compensation cost is recorded as administrative expenses in the consolidated statements of operations and additional paid-in capital in equity. Additional paid-in capital is reduced as the awards are exercised, and the amount initially recorded in additional paid-in capital is credited to common shares.

(s) Non-controlling interests

Non-controlling interests represent the portion of equity ownership in subsidiaries that is not attributable to the equity holders of APUC. Non-controlling interests are initially recorded at fair value and subsequently adjusted for the proportionate share of earnings and other comprehensive income (“OCI”) attributable to the non-controlling interests and any dividends or distributions paid to the non-controlling interests.

If a transaction results in the acquisition of all, or part, of a non-controlling interest in a consolidated subsidiary, the acquisition of the non-controlling interest is accounted for as an equity transaction. No gain or loss is recognized in net earnings or comprehensive income as a result of changes in the non-controlling interest, unless a change results in the loss of control by the Company.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

1. Significant accounting policies (continued)

(s) Non-controlling interests (continued)

Certain of the Company’s U.S. based wind and solar businesses are organized as limited liability corporations (“LLCs”) and partnerships and have non-controlling membership equity investors (“tax equity partnership units”, or “Tax Equity Investors”), which are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. These LLCs and partnership agreements have liquidation rights and priorities that are different from the underlying percentage ownership interests. In those situations, simply applying the percentage ownership interest to U.S. GAAP net income in order to determine earnings or losses would not accurately represent the income allocation and cash flow distributions that will ultimately be received by the investors. As such, the share of earnings attributable to the non-controlling interest holders in these entities is calculated using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting (note 17).

The HLBV method uses a balance sheet approach. A calculation is prepared at each balance sheet date to determine the amount that Tax Equity Investors would receive if an equity investment entity were to liquidate all of its assets and distribute that cash to the investors based on the contractually defined liquidation priorities. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period is the Tax Equity Investors' share of the earnings or losses from the investment for that period. Due to certain mandatory liquidation provisions of the LLC and partnership agreements, this could result in a net loss to APUC’s consolidated results in periods in which the Tax Equity Investors report net income. The calculation varies in its complexity depending on the capital structure and the tax considerations of the investments.

Equity instruments subject to redemption upon the occurrence of uncertain events not solely within APUC’s control are classified as temporary equity and presented as redeemable non-controlling interests on the consolidated balance sheets. The Company records temporary equity at issuance based on cash received less any transaction costs. As needed, the Company reevaluates the classification of its redeemable instruments, as well as the probability of redemption. If the redemption amount is probable or currently redeemable, the Company records the instruments at their redemption value. Increases or decreases in the carrying amount of a redeemable instrument are recorded within deficit. When the redemption feature lapses or other events cause the classification of an equity instrument as temporary equity to be no longer required, the existing carrying amount of the equity instrument is reclassified to permanent equity at the date of the event that caused the reclassification.

(t) Recognition of revenue

The Company accounts for revenue in accordance with ASC Topic 606, Revenue from Contracts with Customers, which was adopted on January 1, 2018 using the modified retrospective method, applied to contracts that were not completed at the date of initial application. The adoption of the new standard resulted in an adjustment of $2,488 or $1,860 net of taxes to increase opening retained earnings for previously deferred revenue related to the Empire fiber business.

Revenue is recognized when control of the promised goods or services is transferred to the Company’s customers in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services.

Refer to note 21, "Segmented information" for details of revenue disaggregation by business units.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

1. Significant accounting policies (continued)

(t) Recognition of revenue (continued)

Regulated Services Group revenue

Regulated Services Group revenues consist primarily of the distribution of electricity, natural gas, and water.

Revenue related to utility electricity and natural gas sales and distribution is recognized over time as the energy is delivered. At the end of each month, the electricity and natural gas delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue and sales are based on the ratio of billable days versus unbilled days, amount of electricity or natural gas procured during that month, historical customer class usage patterns, weather, line loss, unaccounted-for gas and current tariffs. Unbilled receivables are typically billed within the next month. Some customers elect to pay their bill on an equal monthly plan. As a result, in some months cash is received in advance of the delivery of electricity. Deferred revenue is recorded for that amount. The amount of revenue recognized in the period from the balance of deferred revenue is not significant.

Water reclamation and distribution revenue is recognized over time when water is processed or delivered to customers. At the end of each month, the water delivered and wastewater collected from the customers from the date of their last meter read to the end of the month are estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue are based on the ratio of billable days versus unbilled days, amount of water procured and collected during that month, historical customer class usage patterns and current tariffs. Unbilled receivables are typically billed within the next month.

On occasion, a utility is permitted to implement new rates that have not been formally approved by the regulatory commission, which are subject to refund. The Company recognizes revenue based on the interim rate and, if needed, establishes a reserve for amounts that could be refunded based on experience for the jurisdiction in which the rates were implemented.

Revenue for certain of the Company’s regulated utilities is subject to alternative revenue programs approved by their respective regulators. Under these programs, the Company charges approved annual delivery revenue on a systematic basis over the fiscal year. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is disclosed as alternative revenue in note 21, "Segmented information" and is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers (note 7). The amount subsequently billed to customers is recorded as a recovery of the regulatory asset.

Renewable Energy Group revenue

Renewable Energy Group's revenue consists primarily of the sale of electricity, capacity, and renewable energy credits.

Revenue related to the sale of electricity is recognized over time as the electricity is delivered. The electricity represents a single performance obligation that represents a promise to transfer to the customer a series of distinct goods that are substantially the same and that have the same pattern of transfer to the customer.

Revenues related to the sale of capacity are recognized over time as the capacity is provided. The nature of the promise to provide capacity is that of a stand-ready obligation. The capacity is generally expressed in monthly volumes and prices. The capacity represents a single performance obligation that represents a promise to transfer to the customer a series of distinct services that are substantially the same and that have the same pattern of transfer to the customer.

Qualifying renewable energy projects receive renewable energy credits (“RECs”) and solar renewable energy credits (“SRECs”) for the generation and delivery of renewable energy to the power grid. The energy credit certificates represent proof that 1 MW of electricity was generated from an eligible energy source. The RECs and SRECs can be traded and the owner of the RECs or SRECs can claim to have purchased renewable energy. RECs and SRECs are primarily sold under fixed contracts, and revenue for these contracts is recognized at a point in time, upon generation of the associated electricity. Any RECs or SRECs generated above contracted amounts are held in inventory, with the offset recorded as a decrease in operating expenses.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

1. Significant accounting policies (continued)

(t) Recognition of revenue (continued)

Renewable Energy Group revenue (continued)

The Company has elected to apply the invoicing practical expedient to the electricity and capacity in the Renewable Energy Group contracts. The Company does not disclose the value of unsatisfied performance obligations for these contracts as revenue is recognized at the amount to which the Company has the right to invoice for services performed.

Revenue is recorded net of sales taxes.

(u) Foreign currency translation

APUC’s reporting currency is the U.S. dollar. Within these consolidated financial statements, the Company denotes any amounts denominated in Canadian dollars with “C$” immediately prior to the stated amount.

The Company’s Canadian operations are determined to have the Canadian dollar as their functional currency since the preponderance of operating, financing and investing transactions are denominated in Canadian dollars. The financial statements of these operations are translated into U.S. dollars using the current rate method, whereby assets and liabilities are translated at the rate prevailing at the balance sheet date, and revenue and expenses are translated using average rates for the period. Unrealized gains or losses arising as a result of the translation of the financial statements of these entities are reported as a component of OCI and are accumulated in a component of equity on the consolidated balance sheets, and are not recorded in income unless there is a complete or substantially complete sale or liquidation of the investment.

Subsequent to year-end, effective January 1, 2020, the functional currency of APUC, the non-consolidated parent entity, changed from the Canadian dollar to the U.S. dollar based on a balance of facts taking into consideration its operating, financing and investing activities. As a result of the entity's change of functional currency, changes were made to certain hedging relationships to mitigate the remaining Canadian dollar risk.

(v) Income taxes

Income taxes are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A valuation allowance is recorded against deferred tax assets to the extent that it is considered more likely than not that the deferred tax asset will not be realized. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in earnings in the period that includes the date of enactment (note 18). Investment tax credits for the rate regulated operations are deferred and amortized as a reduction to income tax expense over the estimated useful lives of the properties. Investment tax credits along with other income tax credits in the non-regulated operations are treated as a reduction to income tax expense in the year the credit arises.

The organizational structure of APUC and its subsidiaries is complex and the related tax interpretations, regulations and legislation in the tax jurisdictions in which they operate are continually changing. As a result, there can be tax matters that have uncertain tax positions. The Company recognizes the effect of income tax positions only if those positions are more likely than not of being sustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs.

(w)Financial instruments and derivatives

Accounts receivable and notes receivable are measured at amortized cost. Long-term debt and Series C preferred shares are measured at amortized cost using the effective interest method, adjusted for the amortization or accretion of premiums or discounts.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

1. Significant accounting policies (continued)

(w)Financial instruments and derivatives (continued)

Transaction costs that are directly attributable to the acquisition of financial assets are accounted for as part of the asset’s carrying value at inception. Transaction costs related to a recognized debt liability are presented in the consolidated balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts and premiums. Costs of arranging the Company’s revolving credit facilities and intercompany loans are recorded in other assets. Deferred financing costs, premiums and discounts on long-term debt are amortized using the effective interest method while deferred financing costs relating to the revolving credit facilities and intercompany loans are amortized on a straight-line basis over the term of the respective instrument.

The Company uses derivative financial instruments as one method to manage exposures to fluctuations in exchange rates, interest rates and commodity prices. APUC recognizes all derivative instruments as either assets or liabilities on the consolidated balance sheets at their respective fair values. The fair value recognized on derivative instruments executed with the same counterparty under a master netting arrangement are presented on a gross basis on the consolidated balance sheets. The amounts that could net settle are not significant. The Company applies hedge accounting to some of its financial instruments used to manage its foreign currency risk, interest rate risk and price risk exposures associated with sales of generated electricity.

For derivatives designated in a cash flow hedge relationship, the change in fair value is recognized in OCI. The amount recognized in AOCI is reclassified to earnings in the same period as the hedged cash flows affect earnings under the same line item in the consolidated statements of operations as the hedged item. If the hedging instrument no longer meets the criteria for hedge accounting, expires or is sold, terminated, exercised, or the designation is revoked, then hedge accounting is discontinued prospectively. The amount remaining in AOCI is transferred to the consolidated statements of operations in the same period that the hedged item affects earnings. If the forecasted transaction is no longer expected to occur, then the balance in AOCI is recognized immediately in earnings.

Foreign currency gain or loss on derivative or financial instruments designated as a hedge of the foreign currency exposure of a net investment in foreign operations that are effective as a hedge are reported in the same manner as the translation adjustment (in OCI) related to the net investment.

The Company’s electric distribution and thermal generation facilities enter into power and gas purchase contracts for load serving and generation requirements. These contracts meet the exemption for normal purchase and normal sales and, as such, are not required to be recorded at fair value as derivatives and are accounted for on an accrual basis. Counterparties are evaluated on an ongoing basis for non-performance risk to ensure it does not impact the conclusion with respect to this exemption.

(x)Fair value measurements

The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. The Company determines fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels:

• Level 1 Inputs: Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date.

• Level 2 Inputs: Other than quoted prices included in level 1, inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.

• Level 3 Inputs: Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.

(y) Commitments and contingencies

Liabilities for loss contingencies arising from environmental remediation, claims, assessments, litigation, fines, penalties and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

1. Significant accounting policies (continued)

(z) Use of estimates

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of these consolidated financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the years presented, management has made a number of estimates and valuation assumptions, including the useful lives and recoverability of property, plant and equipment, intangible assets and goodwill; the recoverability of notes receivable and long-term investments; the recoverability of deferred tax assets; assessments of unbilled revenue; pension and OPEB obligations; timing effect of regulated assets and liabilities; contingencies related to environmental matters; the fair value of assets and liabilities acquired in a business combination; and the fair value of financial instruments. These estimates and valuation assumptions are based on present conditions and management’s planned course of action, as well as assumptions about future business and economic conditions. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.

2.     Recently issued accounting pronouncements

(a) Recently adopted accounting pronouncements

The FASB issued accounting standards update ("ASU") 2018-15, Intangibles — Goodwill and Other Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract to provide additional guidance to address diversity in practice. This update aligns 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. The Company adopted this update prospectively as at the beginning of the third quarter. There were no significant impacts to the consolidated financial statements as a result of the adoption of this update.

The FASB issued ASU 2018-16, Derivatives and Hedging (Topic 815): Inclusion of the Secured Overnight Financing Rate ("SOFR") Overnight Index Swap ("OIS") Rate as a Benchmark Interest Rate for Hedge Accounting Purposes to identify a suitable alternative to the U.S. dollar LIBOR that is more firmly based on actual transactions in a robust market. This update permits the use of the OIS rate based on SOFR as a U.S. benchmark interest rate for hedge accounting purposes. This update was adopted concurrently with ASU 2017-12. The Company will follow the pronouncements prospectively for qualifying new or redesignated hedging relationships.

The FASB issued ASU 2018-07, Compensation — Stock Compensation (Topic 718): Improvements to Non-employee Share-Based Payment Accounting to expand the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from non-employees. This update changes the measurement basis and date of non-employee share-based payment awards and also makes amendments to how to measure non-employee awards with performance conditions. The adoption of this update in 2019 had no impact on the Company's consolidated financial statements.

The FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities, to improve the financial reporting of hedging relationships to better portray the economic results of an entity's risk management activities in its financial statements. The update also makes certain targeted improvements to simplify the application of the hedge accounting guidance. The FASB also issued ASU 2019-04 that contains further codification improvements to ASU 2017-12. The adoption of these updates in 2019 resulted in a reclassification of $186 from retained earnings to accumulated other comprehensive income for previous hedge ineffectiveness recognized in earnings for outstanding hedging contracts. The Company has also made certain amendments and simplifications to hedge effectiveness testing procedures and documentation to be followed prospectively where applicable in accordance with the pronouncements in the update.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

2.     Recently issued accounting pronouncements (continued)

(a) Recently adopted accounting pronouncements (continued)

The FASB issued ASU 2017-11, Earnings Per Share (Topic 260); Distinguishing Liabilities from Equity (Topic 480); Derivatives and Hedging (Topic 815): (Part I) Accounting for Certain Financial Instruments with Down Round Features, (Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a Scope Exception to address narrow issues with applying U.S. GAAP for certain financial instruments with characteristics of liabilities and equity. The adoption of this update in 2019 had no impact on the consolidated financial statements.

The FASB issued ASU 2016-02, Leases (Topic 842) to increase transparency and comparability among organizations utilizing leases. This ASU requires lessees to recognize the assets and liabilities arising from all leases on the balance sheet, but the effect of leases in the statement of operations and the statement of cash flows is largely unchanged. The FASB also issued subsequent amendments to ASC 842 that provide further practical expedients as well as codification clarifications and improvements. The adoption of this new lease standard in 2019 using a modified retrospective approach resulted in an adjustment of $8,295 to right-of-use assets and operating lease liabilities included in other long-term liabilities on the consolidated balance sheets, with no restatement of the comparative period.

The Company implemented new processes and procedures for the identification, analysis, and measurement of new lease contracts. A new software solution was implemented to assist with contract management, information tracking, and measurement as it relates to the new standard. The Company elected the following practical expedients as part of its adoption:

1. "Package of three" practical expedient that permits the Company not to reassess the scope, classification and initial direct costs of its expired and existing leases;

2. Land easements practical expedient that permits the Company not to reassess the accounting for land easements previously not accounted for under Leases ASC 840; and

3. Hindsight practical expedient that allows the Company to use hindsight in determining the lease term for existing contracts.

In addition, the Company made an accounting policy election to not recognize a lease liability or right-of-use asset on its consolidated balance sheets for short-term leases (lease term less than 12 months).

(b) Recently issued accounting guidance not yet adopted

The FASB issued ASU 2020-01, Investments - Equity Securities (Topic 321), Investments — Equity Method and Joint Ventures (Topic 323), and Derivatives and Hedging (Topic 815): Clarifying the Interactions between Topic 321, Topic 323, and Topic 815 to reduce diversity in practice and increase comparability of accounting for certain transactions. The amendments clarify when to consider observable price changes for the measurement of certain equity securities without a readily determinable fair value. They also clarify the scope of forward contracts and purchased options on these certain securities. The amendments in this update are effective for fiscal years beginning after December 15, 2020, and interim periods within those years. Early adoption is permitted, including early adoption in any interim period. The Company currently does not have any transactions that would be within the scope of this update but will continue to assess the impact of this update in the future.

The FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes as part of its initiative to reduce complexity in the accounting standards. The amendments remove certain exceptions to the general principles in Topic 740 and improve consistent application for other areas of Topic 740 by clarifying and amending existing guidance. The amendments in this update are effective for fiscal years beginning after December 15, 2020, and interim periods within those years. Early adoption is permitted, but all amendments must be early adopted simultaneously. The Company is currently assessing the impact of this update.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

2.     Recently issued accounting pronouncements (continued)

(b) Recently issued accounting guidance not yet adopted (continued)

The FASB issued ASU 2018-18, Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606 to reduce diversity in practice on how entities account for transactions on the basis of different views of the economics of a collaborative arrangement. The update clarifies that the arrangement should be accounted for under ASC 606 when a participant is a customer in the context of a unit of account, adds unit of account guidance in ASC 808 that is consistent with ASC 606, and precludes the recognition of revenue from a collaborative arrangement with ASC 606 revenue if the participant is not directly related to sales to third parties. The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those years. The Company does not expect a significant impact on its consolidated financial statements as a result of the adoption of this update.

The FASB issued ASU 2018-17, Consolidation (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities to improve general purpose financial reporting. The update clarifies that indirect interests held through related parties in common control arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. The amendments in the update are effective for fiscal years beginning after December 15, 2019 and interim periods within those fiscal years. The amendments are required to be applied retrospectively with a cumulative-effect adjustment to retained earnings. The Company does not expect a significant impact on its consolidated financial statements as a result of the adoption of this update.

The FASB issued ASU 2017-04, Business Combinations (Topic 350): Intangibles — Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment. The update is intended to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. The standard is effective for fiscal years and interim periods beginning after December 15, 2019. The Company does not expect a significant impact on its consolidated financial statements as a result of the adoption of this update.

The FASB issued ASU 2016-13, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments to provide financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. To achieve this objective, the amendments in this update replace the incurred loss impairment methodology in current U.S. GAAP with a methodology that reflects expected credit losses. The standard is effective for fiscal years and interim periods beginning after December 15, 2019. The FASB issued codification improvements to ASC Topic 326 in ASU 2018-19 to provide guidance on scoping of operating lease assets and further specific clarifications and corrections in ASU 2019-04 and ASU 2019-11. The FASB issued further updates to Topic 326 in ASU 2019-05 and ASU 2020-02 to provide transition relief that allows companies to irrevocably elect the fair value option for certain instruments held at amortized cost, and to provide certain updates to the SEC paragraphs of the topic. The Company is finalizing its analysis on the impact of adoption of this standard on its consolidated financial statements. The Company does not expect a significant impact on its consolidated financial statements as a result of the adoption of this update.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

3. Business acquisitions and development projects

(a) Acquisition of Enbridge Gas New Brunswick Limited Partnership & St. Lawrence Gas Company Inc.

The Company completed the acquisition of New Brunswick Gas on October 1, 2019, and St. Lawrence Gas Company, Inc. ("St. Lawrence Gas") on November 1, 2019. New Brunswick Gas is a regulated utility that provides natural gas. The purchase price is approximately $256,011 (C$339,036). St. Lawrence Gas is a regulated utility that provides natural gas in northern New York State. The total purchase price for the transaction is $61,820, and subject to certain closing adjustments.

The costs related to the acquisitions have been expensed through the consolidated statements of operations.

The following table summarizes the preliminary allocation of the assets acquired and liabilities assumed at the acquisition date:

	New Brunswick Gas			St. Lawrence Gas
Working capital	$	8,782		$	3,403
Property, plant and equipment	137,668			49,936
Goodwill	56,054			20,259
Regulatory assets	94,827			3,562
Deferred income tax assets, net	—			1,614
Other assets	125			6,418
Regulatory liabilities	(2,076		)	(10,412		)
Pension and post-employment benefits	—			(12,376		)
Deferred income tax liability, net	(38,053		)	—
Other liabilities	(1,316		)	(584		)
Total net assets acquired	$	256,011		$	61,820
Cash and cash equivalent	7,248			1,225
Total net assets acquired, net of cash and cash equivalent	$	248,763		$	60,595

The determination of the fair value of assets acquired and liabilities assumed is based upon management's preliminary estimates and certain assumptions. Due to the timing of the acquisitions, the Company has not finalized the fair value measurements. The Company will continue to review information and perform further analysis prior to finalizing the fair value of the consideration paid and the fair value of assets acquired and liabilities assumed.

Goodwill represents the excess of the purchase price over the aggregate fair value of net assets acquired. The contributing factors to the amount recorded as goodwill include future growth, potential synergies, and cost savings in the delivery of certain shared administrative and other services.

Property, plant and equipment, exclusive of computer software, are amortized in accordance with regulatory requirements over the estimated useful life of the assets using the straight-line method. The weighted average useful life of New Brunswick Gas and St. Lawrence Gas' assets is 47 years and 49 years, respectively.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

3. Business acquisitions and development projects (continued)

(b) Acquisition of Turquoise Solar Facility

Liberty Utilities (Turquoise Holdings) LLC (“Turquoise Holdings”) is owned by Liberty Utilities (Calpeco Electric) LLC ("Calpeco Electric System"). The 10 MWac solar generating facility is located in Washoe County, Nevada ("Turquoise Solar Facility"). On May 24, 2019, a tax equity agreement was executed. The Class A partnership units are owned by a third-party tax equity investor who funded $1,403 on the execution date and $2,000 on December 31, 2019. The final instalments are expected to be made in 2020. With its interest, the tax equity investor will receive the majority of the tax attributes associated with the Turquoise Solar Facility. Because the Class A tax equity investor has the right to withdraw from Turquoise Holdings and require the Company to redeem its remaining interests for cash, the Company accounts for this interest as “Redeemable non-controlling interest” outside of permanent equity on the consolidated balance sheets (note 17). Redemption is not considered probable as of December 31, 2019.

On December 31, 2019, as the Turquoise Solar Facility was placed in service, Turquoise Holdings obtained control of the property, plant and equipment for a total purchase price of $20,830.

(c) Agreement to acquire Mid-West Wind Development Project

The Empire District Electric Company ("Empire Electric System"), a wholly owned subsidiary of the Company, entered into purchase agreements to acquire, once completed, three wind farms generating up to 600 MW of wind energy located in Barton, Dade, Lawrence, and Jasper Counties in Missouri ("Missouri Wind Projects") and in Neosho County, Kansas ("Kansas Wind Project").  The agreements contain development milestones and termination provisions that primarily apply prior to the commencement of construction. Total costs are estimated at $1,100,000 and the acquisitions are anticipated to close following completion of the respective projects. These assets, net of third-party tax equity investment, are expected to be included in the rate base of the Empire Electric System.

In November 2019, Liberty Utilities Co, a wholly owned subsidiary of the Company, acquired an interest in the entities that own the two Missouri Wind Projects and, in partnership with a third-party developer, will continue development and construction of such projects until they are acquired by the Empire Electric System following completion. As part of the investment in the joint ventures, Liberty Utilities Co. entered into guarantee agreements for obligations under letters of credit, engineering and procurement contracts, and turbine supply agreements for the two projects. The Company accounts for its interest in these two projects using the equity method (note 8(d)).

In November 2019, a tax equity agreement was executed for the Kansas Wind Project. The Class A partnership units will be owned by two third-party tax equity investors who have committed to fund on a future date. With their interests, the tax equity investors will receive the majority of the tax attributes associated with the Kansas Wind Project. Initial tax equity funding is expected to be received in Q1 2021.

(d)Agreement to acquire New York American Water

On November 20, 2019, the Company entered into an agreement to acquire American Water's regulated operations in the State of New York ("New York American Water"). New York American Water is a regulated water and wastewater utility serving customers across seven counties in southeastern New York. The total purchase price for the transaction is approximately $608,000, subject to certain closing adjustments. The transaction is expected to close sometime in 2021 and remains subject to regulatory approval and other typical closing conditions.

(e) Agreement to acquire Bermuda Electric Light Company

On June 3, 2019, the Company entered into an agreement to acquire the Ascendant Group Limited ("Ascendant"), parent company of Bermuda Electric Light Company. Bermuda Electric Light Company is the sole electric utility providing regulated electrical generation, transmission and distribution services to Bermuda's residents and businesses. The total purchase price for the transaction is approximately $365,000. Closing of the transaction remains subject to shareholder and regulatory approvals and is expected in 2020.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

3. Business acquisitions and development projects (continued)

(f) Approval to acquire the Perris Water Distribution System

On August 10, 2017, the Company agreed to acquire two water distribution systems serving customers from the City of Perris, California. The anticipated purchase price of $11,500 is expected to be established as rate base during the regulatory approval process.  The City of Perris residents voted to approve the sale on November 7, 2017. The Regulated Services Group filed an application requesting approval for the acquisition of the assets of the water utilities with the California Public Utility Commission on May 8, 2018. Final approval is expected in 2020.

(g) Great Bay Solar Facilities

The Great Bay Solar I and II Facilities are 75 and 40 MWac solar powered generating facilities in Somerset County, Maryland. Commercial operations as defined by the power purchase agreement was reached for all sites at the Great Bay Solar I Facility by March 29, 2018. As of December 31, 2019, one site at the Great Gay Solar II Facility has been fully synchronized with the power grid, while the remaining site is expected to be placed in service in early 2020.

The Great Bay Solar I Facility is controlled by a subsidiary of APUC (Great Bay Holdings, LLC). The Class A partnership units are owned by a third-party tax equity investor who funded $42,750 in 2017 with the remaining amount of $15,250 received in 2018. Through its partnership interest, the tax equity investor will receive the majority of the tax attributes associated with the project. The Company accounts for this interest as "Non-controlling interest" on the consolidated balance sheets.

The Great Bay Solar II Facility is controlled by Great Bay Holdings, LLC. Liberty Utilities (America) Holdco, a subsidiary of APUC, is the tax equity investor for the facility and contributed initial funding of $11,281 in December 2019. The facility generated an investment tax credit of $8,526 during the year, which was recorded by the Company as a reduction to income tax expense in the consolidated statement of operations.

4. Accounts receivable

Accounts receivable as of December 31, 2019 include unbilled revenue of $80,295 (2018 - $79,742) from the Company’s regulated utilities. Accounts receivable as of December 31, 2019 are presented net of allowance for doubtful accounts of $4,939 (2018 - $5,281).

5. Property, plant and equipment

Property, plant and equipment consist of the following: 

2019
	Cost		Accumulated depreciation		Net book value
Generation	$	2,816,611	$	540,118	$	2,276,493
Distribution and transmission	4,988,297		598,449		4,389,848
Land	74,517		—		74,517
Equipment and other	94,583		47,541		47,042
Construction in progress
Generation	140,235		—		140,235
Distribution and transmission	303,529		—		303,529
	$	8,417,772	$	1,186,108	$	7,231,664

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

5. Property, plant and equipment (continued)

2018
	Cost		Accumulated depreciation		Net book value
Generation	$	2,470,279	$	450,230	$	2,020,049
Distribution and transmission	4,455,935		521,236		3,934,699
Land	73,773		—		73,773
Equipment and other	88,757		41,295		47,462
Construction in progress
Generation	104,996		—		104,996
Distribution and transmission	212,579		—		212,579
	$	7,406,319	$	1,012,761	$	6,393,558

Generation assets include cost of $109,653 (2018 - $104,107) and accumulated depreciation of $39,638 (2018 - $34,916) related to facilities under financing lease or owned by consolidated VIEs. Depreciation expense of facilities under finance leases was $1,615 (2018 - $1,987).

Distribution and transmission assets include the following:

• Cost of $1,450,946 (2018 - $1,383,960) and accumulated depreciation of $97,080 (2018 - $69,960) related to regulated generation and transmission assets.

• Cost of $514,709 (2018 - $503,664) and accumulated depreciation of $31,349 (2018 - $21,697) related to commonly owned facilities (note 1(k)). Total expenditures incurred on these facilities for the year ended December 31, 2019 were $69,210 (2018 - $75,427).

• Cost of $3,076 (2018 - $3,076) and accumulated depreciation of $1,003 (2018 - $669) related to assets under finance lease.

• Expansion costs of $1,000 on which the Company does not currently earn a return. 

For the year ended December 31, 2019, contributions received in aid of construction of $7,137 (2018 - $6,057) have been credited to the cost of the assets.

Interest and AFUDC capitalized to the cost of the assets in 2019 and 2018 are as follows:

	2019		2018
Interest capitalized on non-regulated property	$	4,538	$	2,268
AFUDC capitalized on regulated property:
Allowance for borrowed funds	2,745		1,684
Allowance for equity funds	4,896		2,728
Total	$	12,179	$	6,680

6. Intangible assets and goodwill

Intangible assets consist of the following:

2019	Cost		Accumulated amortization		Net book value
Power sales contracts	$	56,206	$	38,931	$	17,275
Customer relationships	26,797		10,104		16,693
Interconnection agreements	14,827		1,179		13,648
	$	97,830	$	50,214	$	47,616

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

6. Intangible assets and goodwill (continued)

2018	Cost			Accumulated amortization		Net book value
Power sales contracts	$	60,775		$	36,063	$	24,712
Customer relationships	26,795			9,476		17,319
Interconnection agreements	13,847		—	884		12,963
	$	101,417		$	46,423	$	54,994

Estimated amortization expense for intangible assets for the next year is $2,018, $2,190 in year two, $2,350 in year three, $1,910 in year four and $1,780 in year five.

All goodwill pertains to the Regulated Services Group.

Balance, December 31, 2018 and 2017	$	954,282
Business acquisitions (note 3(a))	76,313
Foreign exchange	1,101
Balance, December 31, 2019	$	1,031,696

7. Regulatory matters

The operating companies within the Regulated Services Group are subject to regulation by the public utility commissions of the states and provinces in which they operate. The respective public utility commissions have jurisdiction with respect to rate, service, accounting policies, issuance of securities, acquisitions and other matters. These utilities operate under cost-of-service regulation as administered by these authorities. The Company’s regulated utility operating companies are accounted for under the principles of ASC 980. Under ASC 980, regulatory assets and liabilities that would not be recorded under U.S. GAAP for non-regulated entities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate setting process.

During 2019, the Company completed the acquisition of New Brunswick Gas and St. Lawrence Gas, operating public utilities engaged in the distribution of natural gas in the Province of New Brunswick and the state of New York, respectively. New Brunswick Gas is subject to regulation by the New Brunswick Energy and Utilities Board. St. Lawrence Gas is subject to regulation by the New York Public Service Commission. In general, the commissions set rates at a level that allows the utilities to collect total revenues or revenue requirements equal to the cost of providing service, plus an appropriate return on invested capital.

At any given time, the Company can have several regulatory proceedings underway. The financial effects of these proceedings are reflected in the consolidated financial statements based on regulatory approval obtained to the extent that there is a financial impact during the applicable reporting period. The following regulatory proceedings were recently completed:

Utility	State	Regulatory proceeding type	Annual revenue increase	Effective date
Peach State Gas System	Georgia	Georgia Rate Adjustment mechanism	$2,367	February 1, 2019
New England Natural Gas System	Massachusetts	Gas System Enhancement Plan	$2,413	May 1, 2019
Empire Electric System	Kansas	General Rate Review	$2,449	August 1, 2019
Empire Electric System	Oklahoma	General Rate Review	$1,400	October 1, 2019
CalPeco Electric System	California	Catastrophic Events Memorandum Account	$3,525	January 1, 2020

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

7. Regulatory matters (continued)

Regulatory assets and liabilities consist of the following: 

	2019			2018
Regulatory assets
Environmental remediation (a)	$	82,300		$	82,295
Pension and post-employment benefits (b)	143,292			135,580
Income taxes (c)	71,506			34,822
Debt premium (d)	42,150			48,847
Fuel and commodity cost adjustments (e)	23,433			26,310
Rate adjustment mechanism (f)	69,121			37,202
Clean Energy and other customer programs (g)	26,369			24,095
Deferred capitalized costs (h)	38,833			13,986
Asset retirement obligation (i)	23,841			21,048
Long-term maintenance contract (j)	13,264			8,283
Rate review costs (k)	6,695			6,164
Other	19,083			21,463
Total regulatory assets	$	559,887		$	460,095
Less: current regulatory assets	(50,213		)	(59,037		)
Non-current regulatory assets	$	509,674		$	401,058
Regulatory liabilities
Income taxes (c)	$	321,960		$	323,384
Cost of removal (l)	196,423			193,564
Rate base offset (m)	8,719			10,900
Fuel and commodity costs adjustments (e)	16,645			21,352
Rate adjustment mechanism (f)	10,446			4,210
Deferred capitalized costs - fuel related (h)	7,097			7,258
Pension and post-employment benefits (b)	22,256			11,791
Other	14,516			15,754
Total regulatory liabilities	$	598,062		$	588,213
Less: current regulatory liabilities	(41,683		)	(39,005		)
Non-current regulatory liabilities	$	556,379		$	549,208

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

7. Regulatory matters (continued)

(a) Environmental remediation

Actual expenditures incurred for the clean-up of certain former gas manufacturing facilities (note 12(b)) are recovered through rates over a period of 7 years and are subject to an annual cap.

(b) Pension and post-employment benefits

As part of certain business acquisitions, the regulators authorized a regulatory asset or liability being set up for the amounts of pension and post-employment benefits that have not yet been recognized in net periodic cost and were presented as AOCI prior to the acquisition. The balance is recovered through rates over the future service years of the employees at the time the regulatory asset was set up (an average of 10 years) or consistent with the treatment of OCI under ASC 712, Compensation Non-retirement Post-employment Benefits and ASC 715, Compensation Retirement Benefits before the transfer to regulatory asset occurred. The annual movements in AOCI for Empire Electric and Gas systems' and St. Lawrence Gas system's pension and OPEB plans (note 10(a)) are also reclassified to regulatory accounts since it is probable the unfunded amount of these plans will be afforded rate recovery. Finally, the regulators have also approved tracking accounts for a number of the utilities. The amounts recorded in these accounts occur when actual expenses differ from those adopted and recovery or refunds are expected to occur in future periods.

(c) Income taxes

The income taxes regulatory assets and liabilities represent income taxes recoverable through future revenues required to fund flow-through deferred income tax liabilities and amounts owed to customers for deferred taxes collected at a higher rate than the current statutory rates.

On June 1, 2018, the State of Missouri enacted legislation that, effective for tax years beginning on or after January 1, 2020, reduces the corporate income tax rate from 6.25% to 4%, among other legislative changes. A reduction of regulatory asset and an increase to regulatory liability were recorded for excess deferred taxes probable of being refunded to customers of $15,586.

(d) Debt premium

Debt premium on acquired debt is recovered as a component of the weighted average cost of debt.

(e) Fuel and commodity cost adjustments

The revenue from the utilities includes a component that is designed to recover the cost of electricity and natural gas through rates charged to customers. To the extent actual costs of power or natural gas purchased differ from power or natural gas costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability on the consolidated balance sheets. These differences are reflected in adjustments to rates and recorded as an adjustment to cost of electricity and natural gas in future periods, subject to regulatory review. Derivatives are often utilized to manage the price risk associated with natural gas purchasing activities in accordance with the expectations of state regulators. The gains and losses associated with these derivatives (note 24(b)(i)) are recoverable through the commodity costs adjustment.

(f) Rate adjustment mechanism

Revenue for Calpeco Electric System, Park Water System, Peach State Gas System, New England Gas System, Midstates Natural Gas system, and EnergyNorth Natural Gas System is subject to a revenue decoupling mechanism approved by their respective regulator, which requires charging approved annual delivery revenue on a systematic basis over the fiscal year. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers. In addition, retroactive rate adjustments for services rendered but to be collected over a period not exceeding 24 months are accrued upon approval of the Final Order. The difference between New Brunswick Gas' regulated revenues and its regulated cost of service in past years is also recorded as a regulatory asset and is recovered on a straight-line basis over the next 25 years.

(g) Clean Energy and other customer programs

The regulatory asset for Clean Energy and customer programs includes initiatives related to solar rebate applications processed and resulting rebate-related costs. The amount also includes other energy efficiency programs.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

7. Regulatory matters (continued)

(h) Deferred capitalized costs

Deferred capitalized costs reflect deferred construction costs and fuel-related costs of specific generating facilities of the Empire Electric System. These amounts are being recovered over the life of the plants. The amount also includes capitalized operating and maintenance costs of New Brunswick Gas, and these amounts are being recovered at a rate of 2.43% annually over the next 29 years.

(i) Asset retirement obligation

Asset retirement obligations are recorded for legally required removal costs of property plant and equipment. The costs of retirement of assets as well as the on-going liability accretion and asset depreciation expense are expected to be recovered through rates.

(j) Long-term maintenance contract

To the extent actual costs of long-term maintenance incurred for one of Empire Electric System's power plants differ from the costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability on the consolidated balance sheets.

(k) Rate review costs

The costs to file, prosecute and defend rate review applications are referred to as rate review costs. These costs are capitalized and amortized over the period of rate recovery granted by the regulator.

(l) Cost of removal

Rates charged to customers cover for costs that are expected to be incurred in the future to retire the utility plant. A regulatory liability tracks the amounts that have been collected from customers net of costs incurred to date.

(m) Rate base offset

The regulators imposed a rate base offset that will reduce the revenue requirement at future rate proceedings. The rate base offset declines on a straight-line basis over a period of 10-16 years.

As recovery of regulatory assets is subject to regulatory approval, if there were any changes in regulatory positions that indicate recovery is not probable, the related cost would be charged to earnings in the period of such determination. The Company generally earns carrying charges on the regulatory balances related to commodity cost adjustment, retroactive rate adjustments and rate review costs.

8. Long-term investments

Long-term investments consist of the following:

	2019		2018
Long-term investments carried at fair value
Atlantica (a)	$	1,178,581	$	814,530
AYES Canada (b)	88,494		—
San Antonio Water System (c)	27,072		—
	$	1,294,147	$	814,530
Other long-term investments
Equity-method investees (d)	$	83,770	$	29,588
Development loans receivable from equity-method investees (e)	36,204		101,417
Other	1,994		4,773
Total other long-term investments	$	121,968	$	135,778
Less: current portion	—		(1,407		)
	$	121,968	$	134,371

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

8. Long-term investments (continued)

Income (loss) from long-term investments from the years ended December 31, 2019 and 2018 is as follows:

	Year ended December 31
	2019			2018
Fair value gain (loss) on investments carried at fair value
Atlantica	$	290,740		$	(137,957	)
AYES Canada	(6,649		)	—
San Antonio Water System	(6,007		)	—
	$	278,084		$	(137,957	)
Dividend and interest income from investments carried at fair value
Atlantica	$	69,307		$	39,263
AYES Canada	25,572			—
San Antonio Water System	6,007			—
	$	100,886		$	39,263
Other long-term investments
Equity method loss	(9,108		)	(3,082		)
Interest and other income	29,230			16,958
	$	399,092		$	(84,818	)

(a) Investment in Atlantica

AAGES (AY Holdings) B.V. (“AY Holdings”), an entity controlled and consolidated by APUC, has a share ownership in Atlantica Yield plc ("Atlantica") of approximately 44.2% (December 31, 2018 - 41.5%). APUC has the flexibility, subject to certain conditions, to increase its ownership of Atlantica up to 48.5%. In 2019, the Company purchased 1,384,402 treasury shares of Atlantica for cash consideration of $30,000. In addition, 2,000,000 shares were received pursuant to a prepayment of $53,750. Subsequent to year-end, the prepayment purchase agreement settled with no material cash difference. During 2018, APUC purchased from Abengoa S.A. ("Abengoa") a 41.5% equity interest in Atlantica through two transactions for a total purchase price of $952,567, with a holdback of $40,000 of which $29,100 was settled in 2019 with the balance payable at a later date, subject to certain conditions. The Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in Atlantica, with changes in fair value reflected in the consolidated statements of operations.

On November 28, 2018, Abengoa-Algonquin Global Energy Solutions B.V. (“AAGES B.V.”), an equity investee of the Company, obtained a three-year secured credit facility in the amount of $306,500 and subscribed to a $305,000 preference share ownership interest in AY Holdings. The subscription proceeds were distributed by AY Holdings to the Company and used by the Company to repay the $305,000 of temporary financing used for the 2018 investment in Atlantica. The AAGES B.V. secured credit facility is collateralized through a pledge of the Atlantica shares held by AY Holdings. A collateral shortfall would occur if the net obligation as defined in the agreement would equal or exceed 50% of the market value of the Atlantica shares in which case the lenders would have the right to sell Atlantica stock to eliminate the collateral shortfall. The AAGES B.V. secured credit facility is repayable on demand if Atlantica ceases to be a public company. APUC reflects the preference share ownership issued by AY Holdings as redeemable non-controlling interest held by related party (note 17).

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

8. Long-term investments (continued)

(b) Investment in AYES Canada

On May 24, 2019, APUC and Atlantica formed Atlantica Yield Energy Solutions Canada Inc. ("AYES Canada"), a vehicle to channel co-investment opportunities in which Atlantica holds the majority of voting rights. The first investment was Windlectric Inc. ("Windlectric"). APUC invested $91,918 (C$123,603) and Atlantica invested $4,834 (C$6,500) in AYES Canada, which in turn invested those funds in Amherst Island Partnership ("AIP"), the holding company of Windlectric.

APUC continues to control and consolidate AIP and Windlectric. The investment of $96,752 (C$130,103) by AYES Canada in AIP is presented as a non-controlling interest held by a related party (notes 16 and 17). The AIP partnership agreement has liquidation rights and priorities to each equity holder that are different from the underlying percentage ownership interests. As such, the share of earnings attributable to the non-controlling interest holder is calculated using the HLBV method of accounting. The Company incurred non-controlling interest calculated using the HLBV method of accounting of $nil and recorded distributions of $26,465 (C$34,373) during the year.

AYES Canada is considered to be a VIE based on the disproportionate voting and economic interests of the shareholders. Atlantica is considered to be the primary beneficiary of AYES Canada. Accordingly, APUC's investment in AYES Canada is considered an equity method investment. Under the AYES Canada shareholders agreement, starting in May 2020, APUC has the option to exchange approximately 3,500,000 shares of AYES Canada into ordinary shares of Atlantica on a one-for-one basis, subject to certain conditions. Consistent with the treatment of the Atlantica shares, the Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in AYES Canada, with changes in fair value reflected in the consolidated statements of operations. A level 3 discounted cash flow approach combined with the binomial tree approach were used to estimate the fair value of the investment. For the year, APUC recorded dividend income of $25,572 and a fair value loss of $6,649 on its investment in AYES Canada.

As at December 31, 2019, the Company's maximum exposure to loss is $88,494, which represents the fair value of the investment.

(c) San Antonio Water System

On May 1, 2019, APUC invested $17,000 by way of a secured loan into AWUSA VR Holding LLC ("AWUSA"), a wholly owned subsidiary of Abengoa. An additional amount of $5,000 plus interest is payable at a later date, subject to certain conditions. The loan is secured by AWUSA's investment in the Vista Ridge water pipeline project. The Vista Ridge water pipeline project is a 140 mile water pipeline from Burleson County, Texas, to San Antonio, Texas. Since APUC has the power to direct the activities of AWUSA and benefits from the economics of this entity, the Company consolidates AWUSA. AWUSA's 20% interest in Vista Ridge is accounted for using the equity method.

On December 30, 2019, the Company and a third-party developer each contributed C$1,500 to the capital of a new joint venture, created for the purpose of developing infrastructure investment opportunities. The Company sold its investment in AWUSA to the joint venture in exchange for a loan receivable of $30,293. A note payable to AWUSA of $13,293 was recognized by the Company upon deconsolidation of AWUSA. The Company holds an option exercisable at any time to acquire the remaining interest at a pre-agreed price. The sale was accounted for in accordance with ASC 860, Transfers and Servicing and no gain or loss was recognized.

The joint venture is considered to be a VIE due to insufficient equity at risk to finance its operations with additional subordinated financial support. Neither APUC nor the third-party developer is considered to be the primary beneficiary since each party holds 50% voting and economic interests. Accordingly, APUC's investment in the joint venture is considered an equity method investment. The Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment, with changes in fair value reflected in the consolidated statements of operations. A level 3 discounted cash flow approach was used to estimate the fair value of the investment. For the year, APUC recorded interest income of $6,007 and a fair value loss of $6,007 on its investment in the joint venture.

As of December 31, 2019, the Company’s maximum exposure to loss is $27,072, which represents the fair value of the investment.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

8. Long-term investments (continued)

(d)Equity-method investees

The Company has non-controlling interests in various partnerships and joint ventures with a total carrying value of $83,770 (2018 - $29,588) including investments in VIEs of $59,091 (2018 - $9,581).

The Company owns a 75% interest ownership in Red Lily I, an operating 26.4 MW wind facility. APUC exercises significant influence over operating and financial policies of the Red Lily I Wind Facility. Due to certain participating rights being held by the minority investor, the decisions that which most significantly impact the economic performance of the Red Lily I Wind Facility require unanimous consent. As such, the Company accounts for the partnership using the equity method.

The Company also has 50% interests in a number of wind and solar power electric development projects and infrastructure development projects. The Company holds an option to acquire the remaining 50% interest in most development projects at a pre-agreed price. Some of the development projects include AAGES, the international development platform established with Abengoa in 2018; Sugar Creek, a 202 MW wind power development project in Logan County, Illinois; Maverick, a 490 MW wind project located in Concho County, Texas; Altavista, a 80 MW solar power project located in Campbell County, Virginia, and two approximately 150 MW wind projects in southwestern Missouri.

On April 16, 2019, the Company acquired the remaining 50% interest in Windlectric which owns a 75 MW wind generating facility ("Amherst Island Wind Facility") in the Province of Ontario for $6,362. Prior to this acquisition, APUC's 50% interest in Windlectric was recorded as an equity investment. As a result of obtaining control of the facility, the transaction was treated as an asset acquisition. APUC recorded the fair value on that date for property, plant and equipment acquired of $311,175, deferred tax asset of $3,015, working capital of $14,280 and liabilities of $1,600 for asset retirement obligation assumed; and, derecognized the existing development loan between the two parties of $316,786 (note 8(e)).

Summarized combined information for APUC's investments in significant partnerships and joint ventures is as follows:

	2019		2018
Total assets	$	833,791	$	360,372
Total liabilities	697,751		335,331
Net assets	136,040		25,041
APUC's ownership interest in the entities	63,624		18,042
Difference between investment carrying amount and underlying equity in net assets(a)	18,487		11,048
APUC's investment carrying amount for the entities	$	82,111	$	29,090

^(a) The difference between the investment carrying amount and the underlying equity in net assets relates primarily to interest capitalized while the projects are under construction, the fair value of guarantees provided by the Company in regards to the investments and transaction costs.

Except for AAGES BV, the development projects are considered VIEs due to the level of equity at risk and the disproportionate voting and economic interests of the shareholders. The Company has committed loan and credit support facilities with some of its equity investees. During construction, the Company is obligated to provide cash advances (note 8(e)) and credit support in amounts necessary for the continued development and construction of the equity investees' projects. As of December 31, 2019, the Company had issued letters of credit and guarantees of obligations under a security of performance for a development opportunity; wind turbine or solar panel supply agreements; engineering, procurement, and construction agreements; purchase and sale agreements; interconnection agreements; energy purchase agreements; renewable energy credit agreements; equity capital contribution agreements; landowner agreements; and bridge loan agreements. The fair value of the support provided recorded as at December 31, 2019 amounts to $9,493 (2018 - $1,682). The Company is not considered the primary beneficiary of these entities as the partners have joint control and all decisions must be unanimous. Therefore, the Company accounts for its interest in these VIEs using the equity method.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

8. Long-term investments (continued)

(d)Equity-method investees (continued)

Summarized combined information for APUC's VIEs is as follows:

	2019		2018
APUC's maximum exposure in regards to VIEs
Carrying amount	$	59,091	$	9,581
Development loans receivable (e)	35,000		101,417
Commitments on behalf of VIEs	1,364,871		120,669
	$	1,458,962	$	231,667

The majority of the amounts committed on behalf of VIEs in the above relate to wind turbine or solar panel supply agreements as well as engineering, procurement, and construction agreements.

(e) Development loans receivable from equity investees

The Company has committed loan and credit support facilities with some of its equity investees. During construction, the Company is obligated to provide cash advances and credit support (in the form of letters of credit, escrowed cash, guarantees or indemnities) in amounts necessary for the continued development and construction of the equity investees' projects. The loans bear interest at a weighted average annual rate of 7.66% (2018 - 9.90%) on outstanding principal and generally mature on the commercial operation date.

9. Long-term debt

Long-term debt consists of the following:

Borrowing type	Weighted average coupon		Maturity	Par value		2019			2018
Senior unsecured revolving credit facilities (a)	—		2023-2024	N/A		$	141,577		$	97,000
Senior unsecured bank credit facilities (b)	—		2020	N/A		75,000			321,807
Commercial paper (c)	—		2020	N/A		218,000			6,000
U.S. dollar borrowings
Senior unsecured notes	4.09	%	2020-2047	$	1,225,000	1,219,579			1,218,680
Senior unsecured utility notes	6.00	%	2020-2035	$	217,000	233,686			240,161
Senior secured utility bonds	4.75	%	2020-2044	$	662,500	672,337			676,697
Canadian dollar borrowings
Senior unsecured notes (d)	4.48	%	2021-2029	C$	950,669	728,679			474,764
Senior secured project notes	10.22	%	2020-2027	C$	28,503	21,961			22,915
						$	3,310,819		$	3,058,024
Subordinated U.S. dollar borrowings
Subordinated unsecured notes (e)	6.50	%	2078-2079	$	637,500	621,049			278,771
						$	3,931,868		$	3,336,795
Less: current portion						(225,013		)	(13,048		)
						$	3,706,855		$	3,323,747

Short-term obligations of $377,015 that are expected to be refinanced using the long-term credit facilities are presented as long-term debt.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

9. Long-term debt (continued)

Long-term debt issued at a subsidiary level (project notes or utility bonds) relating to a specific operating facility is generally collateralized by the respective facility with no other recourse to the Company. Long-term debt issued at a subsidiary level whether or not collateralized generally has certain financial covenants, which must be maintained on a quarterly basis. Non-compliance with the covenants could restrict cash distributions/dividends to the Company from the specific facilities.

Recent financing activities:

(a) Senior unsecured revolving credit facilities

On October 24, 2019, the Company entered into a new $75,000 uncommitted bilateral letter of credit facility. The facility matures on October 24, 2020.

On July 12, 2019, the Company entered into a new $500,000 senior unsecured revolving bank credit facility that matures July 12, 2024. The interest rate is equal to the bankers' acceptance or LIBOR plus a credit spread. The existing C$165,000 credit facility was canceled.

On February 23, 2018, the Regulated Services Group increased commitments under its credit facility to $500,000 and extended the maturity to February 23, 2023. Concurrent with this amendment, the Regulated Services Group closed Empire's credit facility. The Regulated Services Group's credit facility will now be used as a backstop for Empire's commercial paper program and as a source of liquidity for Empire.

During 2018, the Renewable Energy Group extended the maturity of its senior unsecured revolving bank credit facility from October 6, 2022 to October 6, 2023. On February 16, 2018, the Renewable Energy Group increased availability under its revolving letter of credit facility to $200,000 and extended the maturity to January 31, 2021. Subsequent to year-end, on February 24, 2020, the Renewable Energy Group increased its uncommitted Renewable Energy LC Facility to $350,000 and extended the maturity to June 30, 2021.

(b) Senior unsecured bank credit facilities

On June 27, 2019, the Regulated Services Group extended the maturity of its $135,000 term loan to July 6, 2020. During the year, the Company repaid $60,000 of the facility.

On March 7, 2018, the Company drew $600,000 under a new term credit facility. The balance was repaid in 2018 except for a balance of $186,807, which was repaid on May 23, 2019.

(c) Commercial paper

On July 1, 2019, the Regulated Services Group established a new $500,000 commercial paper program. The amounts drawn at any time under this program may have maturities up to 270 days from the date of issuance and are expected to be replaced with new commercial paper upon maturity. This program is backstopped by the Regulated Services Group's bank credit facility.

(d) Canadian dollar senior unsecured notes

Subsequent to year-end, on February 14, 2020, the Regulated Services Group issued C$200,000 senior unsecured debentures bearing interest at 3.315% with a maturity date of February 14, 2050. The debentures are redeemable at the option of the Company at any time at a predetermined price.

On January 29, 2019, the Renewable Energy Group issued C$300,000 senior unsecured notes bearing interest at 4.60% with a maturity date of January 29, 2029. The notes were sold at a price of C$99.952 per C$100.00 principal amount. Concurrent with the financing, the Renewable Energy Group unwound and settled the related forward-starting interest rate swap on a notional bond of C$135,000 (note 24(b)(ii)).

On July 25, 2018, the Company repaid, upon its maturity, a C$135,000 unsecured note.

(e)Subordinated unsecured notes

On May 23, 2019, the Company issued $350,000 unsecured, 6.20% fixed-to-floating subordinated notes ("subordinated notes") maturing on July 1, 2079. Concurrent with the offering, the Company entered into a cross-currency swap to convert the U.S. dollar denominated coupon and principal payments from the offering into Canadian dollars.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

9. Long-term debt (continued)

(e)Subordinated unsecured notes (continued)

Beginning on July 1, 2024, and on every quarter thereafter that the subordinated notes are outstanding (the "interest reset date") until July 1, 2029, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 4.01%, payable in arrears. In September 2019, the Company entered into forward-starting interest rate swaps to convert its variable interest rate to fixed for the period of July 1, 2024 to July 1, 2029 (note 24(b)(ii)). Beginning on July 1, 2029, and on every interest reset date until July 1, 2049, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 4.26%, payable in arrears. Beginning on July 1, 2049, and on every interest reset date until July 1, 2079, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 5.01%, payable in arrears.

The Company may elect, at its sole option, to defer the interest payable on the subordinated notes on one or more occasions for up to five consecutive years. Deferred interest will accrue, compounding on each subsequent interest payment date, until paid. Additionally, on or after July 1, 2024, the Company may, at its option, redeem the subordinated notes, at a redemption price equal to 100% of the principal amount, together with accrued and unpaid interest.

On October 17, 2018, the Company completed the issuance of $287,500 unsecured, 6.875% fixed-to-floating subordinated notes (“subordinated notes”) maturing on October 17, 2078. Beginning on October 17, 2023, and on every quarter thereafter that the subordinated notes are outstanding (the "interest reset date") until October 17, 2028, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 3.677%, payable in arrears. Beginning on October 17, 2028, and on every interest reset date until October 17, 2043, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 3.927%, payable in arrears. Beginning on October 17, 2043, and on every interest reset date until October 17, 2078, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 4.677%, payable in arrears.

The Company may elect, at its sole option, to defer the interest payable on the subordinated notes on one or more occasions for up to five consecutive years. Deferred interest will accrue, compounding on each subsequent interest payment date, until paid. Additionally, on or after October 17, 2023, the Company may, at its option, redeem the subordinated notes, at a redemption price equal to 100% of the principal amount, together with accrued and unpaid interest.

As of December 31, 2019, the Company had accrued $44,229 in interest expense (2018 - $33,822). Interest expense on the long-term debt, net of capitalized interest, in 2019 was $175,664 (2018 - $146,310).

Principal payments due in the next five years and thereafter are as follows: 

2020		2021		2022		2023		2024		Thereafter		Total
$	602,028	$	117,513	$	351,227	$	97,478	$	215,743	$	2,547,916	$	3,931,905

10. Pension and other post-employment benefits

The Company provides defined contribution pension plans to substantially all of its employees. The Company’s contributions for 2019 were $8,798 (2018 - $8,446).

In conjunction with the utility acquisitions, the Company assumes defined benefit pension, supplemental executive retirement plans and OPEB plans for qualifying employees in the related acquired businesses. The legacy plans of the electricity and gas utilities are non-contributory defined pension plans covering substantially all employees of the acquired businesses. Benefits are based on each employee’s years of service and compensation. The Company also provides a defined benefit cash balance pension plan covering substantially all its new employees and current employees at its water utilities, under which employees are credited with a percentage of base pay plus a prescribed interest rate credit. The OPEB plans provide health care and life insurance coverage to eligible retired employees. Eligibility is based on age and length of service requirements and, in most cases, retirees must cover a portion of the cost of their coverage.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

10. Pension and other post-employment benefits (continued)

(a) Net pension and OPEB obligation

The following table sets forth the projected benefit obligations, fair value of plan assets, and funded status of the Company’s plans as of December 31:

	Pension benefits						OPEB
	2019			2018			2019			2018
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	484,707		$	531,694		$	168,325		$	176,975
Projected benefit obligation assumed from business combination	20,196			—			11,646			—
Modifications to plans	(7,705		)	—			—			—
Service cost	12,351			15,481			4,587			5,791
Interest cost	20,222			19,077			7,575			6,727
Actuarial (gain) loss	65,443			(29,986		)	33,605			(14,800		)
Contributions from retirees	—			—			1,913			1,878
Gain on curtailment	—			(1,875		)	—			—
Medicare Part D	—			—			414			42
Benefits paid	(30,244		)	(49,684		)	(8,848		)	(8,288		)
Projected benefit obligation, end of year	$	564,970		$	484,707		$	219,217		$	168,325
Change in plan assets
Fair value of plan assets, beginning of year	339,099			403,945			115,542			130,487
Plan assets acquired in business combination	8,004			—			15,688			—
Actual return on plan assets	68,025			(36,987		)	25,464			(10,603		)
Employer contributions	22,190			21,825			8,628			2,026
Medicare Part D subsidy receipts	—			—			414			42
Benefits paid	(30,244		)	(49,684		)	(6,863		)	(6,410		)
Fair value of plan assets, end of year	$	407,074		$	339,099		$	158,873		$	115,542
Unfunded status	$	(157,896	)	$	(145,608	)	$	(60,344	)	$	(52,783	)
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets (note 11)	—			—			8,437			3,161
Current liabilities	(1,415		)	(873		)	(1,168		)	(850		)
Non-current liabilities	(156,481		)	(144,735		)	(67,613		)	(55,094		)
Net amount recognized	$	(157,896	)	$	(145,608	)	$	(60,344	)	$	(52,783	)

The accumulated benefit obligation for the pension plans was $526,517 and $439,458 as of December 31, 2019 and 2018, respectively.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

10. Pension and other post-employment benefits (continued)

(a) Net pension and OPEB obligation (continued)

Information for pension and OPEB plans with an accumulated benefit obligation in excess of plan assets:

	Pension				OPEB
	2019		2018		2019		2018
Accumulated benefit obligation	$	504,403	$	439,458	$	202,422	$	163,375
Fair value of plan assets	$	407,074	$	339,099	$	133,711	$	107,430

Information for pension and OPEB plans with a projected benefit obligation in excess of plan assets:

	Pension				OPEB
	2019		2018		2019		2018
Projected benefit obligation	$	564,971	$	476,791	$	202,422	$	163,375
Fair value of plan assets	$	407,074	$	339,099	$	133,711	$	107,430

In 2019, the Company merged the Empire pension plan into the Company's cash balance plan and defined benefit plans, and changed benefits for certain Empire participants. The total impact of these plan amendments resulted in a decrease to the projected benefit obligation of $7,798, which is recorded as a prior service credit in OCI.

In 2018, the Company permanently froze the accrual of benefits for participants in the Park Water System's existing pension plan. Subsequent to the effective date, these employees began accruing benefits under the Company’s cash balance plan. The plan amendments resulted in a decrease to the projected benefit obligation of $1,875, which is recorded as a prior service credit in OCI.

(b) Pension and post-employment actuarial changes

Change in AOCI (before tax)	Pension						OPEB
	Actuarial losses (gains)			Past service gains			Actuarial losses (gains)			Past service gains
Balance, January 1, 2018	$	25,128		$	(4,995	)	$	(3,182	)	$	(470	)
Additions to AOCI	34,916			(1,875		)	3,254			—
Amortization in current period	(1,074		)	649			272			262
Loss on plan settlements	$	(2,547	)	$	—		$	—		$	—
Reclassification to regulatory accounts (note 7(b))	(22,166		)	—			(14,232		)	—
Balance, December 31, 2018	$	34,257		$	(6,221	)	$	(13,888	)	$	(208	)
AOCI from business acquisition	—			(285		)	—			—
Additions to AOCI	17,905			(7,705		)	14,871			—
Amortization in current period	(3,530		)	784			409			208
Reclassification to regulatory accounts (note 7(b))	(10,122		)	7,247			(10,538		)	—
Balance, December 31, 2019	$	38,510		$	(6,180	)	$	(9,146	)	$	—

The movements in AOCI for Empire's and St. Lawrence Gas' pension and OPEB plans are reclassified to regulatory accounts since it is probable the unfunded amount of these plans will be afforded rate recovery (note 7(b)).

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

10. Pension and other post-employment benefits (continued)

(c) Assumptions

Weighted average assumptions used to determine net benefit obligation for 2019 and 2018 were as follows: 

	Pension benefits				OPEB
	2019		2018		2019		2018
Discount rate	3.19	%	4.19	%	3.29	%	4.26	%
Interest crediting rate (for cash balance plans)	4.48	%	4.43	%	N/A		N/A
Rate of compensation increase	4.00	%	4.00	%	N/A		N/A
Health care cost trend rate
Before age 65					6.125	%	6.25	%
Age 65 and after					6.125	%	6.25	%
Assumed ultimate medical inflation rate					4.75	%	4.75	%
Year in which ultimate rate is reached					2031		2031

The mortality assumption for December 31, 2019 was updated to Pri-2012 mortality table and to the projected generationally scale MP-2019, adjusted to reflect the ultimate improvement rates in the 2019 Social Security Administration intermediate assumptions.

In selecting an assumed discount rate, the Company uses a modeling process that involves selecting a portfolio of high-quality corporate debt issuances (AA- or better) whose cash flows (via coupons or maturities) match the timing and amount of the Company’s expected future benefit payments. The Company considers the results of this modeling process, as well as overall rates of return on high-quality corporate bonds and changes in such rates over time, to determine its assumed discount rate.

The rate of return assumptions are based on projected long-term market returns for the various asset classes in which the plans are invested, weighted by the target asset allocations.

Weighted average assumptions used to determine net benefit cost for 2019 and 2018 were as follows: 

	Pension benefits				OPEB
	2019		2018		2019		2018
Discount rate	4.19	%	3.57	%	4.25	%	3.60	%
Expected return on assets	6.87	%	7.13	%	6.51	%	6.52	%
Rate of compensation increase	4.00	%	3.00	%	N/A		N/A
Health care cost trend rate
Before Age 65					6.25	%	6.25	%
Age 65 and after					6.25	%	6.25	%
Assumed ultimate medical inflation rate					4.75	%	4.75	%
Year in which ultimate rate is reached					2031		2024

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

10. Pension and other post-employment benefits (continued)

(d) Benefit costs

The following table lists the components of net benefit cost for the pension and OPEB plans. Service cost is recorded as part of operating expenses and non-service costs are recorded as part of other net losses in the consolidated statements of operations. The employee benefit costs related to businesses acquired are recorded in the consolidated statements of operations from the date of acquisition.

	Pension benefits						OPEB
	2019			2018			2019			2018
Service cost	$	12,351		$	15,481		$	4,587		$	5,791
Non-service costs
Interest cost	20,222			19,077			7,575			6,727
Expected return on plan assets	(20,485		)	(27,820		)	(6,725		)	(7,451		)
Amortization of net actuarial loss (gain)	3,530			1,074			(409		)	(272		)
Amortization of prior service credits	(784		)	(649		)	(208		)	(262		)
Amortization of regulatory assets/liabilities	12,082			10,584			2,534			3,982
	$	14,565		$	2,266		$	2,767		$	2,724
Net benefit cost	$	26,916		$	17,747		$	7,354		$	8,515

(e) Plan assets

The Company’s investment strategy for its pension and post-employment plan assets is to maintain a diversified portfolio of assets with the primary goal of meeting long-term cash requirements as they become due.

The Company’s target asset allocation is as follows:

Asset class	Target (%)		Range (%)
Equity securities	68	%	50% - 78%
Debt securities	32	%	22% - 50%
	100	%

The fair values of investments as of December 31, 2019, by asset category, are as follows:

Asset class	Level 1		Percentage
Equity securities	$	414,985	73	%
Debt securities	141,229		25	%
Other	9,732		2	%
	$	565,946	100	%

As of December 31, 2019, the funds do not hold any material investments in APUC. 

(f) Cash flows

The Company expects to contribute $24,140 to its pension plans and $5,736 to its post-employment benefit plans in 2020.

The expected benefit payments over the next ten years are as follows: 

	2020		2021		2022		2023		2024		2025—2029
Pension plan	$	34,461	$	34,385	$	35,383	$	36,897	$	37,848	$	192,648
OPEB	7,469		7,867		8,379		8,903		9,361		52,864

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

11.Other assets

Other assets consist of the following:

	2019			2018
Restricted cash	$	24,787		$	18,954
OPEB plan assets (note 10(a))	8,437			3,161
Atlantica related prepaid amount (note 8(a))	8,844			—
Long-term deposits	6,319			1,207
Income taxes recoverable	4,416			1,961
Deferred financing costs	5,477			4,449
Other	8,192			4,967
	$	66,472		$	34,699
Less: current portion	(7,764		)	(6,115		)
	$	58,708		$	28,584

 

12.Other long-term liabilities

Other long-term liabilities consist of the following: 

	2019			2018
Advances in aid of construction (a)	$	60,828		$	63,703
Environmental remediation obligation (b)	58,061			55,621
Asset retirement obligations (c)	53,879			43,291
Customer deposits (d)	31,946			29,974
Unamortized investment tax credits (e)	18,234			17,491
Deferred credits (f)	18,952			42,711
Preferred shares, Series C (g)	13,793			13,418
Lease liabilities (note 1(q))	9,695			3,436
Other (h)	35,952			28,360
	$	301,340		$	298,005
Less: current portion	(57,939		)	(42,337		)
	$	243,401		$	255,668

(a) Advances in aid of construction

The Company’s regulated utilities have various agreements with real estate development companies (the “developers”) conducting business within the Company’s utility service territories, whereby funds are advanced to the Company by the developers to assist with funding some or all of the costs of the development.

In many instances, developer advances can be subject to refund, but the refund is non-interest bearing. Refunds of developer advances are made over periods generally ranging from 5 to 40 years. Advances not refunded within the prescribed period are usually not required to be repaid. After the prescribed period has lapsed, any remaining unpaid balance is transferred to contributions in aid of construction and recorded as an offsetting amount to the cost of property, plant and equipment. In 2019, $5,465 (2018 - $3,687) was transferred from advances in aid of construction to contributions in aid of construction.

(b) Environmental remediation obligation

A number of the Company's regulated utilities were named as potentially responsible parties for remediation of several sites at which hazardous waste is alleged to have been disposed as a result of historical operations of Manufactured Gas Plants (“MGP”) and related facilities. The Company is currently investigating and remediating, as necessary, those MGP and related sites in accordance with plans submitted to the agency with authority for each of the respective sites.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

12.Other long-term liabilities (continued)

(b) Environmental remediation obligation (continued)

The Company estimates the remaining undiscounted, unescalated cost of these MGP-related environmental cleanup activities will be $58,484 (2018 - $59,181), which at discount rates ranging from 1.7% to 2.1% represents the recorded accrual of $58,061 as of December 31, 2019 (2018 - $55,621). Approximately $36,382 is expected to be incurred over the next four years, with the balance of cash flows to be incurred over the following 31 years.

Changes in the environmental remediation obligation are as follows:

	2019			2018
Opening balance	$	55,621		$	54,322
Remediation activities	(1,678		)	(2,163		)
Accretion	1,065			1,479
Changes in cash flow estimates	981			4,051
Revision in assumptions	2,072			(2,068		)
Closing balance	$	58,061		$	55,621

By rate orders, the Regulator provided for the recovery of actual expenditures for site investigation and remediation over a period of 7 years and accordingly, as of December 31, 2019, the Company has reflected a regulatory asset of $82,300 (2018 - $82,295) for the MGP and related sites (note 7(a)).

(c) Asset retirement obligations

Asset retirement obligations mainly relate to legal requirements to: (i) remove wind farm facilities upon termination of land leases; (ii) cut (disconnect from the distribution system), purge (cleanup of natural gas and Polychlorinated Biphenyls "PCB" contaminants) and cap gas mains within the gas distribution and transmission system when mains are retired in place, or sections of gas main are removed from the pipeline system; (iii) clean and remove storage tanks containing waste oil and other waste contaminants; (iv) remove certain river water intake structures and equipment; (v) dispose of coal combustion residuals and PCB contaminants and (vi) remove asbestos upon major renovation or demolition of structures and facilities. 

Changes in the asset retirement obligations are as follows:

	2019			2018
Opening balance	$	43,291		$	44,166
Obligation assumed from business acquisition and constructed projects	3,226			225
Retirement activities	(443		)	(5,130		)
Accretion	2,148			1,974
Change in cash flow estimates	5,657			2,056
Closing balance	$	53,879		$	43,291

As the cost of retirement of utility assets, liability accretion and asset depreciation expense are expected to be recovered through rates, a corresponding regulatory asset is recorded (note 7(j)).

(d) Customer deposits

Customer deposits result from the Company’s obligation by state regulators to collect a deposit from customers of its facilities under certain circumstances when services are connected. The deposits are refundable as allowed under the facilities’ regulatory agreement.

(e) Unamortized investment tax credits

The unamortized investment tax credits were assumed in connection with the acquisition of Empire. The investment tax credits are associated with an investment made in a generating station. The credits are being amortized over the life of the generating station.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

12.Other long-term liabilities (continued)

(f) Deferred credits

During the year, the Company settled $29,100 of contingent consideration related to the Company's investment in Atlantica (note 8(a)), and recorded an additional $5,000 contingent consideration related to the Company's investment in the San Antonio Water System (note 8(c)).

(g)    Preferred shares, Series C

APUC has 100 redeemable Series C preferred shares issued and outstanding. Thirty-six of the Series C preferred shares are owned by related parties controlled by executives of the Company. The preferred shares are mandatorily redeemable in 2031 for C$53,400 per share and have a contractual cumulative cash dividend paid quarterly until the date of redemption based on a prescribed payment schedule indexed in proportion to the increase in CPI over the term of the shares. The Series C preferred shares are convertible into common shares at the option of the holder and the Company, at any time after May 20, 2031 and before June 19, 2031, at a conversion price of C$53,400 per share.

As these shares are mandatorily redeemable for cash, they are classified as liabilities in the consolidated financial statements. The Series C preferred shares are accounted for under the effective interest method, resulting in accretion of interest expense over the term of the shares. Dividend payments are recorded as a reduction of the Series C preferred share carrying value.

Estimated dividend payments due in the next five years and dividend and redemption payments thereafter are as follows:
2020	$	1,035
2021	1,050
2022	1,070
2023	1,243
2024	1,454
Thereafter to 2031	9,439
Redemption amount	4,111
	$	19,402
Less: amounts representing interest	(5,609		)
	$	13,793
Less current portion	(1,035		)
	$	12,758

 

(h) Other

Convertible debentures    

As at December 31, 2019, the carrying value of the convertible debentures was $342 (2018 - $470). The convertible debentures mature on March 31, 2026 and bear interest at an annual rate of 0% per C$1,000 principal amount of convertible debentures. The debentures are convertible at a price of C$10.60 per share into up to 44,130 common shares. During the year ended December 31, 2019, $148 (2018 - $447) of principal converted to 19,429 (2018 - 56,926) common shares of the Company (note 13).

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

13. Shareholders’ capital

(a) Common shares

Number of common shares 

	2019	2018
Common shares, beginning of year	488,851,433	431,765,935
Public offering (a)(i) and (a)(ii)	28,009,341	50,041,624
Dividend reinvestment plan (a)(iii)	6,068,465	5,880,843
Exercise of share-based awards (c)	1,274,655	1,106,105
Conversion of convertible debentures (note 12(h))	19,429	56,926
Common shares, end of year	524,223,323	488,851,433

Authorized

APUC is authorized to issue an unlimited number of common shares. The holders of the common shares are entitled to dividends if, as and when declared by the Board of Directors (the “Board”); to one vote per share at meetings of the holders of common shares; and upon liquidation, dissolution or winding up of APUC to receive pro rata the remaining property and assets of APUC, subject to the rights of any shares having priority over the common shares.

The Company has a shareholders’ rights plan (the “Rights Plan”), which expires in 2022. Under the Rights Plan, one right is issued with each issued share of the Company. The rights remain attached to the shares and are not exercisable or separable unless one or more certain specified events occur. If a person or group acting in concert acquires 20 percent or more of the outstanding shares (subject to certain exceptions) of the Company, the rights will entitle the holders thereof (other than the acquiring person or group) to purchase shares at a 50 percent discount from the then-current market price. The rights provided under the Rights Plan are not triggered by any person making a “Permitted Bid”, as defined in the Rights Plan.

(i) Public offering

In October 2019, APUC issued 26,252,542 common shares at $13.50 per share pursuant to a public offering for proceeds of $354,409 before issuance costs of $14,418.

On December 20, 2018, APUC issued 12,536,350 common shares at $10.09 (C$13.76) per share pursuant to a public offering for proceeds of $126,485 (C$172,500) before issuance costs of $366 (C$492).

On April 24, 2018, APUC issued 37,505,274 common shares at $9.23 (C$11.85) per share pursuant to a public offering for gross proceeds of $346,458 (C$444,437) before issuance costs of $590 (C$765).

(ii) At-the-market equity program

On February 28, 2019, APUC established an at-the-market equity program ("ATM program") that allows the Company to issue up to $250,000 of common shares from treasury to the public from time to time, at the Company's discretion, at the prevailing market price when issued on the TSX, the NYSE, or any other existing trading market for the common shares of the Company in Canada or the United States. During the year, the Company issued 1,756,799 common shares under the ATM program at an average price of $12.54 per common share for gross proceeds of $22,034 ($21,704 net of commissions). Other related costs, primarily related to the establishment of the ATM program, were $2,122.

(iii) Dividend reinvestment plan

The Company has a common shareholder dividend reinvestment plan, which provides an opportunity for shareholders to reinvest dividends for the purpose of purchasing common shares. Additional common shares acquired through the reinvestment of cash dividends are purchased in the open market or are issued by APUC at a discount of up to 5% from the average market price, all as determined by the Company from time to time. Subsequent to year-end, APUC issued an additional 1,244,696 common shares under the dividend reinvestment plan.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

13. Shareholders’ capital (continued)

(b) Preferred shares

APUC is authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board.

The Company has the following Series A and Series D preferred shares issued and outstanding as at December 31, 2019 and 2018:

Preferred shares	Number of shares	Price per share		Carrying amount C$		Carrying amount $
Series A	4,800,000	C$	25	C$	116,546	$	100,463
Series D	4,000,000	C$	25	C$	97,259	$	83,836
						$	184,299

The holders of Series A and Series D preferred shares had the right to convert their shares into cumulative floating rate preferred shares, Series B and Series E, respectively, subject to certain conditions, on December 31, 2018 and March 31, 2019, respectively, and every fifth year thereafter. Neither the Series A nor the Series B preferred shares were converted on December 31, 2018 and March 31, 2019 respectively.

The holders of Series A preferred shares are entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The dividend for each year up to, but excluding, December 31, 2018 was an annual amount of C$1.125 per share. The dividend rate for the five-year period from and including December 31, 2018 to but excluding December 31, 2023 will be $1.2905. The Series A dividend rate will reset on December 31, 2023 and every five years thereafter at a rate equal to the then five-year Government of Canada bond yield plus 2.94%. The Series A preferred shares are redeemable at C$25 per share at the option of the Company on December 31, 2023 and every fifth year thereafter.

The holders of Series D preferred shares are entitled to receive fixed cumulative preferential dividends as and when declared by the Board at an annual amount of C$1.25 per share for each year up to, but excluding, March 31, 2019. The dividend for the five-year period from and including March 31, 2019 to, but excluding, March 31, 2024 will be C$1.2728. The Series D dividend will reset on March 31, 2024 and every five years thereafter at a rate equal to the then five-year Government of Canada bond plus 3.28%. The Series D preferred shares are redeemable at C$25 per share at the option of the Company on March 31, 2024 and every fifth year thereafter.

The Company has 100 redeemable Series C preferred shares issued and outstanding. The mandatorily redeemable Series C preferred shares are recorded as a liability on the consolidated balance sheets as they are mandatorily redeemable for cash (note 12(g)).

(c) Share-based compensation

For the year ended December 31, 2019, APUC recorded $10,553 (2018 - $9,458) in total share-based compensation expense detailed as follows: 

	2019		2018
Share options	$	1,288	$	2,054
Director deferred share units	798		714
Employee share purchase	322		312
Performance and restricted share units	8,145		6,378
Total share-based compensation	$	10,553	$	9,458

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

13. Shareholders’ capital (continued)

(c) Share-based compensation (continued)

The compensation expense is recorded as part of administrative expenses in the consolidated statements of operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant.

As of December 31, 2019, total unrecognized compensation costs related to non-vested options and PSUs were $1,252 and $12,750, respectively, and are expected to be recognized over a period of 1.68 and 1.86 years, respectively.

(i) Share option plan

The Company’s share option plan (the “Plan”) permits the grant of share options to officers, directors, employees and selected service providers. The aggregate number of shares that may be reserved for issuance under the Plan must not exceed 8% of the number of shares outstanding at the time the options are granted.

The number of shares subject to each option, the option price, the expiration date, the vesting and other terms and conditions relating to each option shall be determined by the Board (or the compensation committee of the Board (“Compensation Committee”)) from time to time. Dividends on the underlying shares do not accumulate during the vesting period. Option holders may elect to surrender any portion of the vested options that is then exercisable in exchange for the “In-the-Money Amount”. In accordance with the Plan, the “In-The-Money Amount” represents the excess, if any, of the market price of a share at such time over the option price, in each case such “In-the-Money Amount” being payable by the Company in cash or shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards.

The Compensation Committee may accelerate the vesting of the unvested options then held by the optionee at the Compensation Committee's discretion. In the event that the Company restates its financial results, any unpaid or unexercised options may be cancelled at the discretion of the Compensation Committee in accordance with the terms of the Company's clawback policy.

The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on a straight-line basis over the options’ vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the vested portion of the award at that date. The Company determines the fair value of options granted using the Black-Scholes option-pricing model. The risk-free interest rate is based on the zero-coupon Canada Government bond with a similar term to the expected life of the options at the grant date. Expected volatility was estimated based on the historical volatility of the Company’s shares.  The expected life was based on experience to date. The dividend yield rate was based upon recent historical dividends paid on APUC shares.

The following assumptions were used in determining the fair value of share options granted: 

	2019			2018
Risk-free interest rate	1.9		%	2.1		%
Expected volatility	20		%	21		%
Expected dividend yield	4.3		%	4.8		%
Expected life	5.50 years			5.50 years
Weighted average grant date fair value per option	C$	1.66		C$	1.41

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

13. Shareholders’ capital (continued)

(c) Share-based compensation (continued)

(i) Share option plan (continued)

Share option activity during the years is as follows: 

	Number of awards		Weighted average exercise price		Weighted average remaining contractual term (years)	Aggregate intrinsic value
Balance, January 1, 2018	6,738,856		C$	11.18	6.32	C$	19,380
Granted	1,166,717		12.80		8.00	—
Exercised	(1,589,211	)	10.66		5.02	5,059
Forfeited	(23,720	)	12.80		—	—
Balance, December 31, 2018	6,292,642		C$	11.61	5.75	C$	13,342
Granted	1,113,775		14.96		8.00	—
Exercised	(3,882,505	)	11.23		4.45	6,225
Forfeited	—		—		—	—
Balance, December 31, 2019	3,523,912		C$	13.09	5.87	C$	18,609
Exercisable, December 31, 2019	1,735,241		C$	12.57	5.43	C$	14,559

Subsequent to year-end, on February 19, 2020, 394,939 stock options were exercised at a weighted average price of C$12.77 in exchange for 115,517 common shares issued from treasury, and 279,422 options settled at their cash value as payment for the exercise price and tax withholdings related to the exercise of the options.

(ii) Employee share purchase plan

Under the Company’s employee share purchase plan (“ESPP”), eligible employees may have a portion of their earnings withheld to be used to purchase the Company’s common shares. The Company will match 20% of the employee contribution amount for the first five thousand dollars per employee contributed annually and 10% of the employee contribution amount for contributions over five thousand dollars up to ten thousand dollars annually. Common shares purchased through the Company match portion shall not be eligible for sale by the participant for a period of one year following the purchase date on which such shares were acquired. At the Company’s option, the common shares may be (i) issued to participants from treasury at the average share price or (ii) acquired on behalf of participants by purchases through the facilities of the TSX or NYSE by an independent broker. The aggregate number of common shares reserved for issuance from treasury by APUC under the ESPP shall not exceed 2,000,000 common shares.

The Company uses the fair value based method to measure the compensation expense related to the Company’s contribution. For the year ended December 31, 2019, a total of 253,538 common shares (2018 - 252,698) were issued to employees under the ESPP.

(iii) Director's deferred share units

Under the Company’s deferred share unit plan, non-employee directors of the Company may elect annually to receive all or any portion of their compensation in DSUs in lieu of cash compensation. Directors’ fees are paid on a quarterly basis and at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one of the Company’s common shares. Dividends accumulate in the DSU account and are converted to DSUs based on the market value of the shares on that date. DSUs cannot be redeemed until the director retires, resigns, or otherwise leaves the Board. The DSUs provide for settlement in cash or shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards. As of December 31, 2019, 460,418 (2018 - 380,656) DSUs were outstanding pursuant to the election of the directors to defer a percentage of their director’s fee in the form of DSUs. The aggregate number of common shares reserved for issuance from treasury by APUC under the DSU plan shall not exceed 1,000,000 common shares.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

13. Shareholders’ capital (continued)

(c) Share-based compensation (continued)

(iv) Performance and restricted share units

The Company offers a PSU and RSU plan to its employees as part of the Company’s long-term incentive program. PSUs have been granted annually for three-year overlapping performance cycles. The PSUs vest at the end of the three-year cycle and will be calculated based on established performance criteria. At the end of the three-year performance periods, the number of common shares issued can range from 2.0% to 237% of the number of PSUs granted. RSU vesting conditions and dates vary by grant and are outlined in each award letter. RSUs are not subject to performance criteria. Dividends accumulating during the vesting period are converted to PSUs and RSUs based on the market value of the shares on that date and are recorded in equity as the dividends are declared. None of these PSUs or RSUs have voting rights. Any PSUs or RSUs not vested at the end of a performance period will expire. The PSUs and RSUs provide for settlement in cash or shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these units are accounted for as equity awards. The aggregate number of common shares reserved for issuance from treasury by APUC under the PSU and RSU Plan shall not exceed 7,000,000 common shares.

Compensation expense associated with PSUs is recognized rateably over the performance period. Achievement of the performance criteria is estimated at the consolidated balance sheet dates. Compensation cost recognized is adjusted to reflect the performance conditions estimated to date.

A summary of the PSUs and RSUs follows: 

	Number of awards		Weighted average grant-date fair value		Weighted average remaining contractual term (years)	Aggregate intrinsic value
Balance, January 1, 2018	955,028		C$	12.30	1.84	C$	13,428
Granted, including dividends	791,524		12.41		2.00	10,098
Exercised	(285,551	)	10.02		—	3,691
Forfeited	(68,869	)	13.02		—	—
Balance, December 31, 2018	1,392,132		C$	12.75	1.60	C$	19,114
Granted, including dividends	1,471,442		14.69		2.00	16,302
Exercised	(344,340	)	11.55		—	5,148
Forfeited	(107,191	)	13.84		—	—
Balance, December 31, 2019	2,412,043		C$	14.00	1.86	C$	44,309
Exercisable, December 31, 2019	743,787		C$	13.21	—	C$	13,663

 

(v) Bonus deferral RSUs

During 2018, the Company introduced a new bonus deferral RSU program to certain of its employees. Eligible employees have the option to receive a portion or all of their annual bonus payment in RSUs in lieu of cash. The RSUs provide for settlement in shares, and therefore these options are accounted for as equity awards. The RSUs granted are 100% vested and therefore, compensation expense associated with RSUs is recognized immediately upon issuance.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

13. Shareholders’ capital (continued)

(c) Share-based compensation (continued)

(vi) Bonus deferral RSUs

A summary of the bonus deferral RSUs follows:

	Number of  awards		Weighted average grant-date fair value		Aggregate intrinsic value
Balance, December 31, 2017	—		C$	—	C$	—
Granted, including dividends	131,611		12.82		1,683
Exercised	(4,545	)	12.82		61
Balance, December 31, 2018	127,066		C$	12.82	C$	1,745
Granted, including dividends	135,324		15.40		2,084
Balance and exercisable, December 31, 2019	262,390		C$	14.15	C$	4,820

14.Accumulated other comprehensive income (loss)

AOCI consists of the following balances, net of tax:

	Foreign currency cumulative translation			Unrealized gain on cash flow hedges				Pension and post-employment actuarial changes			Total
Balance, January 1, 2018	$	(47,701	)	$	55,366			$	(10,457	)	$	(2,792	)
Adoption of ASU 2018-02 on tax effects in AOCI	—			11,657				(1,032		)	10,625
Other comprehensive income (loss)	(27,969		)	1,567				2,046			(24,356		)
Amounts reclassified from AOCI to the consolidated statement of operations	—			(4,257		)		(86		)	(4,343		)
Net current period OCI	$	(27,969	)	$	(2,690	)		$	1,960		$	(28,699	)
OCI attributable to the non-controlling interests	1,481			—				—			1,481
Net current period OCI attributable to shareholders of APUC	$	(26,488	)	$	(2,690	)		$	1,960		$	(27,218	)
Balance, December 31, 2018	$	(74,189	)	$	64,333			$	(9,529	)	$	(19,385	)
Adoption of ASU 2017-12 on hedging (note 2(a))	—			186				—			186
Other comprehensive income (loss)	7,795			19,177				(7,999		)	18,973
Amounts reclassified from AOCI to the consolidated statement of operations	—			(8,597		)	—	1,490			(7,107		)
Net current period OCI	$	7,795		$	10,580			$	(6,509	)	$	11,866
OCI attributable to the non-controlling interests	(2,428		)	—				—			(2,428		)
Net current period OCI attributable to shareholders of APUC	$	5,367		$	10,580			$	(6,509	)	$	9,438
Balance, December 31, 2019	$	(68,822	)	$	75,099			$	(16,038	)	$	(9,761	)

Amounts reclassified from AOCI for unrealized gain (loss) on cash flow hedges affected revenue from non-regulated energy sales while those for pension and post-employment actuarial changes affected pension and post-employment non-service costs.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

15. Dividends

All dividends of the Company are made on a discretionary basis as determined by the Board. The Company declares and pays the dividends on its common shares in U.S. dollars. Dividends declared during the year were as follows:

	2019				2018
	Dividend		Dividend per share		Dividend		Dividend per share
Common shares	$	277,835	$	0.5512	$	235,440	$	0.5011
Series A preferred shares	C$	6,194	C$	1.2905	C$	5,400	C$	1.1250
Series D preferred shares	C$	5,068	C$	1.2671	C$	5,000	C$	1.2500

16.Related party transactions

(a)Equity-method investments

The Company provides administrative and development services to its equity-method investees and is reimbursed for incurred costs. To that effect, during 2019, the Company charged its equity-method investees $12,374 (2018 - $11,390).

On December 30, 2019, the Company sold its interest in AWUSA to a joint venture entity in exchange for a note receivable of $30,293 (note 8(c)). No gain or loss was recognized on the sale. For the year, APUC recorded interest income of $6,007, and a fair value loss of $6,007 on its investment in the joint venture.

During the year, the Company sold the Sugar Creek Wind Project to AAGES Sugar Creek in exchange for a note receivable of $21,107, subject to certain adjustments. No gain was recorded on deconsolidation of the Sugar Creek net assets. However, an amount of $15,765, or $11,412, net of tax, was reclassified from AOCI into earnings as a result of the discontinuation of hedge accounting on energy derivatives put in place early in the development of Sugar Creek (note 24(b)(ii)).

During the year, the Company entered into an enhanced cooperation agreement with Atlantica to, among other things, provide a framework for evaluating mutually advantageous transactions. For a period of one year from the date of the agreement, Atlantica has an exclusive right of first offer for interests in certain Renewable Energy assets.

(b)Redeemable non-controlling interest held by related party

Redeemable non-controlling interest held by related party represents a preference share in a consolidated subsidiary of the Company acquired by AAGES B.V. in 2018 for $305,000 (note 8(a)). Redemption is not considered probable as at December 31, 2019. The Company incurred non-controlling interest attributable to AAGES B.V. of $16,482 (2018 - $2,622) and recorded distributions of $18,241 (2018 - $nil) during the year (note 17).

(c)Non-controlling interest held by related party

Non-controlling interest held by related party represents interest in a consolidated subsidiary of the Company acquired by AYES Canada in May 2019 for $96,752 (note 8(b)). The Company recorded distributions of $26,465 during the year.

(d)Long Sault Hydro Facility

Effective December 31, 2013, APUC acquired the shares of Algonquin Power Corporation Inc. (“APC”), which was partially owned by Senior Executives. APC owns the partnership interest in the 18 MW Long Sault Hydro Facility. A final post-closing adjustment related to the transaction remains outstanding.

The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

17. Non-controlling interests and redeemable non-controlling interests

Net effect attributable to non-controlling interests for the years ended December 31 consists of the following:

	2019			2018
HLBV and other adjustments attributable to:
Non-controlling interests - tax equity partnership units	$	(55,963	)	$	(103,150	)
Non-controlling interests - redeemable tax equity partnership units	(9,006		)	(7,545		)
Other net earnings attributable to:
Non-controlling interests	2,553			2,174
	$	(62,416	)	$	(108,521	)
Redeemable non-controlling interest, held by related party	16,482			2,622
Net effect of non-controlling interests	$	(45,934	)	$	(105,899	)

The non-controlling tax equity investors (“tax equity partnership units”) in the Company's U.S. wind power and solar power generating facilities are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. The share of earnings attributable to the non-controlling interest holders in these subsidiaries is calculated using the HLBV method of accounting as described in note 1(s).

The terms of the arrangement refer to the tax rate in effect when the benefits are delivered. As such, the U.S. federal corporate tax rate of 35% was used to calculate HLBV as at December 31, 2017. The reduced U.S. federal corporate tax rate of 21% and other certain measures included in the Tax Act effective January 1, 2018 were reflected in the calculation of HLBV in 2018. The changes accelerated HLBV income from future years to the first quarter of 2018 in the amount of $55,900.

Non-controlling interests

As of December 31, 2019, non-controlling interests of $457,834 (2018 - $519,896) include partnership units held by tax equity investors in certain U.S. wind power and solar generating facilities of $457,000 (2018 - 519,100) and other non-controlling interests of $834 (2018 - $796). Contributions from tax equity investors of $15,250 were received for the Great Bay Solar I Facility in 2018 (note 3(g)).

Non-controlling interest held by related party

Non-controlling interest was issued to AYES Canada in May 2019 for $96,752 (note 8(b)). The balance as of December 31, 2019 was $73,707.

Redeemable non-controlling interests

Non-controlling interests in subsidiaries that are redeemable upon the occurrence of uncertain events not solely within APUC’s control are classified as temporary equity on the consolidated balance sheets. If the redemption is probable or currently redeemable, the Company records the instruments at their redemption value. Redemption is not considered probable as of December 31, 2019. Changes in redeemable non-controlling interests are as follows:

	Redeemable non-controlling interests held by related party					Redeemable non-controlling interests
	2019			2018		2019			2018
Opening balance	$	307,622		$	—	$	33,364		$	41,553
Net effect from operations	16,482			2,622		(9,006		)	(7,545		)
Contributions, net of costs	—			305,000		3,403			—
Dividends and distributions declared	(18,241		)	—		(1,848		)	(644		)
Closing balance	$	305,863		$	307,622	$	25,913		$	33,364

During 2019, contributions from tax equity partnership investors of $3,403 were received for the Turquoise Solar Facility (note 3(b)). During 2018, contributions of $305,000 were received from AAGES B.V. for a preference share of AY Holdings (note 8(a)).

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

18. Income taxes

The provision for income taxes in the consolidated statements of operations represents an effective tax rate different than the Canadian enacted statutory rate of 26.5% (2018 - 26.5%). The differences are as follows:

	2019			2018
Expected income tax expense at Canadian statutory rate	$	147,093		$	35,102
Increase (decrease) resulting from:
Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates	(27,703		)	(28,064		)
Adjustments from investments carried at fair value	(60,730		)	25,870
Non-controlling interests share of income	16,991			29,637
Non-deductible acquisition costs	2,500			4,267
Tax credits	(9,332		)	(1,419		)
Adjustment relating to prior periods	(1,240		)	3,673
U.S. Tax reform and related deferred tax adjustments (1)	—			(18,363		)
Other	2,538			2,669
Income tax expense	$	70,117		$	53,372

⁽¹⁾ In 2017, the Tax Cuts and Jobs Act ("Tax Act") implemented significant changes to U.S. tax legislation, including a reduction in the U.S. federal corporate income tax from 35% to 21%, effective January 1, 2018. The Company’s U.S. entities were required to remeasure their deferred tax assets and liabilities at the new corporate income tax rate as at the date of enactment.  In 2018, an adjustment related to the implementation of U.S. Tax Reform  resulted in a non-cash accounting benefit of $18,363, which was recorded in the Company's 2018 consolidated statement of operations.

For the years ended December 31, 2019 and 2018, earnings before income taxes consist of the following:

	2019		2018
Canada	$	351,908	$	(109,537	)
U.S.	203,159		241,998
	$	555,067	$	132,461

Income tax expense (recovery) attributable to income (loss) consists of: 

	Current		Deferred			Total
Year ended December 31, 2019
Canada	$	6,695	$	17,607		$	24,302
United States	9,736		36,079			45,815
	$	16,431	$	53,686		$	70,117
Year ended December 31, 2018
Canada	$	2,872	$	(14,197	)	$	(11,325	)
United States	8,475		56,222			64,697
	$	11,347	$	42,025		$	53,372

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

18. Income taxes (continued)

The tax effect of temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases that give rise to significant portions of the deferred tax assets and deferred tax liabilities as of December 31, 2019 and 2018 are presented below:

	2019			2018
Deferred tax assets:
Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs	$	382,448		$	329,099
Pension and OPEB	54,113			48,586
Environmental obligation	15,541			14,790
Regulatory liabilities	160,200			161,560
Other	59,103			45,193
Total deferred income tax assets	$	671,405		$	599,228
Less: valuation allowance	(29,447		)	(28,018		)
Total deferred tax assets	$	641,958		$	571,210
Deferred tax liabilities:
Property, plant and equipment	$	707,185		$	653,962
Outside basis in partnership	235,063			167,659
Regulatory accounts	145,852			113,758
Other	14,811			7,561
Total deferred tax liabilities	$	1,102,911		$	942,940
Net deferred tax liabilities	$	(460,953	)	$	(371,730	)
Consolidated balance sheets classification:
Deferred tax assets	$	30,585		$	72,415
Deferred tax liabilities	(491,538		)	(444,145		)
Net deferred tax liabilities	$	(460,953	)	$	(371,730	)

The valuation allowance for deferred tax assets as at December 31, 2019 was $29,447 (2018 - $28,018). The valuation allowance primarily relates to operating losses that, in the judgment of management, are not more likely than not to be realized. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities (including the impact of available carryback and carryforward periods), projected future taxable income, and tax-planning strategies in making this assessment.

As of December 31, 2019, the Company had non-capital losses carried forward available to reduce future years' taxable income, which expire as follows: 

Year of expiry	Non-capital loss carryforwards
2020 and onwards	$	1,091,322

The Company has provided for deferred income taxes for the estimated tax cost of distributed earnings of certain of its subsidiaries. Deferred income taxes have not been provided on approximately $370,682 of undistributed earnings of certain foreign subsidiaries, as the Company has concluded that such earnings are indefinitely reinvested and should not give rise to additional tax liabilities. A determination of the amount of the unrecognized tax liability relating to the remittance of such undistributed earnings is not practicable.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

19. Other losses

Other losses consist of the following:

	2019			2018
Pension and other post-employment non-service costs (note 10)	$	(17,332	)	$	(4,990	)
Acquisition and transition-related costs (note 3)	(11,609		)	(687		)
Other	(15,085		)	(2,725		)
	$	(44,026	)	$	(8,402	)

20. Basic and diluted net earnings per share

Basic and diluted earnings per share have been calculated on the basis of net earnings attributable to the common shareholders of the Company and the weighted average number of common shares and bonus deferral restricted share units outstanding. Diluted net earnings per share is computed using the weighted-average number of common shares, subscription receipts outstanding, additional shares issued subsequent to year-end under the dividend reinvestment plan, PSUs, RSUs and DSUs outstanding during the year and, if dilutive, potential incremental common shares resulting from the application of the treasury stock method to outstanding share options and additional shares issued subsequent to quarter-end under the dividend reinvestment plan. The convertible debentures (note 12(h)) are convertible into common shares at any time prior to maturity or redemption by the Company. The shares issuable upon conversion of the convertible debentures are included in diluted earnings per share.

The reconciliation of the net earnings and the weighted average shares used in the computation of basic and diluted earnings per share are as follows:

	2019		2018
Net earnings attributable to shareholders of APUC	$	530,884	$	184,988
Series A preferred shares dividend	4,666		4,169
Series D preferred shares dividend	3,820		3,858
Net earnings attributable to common shareholders of APUC from continuing operations – basic and diluted	$	522,398	$	176,961
Weighted average number of shares
Basic	499,910,876		461,818,023
Effect of dilutive securities	4,828,678		4,227,595
Diluted	504,739,554		466,045,618

The shares potentially issuable as a result of 1,113,775 share options (2018 - 3,380,184) are excluded from this calculation as they are anti-dilutive.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

21. Segmented information

The Company is managed under two primary business units consisting of the Regulated Services Group and the Renewable Energy Group. The two business units are the two segments of the Company.

The Regulated Services Group, the Company's regulated operating unit, owns and operates a portfolio of electric, natural gas, water distribution and wastewater collection utility systems and transmission operations in the United States and Canada; the Renewable Energy Group, the Company's non-regulated operating unit, owns and operates a diversified portfolio of renewable and thermal electric generation assets in North America and internationally.

For purposes of evaluating the performance of the business units, the Company allocates the realized portion of any gains or losses on financial instruments to the specific business units. Dividend income from Atlantica and AYES Canada are included in the operations of the Renewable Energy Group while interest income from San Antonio Water System is included in the operations of the Regulated Services Group. Equity method gains and losses are included in the operations of the Regulated Services Group or Renewable Energy Group based on the nature of the activities of the investees. The change in value of investments carried at fair value and unrealized portion of any gains or losses on derivative instruments not designated in a hedging relationship are not considered in management’s evaluation of divisional performance and are therefore allocated and reported under corporate.

	Year ended December 31, 2019
	Regulated Services Group			Renewable Energy Group			Corporate			Total
Revenue (1)(2)	$	1,366,971		$	257,950		$	—		$	1,624,921
Fuel, power and water purchased	426,046			17,258			—			443,304
Net revenue	940,925			240,692			—			1,181,617
Operating expenses	396,559			75,209			221			471,989
Administrative expenses	36,628			19,405			769			56,802
Depreciation and amortization	194,498			88,825			981			284,304
Loss on foreign exchange	—			—			3,146			3,146
Operating income (loss)	313,240			57,253			(5,117		)	365,376
Interest expense	(101,518		)	(61,039		)	(18,931		)	(181,488		)
Income from long-term investments	9,334			104,025			285,733			399,092
Other income (expenses)	(32,292		)	15,946			(11,567		)	(27,913		)
Earnings before income taxes	$	188,764		$	116,185		$	250,118		$	555,067
Property, plant and equipment	$	4,754,373		$	2,444,382		$	32,909		$	7,231,664
Investments carried at fair value	27,072			1,267,075			—			1,294,147
Equity-method investees	29,827			53,670			273			83,770
Total assets	6,816,063			4,014,067			81,340			10,911,470
Capital expenditures	$	478,936		$	102,396		$	—		$	581,332

⁽¹⁾ Revenue includes $22,282 related to net hedging gains from energy derivative contracts for the year ended December 31, 2019 that do not represent revenue recognized from contracts with customers.

⁽²⁾ Regulated Services Group revenue includes $(4,405) related to alternative revenue programs for the year ended December 31, 2019 that do not represent revenue recognized from contracts with customers.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

21. Segmented information (continued)

	Year ended December 31, 2018
	Regulated Services Group			Renewable Energy Group			Corporate			Total
Revenue (1)(2)	$	1,401,240		$	247,223		$	—		$	1,648,463
Fuel and power purchased	456,974			27,164			—			484,138
Net revenue	944,266			220,059			—			1,164,325
Operating expenses	401,486			70,980			—			472,466
Administrative expenses	33,234			18,539			937			52,710
Depreciation and amortization	177,719			82,044			1,009			260,772
Gain on foreign exchange	—			—			(58		)	(58		)
Operating income (loss)	331,827			48,496			(1,888		)	378,435
Interest expense	(99,063		)	(50,920		)	(2,135		)	(152,118		)
Income (loss) from long-term investments	5,558			45,741			(136,117		)	(84,818		)
Other expenses	(6,775		)	(1,576		)	(687		)	(9,038		)
Earnings (loss) before income taxes	$	231,547		$	41,741		$	(140,827	)	$	132,461
Property, plant and equipment	$	4,210,115		$	2,152,420		$	31,023		$	6,393,558
Investment carried at fair value	—			814,530			—			814,530
Equity-method investees	55			29,273			260			29,588
Total assets	6,022,262			3,269,786			106,541			9,398,589
Capital expenditures	$	370,221		$	96,148		$	—		$	466,369

⁽¹⁾ Revenue includes $14,953 related to net hedging gains from energy derivative contracts for the year ended December 31, 2018 that do not represent revenue recognized from contracts with customers.

⁽²⁾ Regulated Services Group revenue includes $7,425 related to alternative revenue programs for the year ended December 31, 2018 that do not represent revenue recognized from contracts with customers.

The majority of non-regulated energy sales are earned from contracts with large public utilities. The Company has mitigated its credit risk to the extent possible by selling energy to large utilities in various North American locations. None of the utilities contribute more than 10% of total revenue.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

21. Segmented information (continued)

APUC operates in the independent power and utility industries in both Canada and the United States. Information on operations by geographic area is as follows:

	2019		2018
Revenue
Canada	$	87,226	$	70,358
United States	1,537,695		1,578,105
	$	1,624,921	$	1,648,463
Property, plant and equipment
Canada	$	752,016	$	415,979
United States	6,479,648		5,977,579
	$	7,231,664	$	6,393,558
Intangible assets
Canada	$	23,795	$	23,994
United States	23,821		31,000
	$	47,616	$	54,994

Revenue is attributed to the two countries based on the location of the underlying generating and utility facilities.

22.Commitments and contingencies

(a) Contingencies

APUC and its subsidiaries are involved in various claims and litigation arising out of the ordinary course and conduct of its business. Although such matters cannot be predicted with certainty, management does not consider APUC’s exposure to such litigation to be material to these consolidated financial statements. Accruals for any contingencies related to these items are recorded in the consolidated financial statements at the time it is concluded that its occurrence is probable and the related liability is estimable.

Claim by Gaia Power Inc.

On October 30, 2018, Gaia Power Inc. (“Gaia”) commenced an action in the Ontario Superior Court of Justice against APUC and certain of its subsidiaries, claiming damages of not less than $345,000 and punitive damages in the sum of $25,000. The action arises from Gaia’s 2010 sale, to a subsidiary of APUC, of Gaia’s interest in certain proposed wind farm projects in Canada.  Pursuant to a 2010 royalty agreement, Gaia is entitled to royalty payments if the projects are developed and achieve certain agreed targets. It is too early to determine the likelihood of success in this lawsuit; however, APUC intends to vigorously defend it.

Condemnation expropriation proceedings

Liberty Utilities (Apple Valley Ranchos Water) Corp. is the subject of a condemnation lawsuit filed by the town of Apple Valley. A court will determine the necessity of the taking by Apple Valley and, if established, a jury will determine the fair market value of the assets being condemned.  Resolution of the condemnation proceedings is expected to take two to three years. Any taking by government entities would legally require fair compensation to be paid; however, there is no assurance that the value received as a result of the condemnation will be sufficient to recover the Company's net book value of the utility assets taken.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

22.Commitments and contingencies (continued)

(b) Commitments

In addition to the commitments related to the proposed acquisitions and development projects disclosed in notes 3 and 8, the following significant commitments exist as of December 31, 2019.

APUC has outstanding purchase commitments for power purchases, gas supply and service agreements, service agreements, capital project commitments and land easements.

Detailed below are estimates of future commitments under these arrangements: 

	Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
Power purchase (i)	$	30,672	$	11,422	$	11,338	$	11,566	$	11,796	$	179,412	$	256,206
Gas supply and service agreements (ii)	83,083		60,699		49,217		46,406		41,538		135,926		416,869
Service agreements	47,950		40,456		41,554		45,611		47,005		293,436		516,012
Capital projects	104,809		114,806		—		—		—		—		219,615
Land easements	6,603		6,673		6,744		6,835		6,918		200,891		234,664
Total	$	273,117	$	234,056	$	108,853	$	110,418	$	107,257	$	809,665	$	1,643,366

(i) Power purchase: APUC’s electric distribution facilities have commitments to purchase physical quantities of power for load serving requirements. The commitment amounts included in the table above are based on market prices as of December 31, 2019. However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism.

(ii)   Gas supply and service agreements: APUC’s gas distribution facilities and thermal generation facilities have commitments to purchase physical quantities of natural gas under contracts for purposes of load serving requirements and of generating power.

23. Non-cash operating items

The changes in non-cash operating items consist of the following:

	2019			2018
Accounts receivable	$	(20,857	)	$	3,005
Fuel and natural gas in storage	13,985			1,351
Supplies and consumables inventory	(6,028		)	(7,189		)
Income taxes recoverable	17,796			(763		)
Prepaid expenses	(7,501		)	2,907
Accounts payable	63,854			(22,915		)
Accrued liabilities	8,872			28,687
Current income tax liability	(5,016		)	2,974
Asset retirements and environmental obligations	(2,494		)	(7,293		)
Net regulatory assets and liabilities	(2,308		)	(8,890		)
	$	60,303		$	(8,126	)

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

24. Financial instruments

(a) Fair value of financial instruments

2019	Carrying amount		Fair value		Level 1		Level 2		Level 3
Long-term investments carried at fair value	$	1,294,147	$	1,294,147	1,178,581		$	27,072	$	88,494
Development loans and other receivables	37,050		37,984		—		37,984		—
Derivative instruments:
Energy contracts designated as a cash flow hedge	65,304		65,304		—		—		65,304
Energy contracts not designated as a hedge	20,384		20,384		—		—		20,384
Commodity contracts for regulated operations	16		16		—		16		—
Total derivative instruments	85,704		85,704		—		16		85,688
Total financial assets	$	1,416,901	$	1,417,835	$	1,178,581	$	65,072	$	174,182
Long-term debt	$	3,931,868	$	4,284,068	$	1,495,153	$	2,788,915	$	—
Convertible debentures	342		623		623		—		—
Preferred shares, Series C	13,793		15,120		—		15,120		—
Derivative instruments:
Energy contracts designated as a cash flow hedge	789		789		—		—		789
Energy contracts not designated as a hedge	38		38		—		—		38
Cross-currency swap designated as a net investment hedge	81,765		81,765		—		81,765		—
Commodity contracts for regulated operations	2,072		2,072		—		2,072		—
Total derivative instruments	84,664		84,664		—		83,837		827
Total financial liabilities	$	4,030,667	$	4,384,475	$	1,495,776	$	2,887,872	$	827

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

24. Financial instruments (continued)

(a)Fair value of financial instruments (continued)

2018	Carrying amount		Fair value		Level 1		Level 2		Level 3
Long-term investment carried at fair value	$	814,530	$	814,530	$	814,530	$	—	$	—
Development loans and other receivables	103,696		110,019		—		110,019		—
Derivative instruments (1):
Energy contracts designated as a cash flow hedge	61,838		61,838		—		—		61,838
Currency forward contract not designated as a hedge	869		869		—		869		—
Commodity contracts for regulatory operations	101		101		—		101		—
Total derivative instruments	62,808		62,808		—		970		61,838
Total financial assets	$	981,034	$	987,357	$	814,530	$	110,989	$	61,838
Long-term debt	$	3,336,795	$	3,356,773	$	768,400	$	2,588,373	$	—
Convertible debentures	470		639		639		—		—
Preferred shares, Series C	13,418		13,703		—		13,703		—
Derivative instruments:
Energy contracts designated as a cash flow hedge	57		57		—		—		57
Cross-currency swap designated as a net investment hedge	93,198		93,198		—		93,198		—
Interest rate swaps designated as a hedge	8,473		8,473		—		8,473		—
Commodity contracts for regulated operations	1,114		1,114		—		1,114		—
Total derivative instruments	102,842		102,842		—		102,785		57
Total financial liabilities	$	3,453,525	$	3,473,957	$	769,039	$	2,704,861	$	57

⁽¹⁾ Balance of $441 associated with certain weather derivatives have been excluded, as they are accounted for based on intrinsic value rather than fair value.

The Company has determined that the carrying value of its short-term financial assets and liabilities approximates fair value as of December 31, 2019 and 2018 due to the short-term maturity of these instruments.

The fair value of development loans and other receivables (level 2) is determined using a discounted cash flow method, using estimated current market rates for similar instruments adjusted for estimated credit risk as determined by management. 

The fair value of the investment in Atlantica (level 1) is measured at the closing price on the NASDAQ stock exchange adjusted for the impact of the expected settlement under the purchase agreement pursuant to the prepayment of $53,750 (note 8(a)).

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

24. Financial instruments (continued)

(a)Fair value of financial instruments (continued)

The Company’s level 1 fair value of long-term debt is measured at the closing price on the NYSE and the Canadian over-the-counter closing price. The Company’s level 2 fair value of long-term debt at fixed interest rates and Series C preferred shares has been determined using a discounted cash flow method and current interest rates. The Company's level 2 fair value of convertible debentures has been determined as the greater of their face value and the quoted value of APUC's common shares on a converted basis.

The Company’s level 2 fair value derivative instruments primarily consist of swaps, options, rights and forward physical derivatives where market data for pricing inputs are observable. Level 2 pricing inputs are obtained from various market indices and utilize discounting based on quoted interest rate curves which are observable in the marketplace.

The Company’s level 3 instruments consist of energy contracts for electricity sales and the fair value of the Company's investment in AYES Canada. The significant unobservable inputs used in the fair value measurement of energy contracts are the internally developed forward market prices ranging from $13.33 to $178.65 with a weighted average of $23.66 as of December 31, 2019. The weighted average forward market prices are developed based on the quantity of energy expected to be sold monthly and the expected forward price during that month. The change in the fair value of the energy contracts is detailed in notes 24(b)(ii) and 24(b)(iv). The significant unobservable inputs used in the fair value measurement of the Company's AYES Canada investment are the expected cash flows, the discount rates applied to these cash flows ranging from 8.75% to 9.50% with a weighted average of 9.42%, and the expected volatility of Atlantica's share price ranging from 18% to 22% as of December 31, 2019. Significant increases (decreases) in expected cash flows or increases (decreases) in discount rate in isolation would have resulted in a significantly lower (higher) fair value measurement.

(b) Derivative instruments

Derivative instruments are recognized on the consolidated balance sheets as either assets or liabilities and measured at fair value at each reporting period.

(i) Commodity derivatives – regulated accounting

The Company uses derivative financial instruments to reduce the cash flow variability associated with the purchase price for a portion of future natural gas purchases associated with its regulated gas and electric service territories. The Company’s strategy is to minimize fluctuations in gas sale prices to regulated customers.

The following are commodity volumes, in dekatherms (“dths”) associated with the above derivative contracts:

	2019
Financial contracts: Swaps	2,134,739
Options	150,000
Forward contracts	2,500,000
	4,784,739

The accounting for these derivative instruments is subject to guidance for rate regulated enterprises. Therefore, the fair value of these derivatives is recorded as current or long-term assets and liabilities, with offsetting positions recorded as regulatory assets and regulatory liabilities in the consolidated balance sheets. Most of the gains or losses on the settlement of these contracts are included in the calculation of the fuel and commodity costs adjustments (note 7(e)). As a result, the changes in fair value of these natural gas derivative contracts and their offsetting adjustment to regulatory assets and liabilities had no earnings impact.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

24. Financial instruments (continued)

(b) Derivative instruments (continued)

(i) Commodity derivatives – regulated accounting (continued)

The following table presents the impact of the change in the fair value of the Company’s natural gas derivative contracts had on the consolidated balance sheets: 

	2019		2018
Regulatory assets:
Swap contracts	$	28	$	66
Option contracts	38		—
Forward contracts	$	1,830	$	—
Regulatory liabilities:
Swap contracts	$	743	$	218
Option contracts	—		134
Forward contracts	$	—	$	1,259

(ii) Cash flow hedges

The Company reduces the price risk on the expected future sale of power generation at Sandy Ridge, Senate and Minonk Wind Facilities by entering into the following long-term energy derivative contracts. 

Notional quantity (MW-hrs)	Expiry	Receive average prices (per MW-hr)	Pay floating price (per MW-hr)
757,075	December 2028	35.35	PJM Western HUB
3,443,530	December 2027	25.54	PJM NI HUB
2,665,068	December 2027	36.46	ERCOT North HUB

In January 2019, the Company entered into a long-term energy derivative contract to reduce the price risk on the expected future sale of power generation at Sugar Creek. On September 30, 2019, the Company sold the derivative contract together with 100% of its ownership interest in Sugar Creek to AAGES Sugar Creek. The novation and transfer of the derivative contract was subject to counterparty approval, which was received subsequent to year-end in Q1 2020. As a result, the hedge relationship for the Sugar Creek energy derivative was discontinued. Amounts in AOCI of $15,765 and related tax were reclassified from AOCI into earnings in 2019 (note 24(b)(iv)).

During the year, the Company entered into an energy derivative contract to reduce the price risk on the expected future purchase of power on the open market at its Tinker Hydroelectric Facility with a notional quantity of 151,680 MW-hours and a price of $38.95 per MW-hr. The contract expires February 2022.

The Company was party to a 10-year forward-starting interest rate swap beginning on July 25, 2018 in order to reduce the interest rate risk related to the probable issuance on that date of a 10-year C$135,000 bond. During 2018, the Company amended and extended the forward-starting date of the interest rate swap to begin on March 29, 2019. During the year, the Company settled the forward-starting interest rate swap contract as it issued C$300,000 10-year senior unsecured notes with an interest rate of 4.60% (note 9(d)).

On May 23, 2019, the Company entered into a cross-currency swap, coterminous with the subordinated unsecured notes (note 9(e)), to effectively convert the $350,000 U.S. dollar denominated offering into Canadian dollars. The change in the carrying amount of the notes due to changes in spot exchange rates is recognized each period in the consolidated statements of operations as loss (gain) on foreign exchange. The Company designated the entire notional amount of the cross-currency fixed-for-fixed interest rate swap as a hedge of the foreign currency exposure related to cash flows for the interest and principal repayments on the notes. The gain or loss related to the fair value changes of the swap is first reported in OCI and a portion of the change is then reclassified from AOCI into earnings at each reporting date to offset the foreign exchange transaction gain or loss on the notes.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

24. Financial instruments (continued)

(b) Derivative instruments (continued)

(ii) Cash flow hedges (continued)

In September 2019, the Company entered into a forward-starting interest rate swap in order to reduce the interest rate risk related to the quarterly interest payments between July 1, 2024 and July 1, 2029 on the subordinated unsecured notes (note 9(e)). The Company designated the entire notional amount of the three pay-variable and receive-fixed interest rate swaps as a hedge of the future quarterly variable-rate interest payments associated with the subordinated unsecured notes.

The following table summarizes OCI attributable to derivative financial instruments designated as a cash flow hedge: 

	2019			2018
Effective portion of cash flow hedge	$	19,177		$	1,567
Amortization of cash flow hedge	(33		)	(33		)
Amounts reclassified from AOCI	(8,564		)	(4,224		)
OCI attributable to shareholders of APUC	$	10,580		$	(2,690	)

The Company expects $8,704 and $2,203 of unrealized gains currently in AOCI to be reclassified, net of taxes into non-regulated energy sales and interest expense, respectively, within the next twelve months, as the underlying hedged transactions settle.

(iii) Foreign exchange hedge of net investment in foreign operation

The Company is exposed to currency fluctuations from its Canadian-based operations. APUC manages this risk primarily through the use of natural hedges by using Canadian long-term debt to finance its Canadian operations and a combination of foreign exchange forward contracts and spot purchases. APUC only enters into foreign exchange forward contracts with major North American financial institutions having a credit rating of A or better, thus reducing credit risk on these forward contracts.

The Company’s Canadian operations are determined to have the Canadian dollar as their functional currency and are exposed to currency fluctuations from their U.S. dollar transactions. The Company designates the amounts drawn on its revolving and bank credit facilities denominated in U.S. dollars as a hedge of the foreign currency exposure of its net investment in its U.S. investments and subsidiaries. The related foreign currency transaction gain or loss designated as, and effective as, a hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in OCI) related to the net investment. A foreign currency gain of $35,277 for the year ended December 31, 2019 (2018 - loss of $28,705) was recorded in OCI.

Concurrent with its C$150,000, C$200,000 and C$300,000 debenture offerings in December 2012, January 2014, and January 2017, respectively, the Company entered into cross currency swaps, coterminous with the debentures, to effectively convert the Canadian dollar denominated offering into U.S. dollars. The Company designated the entire notional amount of the cross-currency fixed-for-fixed interest rate swap and related short-term U.S. dollar payables created by the monthly accruals of the swap settlement as a hedge of the foreign currency exposure of its net investment in the Renewable Energy Group's U.S. operations. The gain or loss related to the fair value changes of the swap and the related foreign currency gains and losses on the U.S. dollar accruals that are designated as, and are effective as, a hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in OCI) related to the net investment. A gain of $15,946 (2018 - loss of $41,244) was recorded in OCI in 2019.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

24. Financial instruments (continued)

(b) Derivative instruments (continued)

(iv) Other derivatives

The Company provides energy requirements to various customers under contracts at fixed rates. While the production from the Tinker Hydroelectric Facility is expected to provide a portion of the energy required to service these customers, APUC anticipates having to purchase a portion of its energy requirements at the ISO NE spot rates to supplement self-generated energy.

This risk is mitigated through the use of short-term financial forward energy purchase contracts that are classified as derivative instruments. The electricity derivative contracts are net settled fixed-for-floating swaps whereby APUC pays a fixed price and receives the floating or indexed price on a notional quantity of energy over the remainder of the contract term at an average rate, as per the following table. These contracts are not accounted for as hedges and changes in fair value are recorded in earnings as they occur.

The Company is exposed to interest rate fluctuations related to certain of its floating rate debt obligations, including certain project-specific debt and its revolving credit facilities, its interest rate swaps as well as interest earned on its cash on hand.

The Company is exposed to foreign exchange fluctuations related to the portion of its dividend declared and payable in U.S. dollars. This risk is mitigated through the use of currency forward contracts. For the year ended December 31, 2019, a foreign exchange loss of $983 (2018 - gain of $1,115) was recorded in the consolidated statements of operations. These currency forward contracts are not accounted for as a hedge.

For derivatives that are not designated as hedges, the changes in the fair value are immediately recognized in earnings.

The effects on the consolidated statements of operations of derivative financial instruments not designated as hedges consist of the following:

	2019			2018
Change in unrealized loss (gain) on derivative financial instruments:
Energy derivative contracts	$	(530	)	$	77
Currency forward contract	904			(1,230		)
Total change in unrealized loss (gain) on derivative financial instruments	$	374		$	(1,153	)
Realized loss (gain) on derivative financial instruments:
Energy derivative contracts	227			(73		)
Currency forward contract	(147		)	115
Total realized loss on derivative financial instruments	$	80		$	42
Loss (gain) on derivative financial instruments not accounted for as hedges	454			(1,111		)
Discontinued hedge accounting (note 24(b)(ii)) and other	(15,810		)	632
	$	(15,356	)	$	(479	)
Amounts recognized in the consolidated statements of operations consist of:
Loss (gain) on derivative financial instruments	$	(16,113	)	$	636
Loss (gain) on foreign exchange	757			(1,115		)
	$	(15,356	)	$	(479	)

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

24. Financial instruments (continued)

(c) Risk management

In the normal course of business, the Company is exposed to financial risks that potentially impact its operating results. The Company employs risk management strategies with a view of mitigating these risks to the extent possible on a cost effective basis. Derivative financial instruments are used to manage certain exposures to fluctuations in exchange rates, interest rates and commodity prices. The Company does not enter into derivative financial agreements for speculative purposes.

This note provides disclosures relating to the nature and extent of the Company’s exposure to risks arising from financial instruments, including credit risk and liquidity risk, and how the Company manages those risks.

Credit risk

Credit risk is the risk of an unexpected loss if a customer or counterparty to a financial instrument fails to meet its contractual obligations. The Company’s financial instruments that are exposed to concentrations of credit risk are primarily cash and cash equivalents, accounts receivable, notes receivable and derivative instruments. The Company limits its exposure to credit risk with respect to cash equivalents by ensuring available cash is deposited with its senior lenders, all of which have a credit rating of A or better. The Company does not consider the risk associated with the Renewable Energy Group accounts receivable to be significant as over 87% of revenue from power generation is earned from large utility customers having a credit rating of Baa2 or better by Moody's, or BBB or higher by S&P, or BBB or higher by DBRS. Revenue is generally invoiced and collected within 45 days.

The remaining revenue is primarily earned by the Regulated Services Group, which consists of water and wastewater, electric and gas utilities in the United States and Canada. In this regard, the credit risk related to the Regulated Services Group accounts receivable balances of $200,594 is spread over thousands of customers. The Company has processes in place to monitor and evaluate this risk on an ongoing basis including background credit checks and security deposits from new customers. In addition, the regulators of the Regulated Services Group allow for a reasonable bad debt expense to be incorporated in the rates and therefore recovered from rate payers.

As of December 31, 2019, the Company’s maximum exposure to credit risk for these financial instruments was as follows: 

	December 31, 2019
	Canadian $			US $
Cash and cash equivalents and restricted cash	$	53,619		$	45,989
Accounts receivable	42,987			231,006
Allowance for doubtful accounts	(89		)	(4,850		)
Notes receivable	15,963			50,680
	$	112,480		$	322,825

In addition, the Company continuously monitors the creditworthiness of the counterparties to its foreign exchange, interest rate, and energy derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. The counterparties consist primarily of financial institutions. This concentration of counterparties may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

Liquidity risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. The Company’s approach to managing liquidity risk is to ensure, to the extent possible, that it will always have sufficient liquidity to meet liabilities when due. As of December 31, 2019, in addition to cash on hand of $62,485, the Company had $1,047,216 available to be drawn on its senior debt facilities. Each of the Company’s revolving credit facilities contain covenants that may limit amounts available to be drawn.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2019 and 2018

(in thousands of U.S. dollars, except as noted and per share amounts)

24. Financial instruments (continued)

(c) Risk management (continued)

Liquidity risk (continued)

The Company’s liabilities mature as follows: 

	Due less than 1 year			Due 2 to 3 years		Due 4 to 5 years		Due after 5 years		Total
Long-term debt obligations	$	602,028		$	468,740	$	600,721	$	2,260,416	$	3,931,905
Convertible debentures	—		—	—		—		346		346
Advances in aid of construction	1,165			—		—		59,663		60,828
Interest on long-term debt	185,231			318,469		257,443		992,116		1,753,259
Purchase obligations	458,288			—		—		—		458,288
Environmental obligation	14,970			20,850		1,128		21,536		58,484
Derivative financial instruments:
Cross-currency swap	4,149			69,099		3,851		4,666		81,765
Energy derivative and commodity contracts	1,631			909		—		359		2,899
Other obligations	39,115			2,120		2,696		109,094		153,025
Total obligations	$	1,306,577		$	880,187	$	865,839	$	3,448,196	$	6,500,799

25. Comparative figures

Certain of the comparative figures have been reclassified to conform to the financial statement presentation adopted in the current year.