Unaudited Interim Consolidated Financial Statements of

Algonquin Power & Utilities Corp.

For the three months ended March 31, 2017 and 2016

Algonquin Power & Utilities Corp.

Unaudited Interim Consolidated Balance Sheets

(thousands of Canadian dollars)
	March 31, 2017		December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	77,742	$	110,417
Accounts receivable, net (note 4)	292,097		189,658
Fuel and natural gas in storage	42,324		21,625
Supplies and consumables inventory	49,056		15,568
Regulatory assets (note 5)	62,674		48,440
Prepaid expenses	41,091		26,562
Derivative instruments (note 21)	17,170		76,631
Other assets	4,084		2,951
	586,238		491,852
Property, plant and equipment, net	8,199,059		4,889,946
Intangible assets, net	63,761		64,989
Goodwill (note 3(a))	1,296,733		306,641
Regulatory assets (note 5)	475,369		243,524
Derivative instruments (note 21)	80,073		74,553
Long-term investments (note 6)	89,458		105,433
Deferred income taxes (note 16)	50,850		30,005
Restricted cash	26,370		2,026,183
Other assets	12,780		16,334
	$	10,880,691	$	8,249,460

Algonquin Power & Utilities Corp.

Unaudited Interim Consolidated Balance Sheets

(thousands of Canadian dollars)
	March 31, 2017			December 31, 2016
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	74,805		$	90,592
Accrued liabilities	402,641			308,318
Dividends payable (note 13)	59,648			38,973
Regulatory liabilities (note 5)	51,159			47,769
Long-term debt (note 7)	20,066			10,075
Other long-term liabilities and deferred credits (note 9)	67,411			43,157
Other liabilities	14,207			7,665
	689,937			546,549
Long-term debt (note 7)	4,748,366			3,903,340
Convertible debentures (note 10)	5,196			358,619
Regulatory liabilities (note 5)	217,880			134,965
Deferred income taxes (note 16)	881,037			288,139
Derivative instruments (note 21)	112,431			104,647
Pension and other post-employment benefits obligation (note 8)	268,867			147,845
Other long-term liabilities (note 9)	318,871			232,449
Preferred shares, Series C	17,556			17,552
	6,570,204			5,187,556
Redeemable non-controlling interest	66,757			29,434
Equity:
Preferred shares	213,805			213,805
Common shares (note 11(a))	3,109,888			1,972,203
Additional paid-in capital	34,638			38,652
Deficit	(594,007		)	(556,024		)
Accumulated other comprehensive income (note 12)	228,084			254,927
Total equity attributable to shareholders of Algonquin Power & Utilities Corp.	2,992,408			1,923,563
Non-controlling interests	561,385			562,358
Total equity	3,553,793			2,485,921
Commitments and contingencies (note 19)
Subsequent events (notes 5, 6(a), 7, 14, 19(a), 21(b)(iv))
	$	10,880,691		$	8,249,460

See accompanying notes to unaudited interim consolidated financial statements

Algonquin Power & Utilities Corp.

Unaudited Interim Consolidated Statements of Operations

(thousands of Canadian dollars, except per share amounts)	Three Months Ended March 31
	2017			2016
Revenue
Regulated electricity distribution	$	240,065		$	63,396
Regulated gas distribution	196,119			164,279
Regulated water reclamation and distribution	42,930			41,173
Non-regulated energy sales	71,758			65,502
Other revenue	7,045			7,395
	557,917			341,745
Expenses
Operating expenses	148,877			85,102
Regulated electricity purchased	72,273			39,178
Regulated gas purchased	81,445			64,784
Regulated water purchased	2,659			2,757
Non-regulated energy purchased	7,305			5,615
Administrative expenses	14,648			11,418
Depreciation and amortization	82,705			49,725
Loss (gain) on foreign exchange	80			(302		)
	409,992			258,277
Operating income	147,925			83,468
Interest expense on convertible debentures and acquisition financing (notes 7(b) and 10)	17,637			5,863
Interest expense on long-term debt and others	46,925			19,200
Interest, dividend, equity and other income	(3,281		)	(2,596		)
Other gains	—			(1,216		)
Acquisition-related costs (note 3(a))	60,381			6,294
Loss on long-lived assets, net	23			6,185
Loss on derivative financial instruments (note 21(b)(iv))	1,382			942
	123,067			34,672
Earnings	24,858			48,796
Income tax expense (note 16)
Current	2,584			2,558
Deferred	16,788			15,946
	19,372			18,504
Net earnings	5,486			30,292
Net effect of non-controlling interests (note 15)	(20,473		)	(11,744		)
Net earnings attributable to shareholders of Algonquin Power & Utilities Corp.	$	25,959		$	42,036
Series A and D Preferred shares dividend (note 13)	2,600			2,600
Net earnings attributable to common shareholders of Algonquin Power & Utilities Corp.	$	23,359		$	39,436
Basic net earnings per share (note 17)	$	0.07		$	0.15
Diluted net earnings per share (note 17)	$	0.07		$	0.14

See accompanying notes to unaudited interim consolidated financial statements

Algonquin Power & Utilities Corp.

Unaudited Interim Consolidated Statements of Comprehensive Income

(thousands of Canadian dollars)	Three Months Ended March 31
	2017			2016
Net earnings	$	5,486		$	30,292
Other comprehensive income:
Foreign currency translation adjustment, net of tax recovery of $nil and $nil, respectively (notes 21(b)(iii) and 21(b)(iv))	(36,781		)	(158,547		)
Change in fair value of cash flow hedges, net of tax expense of $3,583 and $1,486, respectively (note 21(b)(ii))	5,232			21,566
Change in unrealized appreciation in value of available-for-sale investments	2			25
Change in pension and other post-employment benefits, net of tax expense of $35 and $92, respectively (note 8)	56			68
Other comprehensive loss, net of tax	(31,491		)	(136,888		)
Comprehensive loss	(26,005		)	(106,596		)
Comprehensive loss attributable to the non-controlling interests	(25,121		)	(34,017		)
Comprehensive loss attributable to shareholders of Algonquin Power & Utilities Corp.	$	(884	)	$	(72,579	)

See accompanying notes to unaudited interim consolidated financial statements

Algonquin Power & Utilities Corp.

Unaudited Interim Consolidated Statement of Equity

(thousands of Canadian dollars) For the three months ended March 31, 2017
	Algonquin Power & Utilities Corp. Shareholders
	Common shares		Preferred shares		Additional paid-in capital			Accumulated deficit			Accumulated OCI			Non- controlling interests			Total
Balance, December 31, 2016	$	1,972,203	$	213,805	$	38,652		$	(556,024	)	$	254,927		$	562,358		$	2,485,921
Net earnings (loss)	—		—		—			25,959			—			(20,473		)	5,486
Redeemable non-controlling interests not included in equity (note 15)	—		—		—			—			—			3,549			3,549
Other comprehensive loss	—		—		—			—			(26,843		)	(4,648		)	(31,491		)
Dividends declared and distributions to non-controlling interests	—		—		—			(53,231		)	—			(1,135		)	(54,366		)
Dividends and issuance of shares under dividend reinvestment plan	8,765		—		—			(8,765		)	—			—			—
Common shares issued upon conversion of convertible debentures	1,110,610		—		—			—			—			—			1,110,610
Common shares issued pursuant to share-based awards (note 11(b))	18,310		—		(6,369		)	(1,946		)	—			—			9,995
Share-based compensation	—		—		2,355			—			—			—			2,355
Contributions received from non-controlling interests	—		—		—			—			—			21,734			21,734
Balance, March 31, 2017	$	3,109,888	$	213,805	$	34,638		$	(594,007	)	$	228,084		$	561,385		$	3,553,793

See accompanying notes to unaudited interim consolidated financial statements

Algonquin Power & Utilities Corp.

Unaudited Interim Consolidated Statements of Cash Flows

(thousands of Canadian dollars)	Three Months Ended March 31
	2017			2016
Cash provided by (used in):
Operating Activities
Net earnings	$	5,486		$	30,292
Adjustments and items not affecting cash:
Depreciation and amortization	90,011			51,841
Deferred taxes	16,788			15,946
Unrealized loss (gain) on derivative financial instruments	2,363			(5,278		)
Share-based compensation expense	2,355			1,073
Cost of equity funds used for construction purposes	(549		)	(497		)
Pension and post-employment expense	13,939			2,158
Non-cash revenue and other income	(272		)	(1,590		)
Write-down of long-lived assets	—			6,185
Changes in non-cash operating items (note 20)	(46,297		)	(46,699		)
	83,824			53,431
Financing Activities
Increase in long-term debt	1,281,461			352,295
Decrease in long-term debt	(1,924,342		)	(24,444		)
Issuance of convertible debentures, net of costs	743,908			357,950
Cash dividends on common shares	(29,956		)	(32,607		)
Cash dividends on preferred shares	(2,600		)	(2,600		)
Cash contributions from non-controlling interests	53,405			—
Production-based cash contributions from non-controlling interest	9,124			9,454
Cash distributions to non-controlling interests	(206		)	(1,842		)
Issuance of common shares, net of costs	48			269
Proceeds from exercise of share options	12,761			19,493
Shares surrendered to fund withholding taxes on exercised share options	—			(5,218		)
Increase in other long-term liabilities	9,608			3,834
Decrease in other long-term liabilities	(3,575		)	(2,265		)
	149,636			674,319
Investing Activities
Decrease in restricted cash	2,006,151			4,542
Acquisitions of operating entities	(2,047,401		)	(333,084		)
Additions to property, plant and equipment	(201,769		)	(80,905		)
Increase in other assets	(737		)	(11,221		)
Distributions received in excess of equity income	(1,360		)	(2,766		)
Receipt of principal on notes receivable	—			11,690
Increase in long-term investments	(19,894		)	(114,212		)
	(265,010		)	(525,956		)
Effect of exchange rate differences on cash	(1,125		)	(17,029		)
Increase (decrease) in cash and cash equivalents	(32,675		)	184,765
Cash and cash equivalents, beginning of period	110,417			124,353
Cash and cash equivalents, end of period	$	77,742		$	309,118
Supplemental disclosure of cash flow information:	2017			2016
Cash paid during the period for interest expense	$	63,826		$	28,857
Cash paid during the period for income taxes	$	1,765		$	6,908
Non-cash financing and investing activities:
Property, plant and equipment acquisitions in accruals	$	106,329		$	16,507
Issuance of common shares under dividend reinvestment plan and share-based compensation plans	$	10,291		$	3,336
Issuance of common shares upon conversion of convertible debentures (note 10)	$	1,098,355		$	—

See accompanying notes to unaudited interim consolidated financial statements

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian 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 North American business units consisting of the Liberty Power Group and the Liberty Utilities Group. The Liberty Power Group owns and operates a diversified portfolio of non-regulated renewable and thermal electric generation assets; the Liberty Utilities Group owns and operates a portfolio of regulated electric, natural gas, water distribution and wastewater collection utility systems and transmission operations.

1. Significant accounting policies

(a)     Basis of preparation

The accompanying unaudited interim consolidated financial statements and notes have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and Article 10 of Regulation S-X provided by the U.S. Securities and Exchange Commission (“SEC”). In the opinion of management, the unaudited interim consolidated financial statements include all adjustments that are of a recurring nature and necessary for a fair presentation of the results of interim operations.

The significant accounting policies applied to these unaudited interim consolidated financial statements of APUC are consistent with those disclosed in the consolidated financial statements of APUC for the year ended December 31, 2016 except for adopted accounting policies described in note 2(a).

Effective January 1, 2017, the acquisition date, the unaudited consolidated results of The Empire District Electric Company ("Empire") are consolidated within APUC (note 3(a)). Empire’s accounting policies align with those used by APUC’s except certain Empire-specific policies including policies approved by the regulator as described below.

(b)     Seasonality

APUC's operating results are subject to seasonal fluctuations that could materially impact quarter-to-quarter operating results and, thus, one quarter's operating results are not necessarily indicative of a subsequent quarter's operating results. APUC’s hydroelectric energy assets are primarily “run-of-river” and as such fluctuate with the natural water flows. During the winter and summer periods, flows are generally slower, while during the spring and fall periods flows are heavier. For APUC's wind energy assets, wind resources is typically stronger in spring, fall and winter and weaker in summer. APUC's solar energy assets experience greater insolation in summer, weaker in winter. APUC’s water and wastewater utility assets’ revenues fluctuate depending on the demand for water. During drier, hotter periods of the year, which occurs generally in the summer, demand for water is typically higher than during cooler, wetter periods of the year. During the winter period, natural gas distribution utilities experience higher demand than during the summer period. Where decoupling mechanisms exist, total volumetric revenue is prescribed by the Regulator and fluctuates based on usage while total fixed revenue will not fluctuate through the year. Different electrical distribution utilities can experience higher or lower demand in the summer or winter depending on the specific regional weather, industry characteristics and existence of a decoupling mechanism.

(c)     Commonly owned facilities

Empire 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 Empire's customers. Empire's investment in the undivided interest is recorded as plant in service and recovered through rate base. Empire's share of operating costs are recognized in operating, maintenance and fuel expenditures excluding depreciation expense.

As at March 31, 2017 the following amounts related to commonly owned facilities were recognized in the unaudited interim consolidated financial statements:

Cost of ownership in plant in service	$	871,115
Accumulated Depreciation	$	230,777
Expenditures	$	26,819

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

2.     Recently issued accounting pronouncements

(a) Recently adopted accounting pronouncements    

The FASB issued ASU 2016-17 Consolidation (Topic 810): Interests Held through Related Parties That Are under Common Control. This update amends the consolidation guidance on how a reporting entity that is the single decision maker of a VIE should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. The adoption of this update in the first quarter of 2017 had no impact on the Company's unaudited interim consolidated financial statements.

The FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718), to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The adoption of this update in the first quarter of 2017 had no material impact on the Company's unaudited interim consolidated financial statements. The Company continues to record the stock-based compensation expense adjusted for estimated forfeitures.

The FASB issued ASU 2016-06, Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments, to clarify the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts, which is one of the criteria for bifurcating an embedded derivative. An entity performing the assessment under the amendments in this Update is required to assess the embedded call (put) options solely in accordance with the four-step decision sequence. The adoption of this update in the first quarter of 2017 had no impact on the Company's unaudited interim consolidated financial statements.

The FASB issued ASU 2016-05, Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships, to clarify that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument does not, in and of itself, require dedesignation of that hedging relationship provided that all other hedge accounting criteria continue to be met. The adoption of this update in the first quarter of 2017 had no impact on the Company's unaudited interim consolidated financial statements.

The FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, to simplify the subsequent measurement of inventory by replacing the current lower of cost and market test with a lower of cost and net realizable value test. The adoption of this update in the first quarter of 2017 had no impact on the Company's unaudited interim consolidated financial statements.

(b) Recently issued accounting guidance not yet adopted

The FASB issued ASU 2017-07 Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, to improve the reporting of defined benefit pension cost and postretirement benefit cost (net benefit cost) in the financial statements. This update requires the service cost component to be reported in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The update will also only allow the service cost component to be eligible for capitalization when applicable. The update is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is permitted. The adoption of the presentation component of the standard will change the presentation of net benefit cost in the Company's consolidated statements of operations. The Company is currently in the process of evaluating the impact of adoption of this standard on the eligibility for capitalization of the other components of net benefit cost on its consolidated financial statements, given the application of ASC 980 Regulated Operations and ongoing regulatory developments.

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian 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 2017-05 Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. The update clarifies the scope of the standard as well as provides additional guidance on partial sales of nonfinancial assets. The update is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is permitted however the update must be adopted at the same time as ASU 2014-09. The Company is currently in the process of evaluating the impact of adoption of this update on its consolidated financial statements.

The FASB issued a new revenue recognition standard codified as ASC 606, Revenue from Contracts with Customers. This newly issued accounting standard provides accounting guidance for all revenue arising from contracts with customers and affects all entities that enter into contracts to provide goods or services to their customers unless the contracts are in the scope of other U.S. GAAP requirements, such as the leasing literature. The core principal of the new accounting guidance is that an entity should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASC 606 will also require significantly expanded disclosures regarding the qualitative and quantitative information of the Company's nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. This new revenue standard is required to be applied for fiscal years and interim periods beginning after December 15, 2017 using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach. The Company has not elected to early adopt. The Company has identified existing customer contracts and tariffs that are within the scope of the new guidance and has in the process of conducting an assessment in order to determine the method of adoption and the impact it may have on its consolidated financial statements. The Company also closely monitors outstanding industry specific interpretative issues, including contributions in aid of construction and collectability of sales to low income customers.

3. Business acquisitions and development projects

(a) Acquisition of Empire

On January 1, 2017, the Company completed the acquisition of Empire, a Joplin, Missouri based regulated electric, gas and water utility, serving customers in Missouri, Kansas, Oklahoma and Arkansas. 

The purchase price of approximately U.S. $2,414,000 for the acquisition of Empire consists of cash payments to Empire shareholders of U.S. $34.00 per common share and the assumption of approximately U.S. $855,000 of debt. The cash payment was funded with the acquisition facility for an amount of U.S. $1,336,440 (note 7(b)), proceeds received from the initial instalment of convertible debentures (note 10) and an existing credit facility. The costs related to the acquisition have been expensed through the consolidated statements of operations.

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

3. Business acquisitions and development projects (continued)

(a) Acquisition of Empire (continued)

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

Working capital	$	52,594
Property, plant and equipment	2,763,612
Goodwill	1,001,570
Regulatory assets	258,143
Other assets	50,750
Long-term debt	(1,218,563		)
Regulatory liabilities	(104,896		)
Pension and other post-employment benefits	(107,907		)
Deferred income tax liability, net	(569,358		)
Other liabilities	(103,320		)
Total net assets acquired	$	2,022,625
Cash and cash equivalent	$	2,338
Total net assets acquired, net of cash and cash equivalent	$	2,020,287

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 acquisition, the Company has not completed the fair value measurements, particularly the relative fair value of each of the individual utilities acquired.  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 the 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 the Empire's assets is 39 years.

The table below presents the unaudited consolidated pro forma revenue and net income for the three months ended March 31, 2017 and 2016, assuming the acquisition of Empire had occurred on January 1, 2016. Pro forma net income includes the impact of fair value adjustments incorporated in the preliminary purchase price allocation above and adjustments necessary to reflect the financing costs as if the acquisition had been financed on January 1, 2016. However, non-recurring acquisition-related expenses are excluded from net income.

	Three Months Ended March 31
	2017		2016
Revenues	$	557,917	$	549,674
Net income attributable to common shareholders	$	80,598	$	66,549

This pro forma information does not purport to represent what the actual results of operations of the Company would have been had the acquisition occurred on this date nor does it purport to predict the results of operations for future periods.

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

3. Business acquisitions and development projects (continued)

(b) Luning Solar Facility

On February 15, 2017, Luning Utilities (Luning Holdings) LLC (the “Luning Holdings”) obtained control of the Luning Solar Facility upon achieving commercial operation. Luning Holdings is owned by the Calpeco Electric System, a regulated electric distribution utility of the Company. The Luning Solar Facility is a 50MWac solar generating facility located in Mineral County, Nevada acquired for a total purchase price of U.S.$110,856. The Class A tax equity investor funded approximately U.S. $39,000 of the acquisition cost and will receive the majority of the tax attributes associated with the Luning Solar project.

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

Working capital	$	198
Property, plant and equipment	145,045
Asset retirement obligation	(714		)
Non-controlling interest (tax equity)	(50,548		)
Total net assets acquired	$	93,981

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 acquisition, the Company has not completed the fair value measurements.

The Company accounts for this interest as “Redeemable non-controlling interest” outside of permanent equity on the consolidated balance sheets. Redemption is not considered probable as of March 31, 2017.

(c) Bakersfield II Solar Facility

On December 14, 2016, the Company completed construction and placed in service a 10 MWac solar powered generating facility located adjacent to the Company’s 20 MWac Bakersfield I Solar Facility in Kern County, California (“Bakersfield II Solar Facility”). Commercial operations as defined by the power purchase agreement was reached on January 11, 2017.

The Bakersfield II Solar Facility is controlled by a subsidiary of APUC (the “Bakersfield II Partnership”). The Class A partnership units are owned by a third-party tax equity investor who funded U.S. $2,454 on November 29, 2016 and approximately U.S. $9,800 on February 28, 2017. 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.

4. Accounts receivable

Accounts receivable as of March 31, 2017 include unbilled revenue of $70,838 (December 31, 2016 - $57,822) from the Company’s regulated utilities. Accounts receivable as of March 31, 2017 are presented net of allowance for doubtful accounts of $9,763 (December 31, 2016 - $7,064).

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

5. Regulatory matters

The Company’s regulated utility operating companies are subject to regulation by the public utility commissions of the states 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 state 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.

On January 1, 2017, the Company completed the acquisition of Empire, an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of its electric segment, Empire also provides water service to three towns in Missouri. The Empire District Gas Company a wholly owned subsidiary is engaged in the distribution of natural gas in Missouri. These businesses are subject to regulation by the Missouri Public Service Commission, the State Corporation Commission of the State of Kansas, the Corporation Commission of Oklahoma, the Arkansas Public Service Commission and the Federal Energy Regulatory 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.

Subsequent to quarter-end, in April 2017, the Massachusetts Department of Public Utilities approved a rate increase of U.S. $2,928 for the New England Natural Gas Company, for its 2017 gas system enhancement plan. The rates are effective May 1, 2017.

Subsequent to quarter-end, in April 2017, the State of Iowa Department of Commerce Utilities Board approved a rate increase of U.S. $987 for Midstates Natural Gas. New rates are expected to be effective either June or July 2017.

In June 2016, the New Hampshire Public Utility Commission approved a temporary annual rate increase for the Granite State Electric System of U.S. $2,355, effective July 1, 2016. Subsequent to quarter-end, on April 12, 2017, the New Hampshire Public Utility Commission approved a Final Order of a total U.S. $3,750 annual revenue increase retroactive to July 1, 2016, and a U.S. $2,474 step adjustment for plant additions made in 2016, effective May 1, 2017.In March 2017, the Arizona Corporate Commission approved a rate increase of U.S. $152 for Entrada Del Oro Sewer, effective April 1, 2017.

On January 31, 2017, the Georgia Public Service Commission approved a Final Order for the Peach State Gas System of a U.S. $686 annual revenue increase effective February 1, 2017.

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

5. Regulatory matters (continued)

Regulatory assets and liabilities consist of the following: 

	March 31, 2017			December 31, 2016
Regulatory assets
Environmental remediation	$	104,063		$	104,160
Pension and post-employment benefits	141,927			75,527
Debt premium	102,562			25,173
Fuel and commodity costs adjustments	14,197			6,972
Rate adjustment mechanism	27,997			40,602
Clean Energy and other customer programs	24,645			2,106
Deferred construction costs (a)	19,372			—
Asset retirement	18,870			2,113
Income taxes	36,195			10,182
Rate case costs	14,022			8,572
Other	34,193			16,557
Total regulatory assets	$	538,043		$	291,964
Less current regulatory assets	(62,674		)	(48,440		)
Non-current regulatory assets	$	475,369		$	243,524
Regulatory liabilities
Cost of removal	$	159,737		$	110,330
Rate-base offset	19,948			20,946
Fuel and commodity costs adjustments	35,807			33,891
Deferred compensation received in relation to lost production	14,781			—
Deferred construction costs -fuel related (a)	9,990			—
Pension and post-employment benefits	8,065			5,481
Income Taxes	7,136			1,501
Other	13,575			10,585
Total regulatory liabilities	$	269,039		$	182,734
Less current regulatory liabilities	(51,159		)	(47,769		)
Non-current regulatory liabilities	$	217,880		$	134,965

(a) Deferred construction costs reflects deferred costs from Empire's 2005 regulatory plan related to construction costs and fuel related costs of specific generating facilities. These amounts are being recovered over the life of the plants.

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

6. Long-term investments

Long-term investments consist of the following:

	March 31, 2017		December 31, 2016
Equity-method investees
Red Lily	24,215		23,504
Deerfield Wind Project (a)	—		34,727
Amherst Island Wind Project	763		558
Other	6,020		5,630
	$	30,998	$	64,419
Notes receivable
Development loans (b)	$	49,616	$	32,125
Other	6,034		6,058
	55,650		38,183
Available-for-sale investment	169		169
Other investments	2,641		2,662
Total long-term investments	$	89,458	$	105,433

(a)Deerfield Wind Project

Up to March 14, 2017, the Company held a 50% equity interest in Deerfield Wind SponsorCo LLC (“Deerfield SponsorCo”), which indirectly owns a 150 MW construction-stage wind development project (“Deerfield Wind Project”) in the state of Michigan.

On October 12, 2016, third-party construction loan financing was provided to the Deerfield Wind Project in the amount of U.S. $262,900 and a tax equity contribution agreement was executed. Construction was completed during the quarter and sale of power to the utility under the power purchase agreement started on February 21, 2017. Subsequent to quarter-end, on May 10, 2017, tax equity funding of U.S. $166,595 was received.

On March 14, 2017, the Company acquired the remaining 50% interest in Deerfield SponsorCo for U.S. $21,585 and as a result, obtained control of the facility. The Company accounted for the business combination using the acquisition method of accounting which requires that the fair value of assets acquired and liabilities assumed in the subsidiary be recognized on the consolidated balance sheet as of the acquisition date. It further requires that pre-existing relationships such as the existing development loan between the two parties (note 6(b)) and prior investments of business combinations achieved in stages also be remeasured at fair value. An income approach was used to value these items. A net gain of $nil was recorded on acquisition.

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

Working capital	$	(14,551	)
Property, plant and equipment	442,086
Construction loan	(352,666		)
Asset retirement obligation	(2,816		)
Deferred revenue	(1,556		)
Deferred tax liability	(1,979		)
Net assets acquired	$	68,518
Cash and cash equivalent	4,183
Net assets acquired, net of cash and cash equivalent	$	64,335

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

6. Long-term investments (continued)

(b) Development loans

As at March 31, 2017, the Company has a loan and credit support facility with Windlectric. During construction, the Company provides Windlectric with cash advances and credit support (in the form of letters of credit, escrowed cash, or guarantees) in amounts necessary for the continued development and construction of the Wind Projects. The loan bears interest at an annual rate of 10% on outstanding principal amount and matures on December 31, 2018 .

As of December 31, 2016, the Company had outstanding loans of U.S. $1,789from Deerfield SponsorCo. Following acquisition of control of Deerfield SponsorCo LLC (note 6(a)), amounts advanced to the Deerfield Wind Project were eliminated on consolidation. The effects of foreign currency exchange rate fluctuations on these advances of a long-term investment nature are recorded in other comprehensive income effective March 14, 2017.

No interest revenue was accrued on the loans due to insufficient collateral in the Joint Ventures.

7. Long-term debt

Long-term debt consists of the following:

Borrowing type	March 31, 2017			December 31, 2016
Senior Unsecured Revolving Credit Facilities (a)	$	233,087		$	242,947
Senior Unsecured Bank Credit Facilities (b)	209,606			2,140,122
Canadian Dollar Borrowings
Senior Unsecured Notes (c)	780,405			487,389
Senior Secured Project Notes	35,043			35,600
U.S. Dollar Borrowings
Senior Unsecured Notes (d)	1,686,518			700,600
Senior Unsecured Utility Notes (e)	336,836			174,206
Senior Secured Utility Bonds (f)	1,137,923			132,551
Senior Secured Project Notes (g)	349,014			—
	$	4,768,432		$	3,913,415
Less: current portion	(20,066		)	(10,075		)
	$	4,748,366		$	3,903,340

Long-term debt issued at a subsidiary level relating to a specific operating facility is generally collateralized by the respective facility with no other recourse to the Company. Long-term debt whether or not collateralized have 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.

(a) Senior unsecured revolving credit facilities

In connection with the acquisition of Empire (note 3(a)), the Company assumed a U.S. $200,000 5-year Credit Agreement which expires in October 2019, and includes two one-year extensions of the credit facility’s maturity date. The Empire Facility is used primarily to provide credit support to Empire's commercial paper program.

Subsequent to quarter end, the Liberty Power Group entered into a $150,000 bilateral revolving credit facility. The new facility matures on May 19, 2018.

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

7. Long-term debt (continued)

(b) Senior unsecured bank credit facilities

On December 30, 2016, in connection with the acquisition of Empire (note 3(a)), the Company drew U.S. $1,336,440 from the acquisition facility it obtained from a syndicate of banks earlier in 2016. The funds drawn were transferred to a paying agent on December 30, 2016 for purposes of distribution to holders of the common shares of Empire (note 3(a)) on January 1, 2017. Following receipt of the Final Instalment from the convertible debentures on February 7, 2017 (note 10) and the senior notes financing on March 24, 2017 (note 7(d)), the Company fully repaid the acquisition Facility.

On March 24, 2016, the Company repaid U.S. $100,000 of borrowings under the Corporate Term Facility with proceeds from the closing of the U.S. $750,000 senior unsecured notes (notes 7(d)).

(c) Canadian dollar senior unsecured notes

On January 17, 2017, the Liberty Power Group issued $300,000 senior unsecured debentures bearing interest at 4.09% and with a maturity date of February 17, 2027. The debentures were sold at a price of $99.929 per $100.00 principal amount.

(d) U.S. dollar senior unsecured notes

On March 24, 2017, Liberty Utilities Group's financing entity issued U.S. $750,000 senior unsecured notes in six tranches. The proceeds were applied to repay the acquisition facility (note 7(b)) and other existing indebtedness. The notes are of varying maturities from 3 to 30 years with a weighted average life of approximately 15 years and a weighted average coupon of 4.0%. In anticipation of the financing, the Liberty Utilities Group had entered into forward contracts to lock in the underlying U.S. Treasury interest rates. Considering the effect of the hedges, the effective weighted average rate paid by the Liberty Utilities Group will be 3.6%.

(e) U.S. dollar senior unsecured utility notes

On February 8, 2017, the U.S. $707 Bella Vista Water unsecured utility notes were fully repaid.

On January 1, 2017, in connection with the acquisition of Empire (note 3(a)), the Company assumed U.S. $102,000 in unsecured utility notes. The notes consist of two tranches, with maturities in 2033 and 2035 with coupons at 6.7% and 5.8%.

(f) U.S. dollar senior secured utility bonds

On January 1, 2017 in connection with the acquisition of Empire (note 3(a)), the Company assumed U.S. $733,000 in secured utility notes. The bonds are secured by a first mortgage indenture and consist of ten tranches with maturities ranging between 2018 and 2044 with coupons ranging from 3.58% to 6.82%.

(g) U.S. dollar senior secured project notes

On March 14, 2017, in connection with the acquisition of Deerfield SponsorCo (note 6(a)), the Company assumed U.S. $262,219 in construction loan. The loans bear interest at an annual rate of 2.33% on any outstanding principal amount. Subsequent to quarter-end on May 10, 2017, the construction loan was repaid from proceeds received from tax equity (note 6(a)) and cash contributions from APUC.

8. Pension and other post-employment benefits

In connection with the acquisition of Empire, the Company assumed pension and OPEB obligations of $107,907. Empire District Electric provides the following plans to employees:

• A noncontributory defined benefit pension plan for all employees hired before January 1, 2014 meeting minimum age and service requirements.

• A cash balance defined benefit pension plan for all employees hired after January 1, 2014.

• A supplemental retirement program (“SERP”) for designated officers of Empire. The SERP plan was frozen effective January 1, 2017.

• Certain healthcare and life insurance benefits to eligible retired employees, their dependents and survivors. Participants generally become eligible for retiree healthcare benefits after reaching age 55 with 5 years of service. Employees hired after January 1, 2014 are offered unsubsidized retiree healthcare benefits upon retirement.

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

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

The following table outlines the aggregate financial position for the key plans as at January 1, 2017:

	Pension benefits			SERP			OPEB
Projected benefit obligation	$	329,158		$	17,073		$	131,264
Fair value of Plan Assets	247,740			—			122,900
Unfunded status	$	(81,418	)	$	(17,073	)	$	(8,364	)

Empire has rate orders with Missouri, Kansas and Oklahoma allowing the recovery of pension costs. As a result, Empire records the Missouri, Kansas and Oklahoma portion of any costs above or below the amount included in rates as a regulatory asset or liability, respectively.

The following table lists the components of net benefit costs for the pension plans and other post-employment benefits ("OPEB") recorded as part of operating expenses in the unaudited interim consolidated statements of operations. The employee benefit costs related to businesses acquired are recorded in the unaudited interim consolidated statements of operations from the date of acquisition.

	Pension benefits						OPEB
	Three Months Ended March 31						Three Months Ended March 31
	2017			2016			2017			2016
Service cost	$	4,762		$	2,030		$	1,690		$	815
Interest cost	6,597			3,376			2,212			921
Expected return on plan assets	(8,345		)	(3,512		)	(2,143		)	(319		)
Amortization of net actuarial loss	354			656			(48		)	131
Amortization of prior service credits	(206		)	(151		)	(87		)	(477		)
Amortization of regulatory asset/liability	3,522			1,142			171			267
Net benefit cost	$	6,684		$	3,541		$	1,795		$	1,338

9. Other long-term liabilities and deferred credits

Other long-term liabilities consist of the following: 

	March 31, 2017			December 31, 2016
Advances in aid of construction	$	109,188		$	105,191
Environmental remediation obligations	65,835			63,378
Asset retirement obligations	61,000			24,822
Customer deposits	35,591			14,881
Unamortized investment tax credits	23,957			—
Hook up fees	13,204			12,039
Deferred income	1,538			—
Deferred credits	44,188			44,544
Other	31,781			10,751
	386,282			275,606
Less current portion	(67,411		)	(43,157		)
	$	318,871		$	232,449

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

9. Other long-term liabilities and deferred credits (continued)

In connection with the acquisition of Empire, the Company assumed certain asset retirement obligations. Asset retirement obligations mainly relate to legal requirements to: (i) remove certain river water intake structures and equipment; (ii) disposal of coal combustion residuals and Polychlorinated Biphenyls (PCB) contaminants; and (iii) remove asbestos upon major renovation or demolition of structures and facilities.

As the cost of retirement of asset are expected to be recovered through rates, a corresponding regulatory asset is recorded, as well as the on-going liability accretion and asset depreciation expense.

In connection with the acquisition of Empire, the Company assumed investment tax credits based on the investment made in a generating station, which, if unused, will expire in 2030. Management expects to use these credits to offset future income tax liabilities. The tax credits will have no significant income statement impact because they will flow to customers as the tax credits are amortized over the life of the plant.

10. Convertible Unsecured Subordinated Debentures

Maturity date	March 31, 2026
Interest rate	5.00		%
Conversion price per share	$	10.60
Carrying value at December 31, 2016	$	358,619
Receipt of Final instalment, net of deferred financing costs	743,908
Amortization of deferred financing costs	1,024
Conversion to common shares	$	(1,098,355	)
Carrying value at March 31, 2017	$	5,196
Face value at March 31, 2017	$	5,401

In March 2016, the Company completed the sale of $1,150,000 aggregate principal amount of 5.0% convertible debentures.

The convertible debentures were sold on an instalment basis at a price of $1,000 principal amount of debenture, of which $333 was received on closing of the debenture offering and the remaining $667 (the “Final Instalment”) was received on February 2, 2017 (“Final Instalment Date”) following satisfaction of conditions precedent to the closing of the acquisition of Empire (note 3(a)). The proceeds received from the initial and final instalments, net of financing costs were $357,694 and $743,908, respectively. As the Final Instalment Date occurred prior to the first anniversary of the closing of the debenture offering, holders of the convertible debentures who paid the final instalment by February 2, 2017 received, in addition to the payment of accrued and unpaid interest, a make-whole payment, representing the interest that would have accrued from the day following the Final Instalment Date up to and including March 1, 2017. The interest expense recorded for the three months ended March 31, 2017 is $9,373 (2016 - $4,884).

The debentures are convertible into up to 108,490,566 common shares. As at March 31, 2017, a total of 107,981,056 common shares of the Company were issued (note 11), representing conversion into common shares of more than 99.53% of the convertible debentures.

The remaining convertible debentures mature on March 31, 2026 and bear interest at an annual rate of 0% per $1,000 principal amount of convertible debentures.

After the Final Instalment Date, any debentures not converted into common shares may be redeemed by the Company at a price equal to their principal amount plus any unpaid interest, which accrued prior to and including the Final Instalment Date. At maturity, the Company will have the right to pay the principal amount due in cash or in common shares. In the case of common shares, such shares will be valued at 95% of their weighted average trading price on the Toronto Stock Exchange for the 20 consecutive trading days ending five trading days preceding the maturity date.

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

11. Shareholders’ capital

(a) Common shares

Number of common shares: 

	2017
Common shares, beginning of year	274,087,018
Issuance of common shares upon conversion of convertible debentures (note 10)	107,981,056
Issuance of common shares upon exercise of share options, net of withholding taxes	1,469,362
Issuance of shares under the dividend reinvestment and employee share compensation plans	1,134,849
Common shares, end of period	384,672,285

(b) Share-based compensation

During the three months ended March 31, 2017, the Board of Directors of APUC (the "Board") approved the grant of 2,328,343 options to executives of the Company. The options allow for the purchase of common shares at a weighted average price of $12.82, the market price of the underlying common share at the date of grant. One-third of the options vest on each of January 1, 2018, 2019, and 2020. Options may be exercised up to eight years following the date of grant.

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

Risk-free interest rate	1.42		%
Expected volatility	25		%
Expected dividend yield	4.25		%
Expected life	5.5
Weighted average grant date fair value per option	$	1.45

In March 2017, executives of the Company exercised 1,469,362 stock options at a weighted average exercise price of $7.81 in exchange for common shares issued from treasury and 165,139 options were settled at their cash value as payment for tax withholdings related to the exercise of the options.

In March 2017, 253,809 Performance Share Units ("PSU") were granted to executives of the Company. The PSUs vest on January 1, 2020. During the quarter, the Company settled 173,499 PSU in exchange for common shares issued from treasury and 182,463 PSUs were settled at their cash value as payment for tax withholdings related to the settlement of the PSUs.

During the three months ended March 31, 2017, 14,652 Deferred Share Units (“DSU”) were issued pursuant to the election of the Directors to defer a percentage of their Directors' fee in the form of DSUs.

For the three months ended March 31, 2017, APUC recorded $2,255 (2016 -$1,010 ) in total share-based compensation expense. The compensation expense is recorded as part of administrative expenses in the unaudited interim consolidated statements of operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant.

As of March 31, 2017, total unrecognized compensation costs related to non-vested options and PSUs were $6,051 and $5,116, respectively, and are expected to be recognized over a period of 2.03 and 2.29 years, respectively.

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

12.Accumulated Other comprehensive income (loss)

AOCI consists of the following balances, net of tax:

	Foreign currency cumulative translation			Unrealized gain on cash flow hedges			Net change on available-for-sale investments			Pension and post-employment actuarial changes			Total
Balance, January 1, 2016	$	261,357		$	39,329		$	(72	)	$	(13,877	)	$	286,737
OCI (loss) before reclassifications	(61,029		)	34,308			213			1,648			(24,860		)
Amounts reclassified	—			(7,554		)	—			604			(6,950		)
Net current period OCI	(61,029		)	26,754			213			2,252			(31,810		)
Balance, December 31, 2016	$	200,328		$	66,083		$	141		$	(11,625	)	$	254,927
OCI (loss) before reclassifications	(32,133		)	7,509			2			—			(24,622		)
Amounts reclassified	—			(2,277		)	—			56			(2,221		)
Net current period OCI	$	(32,133	)	$	5,232		$	2		$	56		$	(26,843	)
Balance, March 31, 2017	$	168,195		$	71,315		$	143		$	(11,569	)	$	228,084

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

13. Dividends

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

	Three Months Ended March 31
	2017				2016
	Dividend		Dividend per share		Dividend		Dividend per share
Common shares	$	59,395	$	0.1533	$	34,960	$	0.1287
Series A preferred shares	$	1,350	$	0.2813	$	1,350	$	0.2813
Series D preferred shares	$	1,250	$	0.3125	$	1,250	$	0.3125

14. Related party transactions

Emera Inc.

A member of the Board of APUC is an executive at Emera. During the three months ended March 31, 2017, the Energy Services Business sold electricity to Maine Public Service Company and Bangor Hydro, both of which are subsidiaries of Emera, amounting to U.S. $2,981 (2016 - U.S. $2,606). During the three months ended March 31, 2017, the Liberty Utilities Group purchased natural gas amounting to U.S. $877 (2016 - U.S. $1,913) from Emera for its gas utility customers. Both the sale of electricity to Emera and the purchase of natural gas from Emera followed a public tender process, the results of which were approved by the regulator in the relevant jurisdiction. In 2016, a subsidiary of the Company and Emera Utility Services Inc. entered into a design, engineering, supply, and construction agreement for the Tinker transmission upgrade project. The transmission upgrade was placed in service in April 2017 with final completion of the contract work expected in June 2017.  The total cost of the contract is estimated at  $8,809. The contract followed a market based request for proposal process.

There was U.S. $2,576 included in accruals for the three months ended March 31, 2017 (2016 - U.S. $261) related to these transactions.

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

14. Related party transactions (continued)

Equity-method investments

The Company provides administrative services to its equity-method investees and is reimbursed for incurred costs. To that effect, the Company charged its equity-method investees $439 (2016 - $748) during the three months ended March 31, 2017.

Trafalgar

In 2016, the Company received U.S. $10,083 in proceeds from the settlement of the Trafalgar matter, and paid U.S.$2,900 to an entity partially and indirectly owned by Senior Executives as its proportionate share. The gain to APUC, net of legal and other liabilities, of approximately U.S. $6,600 was recorded in 2016.

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 18MW Long Sault Hydro Facility.  A final post-closing adjustment related to the transaction is expected to be settled in 2017.

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

15. Non-controlling interests and Redeemable non-controlling interest

Net loss attributable to non-controlling interests for the three months ended March 31 consists of the following:

	2017			2016
HLBV and other adjustments attributable to:
Non-controlling interest -Class A partnership units	$	(17,985	)	$	(12,043	)
Non-controlling interest -redeemable Class A partnership units	(3,549		)	(1,388		)
Other net earnings attributable to non-controlling interests	1,061			1,687
Net effect of non-controlling interests	$	(20,473	)	$	(11,744	)

16. Income taxes

For the three months endedMarch 31, 2017, the Company’s overall effective tax rate was different from the statutory rate of 26.50% (2016 - 26.50%) due primarily to higher tax rates in U.S. subsidiaries, non-controlling interest partner’s tax expenses, inter-corporate dividends and non-deductible expenses.

17. 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 subscription receipts outstanding in 2016. Diluted net earnings per share is computed using the weighted-average number of common shares, subscription receipts outstanding in 2016, additional shares issued subsequent to year-end under the dividend reinvestment plan, PSUs 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. The convertible debentures (note 10) are convertible into common shares at any time after the Final Instalment Date, but prior to maturity or redemption by the Company. The Final Instalment Date occurred on February 2, 2017, and as such, the shares issuable upon conversion of the convertible debentures are included in diluted earnings per share beginning on that date.

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

17. Basic and diluted net earnings per share (continued)

The reconciliation of the net earnings and the weighted average shares used in the computation of basic and diluted earnings per share for the three months ended March 31 are as follows:

	2017		2016
Net earnings attributable to shareholders of APUC	$	25,959	$	42,036
Series A Preferred shares dividend	1,350		1,350
Series D Preferred shares dividend	1,250		1,250
Net earnings attributable to common shareholders of APUC – Basic and Diluted	$	23,359	$	39,436
Weighted average number of shares
Basic	343,549,831		268,565,782
Effect of dilutive securities	3,102,922		3,566,763
Diluted	346,652,753		272,132,545

The shares potentially issuable as a result of 1,129,168 share options (2016 - 3,937,340) are excluded from this calculation as they are anti-dilutive.

18. Segmented information

In connection with the acquisition of Empire on January 1, 2017, the Company aligned its management reporting under two primary North American business units consisting of the Liberty Power Group and the Liberty Utilities Group. The two business units are the two segments of the Company.

The Liberty Power Group owns and operates a diversified portfolio of non-regulated renewable and thermal electric generation utility assets; the Liberty Utilities Group owns and operates a portfolio of regulated electric, natural gas, water distribution and wastewater collection utility systems and transmission operations.

For purposes of evaluating divisional performance, the Company allocates the realized portion of any gains or losses on financial instruments to specific divisions. The unrealized portion of any gains or losses on derivative instruments not designated in a hedging relationship is not considered in management’s evaluation of divisional performance and is therefore allocated and reported in the corporate segment. The results of operations and assets for these segments are reflected in the tables below. The results of operations and assets for these new segments are reflected in the tables below. The comparative information for 2016 has been reclassified to conform with the composition of the reporting segments presented in the current year.

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

18. Segmented information (continued)

	Three Months Ended March 31, 2017
	Liberty Power Group			Liberty Utilities Group			Corporate			Total
Revenue	$	76,702		$	481,215		$	—		$	557,917
Fuel, power and water purchased	7,305			156,377			—			163,682
Net revenue	69,397			324,838			—			394,235
Operating expenses	19,199			129,678			—			148,877
Administrative expenses	4,293			9,466			889			14,648
Depreciation and amortization	26,195			56,176			334			82,705
Gain on foreign exchange	—			—			80			80
Operating income (loss) from continuing operations	19,710			129,518			(1,303		)	147,925
Interest expense	11,058			27,415			26,089			64,562
Interest, dividend, equity and other income	(1,220		)	(1,321		)	(740		)	(3,281		)
Other expenses (gain)	1,589			(183		)	60,380			61,786
Earnings (loss) before income taxes	$	8,283		$	103,607		$	(87,032	)	$	24,858
Property, plant and equipment	$	2,896,605		$	5,258,224		$	44,230		$	8,199,059
Equity-method investees	25,230			1,064			4,704			30,998
Total assets	3,213,853			7,563,965			102,873			10,880,691
Capital expenditures	19,026			182,743			—			201,769

	Three Months Ended March 31, 2016
	Liberty Power Group			Liberty Utilities Group			Corporate			Total
Revenue	$	72,362		$	269,383		$	—		$	341,745
Fuel and power purchased	5,615			106,719			—			112,334
Net revenue	66,747			162,664			—			229,411
Operating expenses	16,280			68,822			—			85,102
Administrative expenses	4,905			5,430			1,083			11,418
Depreciation and amortization	21,388			27,999			338			49,725
Gain on foreign exchange	—			—			(302		)	(302		)
	24,174			60,413			(1,119		)	83,468
Interest expense	5,943			12,738			6,382			25,063
Interest, dividend and other income	(514		)	(1,220		)	(862		)	(2,596		)
Other expense (gain)	289			6,048			5,868			12,205
Earnings (loss) before income taxes	$	18,456		$	42,847		$	(12,507	)	$	48,796
Capital expenditures	42,396			38,509			—			80,905
	December 31, 2016
Property, plant and equipment	$	2,455,336		$	2,390,047		$	44,563		$	4,889,946
Equity-method investees	59,021			914			4,484			64,419
Total assets	2,771,651			5,388,966			88,843			8,249,460

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

19.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 financial statements. Accruals for any contingencies related to these items are recorded in the unaudited interim consolidated financial statements at the time it is concluded that its occurrence is probable and the related liability is estimable.

Empire is subject to various federal, state, and local laws and regulations with respect to air and water quality and with respect to hazardous and toxic materials or other wastes, including their identification, transportation, disposal, record-keeping and reporting, as well as remediation of contaminated sites and other environmental matters. Management believes that operations are in material compliance with present environmental laws and regulations. Currently it is not possible to accurately estimate compliance costs for any new requirements, it is expected that these costs might be material, although recoverable in rates.

Condemnation Expropriation Proceedings

Mountain Water is currently the subject of a condemnation lawsuit filed by the city of Missoula.  On August 2, 2016, the Supreme Court of Montana upheld the District Court’s decision that the city of Missoula can proceed with condemnation of Mountain Water’s assets.  Upon taking possession of Mountain Water’s assets, the compensation to be paid by the city of Missoula for such taking will be the value of the utility (determined by the valuation commissioners on November 17, 2015 to be U.S. $88,600 as of May 6, 2014). Mountain Water is expected to receive certain additional amounts that may include legal fees, interest, post-valuation capital expenditures and property tax reimbursement.

On December 22, 2015, various developers filed a lawsuit in Missoula County District Court against Mountain Water and the city of Missoula.  The lawsuit pertains to Funded By Other (FBO) contracts between each developer and Mountain Water.   Under these FBO contracts, the developers paid for facilities to provide water service and Mountain Water agreed to refund such amounts over a 40 year period.   As of the date of acquisition of Western Water Holdings, the outstanding balance of these advances, on a non-discounted basis, was U.S. $23,108.  On February 21, 2017, the court issued an order imposing equitable liens on the Mountain Water assets that are the subject of the FBO contracts, mandating that the liens be satisfied directly from the condemnation award, if and when paid.

On April 27, 2017, Mountain Water agreed in principle to certain terms with the City of Missoula relating to the condemnation of Mountain Water's assets. The city is expected to take possession of Mountain Water's assets in the second quarter or early in the third quarter of 2017.

Subject to final adjustments, APUC expects that the net effect of the foregoing and terms of the original acquisition of Mountain Water will result in Liberty Utilities receiving an amount of approximately U.S. $103,000 from the disposition of the utility. 

(b) Commitments

In addition to the commitments related to the proposed acquisitions and development projects disclosed in notes 3 and 6, the following significant commitments exist as of March 31, 2017.

APUC has outstanding purchase commitments for power purchases, gas delivery, service and supply, service agreements, capital project commitments and operating leases.

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

19.Commitments and contingencies (continued)

(b) Commitments (continued)

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)	$	64,410	$	50,569	$	51,831	$	53,058	$	40,572	$	281,236	$	541,676
Gas supply and service agreements (ii)	105,279		83,306		65,819		41,311		33,538		109,696		438,949
Service agreements	46,184		46,532		48,671		50,676		51,218		493,522		736,803
Capital projects	68,665		19,367		69		69		69		17		88,256
Operating leases	10,502		10,191		9,407		8,930		8,995		246,954		294,979
Total	$	295,040	$	209,965	$	175,797	$	154,044	$	134,392	$	1,131,425	$	2,100,663

(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 which are based on market prices were reflected using the March 31, 2017 prices. 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.

20. Non-cash operating items

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

	Three Months Ended March 31
	2017			2016
Accounts receivable	$	13,193		$	13,619
Fuel and natural gas in storage	11,424			16,621
Supplies and consumable inventory	(1,060		)	310
Income taxes receivable	(1,133		)	(3,762		)
Prepaid expenses	(1,120		)	(3,972		)
Accounts payable	(85,300		)	(35,706		)
Accrued liabilities	25,440			(36,199		)
Current income tax liability	977			(604		)
Net regulatory assets and liabilities	(8,718		)	2,994
	$	(46,297	)	$	(46,699	)

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

21. Financial instruments

(a) Fair value of financial instruments

March 31, 2017	Carrying amount		Fair Value		Level 1		Level 2		Level 3
Notes receivable	$	55,650	$	56,817	$	—	$	56,817	$	—
Derivative instruments:
Energy contracts designated as a cash flow hedge	92,043		92,043		—		—		92,043
Currency forward contract not designated as a hedge	127		127		—		127		—
Commodity contracts for regulated operations	1,819		1,819		—		1,819		—
Transmission congestion rights	3,254		3,254		—		3,254		—
Total derivative instruments	97,243		97,243		—		5,200		92,043
Total financial assets	$	152,893	$	154,060	$	—	$	62,017	$	92,043
Long-term debt	$	4,768,432	$	4,358,719	$	837,559	$	3,521,160	$	—
Convertible debentures	5,196		5,401		5,401		—		—
Preferred shares, Series C	18,451		19,051		—		19,051		—
Derivative instruments:
Cross-currency swap designated as a net investment hedge	102,232		102,232		—		102,232		—
Interest rate swap designated as a hedge	14,463		14,463		—		14,463		—
Commodity contracts for regulated operations	4,221		4,221		—		4,221		—
Total derivative instruments	120,916		120,916		—		120,916		—
Total financial liabilities	$	4,912,995	$	4,504,087	$	842,960	$	3,661,127	$	—

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

21. Financial instruments (continued)

(a)Fair value of financial instruments (continued)

December 31, 2016	Carrying amount		Fair Value		Level 1		Level 2		Level 3
Notes receivable	$	38,183	$	47,933	$	—	$	47,933	$	—
Derivative instruments (1):
Energy contracts designated as a cash flow hedge	84,554		84,554		—		—		84,554
Interest rate swap designated as a hedge	48,093		48,093		—		48,093
Currency forward contract not designated as a hedge	17,864		17,864		—		17,864		—
Commodity contracts for regulatory operations	359		359		—		359		—
Total derivative instruments	150,870		150,870		—		66,316		84,554
Total financial assets	$	189,053	$	198,803	$	—	$	114,249	$	84,554
Long-term debt	$	3,913,415	$	3,999,266	$	517,637	$	3,481,629	$	—
Convertible debentures	358,619		455,975		455,975		—		—
Preferred shares, Series C	18,460		18,613		—		18,613		—
Derivative instruments:
Cross-currency swap designated as a net investment hedge	95,404		95,404		—		95,404		—
Interest rate swap designated as a hedge	13,385		13,385		—		13,385		—
Commodity contracts for regulated operations	36		36		—		36		—
Total derivative instruments	108,825		108,825		—		108,825		—
Total financial liabilities	$	4,399,319	$	4,582,679	$	973,612	$	3,609,067	$	—

(1) Balance of $314 associated with certain weather derivatives have been excluded, as they are accounted for based on intrinsic value rather than fair value.

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

21. Financial instruments (continued)

(a) Fair value of financial instruments (continued)

The Company has determined that the carrying value of its short-term financial assets and liabilities approximates fair value as of March 31, 2017 and December 31, 2016 due to the short-term maturity of these instruments.

Notes receivable fair values (level 2) have been 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 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 derivative instruments primarily consist of swaps, options, rights and forward physical deals 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. The significant unobservable inputs used in the fair value measurement of energy contracts are the internally developed forward market prices ranging from $23.16 to $117.87 with a weighted average of $34.94 as of March 31, 2017.  The processes and methods of measurement are developed using the market knowledge of the trading operations within the Company and are derived from observable energy curves adjusted to reflect the illiquid market of the hedges and, in some cases, the variability in deliverable energy.  Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair value measurement. The change in the fair value of the energy contracts is detailed in notes 21(b)(ii) and 21(b)(iv).

Fair value estimates are made at a specific point in time, using available information about the financial instrument. These estimates are subjective in nature and often cannot be determined with precision.

The Company’s accounting policy is to recognize transfers between levels of the fair value hierarchy on the date of the event or change in circumstances that caused the transfer. There was no transfer into or out of level 1, level 2 or level 3 during the three months ended March 31, 2017 and 2016.

(b) Derivative instruments

Derivative instruments are recognized on the unaudited interim 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:

	2017
Financial contracts: Swaps	922,308
Options	680,671
Forward contracts	17,390,000
	18,992,979

At March 31, 2017, transmission congestion rights ("TCR") of 2,033 monthly MWH have been obtained from TCR auctions to hedge 2017 congestion costs in the Southwest Power Pool ("SPP") Integrated Marketplace.

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

21. Financial instruments (continued)

(b) Derivative instruments (continued)

(i) Commodity derivatives – regulated accounting (continued)

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. Gains or losses on the settlement of these contracts are included in the calculation of deferred gas costs (note 5). 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.

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

		March 31, 2017			December 31, 2016
Regulatory assets:
Swap contracts	U.S.	$	1	U.S.	$	—
Option contracts	U.S.	$	56	U.S.	$	27
Forward contracts	U.S.	$	3,650	U.S.	$	—
Regulatory liabilities:
Swap contracts	U.S.	$	25	U.S.	$	175
Option contracts	U.S.	$	9	U.S.	$	92
Forward contracts	U.S.	$	3,529	U.S.	$	—

(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)
648,647	December 2022	U.S. $	42.81	PJM Western HUB
2,783,176	December 2022	U.S. $	30.25	NI HUB
3,552,626	December 2027	U.S. $	36.46	ERCOT North HUB

On October 25, 2016, the Company entered into forward contracts to purchase U.S. $250,00010-year U.S. Treasury bills at an interest rate of 1.8395% and U.S. $250,00030-year U.S. Treasury bills at an interest rate of 2.5539% which settled on February 13, 2017 in order to reduce the interest rate risk related to the issuance of U.S. $500,000 bonds in relation to the acquisition of Empire (note 7(d)). The change in fair value to February 13, 2017 resulted in a gain of U.S. $36,677. The effective portion of the hedge of U.S. $36,533 for the three months ended March 31, 2017 was recorded in OCI while the ineffective portion was recorded in the unaudited interim statement of operations.

The Company is 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 $135,000 bond. The change in fair value resulted in a loss of $1,079 for the three months ended March 31, 2017 (2016 - gain of $14,425), which is recorded in OCI.

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

21. Financial instruments (continued)

(b) Derivative instruments (continued)

(ii) Cash flow hedges (continued)

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

	Three months ended March 31
	2017			2016
Effective portion of cash flow hedge, gain	$	7,518		$	25,134
Amortization of cash flow hedge	(9		)	(10		)
Gain reclassified from AOCI	(2,277		)	(3,558		)
OCI attributable to shareholders of APUC	$	5,232		$	21,566

The Company expects $11,934 and $2,093 of gains currently in AOCI to be reclassified 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 U.S. based operations. APUC manages this risk primarily through the use of natural hedges by using U.S. long-term debt to finance its U.S. operations and a combination of foreign exchange forward contracts and spot purchases. APUC only enters into foreign exchange forward contracts with major Canadian financial institutions having a credit rating of A or better, thus reducing credit risk on these forward contracts.

The Company designates the amounts drawn on the Liberty Power Group’s revolving credit facility denominated in U.S. dollars in excess of the principal amount on the USD loans receivable from its equity investees as a hedge of the foreign currency exposure of its net investment in the Liberty Power Group’s U.S. operations. 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 loss of $nil for the three months ended March 31, 2017 (2016 - $nil) was recorded in OCI.

Concurrent with its $150,000, $200,000 and $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 Generation 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. For the three months ended March 31, 2017, a loss of $8,169 (2016 - $1,236) was recorded in OCI.

(iv) Other derivatives

The Company provides energy requirements to various customers under contracts at fixed rates. While the production from the Tinker Hydroelectric Facility are 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 though the use of short-term financial forward energy purchase contracts which 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.

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

21. Financial instruments (continued)

(b) Derivative instruments (continued)

(iv) Other derivatives (continued)

The Company is exposed to interest rate fluctuations related to certain of its floating rate debt obligation, 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 currently hedges some of that risk (note 21(b)(ii)).

The Company is exposed to foreign exchange fluctuations related to U.S dollar denominated development loans from projects accounted for as equity investments (note 6(b)). This risk was mitigated through the use of currency forward contracts to sell U.S. $38,400 for $47,225 between July 29, 2016 and September 29, 2016. As of March 31, 2017, these instruments had settled. This currency forward contract was not accounted for as a hedge.

The Company was exposed to foreign exchange fluctuations related to the acquisition of the Empire shares denominated in U.S dollar (note 3(a)). This risk was mitigated through the conversion to U.S. dollars of $359,950 from the proceeds received on the initial instalment of convertible unsecured subordinated debentures (note 10) and the use of a currency forward contract to buy an amount of U.S. $567,665 for $744,050 on January 31, 2017. This currency forward contract was not accounted for as a hedge. The settlement of the currency forward contract resulted in a total realized gain of $1,452 and a loss for the period of $17,864, which is recorded as loss on foreign exchange in the unaudited interim consolidated statements of operations for the three months period ended March 31, 2017 (2016 - $nil).

The Company is exposed to foreign exchange fluctuations related to the portion of its dividend declared and payable in U.S. dollars. This risk was mitigated through the use of a currency forward contract to buy U.S.$25,000 for $33,143 on April 17, 2017. As of March 31, 2017 this instrument had not settled, and resulted in an unrealized gain of $127 which is recorded as a gain on derivative financial instruments in the unaudited interim consolidated statements of operations for the three months period ended March 31, 2017. This currency forward contract was not accounted for as a hedge.

For derivatives that are not designated as hedges and for the ineffective portion of gains and losses on derivatives that are accounted for as hedges, the changes in the fair value are immediately recognized in earnings.

Algonquin Power & Utilities Corp.

Notes to the Unaudited Interim Consolidated Financial Statements

March 31, 2017 and 2016

(in thousands of Canadian dollars, except as noted and per share amounts)

21. Financial instruments (continued)

(b) Derivative instruments (continued)

(iv) Other derivatives (continued)

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

	Three Months Ended March 31
	2017			2016
Change in unrealized gain on derivative financial instruments:
Energy derivative contracts	$	—		(426		)
Currency forward contracts	—			(5,250		)
Total change in unrealized gain on derivative financial instruments	$	—		$	(5,676	)
Realized loss (gain) on derivative financial instruments:
Interest rate swaps	(196		)	—
Energy derivative contracts	730			970
Total realized loss on derivative financial instruments	$	534		$	970
Loss (gain) on derivative financial instruments not accounted for as hedges	534			(4,706		)
Ineffective portion of derivative financial instruments accounted for as hedges	848			398
	$	1,382		$	(4,308	)
Amounts recognized in the consolidated statements of operations consist of:
Loss on derivative financial instruments	$	1,382		$	942
Gain on foreign exchange	$	—		$	(5,250	)
	$	1,382		$	(4,308	)

Effective May 1, 2016, the Company entered into a weather derivative contract as an economic hedge for revenue from its St. Leon I wind powered generating facility in the event the wind resource availability falls below a normal range. Non-exchange-traded options are accounted for using the intrinsic method. Changes in the intrinsic value of $158 during the three months ended March 31, 2017 is reflected in non-regulated energy sales in the unaudited interim consolidated statement of operations. Premiums paid related to these weather derivative agreements are expensed over each respective contract period.

(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.

22. Comparative figures

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